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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. O. Scott

Transient pressure behavior of wells intersected by a single vertical fracture has been examined by means of a heat pow analogy. Results are correlated in terms of dimensionless pressure change and dimensionless transient time. The resulting curves are found to lie between the dimensionless curves for a cylindrical well and a line source when effective well radius is expressed as one-fourth of the total fracture length. Results are also shown for various degrees of afterflow. Use of the curves provides a means of determining reservoir permeability, wellbore radius, and thereby fracture length, even when the final slope of the transient curve is not obtained. Superposition of curves may be used to confirm existence of vertical fractures in the reservoir adjacent to the well or to indicate a damaged zone on the fracture face. INTRODUCTION Hydraulic fracturing has become a standard well completion practice for the purpose of increasing flow. Results are normally gauged in terms of some sort of "stabilized" flow rate established before and after the treatment. This procedure may be misleading because pressures in or around the well do not become "stabilized" during the test period. Transient pressure tests on fractured wells can overcome the objections to stabilized flow tests by indicating when a stable pressure gradient is reached. In addition, the transient pressure tests can be used to determine formation flow capacity and effective wellbore radius. The effective wellbore radius may be used as a measure of the success of the fracturing operation. The slope and position of the transient pressure-log time curve may be used to determine the flow capacity and wellbore size after sufficient lapse of time so that the pressure gradient in the vicinity of the fractures becomes constant. However, in tight reservoirs or in short tests this condition may not be reached. Presence of the fractures in tight reservoirs may cause a constantly increasing slope to the transient pressure curve. If this slope is picked too soon, formation flow capacity will appear high and the fracture size will appear too small. This paper is intended to clarify the early transient behavior of vertically fractured wells. It shows how formation flow capacity and wellbore size can be determined even though the maximum slope of the transient pressure curve is not obtained during the test. Development of the techniques of transient pressure analysis for wells has been summarized by Perrine.' He reviews the various definitions of wellbore effects such as skin effect, productivity ratio, damage factor and condition ratio. In the present paper, use of these terms is avoided by defining an effective wellbore size. For the fractured well this effective wellbore size is larger than the actual wellbore. Assumptions made are constant flow rate at the well, constant fluid compressibility, constant fluid mobility and uniform porosity and formation thickness. From the basic differential equations of flow, two different solutions may be obtained. The first, the line source solution, is commonly used in transient pressure analysis.' It expresses the change in pressure at any radius due to withdrawal or injection of fluid at the line source from an infinite reservoir at uniform initial pressure. This equation, in oil field units: is

By R. H. Kolb

A long term project at Shell Development Co.'s Exploration and Production Research Laboratory has been the improvement of the accuracy and the ease of BHP measurements. As a result of these efforts, two complete and separate systems have now been built for the automatic logging of BHP variations. The first of these is a small-diameter instrument suitable for running through production tubing on a single-conductor well cable. During the development of this instrument, as much emphasis was placed on providing a high degree of usable sensitivity and repeatable accuracy as on obtaining the advantages of surface recording. The second system combines the benefits of automatic, unattended recording with the convenience of a permanently installed Maihak BHP transmitter.' THE CABLE INSTRUMENT For many years the standard instrument for BHP determination has been the wireline-operated Amerada recording pressure gauge or one of several other similar devices. This gauge records on a small clock-driven chart carried within the instrument, and although relatively precise readings from the chart are possible, they are difficult to ob-tain. a Both the maximum recording time and the resolution of the time measurements are limited by chart size, and when a slow clock is required for long tests, the precision of the time measurement is often inadequate. Since it is impossible to determine the data being recorded until the gauge has been returned to the surface, wasted time often results when a test is protracted beyond the necessary time or when it is terminated too soon and must be re-run. Clock stoppage or other malfunctions which would be immediately apparent with surface recording remains undetected with down-hole recording; the test is continued for its full term with a consequent loss in production time. As new uses for subsurface pressure data evolved, the shortcomings of the wireline instrument became increasingly apparent, and the concurrent development of a surface-recording pressure gauge and the associated high-pressure well cable service unit' was undertaken. Description of the Instrument Because of its ready availability and advanced degree of development, the Amerada bourdon-tube element was chosen as the basic pressure-sensing device. This element converts a given pressure into a proportional angular displacement of its output shaft, and a suitable telemetering system was designed to measure accurately the extent of this displacement and to transmit the measurement to the surface and record it. The telemetering system furnishes a digital record printed on paper tape by an adding machine-type printer. The present arrangement provides a resolution of one part in 42,000 over the angular equivalent of full-scale deflection, giving a usable sensitivity of better than 0.0025 per cent of full scale. An additional refinement simultaneously records on the tape the time or the depth of the measurement, also in digital form. When the instrument is placed in operation, an adjustable programer can be set to initiate a read-out cycle automatically at selected time intervals. When subsurface pressures are changing rapidly, readings may be recorded as frequently as once every 10 seconds; when pressures are more nearly stabilized, the period between readings may be extended to as much as 30 minutes. Because the instrument is surface-powered as well as surface-recording, the maximum period of continuous logging is (for all prac. tical purposes) unlimited. The subsurface instrument is a tubular tool, 1 1/4-in. in diameter and 6.5 ft in length, operating on 12,000 ft of conventional 3/16-in. IHO logging cable. The transmitting section, mounted above the bourdon-tube element in place of the regular recording mechanism, contains no fragile vacuum tubes or temperature-sensitive transistors. This unit has been laboratory-tested to 1 0,000 psi and 300°F and has performed dependably during a number of field operations. The down-hole transmitting arrangement can be fitted to any standard Amerada pressure element, regardless of range and with no modification of the element itself. Calibration To obtain a repeatability commensurate with the sensitivity and resolution of the instrument, it was necessary to develop a special calibrating technique. The manufacturers of the Amerada recording pressure gauge claim an accuracy of only 0.25 per cent of full scale, which is a realistic figure for normal calibrating and operating procedures. An exhaustive investigation was made of the errors inherent in the bourdon-tube element, itself, independent

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 R. E. Zinkham, R. J. Goodwin

A mathematical study has been made of the amount of support a cement sheath could provide to casing cemented into the earth. Several assumptions were required to make the analysis, but only two of them are limiting: (I) the pipe must be completely surrounded with cement, and (2) any mud filter cake between the cement and formation has the same physical properties as either the cement or formation. The calculations showed that little support would be provided to the pipe before an unsupported cement sheath failed in tension; however, when the cement is confined between the pipe and wellbore and is loaded in compression, the pipe could receive a considerable amount of support. In fact, the theoretical results indicate the lower grades and larger sizes of pipe could have their working pressures doubled when reasonable compressive loads were applied to a surrounding cement sheath. These data are shown in six charts. Other down-hole conditions such as setting the cement under pressure, increased temperature and cement confinement all tend to increase the potential usefulness of the sheath. Because of size limitations, a laboratory program to verify the most important results of this mathematical study would be very difficult. However, small-scale field tests would be practicable. This paper shows that, if a solid cement sheath can be obtained in the field by either primary cementing or by repair after detection of flaws by surveys such as the new cement-bond logs, the use of this approach to reducing pipe costs merits further consideration. INTRODUCTION A modification in casing design practices is proposed which may either reduce the amount and grade of steel required to contain a specified internal pressure or permit the working pressure to be increased for a specified weight and grade of pipe. One of the more important considerations in casing design is its resistance to collapse; however, Bowers' and, more recently, O'Brien and Goins' have shown many casing programs are unnecessarily conservative in this respect, and they have indicated how savings can be made by designing for more realistic down-hole conditions. Earlier, Saye and Richardson howed that pipe costs could be reduced by considering the cement sheath as a part of the casing string when collapse resistance was being calculated. More recently, Rogers4 has raised the question as to whether a cement sheath might be considered in the design for burst resistance of the cemented casing. Calculations have been made for the increased burst resistance a cement sheath would provide for casing in a wellbore, and the results show that a sizable amount of support could be obtained in some instances. These data are presented in addition to a discussion of several other factors that are considered to affect the burst strength of pipe supported by cement. Two types of support are treated: Case I for tensile loading of the unconfined cement sheath, and Case for compressive loading of the confined cement sheath. ANALYTICAL TREATMENT AND RESULTS CASE I—TENSILE STRESSES IN AN UNCONFINED CEMENT SHEATH Conditions like this would most likely occur in a greatly enlarged portion of the hole where the cement was not in immediate contact with either the formation or a thin and hard mud cake. The mathematical analysis for this condition, as shown in the Appendix, rests on the following concepts. Pressure inside a unit length of pipe causes: (1) a tensile or tangential stress to be exerted over the longitudinal cross-sectional areas of the pipe and cement; and (2) an equal amount of strain in both the pipe and cement that is uniformly distributed over the wall thickness of each. This analysis was then used to make several calculations for a cement sheath around 51/2-in. OD pipe. The results are illustrated in Fig. 1, which shows that a tensile stress of 500 psi is imposed on a 5-in. thick sheath when the casing contains a pressure of only 1,450 psi. It also shows that a 10-in. thick sheath would be stressed to 500 psi in tension when the pipe contained a pressure of only 2,350 psi. Alternatively, if the stress analysis is made by means of the Lame thick-wall cylinder theory, the inner fibers of the 10-in. thick sheath will be stressed to 500 psi in tension when the pressure in the pipe is only 990 psi. This, of course, reveals that an unconfined sheath is of little support to the pipe in burst; however, an entirely different result is obtained when the cement is confined between the pipe and formation.

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 J. B. Scott, J. L. Popham, H. F. Coffer, J. J. Reynolds

This paper concerns field experiments to define the areal extent, orientation and thickness of an artificial fracture in the Sacatosa field, Maverick County, Tex. The fracture was made by a sand-oil treatment of 176,-000 gal of lease crude containing a fluid-loss additive and 270,000 lb of 20-40 mesh subangular Poteet sand. The well was perforated with a jet gun, consisting of six shots in a single plane. Fourteen test holes were drilled at various locations around the fractured well. Drill-stem tests, Micro and Sonic Logs, coring and sampling of formation cuttings were used to determine the presence of the fracture in these holes. The test holes were drilled at distances up to 250 ft in a radial pattern around the fractured well. In addition to fracture areal extent and orientation, sand grain size before and after fracturing, erosion of perforations and fracture thickness were studied. INTRODUCTION The orientation,12 areal extent3, 4 and thickness5-9 of artificially induced fractures in reservoir rock by hydraulic means have been discussed in great detail in the oil industry in recent years. Methods for initiating vertical"' and horizontal" fractures have been tested in the laboratory and the field. Although the methods used give successful well stimulation, good field data on the physical characteristics of the fracture are lacking in the literature. It is recognized generally that properties of a fracture, such as thickness, sand placement in the fracture" and shape, may vary from reservoir to reservoir. This paper gives data on size, orientation and sand placement in a large fracture initiated in a single plane in Sacatosa field, Maverick County, Tex. It is not intended as a speculative study; rather, it is restricted to actual field data on fracture properties. No attempt is made to prove that the same type of fracture occurs in all wells. The field procedure was to drill 14 test holes at various locations around the fractured well. By employing several different testing techniques, the presence of the fracture and some of its characteristics were determined. These techniques as well as the results obtained are discussed in detail in this paper. DESCRIPTION OF FRACTURE TREATMENT N. J. Chittim Well No. 37-1, completed in the San Miguel No. 1 sand, Sacatosa field, Maverick County, Tex., was chosen for the field study. The San Miguel sand is a tight, well consolidated sandstone with an average porosity of 23 per cent. The permeability ranges from 0.1 to 10 md, with a median permeability of 2.3 md. The sand thickness averages 23 ft and is located at depths of 1,150 to 1,700 ft throughout the field.I3 The fracture treatment performed on Well 37-1 was as follows. 1. The well was drilled to a depth of 1,438 ft with native mud, and 51/2-in. casing was set and cemented to the surface. 2. The casing was perforated at 1,349 ft with a fracture-initiating jet gun. This gun consists of six shots, 7/16-in. diameter in a single horizontal plane. The jets were oriented in two groups of three, 180" opposed. The perforating device was designed to initiate a fracture perpendicular to the wellbore.

By H. J. Beach

This paper describes the properties and uses of cementitious mixtures containing 10 to 20 per cent bentonite and 2 per cent or more sodium chloride. Salt additions improve bentonite cement by increasing early strength and stabilizing viscosity without changing thickening time. The volume yield of cement is increased 20 per cent or more without lowered early strength. The unique properties of salt in this type of system make savings of more than 10 per cent possible where light-weight, low-strength cementitious material is adequate to fill behind pipe. The density range of these mixtures is 12 to 13 1b/gal and the filtration rates are medium-low, aiding the placement of long columns in primary cementing. Where available, sea water is an ideal salt source in preparing these slurries. INTRODUCTION Accelerators increase the rate of cement hydration. In speeding reaction with water, they can affect cement performance by reducing thickening time and increasing early strength after set. Accelerators that cause both effects can be considered "total", and those which produce only one effect can be called "partial". Materials that act conversely to accelerators are retarders. and they also can be total or partial. Partial retarders. make high-temperature cementing possible by prolonging thickening time while impairing early strength only slightly. Most known accelerators are total. A useful partial accelerator would increase strength without altering thickening time. This report concerns material combinations in which a normally total accelerator exerts unique partial properties. Utilizing these limited effects improves bentonite cement. SEPARATE EFFECTS OF SODIUM CHLORIDE AND BENTONITE ON CEMENT Sodium chloride and calcium chloride are commonly used in cement, and at low concentrations their effects are similar. Ludwig1 studied sodium chloride in API Class A and Class E cements.' Figs. 1 and 2 sum- marize his data taken at 140°F on slurry pumpability and early strength. Normal water-to-cement ratios are 0.46 and 0.40, respectively, for Class A and Class E cements. At saturation the salt content is 12 to 14 per cent of the weight of cement solids. The illustrations, therefore, cover the range of salt solubility in the mixing water. The data show that sodium chloride is a total accelerator of the Class E cement studied over the range of solubility. It is total in Class A cement to 6 per cent. Above this concentration salt becomes a retarder— partial from 6 to 10 per cent and total above. These results are general for different brands of Class A cement, although the shift from acceleration to retardation may occur at different salt concentrations for different temperatures. The results are specific for the Class E brand studied. In discussing his data, the investigator emphasized that different Class E cements might respond erratically to salt, depending on the brand chosen. Morgan and Dumbauld3 escribe the properties of bentonite cement in a paper that is a standard reference in using these systems. Bentonite functions in cement as an enabling agent; each bentonite addition equal to 1 per cent of the weight of dry cement makes possible the further addition of 4.5 per cent water.' Thus, 10 per cent bentonite in Class A cement, normally slurried neat with 46 per cent water, enables the slurry to contain another 45 per cent before settling. Water is one of the lightest and cheapest cement extenders; it reduces density and cost. Bentonite cements produce uniform slurries having low susceptibility to solids separation. After set, they offer low resistance to perforation.

By W. A. Walker, G. W. Ostroot

An increase in the number of deep wells being drilled where extreme bottom-hole temperatures are encountered, and the anticipated drilling of wells where temperatures in the range of 500°F or higher may occur, has brought about a comprehensive investigation of cementing materials and of the techniques involved in their proper usage at these elevated temperatures. Included are developments in cements, retarders, weighting materials and other cement additives which make it possible to formulate a variety of compositions to help resolve the cementing problems of these extreme well conditions. The problems associated with the selection and testing of cements are discussed, and a resume of field results is included. Previous studies on strength retrogression indicate that caution should be exercised in the selection of a cementing composition for use in high-temperature wells. It now appears that, by the addition of silica flour as a stabilizing additive to certain cements, compositions covering a wide range of slurry densities can be designed to meet extreme well conditions without strength retrogression. Improvements in cement retarders make it possible to produce a four-hour thickening time at static temperatures up to 500°F. This temperature is considerably higher than conditions presently being encountered in drilling and completion work. Inert weighting materials, used to produce 20-lb/gal or heavier cement slurries, are reviewed. INTRODUCTION As the search for oil continues, the number of wells being drilled to depths of 10,000 ft or below has continued to increase over the past decade. During 1959, there were 50,893 wells drilled in the United States for a total of 209 million ft of hole. Of this total, approximately 4.45 per cent were drilled below 10,000 ft and 0.30 per cent below 15,000 ft, with a record depth of 25,340 ft recorded (Table 1). With the drilling of this record-shattering hole comes the question, "How deep can wells be drilled?".' Limitations with respect to equipment (surface and subsurface), cementing materials and techniques would cause some concern; however, a panel of experts have agreed that the U. S. oil industry has the equipment and know-how to drill a 50,000-ft hole. The greatest deterrent would be the 700°F temperature they would anticipate encountering at this depth. Although the number of wells drilled under what is generally considered hot-hole conditions (230°F and higher) has been relatively high, each well often presents distinctly individual problems and requires separate consideration and selection of special materials, techniques and equipment. At the present time there are over 30 additives and special cements available for use in "tailoring" a cementing composition for a specific well. It is not uncommon to use three or four different additives with the basic cement to produce the desired slurry characteristics. A generally accepted procedure is to make laboratory tests on selected cementing compositions prior to pumping them into wells deeper than 12,000 ft, or where static temperatures are in the range of 260°F or higher. In some instances, it is recommended that laboratory tests be made where less severe well conditions are encountered. Prior to selecting a cementing composition for a particular well, key personnel representing the operator, drilling contractor and service company should meet to determine that each individual is acquainted with every detail which might influence cementing results and to discuss the execution of the job. For cementing hot-holes, a number of factors must be evaluated before proceeding with the operation. Consideration must be given to the following. 1. Thickening time—The slurry must remain fluid for a sufficient length of time to allow displacement down the casing and up the annular space in a primary cementing job or, in squeeze-cementing, adequate thickening time for both the build-up of a satisfactory squeeze pressure and the reversing out of excess cement. The thickening time of standard retarded cements will often be too short under extreme temperature conditions, thus involving special formulations and requiring laboratory tests to determine the proper amount of additional retarder to obtain the desired pumpability.

By K. A. Slagle

Hydraulic analysis of the wellbore has become increasingly inzportant for designing cementing operations and selecting equipment, materials and techniques to complenzent modern well-c-ompletion practices. Non-Newtonian fluid technology has advanced beyond the point where former empirical methods of analysis adequately define the hydraulic system and fluid properties. In view of these factors, this paper describes a series of rheological calculations which have been found practical, through field usage, for assistance in selecting a cementing program. A relatively simple laboratory method using standard viscometric equipment is suggested for determination of the rheological properties of slurries, and clrrta are presented on some of the more common cementitrg conzposition.A. A criterion for divergence from laminar-flow characteristics has been proposed. Usefulness of the calculations is indicated by examples of cementing operations where they have been used. INTRODUCTION With the changing aspects of well-completion practices during the past few years, it has been increasingly important to have a relatively simple method of analyzing the flow conditions existing in the well during cementing operations. This is particularly true in view of the improved economics toward which most of the changes have been directed. Rheological characteristics of slurries used for cementing should be a major consideration in the trend toward smaller casing sizes, either single or multiple strings. Receiving increased attention is the practice advocated in 1948 by Howard and Clark' of attaining turbulent flow with the fluids circulated during a primary cementing operation. While there may still be a difference of opinion concerning this technique, most available information indicates that superior primary-cementing results are generally obtained when high displacement rates are employed. Fluid properties of the slurry to be used must be available, as well as calculation methods, to determine what flow rates should be attained and the probable consequences in terms of frictional pressure and horsepower utilization. It would certainly be inappropriate to attempt high displacement velocities if sufficient pressure might be developed to create lost circulation. Since cementing slurries are non-Newtonian fluids, it is not possible to define their rheological or fluid properties by the single factor of viscosity and then make calculations for the quantities just described. Because the shear stress-shear rate ratio is not constant: it becomes necessary to establish at least two parameters for adequate fluid-flow calculations. It is not the purpose of this paper to delve into the mathematical development of non-Newtonian technology, nor to discuss the arbitrary classification system under which a single fluid may resemble two or three different classes depending upon experimental conditions. Rather, the intention is to present a useful series of calculations based on a concept applicable to both Newtonian fluids and to the preponderance of non-Newtonian fluids encountered in the oil-producing industry. Development of this approach was begun some 32 years ago,' and has most recently been brought to fruition by Metzner and his co-workers at the U. of Deleware. Some non-Newtonian fluids encountered in the petroleum industry, other than cementing slurries, have also had the benefit of this method of analysis."' The two parameters required to define the fluid are usually denoted by the symbols n' and K' and, for the purposes of this discussion, are called "flow behavior index" and "consistency index", respectively. These two slurry properties permit calculation of the Reynolds' number and the "critical" velocity, or the velocity at which departure from laminar flow begins. EXPERIMENTAL DETERMINATIONS The two principal instruments used for rheological studies are the pipeline (capillary-tube) viscometer and the rotational viscometer. When conveniently possible, a capillary-tube viscometer (where the pressure drop and flow rate of the material can be measured) is the better method for rigorous determination of the flow behavior index and consistency index for non-Newtonian fluids. With pressure-drop data at various flow rates, it is then possible to prepare a logarithmic plot of shear rate as the abscissa-shear stress as the ordinate. For fluids which do not exhibit time-dependency, these data will usually produce a straight line. The flow behavior index n' represents the slope of this line, while the consistency index K' becomes the intercept of this line at unity shear rate in accordance with the mathematical derivations associated with this concept of rheology. Due to the difficulties anticipated in maintaining a uniform, pumpable cement slurry for the time interval required to obtain measurements from the pipe viscometer, the n' and K' data reported herein were obtained using a direct-indicating rotational viscometer (Fig. 2). The

By P. B. Baxendell, R. Thomas

Work on the calculation of vertical two-phase flow gradients by Cia. Shell de Venezuela has been based mainly on the "energy-loss" method proposed by Poett-mann and Carpenter in 1952. The "energy-loss-factor" correlation proposed by Poettmann and Carpenter was based on relatively low-rate flow data. This correlation proved inapplicable to high-rate flow conditions. In an attempt to establish a satisfactory correlation for high rates, a series of experiments was carried out at rates up to 5,000 BID in Cia. Shell de Venezuela's La Paz field in Venezuela, using tubing strings fitted with electronic surface-recording pressure elements. As a result of these experiments a correlation between energy-loss factor and mass flow rate was established which is believed to be applicable to a wide range of conduit sizes and crude types at high flow rates (e.g., above 900 BID for 27/8-in. OD tubing). It is anticipated that the resulting gradient calculations will have an accuracy of the order of % 5 per cent. At lower flow rates the energy-loss factor cannot be considered as constant for any mass rate of flow, but varies with the free gas in place and the mixture velocity. No satisfactory correlating parameter was obtained. As a practical compromise for low flow rates, a modification of the curve proposed by Poettmann and Carpenter was used. In practice this was found to give gradient accuracies of approxirnately ± 10 per cent clown to flow rates as low as 300 B/D in 27/8-in. tubing. INTRODUCTION Production operations in Cia. Shell de Venezuela's light- and medium-crude fields are principally concerned with high-rate flowing or gas-lift wells. Under these conditions the analysis of well performance, the selection of production strings and the design of gas-lift installations are vitally dependent on an accurate knowledge of the pressure gradients involved in vertical two-phase flow. Initially, attempts were made to establish the gradients empirically as done by Gilbert,' but the results were not reliable due to scarcity of data over a full range of rates and gas-oil ratios. Several methods of calculation based on energy-balance considerations were attempted, but the computations were cumbersome and the results cliscouraging. In 1952 a paper was published by Poettmann and Carpenter' which proposed a new approach. Their method was also based on an energy-balance equation. but it was original in that no attempt was made to evaluate the various components making up the total energy losses. Instead, they proposed a form of analysis which assumed that all the significant energy losses for mutiphase flow could be correlated in a form similar to that of the Fanning equation for frictional 1osses in single-phase flow. They then derived an empirical relationship linking measurable field data with a factor which, when applied to the standard form of the Fanning equation, would enable the energy losses to be determined. The basic method was applied in Venezuela to the problem of annular flow gradients in the La Paz and Mara fields" This involved establishing a new energy-loss-factor correlation to cover high flow rates and, also, some adaptation of the method to permit mechanized calculation using punch-card machines. The final result was 1 set of gradient curves for La Paz and Mara conditions which proved to be surprisingly accurate. With the encouraging results of the annular flow calculations, several attempts were made to obtain a corresponding set of curves for tubing flow. Here, unfortunately, little progress could be made. The original correlation of Poettmann and Carpenter was based on rather 1imited data derived from low-rate observations in 23/8- and 27/8-in. OD tubing. It did not cover the higher range of production rates, and extrapolation proved unsuccessful. A new correlation covering high flow rates was required, but this proved to be extremely difficult to establish since tubing flow pressure measurements at high rates did not exist—due to the difficulty of running pressure bombs against high-velocity flow. The necessity for reliable tubing flow data increased with the development of the new concessions in Lake Maracaibo, where high-rate tubing flow from depths of 10,500 ft became routine. Thus. it was decided to set up a full-scale test to establish a reliable energy-loss factor for tubing flow conditions. A La. Paz field light-oil producer with a potential of approximately 12,000 B/D on annular flow was chosen. To obtain full pressure gradients, a special tubing string was installed which was equipped with electronic surface-recording pressure measuring devices,

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

Because of the extensive utilization of hydraulic fracturing for the stimulation of low-productivity wells, the two related problems of fracture design and evaluation have become economically significant and, as a consequence, helve motivated this investigation. The producing characteristics of horizontally fractured wells were studied to determine the fracture configuration that should be employed as the basis for the design of the treatment and to develop a method that can be used to establish the degree to which the design objectives have been achieved. The equations which describe the steady-state flow of a single-phase fluid into, and through. a finite-capacity fracture were solved numerically for an idealized reservoir-fracture model. The numerical results were used to obtain an apparent skin effect for each combination of the parameters considered. Based on the computed results, subject to the limitcitions implied by the assumptions that were made, the following general conclusions were drawn. 1. For a radius of drainage at least four times us large as the radius of the fracture, an apparent skin effect that is independent of the radius of drainage can be calculated. 2. The productivity of the hydraulically fractured system, relative to that of the unfructured well, can be determined from the apparent skin effect and can be used to establish design objectives. 3. In the evaluation of a fracture job, it is not Possible to determine both the radius of the fracture and its flow capacity uniquely from the apparent skin effect; an independent determination of one of the quantities is necessary. lNTRODUCTION Although hydraulic fracturing has been employed as a method for stimulating the productivity of literally hundreds of thousands of wells during the past 10 years, it is only in the last few years that improvements in fracture design1-6 and fracturing technique' have combined to increase the probability of obtaining a successful treatment to such an extent that the mechanics of the method may be considered to be standardized. From an economic point of view, however, two related questions must be satisfactorily answered before hydraulic fracturing can be used in the most profitable manner. The two questions are the following. I. For a particular well in a given formation, what are the optimum design specifications for the fracture treatment? 2. Have the design objectives been achieved by the fracture treatment? The significance of these questions has been recoguized, and some attempts to obtain answers have been made. Howard, et al,8 endeavored to determine the optimum treatment, based on maximizing profits, for any given formation; unfortunately, this work was based on a crude method for approximating the productivity of a well. Carter and Tracy9 utilized the same approximation to study the effect of fracturing on the behavior of a well producing by virtue of a solution-gas drive. Electrolytic models were used by van Poollen10 to investigate the variation in productivity due to fracturing; however, only a limited number of results were presented. Later, from the same model results, van Poollen, et al,11 attempted to justify an approximate expression for determining the productivity of a fractured well. It is quite apparent that there is a definite lack of the practical information necessary for specifying the optimum fracture configuration to be considered for design purposes. The only detailed attempt to develop a procedure for evaluating the result of a given fracture treatment appears to be that of van Dam and Horner.12 These authors described a technique for analyzing pressure build-down data, obtained immediately after fracturing, to determine the final fracture volume, the final fracture porosity, the fracture area, the fracture thickness and the in situ fluid loss of the fracturing fluid. While this approach should be useful whenever acceptable pressure measurements are available, it does not yield a value for the flow capacity of the fracture. Since the problems of fracture design and evaluation are inversely related, it should be sufficient to study the effect of the fracture configuration on the performance of a well. The primary objective of this investigation is to evolve a technique for computing the desired solutions. The secondary objective is to analyze these computed results in order to prescribe a method for evaluating fracture treatments. Because this study is exploratory in nature, its scope

By F. W. Schremp, J. W. Chittum, T. S. Arczynski

This paper describes a laboratory study of causes of external casing corrosion and the test work that led to the use of oxygen scavengers to prevent this attack. External casing failures are classified as water-line, casing-casing, collar and body failures. A corrosion mechanism based on principles of differential oxygen availability is developed that is consistent with facts known about each kind of failure. The field use of oxygen scavengers is depicted as a direct result of the laboratory study. A part of the paper is devoted to reporting on the field use of hydra-zine to control external casing corrosion. Results of field measurements made over a period of several years are presented as evidence of the efectiveness of the hydrazine treatment. The first conclusion reached is that the use of hydrazine materially reduces the cathodic protection requirements for treated wells. This result is interpreted to mean that a reduction is taking place in the amount of corrosion on the casing. Results indicate also that hydrazine shows its greatest usefulness within the first 12 to 18 months after a well is completed when pitting corrosion is likely to be most active. INTRODUCTION According to surveys sponsored by the National Association of Corrosion Engineers,' the cost of repairing casing leaks caused by external corrosion may exceed $4 million per year. In addition, well damage and lost production resulting from casing leaks probably costs the petroleum industry an additional $5 to $6 million per year. Concern about the cost of external casing corrosion led to an extensive laboratory study of factors causing this external corrosion and to the development of a new approach to its prevention. This paper presents a discussion of various causes of external casing corrosion, details of laboratory studies and the results of the field use of an oxygen scavenger in well cementing fluids to prevent the external corrosion of oil-string casing. Measurements on test wells over a period of several years show that cathodic-protection current requirements are greatly reduced when hydrazine is used in cementing mud. Reduction of current requirements can be interpreted to mean that removal of oxygen by hydrazine has greatly suppressed corrosion cells on the external surface of the casing and thereby, has reduced corrosion. To date, hydrazine has been used by the Standard Oil Co. of California in more than 200 well completions. KINDS OF CASING FAILURES A survey of a large number of casing leaks disclosed four types of external casing failures — water-line, casing-casing, collar and body failures. These types are identified largely by their location on the casing. Water-line failures are found just below the surface of water or mud in the casing annulus. Casing-casing failures occur on the oil string just below the shoe of the surface string. Collar failures are found in the threaded ends of casing joints where they are screwed into casing collars. Body failures may occur at any point on the body of a casing joint. Ex- amples of each kind of failure have some of the general characteristics that are shown in Fig. 1. Water-line failures usually result in the circumferential severance of an oil-string casing. The corrosive action causing a water-line failure usually is sharply defined and is limited to a short length of the casing. Casing-casing failures usually are accompanied by pitting corrosion distributed around the oil-string casing for distances up to 100-ft below the shoe of the surface string. Casing-casing failures may also sever the casing. Collar failures seem to start on the first thread at the bottom of recesses between collar and casing joint. Corrosion proceeds across the threads by what appears to be a normal pitting mechanism. Both casing and collar are severely attacked. Body failures are the result of highly localized pitting at any point on a casing wall. Besides the pit that perforates a casing, a large number of other pits usually are found along one side of the casing joint. The pits occasionally are filled with corrosion products consisting largely of oxides and sulfides.' Frequently, the mill scale is largely intact on the rest of the casing. Examination of a casing failure does not always reveal the cause of the failure. Frequently, the necessary details are destroyed when the failure occurs. For example, formation water flowing through a perforation at high velocity may enlarge the hole and destroy any remaining evidence of the cause of the failure. One way to obtain undistorted information about a failure is to study the nature of other pits on the casing in the vicinity of the failure. A study of such pits frequently suggests that they are characteristic of an attack resulting from the differential availability of molecular oxygen.

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

An effective production control system should maximise recovery of economic material from the resource. To do this, internal waste must be accurately delineated and efficiently removed. Achieving this is most difficult in low grade blocks just above and just below the cut off grade, where ore:waste separation follows assay or statistical, rather than geological boundaries. Difficulties arise from sampling errors, configuration of the economic mineralisation, and local variations in geology. Mine bench parameters and mining equipment size apply further constraints to the actual field separation of the ore from the waste. At BCL, management of the resource starts with an effective orebody model for planning, scheduling and ore:waste prediction. Ore production from each mining location is reconciled with concentrator tonnage and grade, and the reconciled grades are compared with the planning orebody model to highlight any Differences.

Jan 1, 1986

By A. B. Kinzel

IT has often been stated that the steel industry did no research or development work in the decades preceding 1920. If restricted to organized research on the quality and field of application of structural and engineering steels, this statement may be true. But the industry did conduct a vast amount of process research during this period, although some of the projects were not carried out as separate organized research programs. Securing a low cost of tonnage production was the sole problem receiving serious attention from the industry prior to 1920, and today this is still the major problem. Those in the industry deserve much commendation for the important increase in production capacity per dollar invested and for the markedly lowered cost of production. In recent years, a distinct change may be noted in the attitude of the steel industry toward research involving its product. With the advent of high-speed machinery both in the manufacturing and transportation industries, steel as a quality engineering material has come to the fore. In the past, high-quality carbon steels and alloy steels have been introduced over a period of years, largely at the insistence of the consumer and partly prompted by research carried out by those interested in the use of the alloys. The commercial introduction of these materials made slow progress.

Jan 1, 1935

By Larry A. Morris

The environmental impacts of industrial activities have become very serious concerns of the public over the past few decades. Not surprisingly, governments have responded with legislation and regulations to force industry to operate in a more environmentally responsible manner and, more recently, have prompted industry to initiate voluntary measures in response to specific environmental issues. The concept of Product Stewardship has evolved as a system or vehicle for the industrial sector to demonstrate an active concern about the environmental impact of their products, services and processes.

Jan 1, 1996

By Larry A. Morris

The environmental impacts of industrial activities have become very serious concerns of the public over the past few decades. Not surprisingly, governments have responded with legislation and regulations to force industry to operate in a more environmentally responsible manner and, more recently, have prompted industry to initiate voluntary measures in response to specific environmental issues. The concept of Product Stewardship has evolved as a system or vehicle for the industrial sector to demonstrate an active concern about the environmental impact of their products, services and processes.

Jan 1, 1996