Ann: Operations Update, page-15

Multistage hydraulic fracturing is a critical technology for economic production from shale reservoirs. Large amounts of water-based fracturing fluids are pumped into formations, generating extensive fracture networks and stimulating low-permeability formations. Field operations have demonstrated that large volumes of injected fluids are retained in shale formations, with a flowback efficiency of lower than 30 % (Makhanov et al. 2014). In the U.S. Haynesville shale formation, the flowback rate is even lower than 5 % after fracturing operations (Penny et al. 2006). Besides possibly causing a series of environmental problems, the retention of fracturing fluids in shale formations can greatly enhance the water saturation near fracture surfaces and influence two-phase fluid flow, thus further inhibiting the production of shale gas (Sharma and Agrawal 2013). Furthermore, intense interaction between fluid and shale can dramatically change rock properties and impact on the generation of fracture networks during fracturing (Yuan et al. 2014). Therefore, studying the imbibition capacity and its main controlling factors is essential to understanding reservoir performance and optimizing fracturing operations.

It is generally believed that spontaneous imbibition of fracturing fluids into the shale matrix plays an important role in water loss. Many researchers have focused on the mechanism of fracturing fluid imbibition. Makhanov et al. (2012) found that imbibition rates perpendicular and parallel to the bedding plane are different, and the latter is higher. Hu et al. (2012) considered that the Barnett shale has a poor connectivity, which greatly influences the flow and diffusion of fluid. Roychaudhuri et al. (2013) determined that a surfactant can effectively reduce the imbibition rate of fracturing fluids, and the driving force of imbibition is the capillary pressure. Dehghanpour et al. (2013) mentioned that the amount of imbibition in shale is positively related to mineral composition and physical properties. Fakcharoenphol et al. (2014) investigated the effects of salinity on water imbibition and found that the osmotic pressure can act as the driving force for water intake. Currently, it is well known that the imbibition of fracturing fluids is mainly controlled by the capillary pressure, while the effects of clay absorption have not been studied thoroughly. The imbibition capacity, imbibition rate, and other influencing factors in shale reservoirs have not been investigated systematically.

This paper focuses on the imbibition capacity and the influence of the mineral composition and physical properties of tight rocks. Samples include gas shales from the Sichuan Basin, tight sandstones from the Ordos Basin, and tight volcanic rocks from the Songliao Basin. Experiments can be divided into three groups. In group 1, the imbibition capacity and rate of deionized water uptake are investigated systematically. In group 2, each sample is immersed repeatedly in deionized water several times to address the water sensitivity of different rocks. In group 3, comparative experiments are conducted to explore the effects of different fluids on the imbibition capacity.

https://link.springer.com/article/10.1007/s12182-015-0049-2