In the Dan field, very high breakdown pressures were observed for wellbores drilled with a high azimuth with respect to the preferred fracture plane. The increased breakdown pressure was caused by significant near-wellbore friction. In scaled laboratory tests, variation in breakdown pressure was accompanied by a change in fracture geometry. Therefore, the variation in breakdown pressure in the field treatments could not be related simply to in-situ stresses.

This paper provides a framework for adding after-closure fracturing-pressure analysis to the pre-treatment calibration-testing sequence that defines fracture geometry and fluid loss characteristics. The after-closure period contains the reservoir pseudo-linear flow period that is the focus of this paper and the pseudo-radial flow period that has been previously addressed in a comprehensive manner. Considerations beyond linear-flow include the transition from linear-flow to radial-flow that permits extracting the fracture length; the synergy and validation provided by the various phases of a fracture calibration sequence; and application examples for a large range of reservoir parameters and conditions. The examples include a summary of the operational considerations and derived benefits obtained by extensive use of the analysis offshore Trinidad during a frac-and-pack campaign, and the paper concludes with a detailed analysis of the pumping, closing, and after-closure periods for a calibration ("minifrac") treatment during this campaign. A companion paper provides a detailed analytical-framework for the after-closure period. Reservoir linear-flow provides the remaining and missing link for the fracturing-pressure chain-of-events. This chain gives a continuum of increasing information about the fracture geometry, fracturing fluid, and reservoir with feedback to validate or question prior information. The proposed timeline of events (and information) begins with a small-volume injection (for closure pressure) and shut-in (for reservoir transmissibility and initial pressure); pumping the fracture calibration treatment (for fracture geometry characteristic); the shut-in closure-decline (for total fluid-loss coefficient and fracture length to validate geometry); immediately after closure (for separating the various fluid loss mechanisms and validating closure pressure); after-closure linear-flow (for spurt-loss and to validate fracture length); and in the case of high-permeability, transitional flow (for validating various parameter-combinations) and radial-flow (for validating reservoir transmissibility and initial pressure). The ensemble of calibrated and validated information provides all the prerequisite fracture and reservoir information for achieving an on-site economics-optimized design of the proppant treatment. Introduction Figure 1 shows a typical history of the fracturing pressure from the beginning of pumping until the reservoir disturbance from the fracture decays back to the initial reservoir pressure. Of particular importance for this paper is the last period of the pressure response, or the after-closure response noted on the figure as "transient reservoir pressure near the wellbore." A calibration test is generally performed without proppant and, therefore, retains negligible conductivity when it closes. The after-closure pressure behavior is independent of the physical properties governing fracture propagation and depends only on the previous spatial and temporal history of the fluid loss, the fracture length, and the reservoir parameters. The "late-time" behavior becomes pseudo-radial flow and provides reservoir transmissibility (kh/) and initial pressure in a manner similar to more traditional methods for a well test. The after-fracture-closure application of radial-flow has been comprehensively covered in two companion papers. The first paper by Gu et al. focused on application aspects, and the second paper by Abousleiman et al. focused on theoretical aspects. The latter paper also considered approximations for the "early-time" pseudo-linear flow regime. This paper and a companion provide a similar division of focus for after-closure linear-flow. The primary role for linear-flow is to define spurt, loss and validate information available from other parts of a calibration sequence. The following sections provide illustrative examples, a cursory review of the related literature, the role of numerical simulation, an outline for incorporating after-closure and its synergy with other phases of calibration testing, and conclude with a detailed example of a combined analysis for the pumping, closure, and after-closure periods of a calibration treatment. P. 333^

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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Placement of a propped hydraulic fracture in a horizontal well is dependent on several parameters. These parameters include topics such as reservoir conditions, drilling practices, and completion techniques. This paper outlines some of the practical considerations that must be accounted for during the placement of proppant in a horizontal well in describing a propped fracture treatment on an offshore horizontal well, the paper discusses treatment design considerations and verifies the operational and logistical improvements which can be made by utilizing a state-of-the-art stimulation vessel. INTRODUCTION Hydraulic fracturing of horizontal wells is often attractive for a formation where conventional wells driled in the vertical condition to require this type of treatment. The Dan field in the Danish sector of the North Sea is no exception to this philosophy. The field, discovered in 1971, is produced from the Tertiary Danian and Cretaceous Maastrichtian chalks, typified by high porosities (30%) and low permeabilities (1 md). Since the start of development, all conventional deviated wells in this field were fracture stimulated to improve productivity. However, post stimulation production results were disappointing. A feasibility study performed on application of horizontal wells in the Dan field concluded that horizontal wells were economically attractive only by fracture stimulating multiple zones in the drainhole section and maintaining appropriate zonal isolation.1–3 Therefore, in 1987 the operator commenced drilling of horizontal wells to increase the field's production potential. The initial Dan horizontal wells were stimulated with acid fracture treatments, the industry standard for a chalk reservoir. The placement of these treatments proved effective, however, the medium term production was limited due to the low formation integrity and consequent collapse of the induced fracture system. Propped fracture treatments replaced the acid treatments and the benefits to productivity were quickly seen. However, the placement of proppant into some of the Dan horizontal wells became difficult, and in some cases impossible. The difficulties in placement are attributed to several factors. Principal among these is the direction of the horizontal wellbore relative to the preferred direction of the induced fracture.4 The situation is further complicated by the varying nonconformities that can exist at the near wellbore area.5