In the production process of oil and gas wells, the migration of solid particles, such as mud and sand, often leads to screen pipe clogging, resulting in production reduction or even shutdown. Controlled plasma pulse plugging removal technology is a new physical method for unplugging. Plasma, generated by the electrical explosion of the wire, then triggers a shock wave, which can remove the plugging. In this paper, the performance of controllable plasma pulse plugging removal technology is evaluated by simulating the plugging state of the downhole screen through laboratory experiments. The test results of screen plate unplugging effect evaluation fully show that the plasma pulse decongestion technology can carry out effective decongestion, can effectively reduce the pressure behind the clogging zone and increase the flow rate of the clogging zone, and is suitable for different screen plate blockage states such as mild, moderate and severe. Thus, this technology has a good application prospect.

The rheology control of water-based drilling fluids at ultra-high temperatures has been one of the major challenges in deep or ultra-deep resource exploration. In this paper, the effects of 1-ethyl-3-methylimidazolium bis(trifluoromethanesulfonimide) (ILA), 1-ethyl-3-methylimidazolium tetrafluoroborate (ILB) and N-methyl, butylpyrrolidinium bis(trifluoromethanesulfonimide) (ILC) on the rheological properties and filtration loss of polymer-based slurries at ultra-high temperatures (200 °C and 240 °C) are investigated by the American Petroleum Institute (API) standards. The results show that ionic liquids with different structures could improve the high-temperature rheological properties of polymer-based drilling fluids. The rheological parameter value (YP/PV) of the polymer-based slurry formulated with ILC is slightly higher than that with ILA at the same concentration, while the YP/PV value of the polymer-based slurry with ILA is slightly higher than that with ILB, which is consistent with the TGA thermal stability of ILA, ILB, and ILC; the thermal stability of ILC with pyrrolidine cations is higher than that of ILA with imidazole cations, and the thermal stability of ILA with bis(trifluorosulfonyl)amide anions is higher than that of ILB with tetrafluoroborate anions. Cation interlayer exchange between organic cation and sodium montmorillonite can improve the rheological properties of water-based drilling fluids. And meantime, the S=O bond in bis(trifluorosulfonyl)amide ions and the hydroxyl group of sodium montmorillonite may form hydrogen bonds, which also may increase the rheological properties of water-based drilling fluids. ILA, ILB, and ILC cannot reduce the filtration loss of polymer-based drilling fluids at ultra-high temperatures.

Lightweight and ultra-lightweight solid materials are being used in gravel packing for horizontal wells instead of traditional quartz and ceramsite to decrease the risk of premature plugging and improve packing efficiency. Physical and numerical simulation experiments of gravel packing were conducted to assess the effectiveness of reducing solid material density and investigate its impact on packing and sand control. Packed gravel destabilization experiments highlighted the importance of high-compaction degree packing for effective sand control. Further gravel packing experiments examined the packing performance of different solid materials, revealing that lightweight solids have minimal gravitational deposition effect because their density is similar to the gravel slurry, relying primarily on fluid flow for compaction. The numerical simulation indicated that lightweight ceramsite is unsuitable for horizontal and highly-deviated wells because of its poor compaction degree and sand control, especially with high-viscosity slurry. High-density particles enhance gravitational deposition, improving packing compaction and sand control. Lightweight materials are recommended only when advanced plugging of α wave packing cannot be avoided. In highly-deviated wells, high-density materials significantly improve packing stability and sand control. This study provides clear technical guidelines for selecting solid materials for gravel packing in horizontal and highly-deviated wells.

Sand production poses a significant problem for marine natural gas hydrate efficient production. However, the bottom hole gas–water–sand inflow pattern remains unclear, hindering the design of standalone screen and gravel packing sand control completions. Therefore, gas–water–sand inflow patterns were studied in horizontal and vertical wells with the two completions. The experimental results showed that gas–water stratification occurred in horizontal and vertical standalone screen wells. The gas–water interface changed dynamically, leading to an uneven screen plugging, with severe plugging at the bottom and high permeability at the top. The high sand production rate and low well deviation angle exacerbated screen plugging, resulting in a faster rising rate of the gas–water interface. The screen plugging degree initially decreased and then increased as the gas–water ratio increased, resulting in the corresponding variation in the gas–water interface rising rate. Conversely, gas–water stratification did not occur in the gravel packing well because of the pore throat formed between the packing gravels. However, the impact of gas and water led to gravel rearrangement and the formation of erosion holes, causing sand control failure. A higher gas–water ratio and lower packing degree could result in more severe destabilization. Therefore, for the standalone screen completion, sand control accuracy should be designed at different levels according to the uneven plugging degree of the screen. For the gravel packing completion, increase the gravel density without destabilizing the hydrate reservoir, and use the coated gravel with a cementing effect to improve the gravel layer stability. In addition, the screen sand control accuracy inside the gravel packing layer should be designed according to the sand size to keep long-term stable hydrate production.

To meet the requirements of marine natural gas hydrate exploitation, it is necessary to improve the penetration of completion sand control string in the large curvature borehole. In this study, large curvature test wells were selected to carry out the running test of sand control string with pre-packed screen. Meanwhile, the running simulation was performed by using the Landmark software. The results show that the sand control packer and screen can be run smoothly in the wellbore with a dogleg angle of more than 20°/30 m and keep the structure stable. Additionally, the comprehensive friction coefficient is 0.4, under which and the simulation shows that the sand control string for hydrate exploitation can be run smoothly. These findings have important guiding significance for running the completion sand control string in natural gas hydrate exploitation.

Natural gas hydrate is widely distributed, shallow-buried, clean, and pollution-free and has enormous reserves, it is regarded as the alternative clean energy source in the oil and gas field with the most potential. Pressure coring is the only way to drill for gas hydrate core on the surface under in situ conditions, which is of great value for analyzing its occurrence conditions and reserves comprehensively. Based on this, a new wireline pressure coring system (WPCS) with a ball valve seal was designed and developed in this paper; it was applied in the deep sea for the first time in the South China Sea hydrate survey voyage of the Guangzhou Marine Geological Survey (GMGS). A total of 15 runs of deep-sea gas hydrate drilling and coring applications were carried out, and they tested well. The experimental water depth was 1700–1800 m, and the coring depth below the seafloor was about 100–150 m. The formation consisted of sandy hydrate and argillaceous hydrate. The results showed the following. (1) The success rate of ball valve turn-over could reach almost 100% in the argillaceous hydrate reservoir, although there are some isolated cases of pressure relief. Meanwhile, drilling in the sandy hydrate reservoir, the success rate was only 54.55%. (2) When drilling in the argillaceous hydrate reservoir, the core recovery rate could reach 80%, while in the sandy hydrate reservoir, it was almost 0%. In practice, the sandy formation with gas hydrate is stiff to drill compared to the performance in argillaceous formations. After our analysis, it was believed that the ball valve and core tube could be easily plugged by sand debris during the sampling of sandy hydrate formation. Moreover, the sandy core is easily plugged into the core liner because of the high friction of sand grains in clearance. (3) The pressure-holding effect of the core drilling tool was related to the formation of hydrate, the sealing form of the ball valve, and the environmental pressure. Sandy hydrate formations often caused the ball valve to jam, while the muddy hydrate formation did not. The research results of this paper have reference value for the further optimization of the WPCS structure, the optimization of drilling parameters, and the design parameters of the ball valve structure, which could be better used for the pressure coring of gas hydrate and subsequent research work in the future.