In this work, we modeled double- and triple-cluster 3D hydraulic fracturing in a single-layer, quasi-brittle shale formation using planar CZM and XFEM-based CZM including slit flow and poro-elasticity for fracture and matrix spaces, respectively, in Abaqus. Our fully-coupled pore pressure-stress Geo-mechanics model includes leak-off as a continuum-based fluid flow component coupled with the other unknowns in the problem. Having compared the triple-cluster fracturing results from planar CZM with those from XFEM-based CZM, we found that the stress shadowing effect of multiple hydraulic fractures on each other can cause these fractures to rationally propagate out of plane; this also demonstrates the advantages of the second method compared to the first one. We investigated the effect of this arbitrary propagation direction on not only the fractures’ length, aperture, and the required injection pressure, but also fractures’ connection to the wellbore. Depending on the spacing and the number of clusters per stage, this connection can be gradually disrupted with time due to the near-wellbore fracture closure which may embed proppant particles on the fracture wall, or screen out the fracture at early stimulation times. Comparing all studied cases, we concluded that the double-cluster, simultaneous fracturing with 100-ft spacing provides the most viable fracture set for long-term production.


Shale gas resources have profoundly contributed to the prospective independence of the U.S. on oil and gas from foreign resources. The abundant condensate gas production and export from the U.S. shale resources have significantly contributed in the global sharp oil price decline since August 2014 [1]. These resources are known as ultra-low permeable, organic-rich formations with desorption of gas as a major but slow-rate and long-lasting producing mechanism. Economic production from these resources through gas desorption requires a complex network of natural fractures connected to the producing horizontal wellbores by hydraulic fractures in multiple stages, the most common stimulation technology in shale gas reservoirs. The geometry of hydraulic fractures (length, height, aperture, and propagation pattern) significantly contributes to long-term gas production and is inspected roughly by post-fracturing data acquisition methods such as tiltmeter fracturing mapping and micro-seismic monitoring [2]. This later method, however, cannot identify opening-mode or hydraulic fractures since the only detectable events using this method are shear slippage events. The technical restrictions on the hydraulic fracture data acquisition, the limitation on the extendibility of a successful fracturing job data to the other fields [3], and the high cost of re-stimulation plans, if possible, urge to develop numerical tools for optimal hydraulic fracturing design. Furthermore, due to the occurrence of cap rock and shale gas reservoir in close proximity and the environmental concerns about ground water contamination by fracturing jobs, the induced fractures need to be cautiously placed in order not to propagate into the upper and lower geological layers. Such a rigorous hydraulic fracture design in shale rocks demands numerical optimizing tools which should also be versatile for a variety of shale formations in mineralogy and stress state and capture increasingly more complex fracture networks than expected in these resources [2, 4]. Furthermore, a long-term optimum fracture spacing depends on not only the above parameters during fracturing, but also the fluid phase behavior during production in the commonly identified gas condensate windows in shale resources such as Eagle Ford [5], which is out of the scope of our geo-mechanical study.

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