Artificial Gas Lift Solutions
Hybrid Solutions

Aggressively reduce bottom-hole pressure


Hybrid Solutions

There are a number of characteristics that make some wells an attractive candidate for a hybrid artificial lift solution including the gas/liquid ratio, fluid production, casing pressure, and differential. Plunger-assisted gas lift (PAGL) and gas-assisted plunger lift (GAPL) both utilize injection gas and a plunger in a hybrid solution to optimize the well. Injection gas can raise the critical velocity needed to lift both the plunger and the fluid. GAPL is intermittent injection and conventional plunger lift. It is implemented on lower gas and fluid producers. Gas is only intermittently injected during certain phases of the plunger cycle to supplement the wellbore inflow and lift the fluid and plunger to surface.

Hybrid Solutions – (Rigless) Gas Lift

Many operators have found that annular-flow gas lift during initial production delivers the production rates comparable to rates delivered by some electric submersible pumps (ESPs), but at reduced capital costs. As wells decline to the point where tubing flow is more efficient, traditionally a workover rig was brought in and swapped the annular system for a tubing flow system. Our Hybrid Gas Lift System allows for this change-over without the workover rig and associated costs.

Continuous Flow Gas Lift System with a Continuous Flow Plunger (PAGL)

There are several reasons/scenarios why you should consider a continuous flow plunger introduced to a continuous flow gas lift system:

To lift fluids more efficiently than a standalone gas lift system
To mitigate or eliminate paraffin or scale build up in the tubing
To reduce the required gas lift injection volumes on single well sites or field gas lift systems

Intermittent Gas Lift System with a Conventional Plunger Lift System (GAPL)

An intermittent gas lift system by itself can prove to produce less than desirable results in deeper wells, strictly due to the liquid fallback and the total liquid recovered per cycle. Liquid fallback in the tubing per cycle can be as much as 10% of the initial liquid slug per 1000 feet of lift. With the addition of a conventional plunger, liquid fallback can be significantly reduced and more of the slug is delivered to the surface during each cycle.