Slick-water fracturing is the most routine form of well stimulation in shales; however N 2 , LPG and CO 2 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 to 25 MPa and axial stress ranging from 0 to 35 MPa (r 1 [ r 2 = r 3 ). Results show that: (1) under the same stress conditions, CO 2 returns the highest breakdown pressure, followed by N 2 , and with H 2 O exhibiting the lowest breakdown pressure; (2) CO 2 fracturing, compared to other fracturing fluids, creates nominally the most complex fracturing patterns as well as the roughest fracture surface and with the greatest apparent local damage followed by H 2 O and then N 2 ; (3) under conditions of constant injection rate, the CO 2 pressure build-up record exhibits condensation between *5 and 7 MPa and transits from gas to liquid through a mixed-phase region rather than directly to liquid as for H 2 O and N 2 which do not; (4) there is a positive correlation between minimum principal stress and breakdown pressure for failure both by transverse fracturing (r 3 axial) and by longitudinal fracturing (r 3 radial) for each fracturing fluid with CO 2 having the highest correlation coefficient/slope and lowest for H 2 O. We explain these results in terms of a mechanistic understanding of breakdown, and through correlations with the specific properties of the stimulating fluids.

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