Information Notice 2005-15, Three-Unit Trip and Loss of Offsite Power at Palo Verde Nuclear Generating Station

Three-Unit Trip and Loss of Offsite Power at Palo Verde Nuclear Generating Station

ML050490364
Person / Time
Site:	Palo Verde
Issue date:	06/01/2005
From:	Hiland P NRC/NRR/DIPM/IROB
To:
Hodge, CV, NRR/DIPM/IROB, 415-1861
Shared Package
ML051520154	List: Information Notice 2005-15, Three-Unit Trip and Loss of Offsite Power at Palo Verde Nuclear Generating Station
References
IN-05-015
Download: ML050490364 (5)

UNITED STATES

NUCLEAR REGULATORY COMMISSION

OFFICE OF NUCLEAR REACTOR REGULATION

WASHINGTON, D.C. 20555-0001 June 1, 2005 NRC INFORMATION NOTICE 2005-15: THREE-UNIT TRIP AND LOSS OF OFFSITE

POWER AT PALO VERDE NUCLEAR

GENERATING STATION

ADDRESSEES

All holders of operating licensees for nuclear power reactors, except those who have

permanently ceased operations and have certified that fuel has been permanently removed

from the reactor vessel.

PURPOSE

The U.S. Nuclear Regulatory Commission (NRC) is issuing this information notice to alert

addressees to electrical equipment failures and design deficiencies identified following recent

transients at Palo Verde Nuclear Generating Station (PVNGS), Units 1, 2, and 3. As a result, the units lost offsite power, tripped, and experienced other problems, including the loss of an

emergency diesel generator (EDG). It is expected that recipients will review the information for

applicability to their facilities and consider actions, as appropriate, to avoid similar problems.

However, suggestions contained in this information notice are not NRC requirements; therefore, no specific action or written response is required.

DESCRIPTION OF CIRCUMSTANCES

On June 14, 2004, at 7:41 a.m. Mountain Standard Time (MST), the 500 kV system upset at

the PVNGS switchyard originated with a fault across a degraded insulator on a 230 kV

transmission line. Protective relaying detected the fault and isolated the line from the remote

substation. The protective relaying scheme at the other substation received a transfer trip

signal actuating an auxiliary relay (Westinghouse Type AR) in the tripping scheme for two

breakers connected to the faulted line. The AR relay had four output contacts, all of which were

actuated by a single lever arm. The tripping scheme used two contacts in redundant trip coils

for each breaker.

One breaker tripped, demonstrating that the AR relay coil picked up, and at least one of the AR

relay contacts closed. The other breaker did not trip. Bench testing of the AR relay

showed that, even with normal voltage applied to the coil, neither of the tripping contacts for the

failed breaker closed. The breaker failure scheme for the failed breaker featured a design

where the tripping contacts for the respective redundant trip coils also energized redundant

breaker failure relays. Since the tripping contacts for the failed breaker apparently did not

close, the breaker failure scheme was not activated, resulting in a persistent uncleared fault on

the 230 kV line.

Various transmission system event recorders show that, during approximately the first

12 seconds after fault inception, several transmission lines on the interconnected 69 kV, 230

kV, 345 kV, and 500 kV systems tripped on overcurrent. Also during the first 12 seconds, three

cogeneration plants tripped, two with combustion turbines and one with a steam turbine, and

the fault alternated between a single-phase-to-ground fault and a two-phase-to-ground fault, apparently as a result of a failed shield wire bouncing on the faulted line. After 12 seconds, the

fault became a three-phase-to-ground fault and additional 500 kV lines tripped.

Approximately 17 seconds after fault inception, the three transmission lines between the

PVNGS switchyard and the nearby 500 kV substation tripped simultaneously due to the action

of their negative sequence relaying, thereby isolating the fault from the several cogeneration

plants connected to that substation. Approximately 24 seconds after fault inception, the last two

500 kV lines connected to the PVNGS switchyard tripped, isolating the PVNGS switchyard from

the transmission system. At approximately 28 seconds after fault inception, the three PVNGS

generators were isolated from the switchyard and, by approximately 38 seconds, all remaining

lines feeding the fault had tripped and the fault was isolated.

The trips resulted in a total loss of nearly 5,500 megawatts electric of local electric generation.

Because of the loss of offsite power (LOOP), a Notice of Unusual Event was declared for all

three Palo Verde units at approximately 7:50 a.m. MST. The Unit 2 train A emergency diesel

generator started but failed early in the load sequence process due to a diode which short- circuited. The subject diode had less than 70 hours8.101852e-4 days <br />0.0194 hours <br />1.157407e-4 weeks <br />2.6635e-5 months <br /> of run time in the exciter rectifier circuit. As

a result, the train A engineered safeguards features busses deenergized, limiting the availability

of certain safety equipment for operators. Because of this failure, the emergency declaration

for Unit 2 was elevated to an Alert at 7:54 a.m. MST. All three units were safely shut down and

stabilized under hot shutdown conditions. Units 1, 2, and 3 were without offsite power for

approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and 9 minutes, 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 46 minutes, and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 15 minutes, respectively.

DISCUSSION

External fouling on a 230 kV insulator resulted in the deenergizing of a 500 kV switchyard, removing all sources of power to three nuclear units. The single-failure susceptibility of a

transmission line protective system was the primary cause of the cascading blackout. The insulator degradation was caused by external fouling and did not, by itself, represent a

concern about the reliability of the insulators on the 230 kV transmission system. Nevertheless, the failed AR relay and the lack of a robust tripping scheme raised concerns about the

maintenance, testing, and design of 230 kV system protective relaying. The 230 kV substation

where the relay failure occurred was subject to annual maintenance and testing. Following the

event, the failed AR relay was visually inspected. No apparent signs of contamination or

deterioration were found.

As noted earlier, the tripping scheme lacked redundancy that could have prevented the failure

of the protective scheme to clear the fault. The review of the design of the substations

connected to the PVNGS switchyard indicated that two transmission lines at the subject

substation featured a tripping scheme with only one AR relay. The newer lines had two AR

relays. However, the review found that the bus-sectioning breakers at the subject substation

contained only one trip coil instead of two trip coils.

To improve reliability, the tripping schemes for the two identified lines were modified to have

two AR relays energizing separate trip coils for each breaker. The utility is considering

installation of two trip coils in all single-trip-coil breakers. The tielines that connected 500 kV

and 230 kV switchyards did not have overcurrent or ground fault protection. The installation of

overcurrent protection for these tielines were completed in a later modification.

The apparent failure of the Unit 2 train A EDG was a failed diode in phase B of the voltage

regulator exciter circuit. The diode failure resulted in a reduced excitation current and the

current was unable to maintain the voltage output with the applied loads. The failed EDG did

not have a significant impact on plant stabilization and recovery, but it did result in limited

availability of certain safety equipment during a design basis event.

Refer to Attachment 1 for additional discussion.

CONTACT

S

This information notice requires no specific action or written response. Please direct any

questions about this matter to the technical contact(s) listed below or the appropriate Office of

Nuclear Reactor Regulation (NRR) project manager.

/RA/

Patrick L. Hiland, Chief

Reactor Operations Branch

Division of Inspection Program Management

Office of Nuclear Reactor Regulation

Technical Contacts: Amar N. Pal, NRR Thomas Koshy, NRR

301-415-2760 301-415-1176 E-mail: anp@nrc.gov E-mail: txk@nrc.gov

Note: NRC generic communications may be found on the NRC public Web site, http://www.nrc.gov, under Electronic Reading Room/Document Collections.

Attachment (exempt from public disclosure in accordance with 10 CFR 2.390)

PACKAGE: ML051520154, IN (PUBLIC): ML050490364 ATTACHMENT (NON-PUBLIC) ML051520164 OFFICE OES:IROB:DIPM Tech Editor EEIB:DE EEIB:DE LPD4:DLPM

NAME CVHodge PKleene ANPal TKoshy MBFields

DATE 02/24/2005 02/16/2005 02/24/2005 02/24/2005 02/28/2005 OFFICE PDIV-1:DLPM EEIB:DE A:SC:OES:IROB:DIPM C:IROB:DIPM

NAME WDReckley JACalvo EJBenner PLHiland

DATE 03/01/2005 03/01/2005 05/16/2005 06/01/2005