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Abstract In previous frac designs, proppant tracer logs revealed poor proppant distribution between clusters. In this study, various technologies were utilized to improve cluster efficiency, primarily focusing on selecting perforations in like-rock, adjusting perforation designs and the use of diverters. Effectiveness of the changes were analyzed using proppant tracer. This study consisted of a group of four wells completed sequentially. Sections of each well were divided into completion design groups characterized by different perforating methodologies. Perforation placement was primarily driven by RockMSE (Mechanical Specific Energy), a calculation derived from drilling data that relates to a rock's compressive strength. Additionally, the RockMSE values were compared alongside three different datasets: gamma ray collected while drilling, a calculation of stresses from accelerometer data placed at the bit, and Pulsed Neutron Cross Dipole Sonic log data. The results of this study showed strong indications that fluid flow is greatly affected by rock strength as mapped with the RockMSE, with fluid preferentially entering areas with low RockMSE. It was found that placing clusters in similar rock types yielded an improved fluid distribution. Additional improved fluid distribution was observed by adjusting hole diameter, number of perforations and pump rate.
Abstract This paper presents a new methodology that takes readily available drilling data, to identify the location and relative magnitude of localized depletion that is likely caused by induced fractures that are intersected by a newly drilled well. This paper describes the process used to identify the fractures and presents a case study in the Utica Shale that validates the results. In recent years, mechanical specific energy (MSE) has been used to assess mechanical properties of rocks. It is further known that changes in reservoir pressure will also influence MSE. This new process analyzes a modified mechanical specific energy, and looks for anomalous increases in MSE, which should be present when drilling through a depleted fracture. To verify the existence of depleted fractures, a set of three wells were analyzed using this technique, a parent well, and two child wells. Analysis showed that there were no signs of depleted fractures detected in the parent well, while the two child wells both contained multiple drilling signatures that were consistent with depleted fractures. The location of the apparent depleted fractures in the child well were not only consistent with the location of the parent well, but also sections in the parent well that were most likely to create dominant fractures. The identified fractures in the child wells, also were consistent in location, magnitude and area of effect across both wells. These consistencies further promote the conclusion that dominant fractures created while completing the parent well, being penetrated and identified in both child wells. Based on the work done, there is clear indication that the proposed methodology can potentially be used to identify depleted fractures. This information can further be used in order to design completion strategies aimed at reducing both the probability and severity of parent-child fracture interactions such as frac hits. The paper presented will describe the first successful attempt to characterize depleted induced fractures using standard drilling data, without the use of any additional tools being run in the wellbore. This process will provide significant impact, not only in designing completions for parent-child well pairs, but will also further the understanding of far field fracture effects such as the extent of fracture extension, depletion around a fracture, and implications for well spacing.
Abstract It is a well-established principle that rock properties affect fracture geometry. This paper investigates the relationships between fracture responses observed during completion operations and rock properties that are obtained during the drilling of a well. It will also attempt to quantify the benefits of designing completions based on these rock properties. Four pairs of wells adjacent to one another are included the study. Each pair of wells includes one well with a completion design based on the operator's baseline guidelines, and one well with the perforation depths and stage boundaries selected from rock strength information derived from drilling data. The fracture treatment pressure responses are correlated to the rock properties, and the two completion methodologies are compared to determine whether there is an operational or production benefit to this completion methodology. The results of the study show a clear and distinctive difference between treatment responses in wells whose completions are based upon drilling-derived rock properties, and those that did not. The most striking of these differences is that instantaneous shut-in pressures were higher in wells where completion stages and perforation depths were selected based on rock properties, without corresponding increases in average treatment pressures. This is likely an indication of improved fracture containment (higher net pressures) which would be expected with an equitable fluid distribution among perforation clusters. Further to this, the analysis allowed for the identification of rock parameters associated with increased risk of excessive height growth which is independent of the completion methodology used. Production comparisons will be included to support the findings. The result of this work is a clear path forward to improving future wells by understanding how rock properties and completion design are related to fracture height growth. This allows for a re-evaluation of future drilling targets and the modification of treatment designs to maintain the maximum amount of fracture energy within the target zone. It will also help to provide further evidence that completions can be improved through the optimized placements of stage boundaries and perforation clusters. This paper will present a new analytical workflow that combines the use of drilling-derived rock properties and fracture treatment responses to gain important insights and drive future decisions for both the drilling and completion processes.
Abstract When hydraulically fracturing a horizontal wellbore with multiple perforation clusters, the fluid being pumped into the reservoir will preferentially take the path of least resistance. Perforations that are located in the lowest stressed rocks will take a larger amount of fluid, and those perforations located in highest stressed rocks will receive less, or in some cases none. One of the ways that engineers are trying to overcome these differences is the use of diverters. A fluid diverter is typically inserted at some point within a hydraulic fracturing pump schedule to seal off dominant fractures, allowing fluid to flow into under-stimulated fractures. The problem with this methodology is that without reservoir knowledge, operators rely on rules of thumb developed through trial and error to determine when and how much diverter to use. Data has shown how this methodology can be ineffective, leaving some clusters over stimulated and others under-stimulated. Anecdotal evidence also supports these concerns because equally sized diverter slugs do not always have equal pressure response. This paper will present a methodology currently in use that examines well heterogeneity, and designs the diversion strategy based on actual reservoir properties. Estimations of minimum insitu stress at each cluster are combined with estimates of stress shadow effect both from previous stages and between treatment clusters to determine at which pressure each cluster will accept fluid. This data is then used to bin clusters into primary clusters which will be treated first, followed by a diverter slug, then secondary and possibly tertiary clusters. The volume of diverter slug used will be proportional to the number of clusters within the previous bin. In addition to this, an engineered diversion strategy will look at the perforation design, fracture treatment design and pump rate. The result of this workflow is a tool that will maximize the effectiveness of diverters that will ultimately result in better producing wells at lower completions cost.