Field Reactivation Using Innovative and Long-Term High-Alloy Coiled-Tubing Gas Lift System in Highly Corrosive Mediterranean Offshore Field, Libya

An offshore Libya mature oil field with a large gas cap underlies a massive aquifer located in the Mediterranean Sea. It is a naturally fractured carbonate reservoir producing an extremely corrosive crude – naturally- from [SD3][AS4]14 monobore horizontal oil wells and one gas observation well drilled across gas cap. The field suffers from increased water cut and major crossflows across perforated intervals. In previous years, all systematic and maintenance shutdowns, including those caused by force-majeure due to security and political instability in the country, were feasibly overcome by naturally restarting the field. However, recently with the increased water cut, a greater volume of water flooding into the oil-producing zones would make it impossible to reactivate the field without use of artificial lift systems. Installing any artificial lift means in a monobore completion in the depleted field would require a large investment that would make the installation uneconomical. Hence, all future planned shutdowns would be at risk without making a big investment or developing an innovative solution. Developing such a solution meant solving a complex problem in short time that demanded attention to detail, critical thinking, and creative problem-solving, using the already available operational structure to restart the field safely. N2 kickoff was initially performed to reactivate the field without success due to the large N2 quantities required to produce all flooded water into oil zones which takes from a week to few months of lifting, in additional to the logistical challenges and involved cost. A rigless electrical submersible pump does not meet the required flow rates of more than 3,000 BLPD to stop the dynamic crossflow and hence, the reactivation would not be successful. The field was already producing 46 MMscf/D of gas, most of which was burnt out. It was proposed to use part of that wasted gas or to divert the gas production of the only gas well and inject the gas through temporarily installed coiled tubing as a single gas injection point at a predefined depth to offload the flooded water and reestablish the previous production figures. In 2017, 2 wells out of 14 producing wells suffered from liquid loading and were successfully revived using conventional carbon steel single-point coiled tubing gas lift system (CTGL). In 2022, all wells in the field were affected by increasing water cut. The field went on a complete shutdown and all wells required reactivation using the CTGL technique. However, the issues that were faced in the 2017 CTGL operation would be more challenging and complex due to the greater number of wells. These challenges included corrosion pitting, upstream pressure decline (the gas well's wellhead pressure) and lifting time and efficiency with more than 1 month required per well. The greater number of wells would increase CT cost, and the increasing water cut would increase lifting time per well, which would reduce production efficiency and increase corrosion rate. Additionally, because of the urgent timeline requirement for the execution, the single injection point design was extremely critical and had to work within the specifications of the available injection pressure, required flow rates of greater than 4000 BOPD, and available CT reels in country to reactivate all wells. A small error on chosen the injection point would compromise the entire reactivation process. Because this is a sour field, two categories of CT material were required to achieve a durable CT string with acceptable pitting based on a corrosion test. Carbon steel was chosen for a 2- to 3-week lifting period and chrome for a lifting period greater than 4 weeks. This innovative solution uses the already existing platform structure to deliver a green solution. Using the only gas well as a source of gas and pressure, the reinjected gas method aligns with green business objectives with a reduction of up to 80% less CO2 compared to the other possible long-term solutions available to the project.