During gas production, the wellbore operates under high temperature and high pressure conditions, where gas–liquid two-phase flow is commonly present. Thus, it is important to understand the holdup of different flow patterns of gas–liquid two-phase flow in the wellbore. Currently, prediction models for flow patterns and holdup are mainly based on experimental data obtained under normal temperature and pressure, judged by researchers’ subjective observations, resulting in the lack of a unified flow pattern boundary so far. This article uses CFD simulation to study the characteristics of high temperature and high pressure gas–liquid two-phase flow in wellbores and obtains data such as flow pattern, probability density distribution of gas content, and liquid holdup. The results indicate that pressure is the dominant factor affecting the transition of gas–liquid two-phase flow patterns in wellbores. Under high temperature and pressure, each flow pattern has unique probability density distribution characteristics of gas content, which can be used as a basis for flow pattern identification. Flow pattern diagrams of gas–liquid two-phase flow at room temperature and pressure as well as high temperature and high pressure were drawn, and a boundary model for the transition of gas–liquid two-phase flow patterns in wellbores under the influence of variable pressure was established, verifying the rationality of the flow patterns’ transition boundaries. Based on the simulation of high temperature and high pressure gas–liquid two-phase flow in the wellbore, a calculation model for gas–liquid two-phase flow in the wellbore was established. The absolute percentage error between this model and the Fluent simulation results is within 10%, which can achieve the calculation of gas–liquid two-phase flow in the wellbore under different temperature and pressure conditions.

Based on static scale inhibition experiments and molecular dynamics (MD) simulations, this study investigated the influence of concentration and temperature on the scale inhibition performance and adsorption behavior of the hydroxyphosphonic acid-based XCN scale inhibitor on calcite (104) surfaces. Experimental results demonstrate that XCN exhibits excellent inhibition efficiency against CaCO₃ scale, achieving 91.26% at 30 ppm and 60 °C. Further increasing the concentration to 35 ppm improves the inhibition rate by only 0.52%, a marginal gain attributable to the threshold effect. Performance improves with decreasing temperature, increasing from 91.26% at 60 °C to 96.92% at 30 °C. MD simulations reveal that the adsorption energy between XCN and calcite peaks at a specific molecular count (9 molecules), indicating optimal surface coverage. Radial distribution function analyses confirm chemisorption via Ca-O and Ca-H interactions within 1–3.5 Å, inducing lattice distortion that inhibits crystal growth. However, increasing temperature weakens adsorption and promotes molecular desorption, reducing inhibition efficiency. These findings provide molecular-level insights into the threshold and thermal behaviors of phosphonic acid scale inhibitors, supporting the optimized application of XCN in oilfield operations.

This study investigates the use of fly ash to mitigate the long-term performance degradation of Portland cement-based sealing materials in high-salinity environments, such as those found in gas storage reservoirs. We systematically evaluated the evolution of material properties under different temperatures and curing periods. Our integrated methodology combining mechanical tests, microstructural analysis, and chloride migration assessment, reveals a multi-faceted mechanism by which fly ash enhances chloride resistance. The key findings demonstrate that reactive Al₂O₃ in fly ash promotes the formation of Friedel’s salt, increasing chemical chloride binding and reducing the chloride ingress rate in the Portland cement–Fly ash system (PFS) to only 26.6% of that in the Portland Cement system (PCS). Concurrently, the pozzolanic reaction consumes portlandite (Ca(OH)₂), forming stable C-A-S-H gel and refining the pore structure by filling interconnected channels. This nanoscale pore refinement decreased permeability by nearly an order of magnitude. After 90 days of curing in 90 °C saline solution, PFS achieved a compressive strength of 28.2 MPa and maintained an exceptionally low internal chloride content of 0.08 wt.%, demonstrating superior long-term durability. This work clarifies the synergistic mechanisms of fly ash modification and temperature effects, providing a theoretical basis for optimizing sealing materials for deep geological reservoirs and experimental support for the application of fly ash in high-temperature, high-salinity engineering environments.

Wellbore instability and sand production pose critical challenges in deep tight sandstone reservoirs, severely impairing wellbore integrity and reducing hydrocarbon recovery. This study introduces, for the first time, the combined finite–discrete element method (FDEM) to numerically simulate sand production under high in situ stress. The FDEM By seamlessly integrates continuum and discontinuum representations within a unified framework, enabling the simulation of the complete failure sequence—from matrix damage and fracture growth to granular flow. High-resolution numerical simulations are conducted to compare intact and naturally fractured formations, with a focus on the governing role of pre-existing geological discontinuities. Results show that in intact sandstone, stress concentration drives helical crack growth leading to a symmetrical V-shaped breakout, with a critical borehole pressure (CBHP) of 60.05 MPa required to prevent instability. In fractured rock, however, pre-existing fractures act as dominant weakness planes that distort the stress field and induce earlier, asymmetric failure, raising the CBHP to 64.05 MPa. A strong negative linear correlation is observed between reservoir pressure depletion and CBHP: a pore-pressure reduction of 23.75 MPa decreases the CBHP by 4.8–5.0 MPa. Notably, natural fractures amplify the destabilizing effect of depletion, raising the required CBHP by 4.0 MPa at initial reservoir pressure (95 MPa) and by 5.0 MPa under full depletion. Consequently, although fractured formations require a higher CBHP (64.05 MPa vs. 60.05 MPa), their safe operating window is effectively narrower. These findings advance the mechanistic understanding of fracture-controlled sand production and provide a validated numerical framework for determining safe production pressures in deep, fractured sandstone reservoirs.

The integrity of high temperature and high pressure (HTHP) gas well is one of the challenges to the safe and stable production of Tarim Oilfield. As a result, conducting test and evaluation on these wells are of great significance. In this paper, the state of the art of researches related to annular pressure are firstly reviewed, which is followed by the summary of the characteristics and applicable scenarios of the well integrity techniques. In terms of the fact that there are a lot of HTHP gas wells with annular pressure but large scale logging or snubbing operation is unworkable, a method of preliminary integrity is developed. For this method, annular pressure relief and recovery are firstly carried out, with using the ultrasonic method to determine the liquid level of annular space, the pressure gradient and leakage of the annular space can be determined. By using this method, test and evaluation on annular pressure of a HTHP gas well in Tarim Oilfield are conducted and the failure of well barrier parts are determined. Study and filed test show that this simple method can be useful in the preliminary screening of HTHP gas wells before the large scale test operation and thus providing technical support for the logging and snubbing operations.

To accommodate the extreme thermodynamic effects and erosion damage in throttling equipment for ultra-high-pressure natural gas wells (175 MPa), a coupled multiphase flow erosion numerical model for nozzles was established. This model incorporates a real gas compressibility factor correction and is based on the renormalized k-ε RNG (Renormalization Group k-epsilon model, a turbulence model that simulates the effects of vortices and rotation in the mean flow by modifying turbulent viscosity) turbulence model and the Discrete Phase Model (DPM, a multiphase flow model based on the Eulerian–Lagrangian framework). The study revealed that the nozzle flow characteristics follow an equal-percentage nonlinear regulation pattern. Choked flow occurs at the throttling orifice throat due to supersonic velocity (Ma ≈ 3.5), resulting in a mass flow rate governed solely by the upstream total pressure. The Joule–Thomson effect induces a drastic temperature drop of 273 K. The outlet temperature drops below the critical temperature for methane hydrate phase transition, thereby presenting a substantial risk of hydrate formation and ice blockage in the downstream outlet segment. Erosion analysis indicates that particles accumulate in the 180° backside region of the cage sleeve under the influence of secondary flow. At a 30% opening, micro-jet impact causes the maximum erosion rate to surge to 3.47 kg/(m²·s), while a minimum erosion rate is observed at a 50% opening. Across all opening levels, the maximum erosion rate consistently concentrates on the oblique section of the plunger front. Results demonstrate that removing the front chamfer of the plunger effectively improves the internal erosion profile. These findings provide a theoretical basis for the reliability design and risk prevention of surface equipment in deep ultra-high-pressure gas wells.