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As the development of oil fields progresses, an increasing number of fields are entering high water-cut stages.Onsite oil-water separation and wastewater reinjection are crucial for reducing water treatment loads and energy consumption in crude oil transportation. Traditional oil-water separators suffer from issues such as large size and low separation efficiency. Therefore, this paper investigates a highly efficient centrifugal supergravity oil-water separator. Numerical simulations examined the impact of flow parameters, structural parameters, and physical properties on the separator’s flow field and performance. The research findings reveal that the oil-water separation efficiency decreases with an increase in water content. As the inlet flow increased, the oil content at the water outlet continuously rose. With an increase in motor speed, the separation efficiency initially increased and then stabilized. Within the simulated range, the number of blades was positively correlated with the separation effect, while the blade ripple radius, oil density, and viscosity were negatively correlated with the separator's effectiveness. An increase in orifice diameter caused fluctuations in the separation effect and the oil content at the water outlet.

The critical gas flow is widely used to judge the loading status of vertical gas wells. Though it could demonstrate the carrying ability of gas flow, it cannot quantify how much liquid it can remove and it does not take into account the fact that the liquid-carrying ability of gas flow is limited in theory. In fact, the gas wells still load even if the gas production rate is larger than the critical gas flow, as the gas flow rate is not capable of bringing the whole liquid out of a pipe. In this study, the model of maximum liquid-carrying capability was established on the basis of the pipe flow dynamics theory to quantify the liquid-carrying ability of gas flow. By verifying the model with experiments, the formula of the maximum liquid-carrying capability under different degrees of deviation was obtained. Afterwards, the model was tested with the on-site data of the Sebei gas field. The results show that the relative error of the model is generally less than 10%, which meets the requirement of the gas field development. Finally, the graph of airflow capability was obtained, which brings convenience for the operators to estimate the liquid-carrying ability and make a healthy evaluation for the well.

Direct reinjection and discharge of water mixed with oil leads to environmental pollution and exhaust heat waste. Of the various methods used to treat wastewater, the mechanical vapor recompression (MVR) evaporation method has obvious advantages in energy consumption and environmental protection. In this paper, the use of MVR for water recovery from water co-produced with oil was studied and analyzed through experimentation. Based on the design calculations for the MVR system, the MVR rig was set up and a series of experimental studies were conducted. The results show that when keeping the suction pressure constant at 0.035 MPa, the compressor power increases with the increase of discharge pressure. The experimental value of the compressor power was slightly greater than the theoretical value, with a deviation of less than 5%. The amount of distilled water produced rose slightly when the compressor discharge pressure was increased. The power consumption for producing 1 m3of distilled water increased with the increase of discharge pressure, which is also in accordance with the design condition. The experimental value of the power consumption per unit of distilled water is larger than the theoretical value, but the deviation is within 10%.

The temperature distribution in the wellbore under different conditions was studied by using a designed horizontal well simulation experimental device. The experimental results showed that the Joule-Thomson effect was significant in perforated wellbore. When the opening mode was the same, the larger the gas flow rate, the lower the temperature in the wellbore. Furthermore, with the increase of liquid volume, the temperature drop effect decreased gradually. The more uniform the perforation distribution, the smaller the temperature change in the wellbore. With the increase of liquid volume, the influence of gas flow rate on temperature distribution decreased. The temperature gradient caused by Joule-Thomson effect decreased with the increase of wellbore holdup. At the same time, the experimental results were compared with the theoretical values. It was found that the error of the model was within 4%, which showed the reliability of predictions of the model.

With the continuous injection of CO2into the reservoir, a portion of the sequestered CO2is co-produced with crude oil, resulting in a significant concentration of CO2in the associated gas. Utilizing high CO2-content associated gas for offshore gas lift operations improves the reutilization of such gas and reduces costs related to sourcing and transporting it. To ensure smooth activation of the gas lift valve, conducting a thorough study on temperature and pressure within the wellbore during the gas lift process is essential. This study developed a dynamic model for calculating the transient temperature and pressure within offshore gas lift wellbores and fitted equations to calculate the physical properties of high CO2-content associated gas for specific compositions. This refinement minimized computational discrepancies arising from fluctuations in physical property parameters. When applying this model to oilfield scenarios, the maximum error observed was 3.83%, which aligned well with the accuracy standards required for oilfield computations. By integrating oilfield production data, this research explored the influence of injection parameters on temperature and pressure dynamics within the gas lift wellbore. The results revealed that variations in injection temperature and pressure had minimal impact on the temperature at the gas lift valve. Yet, they induced significant changes in the pressure at that point. An increase in CO2concentration within the gas source composition was associated with considerable shifts in temperature and pressure gradients throughout the wellbore. At high mass flow rates, the temperature gradient of the wellbore was notably reduced, while the pressure gradient was significantly enhanced. These research findings provided a theoretical basis for optimizing gas lift operations using high CO2-content associated gas in offshore settings.