Breakdown pressure and fracture surface morphology of hydraulic fracturing in shale with H 2 O, CO 2 and N 2

Abstract

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.

Empirical Modeling of the Viscosity of Supercritical Carbon Dioxide Foam Fracturing Fluid under Different Downhole Conditions

“…The matches between the experimental data of the foam apparent viscosity and the viscosity data predicted by the modified power law model (Equation (10)) are shown in Figure 8. Figure 8 depicts that the experimental data of the foam apparent viscosity is in good agreement with the predicted values using Equation (10). Figure 8.…”

“…A modified power law model that incorporates the effect of shear rate and dimensionless pressure was obtained by substituting K and n values, given in the equation below: (10) where c1, c2, c3, d1, d2, and d3 are the parameter coefficients whose values can be obtained by applying nonlinear regression based on the measured viscometric data shown in Figure 6 using Equation (10). Table 3 includes the parameter estimates of this equation.…”

“…where c 1 , c 2 , c 3 , d 1 , d 2 , and d 3 are the parameter coefficients whose values can be obtained by applying nonlinear regression based on the measured viscometric data shown in Figure 6 using Equation (10). Table 3 includes the parameter estimates of this equation.…”

“…Validation of Equation (11) with experimental data of apparent viscosity obtained 1750 Psi. The models presented in this paper (Equations (6), (10) and (11)) are valid for foam flow in pipes or wellbores; however, it would be difficult to extrapolate these results inside porous media due to different pore-level mechanisms. Apart from fracturing treatment design and fracture simulation studies, these models can also be used as a quick screening tool for optimization of surfactant formulation at different reservoir conditions, which may provide information about surfactant performance for foam generation.…”

Fluid Injection Experiments in Shale at Elevated Confining Pressures: Determination of Flaw Sizes From Mechanical Experiments

“…In anisotropic shales, failure geometries can be more complex. Li et al () observe fail along the bedding planes and normal to the borehole direction in their Green River oil shale samples, while Rutter and Mecklenburgh () observed short opening mode fractures connected by bedding‐parallel shear mode segments in 60‐mm‐diameter samples of Whitby mudstone. Warpinski et al () performed fluid injection experiments into cuboid samples featuring machined joints and found a complex dependency of the fracture propagation on parameters relating to the joints, including joint orientation, spacing, and frictional properties.…”