Improving the Conductivity of Natu2Bl+ufKVT64fYCDGCLvJU8I/Q2LWion with Hydraulic Fracturing in Stress Sensitive Reservoirs. SPE 182306 By Alireza Keshavarz, Ray Johnson, Jr., Themis Carageorgos, Pavel Bedrikovetsky, Alexander Badalyan, Australian School of Petroleum, The University of Adelaide, Adelaide, Australia, 13 Oct 2016

The technology of injecting micro-sized proppant particles along with fracturing fluid is proposed to improve the conductivity of naturally fracture systems in stress sensitive reservoirs, by placing graded particles in a larger, preserved stimulated reservoir volume around the induced hydraulic fracture (Fig. 1). One of the main parameters determining the efficiency of the proposed technology is the concentration of placed proppant particles in the fracture systems. A laboratory study has been conducted to evaluate the effect of placed proppant concentration on coal permeability enhancement using injection of micro-sized proppant into coal core and varying effective stress. Permeability values are measured for different concentrations of placed particles as a function of effective stress (Fig. 2). There is an optimum concentration of placed particles for which the cleat system permeability reaches a maximum, further permeability enhancement is more sensitive to concentration of placed proppant at higher than lower effective stress (Fig. 3). The maximum permeability enhancement by 3.2 folds is observed at effective stress of 950 psi.

In a field application, the determination of all cleat apertures to optimize particle sizing will be difficult and unlike the core test, the effluent concentration cannot be derived once the fluid leaves the hydraulic fracture and travels into the cleat or fracture network. In some cases, the distribution and mean values for cleat or natural fracture aperture can be estimated from: physical core observations; imaging tools; and pressure transient tests to derive dual-porosity parameters; from these, a matchstick model for matrix blocks and regular fracture arrangement can be constructed.

In the field, pre-job estimates of fracture leakoff and stimulated reservoir volume can be derived from repeated, increasing pre-frac diagnostic fracture injection test (DFIT) volumes incorporating a hydraulic fracture simulator to derive a volume to leakoff area relationship. We can assume that a larger region of lower aperture leakoff may be beyond the tested region that may be discernable by surface deformation tiltmeter or microseismic monitoring. Thus, volumes and sizing of increasing graded particles could be derived and applied based on the area defined by pre-frac injection testing and the matchstick model derived from reservoir parameters.

In some cases, the fracture apertures cover the spectrum from centimeters to microns and cannot be discerned from near wellbore data. For these instances, a more detailed mathematical model for fractal geometry of the hydraulic fracture and the associated set of induced micro-fractures can be adopted, and the optimal injection schedule becomes one where the injected rate and the injected particle size and concentration are varied as a function of time and volume. The distinguishing feature of this optimized schedule is: the injection of larger particles with lower then higher concentrations over time; the filling of the far-field and thinner cracks first; then, the filling of larger and enlarged fractures nearer to the wellbore. In a similar manner to the first case, this type of model and optimized schedule can be developed using build-up and fall-off injectivity tests to fully characterize the fractal system.