Search Results (6)

The generation and propagation mechanisms of acoustic waves from leakage below the annular liquid level in gas wells have attracted widespread attention. To study the characteristics of acoustic sources beneath the liquid level, a physical model of leakage in the casing–tubing annulus was established by simulating the distribution patterns of the flow field and acoustic field within the annulus under tubing leakage conditions. Distinct from the traditional acoustic analysis of wellbore leakage in gas wells, this study focuses on acoustic waves generated by leaks located below the annular protection fluid level. It analyzes the flow regime and acoustic source characteristics beneath the liquid level under various operating conditions (including leakage aperture, velocity, and position). The research summarizes the evolution patterns of flow regimes when gas leaks into the annular protection fluid under different conditions and elucidates the generation mechanism of sub-liquid leakage noise and its propagation mechanism across the liquid surface. This work lays the theoretical foundation for detecting sub-liquid leakage at the wellhead using acoustic methods. Full article

In response to the limitations of experimental methods for detecting oil and gas well tubing leaks, this study developed a full-scale indoor simulation system for oil tubing leakage. The system consists of three components: a wellbore simulation device, a dynamic leakage simulation module, and a multi-parameter monitoring system. The wellbore simulator employs a jacketed structure to replicate real-world conditions, while the leakage module incorporates a precision flow control device to regulate leakage rates. The monitoring system integrates high-sensitivity acoustic sensors and pressure sensors. Through multi-condition experiments, the system simulated complex scenarios, including leakage apertures of 1–5 mm, different leakage positions relative to the annular liquid level, and multiple leakage point combinations. A comprehensive acoustic signal processing framework was established, incorporating time–domain features, frequency–domain characteristics, and time–frequency joint analysis. Experimental results indicate that when the leakage point is above the annular liquid level, the acoustic signals received at the wellhead exhibit high-frequency characteristics typical of gas turbulence. In contrast, leaks below the liquid level produce acoustic waves with distinct low-frequency fluid cavitation signatures, accompanied by noticeable medium-coupled attenuation during propagation. These differential features provide a foundation for accurately identifying leakage zones and confirm the feasibility of using acoustic detection technology to locate concealed leaks below the annular liquid level. The study offers experimental support for improving downhole leakage classification and early warning systems. Full article

Due to the failure of string seals, gas can leak and result in the abnormal annulus pressure in gas wells, so it is necessary to relieve the pressure in gas wells. In the process of pressure relief, the leaked gas enters the annulus, causes a the great disturbance to the annulus flow field, and thus reduces the protection performance of the annular protection fluid in the string. In order to investigate the influence of gas leakage on the annular flow field, a VOF finite element model of the gas-liquid two-phase flow disturbed by gas leakage in a casing was established to simulate the transient flow field in the annular flow disturbed by gas leakage, and the influences of leakage pressure differences, leakage direction, and leakage time on annular flow field disturbance and wall shear force were analyzed. The analysis results showed that the larger leakage pressure difference corresponded to the faster diffusion rate of the leaked gas in the annulus, the faster the flushing rate of the leaked gas against the casing wall, and a larger shear force on the tubing wall was detrimental to the formation of the corrosion inhibitor film on the tubing wall and casing wall. Under the same conditions, the shear action on the outer wall of tubing in the leakage direction of 90° was stronger than that in the leakage directions of 135° and 45° and the diffusion range was also larger. With the increase in leakage time, leaked gas further moved upward in the annulus and the shear effect on the outer wall of tubing was gradually strengthened. The leaked acid gas flushed the outer wall of casing, thus increasing the peeling-off risk of the corrosion inhibitor film. The study results show that the disturbance law of gas leakage to annular protection fluid is clear, and it was suggested to reduce unnecessary pressure relief time in the annulus to ensure the safety and integrity of gas wells. Full article

The failure of managed-pressure running casing in oil and gas wells may lead to complex accidents such as overflow or leakage. The technique of using multi-density gradient drilling fluids in wellbores with negative pressure windows (NPWs) is often used to deal with this situation. Therefore, it is vital to analyze the dynamic slurry column structure and calculate the wellbore pressure during casing running. For this issue, the model of transient surge pressure is established during casing running. The calculation equation of the model is proposed, and the calculations of the wellbore pressure are carried out with the exploration of Well LT-X1, located in the Xinjiang oil field. A circulation scheme is designed as follows: Circulate 125 m³ of drilling fluid with a density of 2.45 g/cm³ and 155 m³ of drilling fluid with a density of 2.35 g/cm³ at a depth of 3560 m. From there, circulate 164 m³ of drilling fluid with a density of 2.35 g/cm³ at a depth of 5900 m. Finally, at a depth of 7050 m, circulate 250 m³ of drilling fluid with a density of 2.30 g/cm³. The casing running speeds and back-pressure values were designed as follows for the respective well sections: 0–1523 m: 0.160 m/s casing speed, 0 MPa back pressure; 1523–3560 m: 0.160 m/s casing speed, 1.641 MPa back pressure; 3560–5900 m: 0.145 m/s casing speed, 2.427 MPa back pressure; 5900–6674 m: 0.137 m/s casing speed, 4.041 MPa back pressure; 6674–7050 m: 0.124 m/s casing speed, 4.457 MPa back pressure. The results show that optimizing structure of the multi-density gradient drilling fluid with different densities and applying annular back pressure in stages, with the accurate calculation of wellbore pressure, can achieve the goals of leak-proofing and pressure-stabilization. It is concluded that this result may serve as the foundation for managed-pressure running casing technology. Full article

The pressure bleed-down/build-up (B/B) testing is enforced by the Bureau of Safty and Environmental Enforcement (BSEE) regulations in the US for gas-leaking wells with recurrent casing head annular pressure dubbed “Sustained Casing Pressure” (SCP). The bleed down test involves bleeding the pressure with a needle valve. Once the pressure reached to zero or stabilized, the valve is closedand a 24-h pressure monitoring starts. Analysis of the tests mandated by regulations involves merely a qualitative assessment of the low or high level of environmental risk measured by leak size. A quantitative analysis—based on mathematical models—has been already proposed and used for sizing cement leaks but the models give ambiguous results due to oversimplifying assumptions of the cement leak system and disregard for the testing procedure. This work addresses shortcomings of the current B/B testing and analysis methods by approaching the testing procedure as a source of useful information about the system of annular well leakage. We demonstrate that using a mathematical model for globally matching all stages of the B/B test data would prioritize the pressure bleed-down stage over the buildup stage thus making the latter stage mostly irrelevant in providing information on the whole gas migration system. We verify the hypothesis that a stage-wise analysis would improve the results by separately considering three stages of the B/B test: pressure bleed down, constant flow (steady-state), and pressure buildup, and, then, comparatively reconciling values of the system parameters. The stage-by-stage approach is feasible because—as shown by the sensitivity analysis—each stage is controlled mostly by a single parameter. Also presented is the development of an improved procedure for performing the B-B test. The study shows that the operational parameters controlled by the test operator—duration and size of the needle valve opening, and pressure recording time step, might significantly change values of the test output—the minimum bleed down, and the maximum 24-h buildup pressures. It is also found that the zero bleed-down pressure does not necessarily indicate that the leak is small as it also depends upon the length and properties of the annular fluid column above the cement top. Full article

Offshore drilling operations exhibit various difficulties attributed to shallow flows worldwide. One of the most common practices for drilling offshore wells is to use liners and liner hangers rather than using full casing strings. This reduces the cost of drilling operation. Liners and liner hangers are required to pass certain standards prior to their deployment in the field. This ensures their ability to withstand harsh downhole conditions and maintain the integrity of the well. A liner hanger contains an integrated seal assembly that acts as a barrier to prevent fluid migration. The cement that is placed within the casing–liner overlap is also considered a barrier, and it is critical that it maintains the integrity of the well by mitigating fluid migration to other formations and to the surface. The failure of this dual barrier (cement and seal assembly) system to seal the annular space can result in serious problems that might jeopardize a well’s integrity. Typically, in field applications, the length of a casing–liner overlap is chosen arbitrarily. In some cases, shorter overlaps (50 to 200 ft) are chosen because of the lower cost and easy identification of leaks during pressure tests. However, some loss of well control incidents (particularly the incident that motivated this study) have been linked to fluid leakages along the casing–liner overlap. This paper investigates the critical length of the casing–liner overlap by modeling gas leakage through the cement placed within the overlap using analytical and experimental approaches. Leakage scenarios were developed to mimic gas migration within the cement in the casing–liner overlap. The results showed that the longer the casing–liner overlap, the higher the leakage time. The results also showed that the current casing pressure test duration of 30 min may not be adequate to verify the integrity of the cement within the overlap. Based on the results and analyses, it is recommended to increase the pressure test duration to 90 min. In addition, the results suggest that the length of the casing–liner overlap should not be less than 300 ft to maintain the integrity of the well in the case of gas influx. Further details are highlighted in the results section. In practice, the current rationale behind the selection of a casing–liner overlap length is not sustainable. Thus, the major advantage of this study is that with field data, it provides both scientific and research-based evidence that can be used to inform the decision behind the selection of the casing–liner overlap length, especially in gas migration-prone zones. Full article