Jinhui Li

In recent years, significant breakthroughs have been made in the exploration of deep to ultra-deep oil and gas reserves onshore in China. These conventional deep to ultra-deep reservoirs are typically buried at depths exceeding 4500 m, with bottom-hole temperatures surpassing 150 °C. The high temperatures at the bottom of the well are more likely to cause deterioration in drilling fluid properties, altering its rheological properties and reducing cutting transport efficiency, which can lead to wellbore cleaning issues. In this paper, the numerical simulation method is used to analyze the influence of cutting particle size, drilling fluid flow rate, drill pipe rotation speed, and drill pipe eccentricity on the annular cutting concentration under different wellbore drilling fluid temperature conditions. The results show that at the same cutting particle size, as the drilling fluid temperature increases, the cutting concentration in the annulus increases sharply. The increase is the largest when the particle size is 3 mm, and when the drilling fluid temperature is 220 °C, the cutting concentration increases by 79.7% compared to at 200 °C and by 279% compared to at 180 °C. When the flow rate increases from 0.5 m/s to 1.0 m/s, the annular cutting concentration at drilling fluid temperatures of 220 °C and 200 °C decreases by 70.5% and 50.4%, respectively. The higher the drilling fluid temperature, the better the cutting removal effect when increasing the drill pipe rotation speed. However, when the rotation speed exceeds 120 rpm, the change in cutting concentration with increasing rotation speed becomes insignificant. When the drill pipe eccentricity is small, an increase in drilling fluid temperature leads to a significant rise in annular cutting concentration. However, when the drill pipe eccentricity is large, changes in drilling fluid temperature have a smaller impact on cutting concentration. The research findings can provide engineering guidance and theoretical support for the design of drilling fluid hydraulic parameters for cutting transport and rheological parameters in high-temperature wellbores.

Most hot dry rock geothermal wells are small angle directional wells, and rock cuttings easily accumulate at the bottom of the borehole to form a cuttings bed, causing accidents such as drill sticking, reducing the rate of penetration, and drilling tool breakage. Accurately calculating the resistance coefficient and settling velocity of hot dry rock cuttings can improve cuttings transportation efficiency, design and optimize drilling hydraulic parameters, and is crucial to solving borehole cleaning problems. Through visual experiments, this paper obtained experimental data on the settlement of 167 groups of spherical pellets, 153 groups of granite cuttings, and 174 groups of carbonate cuttings in the Herschel-Bulkley fluid. First, a prediction model for the resistance coefficient of spherical pellets consistent with Herschel-Bulkley fluid was established. Based on this, form factor-Roundness is introduced as the starting point, and two prediction models for the resistance coefficients of granite cuttings and carbonate cuttings in the Herschel-Bulkley fluid were established. The average relative errors between the resistance coefficient model predictions and experimental measurements are 9.61% for granite cuttings and 6.59% for carbonate cuttings. The average relative errors between the predicted and measured values of settlement velocity are 7.27% for granite cuttings and 6.21% for carbonate cuttings, respectively, which verifies the accuracy and reliability of the prediction model. The research results can provide a theoretical basis and engineering application guidance for optimizing drilling fluid rheology and circulation displacement in engineering.