Exploitation of shale reserves requires injection of large quantities of water-based fluids during hydraulic fracturing treatments. Damage to the fracture conductivity and to the near-fracture matrix permeability caused by residual water can be avoided by optimizing fracture cleanup. The wide variation in mineralogy, texture and lithology of kerogen rich shales entails a substantial variation in the wetting characteristics of these rocks on all scales, whether one is comparing rock from different reservoirs, formations, or even different zones within a formation. It is therefore critical to evaluate shale/fluid interactions. The contact angle is a quantitative measure of the relative wettability of a substrate with respect to two fluids brought into contact with it. To understand dynamic processes in the reservoir, dynamic contact angles need to be measured. Dynamic contact angles (advancing/imbibing and receding/draining fluids) differ substantially from static contact angles. For fracture cleanup the receding contact angle is most relevant. Obviously, static goniometer measurements that are presently used in the industry to infer fluid behavior within the rock matrix give wrong results that do not reflect the mixed wettability of shales with diverse pore types. The results of a macroscopic goniometer measurement, obtained on a polished surface cannot be projected down to pore scale with rough and diverse surfaces.

In this document, we present a rapid and practical method to measure the saturation dependent capillary pressure in a shale sample pack. A new method has been developed to measure threshold pressures and receding contact angles on freshly prepared shale and mudstone surfaces. We introduce a fluid retention ratio as a meaningful way to directly compare additive performance with regards to fracture cleanup.

This method is used to screen treatment fluid additives on a reasonably small amount of formation material. Rock samples from different shale formations have been tested with various additives. Measurement results show that different additives behave differently when exposed to shales from different reservoirs; different responses are even observed from well to well in the same reservoir and zone to zone in the same well.

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