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LER 89-004-01:on 891221,reactor Trips & Loss of Power to Reactor Coolant Pumps Occurred.Caused by Malfunctions in MG Sets,Rod Control Sys & Substation Breaker Control Sys. Voltage Regulator for MG Set replaced.W/900319 Ltr
	ML20012D494
Person / Time
Site:	Prairie Island
Issue date:	03/19/1990
From:	Hunstad A, Parker T; NORTHERN STATES POWER CO.
To:	; NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
	LER-89-004, NUDOCS 9003270415
	Download: ML20012D494 (11)
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Northom States Power Company l 414 Nicollet Mall

Minneapolis, Minnesota $54011927 Telephone (612) 330-5500 l- -

March 19, 1990 Report Required by 10 CFR Part 50, Section 50.73 Director of. Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission

~ Attn: Document Control Desk Washington, DC 20555

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L PRAIRIE ISLAND NUCLEAR CENERATING PLANT Docket No. 50-282 License No. DPR-42.

50-306 DPR-60 1

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Revision 1 Unit 2 Reactor Trips and Loss of Power to Reactor Coolant Pumns ,

1 A revised Licensee Event Report is attached, l 'Please contact us if you require additional information related to these l cvents.

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-Thomas M Parker

' Manager Nuclear Support Services c: Regional Administrator - III NRC Sr Resident _ Inspector, NRC NRR Project Manager, NRC MPCA

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Unit 2 tripped on December 21, 1989, from what appeared to be faulty voltage regulation by one of the control rod drive mechanism motor-generator sets. One substation circuit breaker did not operate properly and power was lost to non-safeguards 4KV buses, which supply the reactor coolant pumps. The reactor was cooled by natural circulation for about 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months . The voltage regulator for the MG set was replaced and I tested. .Since the outdoor temperature at the time of the trip was -22 F, l l the cold was blamed for the breaker malfunction. Heating was applied to r the substation breakers and testing showed proper operation. The unit i

was restarted. On December 26, 1989, a nearly identical trip and loss of non safeguards 4KV buses occurred. Extensive investigation uncovered malfunctions in the MG sets, in the rod control system, and in the

substation breaker control system. After repairs and extensive testing, l

Unit 2 was returned to service on January 10, 1990.

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Ol 1 0l2 OF 1 l0 rixv , . w. == we u , am.mm EVFNT DESCRIPTION. CAUSE AND CORRECTIVE ACTIONS On December 21, 1989, Unit 2 was operating at 100% power.

At approximately 0223 hours0.00258 days 0.0619 hours 3.687169e-4 weeks 8.48515e-5 months the reactor tripped. Subsequent to the trip, power to the Unit 2 non safeguards 4KV buses (EIIS Component Identifier BU), which supply the reactor coolant pumps, was not available due to

. failure of 345KV breaker (EIIS Component Identifier BKR) 8H13 in the- 1 substation. Both emergency diesel generators (EIIS Component Identifier DG) started but did not load since the Unit 2 safeguards buses remained powered by their alternate supplies. Power was restored to the non safeguards buses, and the reactor coolant pumps, approximately three hours after the trip. Technical Specifications in effect on December 21, 1989 required one reactor coolant pump or one residual heat removal pump ].

.be. inservice at all times. Technical Specifications allowed all pumps to be shutdown for up to one hour provided the reactor was suberitical, no dilution was in progress, and at least a 10 F margin existed to saturation, ' All of the above criteria were met with the exception that the pumps were off for greater than one hour. Decay heat was being ,

removed by the steam generators with the Reactor-Coolant System in i

. natural circulation.

There was no action statement for that section of the Technical

. Specifications. At the. time of the event a revision to Technical -

Specifications had been approved, but not implemented, that added a "

section to address this issue. It states, consistent with standard Technical Specifications that when a Limiting Condition for Operation is not met and action is not specified, action must be initiated within one hour to place the unit in a condition where the equipment is not required. In this case the equipment in question was the reactor coolant pumps. The Reactor Coolant Pumps are required above 350'F so the action would be to take the unit to less than 350 F. The generic applicability statement goes on to require that for equipment required above 350 F, the unit must be in hot shutdown within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and Reactor Coolant System temperature reduced below 350*F within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

Since the unit was in hot shutdown and pumps resorted prior to the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months requirement for hot shutdown, the intent of the Technical Specifications were not exceeded.

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nxi w m a, . e. . mc w anawm Both the "first out" annunciator (EIIS Gomponent Identifier ANN) and the computer sequence of events indicated that the cause of the reactor trip was a high flux rate trip from the nuclear instrumentation system. A (negative) high flux rate trip is consistent with a dropped rod or rods.

A check of the rod drive motor-generator (MG)(EIIS Component Identifier [

MG) sets showed that the output breaker of No. 21 MG set was open. A I check of the rod control system (EIIS System Identifier AA) showed tihat ::

no fuses were blown.

Investigation of the rod drive MG set protective relaying showed that No. -

21 MG set output breaker had tripped on instantaneous reverse current.

The settings of the relays (EIIS Component Identifier RLY) were checked ;

and found to be correct. Test tripping of the relays was also !

satisfactory. Wave form observation of both MG set voltage regulators t (EIIS Identifier RG) was undertaken to determine if a defective regulator could have caused a loss of power to the rod drive system and a resulting dropping of rods. The wave forms appeared to be satisfactory. It was then decided to withdraw the shutdown bank control rods (a normal hot shutdown condition) for observation. The rods withdrew normally.

Approximately three hours later, the rods fell into the core. The output ,

breakers of both rod drive MG sets were checked and found to be open.

No. 22 MG output breaker had tripped on instantaneous reverse current. 1 It could not be determined why No. 21 MG set output breaker had tripped.

Testing was performed to attempt to duplicate the conditions. By I adjusting the voltages with the voltage regulators in manual, similar conditions could be reproduced. It was then concluded that No. 21 MG voltage regulator had failed to maintain proper voltage, resulting in degraded voltage to the rod control system and subsequent dropping of a rod or rods. This scenario coincided with information gathered concerning rod position changes at the time of the trip. This rod position indication showed that one or more rods may have started to fall into the

- core slightly before the majority of the rods. Due to unknowns about computer rod position indication (RPI) data acquisition and about RPI time response to free falling rods, this information could not be considered to be definitive. The voltage regulator for 21 MG set was replaced and tested satisfactorily. The MG set vendor concurred with the decision to replace the voltage regulator. The shutdown rods were again withdrawn and were observed for approximately five hours. It was then concluded that rod mechanism timing testing was not required and that the systems were operating correctly.

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011 01 4 OF 110 73xT c ans, ausse e #senset. ese assesnar NaC Mne JE4 W M71 Th'e response of substation 345KV breakers to the Unit-2 generator lockout (a design feature of the system) was not' normal. One of the generator output breakers, 8H13, failed to open in the required time. This resulted in substation 345KV Bus 1 being de-energized. In turn, reserve and main auxiliary power were not available for the Unit 2 non-safeguards electrical buses. Auxiliary power was restored to Unit 2, after approximately three hours. The unit was in a hot shutdown, natural circulation condition during this time. All safeguards buses were powered via their alternate sources throughout the event. Since it was very cold at the time of the trip (-22'F), it was assumed that the problem with l breaker 8H13 was related to the cold weather. " Tents" were placed around several of the breakers in the substation 'and heating was. applied.

Breaker 8H13 was trip tested several times with satisfactory opening times. Based on these actions and test results, the cause of the slow opening time was concluded to be low temperature and the breaker was now operating properly. Unit 2 was placed in service at 0009 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months on December 23, 1989.

At approximately 1232 hours0.0143 days 0.342 hours 0.00204 weeks 4.68776e-4 months on December 26, 1989, Unit 2 reactor tripped.

Subsequent to the trip, power to the Unit 2 non safeguards 4KV buses was

' not available due to failure of 345KV breaker 8H13 in the substation.

Both emergency diesel generators started but did not load since the Unit 2 safeguards buses remained powered by their alternate supplies. Power was' restored to the non-safeguards buses and the reactor coolant pumps approximately two hours after the trip. Technical Specifications in effect on December 26, 1989 required one reactor coolant pump or one residual heat removal pump be inservice at all times. Technical Specifications allowed all pumps to be shutdown for up to one hour provided the reactor was suberitical, no dilution was in progress, and at least a 10*F margin exists to saturation. All of the above criteria were I met with the exception that the pumps were off for greater than one hour.

Decay heat was being removed by the steam generators with the Reactor Coolant System in natural circulation.

l There was no action statement for that section of the Technical Specifications. At the time of the event a revision to Technical Specifications had been approved, but not implemented, that added a section to address-this issue. It states, consistent with standard Technical Specifications that when a Limiting Condition for Operation is L not met and action is not specified, action must be initiated within one hour to place the unit in a condition where the equipment is not

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011 OI 5 OF 1l0 i TEXT W must asses e an,nsset, we, _ _ #sC pom JEse'si(171 required. In this case the equipment in question was the reactor coolant pumps. The Reactor Goolant Pumps are re' quired above 350'F so the action would be to take the unit to less than 350'F. The generic applicability statement goes on to require that for equipment required above 350'F, the unit must be in hot shutdown within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and Reactor Coolant System temperature reduced below 350'F within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

Since.the unit was in hot shutdown and pumps resorted prior to the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months requirement for hot shutdown, the intent of the Technical Specifications l-were not exceeded.

This trip and the response of 345KV substation breaker 8H13 was nearly identical to the trip on December 21.

Both the "first out" annunciator and the computer sequence of events indicated that the cause of the reactor trip was a high flux rate trip from the nuclear instrumentation system. A (negative) high flux rate trip-is consistent with a dropped rod or rods. A check of the rod drive motor-generator (MG) sets showed that the output breakers of both MG sets were open. A check of the~ rod control system showed that no fuses were l blown.

Two task forces were formed. Task Force One was to investigate the problems with breaker 8H13. Task Force Two was to investigate the problems with the rod drive MG sets.

Task Force Two obtained on-site services of the vendor. Test programs were formulated for the MG set voltage regulators and for their protective relaying. Equipment to monitor these areas was installed.

While the MG sets were being monitored, two control rods from the shutdown banks, rod E03 and Ill, dropped into the core but an Urgent Failure alarm was not received from the rod control system. This is contrary to the design of the rod control system. As a result, Task Force Three was formed to investigate problems with the rod control system. On-site vendor assistance aas obtai.ned for this effort as well.

Testing of the MG set voltage regulators and protective relaying continued. The testing showed that the dynamic response of the voltage regulators and of the protective relaying was not adequate to maintain a reliable power supply to the rod drive system under reasonably expected upset conditions. Further investigation discovered that the neutral bus had a ground. When it was determined that the ground did not exist in

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Oil 01 6 OF } lg rm ,m .m ., Nees asm nn the MG set or the buses to the reactor trip breakers, Task Force Three was notified. It was determined that 'no'ither MG set voltage regulator was functioning adequately. Replacement regulators were obtained and

. inspected. After some discrepancies were resolved, the spare voltage regulators were bench tested satisfactorily. As-found. data and conditions of the MG set systems were obtained. A loss of prime mover test was performed to determine the response to a loss of power similar to the power conditions that existed after the trips. This test showed-that it is possible to trip one or both generator output breakers on a loss of power to the motors. Both replacement regulators were then installed.

Testing of the protective relaying showed that the settings of the relays would not maintain reliable power to the rod control system while protecting the generator even though the settings were consistent with the technical manual recommendations. The relays and their input devices were determined to be in good condition. After the replacement voltage regulators were installed, the regulator settings and the protective relay settings sete optimized to maintain a reliable power supply while '

still providing proper protection for the MG sets. As-left regulator wave forms were obtained and-long term temporary monitoring instrumentation was installed. Performance will be monitored until the next scheduled outage.

Task Force Three began a testing program to address.the problems in the rod control system. Some parts of the testing program had to wait for MG set availability, as the MG sets had been assigned the higher priority.

Rod drive mechanism timing tests were performed for rods E03 and Ill. The results of these tests disclosed " noise" in the current being monitored.

Data from past mechanism timing tests were reviewed. The ground of the neutral bus reported by Task Force Two was determined to be caused by a faulty sampling resistor for rod C09. The possible effects of a grounded neutral were analyzed. It was concluded that grounding of the sampling resistor in the power cabinet should not affect another power cabinet.

The defective resistor was replaced. Additional monitoring equipment was installed to determine the source of the noise spikes noted earlier.

Shutdown bank rods were withdrawn from the core. Again rods E03 and Ill dropped after they were withdrawn with no Urgent Failure alarm being generated. The Urgent Failure alarm circuit board was replaced after it was determined to be faulty. When "V-ref", a signal used to control current to the rod mechanisms, was noted to be intermittently low in power cabinet LAC, selected areas of the "V-ref" circuit path were

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011 J axv u . w. unc i assmim instrumented. The system was monitored and a mechanism timing test of all rods was performed. All rods were tripped from the fully withdrawn '

position in an attempt to establish the quality of the rod position indication data acquired by the computer during the previous reactor

-trips. .The trip test data generally supports the conclusion that both reactor trips were caused by the dropping of rod E03 and perhaps an, additional rod or rods. It is believed that the failure of the Urgent i Failure alarm circuit (which is designed to prevent rods from dropping in the. event of control system problems), in conjunction with an intermittent V-ref signal, caused at least rod E03 to drop, initiating the trips. Four circuit boards in the path of "V ref" in power cabinet 1AC were replaced and a mechanism timing test was performed on the rods powered by that cabinet, E03 and Ill. The Urgent Failure alarm circuits ;

in the remaining power cabinets were verified to be operable and the Unit !

1. rod control system neutral-to-ground potential was checked and found to be satisfactory. Long term temporary instrumentation was installed.

Performance will be monitored until the next scheduled outage. The circuit boards that were replaced have been sent to the vendor for failure' analysis. ,

Task Force One began a testing program on substation breaker 8H13.

Historical data from past unit trips during cold weather were reviewed and showed no previous problems associated with this type of breaker at temperatures as low as -10'F. Services of a consultant were obtained. :'

While preparing to perform trip time testing, clearances of the C phase.

l~ trip armature were observed to be improper. This time the testing'showed

! the opening time of C phase to be slow. Inspection of this armature showed inadequate clearances and high push-off forces. Both of these can cause'a breaker to open slowly. Wear or galling were noted when the L assembly was disassembled for inspection. No spare assemblies were -

l immediately available. Replacement parts were expedited. Breaker 8H14, L the other Unit 2 generator output breaker, was inspected, tested and l determined to be in good condition and to operate properly. Operation with only 8H14 in service was evaluated and determined to be acceptable.

Unit 2 was returned to service at 1618 hours0.0187 days 0.449 hours 0.00268 weeks 6.15649e-4 months on January 10, 1990.

Breaker 8H13 was later repaired, extensively tested, and returned to l- service on January 17, 1990.

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'Long term corrective actiors will include review and revision of the preventive maintenance programs for the'b'reakers and the rod control system. Information gained from further monitoring will be factored into T those revisions.

ANALYSIS OF THE EVENT .

This event is reportable pursuant to 10CFR50.73(a)(2)(iv) and 10CFR50.73(a)(2)(1)(B). Plant response to the trips was as expected except for loss of power to the non safeguards 4KV buses, which supply the reactor coolant pumps. The reactor was cooled by natural circulation while power was being restored to the pumps. Safeguards buses were unaffected. These events had no effect on public health and safety.

FAILED COMPONENT IDENTIFICATION Westinghouse supplied motor-generator set:

Westinghouse Motor Rating: 150 hp, 1750 rpm, 460 VAC,

'3 ph, 60 Hz, Frame 444-TS, Starting - NEMA Code F Electric Machinery Alternator Rating: 438 Kva, 0.8 PF, 1800 rpm, 260 VAC, 3 ph, 60 Hz, Frame 727 Westinghouse "Thyrex" Voltage Regulator, Size TRX-2 Sub 1 Westinghouse Full Length Rod Control System General Electric Outdoor Air-Blast Circuit Breaker Type ATB 362-7, 362 KV PREVIOUS SIMIIAR EVENTS There have been no previous similar events at Prairie Island.

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