Wellbore instability is a worldwide challenge in the oil drilling industry [1
], causing direct economic losses of more than 1 billion USD annually [2
]. It has been estimated that about 75% of drilled strata are shale formations and that 90% of wellbore instability occurs in such formations [3
]. Shale is a sedimentary rock with distinct laminated layers and a high clay content [5
]. When drilling into a shale formation, the shale comes into contact with the water-based drilling fluid. Thereby, the water molecules in the drilling fluid are adsorbed by the inter-layer of the clay minerals and onto the surface of the clay particles by coordination, electrostatic interaction, and hydrogen bonding; and surface hydration occurs [3
]. Additionally, due to the presence of micro-cracks in the shale, free water can easily enter the interior of the rock and induce a series of physico-chemical and mechanical changes [8
]. The mechanical changes promote the expansion and enlargement of the original micro-cracks inside the shale, and then macro-cracks form, providing channels for the water molecules to enter the shale, which increases the contact area between fluid and clay particles and consequently leads to ion hydration and osmotic hydration [9
]. Shale hydration is responsible for the attenuation of inter-particle interaction and cementation, which result in a decrease in the compressive strength and hardness of the rock [3
]. Al-Bazali et al. [11
] confirmed that diffusion osmosis has a detrimental effect on the mechanical stability of shale by reducing its compressive strength. As the degree of hydration increases, the rock structure is further destroyed, causing the wellbore to expand and fall off, resulting in wellbore instability. Van Oort et al. [12
] found that shale–fluid interactions could be controlled to decrease shale hydration, which can enhance wellbore stabilization.
The factors that cause shale hydration are complex: pressure differentials, chemical potential differences [12
], the crack structure of shale, and the type and content of clay mineral [13
]. Additionally, the difference between the activity of the drilling fluid and the activity of shale formation has been proven to be a crucial factor to affect shale hydration [14
]. Al-Bazali et al. [15
] found that the membrane efficiency decided by the difference in activity between the drilling fluid and the shale formation was related to the types of cation and anion in water-based fluids, which affect shale hydration. Chenevert et al. [16
] proposed the equilibrium activity theory of drilling fluids, and found that the higher the water activity in an oil-based drilling fluid, the more severe the shale hydration. The authors concluded the following: (1) when the shale formation activity is less than the drilling fluid activity, the water molecules in the drilling fluid can flow into the shale formation. Thus, surface hydration or osmotic hydration of the shale formation can be induced, which results in shale inflation; (2) when the shale formation activity is greater than the drilling fluid activity, fluid in the shale formation migrates into the drilling fluid. Thus, dehydration occurs, which induces shale contraction; and (3) when the activity of the drilling fluid is the same as that of the shale, there is no water exchange between the drilling fluid and the shale formation, and the rock remains in its original state [13
]. Therefore, investigating the impact of drilling fluid activity on shale hydration behaviors has practical significance for improving mining efficiency and wellbore stability.
Shale hydration is divided into three stages: surface hydration, ion hydration, and osmotic hydration [19
]. In previous studies, only the surface hydration of shale was considered as an important factor related to the surface wettability of shale, and was mainly related with fluid adsorption characterized by the change in the contact angle of the fluid on the surface of the shale; the faster the fluid adsorption rate, the faster the rate of change of the contact angle. Meanwhile, osmotic hydration was considered to be a factor inducing the swelling of shale, and was usually characterized by the swelling ratio of shale [20
]. Huang et al. [19
] found that a surfactant compound of polyamine (PA) and twelve alkyl two hydroxyethyl amine oxide (THAO) could enhance the surface hydrophobicity after adsorption onto the surface of shale particles and could restrain osmotic hydration through swapping out inorganic cations in the clay inter-layer. Yue et al. [5
] found that the absorption of the cetyltrimethylammonium bromide (CTAB) cation on the surface of shale could increase the contact angle between the drilling fluid and the shale and inhibit the surface hydration of shale. Cai et al. [22
] found that a composite surfactant could effectively change the wettability performance of water-based drilling fluid; this allowed the stability of the shale to be enhanced by controlling the wettability of the drilling fluid. Aghil Moslemizadeh et al. [23
] reported the effect of silica nanoparticles (NPs) as a physical sealing agent on water invasion into the Kazhdumi shale; the authors showed that the use of the NPs reduced shale hydration and improved the wellbore stability. Liu et al. [24
] concluded that when shale comes into contact with water-based drilling fluid, surface hydration occurs on the surface of the shale clay particles, thus forming a surface hydration film, generating hydration stress, destroying the original mechanical balance, and eventually causing the shale strength to decrease. Using shale osmotic hydration experiments based on the generalized Usher model, Wen et al. [17
] established a model related to the activity, swelling ratio, and hydration degree of shale, and classified shale hydration into three stages: dehydration, surface hydration, and osmotic hydration. However, in the above studies, surface hydration and osmotic hydration were not comprehensively considered, nor were they in studies aimed at investigating the relationship between the difference in the activity of the drilling fluid and the shale and shale hydration. Moreover, the relationship between the safety level of fluid activity and shale hydration has not been established. Determining this relationship could allow the impact of fluid activity on shale hydration to be characterized.
The present work takes advantage of the fact that, since the radius of K+
is similar to that of the hexagonal cavity in the clay crystal unit, CTA+
can be embedded into the inter-layer space of montmorillonite and SO3−
can be adsorbed by polar substances on the surface of shale, which can prevent shale hydration. Therefore, potassium chloride (KCl), sodium dodecylbenzene sulfonate (SDBS), and CTAB drilling fluid systems, as typical inorganic and organic drilling fluids, are widely adopted to maintain wellbore stability [25
]. Thus, in this study, three drilling fluid systems with different activities were selected as test fluids to investigate the effects of the activity of drilling fluids on the surface hydration and osmotic hydration of shale using tests of the contact angle between the drilling fluid and shale and swelling ratio tests. Furthermore, an evolution mechanism of fluid–shale contact angles as a function of fluid activity was proposed. Then, the safety of drilling fluid activity was classified into four levels based on the relationship between the shale swelling ratio and fluid activity.
In this paper, wettability and swelling tests were conducted to investigate the effects of the activities of three types of drilling fluid on the surface and osmotic hydration of shale. The following conclusions can be drawn:
(1) As the concentration of inhibitors in the drilling fluid system increases, the activity of the CTAB drilling fluid experiences the largest increase, while the activity of the KCl drilling fluid experiences the lowest increase;
(2) As drilling fluid activity increases, a decreasing trend is observed in the rate of change of the contact angles between the fluid and shale, and the shale swelling ratio increases obviously. The KCl drilling fluid showed the best inhibitory effect on shale surface hydration, and also caused the lowest negative extreme shale swelling ratio;
(3) Based on the safety levels of drilling fluid activity, when the KCl drilling fluid was used, the shale underwent the least shrinkage in the complete dehydration zone and the surface hydration activity threshold was the lowest in the surface hydration zone. The largest osmotic hydration zone was observed with the CTAB drilling fluid, which is disadvantageous for wellbore stability.