Low Fluid Loss Research Articles

Overview of Current Hydraulic Fracturing Design and Treatment Technology-Part 2

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Hydraulic fracturing has played a major role in enhancing petroleum reserves and daily production. Fig. 1 portrays a simplified version of the "typical"fracturing process. It consists of blending special chemicals to make the appropriate fracturing fluid, then mixing it with a propping agent (usuallys and) and pumping it into the pay zone at sufficiently high rates and pressures that the fluid hydraulically wedges and extends a fracture. At the same time, the fluids carry the proppant deeply into the fracture. When done successfully, the propped open fracture creates a "superhighway" for oil and/or gas to flow easily from the extremities of the formation into the well. Note that the fracture has two wings extending in opposite directions from the well and that it is oriented more or less in the vertical plane. Other types (e.g., horizontal fractures) are known to exist. Some have been observed at relatively shallow depths [less than 2,000 ft (600 m)], but they comprise a relatively low percentage of the situations experienced to date. Hence, the discussion is directed primarily to vertical fractures. Fracturing technology requirements are multifaceted and are becoming more complex as our target formations get deeper, hotter, and lower in permeability. Fracturing state of the art over the past permeability. Fracturing state of the art over the past decade has changed continually to address the technological challenges that emerged with the development of massive hydraulic fracturing (MHF). This discussion covers much of the currently developing technology and the future needs for technological advances. Fracturing Fluids A fracturing fluid is used basically to:wedge open and extend a fracture hydraulically, andtransport and distribute the proppant along the fracture. The fluid(s) selected for a treatment can have a significant influence on the resulting effectively propped fracture length and fracture conductivity, as propped fracture length and fracture conductivity, as well a son the treatment cost. Fluid properties strongly govern fracture-propagation behavior and the distribution and placement of the propping agents. Fluids that leak off rapidly into the formation have a low efficiency in hydraulically wedging and extending a fracture. Fluid leak off also may leave an undesirable concentration of particulate residue in the fracture that could reduce fracture conductivity. The effective viscosity of the fluid controls the internal fracturing pressure and the propping agent transporting pressure and the propping agent transporting characteristics. Some desirable features of a fluid for most fracturing treatments include:low fluid loss to obtain the desired penetration with minimum fluid volumes;sufficient effectiveviscosity to create the necessary fracture width, and to transport and distribute the proppant in the fracture as required;no excessive friction in the fracture;good temperature stability for the particular formation being treated;good shear stability;minimal damaging effects on formation permeability;minimal plugging effects on fracture conductivity; plugging effects on fracture conductivity;low-friction-loss behavior in the pipe;good post-treatment breaking characteristics;good post-treatment cleanup and flow back behavior; and post-treatment cleanup and flow back behavior; andlow cost. JPT P. 853

Drilling Fluids for Highly Deviated Wells in North Sea Petroleum Drilling

Summary This paper reviews drilling operations at eight highly deviated wells in three North Sea fields, with emphasis on the use and engineering of drilling fluids to drill the wells and to maintain a stable wellbore until protective casing is set and cemented. Wells with angles deviated more protective casing is set and cemented. Wells with angles deviated more than 500 from vertical are considered highly deviated. The eight wells have an average angle of 560 and an average course length of 3300 m (10,827 ft). In most cases, angle buildup occurs in the measured-depth range of 600 to 1400 m (1,969 to 4,593 ft) at a rate of 20/30 m (98 ft). Figures showing a cross section of the well geometry and pertinent mud and drilling information are presented with each well study. Introduction Drilling fluids play an integral part in any drilling operation. Their main functions are (1) to lubricate and to cool the bit and drillstring, (2) to maintain hole stability (i.e., provide a gauge-size hole), (3) to carry drilled cuttings to the surface, and (4) to prevent the entry of subsurface fluids into the annulus.When a deviated well is drilled, Functions 1 and 2 warrant special consideration because the drillstring tends to lie along the underside of the slope formed by the well in the formations. The increased area of contact between the drillstring and borehole wall, and the increased force of contact as the angle becomes more severe, present the drilling and mud engineers with a challenge. Carrying capacity of the drilling fluid also merits particular attention because the vertical lifting power of the mud decreases as the angle of deviation increases and the cuttings tend to be rolled out of the hole along the low side rather than be lifted out.Pipe rotating torque and drag are important considerations when a deviated well is drilled. Factors affecting the amount of torque and drag are (1) dog-leg severity (in both the horizontal and vertical directions), (2) angle of deviation from the vertical, (3) bottomhole-assembly makeup (number, type, and position of stabilizers), (4) mud lubricity coefficient, and (5) hole stability (torque and drag become more severe if the hole becomes undergauge).Of these factors, the last two can be enhanced by mud engineering. Muds formulated with oil as the continuous phase (oil muds) have a very low lubricity coefficient, as shown by field results (Table 1). At the same time, oil muds provide a very stable borehole wall (especially in claystone) to provide a firm base or area of contact between drillstring/stabilizers and the formation. Also, oil muds have an inherently low fluid loss, giving added assurance against sticking because of differential pressure in underpressured permeable formations (especially produced zones). Most operators do not approve the use of oil muds in the produced zones). Most operators do not approve the use of oil muds in the North Sea until they have proved that water-base muds are unfeasible (too costly in terms of mud cost and drilling time) for drilling development wells through the strata overlying and within the oil field. Specialized products available to treat water-base muds to overcome the problems of products available to treat water-base muds to overcome the problems of drilling highly deviated wells include lubricant surfactants and solid-bead lubricants. These products have been applied with success. Most water-base muds now used for development drilling in the North Sea are inhibited with an electrolyte (potassium chloride, gypsum, lime, or, in some cases, seawater alone, which may contain sufficient electrolyte to inhibit clay hydration) and various types of polymer. The advantages of using efficient and sufficient mud-solids control equipment (maintaining a low mud-solids content without excessive dilution) are recognized by all operators. This is essential to maintain an effective and economical mud system, either water- or oil-base, for development drilling. JPT p. 703

The Sand Intensifier---Its Development And Application To Fracturing

Introduction A major deficiency in fracturing with foam or methanol carbon dioxide systems has been the limitations on sand concentration imposed by surface equipment. A Sand Intensifier has been developed to facilitate ultra-high sand concentrations. The development and field application of an initial prototype machine are discussed. Refinements and later developments have broadened the range of treating pressures and rates substantially, and thereby increased the number of wells that could be stimulated using intensified foam frac, Details of treatments and corresponding results described later indicate better performance than other fracturing techniques. Introduction The properties of foam have resulted in its widespread use as a fracturing fluid. Low fluid loss, low friction and excellent load fluid recovery are characteristics of foam documented in the literature(1.2.3). It has also been noted that foam has excellent sand-carrying capabilities(1.2.3). However, surface mechanical limitations have largely prevented utilizing this capability(3,4) and maximum concentrations to date have been 300 kilograms per cubic metre (2,5 ppg) of foam, At these concentrations, partial monolayers of proppant are usually deposited. In formations where crushing or embedment makes partial monolayer propping unsuitable, foam fracturing has not been successfully applied, Several techniques have been developed to overcome low concentrations in the fracture. One that has been widely used is combination foam liquid fracturing(4). Another is to gradually increase liquid rate near the end of the job. This decreases foam quality, increases sand concentration in the foam and provides a packed fracture near the wellbore. Alcohol mixed with carbon dioxide has been used to treat fluid-sensitive formations for many years(5). As with foam, a primary disadvantage of this type of treatment is low concentrations at the formation face and in the fracture. Work began three years ago on the process that would increase sand concentrations to facilitate packed fractures in foam and other fluids. The following discusses the development and field testing of a prototype Sand Intensifier, the application of such a tool to well stimulation and the results of treatments utilizing higher concentrations. Development Once the basic requirements of an intensifier were established namely to discharge 0.5 m3/min (3.1 BPM) outlet and to increase sand concentrations two or threefold, a low-pressure (1000 kPa or 145 psi) laboratory model was fabricated. Various configurations of rotor, seals and bearings, inlets and outlets were tested. Rotor speed and size were also varied. Tests such as that described in Table 1 provided enough encouragement to proceed with a high-pressure field prototype. By February 1978, adequate information had been accumulated to begin design of the high-pressure model. The machine was fabricated and laboratory tested in the spring of 1978, The first job was conducted on June 28, 1978, on the well CDC Retlaw 6-20-13-18-W4M, Field hookup was basically as described in Figure 2, with the exception that reflux water was piped to a separate tank, This meant that exact balances of water and sand could be made and the flowmeters double checked.

Combination Foam/Fluid Fracturing

Abstract This paper describes the newly developed combination foam/fluid fracturing technique, dealing with the objectives of the process" the equipment required, a typical sand schedule, the calculation for frac area, fluid cleanup procedures and, finally, the advantages of combination fracturing. The areal extent of a combination fracturing treatment is discussed in the Appendix, along with fracture capacity and the fluid co-efficient for foam. Introduction One of the most significant innovations in fracturing technology in recent years -was the development of foam as a fracturing fluid in the fall of 1973. First conceived and researched by Blauer et al.(1) as a thesis project at the Colorado School of Mines, the process was quickly recognized by the oil and gas industry as a technique with a number of advantages resulting from the unique rheological properties of foam. Foam is now widely used as a fracturing fluid, for stimulating productivity of oil and gas wells, with a high ratio of success.(2,3) "Combination Fracturing" was first introduced in February of 1977 as a further improvement of the Blauer form frac process, incorporating the best features of both foam and conventional fluid fracturing treatments in one job. Results of jobs performed to date indicate that Combination Fracs achieve equal or higher productivity increases than either foam fracs or fluid fracs alone. Description of the Process A Combination Frac is actually two different fracturing operations conducted in sequence on a' well first a foam frac, followed by a fluid fracture treatment. These two fracs are continuous, with transition from one type of operation to the other effected by increasing the pumping rates of the liquid and at the same time reducing the rate of the gas volumes pumped. The first stage of a Combination Frac is generated by treated fluids and a specific N2 ratio to develop 75% quality foam at bottom-hole conditions. The foam is injected into the well as the base fluid of the fracturing treatment, with sand being added at concentrations of 1 to 2 pounds/gallon of foam. The rheological properties of foam, including its excellent sand carrying properties and low fluid loss, are such that it develops a fracture of considerable areal extent reaching deep into the formation. In the second stage of a Combination Frac, the aeration and the foaming agent ratios are reduced. Simultaneously, the pumping rate is increased and sand ratios are increased to concentrations as high as 8 to 10 pounds per gallon. The increased viscosity of this fluid stage, combined with the increased rate, develops a greater crack width. This widening of the fracture, as? described in the Appendix, results in a higher flow capacity over the total frac area developed by the treatment. Objective of a Combination Frac The productivity of a well following fracturing is proportional to both the permeability contrast (flow capacity of the fracture in md-ft divided by the flow capacity of the formation in md-ft) and the extent of the fracture area, as illustrated in Figure I.

Prediction of Stimulation From Acid Fracturing Treatments Using Finite Fracture Conductivity

A method is presented for predicting stimulation ratios achieved from acid fracturing treatments of carbonate reservoirs. The method entails calculating acidized-fracture conductivities along the fracture from the acid-concentration profile and accounts for the amount of rock dissolved per unit area, the closure stress on the fracture, and the rock strength. per unit area, the closure stress on the fracture, and the rock strength. Introduction Acid fracturing is a technique commonly used to stimulate carbonate reservoirs. Acid, or a fluid containing acid, is injected into a well at a rate and pressure sufficient to fracture (crack) the formation. The acid flows through the fracture and reacts with the carbonate rock, partially dissolving it. When the treatment ends and the partially dissolving it. When the treatment ends and the fracture closes, a conductive channel remains through which reservoir fluids can flow. The degree of improvement (stimulation) of production depends on the length and conductivity of the acidized fracture. Recent research has led to more realistic modeling of acid fracturing treatments. However, these prior methods for predicting the stimulation resulting from an acid fracturing treatment do not include the effect of acidizedfracture conductivity. Rather, the fracture is assumed to be infinitely conductive to a distance from the wellbore where the acid is 10 percent of its initial concentration. This distance is usually referred to as the acid penetration distance. It will be shown that using acid penetration distance and infinite fracture conductivity is a good approximation for predicting stimulation from plain HCl fracturing treatments. However, assuming infinite conductivity gives much higher predicted stimulations for low fluid-loss, acid-external emulsions than are observed in the field. This paper introduces a method for predicting the stimulation ratio resulting from an acid fracturing treatment using finite fracture conductivity. The amount of rock dissolved along the fracture is calculated from the acid concentration profile. From the amount of rock dissolved, the strength of the rock, and the closure stress on the fracture, realistic acidized-fracture conductivities at various fracture lengths are calculated using relationships developed from laboratory data. From these conductivities, stimulation ratios are predicted and show excellent agreement when compared with stimulations observed in the field. These comparisons include both plain HCl and low fluid-loss, acid-external emulsion plain HCl and low fluid-loss, acid-external emulsion treatments. This improved predictive method is then used to compare equal-cost 15-percent HCl, 28-percent HCl, and low fluid-loss acid emulsion fracturing treatments under various conditions. Finally, techniques for improving acid fracturing treatments are examined. Results and Discussion Comparison of Predicted With Observed Stimulations Stimulation ratios predicted using the method detailed later in this paper showed excellent agreement when compared with observed stimulations from 31 field treatments. Data for these treatments are presented in Table 1, and Fig. 1 shows a plot of predicted and observed stimulation ratios. If predicted values were exactly equal to the observed stimulation ratios, the data points would all lie on the 45 deg. line. points would all lie on the 45 deg. line.The fit between theoretical model predictions and actual field observations was determined from a statistical analysis. P. 1186

Fracturing With Foam

Abstract Foam has been successfully applied as a circulating fluid for workovers and drilling for several years. Now a new oilfield application has been developed for foam: formation stimulation by fracturing. Over 150 wells have been treated to date in Canada using foam as the fracturing fluid, with a high degree of success. Unique 'rheological properties of foam make it well suited to this application: high sand carrying capacity, low fluid loss coefficient, low fluid friction loss, quick load fluid recovery low formation damage, and little or no reduction of fracture conductivity due to residual fluid saturation. The cost of the treatment is competitive with that of conventional systems. Introduction Fracturing of oil and gas wells involves the injection of a fluid into a well at a sufficient rate and pressure to physically rupture the rock down hole. A crack, or fracture, is developed and extended deep into the reservoir with continued fluid injection. Sand is carried in the fracturing fluid to prop the crack open when pumping is stopped, leaving a new, more permeable route for oil and gas to flow into the wellbore. Foam has recently been successfully used in place of conventional fracturing fluids, such as oil or water, for this process. The type of foam normally used is comprised of water, surfactants and a discontinuous gaseous phase of nitrogen. The volumetric gas content, referred to as "foam quality", is generally in the range of 65% to 95% under calculated downhole treating conditions: Equation (1) Available In Full Paper. Field Operations During a Foam Frac ™ treatment, water from a tank is continuously mixed with sand in a blender, at sand-water ratios progressively increasing to as high as 8 lbs/gallon. A surfactant, or foaming agent, is then proportioned into this slurry at a ratio of .2%; to 1.0%, and the resultant fluid blend is transferred to a high-pressure triplex pumper. High-pressure nitrogen gas is manifolded into the discharge line of the triplex, and it is at this point that the foam is developed. KCl, gellants or other chemical treating agents may be added to the base water if required to improve its compatibility with the reservoir rock or fluids. Figure 1 schematically shows this process. The blender and high-pressure pumper are conventional oilfield service equipment, modified to accurately proportion the high sand ratios pumped at slow discharge rates. The high-pressure N2 gas is also available from conventional oilfield N2 service units. Figure 2 illustrates an actual job in progress. The foam injection rates and volumes are in the order of 4 to 5 times those of the liquid pump rates and volumes at the blender because of the expansion by introduction of N2. These total volumes and rates are increased by a factor F, as follows: Equation (2) Available In Full Paper. For example, using a 75% foam quality, the foam injection rate will be 4 times the fluid pump rate at the blender.

Polysaccharide Derivatives Provide High Viscosity and Low Friction at Low Surface Fluid Temperatures

A relatively new, low-damage aqueous thickener with improved fracturing fluid properties is described. The polysaccharide derivative is effective in continuous mixing with low surface fluid temperatures and achieves high viscosity and low friction much more rapidly than conventional thickeners. Introduction Continuous mixing of gelled aqueous fracturing fluids is desirable because it reduces treating time and equipment and storage requirements, and eliminates batch mixing of large volumes of fluid that might not be used. In the past, the time required for conventional thickeners to achieve friction reduction and viscosity, particularly with cold fluids, has limited continuous mixing as a treating technique during cold weather and in shallow wells with low bottom-hole temperatures. New, low-residue polysaccharide derivatives have now been developed, however, that achieve high viscosity and low friction much more rapidly than conventional thickeners. For example, in 40 degree water, the new thickener can reduce friction up to three times more effectively than the conventional thickeners and can also provide viscosities up to four times greater. The advantages of low-residue fluids for minimizing damage and, hence, potential losses in production are discussed. The proper use and design criteria for low-residue systems are examined. Continuous mixing with the thickener permits using higher breaker concentrations to reduce shut-in times, thus providing faster, more effective well cleanup. In conjunction with the new gelling agent, additives such as clay control agents and new surfactants are used to shorten cleanup times by as much as one-half and to increase fracturing fluid recovery two to three times over conventional water-based treatments. It appears to be a growing opinion in the industry that short shut-in times for minimizing fluid retention may be a key to improved production by fracturing. History During the past several years, many new fracturing fluids have been developed. In many cases, these fluids met specific requirements such as high temperature stability, low formation damage, more rapid cleanup, or ultrahigh viscosity. Guar gum has been an effective gelling agent in fracturing fluids for many years. In most aqueous-base conventional fracture treatments, guar gum is still the thickener most commonly used. Guar gum generally meets the basic requirements of an efficient and economical fracturing fluid. Guar gum gives low friction pressures, good viscosity in a variety of brines, low fluid loss, pressures, good viscosity in a variety of brines, low fluid loss, and effective breakdown control following the treatment. The fluid-loss control of guar gum is particularly effective as compared with other aqueous thickeners. The major objection to guar gum has been an insoluble residue component that potentially could cause damage. Although petroleum guar products are more highly refined than other guar products, they contain almost 10 percent residue. Guar gum residue may or may not be detrimental to formation permeability or fracture conductivity, depending on conditions. permeability or fracture conductivity, depending on conditions. If damage occurs to permeability or fracture conductivity, the effect on productivity should be based on the well and treating conditions. Pye and Smith and Cooke have discussed the effect of guar gum and fluid-loss additives on formation damage and damage to fracture conductivity. JPT P. 1067

A New Hydraulic Fracturing Process

In this new fracturing method, high-viscosity fracturing fluids are used to obtain greater fracture length and width. The technique is characterized by higher propagation pressures and lower fluid loss at the fracture face. A film of water surrounding the fracturing fluid reduces friction losses in the tubing, and this lowers surface treatment pressures and pumping power requirements. Introduction A new method has been developed in which high-viscosity fracturing fluids are used for stimulating production from formations having a wide range of production from formations having a wide range of permeabilities. The fluids that have been used to date permeabilities. The fluids that have been used to date have ranged generally from about 500 cp to about 100,000 cp at ambient temperatures. The new method is used commercially under the names "Superfrac", "Super Frac", and "Super Sand Frac". The preferred fluids for use in the new method are loose water-in-oil dispersions or emulsions prepared by blending brine and a surface-active agent into a crude oil or petroleum fraction that has these high viscosities. When properly prepared, these emulsions will not readily change composition in the presence of free water. The emulsions are isolated from the inner wall of the tubing string or casing by a film of free water during injection and are generally pumped with about the same pressure drop as 1-cp oil or water. Studies indicate that the free water is lost to the formation after the fluids enter the fracture and that the high viscosity fracturing fluid remains behind for propagation of the fracture and placement of the propping agent. propping agent. This technique can be used to fracture any formation, but it has particular advantages when a large fracture conductivity ratio cannot be realized with small proppants, when thick or high-permeability formations are to be fractured, when a well must be fractured through small-diameter tubing or casing, and when proppant must be carried great distances from the wellbore. This paper gives the relationships of fluid viscosity to fracture geometry and proppant placement, establishes the advantages of using high-viscosity fluids for stimulating high- and low-permeability formations, and tells how the high-viscosity fluid system is maintained and pumps and Field tests have shown that excellent, sustained productivity increases have been obtained with this new hydraulic fracturing process. Fracture Geometry The use of very viscous oils as fracturing fluids has several benefits, including good fluid-loss control, increased fracture width, and improved sand transport. Fluid Loss Control Since Howard and Fast showed that the rate of fluid leakoff from a fracture depends upon the resistance of the invaded zone, the resistance of the filter cake, and the resistance of the compressible formation fluids, much of the work on fracturing has been directed toward the use of water-based fluids that can be injected at high rates and toward the development of better fluid loss control additives. Results to date indicate that gelled fluids and other water-based systems generally have low viscosities under the temperature and shear conditions existing in most fractures, and also that fluid loss control additives are normally much less effective under dynamic filtration conditions than they were once thought to be. Increased fluid loss can explain many of the difficulties encountered in conventional fracturing operations. JPT P. 89

The Application of Permanent Completion Techniques To Offshore Operations

Abstract To reduce the cost of workovers at offshore locations, several techniques using concentric tubing strings and/or wireline methods, and/or treatments (excluding installation of gas lift valves or acidizing) performed directly down the production tubing have been field tested. Low fluid loss cement slurries have been used to complete deeper below a single zone production packer by squeezing the existing perforations, washing out excess cement and perforating the new zone with an expandable gun. higher recompletions (both below and above a single zone production packer) have been successfully accomplished using the same principles. Sand production has been stopped through the use of epoxy resin solutions displaced either through concentric tubing strings or directly down the production tubing. Plugback operations using dump bailers have been disappointing, but further work in required before this method can be condemned. Results to date are encouraging, and open a way to reduce production maintenance costs at distant deepwater locations. Introduction The average oil or gas field occurring in the Miocene and Pliocene sediments of the offshore U. S. Gulf Coast contains multiple reservoir. Realizing maximum returns from investments requires optimization of two quantities:reduction of direct operating costs. andmaintaining all wells in a continuously producing capacity until all horizons are depleted. To attain this ideal, recompletion of depleted zones or, if economically feasible, the reestablishment of production from the existing completion must be undertaken at minimum cost and with a minimum of delay. During extensive development programs, primary drilling activity tends to take precedence over production maintenance which results in an insufficient number of deepwater rigs being available for the work at hand. While capital expenditures for new development may enable production to maintain an over-all upward trend, production from older fields frequently declines to a level that is lower than necessary because deficient or off-production wells have not been worked over promptly. Rig availability is not the only factor responsible for such delays. The cost of moving an offshore rig into a field is high (between $10,000 and $50,000, depending on the length of the move and type of rig). Single well workover programs may not be economical and it is often necessary to accumulate a series of projects before a profitable workover program can be attempted. To help in solving the problems created by these restraints, workover operations using permanent completion techniques have been adapted for use at marine locations. In this paper, permanent completion techniques are defined as remedial operations which can be conducted without physically disturbing the original downhole mechanical condition of the well. This type of workover involves the use of concentric macaroni tubing strings and/or wireline methods and/or treatments (other than installation of gas lift valves or acidizing) performed directly down the production tubing. Small rigs or pulling units capable of handling the necessary tubular equipment and easily installed on well jackets or platforms are available with little delay at relatively low cost. The small units usually work 12 hours a day, handle tubing in singles and can be installed on location for about $5,000. Research into cement technology has developed low fluid loss slurries which retain fairly constant properties throughout their entire pumping time. Physical properties of such cements enable them to be pumped safely through small openings and small diameter (3/4 in. ID) work strings. Successful recompletions above and below existing perforations have been made, sand controls installed and repaired and small milling operations undertaken. These procedures have resulted in the profitable acceleration of recompletions at reduced costs and the restoration of production from sanded up wells. They have also enabled high-risk recompletions to be attempted in zones which, but for these lower cost techniques, would have been abandoned without testing. Permanent completion workover operations offer attractive economic advantages over conventional methods and enable high risk zones to be exploited. JPT P. 1031ˆ

Non-Plugging Emulsions Useful as Completion and Well-Servicing Fluids

Abstract The development and use of nonplugging emulsions has provided a solution to certain problems associated with completing and reworking wells which have plagued the industry for years. In the present work emulsions free of insoluble solids have been developed for use in wells with temperatures up to 250°F and with pressures requiring densities up to 12.5 lb/gal. They possess the required properties of a satisfactory fluid for completing and reworking wells; they are non-plugging, they exhibit a low fluid loss, and they have a controllable density. Non-plugging emulsions have been used in approximately 200 completion and well-servicing operations. They were positioned to cover the interval to be perforated or to protect existing perforations during workover operations. Comparative data from several wells show that the productivity indices of wells perforated in the emulsions were substantially higher than the productivity indices of offset wells perforated in mud or water. Fewer difficulties in servicing wells and in getting wells back on production were experienced when emulsions were used as protective fluids to prevent water or mud from contacting exposed formations. In one field, the use of emulsions as perforating fluids has reduced the incidence of expensive sand control measures. Precautions should be taken to avoid contamination of drilling muds and cements by the emulsions. Contamination can be avoided in most operations by following careful placement procedures. Introduction Research conducted during the past few years has demonstrated that perforations are often plugged by debris from the perforator, pulverized sand from the formation, and mud solids when drilling mud is in the casing at the time the perforations are made. This plugging of perforations causes numerous problems in the completing, producing, and repairing of wells. For example, low well productivity, sand production, premature gas or water production, and failure of squeeze-cementing jobs are but a few problems recognized as being aggravated by plugged perforations.