Generator Electrical Operating Data

Most generator issues are mechanical or thermal in nature and, in turn, become electrical problems as the dielectric strength of the insulation degrades. The mechanical issues do not always lend themselves to early detection by electrical testing, but they may produce some visible effects that are discernable during service. This portion of the condition assessment is meant to evaluate the present condition of the generator, based primarily on electrical operating data and measurements that are taken during unit operation.

The control room monitors the key parameters of:

• Stator current

• Stator voltage

• Output (MW)

• Reactive power output (MVA)

• Power factor (PF)

Safe operating levels for a specific generator are defined by design curves supplied by the OEM, where the MW, MVA, and PF are applied. An example showing the general format of these design curves and how their limits are established is shown in Figure 1-6.

Turbine-Generator Condition Assessment – In Service

Figure 1-6

Typical Generator Capability Curve

Generators are typically designed for some voltage variation. An OEM may specify a 5% over- or under-voltage design rating. Abnormal voltage operation causes damage due to increased flux heating densities and core heating. Under-voltage operation requires increased excitation and may result in additional wear/damage to the excitation system.

Data Sheet #12 further organizes the electrical inspections of generators into those associated with (1) the stator and (2) the field and exciters: DC, Alterex, and brushless.

The stator core serves a mechanical and electrical purpose. Mechanically, it supports the windings. Electrically, it provides a return path for the lines of magnetic flux induced by the field. The generator field produces an electrical potential induced during normal operation. Shaft grounding brushes are usually installed near the coupling between the turbine and generator to provide a ground path for the potential difference.

Temperature monitoring of the stator windings is normally done with resistance temperature detectors (RTDs) that are embedded within the stator slots. Thermocouples (TCs) measure inlet

Turbine-Generator Condition Assessment – In Service

as a maximum temperature for the exit water, as well as the differential temperatures between the inlet and exit. Gas-cooled windings generally have the same arrangement. In the audit portion of the assessment, temperatures should be recorded at full load. The number of RTDs and TCs out of service should also be noted and whether the failure rate is considered normal or unusual.

Stator winding availability is most often compromised by looseness caused from vibration.

Monitored vibration readings should therefore be noted and compared to trend changes against what values are expected from past service.

Partial discharge data are an indicator of deterioration or degradation of the windings. A partial discharge occurs because there is still some insulation left, whereas a complete breakdown would lead to a ground. Individual units will have their own signature and unique condition, so actual partial discharge levels are trended over time to assess the condition of the winding insulation.

A meggering (megger) test reports insulation resistance where any conducting paths within the insulating system being tested result in current flow and a reduction in the meter reading. A high reading does not necessarily indicate that the equipment can withstand the operating or rated potential since the megger uses a potential much lower than the rated potential. The megger should provide an index of the insulating material through a dielectric absorption test, that is, a measure of dryness of the winding. The ratio of the 1-minute and 10-minute readings is known as the polarization index (PI). The periodic resistance readings are trended to indicate impending insulation failures. PIs above 2.5 for the stator and 1.25 for the field are considered acceptable.

Stator current should never be allowed to exceed the nameplate values. All phases should remain equally balanced. A condition of phase unbalance (a nonsymmetrical magnetic field) can cause negative sequence currents that may overheat one phase of the stator. The amount of damage to the field will be dependent on the magnitude of the negative sequence current imposed on the field. If additional heating occurs in the rotor surface, it can cause further damage to the wedges and retaining rings. These conditions can also occur during a ground fault incident.

The generator field operates with direct current (dc) fed into the rotor windings from an

excitation source, the exciter, through a brushless excitation or a carbon brush and collector ring system. Rotation of the shaft across the dc winding field creates the rotating flux field that induces both current and voltage at the stationary coils of the stator, which has been previously discussed.

Generator internal clearances are not typically close enough to result in damage from excessive vibration (mechanical or thermal imbalance) during operation, except in the bearing and sealing areas. Generator bearings may experience the same problems as turbine bearings. One bearing, usually the collector end bearing will be insulated. This bearing should be checked with a 500-volt megger. A minimum of 100,000-ohms resistance is required.

Potential vibration problems due to thermal sensitivity are determined by monitoring rotor vibration with changes in load (or VAR output). On-line flux probes can identify the presence of

Turbine-Generator Condition Assessment – In Service

The generator field collector rings should be checked for vibration to provide an overview of their condition. A good operating collector ring/ brush assembly will have vibration levels in the range of 2–3 mils (0.05–0.08 mm). Up to 6 mils (0.15 mm) is satisfactory. Readings of 10–20 mils (0.25–0.51 mm) may be experienced when there are problems.

High collector ring vibration levels may mean mechanical problems with the rings. The amplitude of vibrations will normally increase as collector rings wear. Often, however, this is more a reflection of the condition of the rings. Damage manifests itself as peaks and valleys caused by the brushes. Grinding the collector rings will restore the rings to a round condition.

A high collector ring wear rate would indicate both mechanical abrasion and electrical arcing as the brush contact begins to degrade. The brushes tend to chatter and chip as temperatures rise from loss of contact as the condition worsens.

The hydrogen leakage test reports the amount of hydrogen consumed during operation that is absorbed into the seal oil or lost through leakage at the seals or other locations. Damage to the hydrogen seal will reduce sealing capacity and increase hydrogen consumption. Seal oil flow (absorption) is usually 5–15 gallons per minute (gpm) (18.9–56.8 liters per minute or lpm). If the absorption rate is less than 5 gpm (18.9 lpm), this indicates tight seals that may easily be

damaged. A rate greater than 15 gpm (56.8 lpm) means that the seals are open, and when combined with air-side losses, the seal oil requirements may exceed the seal oil supply pump capacity. Acceptable gas loss (leakage) is generally <1000 cubic feet (28.31 cubic meters) per day. If seals are too open, oil leakage may occur into the generator stator and also result in liquid level alarms on the generator.

In evaluating the present condition, the assessor should take note of the following issues or problems that may potentially affect generators:

• Vibration (related to the rotor winding system) is primarily a consequence of mechanical unbalance or uneven cooling and heating in the rotor winding and body. Thermal instabilities result from (a) blocked cooling passages, (b) localized temperature changes due to multiple shorted turns, or (c) other temperature instabilities that result in uneven growth of the copper windings. With regard to unbalance, multiple shorted turns are one of the most common sources of vibration in which the temperature decrease in the shorted turn slot causes less expansion and causes the rotor to bow.

• Thermal aging is the principal cause of the degradation of rotor winding insulation. The deterioration is a combination of high temperature, long operating time, and mechanical stress.

• If the shaft grounding system is not functioning properly, the potential difference between the rotor and stationary components will naturally seek an alternative path through the oil film of the bearings or the hydrogen seal. The result will be electrolysis at either location. It is important to monitor the grounding brushes during normal operation, ensuring that they are clean and in good contact with the rotor.

• Loss of field excitation can produce severe heating in the rotor. Without excitation, the unit becomes an induction generator, where significant surface current is induced in the rotor body and wedges. The consequence may be arced or burned wedges.

Turbine-Generator Condition Assessment – In Service

In evaluating the risk and need for action, the assessor should be aware of the following

circumstances where additional components of the unit may be affected by the condition of the generator:

• If the generator is supplied with excitation and system power, but the turbine loses the driving force from the steam, the generator can effectively operate as a synchronous motor and drive the turbine at rated speed. This is known as motoring. It is not necessarily harmful to the generator, but it may damage the turbine. No cooling of the turbine blades will occur with the steam flow blocked. If the blades rotating at rated speed have large tip diameters, they may heat up rapidly in the stagnant atmosphere.

• Off-frequency operation may also have a more detrimental effect on the turbine than on the generator. The blades of various stages in the turbine may be tuned to operate within a reasonably narrow operating speed (or frequency). Off-speed operation of those stages may induce harmful stimuli to the blades, resulting in resonant fatigue failures.

• Transients and faults may result in high rotor currents and resulting temperature increases, but physical or mechanical damage may result from sudden changes during operation. The mechanical shock induced by strong changes in the magnetic field may distort end turns, loosen or break end turn ties, shift end turn blocking, or damage insulation.

In additional to the generator repair specifications found in Section 8 of Volume 2, a partial listing of EPRI published research on generator operation and testing is as follows (by year of publication):

Demonstration of an Alternative ASME Steam Turbine Generator Acceptance Test, EPRI, Palo Alto CA: 1985. CS-4410.

Synchronous Machine Operation with Cutout Coils, EPRI, Palo Alto CA: 1987. EL-4983.

Generator Unbalanced Load Capability, EPRI, Palo Alto CA: 1991. GS-7393.

Main Generator On-Line Monitoring and Diagnostics, EPRI, Palo Alto CA: 1996. TR-107137.

Generator Stability Parameter Identification Data Acquisition System (PIDAS): Volumes 1 -3, EPRI, Palo Alto, CA: 1996. TR-106902.

Generator Core Overheating Risk Assessment, EPRI, Palo Alto CA: 1999. TO-113531.

Guide to Rotating Electrical Machine Hipot Testing: Draft Report, EPRI, Palo Alto CA:

2000. 1000666.

Voltage Unbalance: Power Quality Issues, Related Standards and Mitigation Techniques:

Effect of Unbalanced Voltage on End Use Equipment Performance, EPRI, Palo Alto, CA:

2000. 1000092.

Partial Discharge On-Line Testing of Turbine-Driven Generator Stator Windings: A guide

Turbine-Generator Condition Assessment – In Service

Testing of Stator Windings for Thermal Aging, EPRI, Palo Alto CA: 2000. 1000376.

Tools to Optimize Maintenance of Generator-Excitation System, Voltage Regulator and Field Ground Protection, EPRI, Palo Alto CA: 2002. 1004556.

Generator Rotor Slot Dovetail Inspection and Risk Assessment, EPRI, Palo Alto CA: 2003.

1008222.

Guide for On- and Off-Line Testing and Monitoring of Turbine Generators, EPRI, Palo Alto, CA: 2004. 1009406.

Generator On-Line Monitoring and Condition Assessment, Partial Discharge and Electromagnetic Interference, EPRI, Palo Alto, CA: 2006. 1012216.

Steam Turbine-Generator Torsional Vibration Interaction with the Electrical Network. EPRI, Palo Alto, CA: 2005. 1011679.

Torsional Interaction Between Electrical Network Phenomena and Turbine-Generator Shafts. EPRI, Palo Alto, CA: 2006. 1013460.