Parent-child relationship is becoming a topic of high interest in the Permian Basin as more infill wells are being drilled at various times after the parent well has been produced. This paper uses an advanced modelling workflow to determine the impact of parent depletion on infill well spacing at various periods of the parent well production. As the parent well is being produced, constant well spacing based on virgin condition becomes problematic because pressure depletion around the well leads to change in stress magnitude and orientations. This change in reservoir conditions, is critical for planning infill well. Parent well depletion results in potential negative impact including: –Asymmetric fracture propagation from the child well into the depleted area around the parent well–Potential detrimental fracturing hits to the parent well These effects would potentially impair the production performance of both parent and infill wells, further reducing the overall pad efficiency of the pad completions. Parent well behavior is simulated using an unconventional fracture model (UFM), and the model is calibrated with available treating data. The resulting hydraulic fracture uses an advanced unstructured gridding algorithm that accounts for a fine complex fracture network along the lateral. A high-resolution, numerical reservoir simulator that combines the unstructured grid, rock physics, and reservoir fluid data is then used to match historical production data. The reservoir pressure depletion profile at various timesteps (6, 12, 24, and 36 months) is used as an input to calculate the resulting stress field state via a finite element model. The resulting updated geomechanical properties are used to simulate the infill well hydraulic fracture geometries at various spacing; subsequent unstructured grids are created and used to forecast production. Results are then compared to quantify the impact of depletion. –Initial reservoir pressure and horizontal stress reduce progressively with increasing time of production of the parent well; the average minimum stress change in the stimulated area reaches 18% decrease after 36 months of parent production.–Hydraulic fractures of infill wells grow preferentially towards the adjacent depleted area, reducing fracture extension in virgin rock by more than 60%.–Parent well depletion impacts fracture geometry and production performance of child wells.–Wells closer to the parent are more affected with increasing depletion time; these wells see up to 50% in production reduction as compared to the parent well.–At larger well spacing, little impact is observed due to limited interference between wells.–To help mitigate the impact of parent depletion on infill wells, an innovative spacing scheme that consists of using varying spacing on infill wells closest to the depleted parent well can be used. For this study and with current reservoir properties and completion design, if the parent well has been produced for less than 12 months, infill wells should be placed a least 750 ft away from the parent and at least 900 ft away for parent production beyond 1 year.
As the oil & gas industry enters into next phase of unconventional reservoir development, many new in-fill wells will be drilled in various shale oil and gas plays in North America. A detailed evaluation to devise an engineered approach for stimulating and completing these wells is critical to maximizing productivity. Challenging economics that prevail today have made it even more vital to perform such a study. This paper focuses on identifying optimum stimulation treatment design and completions strategy for the in-fill well. This work is a companion work to a paper presented by Gakhar et al. at the 2016 SPE/ CSUR Unconventional Resources Technology Conference (URTeC 2431182) on developing an engineered approach for multi-well pad development in Eagle Ford shale. Together these papers, serve as a comprehensive guide for multi-well pad performance optimization in unconventional reservoirs like the Eagle Ford Shale. An ‘advanced integrated modeling workflow’ is used to execute the complex study. The workflow involves building a 3D structural geologic model based on a vertical openhole pilot well log in Eagle Ford shale reservoir. A discrete fracture network (DFN) is built from 3D seismic data interpretation. Hydraulic fracture treatment pumped on a parent well is simulated using ‘unconventional fracture model’ (UFM). The UFM simulates complex fractures, while honoring the interaction between hydraulic fractures and natural fractures. A dynamic grid with unstructured cells is then created. Hydrocarbon production from the parent well is simulated for a period of 400 days. A geomechanical finite element model (FEM) based simulator that is fully coupled with a 3D numerical reservoir simulator is then used to calculate spatial and temporal changes in in-situ stresses. Dynamic reservoir properties in the 3D model are then updated and the child well, which is drilled 600 ft away from the parent well, is built into the model. The UFM is used to simulate an array of stimulation treatment designs and compare alternate completions strategies for the child well. The reservoir simulator is then used to compare production performance of the alternate strategies. Note that in this paper, the terms "in-fill well" and "child well" are used interchangeably. Extensive evaluation is carried out using the advanced integrated modeling workflow to achieve three key objectives. The first key objective is to determine an appropriate hydraulic fracturing treatment design for an in-fill well. Four hydraulic fracture treatment designs based on slickwater, delayed borate crosslinked gels, hybrid fluid treatments, and fiber based channel fracturing fluids for the in-fill well are compared. It has been found that under reservoir conditions specific to this study, the child well produces 22% more oil, if stimulated using the fiber based channel fracturing fluid than, if fractured using the slickwater. The second key objective is to compare the impact of refracturing and recharging the parent well prior to fracturing the child well. For the study well, refracturing increases oil production from the multi-well pad by 11% over the scenario, in which the parent well is recharged by injecting 43,200 bbl of water. The third objective of this study pertains to comparing the traditional plug-and-perf completions design with an alternate based on coupling plug-and-perf with a novel "sequenced fracturing" technique with a degradable fiber based fluid diversion blend for the child well. It has been found that by using the latest sequenced fracturing technique oil production from the multi-well pad can be increased by 14% over a scenario in which the child well is completed using traditional plug-and-perf design, despite pumping fewer stages on the well. The novel completion technique also greatly improves the efficiency of operation and provides significant savings on completions cost.
Production interference between parent and infill wells has become of utmost importance in unconventional reservoirs across the U.S. due to sub-par production performance of child wells as well as possible loss of production to the parent well. To mitigate production interference between parent and child wells, operators have applied various measures such as refracturing, repressurization of the parent well, and reducing child well stimulation jobs; these measures can be costly and yield mixed results. This study demonstrates the benefits of reservoir modeling to understand the effects of parent well production depletion on child wells at different well spacing as well as the use of successful mitigation strategies such as near-wellbore diverters and fracture geometry control to mitigate frac hits between wells drilled as close as 800 ft apart. A multidisciplinary integrated workflow was applied in a multiwell pad in the Bakken consisting of one parent and two child wells. The parent well was completed and produced for about 7 years, after which the two child wells were drilled 1,300 and 800 ft, respectively, on each side of the parent well. High-tier vertical logs were used to build a geomechanical and petrophysical model for the pad. The model was used for hydraulic fracture modeling and production history match of the parent well, after which the reservoir pressure depletion profile was used in a geomechanics simulator for an updated in situ stress state at 7 years. The updated stress state was then used for fracture modeling of the two child wells. The child well 800 ft from the parent well showed more hydraulic fractures directly hitting the parent well. The child well at 1,300 ft showed fewer hydraulic fractures directly hitting the parent well. The pressure depletion profile around the parent well had more negative impact on the child well at 800 ft away compared to the child well at 1,300 ft away because of its proximity. To eliminate this negative effect, fracture geometry control technology was used in the hydraulic fracture model for the child well 800 ft away from the parent well. It showed to be successful in reducing the occurence of frac hits to the parent well, diverting hydraulic fracture growth away from depleted regions around the parent well. During the actual operation, the results were confirmed with high-frequency pressure monitoring. Details of the field deployment of the fracture geometry control technology are discussed in detail in Vidma et al. (2019). No pressure communication was observed in stages pumped with the fracture geometry control technology. The child wells were completed and put on production without any sanding damage to the parent well, saving the operator approximately USD 400,000 and more than 2 weeks of deferred production if cleanout had been required. Actual production results showed superior performance in the child well at 1,300 ft away compared to the child well at 800 ft away. This confirms that the pressure depletion profile had more impact on the child well 800 ft away compared to the child well at 1,300 ft. Reservoir modeling is critical to understanding the level of pressure depletion in a producing well and its effect on child wells at different well spacing. It has also proven helpful in designing an optimum fracture geometry control pill to minimize the occurrence of frac hits that could damage parent well productivity.
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.
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