You’ve got a gas lift well designed with multiple valves spaced up the tubing. The common assumption is that during normal production, gas is injected through all of them simultaneously, providing maximum lift. More valves, more gas entry, more lift, right? Not quite.
In reality, once your well is producing stably, gas enters through one valve only: the operating valve. This is the deepest point where the available injection pressure can overcome the hydrostatic pressure of the fluid column at that depth. Every valve above it serves a completely different, but critical, purpose: solving the start-up problem.
The Start-Up Problem: Getting Off the Kill Fluid
Imagine a well that’s just been killed and is now full of completion fluid to surface. Your design calls for deep gas injection – that’s where you get the most efficient lift, lightening the longest possible fluid column. But at that target depth, the hydrostatic pressure of the kill fluid is typically far higher than your available injection pressure. If you only had a single valve at your design depth, you’d never get the well flowing.
This is precisely where the unloading valves earn their keep. They provide a series of progressively deeper entry points that become accessible as the well’s fluid column lightens. Without them, your well would remain dead, unable to kick off against the heavy kill fluid.
The Unloading Sequence: A Step-by-Step Kick-Off
The process begins when you inject gas into the annulus. This pushes the annulus fluid level down. As the level falls past the shallowest unloading valve, gas enters the tubing at that point. This is the only depth where the fluid column is light enough for your available injection pressure to overcome it.
Gas entering the tubing immediately starts to lighten the column above that valve, displacing fluid to surface and initiating flow. As the tubing lightens, the annulus fluid level continues to fall. When it drops past the second valve, gas can now enter there.
Crucially, the first (shallower) valve senses this change in pressure conditions and closes. Injection then transfers to the second, deeper valve, which lightens a greater portion of the fluid column. This sequence repeats, valve by valve, each opening as the one above closes, until the system stabilizes at the deepest operating valve. At this point, all valves above the operating valve are closed, and the well produces on a single, optimized point of injection.
Designing for Start-Up, Not Production
This operational reality means that gas lift valve spacing is fundamentally a start-up calculation, not a production calculation. Each valve must be reachable – the annulus fluid level must be able to fall past it – using the available kick-off pressure and the tubing conditions that exist at that specific moment in the unloading sequence. Miscalculating this can lead to significant underperformance.
Common Failure Modes and Lessons Learned
Even with a solid design, several operational issues can derail your gas lift system:
Spacing Too Wide: The Stalled Well
If the vertical gap between two valves is greater than the available pressure can uncover, the unloading sequence will simply stop. Gas continues to enter at the last valve reached, and the well produces at a rate corresponding to that shallower injection point. It never reaches its design depth or full potential.
At surface, this manifests as a well that comes on but consistently underperforms. Injection pressure may hold steady, with no obvious fault. The only way to truly diagnose this is to run a flowing temperature or pressure survey to establish the actual point of injection and compare it against your design depth.
Multipointing: Wasted Gas and Instability
Multipointing occurs when gas enters at more than one valve simultaneously during steady-state production. This is a critical issue. It wastes injection gas, destabilizes the well, and can drive heading – cyclic surging as the fluid column alternately loads and unloads, causing erratic production.
Common causes include a valve failing to close, a leaking valve seat, injection pressure set too high for the design, or an operating valve that is undersized, preventing the port above it from seeing a sufficient pressure drop to close.
Valve Cutting: The Silent Killer
During the unloading sequence, valves pass gas at high velocity, often entraining liquids and any solids present in the wellbore. This abrasive flow erodes the valve seat over time, a process known as valve cutting. A cut valve will not close properly, inevitably leading to multipointing later in the well’s life. Wells that are repeatedly killed and restarted experience frequent unloading cycles, which significantly accelerate this wear.
Injection Pressure Creep: A False Fix
It’s tempting to raise injection pressure to try and boost a struggling well. However, this often opens valves above the intended operating valve, converting a stable single-point injection well into a multipointing one. You might see a brief improvement in rate, but it will quickly destabilize, often leading to heading and overall worse performance.
When a gas lift well underperforms, your first step must be to establish the actual point of injection. A flowing temperature survey is your best friend here, showing a characteristic temperature signature where cold injection gas enters. Adjusting injection pressure without knowing where gas is entering is a gamble that’s more likely to make things worse than better.
Valve Types and Retrievability
Different valve types serve specific roles in a gas lift system:
- Injection-Pressure-Operated (IPO) Valves: These are the most common unloading valves. They are controlled by casing pressure and are designed to close as the casing pressure falls during the unloading sequence.
- Production-Pressure-Operated (PPO) Valves: Less common, these valves respond to tubing pressure and are used where that response is preferred for control.
- Orifice Valves: These have a fixed port and no closing mechanism. They are frequently used at the operating point for stable, continuous injection, avoiding the reliability concerns of a charged valve at the most critical position. The unloading valves above it, however, must retain their charged mechanisms because they are designed to close.
A significant operational advantage of modern gas lift systems is that valves are typically run in side-pocket mandrels. This allows them to be retrieved and replaced on slickline using a kickover tool. This means you can reconfigure or resize valves as the well’s conditions change, without the costly and time-consuming process of pulling the entire completion. When designing, specify mandrels generously – a spare pocket or two costs little upfront and is impossible to add later. Just remember to check your tubing stress analysis for buckling that could obstruct slickline access.
Decision Checklist for Gas Lift Optimization
To ensure your gas lift system performs as designed and to troubleshoot effectively, consider these practical checks:
- Confirm available kick-off pressure and design spacing against it, ensuring adequate margin.
- Verify the operating valve depth is achievable with the steady-state injection pressure, not just the kick-off pressure.
- Confirm the gas supply – both volume and pressure – is adequate at the intended injection rate.
- Always verify the actual injection depth by temperature or pressure survey after start-up, and compare it against your design.
- Monitor for heading; treat any cyclic surging as a symptom of multipointing or an oversized operating port until proven otherwise.
- Track valve condition; wells with repeated unloading cycles warrant periodic valve retrieval and inspection.
- Re-evaluate your gas lift design as the well declines – the optimal injection point will likely move.
Bottom Line
Gas lift unloading valves are critical for well kick-off, but their role ends once the well is stable. Understanding this distinction, and diligently verifying actual injection points, is key to preventing common performance issues like stalling, multipointing, and heading. Don’t guess; diagnose with data.
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