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 (s1> s2 = s3 ). 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 CO2pressure build-up record exhibits condensation between &126;5-7MPa 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.


Hydraulic fracturing is a mature completion technique which has been extensively applied in tight and unconventional gas reservoirs. For unconventional reservoirs such as shale with extremely low permeability, long horizontal laterals with multi-staged hydraulic fractures are necessary to deliver economic production. The introduction of hydraulic fractures significantly increases flow rate because of large surface contact area between fractures and the reservoir, enhanced permeability around the wellbore, and reduced fluid diffusion lengths (King, 2010; Vincent , 2010; Faraj & Brown, 2010).

Water-based fluids have become the predominant type of fracturing fluid. Sometimes N2 or CO2 gas is combined with the fracturing fluids to form foam as the base fluid. Other additives can also be combined with N2 or CO2 to improve the efficiency, eg. coupling solids-free viscoelastic surfactants (VES) with a carbon dioxide (CO2)-emulsified system to further enhance cleanup in a depleted reservoir, extend the application to water-sensitive formations, and maintain reservoir gas saturation to prevent any potential water blockage (Hall, et al., 2005); or incorporating low-polymer-loading carboxymethyl guar polymer and a zirconium-based crosslinker to minimize the damage and maximize production (Gupta, et al., 2009). For unconventional reservoirs in arid areas the availability of water is sparse. In these cases, N2, liquefied petroleum gas (LPG) or CO2 may become an "exotic" option for stimulation fluid. For example, fracturing with CO2 has been used in places such as Wyoming where carbon dioxide supply and infrastructure are available (Bullis, 2013).

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