Optimization of Gas Injection Well Productivity Through Integration of Modified Isochronal Test Including the Impact of Phase Behaviour: A Case Study on Coiled-Tubing Gas Lift for Al-Jurf Offshore Oil Field

Abstract Identifying the most effective artificial lift method is one of the key challenges for Al-Jurf offshore field. Utilization of gas lift through coiled tubing has proven to be a successful and pragmatic approach to revitalize the high water-cut oil wells after shutdowns. In this study, we introduce an innovative physics-based approach for the production optimization of a gas supply well through the incorporation of a modified isochronal test including the impact of phase equilibrium analysis. Gas supply wells experienced an unexpected gradual pressure drop, eventually leading to shutdowns and unscheduled interruptions. A modified isochronal test was conducted, encompassing four different gas flow rates ranging from 2.0 MMscf/d to 9.5 MMscf/d, with four hours shut-in periods between each test. A phase equilibrium combination of data analysis with the relevant PVT has enabled the identification of the actual flow behavior in the well that caused this phenomenon. Well performance simulation work was conducted to study and optimize the well's optimum rates coupled with its productivity. The results of the quality check for the modified isochronal test revealed a sudden increase in wellhead pressure from 1770 psi to approximately 2000 psi in a short time, attributed to the cleaning of accumulated condensate in the well near wellbore region. Consequently, the well was allowed to flow for eleven hours to ensure complete clean-up for potential fluid accumulation. The highest recorded gas rate during the clean-up phase was 9.6 MMscf/d, with a maximum wellhead pressure (WHP) reaching approximately 2,040 psi at various flow-time intervals. The relation between the gas rate and WHP yielded the deliverability exponent (n) and the stabilized performance coefficient (C) during the extended flow period, and hence the well's inflow performance relationship was established. The PVT analysis for the physically recombined sample and downhole sample results exhibited excellent agreement. The measured dew point was 3119 and 3128 psia for the SRS and BHS, respectively, at a reservoir temperature of 270 °F. Using these findings, we have determined the productivity of the well based on the developed inflow performance relationship. In addition, optimum liquid drop-out at specific pressure and reservoir temperature using the observed phase behavior, has been established. This study introduces a novel and effective approach to addressing gas lift challenges in offshore oil fields that contain condensates. The combination of a modified isochronal test and constant volume depletion (CVD) data provides a comprehensive understanding of the behavior of the gas supply well. Observed condensate accumulation and its implications were successfully mitigated, leading to the establishment of a robust well inflow performance. The proposed approach allows for the optimization of the gas supply well, ultimately saving time and cost in field operations.