Case History: Coiled Tubing Application During DST Blockage in an Ultra-Deep Subsea Well
This paper presents a novel case study on the application of coiled tubing (CT) intervention to resolve a drill stem test (DST) blockage in an exploration ultra-deep subsea well, evaluate the operational challenges faced and assess the effectiveness of the intervention. Additionally, the paper aims to derive best practices and lessons learned to enhance future coiled tubing operations in similar environments, ultimately contributing valuable insights to the industry for improved decision-making during subsea well interventions. This study employs a case history methodology, analysing data collected from the coiled tubing intervention during the DST blockage in the ultra-deep subsea well. The approach includes a detailed review of operational reports, real-time monitoring data, and performance metrics. Procedures involve assessing the specific techniques used in the coiled tubing application, such as management and fluid circulation methods. Contingency procedures included acidizing, cleanout, and N₂ unloading. The process includes evaluating the outcomes of the intervention, documenting challenges faced, and synthesizing lessons learned to formulate best practices for future subsea operations. The coiled tubing intervention successfully cleared the DST blockage, restoring wellbore flow and enabling further testing of the ultra-deep subsea well. Real-time telemetry confirmed effective debris removal, with pressure stabilization observed post-intervention. The operation encountered challenges such as high-pressure limitations and debris lift, which were mitigated through adaptive procedures and real-time adjustments. Observations highlighted the importance of precise tool selection, as high-pressure rotary jet for soft deposits, while milling assemblies addressed hardened obstructions. The use of real-time monitoring significantly improved operational efficiency and reduced intervention risks. The conclusions drawn from this case study emphasize that CT intervention is a viable and efficient solution for DST blockages in deepwater environments. Lessons learned include the necessity of robust pre-job planning, contingency strategies for unexpected obstructions, and advanced wellbore monitoring for optimizing intervention success. This case history provides valuable insights for future deepwater interventions, helping improve operational reliability, minimize non-productive time, and enhance well performance. This paper presents a case study of coiled tubing intervention in an ultra-deep subsea well first time done in Malaysia, addressing DST blockages under extreme conditions. It provides practical insights into tool selection, real-time monitoring, contingency planning, and adaptive strategies to overcome deepwater challenges. By sharing lessons learned and operational best practices, the paper enhances existing literature and offers engineers valuable guidance to optimize future interventions, improve well productivity, and reduce operational risks in similar environments Well Background The Well UDWM-1 is an exploration oil well, operated by PETRONAS Carigali SDN. Bhd. (PCSB). The well was designed to be drilled by a 7th generation dual derrick DP-3 drillship. For an ultra-deep subsea environment of 2810(m) / 9222(ft) Fig. 1. The seabed temperature was 3° Celsius and the reservoir temperature was 147° Celsius with a maximum reservoir pressure of 9170 psi. The well was targeted to be drilled vertically through a carbonate reservoir with no deviation as a part of a major field development project, the Well TD was 5200 m measure depth (MD). Well completion was planned with a 9-5/8″ liner with shoe depth at 5196 m (MD). The well was temporally completed with a (DST) Fig. 2, using 4-1/2″ OD tubing and run with TCP and subsea assembly on 4-1/2″ tubing. Before landing the string, Motion Compensated Coil Tubing Lifting Frame (MC-CTLF) and Riser Sealing Mandrel (RSM) were installed and landed the DST string. A Permanent packer was installed, and the well was perforated with the TCP guns. The well was perforated between 4767(m) and 4827(m) to assess reservoir productivity. The total depth (TD) for the DST was 4786(m) MD, with a minimal internal restriction of 2.25″. coiled tubing intervention has been identified as a contingency option in the event the well does not flow naturally as expected. The operation falls under Pressure Category (PC) 3, with a maximum anticipated surface pressure (MASP) of 4,290 psi. Formation conditions include a temperature of 167°F and a reservoir pressure of 7,057 psi. The wellbore fluid is oil-based, with a density of 10.3 ppg. No hydrogen sulphide (H₂S) or carbon dioxide (CO₂) contaminants are present.
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