ESP Failure Causes in Hot, Gassy and Sandy Wells

An electrical submersible pump (ESP) that runs for years in a cool, clean, single-phase well can fail within months once it meets high bottomhole temperature, free gas or produced sand. Most short run lives come from a small number of repeatable mechanisms. This article walks through the common ESP failure causes in harsh wells and how to turn teardown findings into a practical spares strategy.

Motor overheating and underload

An ESP motor is cooled by the well fluid flowing past its housing. When that flow is too low, winding temperature climbs, insulation ages quickly and the motor eventually shorts. A widely used rule of thumb is a minimum fluid velocity of about 1 ft/s (0.3 m/s) past the motor; below that, or when the unit is set below the perforations, a shroud is used to force flow over the motor.

Overheating usually shows up together with underload. Typical causes are:

• Pump-off: the pump is oversized for the inflow, the fluid level drops to the intake and the motor runs with little cooling.
• Free gas at the intake: gas has poor heat capacity and reduces both lift and cooling.
• High water cut changes: fluid properties shift, and a design that was right at start-up drifts out of its operating range.
• High static temperature: in deep, hot reservoirs the margin between well temperature and the motor insulation rating is already small.

Downhole gauges that report intake pressure and motor winding or oil temperature are the best defence.

Gas locking and gas handling

Centrifugal stages handle liquid well and gas badly. As free gas fraction at the intake rises, head degrades, current fluctuates and, at worst, the pump gas-locks: it spins but moves no fluid.

The options, roughly in order of gas tolerance, are:

1. Set the intake below the perforations with a shroud, so gas separates naturally in the annulus.
2. Use a reverse-flow or vortex gas separator for moderate gas.
3. Use a rotary gas separator, which spins gas out to the annulus but is vulnerable to erosion in sandy wells.
4. Add an advanced gas handler (multiphase or helico-axial stages) below the main pump to homogenise the mixture and push higher gas fractions through.

These components are not interchangeable across series and manufacturers, so the separator and gas handler need to be specified alongside the pump, not as an afterthought.

Sand abrasion, scale and corrosion

Produced sand attacks the pump in three places: radial bearings, downthrust and upthrust washers, and the impeller and diffuser flow passages. Radial bearing wear is the dangerous one, because it lets the shaft whip, raises vibration and eventually damages the seal section and motor. For sandy wells, specify abrasion-resistant construction: hardened bearings such as tungsten carbide or zirconia, and compression-type or modular stage stacking rather than floater stages where axial loads are high.

Scale is common in hot wells because the motor surface is the hottest point in the system, and carbonate scale deposits there first. Continuous inhibitor injection through a capillary line is the usual control. Corrosion from CO2 and H2S attacks housings, heads and bases; coated housings and corrosion-resistant metallurgy for heads and bases are common choices. For sour service limits on metallic materials refer to NACE MR0175 / ISO 15156, explained in our sour service guide.

Cable, MLE and penetrator failures

The power cable, the motor lead extension (MLE) and the wellhead penetrator are frequent failure points, and they are often blamed last. The main mechanisms are:

• H2S attack on insulation and conductors: in sour wells a lead sheath over each insulated conductor acts as a gas barrier. Without it, H2S permeates the insulation and attacks the copper.
• Gas decompression: gas absorbed into elastomeric insulation expands during a shut-in or fast depressurisation and blisters or splits the jacket.
• Mechanical damage during running: crushed armour at tubing collars, kinks at the sheave and damage at the MLE where it passes the pump and seal section.
• Penetrator and connector leaks: the feed-through at the tubing hanger must hold well pressure and seal the electrical path. Mismatched hanger and penetrator systems cause leaks.

API RP 11S5 covers application of ESP cable systems and API RP 11S6 covers testing of installed cable. Insulation resistance and phase-to-phase resistance readings taken at the reel, after each splice and at the wellhead give a baseline that makes later diagnosis far easier. Surface cable runs and junction boxes in classified areas should use certified Ex cable glands.

Electrical supply and VSD settings

Many downhole failures start at the surface. Voltage imbalance between phases, harmonics from the drive, voltage spikes and frequent trips all shorten motor and cable life. The variable speed drive (VSD) settings matter as much as the hardware:

Keep an amp chart or VSD log for every well. The shape of the current trace often identifies gas locking, pump-off or sand loading before anything is pulled.

Teardown and failure analysis

A pulled ESP is evidence. Dismantle, inspection and failure analysis (DIFA) should follow a consistent format so results can be compared across wells and vendors. API RP 11S1 provides a standard teardown report format, and API RP 11S itself covers operation, maintenance and troubleshooting. Other parts of the series cover testing (RP 11S2), installation (RP 11S3), sizing (RP 11S4), seal chamber sections (RP 11S7) and vibration (RP 11S8). ISO 15551-1 also addresses ESP systems for artificial lift.

Good practice is to witness the teardown, photograph each component, record shaft rotation and play, check for oil contamination in the seal section and motor, and assign a root cause and a contributing cause. The goal is to separate the component that failed first from the damage that followed.

Building a critical spares list

Teardown data tells you what to stock. Start with the failure history of your well group, then match spares to the equipment series actually installed. A practical checklist:

• Confirm housing series, motor HP, voltage and amperage, and shaft spline for every installed unit.
• Hold at least one complete spare string per common configuration where pull costs are high.
• Stock seal sections and protectors separately; they often fail before the motor.
• Keep MLEs, pothead kits and splice kits matched to the cable size and insulation type in use.
• Hold penetrators and connectors that match the installed tubing hanger system.
• Include gas separators or gas handlers for gassy wells and abrasion-resistant stages for sandy wells.
• Store cable reels and elastomer items away from direct sun and heat, and track elastomer shelf life.
• Record all spares by serial number and link them to the well they are allocated to.

Complete systems, pumps, separators and cable can be sourced through our ESP systems and spares range, alongside other artificial lift equipment and chemical injection pumps for scale and corrosion inhibition.

Sending an ESP spares RFQ

For a quick, accurate quotation, send the existing equipment details rather than a generic description: manufacturer and series, part numbers from the last teardown or installation report, motor nameplate data, cable size and type, wellhead penetrator model, bottomhole temperature, H2S and CO2 content, and expected sand production. State the required documentation and inspection up front. Our RFQ documentation guide lists what to include. When the list is ready, send us your RFQ and we will respond with options and lead times.