Rod pump terms, defined.

A surface measurement of how deep the liquid stands in the casing annulus. A pressure pulse is fired at the wellhead, and its echoes off tubing collars and the liquid surface are timed and converted to depth.

A sucker rod pump built to keep the whole rod string in tension through the downstroke, so the bottom of the string never goes into compression and has nothing to buckle. It replaces the downhole pump rather than adding sinker bars.

Any method that adds energy to bring fluid to surface once reservoir pressure alone can no longer do it. Sucker rod pumps are the most common form on land; ESPs, PCPs, gas lift and plunger lift are the others.

An oil field that has been producing for years and is past its peak. Rates are lower, water cut is higher, and the economics depend on keeping existing wells running cheaply rather than drilling new ones.

The large-diameter steel pipe cemented into the drilled hole to hold the wellbore open and isolate formations. In a rod-pumped well the tubing hangs inside the casing, and the space between them is the annulus.

Axial load that pushes on a rod instead of pulling it. On the downstroke, fluid drag and plunger friction can push the bottom of the rod string into compression, which rods are not built to carry.

Weights on the pumping unit's crank or beam that offset the load of the rods and fluid, so the motor and gearbox see a similar torque on the upstroke and the downstroke. Poor counterbalance overloads the gearbox.

A plot of load against plunger position at the pump, calculated from the surface dynamometer card with a wave-equation model of the rod string. It shows what the pump itself is doing: fillage, leaks, gas and pound.

The half of the pumping cycle in which the plunger moves down. The traveling valve opens, the standing valve closes, and the plunger passes through the fluid in the barrel. This is when the bottom rods can go into compression.

A plot of polished rod load against polished rod position over one stroke, recorded at the surface. Its shape is the standard diagnostic for a rod-pumped well: fillage, gas, pound, leaks and buckling each leave a recognisable signature.

The depth of the liquid surface in the casing annulus while the well is pumping. Together with pump depth it gives pump submergence, and it shows whether the pump is running faster than the reservoir can deliver.

The impact when a plunger, falling through a partly empty barrel, hits the liquid on the downstroke. It happens when the pump runs faster than inflow, and the shock load damages rods, pump, tubing and gearbox.

Free gas entering the pump barrel and taking up space that liquid should fill. The gas compresses and cushions the downstroke instead of lifting liquid, so each stroke moves less fluid and pump efficiency drops.

Severe gas interference in which the barrel holds so much gas that the valves stop opening: the plunger only compresses and expands gas, and the pump moves no liquid at all until the gas is cleared.

A downhole device below the pump intake that lets free gas break out and rise up the annulus before the liquid enters the pump. It is the first defence against gas interference in gassy wells.

The reduction gear on a beam pumping unit that turns high-speed motor rotation into the slow, high-torque rotation of the crank. Its torque rating is usually the limit on how much load a unit can lift.

The shape a compressed rod string takes inside the tubing: past a critical load the rods bow and wrap into a helix against the tubing wall. Every stroke then rubs couplings and rod bodies against the pipe.

The curved head at the well end of a beam pumping unit's walking beam. The bridle hangs from it, so the polished rod moves in a straight vertical line while the beam rocks through an arc.

The average producing time between downhole failures that need a rig, usually tracked per well or per field. In rod-pumped wells it is driven mostly by rod, tubing and pump failures, and it sets the workover budget.

The depth in a rod string where axial load changes from tension to compression on the downstroke. Rods above it hang in tension; rods below it are pushed into compression and can buckle.

The moving piston of a sucker rod pump, attached to the bottom of the rod string. It carries the traveling valve and strokes up and down inside the barrel to lift fluid into the tubing.

The top rod of the string, with a smooth surface that slides through the stuffing box at the wellhead. It connects the pumping unit's carrier bar to the rod string and is where surface load and position are measured.

The force on the polished rod at any point in the stroke: rod weight, fluid load, friction and dynamic effects combined. Peak and minimum polished rod loads set rod stress and the size of the pumping unit.

The stationary cylinder of a sucker rod pump in which the plunger strokes. Liquid enters it through the standing valve on the upstroke and is pushed through the traveling valve on the downstroke.

How full of liquid the pump barrel is at the start of the downstroke, as a share of the full stroke. Low fillage means the pump is outrunning inflow or taking in gas, and it precedes fluid pound.

A controller that watches the dynamometer card, or motor load, and stops the pumping unit when the pump starts pumping off, then restarts it after the well has had time to refill. It replaces simple run timers.

The height of liquid in the annulus above the pump intake. Too little and the pump starves and pounds; too much and the well could be produced harder. It is read from the fluid level and the pump setting depth.

The surface machine that turns a motor's rotation into the up-and-down stroke of the rod string. The common beam unit uses a crank, pitman arms and a walking beam with a horsehead over the well.

The threaded sleeve that joins two sucker rods. Couplings are wider than the rod body, so they are where a buckled string touches the tubing first, and where rod-on-tubing wear concentrates.

A moulded collar on a sucker rod that holds the rod off the tubing wall and takes the wear in its place. Guides spread contact, but a compressed rod can still buckle between them.

Metal loss where rods or couplings rub against the inside of the tubing, from buckling or a deviated hole. It ends in a tubing leak or a worn-through coupling, and a rig job to replace the string.

A rod string breaking downhole, usually from fatigue at a pin, coupling or worn rod body. Production stops at once, and the well waits for a workover rig to fish out and replace the string.

The chain of sucker rods, joined by couplings, that runs from the polished rod at surface down to the pump plunger. It transmits the stroke and carries the fluid load, often thousands of feet long.

How long a well produces between failures that need a rig. Longer run-life means fewer workovers, less deferred production and lower lifting cost per barrel, which makes it the headline measure for rod-pumped fleets.

A heavy, large-diameter rod run just above the pump. Its weight moves the neutral point down and keeps more of the string in tension, the most common way to reduce rod buckling. It also adds load.

The pumping speed of a rod-pumped well: how many complete up-and-down strokes the unit makes each minute. With stroke length and pump size it sets displacement, and too high a rate for the inflow causes pound.

The fixed check valve at the bottom of the pump barrel. It opens on the upstroke to let well fluid into the barrel and closes on the downstroke so that fluid cannot fall back into the well.

A low-volume well near the end of its economic life. In the US the term usually means 15 barrels of oil a day or less. Small margins make every workover and every day of downtime decisive.

The vertical distance the polished rod travels in one stroke, set by the pumping unit's crank position. Plunger stroke at the pump is shorter or longer than this because the rod string stretches and contracts.

A solid steel or fibreglass rod, typically 25 or 30 feet long with threaded pins at each end, joined end to end to form the rod string. Rods are designed to carry tension, not compression.

The most widely used artificial lift system on land: a surface pumping unit strokes a rod string that drives a positive-displacement pump at the bottom of the tubing, lifting fluid with each upstroke.

The dynamometer card as measured at the polished rod, before any downhole calculation. It mixes pump behaviour with rod-string stretch and dynamics, so it is often converted to a downhole card for diagnosis.

The check valve in the plunger that moves with it. It closes on the upstroke so the plunger lifts the fluid column, and opens on the downstroke so the plunger can pass back through the fluid in the barrel.

The production pipe hung inside the casing that carries produced fluid to surface. In a rod-pumped well the pump sits at its bottom and the rod string runs inside it, so its inner wall is where rods wear.

A device that grips the casing and holds the bottom of the tubing in place, so the tubing does not stretch and contract with each stroke. It keeps plunger travel up and reduces tubing buckling and wear.

The half of the pumping cycle in which the plunger rises. The traveling valve closes and lifts the fluid column, the standing valve opens, and well fluid flows into the barrel below the plunger.

A motor controller that changes pumping speed continuously instead of switching the unit on and off. On a rod pump it lets the stroke rate follow the well's inflow, and it can slow the downstroke.

The liquid a pump actually delivers as a share of its theoretical displacement. Gas, incomplete fillage, valve leaks, plunger slippage and lost stroke from rod stretch or buckling all pull it down.

The long steel beam on top of a beam pumping unit that pivots on the samson post. The pitman arms drive one end; the horsehead on the other end moves the polished rod up and down.

The share of water in the total liquid a well produces. It rises as fields mature, so mature rod-pumped wells often lift far more water than oil, and the lifting cost per barrel of oil climbs with it.

A rig job on a producing well to repair or replace downhole equipment: pulling a parted rod string, a worn tubing joint or a failed pump. It costs the job itself plus the production lost while the well is down.