The use of 100 mesh sand in well stimulation is not new. What is new is the method of application to gain outstanding results in Permian Basin formations. Permian Basin formations. A year's history and field experimentation has given a positive insight on how best to use 100 mesh most effectively, especially the concentrations and volumes that seem best suited to the different formations. Optimum volumes have not been established with absolute certainty—and may never be; but field experience has established trends that should be designed into the jobs to assure the greatest probability of success.
The basic method of application is to hydraulically initiate or fracture into the formation with a pad fluid. Then, a slurry of 100 mesh sand is introduced which effectively reduces leakoff through any intersecting "hairline" cracks which are encountered. The 100 mesh does not restrict fluid travel down the principal fracture, and thus allows the subsequent fracturing fluid to extend the principal fracture to the desired distance into the reservoir. Once this hydraulic control is established, the principal fracture can then be propped with larger principal fracture can then be propped with larger frac sands, or the fracture faces of a carbonate rock can be etched with acid just as they are in conventional treatments. Therefore, this particular use of 100 mesh sand is primarily particular use of 100 mesh sand is primarily as an added conditioning step in the pad fluids of a stimulation treatment. In partially depleted zones which have been heavily acidized, it is necessary to use large volumes of 100 mesh sand in order to fill all the previously created void so that the new treatment can enter previously untreated portions of the zone. portions of the zone.
For a number of years, calculated penetrations for both acid and fracturing penetrations for both acid and fracturing jobs and consequently the folds of increase to be expected have not been achieved by actual well performance in our carbonate reservoirs. Many things were tried to correct this deficiency—such as higher or lower pump rates, more exotic fluids, more or different fluid loss materials, larger volumes, etc. Still, the actual well performance was most often less than that performance was most often less than that which is predicted.