What Is Gas Lift?
Gas lift is an artificial-lift method that adds energy to a well not by pumping, but by injecting compressed gas into the fluid column to make it lighter and easier for reservoir pressure to lift. It is a favorite for high-rate, gassy, and deviated wells - and for offshore, where gas is available and downhole pumps are costly to service. This guide explains how gas lift works and where it fits.
Gas Lift in one line: Gas lift is an artificial-lift method that injects compressed gas into the production tubing to reduce the density of the fluid column, so the well's own pressure can lift the lighter mixture to the surface. It uses no downhole moving parts.
How Gas Lift Works
A well's fluid column has weight, and that weight is the back-pressure the reservoir must overcome to flow. Gas lift injects gas into the tubing so the produced fluid becomes a lighter gas-liquid mixture; the lighter column exerts less back-pressure, and the reservoir can then push the well to surface at a higher rate. It is aeration, not pumping.
Injection gas is compressed at surface and sent down the tubing-casing annulus. It enters the tubing through gas lift valves mounted in side-pocket mandrels at set depths. On startup, the upper valves unload the well progressively until gas is injected at the deepest point of injection, where it does the most good.
Continuous vs Intermittent Gas Lift
In continuous gas lift, gas is injected steadily to keep the column aerated - suited to wells with reasonable inflow that benefit from a constantly lighter column. In intermittent gas lift, a slug of gas is injected periodically to push a liquid slug to surface, then the well builds back up - suited to lower-productivity wells, and conceptually similar to plunger lift.
Gas lift has real strengths: no downhole moving parts to fail, tolerance of sand and high gas-oil ratios, effectiveness in deviated wells, and easy rate adjustment from surface. Its requirements are a source of compressed gas and enough reservoir pressure to respond to the lighter column.
Monitoring Gas Lift
Key data include injection gas rate and pressure, casing (injection) pressure, tubing (production) pressure, and produced rates. Watching these together shows whether gas is entering at the intended valve, whether the well is stable or heading, and whether the injection rate is optimized - too little gas underlifts, too much wastes compression and can increase friction.
SCADA gathers injection and production data from field instruments and controllers. A cloud platform such as Merobix reads injection controllers and meters over Modbus, so gas lift injection rates and pressures across a field are visible and can be optimized remotely.
The Surface Side: Compression and Injection Control
Downhole, gas lift is passive - all the moving decisions happen at surface. A gas lift installation needs a source of high-pressure gas (a dedicated compressor, a shared field compressor station, or occasionally a high-pressure gas well), a distribution system to each wellhead, and on every well an injection choke or flow control valve with a meter run so you know what the well is actually getting. The produced gas comes back with the oil, gets separated, and most of it is dried and recompressed - lift gas is a loop, and compressor availability is well availability.
The injection controller on each well usually holds one of two things: a target injection rate or a target casing pressure. Rate control keeps the design gas allocation steady as supply pressure wanders; casing-pressure control reacts faster to downhole changes but follows supply swings whenever the compressor hiccups. Either way, remember that lift gas is a shared resource. One well opened wide can starve three neighbors, so allocating gas across a field is an optimization exercise - each well has a lift performance curve, and the last unit of gas does more good on some wells than on others.
Reading Casing and Tubing Pressures Together
The casing and tubing pressures are the cheapest diagnostic pair on the well. Steady casing pressure with steady tubing pressure and steady production is the signature of stable single-point injection at the operating valve. A slow sawtooth on the casing pressure usually means gas is being admitted in pulses - a valve cycling open and closed rather than passing gas continuously.
Drift tells its own story. Casing pressure climbing at a constant injection rate suggests the operating valve is passing less gas than before, or that injection has transferred to a shallower valve. Casing pressure falling while injection rate rises points at a cut valve - one eroded to the point that it passes gas freely. Trend both pressures against injection rate and production and the patterns become readable; the guide on how to interpret a casing pressure trend on a gas lift well walks through the classic shapes.
Common Operating Problems
The classic instability is heading: a slow, self-reinforcing oscillation in which casing pressure, tubing pressure, and production rate cycle against each other, the well surging and dying on a repeating period. It usually appears when a well runs too close to its minimum stable injection rate. Remedies include more injection gas, a smaller port at the operating valve, or moving injection deeper - gas lift heading instability covers the mechanics and the cures.
Other recurring problems: multipoint injection, where gas enters at more than one valve at once and lift efficiency drops; cut or leaking valves that pass gas uncontrolled at a shallow depth; hydrate or freeze plugs in the injection line choking supply; and compressor trips, after which a well may load up with liquid and need the full unloading sequence again before it returns to its deepest injection point.
How Gas Lift Compares to Other Lift Methods
No lift method wins everywhere. The rough qualitative picture:
| Method | Downhole moving parts | Sand and gas tolerance | Deviated wells |
|---|---|---|---|
| Gas lift | None | Good on both | Good |
| Rod pump | Rod string and pump | Gas locks the pump, sand wears it | Rod wear limits deviation |
| ESP | Motor and pump | Sensitive to both | Workable if it fits the build section |
| Plunger lift | Free piston | Handles gas well, modest liquid rates | Limited |
The natural neighbor is plunger lift: as a gassy well declines, intermittent gas lift and plunger lift converge, and the two are combined as gas-assisted plunger lift, where injection gas supplements the well's own buildup to run the plunger cycle. The deciding inputs are almost always gas availability, well deviation, sand, and the economics of compression.
Frequently Asked Questions
How does gas lift lift oil?
It injects compressed gas into the production tubing so the fluid becomes a lighter gas-liquid mixture. The lighter column exerts less back-pressure, letting the reservoir's own pressure push the well to surface at a higher rate. It lightens the column rather than pumping.
What is a gas lift valve?
A gas lift valve is a pressure- or fluid-operated valve set in a side-pocket mandrel on the tubing at a specific depth. It admits injection gas from the annulus into the tubing. Upper valves unload the well on startup until gas is injected at the deepest point of injection.
What is the difference between continuous and intermittent gas lift?
Continuous gas lift injects gas steadily to keep the column aerated, suited to wells with decent inflow. Intermittent gas lift injects gas in periodic slugs to push liquid to surface, then lets the well build back up, suited to lower-productivity wells.
Why does a gas lift well need to be unloaded?
Because at startup the annulus and tubing are full of heavy completion or kill fluid that injection gas cannot push past the deepest valve directly. The unloading valves are spaced so gas can displace that liquid stage by stage: the top valve uncovers first, aerates the tubing, the fluid level drops, the next valve uncovers, and so on until injection reaches the operating depth. Each transfer shows up as a step change in casing pressure, which is how you follow unloading from surface.
How much injection gas does a gas lift well need?
It is well-specific, and there is a real optimum. Each well has a lift performance curve: production rises steeply with the first gas, flattens, and eventually declines as friction from excess gas outweighs the density reduction. The optimum rate comes from well testing and the field's gas allocation model, not from a rule of thumb, and it shifts as reservoir pressure and water cut change.
Sources and verification
This page references the protocol specifications published by the organizations below. Editions, product capabilities, and documentation change over time - confirm current requirements and specifications directly with the source.
- Modbus Application Protocol Specification - Modbus Organization
Merobix is not affiliated with, endorsed by, or sponsored by these organizations; their names are used only to identify the standards and products discussed.
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