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The research progress of deep and ultra-deep drilling fluid technology systematically reviewed, the key problems existing are analyzed, and the future development direction is proposed. In view of the high temperature, high pressure and high stress, fracture development, wellbore instability, drilling fluid lost circulation and other problems faced in the process of deep and ultra-deep complex oil and gas drilling, scholars have developed deep and ultra-deep high-temperature and high-salt resistant water-based drilling fluid technology, high-temperature resistant oil-based/synthetic drilling fluid technology, drilling fluid technology for reservoir protection and drilling fluid lost circulation control technology. However, there are still some key problems such as insufficient resistance to high temperature, high pressure and high stress, wellbore instability and serious lost circulation. Therefore, the development direction of deep and ultra-deep drilling fluid technology in the future is proposed: (1) The technology of high-temperature and high-salt resistant water-based drilling fluid should focus on improving high temperature stability, improving rheological properties, strengthening filtration control and improving compatibility with formation. (2) The technology of oil-based/synthetic drilling fluid resistant to high temperature should further study in the aspects of easily degradable environmental protection additives with low toxicity such as high temperature stabilizer, rheological regulator and related supporting technologies. (3) The drilling fluid technology for reservoir protection should be devoted to the development of new high-performance additives and materials, and further improve the real-time monitoring technology by introducing advanced sensor networks and artificial intelligence algorithms. (4) The lost circulation control of drilling fluid should pay more attention to the integration and application of intelligent technology, the research and application of high-performance plugging materials, the exploration of diversified plugging techniques and methods, and the improvement of environmental protection and production safety awareness.

In the present study, the evolution of free water content in five different alkali-activated slag (AAS) systems was continuously monitored and compared using 1H low-field NMR. The alkali activators used were waterglass solutions with three different moduli (1.2, 1.4, and 1.6), sodium hydroxide solution, and sodium sulfate solution. The findings reveal that the type of activator significantly affected the dynamic changes in the relative free water content. Notably, an increase in free water content was observed in the early stages of hydration of all AAS systems except for those activated by sodium sulfate solution. Additionally, this study investigated the relationship between changes in free water content and hydration heat in the AAS systems, dividing the initial 24 h of AAS hydration into three stages. The results demonstrate that free water can serve as an effective probe for monitoring the hydration process in fresh AAS pastes, offering valuable insights alongside traditional thermal signals.

Lost circulation is one of the important problems that restricts the speed and efficiency of oil and gas drilling and production. In this study, a resin plugging system was successfully developed for lost circulation formation. The resin plugging system showed excellent performance under high temperature and pressure conditions. The experimental results showed that the compressive strength of the resin plugging material can reach 9.23 MPa after curing, which is significantly higher than that of the traditional polymer gel material. The resin material can achieve effective curing in the temperature range of 60 °C to 100 °C, and the curing time decreases with the increase of temperature and only needs 3.46 h at 140 °C. The microstructure results showed that the resin material can form a chain or three-dimensional network structure after curing, which can effectively increase the toughness and strength of the cured plugging layer. Infrared and thermogravimetric analysis further confirmed the thermal stability of the chemical bonds in the material, and the initial decomposition temperature was about 241 °C, indicating that it had good thermal stability at about 300 °C. In addition, the effects of curing temperature, salinity, and drilling fluid pollution on the properties of the resin plugging agent were also investigated. The results showed that curing agent dosage and curing temperature are the key factors affecting curing time, while salinity and drilling fluid pollution affect the curing strength and overall properties of the materials. After adding 20% KCl polysulfonate drilling fluid, the compressive strength of the consolidated body decreased to 4.55 MPa. This study can provide an efficient and reliable plugging solution for malignant loss formation.

Thermosetting resins have good temperature resistance and high strength and have been widely used as plugging agents in oil fields. However, the current resin materials have high costs, and unmodified thermosetting resins are brittle or have deteriorated properties such as flame retardancy after curing to form a crosslinked network structure. In this study, the resin was modified via physical blending. The curing strength and temperature resistance were used as the main indicators. The resin matrix, curing agent, rheology modifier, and filling materials were modified and formulated optimally to form a high-strength resin gel plugging system. The resin gel system exhibited good fluidity and pumpability. When the shear rate was 200 s−1 at 25 °C, the initial viscosity was 300–400 mPa·s. The viscosity gradually decreased with increasing shear rate, and the apparent viscosity had good long-term stability at room temperature. A contamination test of different types of drilling fluids on the resin gel system showed that this system had good anti-contamination capability and could maintain a high curing strength even after being contaminated. At the same time, the system exhibited good plugging capability. A wedge-shaped fracture with an inlet size of 7 mm and an outlet size of 5 mm was plugged at 12.84 MPa for 10 min without leakage. A sand-filling pipe (with a diameter of 3.8 cm and pipe length of 30 cm) connected to the pipeline with a 6 mm outlet was subjected to a constant pressure of 11.29 MPa and plugged for 8 min before breaking through. Therefore, it exhibited good capability for plugging fissures and cavities. The resin gel leakage-plugging system has significant potential to realize effective plugging of the deep large-fracture leakage layer.

Lost circulation is a common and complicated situation in drilling engineering. Serious lost circulation may lead to pressure drop in the well, affect normal drilling operations, and even cause wellbore instability, formation fluid flooding into the wellbore, and blowout. Therefore, appropriate preventive and treatment measures need to be taken to ensure the safe and smooth operation of drilling operations. So, it is necessary to conduct in-depth research on the development and performance of the plugging materials. In this study, urea formaldehyde resin with high temperature resistance and strength was used as the main raw material, and the curing conditions were optimized and adjusted by adding a variety of additives. The curing time, compressive strength, temperature resistance, and other key performance indexes of the resin plugging agent were studied, and a resin plugging agent system with excellent plugging performance was prepared. The formula is as follows: 25% urea formaldehyde resin +1% betaine +1% silane coupling agent KH-570 + 3% ammonium chloride +1% hexamethylenetetramine +1% sodium carboxymethyl cellulose. The optimal curing temperature is between 60 and 80 °C, with a controllable curing time of 1–3 h. Experimental studies examined the rheological and curing properties of the resin plugging agent system. The results showed that the viscosity of the high-strength curable resin system before curing remained stable with increasing shear rates. Additionally, the storage modulus and loss modulus of the resin solutions increased with shear stress, with the loss modulus being greater than the storage modulus, indicating a viscous fluid. The study also investigated the effect of different salt ion concentrations on the curing effect of the resin plugging system. The results showed that formation water containing Na+ at concentrations between 500 mg/L and 10,000 mg/L increased the resin’s curing strength and reduced curing time. However, excessively high concentrations at lower temperatures reduced the curing strength. Formation water containing Ca2+ increased the curing time of the resin plugging system and significantly impacted the curing strength, reducing it to some extent. Moreover, the high-strength curable resin plugging agent system can effectively stay in various fracture types (parallel, wedge-shaped) and different fracture sizes, forming a high-strength consolidation under certain temperature conditions for effective plugging. In wedge-shaped fractures with a width of 10 mm, the breakthrough pressure of the high-strength curable resin plugging agent system reached 8.1 MPa. As the fracture width decreases, the breakthrough pressure increases, reaching 9.98 MPa in wedge-shaped fractures with an outlet fracture width of 3 mm, forming a high-strength plugging layer. This research provides new ideas and methods for solving drilling fluid loss in fractured loss zones and has certain application and promotion value.