Marine organic-rich shales deposited in oceanic and continental margin basins are the most important source rocks of both conventional and unconventional oil and gas resources all over the world (Zou et al., 2019). During the past decade, marine shale gas exploration in China has acquired rapid progress. With the discovery of Fuling, Weiyuan, Changning, Fushun, Yongchuan Block in Sichuan Basin, the proved reserves of marine shale gas in China were up to 544.1 billion cubic meters, and the output of shale gas in 2020 reached 20 billion cubic meters (Cnr, 2021). Consequently, China has become the fourth country that achieved large scale commercial development of shale gas resources, and the other three countries are America, Canada and Argentina (Wang, 2017).

Shale hydration is a key factor that leads to wellbore instability problems in hard-brittle shale formation (Ma et al., 2021). Most researchers focused on revealing hydration mechanism (CHENEVERT ME, 1970; DARLEY HCH, 1969; Dokhani et al., 2015; Roshan et al., 2015; Wen et al., 2015; Liang et al., 2015; Kang et al., 2017) and developing effective anti-hydration drilling fluids to guarantee wellbore stability (Deville et al., 2011; Riley et al., 2012; An et al., 2015; Zhong et al., 2016; Barati et al., 2017). However, in the view of reservoir stimulation, it might be a positive effect on improving recovery ratio in shale gas reservoir (Dehghanpour et al., 2013; Ji and Geehan, 2013; Morsy and Sheng, 2014), because hydration induced fractures could enhance the formation permeability.

Field practice of shale gas exploration in Jiaoshiba block, Fuling Distict, Chongqing, China showed that it consumed about 3 h to fracturing one stage, preparation time between two adjacent stages was about 3–4 h, so fracturing 2 stages would cost nearly 1 day. Supposing that a well needs to fracture 16 stages, 8 days were needed (Wang et al., 2017). Typically, during the whole process of hydraulic fracturing, tens of thousands cubic meter fluid were injected in the reservoir, with very small proportion returning to the ground (Yuyang et al., 2021). So, shale reservoir was in a state of fluid immersion environment and hydration process would fully develop. Zhang and Sheng (2017) studied of the propagation of hydration-induced fractures in Mancos shale using computerized tomography. Ma and Chen (2014) investigated on the meso-damage characteristics of shale hydration. However, previous studies mainly focused on the certain or final hydration state to evaluate hydration effect. The detailed spatial-temporal evolution process of hydration fractures in marine shale was rarely reported and still need systematic study, which was valuable for reservoir engineers to design more abundant and effective permeable fractures.

This paper presents a detailed study on the fracture evolution of Longmaxi marine shale, soaked in three different types of fluids. The distribution and total length of hydration fractures were observed and analyzed from the time of immersion to more than 10 days. A mechanical model, considering the effects of in-situ stress, fluid pressure, hydration stress, and capillary force, was established to reveal the propagation mechanism of hydration fracture. Results could enlighten us about the formation mechanism of complex hydraulic fractures in shale gas reservoir.

By investigating microstructure change during shale hydration, Shi et al. (2012) argued that capillary force induced by microfractures in shale promoted the hydration of clay mineral. Meanwhile, hydration in turn accelerated the propagation of microfractures. This mutual promotion mechanism leads to the rapid evolution of hydration cracks. For this reason, a fracture propagation model considering hydration and capillary effect were established based on the theory of fracture mechanics (Anderson, 2005), and the promoting mechanism of hydration and capillary effect to fracture propagation were analyzed in a mechanical view.

The mechanical model is based on the following assumptions:

1) An infinite homogeneous medium contains a finite fracture;

By considering hydration and capillary effects, the stress intensity factor (SIF) at fracture tip is determined by remote in-situ stress, fluid pressure, hydration stress and capillary force (see Figure 8).

1) SIF induced by in-situ stress

Hydration force are the result of swelling of clay mineral. Assume the clay mineral is distributed evenly in shale, and the hydration stress σ _w spread uniformly in fracture surface, the model Ⅰ SIF can be described by K I ( 3 ) = 2 σ w a π arcsin b a (3)

4) SIF induced by capillary force

By simplifying the micro-fracture faces as parallel-plate, capillary force could be calculated by F = 2 γ ⁡ cos ⁡ θ W (4) Where F is capillary force, N; θ is contact angle, °; W is fracture width, m; γ is surface tension of water, N/m (Figure 9).

Fracture surface would bear the counter force of capillary force, Fcosθ. SIF induced by this counter force is K I ( 4 ) = 4 γ ⁡ cos 2 ⁡ θ W a π a 2 − b 2 (5)

The superposition of the above 4 parts results in the final mode Ⅰ SIF. K I = K I ( 1 ) + K I ( 2 ) + K I ( 3 ) + K I ( 4 ) = − σ π a + 2 p f + σ w a π arcsin b a + 4 γ ⁡ cos 2 ⁡ θ W a π a 2 − b 2 (6)

Without considering the influence of in-situ stress and fluid pressure, assume the half length of micro-fracture is 0.005 m, half-length of infiltration area is 0.004 m, fracture with is 0.001 m, contact angle is 15°, surface tension is 0.0728 N/m, hydration stress is 1 MPa, the SIF induced by hydration and capillary effects is 3.613 MPa m^1/2. Heng et al. (2015) got the fracture toughness of shale (0.566 MPa m^1/2 along the bedding plane and 1.146 MPa m^1/2 perpendicular the bedding plane) by performing three-point bending test. By comparing this with previous study, it is apparently that the SIF caused by hydration stress and capillary force is greater than the measured fracture toughness and the micro-fracture would probably propagate.

Fracture propagation caused by hydration might play a key role in the formation of fracture network in shale gas extraction. As the major hydraulic fracture extends in the vertical or transverse direction, hydration fracture would form along the direction of bedding plane in the face of fracture. High fluid pressure and capillary induced hydration effect promotes fracture propagation along bedding-plane to the deeper shale reservoir. Micro hydration fracture would gradually develop into macro-crack which is a part of the whole hydraulic fractures. Finally, a 3-D stimulated volume would form, where major hydraulic fractures propagate along the direction of fracture height and length and secondary fractures extend along the direction of bedding planes (Figure 10).

Another import change is the reservoir stiffness. Shale formation that has been hydro-fractured is no longer an intact rock mass. Its strength, Youngs Modulus would reduce to some extent, and the permeability might increase. All these would bring critical influence on the follow-up fracturing and refracturing Wang et al., 2020.

It is a very interesting phenomenon that vertical cracks (fractures perpendicular to the bedding planes) occurred with horizontal (along bedding) fractures. Further analysis indicated that the occurrence time of vertical fractures distributed between 5 h and 4 days, at which the horizontal fractures had already been fully developed. It seems the horizontal and vertical fractures appeared in chronological order. As shown in Figure 11, the clay minerals usually arranged directionally along shale bedding planes. During the initial hydration process, the water absorption of clay minerals could induce great swelling stress to open the bedding planes. So, horizontal fractures along bedding planes would occur first and fully develop. Furthermore, the fully developed horizontal cracks promoted continuous hydration and swelling of clay minerals. This process could produce tensile stress along horizontal fracture surface and then induce the crack initiation and propagation perpendicular to the bedding planes, which contributed to forming the vertical cracks.

The application of water based fracturing fluid could induce abundant hydration cracks to increase the fracture complexity of fracking. But complex fractures would not surely represent high conductivity. The permeability damage caused by the swelling of clay mineral should also be evaluated, which is one of the critical disadvantages of the application of water based fracturing fluid Cong et al., 2022. Extra permeability tests should be conducted. The ideal water based fracturing fluid should not only create complex fractures, but also keep good fracture conductivity.

Although the evolution of hydration cracks was studied in this experiment, several limitations should be clarified to guide future research. Firstly, the test was conducted at room temperature and pressure, which ignored the high temperature and high pressure formation environment (Wang et al., 2021). Secondly, we only described the surface crack evolution, and failed to present the crack propagation inside the sample, which could be revealed by CT scanning (Ma and Chen, 2014; (Ma et al., 2016; Zhang and Sheng, 2017). Finally, the anisotropic bedding structure of shale was not considered in theoretical analysis (Gui et al., 2018; (Ma et al., 2021). Restricted to experiment condition, the above aspects were not realized and would be paid attention in future study.

Shale hydration fractures not only threaten wellbore stability, but also influence the effect of reservoir stimulation. By performing shale soaking experiment in three different fluids, conclusions are as follows:

1) For specimens soaking in distilled water, hydration fractures were extremely developed and evenly distributed in a state of network, and their final average cumulative length were 299 mm.