Pressure Capability

Pressure capability is the maximum differential pressure that an electrical submersible pump (ESP) can develop and maintain without failing or losing efficiency. It is the single most important sizing number when matching an ESP to a well. The differential pressure is the difference between the pressure at the pump discharge and the pressure at the pump intake. If a well's flowing conditions ask the pump to work against more pressure than its rated capability, production falls off, the pump runs hot, and the motor trips or fails. If the pump is oversized, you spend more money on equipment and power than the well warrants.

Key Takeaways

Pressure capability in an ESP is the maximum differential pressure between the pump discharge and intake, measured in kilopascals (kPa) in Canada and Australia, pounds per square inch (psi) in the US.
Each stage of a multistage centrifugal pump contributes a fixed amount of head (pressure lift) at a given flow rate. Total pressure capability is the number of stages multiplied by the head per stage, minus friction losses.
Pump performance curves show how head (and therefore pressure capability) changes with flow rate. As flow rate increases, head per stage drops. The operating point is where the pump curve intersects the system resistance curve.
Choosing a pump with insufficient pressure capability results in underperformance and possible pump-off damage. Choosing one with too much capability wastes capital and electricity, and runs the pump to the left of its best efficiency point, accelerating wear.
ESP pressure capability must be re-evaluated any time reservoir pressure declines, water cut rises, or the operator changes the target flow rate. ESP systems that were right-sized at first production often need restaging or replacement within two to four years as reservoir conditions change.

What Is Pressure Capability in an ESP?

An electrical submersible pump is not a single pump so much as a stack of identical centrifugal pump stages sitting one on top of another inside a metal housing. Each stage has an impeller that spins and a diffuser that converts the spinning motion into pressure. Every stage adds a fixed amount of pressure lift, called head, to the fluid passing through. Total head is stage count multiplied by head per stage.

Pressure capability is just that total head converted into pressure units at a specific fluid density. Freshwater is the standard reference. A pump rated at 1,000 metres of head will deliver 9,810 kilopascals (about 1,422 psi) when pumping freshwater. Pump saltwater, oil, or a water-oil mixture and the actual pressure depends on the density of whatever is flowing through.

The differential pressure the pump has to work against comes from two things: the weight of the fluid column above the pump (the hydrostatic head) minus the reservoir pressure pushing fluid into the wellbore, plus friction losses in the tubing string. In a well where reservoir pressure is high and the fluid column is light, the pump does not need much capability. In a depleted, gassy, or deep well, the required differential can be enormous.

Fast Facts

Modern ESP stages are rated on performance curves at the factory using freshwater at 60°F (15.6°C). The same pump moves differently in downhole conditions: crude oil is more viscous than water, gas entering the pump stages disrupts the impellers, and temperatures that can reach 130°C or more affect motor efficiency. Operators use viscosity correction factors and gas-handling calculations to predict actual downhole performance before running the equipment. A pump that looks perfect on a factory curve can underperform badly if the gas-oil ratio is high and no gas separator is installed above the pump intake.

How Pressure Capability Is Calculated

The starting point is the pump performance curve supplied by the manufacturer (Baker Hughes, SLB, Borets, and Weatherford are the main suppliers). The curve plots head in metres against flow rate in cubic metres per day or barrels per day. At any given flow rate, you read off the head the pump generates.

Multiply that head by the fluid density relative to freshwater (the specific gravity) and by the gravitational constant (9.81 m/s²) and you get the differential pressure in pascals. In practical terms, one metre of head on freshwater equals about 9.81 kPa or 1.422 psi.

The system curve describes how much pressure the pump needs to work against at every possible flow rate. It starts at the static head requirement (what is needed just to lift fluid to surface with no flow) and rises with flow rate as friction increases. The pump's operating point is where its performance curve intersects the system curve. If the pump's curve sits entirely below the system curve at all flow rates, the pump cannot lift fluid to surface. If the intersection happens at a flow rate that puts the pump far to the left of its best efficiency point, the pump will run hot and fail early.

Pressure Capability in the Field

In Alberta's heavy oil fields, ESP systems dominate where viscosities and water cuts are too high for other lift methods. The Cold Lake and Lloydminster fields run ESPs in wells producing up to 90 percent water. Reservoir pressures are moderate (typically 3,000 to 6,000 kPa at the pump intake), but the fluid is dense and the column is tall. Pump stages in these wells are often rated at 15 to 20 metres of head per stage, and operators run 100 to 200 stages to meet the differential pressure requirement.

In the Permian Basin and Eagle Ford shale in Texas, ESPs handle the transition from a naturally flowing well to an artificially lifted one as reservoir pressure depletes. Engineers monitor the pump intake pressure (PIP) sensor in real time and adjust the variable speed drive to maintain the pump near its best efficiency point even as conditions change month to month.

Offshore Australia (the North West Shelf, Carnarvon Basin, and Bass Strait fields) uses ESPs in deviated and horizontal wells where wellbore geometry means conventional rod pumps cannot operate. In these wells, pump placement and the effect of well deviation on fluid flow must both be accounted for in the pressure capability calculation.

Pressure capability is also called differential pressure rating or total dynamic head (TDH). Related terms include electrical submersible pump (ESP, a multistage centrifugal pump installed downhole and driven by an electric motor; the most common artificial lift method in high-rate and offshore wells), pump intake pressure (PIP, the flowing pressure at the pump inlet, measured by a downhole sensor; a critical input for diagnosing whether the pump is running on its design curve or is being starved of fluid), best efficiency point (BEP, the flow rate at which the pump operates at peak hydraulic efficiency; running persistently left of BEP generates heat and accelerates thrust bearing wear), variable speed drive (VSD, an electronic controller that adjusts the motor speed and therefore the pump's operating point to follow changing well conditions without swapping equipment), and artificial lift (the family of methods used to boost production from a well that cannot flow to surface on reservoir pressure alone; ESPs, rod pumps, gas lift, and PCPs are the main types).

Why Getting Pressure Capability Wrong Costs Two Wells' Worth of Equipment

A heavy oil operator in the Lloydminster area of Saskatchewan runs a fleet of 47 ESP wells. At initial production, the reservoir pressure averaged 5,200 kPa. The engineering team sized pumps to provide 8,000 kPa of differential pressure at the target flow rate, giving a comfortable margin.

Over 18 months, reservoir pressure declined faster than the model predicted, dropping to 3,100 kPa in the better producers. At lower intake pressure, the pump needs to generate more differential to reach the surface. Several wells began producing below target. Rather than staying at the original operating point, the pump was starved, running left of the best efficiency point, overheating the motors.

Seven motors failed within four months. Each motor pull and replacement cost CAD 65,000 in service rig time and equipment, plus three to five days of lost production. The remediation was to restage the pumps with higher-head impellers matched to the new reservoir conditions, and to install variable speed drives that automatically backed off motor speed during gas slugs. Restaging cost CAD 18,000 per well; the seven motor failures cost CAD 455,000.

The lesson: pressure capability is not a static number. It needs to be recalculated at each reservoir pressure decline milestone. The pump that was right for day one is rarely right for month eighteen.