Production Optimization of Liquid Loading Problem in Offshore Niger Delta Gas Condensate Field

Abstract

In a natural gas field development plan, determining the life of the field and deciding the best-optimized production strategy as well as meeting the economic viability are the most important considerations to sustain gas production. Development optimization can increase the net present value by maximizing the hydrocarbon recovery and reducing the operating cost. Optimizing gas condensate bearing reservoirs below dew point exhibit complexities due to the hydrocarbon condensation and many times, an in-situ oil phase may result to reduce gas well productivity. Liquid loading can be a serious problem in gas-bearing condensate wells near the end of their production life. As the pressure in the drainage area is depleted below the dew point, the condensate will start to build up and the gas velocity in the production tubing falls below the critical rate resulting in inadequate energy to lift the entire condensate hydrocarbon out of the wellbore. The condensate liquid migrates down the tubing and accumulates at the bottom of the completion, increasing the bottom hole flowing pressure, thereby, reducing the production rate. Liquid loading phenomenon can be encountered in low productivity gas condensate wells. Preventive actions need to be considered for predicting and monitoring of liquid loading issue before it becomes a serious problem in production system form a reservoir to the surface facilities. This study focuses on optimizing gas production strategy in a field development plan of gas condensate well. Sensitivity analysis was implemented on the Bara well-1 through optimizing the operating parameters such as tubing sizes, wellhead pressures, skin factors, condensate gas ratio, water gas ratio and surface chokes sizes by using Niger-Delta field data and PROSPER dynamic simulator in order to select best well model construction that promote high gas deliverability and low condensate production. The reservoir GIIP has been estimated to 370 Bscf from both geological and dynamic simulation models. From the dynamic nodal analysis result, 5.5in tubing size promotes the highest optimum gas rate and low erosional velocity based on the investigated operating conditions.