Plunger Lift

Controllers that open and shut the well on fixed time intervals set by the operator, the simplest and lowest-cost form of plunger cycle control.

Sensors that detect the passing ferrous plunger by the change in magnetic field actuating a reed switch or Hall-effect element, mounted externally on the tubing or lubricator so no penetration of the pressure boundary is required.

One-piece pistons that travel as a single body, providing a continuous seal against the tubing wall for liquid removal in vertical and lightly deviated wells. They require the well to be shut in long enough for the plunger to fall to bottom before each cycle.

Single helical coil spring assemblies that compress under plunger impact to absorb energy. The most common configuration for standard plunger lift wells with moderate fall velocities.

Bottom-hole stops that lock into the recess of a tubing collar coupling, using the collar gap as a no-go shoulder to anchor the assembly. They suit standard tubing strings where a coupling is available at the desired setting depth.

Lubricators machined from a single piece of bar stock rather than welded from tubing, eliminating weld seams in the pressure boundary. Favored for higher-pressure wells and sour service where weld integrity and consistent wall thickness are critical.

Pneumatically actuated valves using a spring-opposed elastomeric diaphragm to stroke the trim. The most common surface valve in plunger lift because of fast, repeatable open/close action on low supply-gas pressure.

Units that trigger open/shut decisions from measured casing, tubing, and line pressure setpoints rather than a clock, allowing the cycle to follow actual well conditions.

Designs that stack multiple springs or spring stages to absorb higher impact loads from heavy plungers or deep wells with high fall velocities, distributing energy across several elements.

Stops set at any point in the tubing bore by mechanical slips that bite into the tubing wall, independent of collar position. They allow flexible placement of the plunger stop where no coupling recess exists.

Valves driven by a pneumatic or hydraulic piston actuator, used where higher seating force or higher supply pressure is needed than a diaphragm can provide, such as larger bore or higher line-pressure wells.

Lubricators fabricated from drawn-over-mandrel (DOM) seamless tubing for the body, providing a smooth, uniform bore that limits plunger wear and arrival shock. A common, cost-effective construction for standard plunger lift pressure ratings.

Sensors that register the physical impact of the plunger striking the surface catcher or spring, converting the mechanical shock into a switch closure that signals arrival to the controller.

Systems pairing a free ball with a bottom-seated spring or sleeve so the ball can fall through liquid quickly and seat for the upstroke. They reduce shut-in time and suit higher-rate or lower-pressure wells that cannot tolerate long fall periods.

Sensors using a piezoelectric or accelerometer element to sense the vibration and sound of the plunger landing, often used where a non-contact or retrofit detection method is preferred.

Plungers with an internal bypass that opens during the fall so the plunger descends against flowing gas, minimizing or eliminating well shut-in. They are commonly applied to horizontal and high-deliverability wells to maximize uptime.

Reinforced, heavy-duty cushioning assemblies engineered for severe-service wells, providing greater energy absorption and longer service life than a standard single coil under repeated high-impact cycling.

Intelligent controllers that combine pressure inputs, plunger arrival timing, and optimization logic to automatically tune cycles for changing well behavior.

Combination assemblies that integrate a standing (one-way) check valve with the plunger stop, holding liquid in the tubing during shut-in while still arresting the falling plunger. They are used where fluid retention above the stop improves cycle efficiency.

Segmented lubricator assemblies whose body, catcher, spring section, and head are separate threaded or flanged components that can be reconfigured or replaced individually. Modular designs simplify field servicing and let one base assembly be adapted to different plunger types.

Motor valves fitted with throttling trim or an adjustable choke insert so the afterflow rate is metered rather than fully open, controlling production drawdown and reducing slugging after plunger arrival.

Arrival detection integrated into the lubricator or plunger catcher assembly at the top of the wellhead, combining the plunger-retaining catcher with a built-in sensor in a single body.

Combined devices that perform AGA gas flow measurement and plunger lift control in one enclosure, used where custody or allocation metering is required at the wellhead.

Bumper springs that latch into a standard tubing seating nipple or collar stop, allowing retrieval and replacement without pulling tubing. Sized to a specific nipple profile and tubing ID.

Lubricators that allow the plunger to be removed or dropped into the tubing from surface without disassembling the full lift cap, typically through a top access point. Used where operators routinely retrieve, inspect, or change plungers.

Spring-return actuators that close on loss of supply gas or control signal, shutting the well in during build-up and providing a safe default state on instrument failure.

Standing valve assemblies designed to bleed off trapped pressure above the seat before retrieval, easing wireline pulling of the bottom-hole assembly. They reduce the pull force and equalization hazard when recovering the stop.

Surface control units that open and close the motor valve to govern the shut-in, afterflow, and flow stages of each plunger cycle. Configurations range from simple timer-based controllers to electronic units that adjust cycles from pressure and arrival data.

Stops fitted with a spring or cushioning element that dampens the impact of the plunger as it lands at bottom-of-stroke. They extend plunger and stop service life in wells with high fall velocities.

Two-position valves that fully open during the flow phase and fully close during build-up, switching the well between production and shut-in under controller timing rather than metering flow.

Arrival sensors certified for Class I Division 1 or ATEX/IECEx zoned areas, using explosion-proof enclosures or intrinsically safe circuits suitable for the flammable gas environment around a wellhead.

Magnetic or acoustic detectors mounted at the lubricator that register each plunger arrival at surface. The arrival signal feeds the controller for cycle verification, optimization, and detection of slow or missed arrivals.

The mechanism inside or atop the lubricator that captures and holds the plunger at surface so it is not carried into the flowline. Catchers may be manual or auto-catch, and allow controlled release of the plunger to begin the next fall cycle.

Bumper springs manufactured from corrosion-resistant or NACE MR0175/ISO 15156-compliant materials for wells producing H2S or CO2, resisting sulfide stress cracking and environmental embrittlement.

Stops anchored by shear pins that release at a set tension or jar force, allowing the assembly to be freed and retrieved when normal pulling is obstructed. They provide a controlled means of recovering a stuck bottom-hole assembly.

The removable top cap and the internal spring, bumper, or shock-absorbing element that arrests the rising plunger and protects the assembly from arrival impact. These wear components are matched to plunger weight and well velocity.

The wellhead-top housing that receives the rising plunger, cushions its impact with a spring bumper, and provides a catcher to hold the plunger for retrieval. It also mounts the arrival sensor and provides access for plunger removal without killing the well.

Surface controllers that pair with the arrival sensor to time motor-valve open/close cycles, record arrival velocity and missed arrivals, and adjust afterflow and shut-in periods automatically.

Motor valves with bodies and trim rated for high wellhead working pressures and built to API 6A or comparable ratings for service close to the tree on high-pressure gas wells.

The pneumatic or electric control valves and actuators on the flowline that the controller commands to open or shut the well during each plunger cycle.

The mandrel, cage, or housing that carries and protects the spring element and provides the latch or no-go interface to the bottom-hole assembly. Sold as a matched component to the spring.

Downhole stops set at the base of the tubing that absorb the plunger's fall impact and define the bottom of travel. Seating nipples and standing-valve assemblies position the spring and protect downhole equipment.

Calibrated rings used to verify tubing and lubricator bore drift before running a plunger, confirming clearance for the plunger to pass. Puller gauge rings include a retrieval feature so the ring can be pulled back to surface after a drift check.

Valves with wetted components selected per NACE MR0175/ISO 15156 to resist sulfide stress cracking for plunger-lift wells producing hydrogen sulfide.

Assemblies fitted with a fishing neck or pulling profile so the spring can be set and recovered on slickline or wireline, simplifying replacement of a worn or failed cushion.

The brackets, clamps, conduit, and signal cabling that fix the sensor to the tubing string or lubricator and route the dry-contact or pulse output to the controller.

The cushioned landing component, often combined with the stop, against which the plunger seats at the bottom of the tubing. They convert plunger impact into a damped stop and reset the plunger for its next upward cycle.

Controllers with integrated cellular, radio, or satellite communications that report well data to SCADA or cloud platforms and accept remote setpoint changes.

Lubricator families grouped by working pressure class, such as 3,000 psi (3K) assemblies, selected to meet or exceed the well's maximum surface pressure. The rating governs body wall thickness, connection type, and material selection.

Field and software services that monitor cycle data, arrival times, and pressures to tune controller setpoints and improve liquid unloading. They support deliquification programs across well portfolios, including horizontal gas wells.

Solar panels, batteries, and weatherproof/hazardous-area enclosures that power and house controllers at remote, unelectrified well sites.