The placement of a propping agent in hydraulically created fractures is a more adequate basis for predicting the folds of increase after a job. This is based on the premise that all unpropped areas of the created fracture eventually heal. Thus, the penetration of the prop pack into the reservoir and the amount of fill-up in the fracture determine the stimulation results. INTRODUCTION PRESENT METHODS of predicting the results of stimulation treatments are based on the productivity index ratios developed by McGuire and Sikora(1) (Figure 1). The predicted folds of increase are in relation to the conductivity ratio before and after fracturing and the penetration of the producing formation. This assumes that the propping agent supports the entire area of the hydraulically created facture(2). Although the industry has recognized for some time that the propping agent neither penetrates the full length of the fracture nor gives complete fill-up, the complexities of describing the placement of the prop have prevented using this feature in the treatment design. Limited use has been made of the settling-rate method for describing the extent which the prop pack penetrates the vertical fracture. The quotient of the vertical extent of the fracture and the settling rate gives the maximum time the prop is suspended by the fluid. The product of this time and the velocity of the fluid in the fracture gives the maximum distance the prop penetrates the fracture. Stokes Law can be used to predict the settling rate in Newtonian fluids, but is not applicable for non-Newtonian or power-law fluids. Kerns(3) et al. and Babcock(4) et al. have made studies on the transport of prop in vertical fractures, introducing the term ?equilibrium velocity' to the industry. Equilibrium velocity is the minimum linear velocity required to keep the prop moving through the fracture. A comparison of the settling-rate method and the equilibrium-velocity method is illustrated in Figure Z. However, as is known, little has been done toward using these methods for predicting the placement of prop in the fracture. One reason for this is that most of the fluids employed in these studies have been Newtonian, and the majority of the fracturing fluids are non-Newtonian. For this reason, a study was undertaken to expand the available information on commonly used fracturing fluids, such as gelled water. Laboratory tests were run in a plexiglas model of fixed, but variable, fracture width. The simulated vertical linear fracture was 2 ft in height by 6 ft long. Fracture widths were variable from 0.1 to 0.5 inch. Prop-laden fluids passing through this fracture exhibited the same general phenomena. While pumping down the pipe, the prop is fairly evenly dispersed in the fracturing fluid. However, as the fluid 'turns the corner, going into the fracture, centrifugal force and gravity concentrate the prop in the fluid moving through the lower part of the fracture. The bulk of the prop moves along the bottom of the fracture, as a fluidized bed.

Recent studies under downhole conditions show the relationship between foam texture, i.e., bubble size and foam rheology. They also show that under the low shear conditions that exist in a fracture during treatment, foams behave as power law fluids. Dynamic fluid-loss testing indicates ·stabilized foams are some of the more efficient fracturing fluids available.Formation damage results help explain why foam-fractured wells clean up so well.As a result of our better understandi ng of the properties of foam under downhole conditions, we have developed new, highly stable foam systems. These systems a re 100 to 1000 times more stable than conventional foams and, therefore, greatly broaden the downhole conditions under which foams can be used.Fi el d results demonstrate the successful pl acement of large amounts of proppants with stable foams in both oil and gas wells at temperatures up to 300°F. In addition, foam-fractured wells clean up better and, therefore, payout faster than we 11 s fraced with conventional fluids.

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This paper was prepared for the Society of Petroleum Engineers of AIME Symposium on Formation Damage Control, to be held in New Orleans, La., Feb. 7–8, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Mixtures of calcium bromide, calcium chloride and water provide a solids-free brine with densities up to 15.1 ppg. For the first time gravel packing, sand consolidation and other types of workovers can be done with clear non-damaging fluids having these very high n-sities. Like calcium chloride, the calcium bromide-calcium chloride mixtures have very natural corrosion rates. These rates can b lowered by the addition of an inhibitor. Acid soluble additives to reduce fluid loss and increase viscosity are available to modify these heavy brines for use in almost any well situation. In addition, they are both toxicologically and ecologically safe to use. Data showing the properties of calcium bromide-calcium chloride brines and brines modified with additives will be presented. The ways these heavy brine systems may be used to solve well problems will also be discussed. Drilling fluids are often used to maintain control during perforating, completion, or workover operations. When these fluids are used opposite highly permeable zones, extensive or even irrepairable formation damage can result. Such damage can be minimized or overcome by use of new heavy brine completion fluids weighted with calcium chloride and calcium bromide. Introduction Drilling fluids are formulated to plate out and plug the formation face so that only small volumes of fluids are lost during drilling. The filter cake formed from many drilling fluids is frequently difficult if not impossible to remove. The fluids themselves are sometimes highly alkaline and pH may be as high as 12–14. This causes precipitation of insoluble hydroxides along the filtrating path. The point is that drilling fluids are primarily designed to increase drilling efficiency. The technology of these fluids is well advanced and as a result drilling is faster, requires less horsepower, and in some cases permits drilling to progress under conditions which would have been impossible to overcome a few years ago. While strides have been made to reduce the damage drilling fluids do to the producing zone, nevertheless some of the properties intentionally built into these fluids are diametrically opposed to the ideal properties of a completion or workover fluid. Drilling fluids are also used as packer fluids.

This paper describes a new, fast, simplified procedure for determining fracture conductivity at downhole stresses. The embedment and crushing of proppant between rock samples from a specific formation are measured at closure stresses. The conductivities of fractures propped with various proppants can be determined rather quickly. As a result, the procedure can supply information useful in determining optimum fracture treatment for a specific well. In the new procedure, samples of formation and proppants are placed in an appropriate confinement chamber. Closure stresses are applied and fracture conductivity can be calculated. A proppant data base obtained using a modified Cooke2 conductivity test unit includes permeabilities, porosities and fracture widths measured over a range of closure stresses. These properties are dependent upon the type and amount of proppant tested and the stress applied. Fracture porosity determinations can be made in a short time with a relatively small investment in equipment. Core preparation and testing time require a few manhours per test. The paper includes examples of permeability and surface areas of conventional proppants. Fracture conductivity determinations, made with a variety of formations and proppants, indicate how this procedure can be useful when making decisions concerning fracture treatment design. An improvement in equipment design is also presented. The use of a Hoek11 triaxial cell as a fracture porosimeter allows the application of both closure and confining stresses, thus more closely simulating downhole conditions.