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 nearwellbore 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. FIELD IMPLEMENTATION OF PROPPANT SLUGS TO AVOID PREMATURE SCREEN-OUT OF HYDRAUUC FRACTURES WITH ADEQUATE PROPPANT CONCENTRATION SPE 25892Simple Phenomenological Model of TortuosityThe phenomenon of tortuosity, in our adopted terminology, is that of a convoluted pathway connecting the wellbore to the main body of the fracture(s) further away from the wellbore. Schematics of the concept are shown in Figs. 1 and 2, but these represent the process only in a simple conceptual way, which may (be expected to) have an infinitely-variable form. However, the result is a major effect on wellbore pressure during fracturing z . The causes of near-wellbore tortuosity may also be (expected to be) many and variable, as we discuss later (e.g. in the context of perforation strategy) but we group them, for convenience, into two sources:

This paper presents the results of extensive technical and statistical analyses of more than 650 matrix stimulation jobs. Seventy-eight failures were identified with absolute reliability by second stimulations successfully repeated on the same pay zones of the same wells. Only one significant parameter of the stimulation design differentiated the first failed stimulations from the second successful ones. This paper illustrates these failure/success factors and gives novel field-stimulationresponse graphs.

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 nearwellbore 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. FIELD IMPLEMENTATION OF PROPPANT SLUGS TO AVOID PREMATURE SCREEN-OUT OF HYDRAUUC FRACTURES WITH ADEQUATE PROPPANT CONCENTRATION SPE 25892Simple Phenomenological Model of TortuosityThe phenomenon of tortuosity, in our adopted terminology, is that of a convoluted pathway connecting the wellbore to the main body of the fracture(s) further away from the wellbore. Schematics of the concept are shown in Figs. 1 and 2, but these represent the process only in a simple conceptual way, which may (be expected to) have an infinitely-variable form. However, the result is a major effect on wellbore pressure during fracturing z . The causes of near-wellbore tortuosity may also be (expected to be) many and variable, as we discuss later (e.g. in the context of perforation strategy) but we group them, for convenience, into two sources:

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Perforations provide the communication between wellbore and formation resulting in a communication path both for injected and produced fluids from the reservoir. Many perforation parameters such as shot phasing, charges size, shot density, type of gun and length of interval play an important role in the correct execution of a fracturing job. Those parameters have to be engineered to guarantee easy formation breakdown, minimize near wellbore restrictions (or tortuosity) and be big enough to prevent proppant bridging while considering fracture treatment size, proppant concentration, proppant size and treatment flow rate. Ideal fracture initiation perforations would create a minimum injection pressure initiating a single fracture (not for shale gas reservoirs) and generate a fracture with minimum tortuosity at an achievable fracture initiation pressure. Best perforation practices are important during the decisional and designing phase but have to be confirmed by field experience even in well known reservoir where formation heterogenity, well deviation, local stress anomalies, cement bound and many other factors can result in unexpected behaviors that could compromise the success of the stimulation treatment. In the following paper a briefly description of perforating theories and different field experiences are reported showing test results executed for a better perforation strategy. Unexpected deviations both from theory recommendations and from field analogies were analyzed as well as successful and unsuccessful remedial solutions in cases of injectivity issues.