One of the more important aspects of any fracturing treatment is the proppant that is used. In some instances, particularly in deep well applications, the type of proppant used can make a difference between the treatment being an economic success or failure. As job size increases, the price of the proppant becomes a significant percentage of the proppant becomes a significant percentage of the overall treatment cost. This is especially true if the various high strength proppants are to be used. This paper deals with a fracture permeability study of many of the available low and high strength proppant materials. In each case, fracture proppant materials. In each case, fracture permeability is measured as a function of closure stress. permeability is measured as a function of closure stress. Using the apparatus described in this paper, the relative permeabilities of each proppant are obtained using identical testing procedures. Many current treatments incorporate both frac sand and one of several more expensive high strength proppants. For this reason, special emphasis is placed on test results obtained from mixtures of the high strength proppant and the more economical frac sand. proppant and the more economical frac sand. To illustrate the effect that various proppants or proppant mixtures have on the results obtained from a fracturing treatment, a computer analysis is made. The analysis will indicate the effect of fracture permeability on estimated production increase and the effect of proppant choice on the economics of the treatment. From this analysis and the permeability data reported, guidelines for the choice of a permeability data reported, guidelines for the choice of a proppant or mixture of proppants are set up for proppant or mixture of proppants are set up for shallow, medium and deep well application. Introduction The use of hydraulic fracturing, as a method for increasing well production, has risen significantly in recent years. This trend will continue as it becomes increasingly important to maximize the amount of oil or gas that can be produced from a given well. In the past, most pre-job planning centered around decisions concerning the type of fracturing fluid to be used or the pump rate and treating pressure to be encountered. Little, if any, time has spent on the choice or combinations of proppants to be used. As treatment costs rise, increased design time is being spent on all aspects of the treatment. Until recently, there have been relatively few significant changes in the proppants used in hydraulic fracturing. By far the most common proppant consists of a specially screened, high grade sand (usually 10–20 or 20–40 mesh). As well depths increased, it became apparent that higher strength proppants were required. The first such proppant to proppants were required. The first such proppant to gain widespread use was glass beads. Recent advances have resulted in the development of the new sintered bauxite proppant. In order to take full advantage of all the available proppants, it is necessary to determine certain well parameters, in particular, the amount of closure pressure exerted by the fracture faces on the proppant. Once this value has been calculated, the proppant. Once this value has been calculated, the permeability of the proppant at reservoir conditions permeability of the proppant at reservoir conditions can be evaluated and the economics of the treatment and its results estimated. Presented in this paper are the relationships between fracture permeability and closure pressures for the following list of proppants:10–20 and 20–40 Hickory Sand (Heart of Texas or San Saba frac sand)20–40 St. Peters Deposit (Ottawu or Gopher State frac sand)12–20 and 20–40 Glass Beads20–40 Sintered Bauxite100 Mesh Sand (Oklahoma #1)Mixtures of Hickory Sand and Glass Beads

Once a reservoir is hydraulically fractured, the fracture may experience several repeated production/shut-in cycles. Evidence of reduced rate of recovery as wells are placed back on production, has been noted in gas wells that have been exposed to this type of cycling. As the cycling process is repeated, the propped fracture undergoes the ups and downs of closure stress, resulting in a gradual reduction in fracture conductivity. To observe the phenomenon, a propped fracture using formation rock, was subjected to cyclic loading in the laboratory. Change in fracture conductivity with time and the number of cycles was measured. Interaction between proppant and formation rock was examined. One sand size and two synthetic proppant sizes were evaluated. Two formation rock types of different hardnesses were used in simulating the fracture. At the same closure stress level, fracture conductivity continuously decreased as the loading cycle is repeated. The amount of reduction in conductivity depended upon the rock hardness and proppant size. For the same hardness rock, the magnitude of closure stress dictated the suitable proppant size to minimize the cyclic effect. Thus, the combination of information obtained through this study is a tool to select a proppant to minimize the cyclic effect. Suggestions and optimum design criteria to circumvent or minimize the repeated shut-in effect are presented along with the test results. Introduction For a hydraulic fracturing treatment to be successful, proppants must be placed across the producing zone to provide an effective propped fracture. Reservoir size and characteristics will determine the type and amount of proppant to be used. Properly placed proppant in the fracture will support the closure stress to maintain fracture conductivity high enough for transporting reservoir fluids to the wellbore. Surrounding tectonic stress being constant, the closure stress upon the proppant starts to increase as the well begins to flow, gradually deteriorating the conductivity of the propped fracture. This is considered to be a normal occurrence. However, the effective life of a propped fracture may be shortened by production methods. One such method is production cycling. Many fracture stimulated gas wells are subject to occasional shut-ins of short or extended duration due to demand restrictions or other reasons. Experience has indicated that the stabilized production rate, following the shut-in, is lower than the previous rate at the same wellbore pressure. An analysis of pressure buildup data indicated that fracture conductivity continued to decrease following the subsequent shut-ins. Repeated production and shut-in of the fracture stimulated well will cause cyclic loading onto the proppant in the fracture, thus, resulting in the decreased width of the propped fracture with cycles. To study this phenomenon, laboratory experiments were performed with a simulated propped fracture. Formatiion rocks of the Rotliegendes and the Wilcox sandstone were propped with Ottawa sand (20/40 mesh) and Intermediate strength proppants (20/40 and 12/20 mesh Interprop TM Plus) and subjected to cyclic TM- Interprop TM is a trademark of Norton-Alcoa Proppants. P. 351^

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. 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 request 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 Gravel pack completions done with viscous carrier fluids and high sand concentrations have resulted in greater productivity for longer periods of time productivity for longer periods of time than have gravel pack completions carried out by conventional methods. Wells having a sand production problem, whether they are completed problem, whether they are completed with long open hole sections, inner liners, or perforated casing, have been successfully gravel packed with the highly viscous slurries. Deviated holes present no more problem than straight present no more problem than straight holes. Case histories and treatments used in gravel packing some of these wells in the California fields will be presented. The design application and presented. The design application and techniques used will vary from well to well, but the basic concepts of viscous gravel packing are always considered. These are to ensure clean permeable packs, to minimize intermixing of packs, to minimize intermixing of gravel with formation sand, and to provide adequate sand suspension for proper provide adequate sand suspension for proper placement of gravel. placement of gravel. Factors associated with the success or failure of viscous gravel packing will be discussed. Introduction Methods for controlling sand problems associated with oil and gas problems associated with oil and gas production have been of major concern in production have been of major concern in the industry. The presence of sand in a produced fluid may lead to erosion of equipment and eventual loss in production, due to sanding up of the well. production, due to sanding up of the well. Sand control systems utilizing conventional gravel packing procedures have been the basic method for control of formation sand production. Large volumes of fluids, such as brine water, muds, or low viscosity crudes, are used to transport 1 to 4 pounds per gallon of gravel at pump rates from 1 to 10 bbl/min. This procedure intended to create a gravel pack in the area between the slotted or wire-wrapped liner and the formation. Difficulties inherent to these treatment conditions often produce unfavorable results. produce unfavorable results.

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