ABSTRACT
The paper presents and discusses results of hydraulic fracturing simulations performed for a two-layered reservoir bounded by highly stressed formations. Each reservoir layer was 75 feet thick, separated by a 50 feet thick impermeable formation and bounded on the other sides by similar barrier formations. Stresses in each barrier formation was either 1200 psi or 600 psi greater than in the reservoir layers. Fractures were initiated either from the upper payzone or the highly stressed barrier separating the payzones. Two fracture treatment schedules were considered for the different fracture initiations. In the first treatment, only neat fluid was used; the second treatment incorporated proppant concentrations varying from 1 to 6 lb/gal after pumping 2880 barrels pad volume. For both treatments, Newtonian fluid, with 100 cp viscosity, was injected at a rate of 3 0 bpm for a total slurry injection volume of 7200 barrels. The calculated geometry and width profiles along the wellbore are provided on completing the injection. Fracture length, height, treatment pressure, and maximum opening histories are also presented. Contours of fluid fronts, proppant fronts, and proppant are demonstrated for one case.
The fracture initiated in the highly-stressed middle layer showed: (i) a bell shape fracture with lengths of 400 ft in both payzones but of shorter length in the middle layer at the early pumping stage, (ii) the fracture opening at the wellbore decreased as the fracture initially migrated into the low stress payzone and increased after the fracture reached the outer barriers, and (iii) a higher net fluid pressure was required to initiate the fracture in comparison to the fracture initiated in the payzone.
