Thermal Simulations of Gas Lift and Water Injection Wells for Magurele Field Development: Future Strategies

A secondary recovery techniques are those used after natural energy depletion of an oil or a gas reservoir to boost its production such as gas lift and water injection. Both methods have been proved their success and effectiveness for enhancing field production. However, each reservoir or field has its own criteria and they may be ineffective depending field criteria and future plans. Furthermore, a field development strategy is considered as a key activity for enhancing the field recovery. Therefore, the aim of this article is to do well thermal simulation and analysis during making gas lift and water injection for Magurele field development at different conditions such temperature, tubing size, and production parameters. Several strategies are suggested from putting a new drilled well (M#206) on production till abandonment. A sensitivity study is done to know the effect geothermal zones and tubing size on well performance and flow regimes. It was found that utilizing a reservoir temperature of 70°C and tubing 3 1/2, all production activities displayed normal fluid and wellbore temperature profiles, using larger tubing or producing from the high temperature (HT) zone has only a minimal impact on the pressure profile, only slightly increasing surface pressures and The suggested production activities are unaffected by the higher temperature. With regard to the flow regime created by strategies, starting usage circumstances for tubing 3 1/2", with the exception of injection, which is turbulent in all scenarios, the flow regime is slug flow between 70°C and HT zones. Additionally, it seems like the bubbly flow is at shallower depths. Due to the use of 4 1/2-inch, the flow regime is altered to transitional and bubbly flows at deeper depths. This study helps to maximize the reservoir output and keep the new drilled wells usable and useful as long as possible.