This paper introduces a new CO2-hybrid fracturing fluid design that intends to improve production from ultra-tight reservoirs and reduces freshwater usage. The design consists of: (1) injecting pure CO2 as the pad fluid to generate a complex fracture network, and (2) injecting a gelled slurry (water- or foamed-based) to generate near-wellbore conductivity. The motivation behind this design is that while current aqueous fluids provide sufficient primary hydraulic fracture conductivity back to the wellbore, they under-stimulate the reservoir and leave behind damaged stimulated regions deeper in the fracture network. Much of that (unpropped) stimulated area is ineffective for production due to interfacial tension effects, fines generation, and/or polymer damage. We present simulation work that demonstrates how CO2, with its low viscosity, can extend the bottom-hole treating pressure deeper in the reservoir and generate a larger producible surface area. We also present experimental evidence that CO2 leaves behind higher unpropped fracture conductivities than slick water. This paper does not address the many operational and logistical challenges of using CO2 as a fracturing fluid. Rather, it intends to demonstrate the production uplift potential of the proposed design, which seems particularly attractive in reservoirs capable of sustaining production from unpropped fractures (e.g., reservoirs with low stress anisotropy, high Young's modulus, and a pervasive set of natural fractures).

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