Many studies have been performed to identify chemical additives that will aid shale stability in large volume slick water fracturing treatments. Most of the targeted shale formations have a very low permeability, do not experience conventional leakoff and do not contain high amounts of swelling clays such as smectite, leading to a perception that the shale is not water sensitive. However, recent laboratory evaluations have shown that not all shales are stable in fresh water, destabilizing with fresh water contact and releasing fines which could potentially result in formation damage and reduce net fracture pack conductivity.Previous studies of the ability of inorganic salts, temporary clay stabilizers, and permanent polymeric based clay stabilizers show that some of the common hydraulically fractured shales encounter stability problems when contacting fresh water. The studies have revealed that cationic polymeric permanent clay stabilizers improve the stability of the water sensitive shales. However, polymeric shale stabilizers are not without potential detriments. Polymers can lead to formation damage by blocking pore throats and reducing permeability. Additionally, the use of cationic polymers can limit the use of other chemical compounds used in treating fluids that may not be compatible with the cationic charge. This paper will compare a non-polymeric permanent clay stabilizer to conventional cationic polymers, temporary clay stabilizers, and inorganic salts and demonstrate equivalent and, sometimes, improved performance. Laboratory data from shale stability (roller oven), capillary suction time (CST), and regained permeability (core flow) studies will be presented demonstrating the efficacy of this new compound. Shales selected for the study will include standard Pierre shale and a variety of commonly hydraulically fractured shales from North America. Additionally, chemical compatibility testing will demonstrate the benefits of the new compound over conventional cationic polymeric clay stabilizers.

This study aims to demonstrate the true benefit of an innovative salt tolerant high viscosity friction reducer (HVFR) that excels at promoting extended proppant suspension and vertical distribution into the fracture when it is used as a base fluid for the Capillary Bridge Slurry (CBS) and other conventional fracturing fluid systems in combination with nitrogen. The completion of super-lateral wells now being drilled in tight oil and gas shales in North America, with record lengths close to 4 miles, demand for greater carrying capability of low viscosity (slickwater) fracturing fluids, where significant sand settling can occur before the proppant even reaches the fractures. This has sparked recent interest in the development and application of salt tolerant polyacrylamide-based friction reducers, referred to as High Viscous Friction Reducers (HVFR). The downfall of these first generation HVFR's is the lack of compatibility with high salinity brines such as recycled and flowback water, and diminished ability to reduce friction pressure during hydraulic fracturing treatments when compared to industry standard FR's. Herein, we report the field application of a unique salt tolerant HVFR (HVFR-ST), that consistently provides higher viscosity values (corresponding industry standard HVFR loading comparison) when tested in brines, without sacrificing friction reduction effectiveness. Additionally, a new concept of fracturing fluid referred to as Capillary Bridge Slurry (CBS) has been successfully implemented in North America, where through a surface modification to the proppant, the addition of a gas phase such as N2, and the use of a polyacrylamide-based friction reducer, the proppant becomes part of the fluid structure and is no longer the burden to be carried. The combination of HVFR's and the surface modified proppant can effectively combat the issues faced with proppant transport in long laterals. This paper will highlight the results on the analysis of the governing proppant transport mechanisms (suspended and bed) of CBS system formulated with HVFR-ST, in the presence of nitrogen (N2), where no detrimental effect in the average distance traveled of the sand particle in the Proppant Transport Test Bench (PTTB) was observed when the brine concentration of the base fluid was increased from 1% to 5% in comparison to industry standard HVFR (HVFR-FW). Field production data on wells stimulated with CBS show a significant upside (~ 50%) in liquid hydrocarbon production than offsetting wells over a ~ one year period of time. Friction loop data carried out at 45 L/min (11.89 gals/min) flow rate in an internal diameter pipe of 0.305" shows a reduction on friction pressure in excess of 70%, when HVFR was tested in 5% API brine (4% (w/v) NaCl and 1% (w/v) CaCl2·2H2O) at loadings as low as 0.1%. Furthermore, dynamic measurements within the viscoelastic regime/behavior of the HVFR at different loadings in the oscillatory viscometer will provide learnings on the elasticity-proppant transport relationship of the different fracturing fluid systems. Through the use of laboratory testing and field study cases, this paper will illustrate the true benefits on the use of salt tolerant HVFR's as a base fluid with the increasing demand of re-cycled and flowback water use in fracturing fluid systems.