No abstract

No abstract

As the primary mechanism of gas storage in shale, sorption phenomena of CH4 and other hydrocarbons in the micropores and mesopores are critical to estimates of gas-in-place and of the long-term productivity from a given shale play. Since C2H6 is another important component of shale gas, besides CH4, knowledge of CH4–C2H6 binary mixture sorption on shale is of fundamental significance and plays a central role in understanding the physical mechanisms that control fluid storage, transport, and subsequent shale-gas production. In this work, measurements of pure component sorption isotherms for CH4 and C2H6 for pressures up to 114 and 35 bar, respectively, have been performed using a thermogravimetric method in the temperature range (40–60 °C), typical of storage formation conditions. Sorption experiments of binary (CH4–C2H6) gas mixtures containing up to 10% (mole fraction) of C2H6, typical of shale-gas compositions, for pressures up to 125 bar under the aforementioned temperature conditions have also been conducted. To the best of our knowledge, this is the first time that systematic measurements of CH4 and C2H6, both pure and in binary mixtures, sorption on the Marcellus shale have been conducted, thus providing a comprehensive set of CH4–C2H6 competitive sorption data, which can help to improve the fundamental understanding of shale-gas storage mechanisms and its subsequent production. In the study, the multicomponent potential theory of adsorption (MPTA) approach is utilized to model the sorption data. The MPTA model is shown capable in representing the pure component sorption data, and also provides reasonable predictive capability when applied to predict the total sorption for CH4–C2H6 binary mixtures in shale over a range of compositions and temperatures.

No abstract

Multi-stage horizontal wells play an important role in the development of domestic shale-gas resources. The completion strategy for shale-gas wells commonly includes hydraulic fracturing that utilizes large volumes of fresh (and recycled water) complimented by the addition of assorted chemicals. A general observation from the completion of shale-gas wells is that a large fraction of the injected water remains in the formation after flowback, and that the fluid loss from any single well can exceed 50% of the original injected volume. In this work, we study spontaneous imbibition of water into shale samples from the Appalachian Basin in order to explore the role of capillarity in the fluid-loss mechanism. We investigate the imbibition characteristics for a range of shale samples encompassing the mineralogy and petrophysical properties that can be observed along the vertical column of a gas play. Imbibition experiments are performed on shale cubes, whereby one face of the sample is exposed to water in order to mimic the invasion characteristics of the fracturing fluid from the main hydraulic fracture through the micro-fracture network into the shale matrix. In most of the experiments we observe a distinct transition from an initial linear rate (vs. square root of time) to a much slower imbibition rate at later times. This transition is attributed to the complex, multi-porosity nature of the shale samples which are characterized by a micro-fracture network imbedded in the sample matrix. Based on a scaling argument, we demonstrate that the fluid loss during hydraulic fracturing can be explained, at least in part, by the imbibition processes.