A mechanistic plunger lift tool was developed to estimate cycle mechanics, liquid unloading, and avoid well integrity issues. The study focuses on the plunger-assisted gas lift (PAGL) wells operated with the two-piece plunger under low tubing wellhead pressure conditions.
The fall and upstroke stages of two-piece plungers were analyzed for eleven wells from San Juan Basin. The fall velocity estimation for plunger parts was modeled for; shut-in, transitional and multiphase flow conditions. Fall and upstroke velocities were estimated using drag-based models that feature drag coefficient, wall factor, and two-phase correction. The field data up to three years from each well was compared with the PAGL Tool estimations. The downhole pressure gauge data was analyzed and compared with plunger liquid slug estimations for two wells. Plunger inspection data and shut-in, afterflow time effects on liquid loading and plunger cycle time were investigated.
The PAGL Tool estimations for full-cycle times were in fair agreement with daily production and plunger lift data of 10 of the 11 wells. The field data and tools estimations for 2- 7/8 in tubing show that two-piece plungers can fall against 600 STB/d liquid and 2 mmscf/d gas production rates with little to no shut-in times, and lower operational boundary for surfacing can be as low as 300 mscf/d without requiring a pressure buildup. The lower gas production being sufficient for upstroke movement increases the operational range of PAGL. The main reason was the low wellhead pressure, which causes gas expansion and higher gas velocity along the well to increase drag force hence the upstroke capability of PAGL with lower gas production rates. The downhole pressure data was compared with multiphase flow simulation with plunger hydrostatic pressure removal. Higher afterflow time settings were shown to be increasing the arrival time data, which suggests a growth of the liquid accumulation at the bottom hole.
Field data shows that plunger lift operation is not limited to wells with marginal production, and it can be used before liquid loading conditions. The hydrostatic pressure removal with plunger lift is shown with field data analysis and plunger lift tool estimations. The study presents that the continuous flow plunger lift operational range can be extended to lower production rates if lower wellhead pressure is achieved.