Hydraulic and Progressive Cavity Pumps Quiz

Methods used to enhance well production when natural pressure isn't sufficient.

Relationship between well production rate and flowing bottomhole pressure, showing how much a well can produce.

Amount of fluid produced from a well in a particular time period (e.g., barrels per day).

Measure of a well's ability to produce fluid for a given pressure difference.

Average pressure of the reservoir fluid around the well.

Pressure at the bottom of the well during production.

Artificial lift method using injected gas to lift reservoir fluids.

Artificial lift method using a reciprocating pump mechanism operated by rods connected to surface machinery.

A pump that moves fluid due to its own momentum.

A pump with a spiral rotor and stator that moves fluid in cavities.

The capacity of a rod pump to move fluid; it is lower in wells with high gas-liquid ratios, small tubing diameters, or deep producing intervals.

The pump component placed in the well, consisting of a barrel, plunger, and valve.

The surface equipment that operates the rod pump.

Decrease in volume as the pump sucks up fluid; increase to force it out.

A pump that displaces a fixed volume of fluid with each stroke.

A submersible electric pump installed in the wellbore to lift fluids.

A pump that uses pressurized hydraulic fluid to drive a piston.

In these reservoirs, excessive water production can cause problems for lifting systems, potentially reducing production efficiency.

In reservoirs with a gas cap, a high gas-liquid ratio can negatively impact lift efficiency. This happens because the gas expands and pushes the oil upwards, making it harder for the lifting system to work efficiently.

When oil, water, and gas mix in a well, they create an emulsion that can increase backpressure and reduce lifting efficiency. This happens because the emulsion is thicker than the individual fluids, making it harder to flow.

The depth of a well influences the surface energy needed to bring fluids to the surface. Deeper wells need more energy to overcome gravity.

These factors influence how well a well can produce fluid. A well with a poor completion or perforation will have lower productivity.

Small casing and tubing size limits the amount of fluid that can be produced. Larger tubing may lead to excessive fluid fallback as the lifting system pauses.

Flow rates are influenced by wellhead pressure and backpressure in surface equipment like separators and flow lines. Higher backpressure reduces flow rates.

The length and diameter of the flow line determine wellhead pressure requirements and impact overall production system performance.

Surface-based systems that use injected power fluid (oil or water) to operate downhole pumps, lifting produced fluids to the surface.

A downhole pump driven by a fluid engine that converts injected power fluid into piston movement to pump formation fluids to the surface.

A downhole pump that uses a high-velocity jet of power fluid to lift formation fluids. It has no moving parts.

Deep well capability (up to 17,000 feet), high production rates (up to 10,000 B/D), adaptability to changing field conditions (no need for wireline/rig operations), and ability to lift heavy fluids.

Potential fire hazards (if oil is used as power fluid), difficulty pumping fluids with high solids content, gas effects on pump efficiency, and the need for dual tubing strings on some installations.

Reciprocating pumps have moving parts (pistons) powered by a fluid engine, while jet pumps rely on a high-velocity fluid jet without any moving parts.

Rod strings experience significant torsional stress at depth, and the elastomers used in their operation are limited by high temperatures encountered in deeper wells.

Eliminating the need for wireline or rig operations to replace pumps, making the system adaptable to changing well conditions.

Rod pumps are susceptible to gas locking, rod wear due to sliding against tubing, and high back pressure caused by the fluid head between the pump setting and the well bottom.

Rod guides are essential in deviated wells to prevent rod wear from friction against the tubing.

Gas lift is limited in horizontal wells due to difficulty installing equipment with wireline and challenges of injecting gas effectively.

Gas lift can help prevent liquid and solids from accumulating and forming slugs in the low parts of an undulating lateral leg, improving flow.

Gas lift only delivers less than 20% of its energy into lifting fluids, limiting its overall efficiency.

In undulating horizontal legs, gravity helps lift fluids only when they reach the vertical section; it can even counteract the lift in other sections.

In undulating laterals, gas tends to segregate to the high points and remain there until it reaches the vertical section, limiting fluid lift in these sections.

Liquids and solids can collect in the low parts of an undulating lateral leg and flow into the vertical section in large slugs, causing production issues.