As shown in Table 1, the efficiency of shale components’ dissolution by neutral fluids is characterized using a hydrolysis constant, where a small hydrolysis constant indicates a large difficulty of mineral hydrolysis [7]. Ali et al.’s experiments showed indistinct mineral dissolution in shale debris samples (with a particle diameter of ~1 μm) soaked in distilled water for 21 d at 65°C (with a solid-to-liquid ratio of 1 g:5 ml), and these samples exhibited extremely low hydrolysis rates for each mineral component (Table 2) [8].

Shale is rich in clay minerals that comprise illites, illite/smectite mix-layers, chlorites, and kaolinites, and the crystal structures and physical-chemical properties of which determine the strong hydratability of shale rock. Water molecules and hydrated cations are adsorbed and accumulated on the surface of the clay mineral or crystal layers to form an electric double layer, which increases the interlayer repulsion force and interlayer spacing interval and leads to the hydration swelling of clay minerals [9]. Clay hydration is controlled by three main mechanisms: surface hydration, ionic hydration, and osmotic hydration. Surface hydration is initiated by water molecule absorption by clay minerals due to surface hydration energy, ionic hydration refers to the hydration shell forming around compensatory cations on silicate crystals in clay minerals, and osmotic hydration launched after the first two processes is jointly actuated by the repulsion force of the diffuse electric double layer and osmotic pressure [10]. The distance needed to generate surface hydration, which occurs for all clay minerals, is about 1 nm. The distance needed to generate osmotic hydration is larger than 10 nm, and it takes a long time to reach equilibrium due to large volumetric expansion and small swelling pressure [11].

Compared to water-based drilling fluids, oil-based drilling fluids with strong anti-pollution capacity and inhibitory capacities can maintain borehole stability and have been widely applied to shale gas wells. To preserve the rheological properties of oil-based drilling fluids and the activities of various treating agents, sodium hydroxide (NaOH) or lime is generally used to adjust the pH value of drilling fluids. The pH value of oil-based drilling fluids is usually higher than 9 [12,13].

Due to high clay content and small clastic mineral particles, shale samples exposed to alkaline fluids are liable to be eroded [12,13]. The corrosion rates of quartz, feldspar, and clay minerals increase with an increasing pH value in an alkaline environment [14]. The corrosion rate of quartz remains unchanged at a pH value of 2.0–8.5 and then sharply increases with the pH value of alkaline fluids; a rise in temperature will also elevate the corrosion rate [15]. Feldspar may react with NaOH solutions at certain concentrations. Alkaline fluids could erode clay minerals, such as kaolinite, smectite, and illite. After erosion, kaolinites will generate amorphous silicon, gibbsite, albites, and analcimes [12]. Table 3 shows complicated and even multi-step associated reaction equations between shale components and alkaline fluids. The intensity of shale mineral erosion by alkaline fluids is ranked as smectite > kaolinite > illite > plagioclase > quartz > orthoclase [16]. The reaction between shale and alkaline fluids mainly generates silicate with some carbonate compounds and hydrated oxides [17]. According to the experiments by Kang et al., the reaction between Longmaxi shale samples from the Sichuan Basin and alkaline fluids is very slow; additionally, they found a positive power correlation between alkaline fluid concentration and reaction rate and a positive exponential correlation between temperature and reaction rate [18].

As a type of working fluid frequently used in reservoir stimulation, acid fluids may erode the microstructure of shale rock directly and initiate various complicated reactions (Table 4). Carbonate minerals exposed to acid fluids show high activity; hydrochloric acid (HCl) reacts quickly with calcites and slowly with dolomites. The reaction experiments at 60°C for individual minerals and acid fluids (pH = 4) showed a calcite reaction rate of 10⁻⁵–10⁻³ mol/m² s and a dolomite reaction rate of 10⁻⁷–10⁻⁵ mol/m²s [19]. When HCl erodes chlorite crystal layers, the leaching out of Al³⁺, Mg²⁺, and Fe²⁺ ions causes excessive dissolution of chlorites [20], and H⁺ will cause surface dissolution [21]. Surface crystal lattices of kaolinites with almost no isomorphous replacement exhibit extremely high stability in acid fluids and chemically react only with high-concentration (about 21–26%) HCl at high temperatures [22]. The overall structure of illites is destroyed when reacting with HCl, and then, the corroded illites completely peel off from the surface of the shale samples [23]. The products of illite acidification reactions are the primary source of fine migration and could result in pore throat blinding and reservoir permeability decline [24]. In addition, a high-temperature environment facilitates the acid corrosion of illites, chlorites, and albites. Experiments by Black et al. [25] showed an albite reaction rate of ~10⁻¹⁰ mol/m²s and a clay mineral reaction rate of 10⁻¹⁴–10⁻¹⁰ mol/m²s in acid fluids of pH = 4 at 60°C. The reaction rate of kaolinite or illite is higher than that of chlorite and smectite. Moreover, pyrite is among the common minerals in the sulfide family and could be dissolved effectively in HCl.

When black shale formations are tectonically uplifted to crop out, the chemical equilibrium of organic matter and pyrite occurrence is upset due to rising oxidation-reduction potential; hence, oxygenolysis reactions can easily occur in oxygen-rich surface water [26]. Acid water usually generated in the oxidative dissolution of organic matter or pyrite, may corrode carbonate minerals and cause metallic cations to leach out of feldspar, illites, and chlorites and could cause hydrolysis of silicate minerals. It is hard to decompose quartzes in acid and oxidative environments [27]. As shown in Table 5, which compares black shale component stabilities in the land surface environment, organic matter and pyrite are the major objects of weathering and oxidation.

Oxidizing agents such as hydrogen peroxide (H₂O₂), ammonium persulfate (Na₂S₂O₈), and chlorine dioxide (ClO₂) have been widely used in well drilling, well completion, stimulation, and enhanced recovery [28–30]. Experiments by Mikutta et al. [31] revealed the dissolution of organic matter in the soil by H₂O₂, Na₂S₂O₈ and sodium hypochlorite (NaClO) solutions. Oxidative degradation of organic matter in coals accompanies decarboxylation and then the generation of olefin. As the degree of oxidation increases, decarboxylation and ring-opening reactions arise in turn [32]. Some experiments have confirmed the dissolution of organic matter, epyrite, and carbonate minerals in shale by NaClO/H₂O₂ [33,34]. In the oxidation process of pyrite by H₂O₂ molecules, thiosulfates (e.g., S₂O₂²⁻ and S₂O₃²) are produced first and are then oxidized to generate sulfates or are decomposed into elementary sulfurs and bisulfites [35]. There is a power correlation between the oxidation reaction rate of shale rock and H₂O₂ solution concentration and an exponential correlation between the reaction rate and temperature. For an H₂O₂ solution with a mass concentration ranging from 2–10%, the oxidation activation energy of Longmaxi shale samples ranges from 3.51–12.10 kJ/mol [36].

The capillary effect in shale rocks and strong hydration swelling after water imbibed into pores and microfractures among mineral particles jointly lead to the generation, propagation, and connection of microfractures and final macroscopic rock failure [38]. According to fracture mechanics, material failure originates in the generation, propagation, and connection of internal microfractures. Tightly cemented shale is rich in microfractures, and swelling stress caused by clay hydration tends to induce stress concentration at the tip of the microfractures. As the swelling stress increases, continuous microfracture propagation l causes shale to burst and collapse once the swelling stress exceeds the critical stress at the fracture tip [39–41]. As shown in Fig. 1, non-clay mineral particles on the shale surface may fall off to form inorganic pores with a diameter from several microns to dozens of microns due to water-rock interaction. In addition, microfractures may occur between organic matter and inorganic minerals and inside inorganic minerals [38]. Liang et al. [42] established a shale crack propagation model involving hydration and wettability (capillary effect), and their results showed that hydration has a great impact on the increment of the stress intensity factor and tends to cause crack propagation. Yang established a model for calculating the release rate of mechanical energy at the tip of shale fractures under capillary force, and they quantitatively discussed the mechanical mechanism of subcritical crack growth under capillary force and explained the reason for shale bursts after water imbibition [43].

In situ conditions, inorganic pores that manifest as microfractures among clay mineral and non-clay mineral particles tend to cause hydration damage [44]. Hydration that mainly occurs along the lamination or pre-existing fractures goes through three stages: a stage with enlarged macropores and cracks, a stage with generated fine pores and enlarged macropores and cracks, and a stage with enlarged fine pores, connected macropores and induced cracks that cause hydration-induced fracturing [45]. Due to the combined effect of surface hydration of clay minerals, ionic hydration, and osmotic hydration, micro-scale hydration damage gradually evolves into macro-scale failure, which is regarded as successive loss of local rock mechanical strength. Hydration damage tends to occur in shale samples with high clay content, when shale fabric may be seriously destroyed over a short period of time [46]. Under high isotropic compressive stress, shale hydration is likely to close microfractures instead of producing new fractures; under low isotropic compressive stress, hydration induces fractures preferentially growing along lamination and reopening or extending pre-existing fractures [47,48]. Compared with isotropic compressive stress, anisotropic compressive stress is liable to produce hydration-induced fractures; the size of the induced fracture geometry and the number of fractures increase with increasing stress anisotropy [49–51].

Intense erosion of surface minerals on shale by alkaline fluids may generate many pores (Fig. 2), which increases the internal nano-pore volume and specific surface area, resulting in loosened rock fabric and significantly decreasing rock compression strength. This can consequently expand fractures, enlarge fracture width, and increase the stress sensitivity of shale fractures [18]. As indicated by Kang et al., hydration swelling and alkaline erosion induced by drilling fluid intrusion are the dominant types of shale chemical damage, burst and instability [52]. Since hydroxyl (OH⁻) concentration has a great positive effect on the hydration of non-swelling shale rock, alkaline erosion may also accelerate shale hydration swelling. Hydration swelling is intensified when NaOH or potassium hydroxide (KOH) solutions are nearly neutral, alleviated when the pH value ranges from 8 to 9, and enhanced once again when pH > 9 [53]. The hydratability of organic-rich shale increases with pH value; alkaline erosion and its effect on strengthening clay hydration play a role in promoting fracture propagation [54].

After treatment of acid fluids, the Bakken shale sample generated mass dissolved pores with the largest diameter of 120 μm, which remarkably improved pore connectivity [55]. Morsy et al. [56] used CT scanning to investigate the porosity change of shale samples acquired from different regions in North America after the acid treatment, in which carbonate-rich shale (Eagle Ford shale) showed a greatly improved porosity after acid corrosion, and clay-rich shale (Barnett shale) showed a negatively growing porosity (Table 6). Three types of microfractures may occur inside shale after acid treatment: stress-induced fractures, acid corrosion-induced fractures, and acidizing-induced contraction fractures. For clay-rich shale, acid corrosion may generate more stress-induced fractures at the boundaries of kaolinites and chlorites/biotites and more acidizing-induced contraction fractures in chlorite zones. For carbonate-rich shale, acid corrosion-induced fractures turn up in zones with anhydrites, calcites, illites, and organic matter [57].

Acid corrosion, which is affected by carbonate mineral distribution, may alter the microstructure of shale rock (Fig. 3), cementing strength of mineral particles, strength of rock mass, and rock deformation and failure [58]. According to the experiments of reactions between Eagle Ford shale samples and dilute hydrochloric acid (HCl) solutions reported by Morsy et al. at 93°C, the elastic moduli of rock samples were reduced by 25–82% after reactions [59]. Decreased shale hardness and microstructure alteration after acid damage are all related to the distribution of reaction minerals [55]. Acid corrosion deteriorates the mechanical strength and breakdown pressure of shale rock, which is favorable for hydraulic fracturing stimulation in shale reservoirs [60].

Outcrop shale weathering mainly works on organic matter and pyrite, and acidulous water produced in the process corrodes carbonate minerals. Due to the erosion by acidulous water, mineral dissolution, generation of secondary minerals, and ion exchange adsorption lead to a change in mineral components and the ways of mineral particle connection, which induces a large number of micropores [61].

Kuila et al. [62] used low-pressure gas adsorption, X-ray diffraction, rock pyrolysis, and nitrogen adsorption to characterize the pore structures in shale samples from the Silurian System in Eastern Europe, Haynesville, the Paleozoic Erathem and Marcellus in North America, and the Baltic Sea Basin after the treatment with NaClO solutions. After the organic matter in shale rock with high thermal maturities was removed by oxidative dissolution, the volume of pores with diameters smaller than 5 nm was greatly reduced, whereas the volume of pores with diameters greater than 10 nm was greatly increased. Zhu et al. [63] adopted the same methodology to investigate the porosity, total organic carbon (TOC), and mineralogical features of shale samples from the Yanchang Formation in the Ordos Basin in China after treatment with H₂O₂ solutions, and the results showed a positive correlation between a decrease in TOC content and an increase in pore volume.

Chen et al. reported that the average diameter of nano-pores in Longmaxi outcrop shale increased from 4.9 to 24.5 nm after a sufficient reaction with H₂O₂ solutions, the nano-pore volume (with a pore diameter <193.5 nm) increased from 0.025 to 0.041 cm³/g, and the overall pore volume increased from 0.015 to 0.079 cm³/g [33]. Oxidative dissolution may accelerate subcritical crack growth, promote hydration-induced fracturing, and cause oxidative damage to shale rock to intensify macroscopic fracturing under axial stress [64–66]. Fig. 4 shows in situ dissolved pores and fractures generated by the oxidative dissolution of pyrite and organic matter [67].

With respect to acid fluids and slick water used in the fracturing stimulation of shale gas wells, this section deals with oxidizing acid fluids, which enhances the performance of acid fluids in reducing the breakdown pressure of shale rock, and with oxidizing fracturing fluids, which facilitates adsorbed gas desorption.

A shale gas well usually goes through three stages after the fracturing operation: shut-in, flowback operations, and production testing. This section deals with the optimization of shut-in time in view of water-rock interaction and pressure-controlled production systems (PCPs).