Surface compressors lower the wellhead pressure and increase the tubing drawdown and hydrocarbon production. Hybrid use of surface compression, continuous flow plunger lift, and continuous gas injection reduces flowing bottomhole pressure and avoids liquid loading. The study focuses on favorable conditions for lower tubing wellhead pressure, leading to significant production and production lifetime increases.
Multiphase flow simulations were conducted to investigate the effect of different tubing wellhead pressure settings. Sensitivity analysis for different production rates and gas-liquid ratios are employed. Field data from 14 wells from San Juan Basin is used to analyze the hybrid use of surface compression and plunger-assisted gas lift. Operational range and cycles of plunger lift analyzed for tubing wellhead pressure of 30, 120, and 210 psi for different production rates. Nodal analysis is used with productivity index and backpressure gas equation to estimate production increase provided by surface compression.
Lower tubing wellhead pressure promotes gas expansion and higher gas velocity along the tubing. Higher gas velocity helps to reduce liquid holdup and gravitational pressure losses but increases the frictional pressure losses. In a few months, unconventional wells experience liquid loading where gravitational pressure losses dominate. Surface compression was found to be lowering flowing bottomhole pressure hence increasing reservoir inflow for unconventional wells. Furthermore, plunger lift analyses showed that surface compression allows plungers to surface without shut-in, which extends PAGL operation for years.
The mechanistic model simulations and field data show that surface compression and PAGL usage increase production and extend the unconventional wells’ production lifetime. The sensitivity analysis shows favorable production rates by lowering tubing wellhead pressure, which applies to many shale plays. The study presents the methodology to estimate production increase and feasibility analysis for surface compressed plunger and gas lift.
Artificial lift methods are implemented to improve production and avoid well integrity problems. Improving the production rate includes avoiding production instability and extending the production lifetime of wells and helps with daily production and total hydrocarbon recovery. Furthermore, severe slugging, corrosion, hydrate formation, and sand issues, which may create serious problems to surface facilities, can be tackled by changing the flow conditions using artificial lift methods and choking. Artificial lift needs and integrity problems of a well change for different reservoirs and production platforms. ESP or gas lift may be suitable for a high-production offshore well with low GLR, whereas an onshore well with high GLR may experience gas locking problems for a rod pump. Production engineers select and design artificial lift methods with the consideration of the feasibility and limitations of each well.
