TECHNICAL FIELD

This disclosure relates to employing plunger lift to unload a well.

BACKGROUND

Plunger lift is an artificial lift mechanism for high gas-liquid ratio (GLR) oil wells and for gas well deliquification. The plunger lift may utilize a solid plunger or flow-through plunger to act as interface between wellbore fluids to facilitate utilizing wellbore pressure to produce the well. The plunger lift may be implemented with no external power source to the plunger. Plunger lift generally relies on reservoir natural energy to lift accumulated liquids from the wellbore to unload a liquid-loaded well so that the well may produce hydrocarbon from the reservoir. However, once the reservoir energy ceases to cycle the plunger naturally, another lifting mechanism should be considered. In startup and commissioning cases, swabbing or coiled-tubing intervention may be considered to kick off the well and then for the plunger lift to operate.

A well may be unloaded by removing a column of kill fluid from the wellbore to initiate flow from the subterranean formation (reservoir). Practices for unloading a well may include circulation of lower density fluid, nitrogen lifting, swabbing, plunger lift, and so on. The selection of the technique employed may depend on the well completion design, reservoir characteristics, and other factors. Plunger lift is an artificial lift technique for unloading a well that utilizes well energy of formation pressure to cycle a plunger (e.g., traveling piston) up the tubing or casing of a well. The plunger may serve as a solid interface between the liquid above the plunger and the fluid (e.g., primarily gas) below the plunger. The fluid below the plunger may supply the energy (via formation pressure) to propel the plunger (and the liquid slug above the plunger) to the Earth surface. Once the plunger is at the surface, the well may produce hydrocarbon from the subterranean formation. Then, when a column of liquid again accumulates in the wellbore, the well (wellbore) may be shut in to facilitate (allow) the plunger to drop back to bottom. Another plunger-lift cycle may begin once the well has built up sufficient pressure. Cycle frequency may vary with each well and type of production.

SUMMARY

An aspect relates to an unloading plunger to unload liquid from a well. The unloading plunger includes a body to interface with an inside surface of production tubing in a wellbore to provide a seal in the production tubing between above the unloading plunger and below the unloading plunger. The unloading plunger includes an internal chamber to hold compressed gas. The internal chamber has a chamber inlet to receive the compressed gas into the internal chamber and a chamber outlet to release the compressed gas from the internal chamber. The unloading chamber has a gas jetting port in the body at a bottom portion of the unloading plunger to receive the compressed gas from the internal chamber through the chamber outlet and discharge the compressed gas from the unloading plunger to below the unloading plunger as a jetting force for the unloading plunger. The unloading plunger includes a timer-operated valve disposed at the chamber outlet to prevent flow of the compressed gas through the chamber outlet when the timer-operated valve is closed and to provide release of the compressed gas through the chamber outlet from the internal chamber when the timer-operated valve is open.

Another aspect relates to a method of operating a well, including descending an unloading plunger from a rest position at a wellhead into production tubing to below liquid in the production tubing in a bottom portion of a wellbore. The unloading plunger has an internal chamber having compressed gas. The method includes ejecting the compressed gas from the internal chamber into the production tubing below the unloading plunger to provide motive force for ascent of the unloading plunger through the production tubing from the bottom portion of the wellbore to the wellhead. The method includes ascending the unloading plunger through the production tubing from the bottom portion of the wellbore to the rest position at the wellhead via a combined motive force of a first motive force that wellbore pressure provided by formation pressure and a second motive force that is the motive force provided by ejecting the compressed gas. The method includes unloading the liquid above the unloading plunger in the production tubing via the ascending of the unloading plunger.

The details of one or more implementations are set forth in the accompanying drawings and the description below. Other features and advantages will be apparent from the description and drawings, and from the claims.

