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Abstract Uniformity of proppant distribution among multiple perforation clusters affects treatment efficiency in multistage fractured wells stimulated using the plug-and-perf technique. Multiple physical phenomena taking place in the well and perforation tunnels can cause uneven proppant distribution among multiple clusters. The problem has been studied in the recent years with experimental and computational fluid dynamics (CFD) methods, which provide useful insights but are impractical for routine designs. Simplified models that incorporated the proppant transport efficiency (PTE) correlation derived from the CFD results in a hydraulic fracture model have been also presented in literature. In this paper, we present a numerical model that simulates the transient proppant slurry flow in the wellbore, considering proppant transport and settling including bed formation, rate- and concentration-dependent pressure drop, PTE, and dynamic pressure coupling with the hydraulic fractures. The model is efficient and is designed to be an independent wellbore transport model so it can be integrated with any fracture models, including fully 3D and/or complex fracture network models, for practical design optimization. The model predictions are compared and found to agree with previously published studies. Parametric studies demonstrate sensitivity of proppant distribution to grain size, fluid viscosity, and pumping rate for fixed perforation designs. Analysis of the simulation results shows that the dominant cause of uneven proppant distribution is proppant inertia. Possible slurry stratification is less important, except for the cases with relatively low flow rates and near toe clusters. Accordingly, proppant distribution is less sensitive to perforation phasing than to the number of perforations in clusters. Alterations of the number of perforations per cluster within a stage enable achieving more even proppant distribution.
This paper investigates the effect of variable perforation configurations on proppant transport, settling, and distribution across different perforation clusters in multistage horizontal wells. The results are compared to other previously published data (
It commonly assumed that the injected proppant is distributed evenly across the perforation clusters and that the distribution of fluid and proppant is identical. However, this research shows that this is not always the case. The results show uneven fluid and proppant distributions between clusters when altering the perforation configurations, injection rates, and proppant concentrations. Sieve analysis also shows different size distribution of the settled and exited sand through different clusters and individual perforations. Such information is beneficial to understanding transport in horizontal, multi-stage completions and how such impacts the overall treatment efficiency.
Abstract The correlation between reduced stage spacing (RSS) and increased well performance is well documented in unconventional plays, as is the propensity for heel-ward bias within the treatment of each stage. The authors postulate that RSS is effective because it results in a more uniform proppant distribution along the length of the lateral, and while it improves well performance, it also increases completion costs. This study proposes a more effective and cost-neutral way of achieving uniform proppant distribution by using an optimized variable shot cluster (VSC) perforating scheme to ensure all perforations are treated, and to alleviate heel-ward bias. The objective of this study is to design a VSC perforating scheme that provides the same production uplift as RSS, and potentially more uniform fracture half-lengths by preventing uncontrolled half-length growth associated with dominant clusters taking the majority of the treatment. A downhole camera was utilized on multiple wells to inspect perforations for evidence of erosion and perform a semi-quantitative ranking of the amount of proppant which passed through each perforation. Multiple VSC perforating schemes were observed to help ascertain which variables control the distribution of proppant along the length of a stage. Results demonstrate that effective flow area (EFA) is the controlling factor that determines which perforations will accept fluid and proppant. In nearly all stages, perforation efficiency is 100% until such a point is reached where beyond that point, perforations do not accept significant volumes of proppant. Limiting the number of perforations to the treatable EFA is required to ensure all perforations in a stage are treated, and an arithmetic model is constructed for the calculation of an appropriate VSC perforating scheme to promote uniform proppant distribution among each cluster. A cost-effective and tangible method is presented to evaluate uniformity of proppant distribution. Uniform cluster treatment and proppant distribution has the opportunity to replace less direct and costly practices such as RSS, diverters, etc. for improving well production, and has the added benefit of potentially limiting outsized fracture half-length growth associated with dominant clusters. This study was performed in the Marcellus Shale, but generally applies to all unconventional plays where plug-and-perf slickwater hydraulic fracturing treatments are utilized.
Abstract Monitoring of multi-stage hydraulic fractures in unconventional reservoirs has shown that some fractures are more effective and productive than others. Stress shadowing, in addition to reservoir lateral heterogeneity, are two potential factors behind this phenomenon. The focus of this study is to find the optimum hydraulic fracture spacing that aims to reduce the stress shadowing effect and ensure placement of hydraulic fractures in the best quality reservoir rock along the horizontal lateral. A base hydraulic fracture model was created for a well in the Eagle Ford reservoir. Fiber optic distributed acoustic sensing (DAS) data were analyzed to find the individual perforation cluster contribution to production based on the total proppant placed in each cluster. The modeled well cluster contribution and production data were then matched with actual data. Reservoir and geomechanical properties for certain stages of the horizontal wellbore were altered from the base model to address the effect of rock quality lateral variations. Four scenarios of 57 ft, 76 ft, 100 ft, and 142 ft spacing between perforation clusters were investigated to address the effect of stress shadowing. The sensitized reservoir and geomechanical properties include matrix permeability, Poisson's ratio, and Biot's coefficient. Increasing the matrix permeability from a base value of 0.2 ?D to 2 ?D caused the flowing fracture lengths to increase by 69%, 68%, and 48% in the heel, middle, and toe clusters, respectively. Stages with higher Poisson's ratio of 0.33, compared to a base value of 0.28, created larger flowing fracture lengths by 32% and 41% in the heel and middle clusters. Altering Biot's coefficient resulted in the same effect on flowing fracture lengths as altering Poisson's ratio. Overall, the rate of increase in flowing fracture lengths as a response to changing these properties was found to be more pronounced in the heel and middle clusters but less evident in the toe clusters. As for the cluster spacing scenarios, simulations showed that tighter spacing scenarios yielded a larger fracture network volume due to the higher number of clusters. However, these created fractures were less conductive than the ones created with wider spacing scenarios due to the stress shadowing effects. Production runs showed that scenarios with more accessed reservoir volume via more perforation clusters yielded a larger cumulative production over a 30-year simulation period.