Yonghai Gao

During the drilling and well test operation cycles of horizontal wells, wellbore instability and collapse frequently occur in sand–mudstone reservoirs. The fallen wellbore debris and rock fragments accumulate inside the wellbore, triggering local wellbore blockage. At present, research regarding the influence of collapse-induced blockage on test productivity under various blockage conditions is lacking. A self-developed visualized experimental system for horizontal well productivity testing was adopted in this study to investigate the fluid flow characteristics and pressure loss in the wellbore under variable blockage degrees and fluid flow parameters. The influence mechanism of collapse blockage on flow pressure loss was analyzed. The results show that at low production rates (less than 100 m³/d) under blockage degrees of 1/3 and 2/3, the fluid flow velocity in the wellbore is low, and the collapsed solid fragments exhibit no migration behavior. Severe blockage can hardly form in the wellbore, and the proportion of hydraulic pressure loss along the wellbore to the total production pressure difference of the reservoir is relatively low. Under high production rates (greater than 150 m³/d), fine debris fills the voids between large collapsed fragments and forms blockages. Furthermore, the pipe flow friction factor of horizontal wells under different collapse blockage degrees was revised based on measured experimental data, which fills the theoretical gap for the selection of pipe flow friction factors under blockage conditions.

When a H₂S-containing gas kick occurs during drilling, the formation fluid containing hydrogen sulfide is mixed into the drilling fluid. Drilling fluid containing hydrogen sulfide is prone to causing hydrogen embrittlement when it comes into contact with the drill string during the upward return process. However, research on the risk and timing of hydrogen embrittlement in drill pipes remains limited. This study constructed a risk area and hydrogen embrittlement time analysis model. The risk area and time of hydrogen embrittlement in the drill pipe of the Jinyue 402 well in Tarim Oilfield were analyzed using the constructed model. The results indicate that the concentration of hydrogen sulfide in the Jinyue 402 well is in the area where the corrosion rate of steel increases rapidly, and the partial pressure of hydrogen sulfide is higher than the critical partial pressure at which corrosion cracking occurs. Taking into account the pH of the drilling fluid, fluid flow rate, hydrogen sulfide partial pressure, drill pipe tensile stress, hydrogen sulfide concentration, and gas partial pressure, the high-risk area for hydrogen sulfide corrosion damage in the Jinyue 402 well is 0–1680 m. The predicted highest risk point location and hydrogen embrittlement time are at a well length of 280 m and 21 h. Further predictions were made for the hydrogen embrittlement length and time of the Tazhong 83 and Zhonggu 503 wells in the Tarim Oilfield. The maximum prediction errors for the hydrogen embrittlement position and time of the drill pipe in the three wells were 4.8% and 5.2%, respectively. This indicates that the model can be applied to wells with different geological conditions and hydrogen sulfide concentrations.

Summary: Caused by the weak cementation of the reservoir rock, the safe pressure window for drilling in deepwater hydrate formations is narrow. However, during drilling in different layers, such as the hydrate-bearing layer (HBL) or three-phase layer (TPL), the migration and decomposition of hydrate cuttings and the generation of hydrates through gas phase transition result in complex multiphase flow in the annulus. This poses a challenge to the accurate prediction and control of equivalent circulating density (ECD). To study the effects of annular hydrate phase transition on ECD, we constructed a gas-liquid-solid transient flow model, taking into account factors such as drilling fluid salinity, interphase heat and mass transfer, hydrate cuttings migration and decomposition, and gas phase transition. We then compared the feasibility of the model against some drilling data from the second hydrate trial production well in the South China Sea, and used the model to analyze the influence of hydrate phase transition on ECD during the first and second hydrate trial drillings in different layers. The results indicate that the annular hydrate phase transition during riser drilling can reduce the ECD, and the maximum reduction in ECD at bottom under calculation conditions was 48.36 kg/m3. However, the effect of annulus phase transition on ECD is small in riserless drilling. Under the calculation conditions, the maximum increase in ECD at bottom was 3.09 kg/m3, caused by gas phase transition to hydrate when drilling in a TPL, and the maximum decrease in ECD at bottom was 6.72 kg/m3 because of hydrate cuttings decomposition when drilling in an HBL. ECD prediction is useful in the planning phase, and the proposed model is meant to provide a quantitative reference for understanding the magnitude of ECD variations under different conditions.

Summary: This study elucidates the dynamics of rock fragmentation under high-voltage electrohydraulic pulse (HVEP) fracturing by employing a fully coupled electric-thermal-mechanical-damage model. Although increased energy input generally promotes fracture propagation, we identify a previously unrecognized mechanism: heterogeneity-induced nonlinear pressure attenuation. This mechanism gives rise to anomalously high local pressure peaks (5.064 MPa) under lower-voltage pulses (10 kV), surpassing those induced by higher-voltage pulses (4.098 MPa at 12/14 kV). Quantitative analysis reveals significant energy dissipation, with a 97.18% pressure drop occurring within 3.75 m for 10-kV pulses. Simulation results indicate that discharge voltage predominantly controls the extent of final damage—yielding a 31.5% larger damaged area at 14 kV than at 10 kV after five pulses—whereas the cumulative impact of repeated discharges increases the damaged area by 632% relative to a single pulse. Taken together, these findings establish a synergistic framework in which initial energy input, heterogeneity-modulated wave propagation, and stress-induced damage feedback loops jointly dictate fracture outcomes, offering crucial theoretical insights for optimizing HVEP operations in geologically complex formations.

Summary: It is often essential to provide backpressure to the wellbore by changing the opening size of the choke valve when a gas kick is detected during managed pressure drilling (MPD), which maintains the pressure in the bottom of the hole. In this study, a mathematical model was developed to explain how backpressure waves spread and weaken in a wellbore during MPD when there is a gas-liquid two-phase flow. The model is founded on a two-phase flow model, which thoroughly accounts for the gravity, shear force, and interphase interactions between the gas and liquid phases. The small perturbation theory was used to compute the backpressure wave’s propagation speed and attenuation coefficient. The outcome showed satisfactory agreement with other scholars’ experimental results. The model was used to study the impacts of the following variables on the backpressure wave propagation properties: void fraction, temperature, pressure, interphase resistance, shear force, density, invading gas composition, displacement of the drilling fluid, rate of intrusion of gas, gas-liquid surface tension, and drilling fluid viscosity. By using an example well, the laws of pressure wave propagation speed, attenuation coefficient, and propagation time with well depth were analyzed. Through evaluative methods in the field of economic management, the principal control variables governing the propagation of backpressure waves were determined. The conclusion is that, in terms of operational feasibility, lower drilling fluid density and reduced drilling fluid displacement are advantageous for a faster propagation of backpressure waves to the bottom of the well.

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.

Offshore heavy oil resources are abundant, but they have greater difficulty and higher costs compared to onshore extraction. When crude oil flows through the seawater section, the temperature of the crude oil decreases faster, making it susceptible to solidification in the wellbore and resulting in lower well production. The cooling of crude oil becomes more pronounced in deep-water wellbore. However, the injection of low-temperature gas will have a cooling effect on the formation production fluid, which will have a negative effect. The model analyzes the effects of coiled tubing running depth, gas injection temperature, gas injection volume, coiled tubing diameter, and crude oil production on the temperature distribution of heavy oil in deep-water and shallow water wellbores. We propose recommendations for the selection of each parameter for deep and shallow water environments by analyzing and summarizing the laws.