Electrostatic Discharge in a Condensing Steam Turbine Driving a Propylene Compressor Train

by Jonathan Cardell and Stephen Plaisance


This paper is a case study of bearing damage caused by electrostatic discharge. Many photos of the actual pad damage are given. Many characteristic orbits with the descriptive random spikes caused by electrostatic discharge are shown. An economic evaluation of the potential losses averted is included. Before and after orbits are shown that prove the newly installed grounding brush stopped the progression of the problem. Several references are given in the bibliography of other similar situations.


“Machine Train Layout

Figure 1 shows the propylene compressor train that is the subject of this article. A steam turbine drives a Low Pressure (LP) and High Pressure (HP) axial compressor, which are coupled in tandem.

Machine Characteristics

• Steam Turbine: 36,000 HP 600 psi condensing unit, (rotor weight = 10,500 lb).
• Low Pressure Compressor (LPC): 8 stage centrifugal compressor, (rotor weight = 10,800 lb).
• High Pressure Compressor (HPC): 4 stage centrifugal compressor, (rotor weight = 6,000 lb).
• Typical machine operating speed = 3,800 rpm

Condition Monitoring System Display

The System 1 display consoles shown in Figure 2 are located where they are easily accessible by the turbomachinery team.

Process Upset

On the morning of 10 April 2009, a process upset following a converter mis-valving event sent the Propylene LP Compressor into severe surge condition (Figure 3).

Initial diagnosis of the event included reviewing the following parameters:

• Vibration on all bearings
• Temperature on all bearings
• Axial position of all rotors
• Phase angle shift of all rotors
• Spectral analysis of vibration
• Process temps & pressures
• Steam temps & pressures
• Plant loading
• Machine speed & horsepower

The data reviewed in these parameters did not appear to correlate with the vibration trends. However, the shape of the orbit (Figure 4) in the steam turbine outboard bearing suggested that a rub condition could be present. Figure 5 shows trends of the unfiltered (Direct) vibration amplitudes at the steam turbine bearings.

The decision was made to continue to monitor machine condition with the expectation that the process conditions would stabilize with the proper valve operations set.

We believed that this rub was due to a thermal bow of the rotor on that end of the machine, possibly a “hot spot” on the rotor. We adjusted the balancing steam to pull more flow from the high pressure end of the machine to the low pressure end. This slowed the rate of change in bearing vibration. At this point, we continued to monitor the machine, expecting stabilization.

Vibration continued to slowly trend up (Figure 6), even after waiting for the thermal bow to dissipate. The team began to look at other possible failure mechanisms that could be exhibiting such behavior. The rub was evident, but closer examination showed a continuous degradation in shaft position within the bearing. Having noted this, other previously unseen clues began to surface as suspect.”

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