Northern States Power d/b/a Xcel Energy (NYSE:XEL) on Oct. 21 submitted a long-promised Root Cause Analysis Report to the Minnesota Public Utilities Commission about the primary cause of the catastrophic outage that occurred in November 2011 at the coal-fired Sherburne County Unit 3 (Sherco 3).
Nearly two years of Sherco 3 restoration work has been completed and the repaired unit was synchronized to the electric grid on Sept. 4, taken off-line several days later to address post-restoration items and returned again to service Oct. 10, with testing continuing at various load levels.
Xcel said it is prefiling this report in support of a request to return Sherco 3 into rate base in an upcoming electric rate case filing. Also, cost recovery for replacement power associated with the Sherco 3 outage will be need to be considered within the Annual Fuel Clause review process.
The Unit 3 steam turbine generator at the Sherco is a tandem compound train consisting of a high pressure turbine module, double flow reheat intermediate pressure turbine module, two double flow low pressure turbine modules, a two pole 1,043,000 KVA generator and a two pole 3255 KVA alternator-exciter. Designed and manufactured by General Electric, the turbine train arrived on site in late 1979 but remained in storage for a number of years and was not placed into initial operation until July 1987 and commercial operation in November 1987.
The low pressure turbine rotors were stored indoors in a heated environment per General Electric standards. General Electric performed inspection audits of the stored turbine components from 1979 through 1982 and Northern States Power performed inspection audits from late 1978 through 1984. The inspection audits occasionally revealed light oxidation and shallow pitting on the journals of the low pressure turbine rotors where they had rested on supports. The oxidation and pitting was removed by light buffing. No other conditions were noted during the inspection audits with regard to the low pressure turbine rotors.
Original design rated conditions were 936 MW at an inlet temperature of 1000°F, inlet pressure of 2520 psig, exhaust pressure of 1.5″ HG absolute and speed of 3600 RPM. The steam turbine generator is typically operated as a baseload unit although it has operated at part load depending on system demands. The unit has not been cycled completely offline except for forced and planned outages.
The generator was uprated twice over its lifetime. It was originally shipped as a 956 MVA unit, but was upgraded to 1000 MVA and in fall of 2011 was upgraded to 1,043 MVA. No major upset or abnormal events were reported during the operating history of the Unit 3 steam turbine generator until the incident of November 2011.
In the fall of 2011, the Unit 3 steam turbine generator was retrofitted with a new high pressure turbine module and intermediate pressure turbine module. The low pressure turbine modules were not replaced. The new high pressure turbine module and intermediate pressure turbine module were designed and manufactured by Alstom Power and included features to increase efficiency and overall power output of the steam turbine train.
Numerous fractures caused a cascading series of turbine problems
Consultant Thielsch Engineering said in the root cause report that the Unit 3 steam turbine generator event of November 2011 was precipitated by the fracture of multiple finger pinned blade attachments in the Low Pressure Turbine “B” turbine end L-1 stage disk rim. The fractures resulted in liberation of portions of the finger pinned blade attachments and associated L-1 blades. The loss of mass, due to the liberation of these blades and disk sections, created a significant imbalance at the affected stage, resulting in high amplitude vibration throughout the steam turbine generator train. This vibration was responsible for the fracture of the generator shaft, fractures of the exciter shaft at three locations and extensive additional damage to the steam turbine generator train and other plant equipment.
The fractures of the finger pinned blade attachments in the low pressure turbine L-1 turbine end disk were due to the presence of pre-existing caustic stress corrosion cracks at the pin holes, ledges and at the base of the finger pinned blade attachments. The chemical species responsible for stress corrosion cracking could not be positively identified but sodium hydroxide (NaOH) is suspected.
Although the exact age of the stress corrosion cracks could not be determined, it is likely that they were initiated a few years ago. The propagation and “linking-up” of the stress corrosion cracks during subsequent operation incrementally reduced the load carrying capability of the finger pinned blade attachments. By November 2011, the load carrying capability of the finger pinned blade attachments had been reduced to the point that they could no longer sustain the centrifugal stresses generated during the planned overspeed test and fractured due to tensile overload. Investigation also revealed numerous similar stress corrosion cracks in the finger pinned blade attachments of the Low Pressure Turbine “B” generator end L-1 disk and the generator and turbine end L-1 disks of the Low Pressure Turbine “A”.
The primary causal factor responsible for the stress corrosion cracking of the low pressure turbine L-1 disks was the high static stresses generated during normal operation at the pin holes, ledges and at the base of the fingers of the finger pinned blade attachments in the low pressure turbine L-1 stage disks.
The water chemistry of Unit 3 conformed to EPRI guidelines and was not a significant factor contributory to the stress corrosion cracking observed in the finger pinned blade attachments of the L-1 stage disks, the report said. There was no evidence of abnormal operating conditions or maintenance practices that would have contributed to the stress corrosion susceptibility of the finger pinned blade attachments in the L-1 disks.