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By R. J. Watson, A. H. Juch

About half a million sucker-rod pumps are installed in oil wells in the U. S. alone. In Venezuela, too, the system is widely used; some 5,000, or 90 percent, of Cia. Shell de Venezuela's wells produce a total of 400,000 BOPD by this method. Most of the crude pumped is viscous, gassy and contains relatively small amounts of free water. API gravities vary from 90 to 16O; dead oil viscosities vary from 10 to 10,000 cp at the pump; and GOR's range from 100 to 2,000 cu ft/bbl. Pumps are set at depths ranging from a few hundred to 6,000 ft; the average setting depth is about 2,500 ft. From the literature, it appears that although recent years have seen significant progress toward understanding the rod pumping system as a whole, relatively little attention has been paid to those key items, the sucker-rod pump and the subsurface gas separator or gas anchor. Perhaps because of proration in the U. S., pump manufacturers have seemingly concerned themselves more with the durability of their product, achieved mainly through robust design and metallurgical know-how, than with its working efficiency. In 1963, CSV commenced a major rehabilitation and expansion of its heavy oil fields along the Bolivar Coast. The advent of the more efficient gravel-packed completion and of large-scale thermal recovery (mainly steam soak) operations resulted in well potentials *Now with B. I. P. M., The Hague, The Netherlands. greater than pump capacities. Hence, an urgent need arose to improve over-all pump efficiencies and to attack those special problems related to the production of both the extremely viscous and the hot, steam-laden crudes that formed an increasing proportion of the total stream. There followed a detailed investigation and testing program, carried out in close cooperation with a major pump manufacturer. This culminated in the introduction to the oil industry of a new line of sucker-rod pumps. Early Investigations and Experiments Field Tests Extensive field tests were carried out in three primary Bolivar Coast wells with an in-situ dead oil viscosity ranging from 400 to 6,000 cp. In these installations provision was made to (1) monitor bottom-hole pressures below, in and above the pump by means of pressure transducers, and record casing- and tubing-head pressures continuously; (2) measure accurately the annulus gas, as well as measure the tubing gas and liquid production from the well; (3) take special PVT samples of the well fluid; (4) measure power consumption of the prime mover; and (5) measure the rod loads at the polished rod. A typical test installation is illustrated in Fig. 1. It was established from the pressure transducers that with viscous oils, there is considerable flow resistance across the pump and gas anchor assembly. Pressure surges were observed over each pump cycle,

Jan 1, 1970

By Karl A. Bauer, Cornelis Bezemer

The deposition of calcium carbonate scale on surface and subsurface production equipment creates an operation problem in many oil fields. The formation water in which the carbonate-scale-forming components are initially dissolved becomes supersaturated with calcium carbonate as a result of the drop in pressure during production. The continuous flow of a supersaturated solution through the production equipment results in the growth of a dense layer of calcium-carbonate crystals. For a scale layer to be built up, the supersaturated formation water should contact the walls of the production equipment. The tendency for scale to be deposited, therefore, will be low, if the crude has a low water cut and if the water is finely dispersed in the oil. A scale problem will occur, if at a high water cut part of the water is present as free water. The rate of scale deposition will then be approximately proportional to the rate of free water production. Depending upon where the formation water becomes supersaturated, scale may be deposited in the flow line only, in both flow line and tubing, and in some cases even in the perforations and in the formation near the wellbore. In the South Sumatran fields (Indonesia) the main difficulties encountered due to the deposition of calcium-carbonate scale have been restriction of flow through tubings and flow lines, wear and abrasion of plungers and liners, and stuck plungers or wellhead valves. So far, the only methods of combating the *Presently associated with Brunei Shell Petroleum Co., Ltd.. Seria. scale problem have been routine acidizing and additional well pulling. As for the pumping wells, it was estimated that some 50 percent of the total well-pulling effort was directly attributable to scale deposition. The most promising alternative was to prevent the deposition of calcium carbonate scale by means of chemicals. Inorganic polyphosphates such as sodium hexametaphosphate and trisodium polyphosphate are known to retard the formation of scale by the "threshold action". They are adsorbed on specific faces of the crystal nuclei and thus prevent crystal growth, thereby stabilizing supersaturation. Polyphosphates are effective at very low concentrations ( a few ppm), and far less than stoichiometric quantities are required to keep the scaling ions in solution. Recent investigations on barium sulfate scale1 have confirmed this mechanism. The types of polyphosphate mentioned can be applied as concentrated aqueous solutions either squeezed into the formation, lubricated down the annulus or injected via macaroni string. Several squeeze jobs with polyphosphate solutions have been carried out in the South Sumatran fields, however, with disappointing results. Lubrication down the annulus and injection through a macaroni string were not considered attractive in this area because of the kind of equipment and the degree of supervision these techniques require. Polyphosphates are also available in a granular, glassy form, which, in contrast with the readily soluble types already mentioned, show an extremely low

Jan 1, 1970

By M. A. Childers

Recent work with controlled laboratory tests.' field experience and a new analytical approach indicate that casing centralization, pipe movement and relative rheological properties between the mud and cement (yield point and density) are the three controlling factors in successfu1 primary cementing of dual casing. Turbulent flow has been demonstrated to be unnecessary under the severe displace ment conditions of parallel dual strings of casing. Simultaneous reciprocation of dual casing in directionally drilled boreholes is highly dependent on centralization and on the rapid initiation of pipe movement once the casing has been run to total depth. Successful cementing of 30 out of 32 dual, 3%-in casing wells substantiated these conclusions. A review of 15 dual, 3 1/2-in. casing wells completed prior to the adoption of these principles disclosed only one success. Mathematical and graphical techniques permit the engineer to analyze and anticipate the success or failure of a cementing operation. Standoff, mud displacement and reciprocation can be analyzed mathematically and planned in deep, directional or straight boreholes by review of annular geometry, relative rheological properties between the mud and cement, and forces caused by caring weight, functional drag and differential sticking. Introduction The objective in primary cementing is to displace the drilling fluid with cement that will bond to the formation and casing to prevent communication through the annulus. The predominant cause of failure appears to be channels of gelled mud that remain in the annulus after cementing.1 '* Past investigations have noted many procedures that could improve the displacement process.2-' These procedures include centralization, chemical preflushes, mechanical mud cake removers, controlled flow rates in certain regimes, pipe movement an1 control of mud and cement properties. Not until recently have the effects of many of these procedures been isolated so that their individual importance could be determined. In a recent paper,' a comprehensive and analytical laboratory study of various factors controlling the displacement process concluded that there are three major factors in obtaining complete mud displacement by the cement slurry. 1. Good relative rheological properties between the mud and cement. The cement should be heavier and have a yield point and plastic viscosity higher than the mud being displaced. Buoyancy forces often can dominate the displacement process. 2. High degree of standoff or centralization. The more centered the casing, the greater the likelihood of complete mud displacement and removal. 3. Pipe movement obtained by rotation or reciprocation. Often unfavorable rheological properties between the mud and cement, and poor standoff can be compensated by pipe movement. This work demonstrates the compatibility of the latter concepts with field results extended to the more severe dual casing displacement process. Early Experience With Dual 3'/t-In. Primary Cementing Early slim casing completions in the West Delta Block 73 field, offshore Louisiana, included 17 dual 3%-in., 3 single 3% -in. and 1 dual 2% -in. casing installations. Table I provides data on these earlier wells. Usually, common Class A cement was placed across the pay zone and 12 percent gel cement was placed to a height of 500 ft above the highest productive sand. Centralizers (6%-in. OD maximum expansion) were placed two or three per joint on both casing strings from total depth through the completion intervals and at least one per joint for the remainder of the cement sheath. A number of techniques and procedures were attempted to improve cementing success. Casing was run simultaneously or separately with a number of mud conditioning and circulating techniques. Mechanical aids such as cement bonders, slmiding sleeves, turbulizers and various sizes and strengths of centralizers were used. Common and gel cements were mixed with fresh or sea water with a number of different additives to control retardation and dispersion. Cements were thinned and mixed at high rates to try to induce turbulent flow in the annulus. On one well the "slow flow" method was used." Perforating was accomplished with a jet orienting gun. Unsuccessful cement jobs were indicated by production of extraneous fluids or by pressure communication between zones. On test, five wells flowed water, four flowed sand and six had pressure communication with the other string or the 10%-in. casing. A total of 25 remedial squeeze ce-

Jan 1, 1969

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 T. K. Perkins, W. W. Krech

Jan 1, 1969

By A. G. Weber, R. L. Ledbetter, A. L. Hicks

A procedure which makes use of both analog and digital computers has been developed for predicting the pressure-production behavior. of water-drive reservoirs. The electric analyzer is used for matching the past pressure and production history of the reservoir and inferring the physical characteristies of the aquifer. When the history has been matched, a .set of base curves called influence functionce" are derived and the future behavior of the reservoir is calculated from these curves. INTRODUCTION Electric analog methods are particularly well-suited for complex water-drive problems. Like all other methods of analyzing water-drive reservoirs, however, analog methods are subject to certain limitations. One of the more obvious and serious of these results from inaccurate or insufficient knowledge about physical characteristics of the reservoir and aquifer. However, it is not insurmountable because the unknown characteristics can usually be inferred from the reservoir's previous behavior. Simons and Spain have shown that even with scant reservoir data and limited production history, electric analyzer studies can provide useful and reliable results. Aside from this limitation on analyzer predictions, the main disadvantage has been lack of a technique for keeping predictions abreast of latest production forecasts. Pressure behavior of a reservoir depends on the rate at which fluid is withdrawn; it is therefore necessary to specify the future withdrawal schedule before the future pressure behavior can be calculated. Conventionally, the electric analyzer predicts pressure behavior for a specific production schedule. If this schedule is abandoned in favor of some new one, as is frequently the case, either the study must be rerun or results adjusted in some manner. The usual procedure is to predict pressures for several different forecasts covering a wide range of production rates. Pressures for specific rates other than those studied can then be approximated by interpolating between the analyzer predicted curves. However, reliability of this type of prediction is doubtful. This paper describes a technique for predicting future behavior of water-drive reservoirs that retains all advantages of electric analyzer analysis and eliminates the main disadvantage. That is, the analyzer is used conventionally to infer unknown reservoir parameters from the pressure history, but not to predict the future behavior directly. Instead, a derived set of base curves, called influence l'unctions, can be used to calculate future behavior for any production schedule.

By E. B. Brauer, W. Hurst, J. D. Clark

Because of drilling, completion, and workover practices, the permeability around a wellbore generally is different from the permeability of the formation. The zone with the altered permeability is called "skin" and its effect on the pressure or flow behavior of the well is called "skin effect". Hawkinsl has shown that the radius and the permeability of this zone are related to the skin by: If the permeability in the skin zone is less than that of the formation, the skin is positive; if it is more than that of the formation, the skin is negative. If the two permeabilities are equal, s is zero; that is, there is no skin. Van Everdingen2 and Hurst3 have given mathematical solutions to the case of a zone of reduced permeability around the wellbore. This skin effect is illustrated in Fig. 1. They treat the positive skin as a zone of reduced permeability of infinitesimal thickness around the wellbore. When applied to a well with negative skin, however, their solutions lead to the calculated flowing well pressure which is smaller than the formation pressure, i.e., an injection situation. This is a physical contradiction. In this paper, it is shown that this mathematical difficulty can be overcome by assuming an effective wellbore radius larger than the actual wellbore. Existing solutions2"4 are modified to include the effect of an enlarged wellbore radius, and thus enable the engineer to deal with negative as well as positive skins. Theoretical Development Van Everdingen and Hurst,4 through the use of Laplace transformation, obtained the following expression for transient fluid influx into a wellbore: The values for QtD, reported extensively by van Everdingen and Hurst,4 are obtained from the following integral:

Jan 1, 1970

By W. T. Malone, J. R. Williams, R. L. Tiner, J. M. Tinsley

Hydraulic fracturing methods for production stimulation have become a common procedure in the oil and gas industry. Fracturing treatments are performed on wells of various potentials to help increase the production rate. In addition to the desire for increased production is the need to predict what increase might be expected. This knowledge is useful in economical treatment planning to accomplish the desired production goals for the well. Theoretical production increases due to horizontal radial fractures may be calculated using equations developed from mathematical analyses and electrical models.1,2,6 It also is possible to predict theoretical production increases due to vertical fractures using curves developed from electrical3 and mathematical models.8 However, these studies assumed that the vertical fracture height and the formation height were equal, which may not be true." In addition, the final fracture height through which fluid is produced may not be equal to the created height. The development of vertical fracture proppant transport relationships has made unrealistic the assumption that propped fracture height is equal to created fracture height. Through the use of published proppant transport equations,4'12 it is possible to calculate the height of a bed of propping agent deposited in a fracture of a given height. Assuming that the fluid flowing in the fracture moves through only the propped portion of that fracture (i.e., that the un-propped part of the fracture heals) it becomes essential to know how production increase varies with the ratio of propped fracture height to formation height. It should be recognized that future investigation may determine that the fracture does not heal completely and that a highly permeable channel exists over the deposited bed of proppant. The effect of this channel was not considered for the present study. The following analysis of experimental data allowed development of curves to determine theoretical production increases considering fracture height as a variable. Discussion In designing a fracturing stimulation treatment a number of variables must be considered. The size of the treatment, type of proppant used, proppant concentration, treatment fluid properties and well conditions are all factors affecting the dimensions and permeability of the fracture. Production increase due to a vertical fracture is affected by propped length, height, width and permeability of the fracture for a given set of formation conditions. Production increase may be defined as the ratio of production rate after fracturing to the production rate before fracturing at the same pressure differential, pe — pw. The producing rate in an

Jan 1, 1970

By W. G. Bearden, G. C. Howard, J. W. Spurlock

An investigation of the factors af-fec.ting the inter-zonal flow of fluids in the casing-wellbore annrc1rt.s of an oil or gas ivell is presented Laborntory tests revealed that failure of the caring-cement bond allows communi-cation of fluid at pressure differentials near 1.000 psi. Perforating with a 11011011: carrier gun does not shatter or crack the cement sufficiently to allow communication through these cracks and does not seriously affect the casing-cement bond failure pressure. The pressure to cause communication at the casing-cement bond can he increared to 3,000 psi by. limiting pipe deformation during cementing and subsequent operations. Communication can be prevented, however. up to pressures sufficient to cause the cement to fail or the casing to col-lapse, by attaching to the casing a seal ring of deformable ruhber molded between two steel flanges. When installed, one flange is attached rigidlv to the casing to serve as back-up for the gasket While tile other flange is movable. To date, these gasket seal rings have been field-tested in 27 Wells. Althotrgh communication has been noted in two wells, inter-zonal flow has been prevented in other wells in the same area by installing more seal rings between the communicaring zones. INTRODUCTION The inter-zonal flow of fluids behind casing cemented in oil wells during normal production or stimulation operations is a major operating problem. If it cccurs during production operations. it can seriously limit the pressure to which a reservoir may be depleted without harmful invasion of unwanted fluids. If it occurs during stimulation operations, it may preclude the possibility of stimulating the desired zone. This communication can be caused by failure of the bond between the casing and cement, failure of the bond between the cement and formation, or failure of the cement itself. This paper presents the results of an investigation of factors affecting com-munication at the casing-cement bond and methods which aid in preventing it. LABORATORY INVESTIGATIONS The laboratory tests performed in this study were divided into three phases. The first phase consisted of tests to determine if perforating would shatter and crack the cement sheath so severely that communication would occur through the cement itself. The second phase consisted of tests to determine more precisely the cause for the casing-cement bond failure. The third phase consisted of tests to evaluate the effectiveness of various de-formable seals attached to the casing in preventing communication. EFFECT OF PERFORATING, The effect of perforating was invest~gated in tests performed with apparatus shown on Fig. 1. Cement was poured into the annulur space hetween 5%-in. casing and 8%-in. casing and allowed to cure for 72 hours. The apparatus was then perforated with a hollow carrier gun containing eight duPont 26-A shaped charges. Bull plugs were placed over the perforations in the 8 5/8-in. casing and hydraulic pressure was applied inside the 5 1/2i-in. casing. The pressure to cause fluid communication past the cement sheath was observed and termed the "bond failure pressure". Several different cement compositions were included in these tests, the results of which are shown in Table 1. In Tests 1 through 4 of Table 1, bond failure occurred at- the inter- .

Jan 1, 1966

By K. K. Clark, W. H. Somerton

The feasibility of reducing pressures needed to fracture formations by heating the borehole intensively has been investigated on a laboratory scale. Reductions in fracture pressures of heated Bandera, Berea and Boise sandstone cores were observed at various confining pressures, simulating reservoir stress conditions to a depth of 5,000 ft. Both permeable and impermeable borehole boundary conditions were tested. Three heating conditions were used in the tests. One group of samples was heated in a furnace to a temperature of 600C, cooled to room temperature., and then tested for fracture pressures. Two other groups of samples were heated with a borehole heater to maximum borehole wall temperatures of 625 and 792C, then cooled and tested. In all cases, heated samples showed substantial reductions in fracture pressures compared to unheated samples. The higher temperature borehole heated samples showed the greatest reduction, amounting to 70 per cent in the extreme case. In actual application to wells, it was concluded that fracture pressures may be reduced by 20 to 50 per cent by intensive borehole heating before fracturing. INTRODUCTION Hydraulic fracturing of oil and gas wells is an accepted and effective technique for increasing well productivity in many areas, but is notoriously unsuccessful in other areas. The technique becomes less interesting for production stimulation purposes when excessive fracture pressures are necessary. Formations which do fracture but require high pressures, probably form horizontal fractures. There is good evidence to indicate that some formations do not fracture at all, but yield plastically under high pressure. Thus, any technique which will make formations easier to fracture or will reduce fracture pressures is potentially interesting to petroleum producers. Horizontal fractures generally occur in planes of weakness, such as bedding planes, and at pressures equaling or exceeding the effective overburden stress. In the unusual case where planes of weakness do not exist, a slightly higher pressure must be applied to overcome the tensile strength of the rock. In general, high fluid-loss fracturing fluids are conducive to the formation of horizontal fractures.1 Vertical fractures, when they do occur, are initiated at pressures generally lower than overburden pressure and are favored by low fluid-loss fracturing fluids or impermeable boreholes. The pressure necessary to create a vertical fracture in an impermeable, elastic medium can be predicted from the so-called "thick-walled cylinder" equation: Pf = 2 or+ st.............(1) where pf = fracture pressure or = radial stress st = tensile strength of medium. This equation indicates that to fracture it is necessary to overcome a tangential compressive stress, induced by and equal to two times the radial confining stress, plus the tensile strength of the medium. If the above equation held strictly true for rocks, very little could be done to reduce fracture pressure. The tensile strength of the rock might be reduced somewhat, but any change in st would be small compared to the magnitude of the tangential stress at reasonable subsurface depths. Laboratory tests have shown that actual fracture pressures exceed values predicted from Eq. 1 by factors of 1.4 to 28.6.1,2 Eq. 1 thus does not properly describe the

Jan 1, 1966

By J. van Lookeren

In the case of a reservoir where the oil underlies a large gas cap and overlies bottom water, production can be inzproved considerably if wells are perforated below the water-oil contact rather than opposite the oil-bearing section. The theoretical arguments for this improvement, which in some cases may be tenfold, are supported by experimental evidence. INTRODUCTION Reservoirs frequently consist of one sand body containing an oil layer underlying a thick, gas-bearing section and overlying bottom water (Fig. 1). Wells in such reservoirs are customarily opened up opposite the oil-bearing interval or, rather, opposite the lower part of this interval (Fig. 2). More often than not, it is inefficient or prohibited to blow off large quantities of gas with the oil. This im-psses a severe limitation on the drawdown, which results in low oil-production rates. Because of the small difference in specific gravity between oil and water, the latter will easily cone upwards, so that the production of water together with the oil is not prevented by this completion method. In such a situation wells should be opened deeper, in the originally water-bearing zone. The gas can be shut off by not perforating over the upper part of the interval (Fig. 3) or by a tubing hung close to the bottom of the interval (Fig. 4). Initially much water will be produced, but when steady-state conditions have been established (as depicted in Figs. 3 and 4) larger drawdowns are permissible than in a conventionally completed well, and correspondingly higher oil-production rates will result. Water cuts are only slightly higher because of the small effect of gravity on the water-oil flow distribution. CALCULATIONS The ratio of improvement has been estimated by means of approximate calculations. The completion depicted in Fig. 4 is the most convenient basis for these calculations. By postulating that vertical flow gradients can be disregarded, the Appendix shows that the well-known Dupuit formula can be obtained except for some complication due to the presence of two fluids rather than one. The Appendix makes the reasonable assumption that, for suitable boundary conditions, the oil layer occupies a constant fraction of the total fluid height throughout the reservoir. The oil- and water-production rates can thus be related to the liquid levels in the borehole as follows:

Jan 1, 1966

By W. T. Bell, M. P. Lebourg

The perforating of multiple tubingless completions, in which two or more strings of 27/8-in. OD casing are installed in the same borehole, presents two basic problems. First, good completion practices require an eficient perforator that leaves no debris to interfere with subsequent completion operations. Second, and of more complicated nature, a system is needed for controlling the direction of fire so that adjacent strings are not damaged. Development of of a 2-in. OD, steel retrievable, shnped-charge gun has solved the first problem. The second was resolved through development of three different devices to provide directional perforating for the two types of completion methods being employed today. These include a mechanical orienting device and two self-orienting radiation devices. Conceivably, the latter methods could be adapted to the directional perforating (of .upper zones) of conventional dual and triple completions without removing production tubing and packers. INTRODUCTION The recent trend to multiple tubingless completions,' wherein two or more strings of 27/8-in. OD casing are installed in the same borehole, has presented two basic perforating problems. The first problem to be overcome was the design of a gun that would result in efficient perforations without causing debris to bridge in these small-diameter casings. The second problem was, of course, to devise a system for controlling the direction of fire such that adjacent strings would not be damaged. The problem of gun debris in slim-casing completions has been well defined in the numerous 27/8-in. single tubingless completions which have been effected during recent years with the expendable-type perforators. Failure of expendable-gun debris to settle out properly, even with good gun break-up, has resulted in bridging inside these small-diameter casings. This, in turn, has interfered with completion and re-conditioning operations. The past two years have clearly shown, in fact, that debris problems are not confined to this small range of casing with most designs of expendable-type guns. A high incidence of bridging has even been reported in 4%-in. OD casing. The perforating of multiple tubingless completions has entailed, therefore, the development of a completely debris-free gun of adequate performance, as well as the necessary devices to provide positive directional perforating in the two completion methods presently being employed. THE GUN —DESIGN CONSIDERATIONS The design of a shaped-charge gun for slim-casing perforating has presented a maze of interrelated prob-lems. Since the primary specification has been leveled at efficient charge performance with complete elimination of gun debris, it has been necessary to develop a retrievable steel-carrier gun of tubular construction to house the charges. The carrier must be retrievable through 2.29-in. API pump-seating nipples which are usually installed in 2 7/8-in. strings. To provide for recovery of the gun from the well, swelling of the carrier on firing must be carefully controlled. Control of swelling automatically means control of explosive weight in the shaped charge which, in turn, influences charge performance. Carrier swelling also depends upon the confinement pressure at the level being perforated, which imposes a hydrostatic pressure-depth limitation. Burr interference on the wall of the carrier, resulting from passage of the jet through the carrier wall, must be eliminated by suitable design. Clearly then, a satisfactory shaped-charge gun design for slim-casing operations represents a fine balance between carrier swelling, hydrostatic pressure, explosive weight and charge performance. Additionally, to lend itself to directional perforating, the gun design must provide a positive locking mechanism for individual charges within the gun carrier. This fixes charge orientation within the carrier and prevents

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 J. Handin

Triaxial compression tests with independently applied external confining pressures and internal pore pressures show that the ultimate compressive strengths of representative oil well cements are nearly linear functions of effective pressure — the difference between external and internal pressures on the jacketed cylindrical specimens (to 15,000 psi). The strengths are little affected by the test temperature to 350F (not to be confused with the curing temperature). At an effective pressure of 15,000 psi, strengths are in the rage of 30,000 to 50,000 psi, comparable to those of sedimentary rocks under similar conditions. The cements become very ductile even under low effective pressures; permanent shortenings of 30 per cent or more are attainable without rupture. INTRODUCTION Since the pioneering work of Richart, Brandtzaeg and Brown1 on the failure of cement under combined compressive stresses, it has been recognized that ultimate compressive strength is greatly enhanced by the application of confining pressure. More recently, Mc Henry2 showed that the strength of concrete was a linear function of the effective pressure (the difference between the external confining pressure on a jacketed specimen and the internal fluid pore pressure), at least for a range of 0 to 1,500 psi. The effect of temperature had not been investigated, and no previous systematic triaxial compression testing of naterials used for oilwell cementing seems to have been done. The present work was suggested by the late J. hi. Bugbee3 who stated that "consideration of the common application of high-pressure hydraulic fracturing to the initial completion or recompletion of wells, and the large pressure drawdowns in some producing wells, particularly those in abnormally high-pressure gas-condensate reservoirs, raises the question of what is a suitable cement strength for various completions. The intuitive belief exists that cement strength need be no greater than formation strength. Tests should, however, be conducted at downhole conditions." The ultimate compressive strengths of rocks penetrated by the borehole must rise several fold with increasing depth.4 This marked enhancement of strength is due to the influence of the effective pressure, the total weight per unit area of the overburden less the hydrostatic pore pressure. (The effect of temperature due to the geothermal gradients is relatively small for depths to 30,000 ft.) .A significant comparison of the strengths of rocks and cements at downhole conditions requires knowledge of the confined compressive strengths of cements as well. EXPERIMENTAL PROCEDURES The theory and technique of triaxial compression testing are fully discussed in earlier reports.4-6 Briefly, cylindrical specimens 1-in. long and 0.5-in. in diameter are jacketed in thin copper tubes of negligible strength, placed in the test chamber and subjected to an external confining pressure of kerosene and loaded axially by the piston at a strain rate of 1 per cent per minute. Pore pressures of water (or kerosene) are applied independently through the hollow piston and are maintained constant during the shortening of the specimen, Tests at sensibly 0 pore pressure are arranged so that any free water in the cement can escape to the atmosphere. (If egress of water were denied, pore pressure would rapidly attain the value of the external confining pressure because of reduction of pore space.) The test chamber can be heated for high-temperature experiments. Unless otherwise noted, the cement samples were air dried for about a week. Recorded during a test are pore and confining pressures, shortening and axial differential force (total force less the product of the confining pressure and the area of the piston). True stress-strain curves are constructed by dividing the measured differential force by the actual cross-sectional area of the specimen at a given

Jan 1, 1966

By F. W. Jessen, C. C. Patton

Adsorbed films were formed on polished stainless steel specimens from dilute benzene solutions of two crude oil distillation residua. Although the two residua were extremely dissimilar in composition, contact angle measurements showed that the two films increased the wettability of the steel specimens to oil by equal amounts. Furthermore, the wettability of the films was essentially unaffected by the desorption techniques used. Paraffin deposits were formed from heptane-wax solutions on the same stainless steel specimens. These deposits definitely adhered to the surface. Presence of an adsorbed crude oil film on the metal surface increased its free surface energy and resulted in increased deposition of paraffin. The addition to the heptane - wax solution of small amounts of the same distillation residua that were used to form the adsorbed films resulted in decreased cohesive strength in the deposits formed, which resulted in decreased deposition. The presence of a crude oil fraction both in the solution and as a preadsorbed film eliminated the adherence of a deposit of any kind. A mechanism of deposition is proposed which explains the results obtained. INTRODUCTION The natural formation of any predominantly organic accumulation in oilwell tubing, surface flow lines or other production and storage facilities is called a paraffin deposit. These deposits restrict the production of crude oil, causing a substantial increase in production costs because of decreased flow capacity, expense for periodic deposit removal and unproductive downtime. The conditions under which such deposits form, their physical characteristics and the nature and severity of the problem created are extremely varied. Over the past several years, much progress has been made in developing and utilizing methods to remove accumulated paraffin deposition. However, like so many other problems, the basic stumbling block appears to be a lack of understanding of the fundamental mechanism involved in the formation of such deposits. Crude petroleum is known to contain considerable quantities of polar, surface active substances which Doddl has shown to be present at the oil-water interface. Denekas, Mattax and Davis2 observed that the wettability of reservoir rocks was drastically altered by exposure to crude oil fractions; and Zisman, et a1.3 showed that the nature of the compounds adsorbed on a surface would determine its wettability characteristics. Cole and Jessen4 and Ehrig5showed that surface wettability can have a profound effect on the magnitude of paraffin deposition, and Parks6 demonstrated chat the presence of certain adsorbed films on a metal surface would reduce the adherence of paraffin to that surface. Zisman7 has since advanced the theory that the conditions for adhesion are the same as for wetting. Therefore, it was felt that there was adequate evidence to support the supposition that adsorption of compounds from a crude oil might play an important part in paraffin deposition. ADSORPTION-WETTABILITY EXPERIMENTS Initial experiments were conducted to determine the effects of adsorption from solution of crude oil residua on the wettability of a polished stainless steel surface. Distillation residua with initial atmospheric boiling points of 700F were used in preference to the whole crudes in order to concentrate on the molecular weight range of interest, and to eliminate the possibility of composition change due to evaporation of the light ends. Also, these high boiling materials would be expected to be adsorbed from the whole oil in preference to similar compounds of lower molecular weight.

Jan 1, 1966

By V. J. Sikora, W. J. McGuire

Several years ago, we used an electric analogue computer to study the effect of vertical fractures on the productivity of wells in expanding fluid-drive reservoirs. The results of this work were used both as a guide to research and as a basis for the design of actual fracturing operations. In 1958, Dyes, Kemp and Caudle' published portions of the data from this study. The results were released in 1959 to service companies for use in fracturing guides. The purpose of this note is to discuss the experimental conditions and assumptions which were made to derive the information which is already partially a matter of public record. ASSUMPTIONS This study applies to fractures which extend in a vertical plane symmetrically from the well. For simplicity, we chose to study the case of a well in a square drainage area with its fractures extending toward two of its nearest neighbors. We have assumed no migration of fluid across the boundary of this area. The quadrant shown in Fig. 1 models this system. We made the usual assumptions that the reservoir is homogeneous and isotropic, that the fluid is homogeneous and that production is effected by fluid-expansion drive. We also assumed that the fracture extends from top to bottom of the reservoir. Of more practical interest is our assumption that the fracture does not change the size of the drainage area. This premise is appropriate if all the wells in the reservoir are fractured in the same way. But where a single well is fractured, its drainage area may be enlarged at the expense of its neighbors. This could be of economic importance. The assumption that the fracture will not extend beyond the established drainage area of the well also limits the application of the results. Such long frac- tures will yield benefits in excess of those predicted here. When we assume homogeneity, we disregard the frequently observed zone of damage in the vicinity of the well. Where damage is severe, the benefits resulting from by-passing it will far exceed those predicted by this study. All comparisons were made of systems producing in the semi-steady state. By this we mean that equal volumes contributed equally to flow (pressure was dropping at a uniform rate throughout the system) when the rate of flow was observed. EXPERIMENTAL SET-UP We used the pool unit of an electric analyzer' in this study. The squase drainage system of a well was rep-

By J. E. Warren, J. H. Hartsock

An asymptotic solution to the equation that describes the flow of a slightly compressible fluid in an infinite porous medium has been used to estimate the interaction between two adjacent wells producing from a common reservoir. A direct method for approximating the interference time defined by Stevens and Thodosl has been suggested. An alternative definition for the time of interference, based on the minimum pressure change in the interference region, has been proposed; also, a direct method of determination has been prescribed. Examples have been employed to illustrate the use of both methods.

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 E. B. Hunt

Paraffin deposition has been studied in the laboratory under conditions simulating deposition in well tubing. A theoretical analysis has been made of the cooling of the oil and the precipitation of paraffin from the oil as it flows up the well tubing and through surface flowlines. It is proposed that paraffin deposits are initiated by the precipitation of paraffin directly on or adjacent to the pipe wall and grow by diffusion of paraffin from solution to the deposit. This mechanism is consistent with laboratory and field observations, and has proved useful in the design and interpretation of laboratory paraffin-deposition tests. Tests have been made of the effect of plastic pipe coatings and chemical additives on paraffin deposition. INTRODUCTION Paraffin deposits which form in well tubing and surface flowlines interfere with production and must be removed. Over the years much progress has been made in developing and improving methods of removing these deposits after they form. Much less progress has been made in developing methods of preventing or inhibiting the formation of paraffin deposits. This is due, it is believed, to the lack of knowledge of the mechanism of paraffin deposition, the absence of satisfactory laboratory testing methods and the difficulties in evaluating the results of field tests of preventive treatments. The present investigation was undertaken to elucidate the mechanism of paraffin deposition and to develop suitable laboratory tests for studying the inhibition of paraffin deposition in well tubing and surface flowlines. Current theories on the mechanism of paraffin deposition have been evolved from field observations, from laboratory studies of various factors which might be involved in paraffin deposition, and from laboratory paraffin-deposition tests.1-9 Paraffin deposits have been formed in the laboratory by immersing a cold finger into a hot wax-oil solution and by flowing hot wax-oil solutions through cooled pipe or over cooled plates. These laboratory conditions differ in important features from field conditions, and the observed deposition behavior is not entirely field-like." Thus, there is reason to question the field applicability of the results of these tests. The present investigation was undertaken to determine how to perform and interpret laboratory paraffin-deposition tests to obtain information on the inhibition of deposition in the field. The paraffin problem in the broadest sense encompasses the formation of any predominantly organic deposit in well tubing, surface flowlines and other equipment in contact with crude oil or gas. The present investigation was limited to paraffin deposition involving the precipitation of paraffin wax from solution by cooling and its concentration in a deposit on a cooled surface. This probably excludes its applicability to those problems arising from asphaltic-base crudes, but not those arising from paraffin-or mixed-base crudes. This also excludes its applicability to emulsion and congealing oil problems which are often included as part of the paraffin problem. The phenomenon of cooling appears to be the controlling factor in paraffin deposition involving the precipitation of paraffin wax and its concentration in the deposit. Deposits of this type are usually found in the field only where cooling occurs. Early in this laboratory investigation, it was not found possible to form deposits under constant temperature conditions from a wax-oil slurry, either by steady flow through pipe or by gas-lift up a pipe. Thus, the investigation was limited to situations involving cooling. THEORY The relationships involved in establishing the temperature profiles in an oil stream as it flows up well tubing with a linear (geothermal) pipe-wall temperature distribution or through surface flowlines with essentially constant pipe-wall temperature are presented in the Appendix. The relationship between radial distance in the pipe and the rate of cooling of the oil is then combined with a relationship between cloud point and rate of cooling to develop the pattern of formation of a wax cloud in the oil. The following discussion of paraffin deposition under various laboratory and field conditions is based upon this development which is presented in the Appendix. PARAFFIN DEPOSITION IN SURFACE FLOWLINES The average temperature of the oil coming out of a well is somewhat higher than the ground temperature. Thus, the oil continues to cool on its trip through the surface flowline, and wax deposition can occur. The temperature distributions calculated from Eq. A-4 are given in Fig. 1. As can be seen, almost all the cooling occurs in the first 500 ft from the wellhead. In addition, the radial temperature gradient near the wall decreases rapidly with distance and becomes very small after a few hundred feet. Thus, growth of a paraffin deposit would be expected to decrease rapidly with distance from the wellhead and become negligible after a few hundred feet, since growth is dependent on concentration gradient. Wax precipitation and diffusion of wax to the already

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