Mitigation of Multiple Fractures from Deviated Wellbores

Abstract

Abstract While over six hundred Kuparuk A Sand wells have been hydraulically fractured or re-fractured successfully from deviated wellbores a number of wells in the field have not responded to the conventional fracture treatments. In these wells, the conventional design resulted in premature, near-wellbore screenouts, with low proppant placement. and consequently, poor productivity. A symptom common to each of the failed treatments was a near-wellbore friction pressure loss too high to be explained by perforation restriction or simple fracture twisting and turning. An extensive analytical study of hydraulic fracture initiation and propagation from deviated wellbores suggested multiple fractures as a mechanism to account for the abnormally high near-wellbore friction pressure loss and the reduction in fracture width. A model was developed (XFRAC) which correlates these responses to formation stress, wellbore parameters and treatment conditions. A counter-intuitive fracture treatment which employed lower pumping rates combined with higher viscosity fracturing fluids was designed to minimize the formation of multiple fractures and increase fracture width. This unconventional design has been successfully pumped in eleven wells which exhibited the premature screenout problem. Proppant placement was increased over ten fold with a tripling of post-frac production rates and a 35 percent increase in estimated recovery. Introduction The Kuparuk River Reservoir contains approximately 6.4 billion barrels of original oil in place. It is located on the Alaskan North Slope, approximately forty miles west of the Prudhoe Bay Field. The field produces from two physically independent sands of the Kuparuk River Formation, a lower Cretaceous, shallow marine sandstone. The productive sands are informally named the A and C Sand members. The C Sand overlies the A Sand and is highly permeable, having an average permeability thickness of 5000 md-ft. The A Sand is considerably less productive than the C Sand having an average permeability thickness of 1000 md-ft. The field was developed on 160 acre spacing, typically with 16 wells drilled directionally from a central drill site with stepouts of up to 7500 feet. With sixty-five percent of the Kuparuk reserves in the less permeable A Sand, it is desirable to fracture stimulate these wells to maximize rate and recovery. Conventional fracture stimulation treatments at Kuparuk have evolved over the years from small fracture treatments in the mid 1980's designed to overcome formation damage, to large refracture treatments employing tip screenout designs for true productivity improvement through the early 1990's. Despite the success of the fracturing program at Kuparuk, a few wells in some parts of the field stubbornly refused all attempts at fracture stimulation. In these wells, the conventional design resulted in premature, near- wellbore screenouts, with low proppant placement, and consequently, poor productivity. Typically, these wells had the largest stepouts and highest deviations and/or adverse wellbore orientation to the preferred fracture plane, but in other parts of the field, wells with these same deviations and orientations treated normally. Drill Site 2A was one of these problem areas. Fracture History at Drill Site 2A Production wells at The Kuparuk River Field Drill Site 2A have gone through three generations of fracture stimulation. Seven of the initial development production wells on the drill site had A Sand fracture stimulations prior to production. The objective of these jobs was to frac past the near wellbore damage due to drilling. Results of these initial fracture stimulations is summarized in Table 1. These seven stimulations used a gelled diesel fracturing fluid with silica flour as a fluid loss additive and had an average proppant placement of 3,700 lbm of 20/40 mesh sand. All of these jobs were pumped to completion. P. 331