Continuous Gas Lift: Artificial Lift Design and Optimization

What Is Continuous Gas Lift?

Continuous gas lift (also called continuous flow gas lift) is an artificial lift method in which high-pressure injection gas is continuously injected down the production tubing-casing annulus, enters the tubing through one or more gas lift valves positioned at predetermined depths in the tubing string, mixes with the produced reservoir fluids, reduces the fluid column density and hydrostatic head, and enables the reservoir to sustain flow at a lower bottomhole flowing pressure than would be possible without lift assistance. The system allows operators to maintain economical production rates in wells with insufficient reservoir energy to flow naturally at surface, and is one of the most widely used artificial lift methods in the global oil industry due to its mechanical simplicity and suitability for high-volume wells.

Key Takeaways

Continuous gas lift is most efficient in wells producing 2,000 to 20,000 barrels of fluid per day; at lower rates, the gas-liquid ratio required becomes uneconomically high relative to produced volumes.
Injection gas pressure at the wellhead typically ranges from 800 to 1,500 psi depending on injection valve depth, with deeper valves requiring higher injection pressures to open against annular pressure.
The optimum injection gas-liquid ratio (GLR) is determined by the gas lift performance curve, which shows production rate as a function of injection rate; the optimum point is where the incremental production benefit per Mscf of injected gas begins to decline.
Offshore platforms commonly supply injection gas from gas processing facilities, allowing continuous gas lift on dozens of subsea wells simultaneously from a single compression system.
Continuous gas lift is particularly effective in deviated and horizontal wells and in wells with significant sand production or scale tendency that would damage submersible pump equipment.

System Components and Operating Principles

A continuous gas lift installation consists of surface and downhole components integrated into a closed injection loop. At surface, gas compressors raise injection gas pressure to the required injection pressure, which is metered and distributed through an injection manifold to individual wellhead injection chokes. Each well has a dedicated injection choke that controls the injection gas rate to the annulus. The wellhead also incorporates a production choke on the tubing side and a check valve in the injection line to prevent produced fluids from backflowing into the injection system. Downhole, the tubing string carries gas lift mandrels — side-pocket or conventional mandrels — at calculated depths spaced to allow progressive unloading of the wellbore during start-up.

Gas lift valves are the critical downhole components. Each valve sits in a mandrel and opens when the injection pressure in the annulus exceeds the valve's opening pressure, allowing gas to enter the tubing. Valves are tuned to specific opening pressures using nitrogen charge in a bellows assembly, and the opening pressure decreases with depth because the weight of the annular gas column provides additional pressure at deeper valves. In a properly designed installation, only the deepest valve — the operating valve — is open during steady-state production; the shallower valves, called unloading valves, are used only during the initial unloading sequence to progressively move the liquid level down the annulus until the operating depth is reached. Side-pocket mandrels allow valves to be retrieved and replaced by wireline without pulling the tubing string, which is a significant advantage in offshore and high-well-cost environments.

The gas lift performance curve (GLPC) is the primary design and optimization tool. It plots liquid production rate on the vertical axis against injection gas rate on the horizontal axis for a given wellhead pressure and water cut. The curve rises steeply at low injection rates as added gas provides large incremental lift benefit, then flattens and eventually declines at very high injection rates as excessive gas slippage, friction losses, and separator capacity constraints reduce efficiency. The operating point that maximizes oil production for a given compression capacity is identified by plotting the allocation line — the available compression capacity divided among wells — against each well's GLPC. On multi-well fields, gas lift optimization software allocates injection gas across the well portfolio to maximize total field liquid production subject to compression and separator constraints.

Fast Facts: Continuous Gas Lift

Injection pressure range: 800 to 1,500 psi at wellhead for most onshore applications
Optimal liquid rate: most efficient at 2,000 to 20,000 barrels per day of total fluid
Typical injection GLR: 400 to 1,200 scf per barrel of produced liquid
Valve retrieval method: wireline kickover tool for side-pocket mandrels (no tubing pull)
Valve spacing: 200 to 500 meters between mandrels depending on pressure gradient
Operating valve depth: set as deep as injection pressure allows to maximize hydrostatic reduction
Compressor efficiency: 15 to 35 percent of injection gas energy is converted to useful lift work
Common applications: offshore platforms, mature onshore waterfloods, high-GOR wells

Production Engineering Tip:

When optimizing continuous gas lift on a multi-well platform, allocate injection gas using incremental production curves rather than fixed per-well allocations. Calculate the incremental barrels per Mscf of injection gas at each well's current operating point. Redirect gas from wells operating past the peak of their GLPC (where the curve is declining) to wells still on the rising portion of their curve. This reallocation typically increases total platform liquid production by 3 to 8 percent without adding compression capacity.

Continuous vs. Intermittent Gas Lift

Continuous gas lift involves steady-state injection where gas flows constantly into the tubing at a controlled rate, and the wellbore fluid column is in approximate steady-state flow. It is appropriate for wells with a productivity index (PI) sufficient to sustain continuous flow — generally wells producing more than 500 barrels of fluid per day. Intermittent gas lift, by contrast, injects gas as discrete high-pressure slugs that lift accumulated liquid slugs to surface in a cyclic fashion. Intermittent lift is designed for low-PI wells where reservoir inflow is too slow to maintain a continuous flow column; the well is allowed to accumulate a liquid slug in the tubing, then a timed or pressure-actuated controller opens the injection valve, a high-pressure gas slug enters beneath the liquid slug, and the slug is driven to surface. Intermittent lift operates at lower average injection rates but requires precise timing to prevent excessive gas breakthrough through the liquid slug. Many wells begin their artificial lift life on continuous gas lift and transition to intermittent lift as reservoir pressure declines and PI falls below the threshold for continuous flow.

Continuous gas lift is also referred to as:

Continuous flow gas lift — the technically precise descriptor emphasizing the steady-state nature of the injection and production flow
Gas injection lift — a general term that encompasses both continuous and intermittent methods
Annular gas injection — describes the physical pathway where injection gas travels down the casing-tubing annulus before entering the tubing through valves
CGL — common abbreviation used in production operations, well test reports, and artificial lift design documentation

Frequently Asked Questions About Continuous Gas Lift

How is the operating valve depth selected during gas lift design?

The operating valve is placed as deep as the available injection pressure allows. The design constraint is that the injection pressure at the wellhead, minus the pressure required to open the valve against wellbore pressure at depth, must be sufficient to lift fluids from the operating valve to surface. The maximum feasible operating depth is calculated by building a pressure traverse from wellhead injection pressure down the annulus (adding gas column gradient) and comparing it to the tubing pressure traverse (subtracting hydrostatic lift). The intersection of these two traverses defines the maximum injection depth. Placing the valve at maximum depth minimizes the height of fluid column that must be lifted by reservoir pressure alone below the valve, maximizing the reduction in bottomhole flowing pressure and thus maximizing inflow from the reservoir.

What are the most common causes of gas lift failure or underperformance?

The most frequent causes of continuous gas lift underperformance include valves that have failed open (stuck open due to debris or worn valve seats), which allows gas to short-circuit through an upper unloading valve rather than entering at the design operating depth; loss of nitrogen charge in the valve bellows, which causes the valve to remain open at all injection pressures; wax or scale deposition plugging mandrel ports; and insufficient injection pressure due to compressor capacity constraints or high pipeline back-pressure. Valves that fail open at shallow depths reduce the effective lift point, increase injection GLR requirements, and can cause severe heading (cyclic surging) in the production stream. Regular valve inspection during workover and downhole pressure surveys to confirm the injection point depth are essential maintenance practices.

Why is continuous gas lift preferred over submersible pumps on many offshore wells?

Electric submersible pumps (ESPs) deliver higher pump efficiency at low GOR, but continuous gas lift has significant advantages in offshore applications. Gas lift equipment has no electrical components downhole, eliminating ESP motor failures caused by gas locking, overheating, or produced water with high chloride content. Wireline-retrievable gas lift valves can be replaced in hours versus the days required to pull and replace an ESP completion. Gas lift handles high GOR and high sand production without damage that would destroy a centrifugal pump impeller. On subsea tiebacks where intervention cost is 500,000 to several million dollars per well, the robustness and ease of wireline maintenance of gas lift valves often outweigh ESP efficiency advantages, particularly as reservoirs mature and GOR rises.

Why Continuous Gas Lift Matters in Oil and Gas

Continuous gas lift is estimated to be the dominant artificial lift method by produced fluid volume globally, with particular prevalence in offshore Gulf of Mexico, offshore West Africa, the Middle East, and mature onshore fields in North America and Latin America. Its combination of mechanical simplicity, tolerance of adverse well conditions, suitability for high-volume production, and compatibility with intelligent completions makes it the default artificial lift choice for many operators designing offshore development projects. As fields mature and reservoir pressure declines, optimizing gas injection allocation across a platform's well portfolio can add millions of barrels of incremental recovery at low marginal cost. Continuous gas lift will remain a central production technology as operators seek to maximize recovery from existing wells rather than drill new ones.