Employing Innovative Distributed Temperature Sensing Technique for Conclusive Downhole Leak Detection via Coiled Tubing: A Case Study from Pakistan

Abstract

Leak identification across well completions is a crucial operation in the oil and gas industry. A failure of well barriers can result in uncontrolled release of hydrocarbons and pose major risks to personnel and environment. Downhole gauges are widely used to provide pinpoint measurements of pressure and temperature across the completion; however, those measurements alone are insufficient to properly diagnose single or multiple well integrity issues. Alternative well intervention methods are needed to qualitatively estimate the location and number of potential leaks. For the past decade, distributed temperature sensing (DTS) has been used in wellbore completions and surface pipelines with preinstalled fiber optic lines to identify leaks by monitoring and processing temperature profiles across the length of the installation. The proposed methodology makes use of a similar principle, relying on coiled tubing (CT) to deploy the fiber optics and conduct DTS integrity assessment in wells completed without fiber optic lines. This use of fiber optics inside a CT pipe also provides simultaneous real-time downhole measurements, which include CT internal and annulus pressures, and casing collar locator (CCL), for precise depth control and accurate correlation of well parameters. In the south of Pakistan, the tubing-casing annulus pressure of a high-temperature gas well increased to near flowing wellhead pressure at the tubing, giving a clear indication that at least one of the completion components had failed, resulting in flow of hydrocarbons to the annulus. Yet, the high wellbore temperature limited conveyance of conventional logging tools to assess downhole completion integrity. A thorough analysis of well hydraulics was first conducted to gather the possible options to identify the leak using DTS. This enabled the determination of a workflow aiming to create enough differential pressure to generate particular temperature disturbance. CT equipped with fiber optics was run and stationed across the complete wellbore length, and DTS data were acquired for approximately twelve hours under changing well conditions, including shut-in and flowing periods. The acquired temperature information for each phase, along with pressure information, helped to narrow down the location of possible leak points. This methodology enabled the identification of a single, major leak point located at an expansion joint in the completion. The operator was able to riglessly set an annular plug to restore integrity, thus saving significant workover cost and time.