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Creating a reliable, calibrated frac model used to be a long and expensive task in frac optimization. Today, with the proliferation of fracture diagnostics to calibrate models, simple frac dimensions can be calculated from indirect measurements on most North American shale fracs. Through the US Shale Revolution, fracturing operations have increasingly focused on pumping efficiencies. "Factory mode" operations today often allow little time for what used to be a lengthy optimization process of estimating fracture dimension sensitivity to job design changes for well placement selection and optimization of production economics. While some new fracture diagnostics have been designed to do measurements without interfering with frac operations, the calibrated models that harness these measurements remain cumbersome. We have developed a practical engineering tool that can extend the use of direct measurements to all shale horizontal well frac jobs. Unlike complex models that require lots of inputs and that are only routinely run on a few stages in a limited fraction of all North American shale wells, this Back-of-the-Envelope (BoE) model can be run effectively on every horizontal well stage. To date, it has been run on almost a quarter million stages. The BoE model provides two main advantages: (1) utilization of average basin diagnostic feedback and model calibration for more realistic results, and (2) augmenting more complex models on a much larger scale through a simpler workflow. The BoE model incorporates key fundamental processes in elliptical-shaped hydraulic fracture growth, including conservation of mass; limited entry-driven cluster distribution into simultaneously growing equal-sized multiple fractures; and Sneddon width profile with calibrated coupling over the fracture height. The physical model is further constrained by assuming a fixed half-length-to-height ratio from direct observation of hydraulic fracture growth. The BoE fracture model can be described with a few different rock mechanical fracture design and treatment parameters and ISIP measurements at the end of each fracture treatment stage. A key feature of the BoE model is that direct measurements are directly incorporated as an inherent calibration step. The model is anchored to basin closure stress measurements from DFITs and calibrated with past fracture geometry measurements, for example from Volume-to-First-Response data provided through Sealed Wellbore Pressure Monitoring (SWPM), or from other direct fracture diagnostics. In our paper, we present the results of this simple model and compare it with more complex fracture modeling efforts and fracture diagnostic results in a few major US shale basins.
Creating a reliable, calibrated frac model used to be a long and expensive task in frac optimization. Today, with the proliferation of fracture diagnostics to calibrate models, simple frac dimensions can be calculated from indirect measurements on most North American shale fracs. Through the US Shale Revolution, fracturing operations have increasingly focused on pumping efficiencies. "Factory mode" operations today often allow little time for what used to be a lengthy optimization process of estimating fracture dimension sensitivity to job design changes for well placement selection and optimization of production economics. While some new fracture diagnostics have been designed to do measurements without interfering with frac operations, the calibrated models that harness these measurements remain cumbersome. We have developed a practical engineering tool that can extend the use of direct measurements to all shale horizontal well frac jobs. Unlike complex models that require lots of inputs and that are only routinely run on a few stages in a limited fraction of all North American shale wells, this Back-of-the-Envelope (BoE) model can be run effectively on every horizontal well stage. To date, it has been run on almost a quarter million stages. The BoE model provides two main advantages: (1) utilization of average basin diagnostic feedback and model calibration for more realistic results, and (2) augmenting more complex models on a much larger scale through a simpler workflow. The BoE model incorporates key fundamental processes in elliptical-shaped hydraulic fracture growth, including conservation of mass; limited entry-driven cluster distribution into simultaneously growing equal-sized multiple fractures; and Sneddon width profile with calibrated coupling over the fracture height. The physical model is further constrained by assuming a fixed half-length-to-height ratio from direct observation of hydraulic fracture growth. The BoE fracture model can be described with a few different rock mechanical fracture design and treatment parameters and ISIP measurements at the end of each fracture treatment stage. A key feature of the BoE model is that direct measurements are directly incorporated as an inherent calibration step. The model is anchored to basin closure stress measurements from DFITs and calibrated with past fracture geometry measurements, for example from Volume-to-First-Response data provided through Sealed Wellbore Pressure Monitoring (SWPM), or from other direct fracture diagnostics. In our paper, we present the results of this simple model and compare it with more complex fracture modeling efforts and fracture diagnostic results in a few major US shale basins.
Significant attention has been placed on well-to-well interactions since the beginning of infill development in unconventional plays. Asymmetry of hydraulic fractures toward pressure-depleted parent wells has been attributed to poor performance of early in-fill completions (Xuyang et al., 2019). Factors include well spacing, timing, and specifics of colocation. Various operators have developed strategies to mitigate these effects and improve production for new spacing units. This paper reviews the historical response to parent–child well development in the Bakken, characterizes trends, and examines the techniques that have been applied and their efficacy. Results provide evidence that development decisions continue to be largely driven by surface constraints, suggesting there is more work needed to improve future child well performance. There is a trend away from refracturing for most operators, particularly as part of drilling spacing unit (DSU) redevelopments involving drilling of multiple child wells. Common mitigation techniques include fracturing the child well closest to the parent well first and increasing well spacing.
There is a large technological gap between the end of the frac and until operators accumulate long term production data to perform a meaningful lookback. Over the last 10 years flowback analysis (FBA) has emerged as a successful technology to address this problem by utilizing only commonly gathered production test data. FBA provides operators with a low-cost technology to perform rapid diagnostics and rapid lookbacks within days of opening the well to flow. In this paper, several case studies from prolific North America tight and shale plays will be presented to demonstrate the immense value of FBA for rapid diagnostics and rapid lookbacks. The presented case studies will focus on the interpretation of FBA results to identify hydraulic fracture optimization opportunities and improve future well performance. A new set of physics-based correlations are also demonstrated, which link effective stress (from DFIT), fracture area/stimulated volume (from FBA) and long-term pressure-normalized productivity, to extend the application of FBA to a large-scale field development. It allows operators to use extensive horizontal well base to predict and select optimal completion design ahead of pumping and to high grade the land base for full field development, forecasting and budget planning purposes. FBA is closing a significant technological gap in diagnostics methods from the time well has been completed to the time until we gather enough long-term production data to perform lookback or design evaluation. By integrating FBA diagnostics into hydraulic fracture optimization workflows, operators can promptly evaluate the efficacy of their fracture treatments and identify wells that are likely to underperform long-term within days of finishing pumping, enabling them to apply these insights to subsequent wells or pads. FBA provides results 6-12 months faster than other low-cost diagnostics (i.e. rate-transient analysis on long-term production data). By incorporating FBA into hydraulic optimization workflows, operators can quickly identify numerous commonly observed detrimental effects including small or unexpected fracture geometry, fracture skin damage, insufficient or degrading conductivity, and poor cluster efficiency. Through rapid diagnostics, operators are able to quickly identify optimization opportunities and drive their learning curve ahead of their capital spending.
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