The influences of curing pressure on the physical and mechanical property development of oil well cement during long-term curing were studied. Five silica-enriched cement slurries designed without and with reinforcement materials (latex fiber and nano-graphene) were autoclaved at 200 °C under two different pressures. The low pressure (50 MPa) curing was conducted for 2, 60, 90 and 180 days; the high pressure (150 MPa) curing was conducted for 2 and 360 days. The physical and mechanical properties of set cement were characterized by compressive strength, Young’s modulus, and water/gas permeability; the mineral composition and microstructure were determined by X-ray diffraction, mercury intrusion porosimetry, thermogravimetry and scanning electron microscope. Test results showed that high pressure (150 MPa) curing led to a more compact microstructure, which reduced the rate of strength retrogression in the long term. Samples with reinforcement materials, especially the latex fiber, showed higher compressive strength, Young’s modulus and lower permeability during long-term curing at both pressures.

During deep coalbed methane (CBM) drilling, wellbore stability is significantly influenced by the interaction between drilling fluid and coal rock. However, quantitative data on mechanical degradation under long-term high-temperature and high-pressure conditions are lacking. This study subjected coal cores to immersion in field-formula drilling fluid at 60 °C and 10.5 MPa for 0–30 days, followed by uniaxial and triaxial compression tests under confining pressures of 0/5/10/20 MPa. The fracture evolution was tracked using micro-indentation (µ-indentation), nuclear magnetic resonance (NMR), and scanning electron microscopy (SEM), establishing a relationship between water absorption and strength. The results indicate a sharp decline in mechanical parameters within the first 5 days, after which they stabilized. Uniaxial compressive strength decreased from 36.85 MPa to 22.0 MPa (−40%), elastic modulus from 1.93 GPa to 1.07 GPa (−44%), cohesion from 14.5 MPa to 5.9 MPa (−59%), and internal friction angle from 24.9° to 19.8° (−20%). Even under 20 MPa confining pressure after 30 days, the strength loss reached 43%. Water absorption increased from 6.1% to 7.9%, showing a linear negative correlation with strength, with the slope increasing from −171 MPa/% (no confining pressure) to −808 MPa/% (20 MPa confining pressure). The matrix elastic modulus remained stable at 3.5–3.9 GPa, and mineral composition remained unchanged, confirming that the degradation was due to hydraulic wedging and lubrication of fractures rather than matrix damage. These quantitative thresholds provide direct evidence for predicting wellbore stability in deep CBM drilling.

A high-temperature and high-pressure gas field in an oil field requires the use of super 13 chromium material due to corrosive environments. In the recent production process, there have been four consecutive cases of corrosion, fracture, and perforation of tubing nipples, which have brought enormous economic losses to the oilfield. This article analyzes the failure causes of these four tubing nipples and proposes preventive measures. In this paper, the macroscopic morphology, chemical composition, mechanical properties, metallography, and microscopic morphology of four failed tubing nipples have been analyzed. Combined with the field service conditions and string structure of the tubing nipples, it is believed that the failure of the tubing nipples is mainly due to the connection of carbon steel and stainless steel materials, forming a typical galvanic corrosion galvanic cell. The geometric and environmental factors of the materials exacerbate this corrosion. Eventually, severe galvanic corrosion occurred on the inner surface of the tubing nipple, resulting in severe wall thinning or partial perforation, and four tubing nipples failed. The failed tubing nipples in Wells A, B, and C have erosion marks, which are caused by the action of high pressure and high flow rate fluids in the well; The inner surface of the tubing nipple in Well D is rusty yellow, mainly due to the corrosion of its inner wall caused by the acid fracturing fluid injected earlier. At the same time, the string structure of four wells shows that the tubing nipple is located at the variable diameter node of the string. When the fluid in the well flows from the large hole into the smaller hole, the fluid in the well will change there, and its flow rate and pressure will also increase, further exacerbating the erosion in this area. With the development of deep wells containing carbon dioxide in oil fields and the application of carbon dioxide injection secondary oil recovery technology, the use of 13Cr martensitic stainless steel is also increasing. In order to avoid the occurrence of similar accidents that will bring huge economic losses to the oil field, it is recommended that the material of the pipe string (including accessories) of such wells be confirmed using a portable direct reading spectrometer before entering the well.

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.