Gas Lift: Artificial Lift Method, Valves, and Design

What Is Gas Lift?

Gas lift is an artificial lift method that injects compressed gas down the casing-tubing annulus and into the production tubing through a series of gas lift valves, aerating the produced fluid column to reduce hydrostatic pressure so that reservoir energy can push fluids all the way to surface at economic rates.

How Gas Lift Works

At its core, gas lift exploits the same principle as a bubble column reactor: introducing a less-dense phase into a liquid-filled column reduces the average density of that column, lowering the hydrostatic head that the reservoir must overcome to produce fluids to surface. A surface compressor or a high-pressure gas source raises the injection gas (typically dry pipeline gas or produced gas) to the required injection pressure, which commonly ranges from 6,900 kPa to 20,700 kPa (1,000 psi to 3,000 psi) depending on well depth and reservoir pressure. The compressed gas travels down the annulus between the production tubing and the casing, enters the tubing through the deepest open gas lift valve, and rises with the produced fluids in the form of dispersed bubbles or elongated gas slugs.

The gas lift system consists of a series of mandrels, each housing a valve, installed at calculated depths along the tubing string during completion. The deepest valve that will open under the available injection pressure is called the operating valve; valves above it are typically closed under normal conditions and serve as unloading valves during the startup sequence. When the well is first placed on gas lift or returned to production after a workover, the fluid column above each valve must be unloaded progressively, starting from the shallowest valve and working downward until the deepest operational point is reached. This unloading sequence is a critical design step and is governed by the available injection pressure and the transfer of the operating point from one valve to the next.

The gas-liquid ratio (GLR) in the tubing directly controls the density reduction and therefore the bottomhole flowing pressure. Gas lift design software such as Prosper (Petroleum Experts) or PIPESIM (SLB) calculates the optimum injection gas rate by balancing the reduction in hydrostatic head against the friction pressure increase caused by higher gas velocities. Injecting too little gas leaves the well under-lifted; injecting too much gas causes severe heading, flow instability, and ultimately a reduction in production because friction losses dominate. The optimum injection rate is defined as the point on the performance curve where incremental production gain per unit of injected gas is maximized, a key economic metric for field-wide gas allocation optimization.

Gas Lift Across International Jurisdictions

In Canada's Western Canada Sedimentary Basin (WCSB), gas lift is widely applied in heavy oil production from the Cold Lake and Lloydminster areas where the produced fluid has an API gravity of 12 to 20 degrees and high viscosity renders rod pumps prone to failure. Producers such as Canadian Natural Resources and Cenovus Energy operate large gas lift infrastructure networks in these plays. The Alberta Energy Regulator (AER) governs the design and operation of well completion equipment including gas lift installations under Directive 059 (Well Drilling and Completion Data Filing Requirements) and Directive 007.

In the United States, gas lift is the dominant artificial lift method in the deepwater Gulf of Mexico, where ESP deployment and retrieval are costly and the high gas-oil ratios of many deepwater reservoirs provide a ready source of lift gas. Operators including bp, Shell, and Chevron Corporation run continuous gas lift on the majority of their subsea wells tied back to floating production systems. The Bureau of Safety and Environmental Enforcement (BSEE) regulates well completion equipment including gas lift installations in federal offshore waters under 30 CFR Part 250. In the Permian Basin of west Texas and southeast New Mexico, continuous gas lift competes with ESPs and rod pumps; the choice depends on well depth, fluid properties, and available infrastructure.

On the Norwegian Continental Shelf, the Norwegian Offshore Directorate (formerly Oljedirektoratet, now Sodir) requires that all subsurface safety devices, including gas lift check valves and downhole safety valves, comply with NORSOK D-010 and are tested at the intervals specified in the well's approved well integrity management plan. The Johan Sverdrup gas lift system is managed using Equinor's Integrated Operations center in Stavanger, with automated gas allocation algorithms adjusting injection rates well by well across the field in near real time.

In the Middle East, gas lift is the principal artificial lift method in the supergiant Ghawar field in Saudi Arabia, operated by Saudi Aramco. Ghawar produces from the Arab-D carbonate reservoir and injection gas is supplied from the Master Gas System (MGS), Saudi Aramco's national gas gathering network. With reservoir pressures declining after decades of production, gas lift provides the pressure support needed to maintain the field's approximately 3.8 million barrel-per-day production rate. Iraq's southern oilfields, operated under technical service contracts by operators including bp and Basra Oil Company, also rely heavily on gas lift as gas supply infrastructure is expanded.

Gas Lift Technical Details: Valves, Mandrels, and Optimization

Gas lift valves are the engineered check valves that control gas entry into the tubing at each mandrel location. Three principal valve types are in common use. Bellows-charged valves use a nitrogen-charged bellows as a dome pressure reference; the valve opens when the injection pressure in the annulus rises above the valve's opening pressure, which is set by the nitrogen charge pressure at surface before installation. Pilot-operated valves use a small pilot element to control a larger main port, allowing high injection rates at modest pressure differentials and improving stability in high-rate wells. Throttling valves (also called proportional-response valves) modulate the injection rate continuously rather than opening or closing in a binary fashion, making them useful for wells where precise flow rate control is required to avoid heading or liquid slugging.

Mandrels are the side-pocket or tubing-retrievable housings that hold the gas lift valves. Side-pocket mandrels allow valve replacement using wireline or coiled tubing without pulling the tubing string; this feature is particularly important on offshore wells where workover costs are high. Conventional tubing-retrievable mandrels require the tubing to be pulled to replace valves. Mandrel spacing is calculated during the design phase by constructing a pressure-temperature gradient traverse through the tubing and determining the maximum depth at which each valve can be set, given the available injection pressure and the fluid gradient. The ALS (artificial lift system) designer places mandrels at calculated depths that allow the unloading sequence to progress from the shallowest to the deepest valve while maintaining the minimum operating injection pressure at each step.

Continuous gas lift is used when the well has sufficient reservoir inflow to maintain a continuous stream of fluids in the tubing. The injection gas rate is optimized to maintain the desired flowing bottomhole pressure (FBHP) while minimizing compressor fuel consumption. Gas-liquid ratio (GLR) is the primary diagnostic parameter; a well producing at a GLR of 150 scf/bbl (27 m3/m3) in a deep well requires significantly more injected gas to unload the column than a well with a natural GLR of 400 scf/bbl (71 m3/m3). Intermittent gas lift is applied to low-productivity wells where continuous injection would over-gas the well and cause liquid fallback. In intermittent operation, a cycle timer or pressure controller closes the injection valve while liquid accumulates in the tubing, then opens it to inject a slug of high-pressure gas that drives the accumulated liquid slug to surface.

Gas Lift Synonyms and Related Terminology

• Continuous gas lift: the operating mode in which gas is injected at a steady rate to maintain a continuously aerated fluid column.
• Intermittent gas lift: the cyclic operating mode used in low-PI wells where injection gas is introduced in timed slugs to push accumulated liquid to surface.
• Gas lift valve (GLV): the pressure-actuated check valve installed in the mandrel that controls gas entry into the tubing.
• Mandrel: the tubing sub or side-pocket tool that houses the gas lift valve at a specific depth in the tubing string.
• Unloading: the startup sequence during which each valve above the operating valve is progressively opened and closed to displace kill fluid from the well.
• GLR (gas-liquid ratio): the ratio of produced gas volume to produced liquid volume, expressed in scf/bbl or m3/m3, used to quantify the natural lift energy available in the well.
• Kick-off pressure: the injection pressure required to open the shallowest unloading valve and initiate the unloading sequence.

Related terms: christmas tree, casing, packer, separator, production log, well control, horizontal drilling, plunger lift, flow regime