Fracturing fluid compositions have historically been formulated to achieve desired rheological properties under the conditions of pump time and temperature in the subsurface. However, fluid selection best practices came into being when conventional and mixed conventional and tight-gas sandstone reservoirs dominated oil and gas operations. Those reservoirs consisted mainly of quartzose sandstones cemented by quartz overgrowths or calcite. Those rocks were relatively unreactive to water-based fracturing fluids, except for their grain-coating clay minerals. Only rarely was clay present in the reservoir rock-pore network in sufficient quantity to contribute to changes in fracture wall mechanical properties such as Brinell hardness. The changeover in the North America hydraulic fracturing market to include the shale plays has brought into question whether rheology at time and temperature should remain the dominant fluid design criteria.
Samples of Bakken, Huron, Haynesville, and Marcellus shale core material have been tested against different fracturing fluid compositional pH values for time periods up to 8 months. The shale samples were subjected to Brinell hardness measurement before and after testing with pre-test measurements being taken in the wet condition and post-test measurements being done in the dry condition. Water composition was measured before and after each test, as was proppant strength.
Results indicate that pre-and post-immersion Brinell hardness values vary from one shale sample to another. Samples having different mineral composition may have different softening response to wetting. Also, natural and man-made proppants exhibit different degrees of strength loss or retention under long-term test conditions.
This paper is significant in that it directly compares measurements related to proppant embedment potential across different shales. It also provides a series of data points to aid in choosing particular fracturing base fluid compositional pH values for treatment design in wildcat areas.