Hydraulic fracturing in shale with H₂O, CO₂ and N₂

Slick-water fracturing is the most routine form of well stimulation in shales; however N₂, LPG and CO₂ have all been used as "exotic" stimulants in various hydrocarbon reservoirs. We explore the use of these gases as stimulants on Green River shale to compare the form and behavior of fractures in shale driven by different gas compositions and states and indexed by breakdown pressure and the resulting morphology of the fracture networks. Fracturing is completed on cylindrical samples containing a single blind axial borehole under simple triaxial conditions with confining pressure ranging from 10∼25MPa and axial stress ranging from 0-35MPa (σ₁ > σ₂ = σ₃). Results show that: 1) under the same stress conditions, CO₂ returns the highest breakdown pressure, followed by N₂, and with H₂O exhibiting the lowest breakdown pressure; 2) CO₂ fracturing, compared to other fracturing fluids, creates nominally the most complex fracturing patterns as well as the coarsest fracture surface and with the greatest apparent local damage; 3) under conditions of constant injection rate, the CO₂ pressure build-up record exhibits condensation between ∼5-7MPα and transits from gas to liquid through a mixed-phase region rather than directly to liquid as for H₂O and N₂ which do not; 4) there is a positive correlation between minimum principal stress and breakdown pressure for failure both by transverse fracturing (₃axial) and by longitudinal fracturing (₃radial) for each fracturing fluid with CO₂ having the highest correlation coefficient/slope and lowest for H₂O. We explain these results in terms of a mechanistic understanding of breakdown, and through correlations with the specific properties of the stimulating fluids.