Effective well control depends on the drilling teams’ knowledge of wellbore flow dynamics and their ability to predict and control influx. Unfortunately, detection of a gas influx in an offshore environment is particularly challenging, and there are no existing datasets that have been verified and validated for gas kick migration at full-scale annular conditions. This study bridges this gap and presents pioneering research in the application of fiber optic sensing for monitoring gas in riser. The proposed sensing paradigm was validated through well-scale experiments conducted at Petroleum Engineering Research & Technology Transfer lab (PERTT) facility at Louisiana State University (LSU), simulating an offshore marine riser environment with its larger than average annular space and mud circulation capability. The experimental setup instrumented with distributed fiber optic sensors and pressure/temperature gauges provides a physical model to study the dynamic gas migration in full-scale annular conditions. Current kick detection methods primarily utilize surface measurements and do not always reliably detect a gas influx. The proposed application of distributed fiber optic sensing overcomes this key limitation of conventional kick detection methods, by providing real-time distributed downhole data for accurate and reliable monitoring. The two-phase flow experiments conducted in this research provide critical insights for understanding the flow dynamics in offshore drilling riser conditions, and the results provide an indication of how quickly gas can migrate in a marine riser scenario, warranting further investigation for the sake of effective well control.

Early detection of a gas kick is crucial for preventing uncontrolled blowout that could cause loss of life, loss of assets, and environmental damage. Multiphase flow experiments conducted in this research demonstrate the capability of downhole fiber optic sensors to detect a potential gas influx in real-time in a 5000 ft deep wellbore. Gas rise velocities estimated independently using fiber optic distributed acoustic sensor (DAS), distributed temperature sensor (DTS), downhole gauges, surface measurements, and multiphase flow correlations show good agreement in each case, demonstrating reliability in the assessment. Real-time data visualization was implemented on a secure cloud-based platform to improve computational efficiency. This study provides novel insights on the effect of circulation rates, gas kick volumes, backpressure, and injection methods on gas rise dynamics in a full-scale wellbore.

A novel workflow is presented for integrating fiber optic Distributed Temperature Sensor (DTS) data in numerical simulation model for the Cyclic Steam Stimulation (CSS) process, using an intelligent optimization routine that automatically learns and improves from experience. As the steam–oil relationship is the main driver for forecasting and decision-making in thermal recovery operations, knowledge of downhole steam distribution across the well over time can optimize injection and production. This study uses actual field data from a CSS operation in a heavy oil field in California, and the value of integrating DTS in the history matching process is illustrated as it allows the steam distribution to be accurately estimated along the entire length of the well. The workflow enables the simultaneous history match of water, oil, and temperature profiles, while capturing the reservoir heterogeneity and the actual physics of the injection process, and ultimately reducing the uncertainty in the predictive models. A novel stepwise grid-refinement approach coupled with an evolutionary optimization algorithm was implemented to improve computational efficiency and predictive accuracy. DTS surveillance also made it possible to detect a thermal communication event due to steam channeling in real-time, and even assess the effectiveness of the remedial workover to resolve it, demonstrating the value of continuous fiber optic monitoring.

Effective well control depends on the drilling teams’ knowledge of wellbore flow dynamics and their ability to predict and control influx. Detection of a gas influx in an offshore environment is particularly challenging, and there are no existing datasets that have been verified and validated for gas kick migration at full scale annulus conditions. This study bridges this gap with the newly instrumented experimental well at PERTT (Petroleum Engineering Research & Technology Transfer Lab) at Louisiana State University (LSU) simulating an offshore marine riser environment with its larger than average annular space and mud circulation capability. The experimental setup instrumented with fiber optics and pressure/temperature gauges provides a physical model of the dynamic gas migration over large distances in full scale annular conditions. Current kick detection methods do not always reliably detect a gas influx and have not kept pace with the increasingly challenging offshore drilling conditions. Even though there have been some recent developments in offshore kick detection, all methods thus far are only qualitative in nature because they are based on measurements at the surface. This study addresses current kick detection limitations and illuminates the potential for implementing distributed fiber optic sensing (DFOS) to the marine riser as a non-invasive and effective kick detection method in both stagnant and circulating annular conditions. As North America's only academic full scale well testing center, an experimental well in the PERTT lab was utilized to monitor and characterize gas rise using DFOS to simulate well control scenarios in offshore drilling riser environments. DFOS allows for the tracking of the gas migration in both the stagnant and full-scale circulating annulus conditions. Data from pressure sensors is integrated with the distributed temperature (DTS) and acoustic (DAS) measurements, for real-time downhole monitoring of the dynamics of the gas migration and fluid front movement. By implementing time and frequency domain analysis of the fiber optic data, we show that the gas rise and water front movement can be identified. Both the water and gas injection down the tubing independently show characteristic fronts in the DTS and DAS data, which gives us confidence in our interpretation. Once the gas is present in the annulus, the DAS measurements indicate a higher than expected gas-rise velocity, and this is most probably due to the full-scale annular geometry and circulating conditions enabling a faster gas rise velocity compared to previous work in this area consisting only of small-scale experiments and experiments through tubing. The two-phase flow experiments conducted in this research provide critical insights for understanding the flow dynamics in offshore drilling riser conditions, and the results provide an indication of how quickly gas can migrate in a marine riser scenario warranting further investigation for the sake of effective well control.

Multiphase flow experiments demonstrate the capability of fiber optic Distributed Acoustic and Temperature Sensors to detect and track a potential gas-influx in 5000 ft. deep wellbore, to prevent a well control incident.