Impact of capillary imbibition and osmosis during hydraulic fracturing of shale formations, The

Abstract

Most shale formations typically do not produce without hydraulic fracture stimulation. Therefore, in the development of shale formations, hydraulic fracturing is widely applied which has led to the U.S. shale revolution. During a hydraulic fracturing treatment of gas-bearing shales, it is reported that longer shut-in time results in a good initial gas production rate. However, a large percentage of the fracturing fluid remains unrecovered. The cause of this is believed to be capillary imbibition and osmosis in the shale where fluid is imbibed into the shale and trapped inside the pores. In addition, whether the fracturing fluid loss because of the capillary imbibition and osmosis causes serious formation damages during hydraulic fracturing is an important question. Hence, this dissertation investigates capillary imbibition and osmosis that cause fluid loss in shale formations, parameters that influence the capillary imbibition and osmosis process of shale formations, and the potential impact of capillary imbibition and osmosis on shale formations. Shale samples were obtained from the Horn River, Woodford, and Niobrara shale formations. Capillarity and osmosis were studied as the key mechanisms through experiments. It is believed that both capillarity and osmosis work together to result in fracturing fluid loss during hydraulic fracturing in shale formations. Laboratory test results illustrate that the fluid loss process includes both capillary imbibition and osmosis. In addition, experiments indicate that the amount of clays is a most important factor affecting the fracturing fluid loss process. Specifically, shale samples with high clay content imbibe more fracturing fluids than the measured pore space because clays have a strong ability to expand and hold water. Based on contact angle measurements, shale samples with smaller contact angles have a faster imbibition rate than those with larger contact angles. According to salinity tests, higher pore water salinity correlates to a faster rate of osmosis. Moreover, the lower initial water saturation causes more volume loss and a faster rate of capillary imbibition and osmosis. Experiments also show that 2% (by weight) KCl and 2% (by volume) KCl substitute fracturing fluids are imbibed from 10% to 40% less than 0.07% (by volume) friction reducer in the shale formation with high clay content; whereas in the shale formation with low clay content, the opposite occurs. In the low clay content shale, 0.07% (by volume) friction reducer test fluid is imbibed from 10% to 30% less than 2% (by weight) KCl fluid, but has similar imbibed amount with 2% (by volume) KCl substitute fluid. The permeability changes under various fracturing fluids, as the criterion of the impact from capillary imbibition and osmosis on the shale, are determined by the pressure build-up method. The experimental results show that the fracturing fluid will damage and seriously reduce the matrix permeability of the shale sample. When the sample imbibes more fluid, the matrix permeability is more severely reduced. Capillary imbibition and osmosis also decrease the fracture permeability of open fractures, but the decrease is less than the reduction of matrix permeability. Moreover, there is a lubrication effect that can reopen micro-fractures on shale samples and increase the micro-fracture permeability during capillary imbibition and osmosis.