## 1 Introduction  
Offshore deepwater regions are rich in oil, natural gas and gas hydrate resources. The drilling fluid is called the blood of drilling engineering [1], and it is extremely important for deepwater drilling operations. Shale in deepwater is water sensitive, so it is prone to hydration on exposure to filtrates of water-based drilling fluid (WBDF), thus causing wellbore instability [2; 3; 4; 5]. Serious thickening of the drilling fluid occurs in deepwater drilling when it is cooled down by the low-temperature environment (approximately 4 \({}^{\circ}\)C) [6; 7; 8], leading to operation troubles. Salt/polymer WBDF was initially used in deepwater drilling operations in the Gulf of Mexico in the early 1990s [9]. The partially hydrolyzed polyacrylamide (PHPA) was used to inhibit the hydration of shales to maintain the integrity of cuttings as well as the wellbore stability. As the drilling operations moved into deeper water regions, the wellbore instability in water-sensitive shale formation and thickening of drilling fluid caused by the high-molecular-weight polymer PHPA made this WBDF unsatisfactory for deepwater drilling operations. Synthetic-based drilling fluid (SBDF) has the advantages of high penetration rate, wellbore stability, etc. However, field applications show that it is an extraordinary challenge in managing the downhole pressure, because the elevated rheology of drilling fluid at a low temperature leads to a high equivalent circulating density (ECD). Since the safe density window between the fracture pressure and pore pressure in deepwater drilling is very narrow, the substantial increase in ECD exceeds the safe density limit, resulting in loss circulation of drilling fluid [6; 10; 11]. The frequent lost circulation significantly reduced or eliminated the economic benefits. Moreover, there are environmental concerns on the use of SBDF for some regions. Therefore, WBDF is favored in consideration of environmental protection and costs, but the shale inhibition and low-temperature rheology problems related to the high-molecular-weight encapsulator are still big concerns. In recent years, a high performance WBDF has been developed [5; 12; 13], and it performs better than traditional WBDFs (water-based drilling fluids) in deepwater drilling. Owing to the development of a novel hydration inhibitor along with the use of encapsulator, the novel WBDF can achieve comparable shale inhibition to SBDF. Generally, the encapsulators for WBDF were the high-molecular-weight amide polymers, such as PHPA, polyacrylamide (PAM), and particular zwitterionic polymer [3; 14; 15; 16; 17; 18; 19]. They can form multi-point adsorption on the surface of clay particles on the wellbore by hydrogen bonding interaction of -CONH\({}_{2}\) and other adsorption groups, and bridge the surrounding clay particles together and wrap them, thus preventing the dispersion and exfoliation of clay particles [13]. At the same time, the encapsulator can also maintain the integrity of drill cuttings in drilling fluid, enabling them to be easily removed by solid control equipment. Therefore, the high-molecular-weight (usually above 2,000,000) polymer is required to effectively bridge and wrap the clay particles [17]. However, the long molecular chains of these polymers result in high friction, and the curly molecular chains are prone to form grid structure through intertwining, and thus the WBDF thickens [20]. Particularly in deepwater drilling, the polymer molecular chains curl up and entangle with each other at a low temperature. Due to this, the viscosity and gel strength of WBDF substantially increase, so the ECD apparently increases, resulting in lost circulation. In addition, the viscous drilling fluid due to the presence of high-molecular-weight encapsulator at a low temperature usually adheres to the vibration screen and unable to get through the sieve, thus leading to drilling fluid leakage [21].