The electric heating process for lifting heavy oil has been widely applied. However, research on its temperature field laws mostly focuses on onshore heavy oil wells, while research offshore is limited. Therefore, based on the energy conservation equation and heat transfer theory, a transient one-dimensional wellbore temperature model coupled with the temperature and viscosity of heavy oil and considering the effect of time was developed. In order to verify the accuracy of the model, the results of the previous model were used for comparison with the present model, and the results showed that the model has good accuracy. The results show that a reasonable selection of the process parameters of electric heating can increase the production of heavy oil while saving development costs and improving the economic benefits of the oilfield. The conclusions and recommendations of this paper can provide a theoretical basis and guiding suggestions for the optimal design of process parameters for lifting heavy oil using an offshore electric heating process.

The sand conglomerate has strong heterogeneity, great difference in rock mechanical properties, and serious filtration loss of fracturing fluid. In order to describe the effect of heterogeneous gravel distribution on the filtration loss of conglomerate reservoir, a dual media filtration model was established based on the equivalent flow principle, and the heterogeneous distribution relationship was characterized by Fuller gradation and solved by numerical method. The degree of non-uniformity, formation gravel characteristics and pressure process parameters were taken into account for simulation analysis and calculation. The results show that the average filtration rate of 60% gravel content is 54.2% lower than that of 20% gravel content. When the degree of non-uniformity is 6, the average filtration rate is 73% higher than that of uniformity. Injection rate and injection pressure have a great influence on the filtration loss of fracturing fluid. The research results can provide theoretical support for fracturing optimization design.

Gravel sandstone reservoirs are characterized by low porosity, low permeability, and strong heterogeneity, presenting significant challenges for hydraulic fracturing. This study investigates the fracture propagation mechanisms in gravel sandstone formations using a combination of laboratory experiments, numerical simulations, and theoretical modeling. The findings reveal that gravel size, strength, and distribution significantly influence fracture morphology and propagation behavior. Under low stress differences, cracks tend to wind around gravel, while under high stress differences, cracks are more likely to penetrate gravel. Numerical simulations highlight the complex fracture network caused by high gravel content, leading to increased filtration loss, accelerated energy dissipation, and reduced fracture length. A quantitative model was developed to describe trans-gravel behavior, offering theoretical support for optimizing hydraulic fracturing designs in gravel sandstone reservoirs. This work provides valuable insights into the coupling mechanisms between gravel properties, stress conditions, and fracture propagation, contributing to more effective stimulation strategies for complex reservoirs.

High temperatures in ultra-deep buried-hill wells of the Bohai Bay Basin and rapid wellbore temperature recovery after circulation shutdown restrict the available operating time of logging tools. To quantitatively determine the safe logging window, a transient wellbore–formation heat transfer model was developed to simulate the complete circulation cooling and shut-in recovery process. Formation thermal heterogeneity was characterized using lithology, porosity, and shale volume fraction, and the governing equations were solved using a hybrid explicit–implicit finite volume method with refined radial grids near the wellbore and stage-dependent time stepping. The safe logging window was determined according to the allowable operating temperature of logging tools. Field validation in Well M15 yielded a mean absolute error and root mean square error of 0.75 °C and 0.87 °C, respectively, while the relative temperature prediction errors for another 12 wells were all below 5%. Benchmark tests demonstrated that the proposed method reduced computational time by approximately 69% compared with the uniform small-time-step scheme. Under the investigated conditions, increasing the circulation rate from 10 L/s to 30 L/s reduced the bottom-hole temperature from approximately 120 °C to 65 °C, whereas the cooling benefit gradually diminished at higher rates. The safe logging window exhibited clear dependence on measurement depth and tool temperature limits; at 5274.87 m in Well M15, the predicted windows were 3.32 h and 17.78 h for temperature limits of 150 °C and 170 °C, respectively. Sensitivity analysis indicated that the geothermal gradient was the dominant factor affecting the safe window, while thermal conductivity and bedding anisotropy also influenced the prediction results. The proposed model provides a quantitative basis for optimizing circulation cooling strategies and logging timing in ultra-deep buried-hill wells and offers an effective approach for safe logging window evaluation under high-temperature complex geological conditions.