Drilling fluid plays a critical role in drilling engineering. With the deepening implementation of clean production concepts and increasingly stringent environmental regulations, the treatment standards for drilling wastewater at operational sites have been significantly elevated. In response to the characteristics of high oil content, high COD, high chromaticity, high ammonia nitrogen, and total phosphorus content in drilling, the use of fine bubbles to improve gas utilization efficiency and mass transfer effect, combined with ozone gas, is aimed at degrading difficult-to-degrade high-molecular-weight organic compounds, aiming to solve the problems of high viscosity and high oil content in drilling fluids returned from offshore platforms. Indoor simulation experiments have shown that by using ozone fine bubble technology to treat drilling fluids, the viscosity reduction rate can reach over 29%, and the oil removal rate can reach 40%. Ozone fine bubble technology has significant viscosity reduction and oil removal effects on high viscosity drilling fluids.

Low salinity water containing sulfate ions can significantly alter the surface wettability of carbonate rocks. Nevertheless, the impact of sulfate concentration on the desorption of oil film on the surface of carbonate rock is still unknown. This study examines the variations in the wettability of the surface of carbonate rocks in solutions containing varying amounts of sodium sulfate and pure water. The problem is addressed in the framework of molecular dynamics simulation (Material Studio software) and experiments. The experiment’s findings demonstrate that sodium sulfate can increase the rate at which oil moisture is turned into water moisture. The final contact angle is smaller than that of pure water. The results of the simulations show that many water molecules travel down the water channel under the influence of several powerful forces, including the electrostatic force, the van der Waals force and hydrogen bond, crowding out the oil molecules on the calcite’s surface and causing the oil film to separate. The relative concentration curve of water and oil molecules indicates that the separation rate of the oil film on the surface of calcite increases with the number of sulfate ions.

The low permeability and submicron throats in most shale or tight sandstone reservoirs have a significant impact on microscale flow. The flow characteristics can be described with difficultly by the conventional Darcy flow in low-permeability reservoirs. In particular, the thickness of the boundary layer is an important factor affecting the formation permeability, and the relative permeability curve obtained under conventional conditions cannot accurately express the seepage characteristics of porous media. In this work, the apparent permeability and relative permeability were calculated by using non-Darcy-flow mathematical modeling. The results revealed that the newly calculated oil–water relative permeability was slightly higher than that calculated by the Darcy seepage model. The results of the non-Darcy flow based on the conceptual model showed that the area swept by water in non-Darcy was smaller than that in Darcy seepage. The fingering phenomenon and the high bottom hole pressure in the non-Darcy seepage model resulted from the larger amount of injected water. There was a large pressure difference between the injection and production wells where the permeability changed greatly. A small pressure difference between wells resulted in lower variation of permeability. Consequently, the non-Darcy simulation results were consistent with actual production data.

The prevalence of micropores and nanopores in low-permeability reservoirs is a cause for concern, as it results in a sizeable quantity of oil reserves being trapped within them. The water-gas dispersion system has the capacity to expand the reservoirs’ wave volume and enhance oil recovery. While the microscopic oil repulsion mechanism has been the center of attention, the oil repulsion effect of three distinct types of gases (N₂, CH₄, and CO₂) is of particular importance in understanding the displacement mechanism of N₂/CH₄/CO₂ on heptane at the blind end of the nanometer. A molecular dynamics simulation using the LAMMPS software was employed to construct a model of a blind end of heptane on a SiO₂ wall and an interface model with different types of gas molecules. This was done to investigate the microscopic mechanism of heptane replacement by gas molecules. The temperature (50 °C) and pressure (30 MPa) of the reservoir in the Changqing oil field are selected as the parameters for analysis. The findings indicate that all three types of gas molecules can enter the blind end and displace heptane. However, supercritical CO₂ forms a mixed phase with heptane, which is more prone to extruding oil molecules situated near the inner wall surface of the blind end and desorbing the oil film. The results demonstrate that, in the context of the blind end, gaseous CO₂ exhibits a lower solvation ability but superior extrusion diffusion ability for heptane compared to N₂ and CH₄. Furthermore, the interaction energy indicates that the interactions between two states of CO₂ and heptane, as well as the thickness of the interface, increase with increasing pressure and temperature. The findings of this study elucidate the microscopic mechanism underlying the replacement of oil droplets or oil films at the blind end by different gases under reservoir conditions at the molecular level and offer further guidance for the selection of the gas phase and the replacement state in the water-gas dispersive drive system.

The treatment of high-viscosity oil-bearing drilling mud from offshore platforms is constrained by limited space and stringent environmental regulations, yet no previous study has demonstrated the combined application of ozone-assisted micro-nano bubble (MNB) oxidation with filtrate recycling for this specific waste stream. Here, we address this gap by integrating ozone MNB treatment, flotation oil removal, and filtrate reuse into a unified process for the viscosity reduction and deoiling of water-based drilling mud. Experimental results show that the ozone MNB process achieves a viscosity reduction rate exceeding 50.2% and an oil removal rate of 60.87%, with filtrate ion concentrations (Ca²⁺ 382 mg/L, Mg²⁺ 1380 mg/L, SO₄²⁻ 1107 mg/L) within reuse thresholds. Drilling fluid reformulated with the recycled filtrate maintains consistent rheological properties before and after thermal aging. These findings demonstrate that the coupled ozone MNB treatment-reuse strategy is scientifically viable for managing high-viscosity drilling waste, advancing beyond conventional disposal approaches by enabling simultaneous viscosity reduction, oil removal, and resource recovery within a compact process footprint.