Gas lift is a method of boosting oil production from wells that can no longer flow on their own. Compressed gas is injected into the well’s tubing, where it mixes with the crude oil and makes the fluid column lighter. That reduction in weight lowers the pressure at the bottom of the well, allowing more oil to flow up to the surface. It’s one of the most widely used forms of artificial lift in the oil and gas industry, valued for its simplicity, flexibility, and ability to handle difficult well conditions.
How Gas Lift Works
Every oil well relies on reservoir pressure to push fluid to the surface. Over time, that natural pressure declines, and the weight of the fluid column inside the tubing becomes too great for the reservoir to overcome. Gas lift solves this by injecting compressed gas, usually natural gas, into the tubing at depth. The gas mixes with the produced fluid, creating a lighter, aerated mixture. Because this mixture weighs less per unit of height, the pressure needed at the bottom of the well drops, and the reservoir can push more fluid upward.
Think of it like blowing air into a milkshake through a straw. The bubbly mixture rises more easily than the dense liquid alone. In a well, the injected gas supplements whatever formation gas is already present, reducing the flowing bottomhole pressure and increasing the total volume of oil that reaches the surface.
Key Components of the System
A gas lift system has two halves: surface equipment and downhole equipment. On the surface, a compressor pressurizes the injection gas and sends it down the annular space between the well’s casing and its inner tubing. A control valve on the injection line regulates how much gas enters the well and at what pressure.
Downhole, the system relies on gas lift valves installed inside side-pocket mandrels, which are special fittings built into the tubing string. These valves act as one-way entry points, allowing pressurized gas to pass from the annulus into the tubing at specific depths. The valves come in three main types:
- Orifice valves are the simplest. They don’t open and close at all. They’re just fixed-size ports that let gas flow continuously into the tubing, making them ideal for steady, continuous-flow operations.
- Injection pressure operated (IPO) valves respond primarily to the pressure of the injection gas in the annulus. They’re the most common type used during the initial startup process known as unloading.
- Production pressure operated (PPO) valves respond to pressure changes in the produced fluid inside the tubing. They’re useful in wells where tubing pressure fluctuates significantly.
The Unloading Process
Before a gas lift well reaches steady production, it has to go through a startup sequence called unloading. When a well has been shut in, kill fluid or accumulated liquids fill the tubing and sometimes the annulus. The goal of unloading is to push that heavy liquid out, working from the top valve down to the deepest operating valve.
The process is methodical. If the tubing pressure is higher than the separator pressure, the tubing is first bled down slowly through a small choke. No lift gas is injected during this step. Once the tubing is bled down, gas injection begins at a controlled rate, typically limited to no more than a 50 psi increase in casing pressure per 10-minute interval. The gas first enters through the shallowest valve, pushing the liquid slug above it into the flowline. Operators may need to repeat a “rocking” process, alternating injection and flow, several times before uncovering deeper valves. Each successive valve reached allows injection at a greater depth, which improves lifting efficiency. Eventually, gas enters through the deepest operating valve, and the well transitions to normal production.
Continuous vs. Intermittent Gas Lift
Gas lift operates in two modes, and the choice between them depends on how much fluid the well can produce and how much reservoir pressure remains.
Continuous gas lift injects a steady stream of gas into the tubing. It’s the preferred method whenever possible because it produces a smoother, more predictable flow. Advances in multiphase flow modeling have extended the practical range of continuous flow to much lower daily production rates than were once considered feasible, so even moderately low-output wells can often use this approach if the tubing size is selected carefully.
Intermittent gas lift is reserved for wells with low productivity or low reservoir pressure. Instead of a constant gas stream, a burst of high-pressure gas is injected on a timed cycle, pushing a slug of accumulated liquid to the surface. A surface controller manages the timing of each injection and shut-in period. This mode is less efficient than continuous flow and produces in slugs rather than a steady stream, but it’s the only viable option for wells that simply don’t produce enough fluid to sustain continuous lifting.
Advantages Over Other Lift Methods
Gas lift stands out from other artificial lift options in several practical ways. Unlike rod pumps or electric submersible pumps (ESPs), gas lift has no moving parts downhole. That means it handles sand, paraffin, and corrosive fluids far better than mechanical pumps, which can wear out or seize. Wells with high gas-to-oil ratios that would cause gas locking in a pump are natural candidates for gas lift, since the extra gas actually helps the process.
The system is also flexible. Operators can adjust injection rates from the surface to match changing well conditions without pulling equipment out of the hole. Deviated and horizontal wells, which create challenges for rod-driven systems, work well with gas lift because the valves sit in fixed mandrels along the tubing regardless of wellbore angle. And when a valve does need to be replaced, it can often be retrieved and reinstalled using a wireline tool, avoiding the cost and time of pulling the entire tubing string.
The main disadvantage is the need for a reliable, high-pressure gas supply. A compressor failure shuts down every well on the system. Gas lift also tends to be less energy-efficient than pumping methods in straightforward, high-volume wells, and it requires enough casing-tubing annular space to serve as the gas injection conduit.
Common Operational Challenges
Injecting gas into a well changes more than just fluid density. It also cools the produced fluid, which can trigger wax and paraffin deposition inside the tubing. These deposits are a mix of normal and branched paraffins, sometimes trapping asphaltenes, sand, scale, and other solids. Left unchecked, they restrict flow and reduce efficiency. Chemical inhibitors and periodic hot-oil treatments are common countermeasures.
Hydrate formation is another concern, particularly in high-pressure, low-temperature conditions. Hydrates are ice-like crystals that form when water and gas combine under the right conditions, and they can plug valves or flowlines. One somewhat fortunate quirk: in wells where wax has already coated the tubing walls, hydrates have a harder time adhering because the waxy surface repels the water-based crystals.
Valve reliability matters too. If an upper unloading valve fails to close properly after the well is unloaded, injection gas escapes through it instead of reaching the deeper operating valve. This “multipointing” wastes gas and reduces lift efficiency. Regular valve testing and proper design help prevent it.
Automation and Optimization
Modern gas lift operations increasingly rely on automated systems to fine-tune performance across entire fields. ExxonMobil, for example, has deployed a closed-loop optimization workflow across more than 1,300 gas lift wells. The system runs automated multi-rate tests on each well, updates downhole pressure models in real time, and uses machine learning to estimate conditions in wells that lack pressure gauges. The result has been a consistent 2% production uplift with little additional capital or operating cost.
This kind of fieldwide automation reflects a broader shift in the industry. Rather than engineers manually adjusting injection rates well by well, algorithms continuously calculate the optimal gas allocation across dozens or hundreds of wells sharing a common gas supply. The goal is to direct gas where it generates the most incremental oil, something that’s nearly impossible to do manually at scale. Engineers still handle complex troubleshooting, but routine tuning is increasingly handled by software that updates itself as reservoir conditions change.