Premature screen-outs and/or low proppant concentration are the most likely cause of failure in hydraulic fracturing treatments. Although commonly blamed on a variety of presumed problems—most typically the treating fluid, or large-scale reservoir conditions, such as permeability or stress profile—the true source of most problems has been uncovered only recently by careful analysis of treatment data. The source is referred to as near-wellbore tortuosity, but it can variously arise from deviatoric stress, natural fractures and/or perforation-dominated creation of complex fracture patterns in the wellbore vicinity.
Numerous theories have been formulated to deal with near-wellbore screen-outs and, especially for oriented wellbores from Arctic or offshore platforms, various perforation strategies have been postulated and/or implemented. In contrast to the idealizations and costs associated with those theories and strategies, this paper presents simple cheap solutions that are less sensitive to the wellbore environment This novel strategy involves injection of proppant slugs into the near-wellbore region and, when necessary, immediate shut-ins upon small slugs, with three important results: the response of the near well-bore region can be measured and characterized; a large part of the near-wellbore tortuosity can be removed, by simplifying the near-wellbore fracture pattern; and the true nature of the large-scale reservoir response can be determined, e.g. from the greatly modified pressure fall-off obtained after placing slugs near the wellbore.
The paper reports the concept and implementation, in a number of commercial fracturing environments, in both gas and oil reservoirs, with both foam and liquid-gel jobs. These show the effective removal of tortuosity varying from 20 to 200 bars and associated elevation of allowable proppant concentrations.