How Gas Lift Systems Work
Lesson Summary
Gas is injected into the annulus to enter the tubing through valves, lightening the column and lifting the fluids.
This lesson is part of the Production & Processing track and is 1:27 minutes long. Watch the video first, then review the key points and test your understanding with the questions below.
Key Points
- 1Gas reduces column density
- 2Enters through Gas Lift valves in the mandrels
Written Lesson
Why does a well stop flowing?
A well flows naturally (Natural Flow) as long as reservoir pressure is sufficient to lift the fluid column in the tubing and overcome friction and wellhead pressure. Over time, reservoir pressure drops and the water cut (heavier than oil) may increase, making the fluid column too heavy for the reservoir to lift. This requires Artificial Lift, with Gas Lift being one of the most common types, especially where high-pressure gas is available.
The Concept: Lightening the Column
Compressed gas is injected into the annulus between the casing and tubing; it enters the tubing through a valve at a specific depth and mixes with the fluids. The mixture is lighter than the liquid alone, reducing the pressure gradient above the injection point and lowering the Flowing Bottomhole Pressure (FBHP). This increases the difference between reservoir pressure and bottomhole pressure, known as drawdown, bringing the well back to production.
FBHP ≈ Pwh + G(above injection) × D(inj) + G(liquid) × (TVD − D(inj))
q = PI × (Pr − FBHP)
Calculation Example: A well with 8,000 ft TVD, reservoir pressure of 2,800 psi, and a liquid gradient of 0.4 psi/ft. If the tubing were full of liquid only, it would require 0.4 × 8,000 = 3,200 psi at the bottom, which is higher than reservoir pressure; the well won't flow, and the static level settles at 8,000 − 2,800 ÷ 0.4 = 1,000 ft from surface. By injecting gas at 6,000 ft, the mixture gradient above the injection point drops to about 0.2 psi/ft. With a wellhead pressure of 100 psi: FBHP = 100 + 0.2 × 6,000 + 0.4 × 2,000 = 100 + 1,200 + 800 = 2,100 psi. The Drawdown = 2,800 − 2,100 = 700 psi, and with a productivity index of 1.5 bbl/d/psi, production is approximately 1.5 × 700 = 1,050 bbl/d.
Mandrels and Lift Valves
Tubing is equipped with Side Pocket Mandrels containing the gas lift valves. The advantage of the side pocket is that the valve can be replaced via slickline without pulling the tubing. Valves are categorized into two main types by function:
- Unloading Valves: Distributed at staggered depths, they open sequentially during startup to gradually bleed off annulus fluid, then close.
- Operating Valve: Usually a fixed orifice valve at the deepest injection point, through which gas enters during stable operation.
The most common unloading valves are Injection Pressure Operated (IPO); the valve contains a nitrogen-charged bellows that determines its opening pressure.
Unloading operation (Unloading)
Initially, the annulus is full of completion fluid. Gas is injected slowly to push the liquid into the tubing through the valves. When the annulus liquid level reaches the first valve, gas enters and lightens the tubing column, allowing gas to continue pushing liquid to the next valve. Once the deepest valve is uncovered, annulus pressure drops slightly, closing the upper valve. Injection thus moves down step-by-step to the operating valve. Rapid unloading can damage valves through erosion from the surging fluid.
Continuous and Intermittent Injection
- Continuous Injection (Continuous Gas Lift): A constant gas flow, suitable for wells with good productivity and reasonable bottomhole pressure.
- Intermittent Injection (Intermittent Gas Lift): Gas slugs injected at intervals to lift an accumulated liquid slug, suitable for low productivity or low pressure wells.
Is more gas always better?
No. Increasing gas lightens the column, but beyond a certain limit, friction in the tubing increases more than the weight reduction, decreasing production. Therefore, we plot a Gas Lift Performance Curve between injected gas rate and production, select an economic point before the peak, and distribute available gas among wells based on each well's response.
Summary
- Gas lift lightens the fluid column, which lowers bottomhole pressure and increases the drawdown.
- Unloading valves open in sequence, and the operating valve is the permanent injection point.
- Side pocket mandrels allow changing valves via slickline.
- Each well has an optimal gas rate; increasing beyond it reduces production.
The figures and examples in this lesson are for educational purposes. On the job, always follow your company procedures and accredited training center instructions.
Lesson Glossary
A component in the tubing that holds the gas lift valve out of the main flow path and is replaced via slickline.
A valve that opens temporarily during startup to unload liquid from the annulus and then closes.
The operating valve through which gas enters during steady-state operation.
The pressure at the bottom of the well during production.
Production per psi of drawdown, in units of bbl/d/psi.
Conduit through which produced fluids flow to the surface.