As the inventory of single well pads in North American unconventional plays builds up, some critical questions that need to be answered are: What is the optimum spacing for an in-fill well? Where new multiple in-fill wells should be drilled? How should the in-fill wells be fractured? Challenging economics associated with unconventional reservoir development demands for an engineered approach for such multi-well pad development unlike traditional trial and error approach that has been widely adopted by Oil & Gas industry. The engineered approach for evaluating the problem relies on expanded seismic-to-stimulation workflow (Cipolla et al. 2011). The workflow involves complex fracture modeling that honors impact of natural fractures on hydraulic fracture geometry, dynamic reservoir simulation and geotnechanical finite element modeling (FEM) to compute spatial and temporal changes in in-situ stresses due to production from parent well, which chronologically is the first well drilled on a pad. The new integrated workflow used in this evaluation involves the following key steps: A 3D structural geologic model based on a vertical openhole pilot well log in Eagle Ford shale reservoir is built. A discrete fracture network (DFN) representative of the area of interest in the reservoir is created from 3D seismic data interpretation. The parent well stimulation treatment is then modeled using 'Unconventional Fracture Model', (UFM) (Kresse et al. 2011). An unstructured production grid (Malpani et al. 2015; Ejofodomi et al. 2015) with finer cell size along the complex fractures is then created. Hydrocarbon production from the parent well is modeled using dynamic reservoir simulation, and a geomechanical FEM based simulator is then used to calculate spatial and temporal changes in in-situ stress magnitude and orientation (Morales et al. 2016). The modeling workflow is used to evaluate scenarios for multi-well pad optimization in Eagle Ford shale play. In this paper terms "in-fill" well and "child" well have been used interchangeably. This study evaluates two critical cases. Case 1 focuses on identifying optimum well spacing for an in-fill well that is to be drilled next to the parent well with a production history spanning a little over a year. Child wells drilled 400 ft., 600ft., and 800 ft. away from the parent well are simulated under similar conditions to identify optimum well spacing. Case 2 focuses on four multi-well pad development scenarios in which multiple wells are drilled in configuration A and B at different stages of field development and in areas with minimum and severe impact of kaolinite and smectite rich altered ash beds (Calvin et al. 2015) on vertical conductivity of hydraulic fractures. In multi-well configuration A, two child wells are drilled 600 ft. and 1200 ft. away from the parent well in B1-B2 (Donovan et al. 2010) unit of the lower Eagle Ford. Whereas, in configuration B wells are stacked in different lithostratigraphic sections of Eagle Ford. One of the child wells that is 600 ft. away from the parent well is landed in shallower section, B3-B5 and the second child well is landed 1,200 away in B1-B2, the same section of the Eagle Ford where the parent well is landed. It is important to note that results from this study are applicable to sections of Eagle Ford, where B unit is less than 150 ft. thick. For regions of Eagle Ford shale play, where B Units can be as thick as 300 ft., a similar comprehensive analysis is required to derive an effective multi-well pad development strategy.
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