Monetizing a Well with Casing Hanger Leak: Risk-Based Concept Selection of Ctu Gas Lift Versus Conventional Gas Lift

Abstract

This paper addresses the artificial-lift selection challenge for a mature offshore single-string oil producer affected by a confirmed, non-repairable casing hanger leak that creates pressure communication between the production and intermediate annuli. The well is currently producing at approximately 55% water cut and exhibits unstable flow behaviour, with nodal analysis predicting cessation of natural flow at around 68% water cut. The objective of this study is to identify an artificial-lift solution that sustains near-term production and maximizes reserve recovery while maintaining well integrity under strict Maximum Allowable Wellhead Operating Pressure (MAWOP) and As Low As Reasonably Practicable (ALARP) constraints, where conventional remediation of the casing hanger leak is not feasible. A structured, risk-based concept selection workflow was applied to evaluate three artificial-lift options: (1) Coiled Tubing Unit (CTU)-deployed velocity string with reverse gas-lift injection, (2) capillary string gas lift with reverse injection, and (3) conventional gas lift utilizing an existing well-to-well gas-lift network. Each option was assessed against operational complexity, readiness timeline, HSE exposure, cost, annulus pressurization risk, and integrity assurance. For the selected conventional gas-lift option, a detailed feasibility assessment was conducted, including CO2 corrosion risk evaluation using OLI modelling and analogue Multi-Finger Imaging Tool (MIT) data, emergency annulus bleed-off simulations, and the development of operational controls and standing instructions to manage sustained casing pressure below 50% MAWOP. CTU-deployed and capillary-based gas-lift solutions offered theoretical annulus isolation benefits but were associated with high execution complexity, extended readiness timelines of 6–8 months, significant wellhead and tree modifications, vessel dependency, and elevated HSE exposure, resulting in poor project value for a late-life well. Conventional gas lift, despite exposing the intermediate annulus to injection gas, enabled immediate deployment through existing infrastructure and rapid production monetization. Corrosion assessment confirmed minimal casing degradation risk due to the extremely low water content of the CO2-rich dry gas source, while emergency bleed-off simulations and operational safeguards demonstrated that annulus pressures can be effectively controlled within acceptable limits. The study concludes that conventional gas lift represents the most operationally feasible and cost-efficient solution while maintaining well integrity within ALARP principles. This paper provides a practical, field-proven framework for deploying conventional gas lift in wells with non-repairable casing hanger leaks and MAWOP-constrained conditions. It integrates corrosion risk assessment under dry CO2 exposure, annulus pressure management strategies, and emergency response planning into a unified decision-making process. The work demonstrates that, contrary to conventional risk aversion, conventional gas lift can be safely implemented in integrity-compromised mature wells when supported by robust surveillance, pressure limits, and procedural controls, offering valuable guidance for late-life offshore asset optimization.