Intermittent Gas Lift: Cyclic Injection for Low-Rate Wells

What Is Intermittent Gas Lift?

Intermittent gas lift (also called intermittent lift or cyclic gas lift) is an artificial lift method in which high-pressure gas is injected into the production tubing in periodic slugs or cycles rather than continuously, causing discrete liquid slugs to be driven from the wellbore to the surface. It is specifically designed for low-productivity wells that cannot sustain continuous liquid flow rates high enough to maintain velocities above the critical rate for stable two-phase flow — wells where continuous gas lift would result in gas locking, heading, or inefficient lift due to insufficient liquid fill.

Key Takeaways

Gas is injected in periodic cycles rather than a steady stream, allowing liquid to accumulate in the tubing between cycles before each lift event.
A surface time-cycle controller or pressure-based intermittent-lift controller governs injection timing and duration.
Plunger-assisted intermittent lift adds a free-traveling plunger that acts as a mechanical interface between the gas and liquid slug, significantly reducing slippage and improving efficiency.
Intermittent lift is most effective for low-productivity-index (low-PI) wells producing fewer than 200 to 400 barrels of liquid per day.
Cycle frequency and slug volume must be optimized for each well to maximize liquid recovery while minimizing gas injection volumes and compressor wear.

How Intermittent Gas Lift Works

In a continuous gas lift installation, gas is injected steadily into the tubing through a series of gas lift valves, aerating the fluid column and reducing its hydrostatic head so reservoir pressure can push it to surface. This works well when the well produces enough liquid to maintain a continuous, rising fluid column. But in a low-rate well, the liquid production rate is too low to sustain the minimum velocity required to keep the gas and liquid moving together — the gas tends to migrate through the liquid (slippage), and lifting efficiency collapses.

Intermittent lift sidesteps this problem by accumulating liquid at the bottom of the tubing during a closed (non-injection) period. When the liquid column reaches a sufficient height — or when a set time interval expires — an injection valve opens and a slug of high-pressure gas enters the tubing from the casing annulus. The gas slug pushes the accumulated liquid slug up the tubing ahead of it, propelling it to the surface production facilities. Once the liquid slug reaches the surface, the gas slug breaks through, the injection valve closes, and the cycle restarts. The well effectively produces in discrete pulses rather than a continuous stream.

The injection gas volume, cycle duration, and rest period between cycles are the key operating parameters. Too short a rest period means insufficient liquid accumulation and wasted injection gas. Too long a rest period means underproduction. Optimizing these parameters — often done with downhole pressure gauges, surface production measurement, and simulation software — can meaningfully increase liquid recovery and reduce operating costs.

Fast Facts: Intermittent Gas Lift

Best application: Low-PI wells producing fewer than 200-400 bbl/day of liquid
Injection mode: Periodic slugs controlled by surface time-cycle or pressure controller
Cycle frequency: Typically 4 to 20 cycles per day depending on well productivity
Key variable: Slug length at injection — too short wastes gas, too long causes slippage
Plunger assist: Adds a free-traveling plunger to reduce gas-liquid slippage by 30-60%
Injection point: Single operating valve near the bottom of the tubing string
Gas source: Surface compression from field gathering system or dedicated wellsite compressor
Monitoring: Surface production meter, casing and tubing pressure gauges, cycle counter

Field Tip:

A surface time-cycle controller is the simplest and most common method for governing intermittent lift, but it cannot account for changing well conditions — rising water cut, declining reservoir pressure, or seasonal surface temperature changes that affect injection gas density. When production begins to decline on a fixed-time controller, switching to a pressure-based intermittent-lift controller that uses actual casing and tubing pressures as triggers can recover significant production without adding compression capacity. Monitor the casing pressure buildup rate between cycles; a faster buildup rate indicates the well is making more fluid than the current cycle frequency allows.

Timing Controllers and Cycle Optimization

The two main control approaches for intermittent gas lift are time-cycle controllers and pressure-based controllers. A time-cycle controller — essentially a programmable timer on the surface injection choke or valve — opens and closes gas injection at fixed intervals. It is inexpensive and reliable but inflexible; it cannot adapt when the well's liquid fill rate changes. A pressure-based intermittent-lift controller uses measured casing and/or tubing pressures to trigger injection when the tubing pressure reaches a set low point (indicating sufficient liquid accumulation) and to terminate injection when the tubing pressure rises to a set high point (indicating the slug has been swept to surface). Pressure-based control is more responsive but requires reliable instrumentation and more careful commissioning.

Cycle optimization analysis begins with a flow survey or production logging to determine the actual fill efficiency — the percentage of each cycle that contributes to liquid production versus wasted gas injection. Engineers use nodal analysis software to model the expected liquid slug volume per cycle at various cycle frequencies and injection gas volumes, then compare to measured surface production to identify the optimal operating point. In fields with many intermittent-lift wells on a shared compression system, coordinating cycle timing across wells can reduce peak gas demand and allow a smaller, more consistently loaded compression facility.

Plunger-Assisted Intermittent Lift

One of the primary inefficiencies in intermittent gas lift is slippage — gas migrating upward through the liquid slug rather than pushing it as a coherent unit. A plunger (a cylindrical free-traveling device that moves up and down the tubing) inserted between the gas slug and the liquid slug acts as a mechanical interface, dramatically reducing slippage. As the gas slug expands and rises, it pushes the plunger upward; the plunger in turn pushes the liquid slug above it with minimal gas breakthrough. At surface, the plunger is caught in a surface lubricator, the liquid slug flows to the production header, the plunger falls back to the bottom on the next rest period, and the cycle repeats. Plunger-assisted intermittent lift is particularly effective in wells with high gas-liquid ratios and can improve lift efficiency by 30 to 60 percent compared to unassisted intermittent lift in the same well.

Comparison to Continuous Gas Lift

Continuous gas lift is the preferred and simpler operating mode for high-rate wells with sufficient productivity to maintain a stable, rising fluid column in the tubing. It uses multiple gas lift valves at different depths to unload the well and then a single operating valve for steady-state lift. Intermittent lift is a lower-rate technique, typically reserved for wells producing below the minimum throughput at which continuous lift remains efficient — generally below 100 to 200 barrels of liquid per day in most field conditions. Some wells transition from continuous to intermittent lift as reservoir pressure declines and liquid production drops below the continuous lift threshold, extending the productive life of the gas lift installation without changing the surface equipment.

Intermittent gas lift is also referred to as:

Intermittent lift — shortened form used on well records and artificial lift system reports
Cyclic gas lift — emphasizes the periodic, repetitive nature of the injection cycle
Slug lift — describes the liquid slug transport mechanism at the heart of the method

Frequently Asked Questions About Intermittent Gas Lift

How do I know if my well needs intermittent rather than continuous gas lift?

The primary indicator is liquid production rate relative to the minimum continuous lift rate for the tubing size and depth. If a nodal analysis or production test shows the well cannot sustain the minimum liquid velocity needed for stable continuous lift — typically 50 to 150 bbl/day for common 2-3/8 in. and 2-7/8 in. tubing strings in wells of moderate depth — intermittent lift is the appropriate mode. Symptoms of a continuous gas lift well operating below its minimum rate include heading (erratic surface production), gas locking (no liquid production despite gas injection), and declining liquid rates despite unchanged injection gas volumes.

What is fill efficiency, and why does it matter?

Fill efficiency is the fraction of the tubing volume below the operating gas lift valve that is actually filled with liquid at the time of gas injection. High fill efficiency (80-100%) means the gas slug is pushing a full, dense liquid slug to surface and the lifting work is efficiently used. Low fill efficiency means the gas slug enters mostly gas-filled tubing, expands rapidly, breaks through quickly, and delivers little liquid — a waste of compression energy. Downhole pressure gauges measuring the buildup of tubing pressure between injection cycles give the clearest picture of actual fill rate.

Can intermittent gas lift work in deviated or horizontal wells?

Intermittent gas lift is most effective in vertical or near-vertical wellbores where gravity assists liquid slug accumulation and the gas-liquid interface remains stable. In highly deviated wells, the liquid slug tends to settle on the low side of the tubing and slippage increases substantially, reducing efficiency. Horizontal sections are generally not amenable to intermittent gas lift. For highly deviated producers with low liquid rates, electric submersible pumps (ESPs) or progressive cavity pumps (PCPs) are usually more effective artificial lift options.

Why Intermittent Gas Lift Matters in Oil and Gas

As oil fields mature and reservoir pressure declines, many wells that once flowed naturally or produced well under continuous gas lift fall below the rate threshold where continuous lift remains economic. Intermittent gas lift extends the productive life of these wells by matching the lift method to the well's actual deliverability, recovering reserves that would otherwise be left behind. In gas lift fields with hundreds of wells on shared compression, proper intermittent lift design and cycle optimization can also reduce total compression horsepower requirements and operating costs across the entire system.