The sensitivity of gas and water phases to DAS acoustic frequency bands can be used to interpret the production profile of horizontal wells. DAS typically collects acoustic signals in the kilohertz range, presenting a key challenge in identifying the sensitive frequency bands of the gas and water phases in the production well for accurate interpretation. In this study, a gas–water two-phase flow–acoustic coupling model for a horizontal well is developed by integrating a gas–water separation flow model with a pipeline acoustic model. The model simulates the sound pressure level (SPL) and amplitude variations of acoustic waves under different flow patterns, spatial locations, and gas–water ratio schemes. The results demonstrate that within the same flow pattern, an increase in the gas–water ratio significantly elevates acoustic amplitude and SPL peaks within the 5–50 Hz frequency band. Analysis of oil field DAS data reveals that the amplitude response range for stages with a lower gas–water ratio falls within 5–10 Hz, whereas stages with a higher gas–water ratio exhibit an amplitude response range of 10–50 Hz.

This study employed a full-scale cement sheath quality evaluation apparatus, along with a high-precision distributed fiber optic temperature sensing system, to perform real-time, continuous monitoring of the temperature change throughout the cement hydration process. The results of the cement annulus and cement bond defect monitoring during the hydration process indicated that the distributed fiber optic temperature data enabled centimeter-level resolution in defect identification. Defective regions exhibited significantly reduced temperature fluctuation amplitudes, and an inversion in temperature change at the early hydration stage, detected at the cement–defect boundary, facilitated the early detection of defect locations. The distributed fiber optic system was capable of conducting continuous and comprehensive monitoring of the sequential hydration temperature peaks of cement stages injected into the annulus. The results revealed the interdependence among different cement stages, as well as a phenomenon whereby an elevated annular temperature accelerates the progression of cement hydration. The experimental findings provide a reference for identifying the characteristic signals in distributed fiber optic monitoring of well-cementing operations, thereby establishing a foundation for the optimal and effective use of distributed fiber optics in assessing well-cementing quality.

Ensuring long-term wellbore integrity is critical for carbon dioxide geological storage. Ordinary Portland cement (PC) is usually used for wellbore primary cementing and plug operation, and set cement is easily corroded by acidic fluids, such as carbon dioxide, in underground high-temperature and high-pressure (HTHP) environments, resulting in a decrease in the mechanical properties and an increase in permeability. In order to achieve long-term wellbore integrity in a CO₂-rich environment This study introduces materials such as thermosetting vinyl ester resin (TSR), filler composite resin (FCR), and low-cost resin cement (RC). Corrosion experiments were conducted using four materials in 28 days under supercritical carbon dioxide gas and water phase conditions of 60 °C and 10 MPa. The samples were characterized through mechanical property testing machines, core permeability measuring instruments, FTIR, XRD, and SEM. The results proved that after corrosion, PC mechanical properties decreased, the permeability increased, and the microscopic composition and morphology changed greatly. Penetrating corrosion occurs in the sample in the gas phase environment, and propulsive corrosion from outside to inside occurs in the water phase environment. However, TSR, FCR, and RC materials all maintain excellent resistance to carbon dioxide corrosion in gas and water environments. They have higher compressive strength and extremely low permeability compared to ordinary Portland cement. These three materials’ compressive strengths can be maintained around 131, 99, and 58 MPa, and permeability can be stabilized at <6 × 10⁻⁷, <6 × 10⁻⁷, and 0.16 mD levels. In summary, the above three materials all show better performance than ordinary Portland cement and are promising alternative materials that can be used in primary cementing and plug operations of carbon dioxide geological storage wells.

Tight oil reservoirs tend to contain more natural fractures, and the presence of natural fractures leads to a greater stress sensitivity in tight oil reservoirs. It is a very challenging task to model the seepage in the volume fracturing horizontal wells considering the stress-sensitive effects. Based on the Laplace transform, Perturbation transform and Stefest numerical inversion, this paper establishes a horizontal well seepage model for volume fracturing in fractured stress-sensitive tight oil reservoirs. This model allows us to analyze and study the effect of stress sensitivity, fracture interference, dual media and complex fracture network on seepage flow in tight oil reservoirs. We apply the model to delineate the seepage stages of volume fracturing horizontal wells, it can be divided into seven seepage stages I wellbore storage flow, II surface flow stage, III transition flow, IV natural fracture system proposed radial flow, V interporosity flow, VI system proposed radial flow and VII stress-sensitive flow stage. Wellbore storage coefficient mainly affects the flow in the wellbore storage stage. The larger the wellbore storage coefficient is, the longer the duration of wellbore storage flow will be. The higher the skin coefficient is, the greater the pressure drop is. The storage capacity ratio has a greater influence on the flow before the occurrence of channeling flow, and the “groove” depth on the derivative curve of dimensionless pressure drop becomes shallower with the increase in storage capacity ratio. The higher the channeling coefficient is, the earlier the channeling occurs from the matrix system to the natural fracture system and the more leftwing the “groove” position is.

In the marine natural gas hydrate solid-fluidization mining process, current separation devices are insufficient in de-bonding the hydrate cementation between sand particles, affecting the hydrate collection efficiency. To address this issue, a composite separator was designed in this study that is used to restrict the axial movement of cemented particles, thereby achieving the goal of enhanced de-bonding efficiency. A combined computational fluid dynamics–discrete element method simulation method was used to verify the de-bonding performance of this composite separator on weakly cemented hydrate particles with different sizes and to study the influence of the spiral flow channel structural parameters and inlet types on the de-bonding performance.