Imbibition of Oxidative Fluid into Organic-Rich Shale: Implication for Oxidizing Stimulation

Abstract

A large amount of fracturing fluid enters a well of a shale gas reservoir to create a fracture network, but the recovery of fracturing fluid is generally less than 30%. Fracturing fluid from the hydraulic fractures usually invades the microfractures and matrix by spontaneous imbibition during the shut-in. Recent studies show that the water–rock interaction may induce shale structure failures, which can significantly affect imbibition rate. Due to the presence of oxidizable compositions (e.g., pyrite and organic matter (OM)), oxidation easily induced the structure failures and dissolution pores. However, its effects on imbibition of water into the shale is poorly understood. In this study, imbibition experiments of deionized water (DI water) and oxidative fluid under no confining pressure conditions were conducted to determine the imbibition characteristics; shale cubes (1 cm × 1 cm × 1 cm) and crushed samples (380–830 μm) were treated by DI water and oxidative fluid for revelation of the change in the composition and the associated dissolution structures and explanation of the imbibition characteristics of oxidative fluid in shale. The results show that the final amount of oxidative fluid imbibed is higher than that of DI water; oxidation-induced microfractures during the imbibition lead to a “phase step” of the normalized imbibed volume vs time curve and “S” characteristic of the normalized imbibed volume vs square root of time (sqrt time) curve. These differences are mainly caused by the improvement of the imbibition pathway and the increase of water retention space by oxidation. After the oxidation treatment of crushed shale samples for 48 h, lots of oxidation-induced microfractures and dissolution pores were observed by field-emission scanning electron microscopy. Combining the analysis of X-ray diffraction (XRD) and atomic absorption spectroscopy (AAS) found that the dissolution pores seemed to strongly contribute to the loss of calcite, dolomite, and pyrite. Results from mercury injection capillary pressure analysis showed that the oxidative dissolution could lead to a high porosity and good connectivity of nanoscale pores networks in shale cubes. Moreover, oxidative dissolution decreased the barriers of microfracture propagation according to the decrease of zeta potential in the shale–water system and, meanwhile, accelerated the release of clay hydration forces to induce microfractures. The results indicate that the coordinative effect between spontaneous imbibition and oxidative dissolution may play a significant role in increasing the gas supply ability of nanoscale pores and microfractures, thus achieving oxidizing stimulation of shale formation to enhance shale gas recovery.

Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

“…To increase the imbibition volume, the formulation of HFF can be adjusted to be acidic, alkaline, or oxidative as discussed in the Imbibition Potentials of Shale Gas Formation section. [78][79][80][81]102 As we know, gas shales contain a large amount of chemically unstable compositions (e.g., clay minerals, carbonate, pyrite, and organic matter (OM)) which are sensitive to the adjusted HFF. 69 For example, OM is sensitive to oxidation reaction, and carbonate is sensitive to acidification reaction.…”

Effect of salinity on the kinetics of pyrite dissolution in oxygenated fluids at 60 °C and implications for hydraulic fracturing

“…Besides the mobilization of trace elements, pyrite oxidation also alters the shale pore and fracture network, which impacts hydrocarbon production. Pyrite oxidative dissolution initially increases the shale porosity and the connectivity of the nanoscale pore network, improving the imbibition pathway and water retention (You et al, 2018). One of the biggest challenges in shale gas production from hydraulically fractured unconventional reservoirs, though, is that the productivity can drop significantly within several months of the start of production (Bustin and Bustin, 2012;Falk et al, 2015;Patzek et al, 2013).…”

Comparison of Chemical-Induced Fracturing by Na2S2O8, NaClO, and H2O2 in Marcellus Shale

“…Adding oxidants as chemical additives to the fracturing fluid to improve the permeability of shale reservoirs through chemical-induced fractures has been proposed in recent years . Also, there are studies investigating shale fracturing due to shale and the oxidative fluid–H 2 O 2 interaction. − It was proved that H 2 O 2 can induce multiscale cracks, which indicate that H 2 O 2 may play a favorable role in shale matrix stimulation by oxidative dissolution. However, H 2 O 2 may not be the most suitable oxidant because its effectiveness is largely affected by thermal decomposition. − Some other oxidants need to be compared with H 2 O 2 and further evaluated.…”