Measuring Capillary Pressure Tells More Than Pretty Pictures

Abstract

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.

Numerical investigation of fluid-loss mechanisms during hydraulic fracturing flow-back operations in tight reservoirs

“…This is evidenced by the decreased water recovery (as compared to the base case, of 8.82%, 15.99% and 23.09% for the cases with S wirr ¼ 0.25, 0.3, 0.4, respectively). Pagels et al (2012) and Fan et al (2010) proposed that high capillary pressure caused by small permeability and aperture can cause water trapping in the secondary fractures. The concept of permeability jail has also been proposed by some researchers as a possible mechanism for water trapping in secondary fractures (Shanley et al, 2004;Wattenbarger and Alkouh, 2013).…”

“…However, less than 50% of fracturing fluids are typically recovered (McClure, 2014;Cheng, 2012;Wattenbarger and Alkouh, 2013). Three fluid-loss mechanisms have been reported in the literature (Pagels et al, 2012;Wattenbarger and Alkouh, 2013). Water imbibition from fracture system into rock matrix is facilitated by the high matrix capillary pressure in tight rocks.…”

“…Water and oil redistribute in the fracture-matrix system during this countercurrent imbibition process. (Pagels et al, 2012;Bahrami, 2012;Holditch, 1979). Besides matrix imbibition, water can be retained in the secondary fractures (Pagels et al, 2012;Fan et al, 2010).…”

“…Besides matrix imbibition, water can be retained in the secondary fractures (Pagels et al, 2012;Fan et al, 2010). Finally, secondary fractures, which are filled with fracturing fluid and perpendicular to maximum in-situ stress, might close and lose contact with the main hydraulic fracture systems as fluid pressure depletes (Pagels et al, 2012;McClure 2014).…”

“…First, in terms of secondary fracture trapping, Pagels et al (2012) and Fan et al (2010) proposed that water could be retained in the small secondary fractures due to their large capillary pressure, but this claim was not substantiated with physical evidence or modeling results. Wattenbarger and Alkouh (2013) demonstrated that low relative permeability in matrix and fracture, high fracture width, and strong permeability jail in matrix and fracture would increase water retention in secondary fracture during shutin.…”