IR 05000346/1979032
| ML19262C349 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 12/27/1979 |
| From: | Reyes L, Tambling T, Warnick R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML19262C346 | List: |
| References | |
| 50-346-79-32, NUDOCS 8002110319 | |
| Download: ML19262C349 (15) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
.
OFFICE OF INSPECTION AND ENFORCEMENT
REGION III
Report No. 50-346/79-32 Docket No. 50-346 I.icense No. NPF-3 Licensee: Toledo Edison Company Edison Plaza 300 Madison Avenue Toledo, OH 43652 Facility Name: Davis-Besse Power Station, Unit 1 Inspection At: Davis-Besse.iite, Oak Harbor, OH Inspection Conducted: October 15-20, Novamber 1, 2, 15, 16 and 20, 1979 Inspectors:
R. F. Warnick (October 16-20, 1979)
T TcdWb
~t.
J. D. Smith (2 '2,fg<3 (October 16-19, 1979)
T '.Q. Tc-( b T. N. Tambling
/ 2. f 2 7 /~l 3 (October 16-19, November 1 and 2, 1979)
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T, T> M. -
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L. A. Reyes (October 15-20, November 1, 2, 15, 16 a
0 19 )
-
~-2 Approved By:
. F. Wa rnic't, Chief
/ /I Reactsr Projects Section 2
/
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Inspection Summary Inspection on October 15-20, November 1, 2, 15, 16 and 20, 1979 (Report No.
50-346/79-32)
Areas Inspected: Special unannounced inspection associated with the reactor trip and subsequent 30ss of offsite power that occurred October 15, 1979; followup on corrective action and the tripping of a rea dor coolant pump on October 25, 1979. The inspection involved 153 inspector-hours onsite by four NRC inspectors.
Pesults: An Immediate Action letter was issued October 17, 1979 confirming corrective action on five equipment problems prior to the unit startup.
(Para-graph 4) No items of noncompliance were identified.
19a6 056 8002110 tlC'
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DETAILS 1.
Persons Contacted
- T. Murray, Station Superintendent
- B. Beyer, Assistant Station Superintendent D. Carr. Maintenance Engineer S. Quennoz, Technical Engineer L. Simon, Operations Supervisor D. Lee, B&W Site Manager T. Beeler, Engineer R. Naylor, Engineer R. Brown, Lead Maintenance Engineer B. Hill, B&W J. Nelson, I&C Engineer The inspectors also interviewed other licensee employees, including members of the administrative, technical, maintenance and operating staff.
- Denotes those attending the exit interviews.
2.
General-Reactor Trip Subsequent Loss of Offsite PowerEvent The Davis Besse 1 reactor was automatically shutdown at 12:27 p.m.
on October 15, 1979, by a reactor high flux trip. Approximately 23 minutes later, while preparing to restart the reactor, the plant lost offsite power. During and subsequent to the reactor trip and loss of power, several problems were experienced with plant equipment.
Because of the multiple equipment problems and the plant blackout Region III sent two inspectors and a section chief to the site on October 16, 1979, to assist the resident inspector in v.LFing a thorough inspection of the plant trip, plant blackout, and che equipment problems before the station went back into operation.
During their initial review of the loss of power, the onsite inspection team questioned whether or not the plant electrical supply design actually met the requirements <f Criterion 17 of Appendix A, to 10 CFR 50.
This matter was discussed with RIII, IE, and NRR on October 17, 1979, and the onsite team was informed that the design did meet the criterion.
To make sure NRR had all the facts and to be certain the design met general design Criterion 17, the licensing project manager and a NRR electrical er.gineer visited the site on October 18, 1979.
1946 057-2-
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3.
Sequence of Events on October 15, 1979 a.
Plant Situation Prior to Reactor Trip (1) At 4:38 p.m. on October 1,,
1979, the absolute position indicator for control rrJ 7 in group 7 was declared inoper-able.
In accordance t, Technical Specifications 3.1.3.3 the reactor thermal power was reduced to 60% and the High Flux Trip Setpcint was reduced from 105.5% to 70% (four RCP's operating).
(2) At approximately 12:24 p.m. on October 15, 1979, the plant computer was taken out of service to correct a problem. It was not put back in service until approxi-mately 3 minutes after the reactor trip.
b.
Reactor Trip (1) Approximately 15 seconds prior to the reactor trip, a capacitor failed (shorted) in the Integrated Control System (ICS) pulser circuit to the main turbine EHC.
(2) The turbine control valves opened due to the capacitor fcilure. This caused an approximate 50 psi drop in steam generator pressure. The ICS responded to the decreasing steam generator pressure by increasing feed-water flow and reactor power (pulling control rods).
(3) Reactor power and main generator power increased.
(4) When reactor power reached the High Flux trip setpoint of 70%, the reactor tripped. Approximate time of the trip was 12:27 p.m. (the plant computer was out of service at the time).
(5) The main steam safety valves opened and then reset at approximately 963 psig (loop 1-2).
Minimum indicated pressurizer level was approximately 42 inches. Minimum Tave was 553 F.
Primary system pressure and temperature stabilized in approximately 6 minutes.
c.
Plant Situation Prior to Loss of Offsite Power (1) Primary and secondary systems were stabilized.
(2)
In-house electrical loads were being supplied by Startup Transformer (SU) 01.
SU-01 was being supplied 1946 058-3-
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by the 345 KV
'J' bus.
SU-01 was supplying both A and B 13.8 KV buses.
SU-02 was energized from the 345 KV
'K'
bus, but was not connected to either the A or B bus.
(3) With the loss of
'J' bus SU-01 was denergized and all offsite power to the plant was lost. All operating equipment tripped including the reactor coolant pumps.
(4) At 12:49:58 p.m. the two emergency diesel generators (DG) started on the loss of voltage to the 4.16 KV buses C-1 and D-1.
(5) Component Cooling Water Pump No. 2 and Service Water Pump No. 3 (aligned as No. 2 pump) failed to start auto-matically when No. 2 Diesel Generator started.
The pumps were subsequently started by an operator.
(6) The four reactor coolant pumps (RCS) tripped on loss of the 13.8 KV buses.
(7) The Steam Feedwater Rupture Control System activated on the loss of the four RCP's and both auxiliary feedwater pumps started approximately 40 seconds after loss of power.
(8) Natural circulation in the primary system was established with a nominal 20 F delta temperature across the steam generators.
(See attached figure 1)
(3) Switchyard breakers 34560 and 34561 were open. These breakers open automatically on loss of the main generator.
(4) When 34560 opened, the air muffler on the breaker rup-tured blowing out copper mesh coiled inside the muffler.
The copper mesh provided a ground fault, but was not detected because the breaker was isolated from the sources on opening.
(5) The load dispatcher opened the disconnect 34620 between the main transformer and breaker 34560 and 34561. This is a normal procedure in preparation to closing 34560 and 34561 and reestablishing the ring bus configuration in the switchyard.
(6) The reactimeter (data logger) was being delogged at the time and was not available to log transient data.
1946 059-4-
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d.
Loss of Offsite Power (1) At 12:49:55 (computer time) a J-bus fault was recorded on the alarm computer. This occurred as breaker 34560 in the switchyard was closed.
(2) Breaker 34560, 34561 and 34563 opened on the fault to separate buses
'J'
and 'K'
and to separate the
'J' bus from the 345 KV sources.
(9) The reactimeter was converted from delogging to the logging mode at approximately 12:57 p.m.
(10) The 13.8 KV A and B buses were reenergized from Startup Transformer 02 at approximately 1:16 p.m. and 1:33 p.m.
respectively.
(11) On restoration of offsite power, initial efforts were dedicated to restarting the air compressor to prevent possible loss of control functions.
(12) Reactor Coolant Pump 1-2 was restarted at approximately 2:15 p.m.
Due to problems in the component cooling water interlocks on the RCP's, RCP 2-2 was not restarted until 7:15 p.m., RCP 1-1 at 8:00 p.m. and RCP 2-1 at 1:35 a.m.
(the next day, October 16, 1979)
4.
Immediate Action Letter Region III issued an immediate action letter on October 17, 1979, confirming our understanding that the licensee would keep the unit shutdown until the causes of five equipment problems were determined and corrective actions to prevent recurrence were identified and completed. The inspectors completed their review of these matters on the morning of October 20 and the unit resumed operation at 10:03 p.m. that evening. The specific problems and corrective actions are discussed in paragraphs 5.b, 6.a, 6.c, 7.a, 8.a and 8.b.
5.
Reactor Trip, October 15, 1979 At approximately 12:27 p.m. on October 15, 1979, a capacitor failed in the Integrated Control System (ICS) pulser circuit to the turbine electro-hydraulic control system.
This capacitor failure caused the turbine control valves to open which lowered the main steamline header pressure. The ICS responded to the low steamline header pressure by increasing both reactor power and feedwater flow to the steam gener-ators. The increased reactor power (from approximately 60 to 70%)
1946 060-5-
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resulted in a reactor protection system trip on high flux setpoint.
The high flux setpoint had been previously reduced to a nominal value of 70% in accordance to Technical Specification 3.1.3.3 limiting con-dition for operations.
a.
Primary and Secondary Systems Responses Attached Figure I shows the responses of the major primary and secondary parameters. Reactor Coolant average temperature decreased to a minimum of 553 F.
Reactor Coolant pressure decreased to a minimum of 1850 psig prior to recovery. Minimum indicated pressurizer level was 42 inches.
The main steamline safety valves opened.
Maximum steam header pressure was approx-imately 1060 psig. The lowest steam safety valve reset pressure recorded was 970 psig on line 1-1 and 963 psig on line 1-2.
b.
Integrated Control System Pulser Failure The cause of the reactor trip was due to the failure of capacitor in the ICS pulser to the main turbine EHC system.
The capacitor, used for arc suppression, shorted. The failure applied a signal to the turbine throttle valves causing them to open.
This was the third recorded capacitor failure in the pulser circuit. The previous two failures occurring on April 25, 1979 and August 20, 1979 did not result in a reactor trip.
These failures were under investigation but had not been resolved other than to replace the capacitor.
In the investigation of this third capacitor failure by the licensee and B&W, it was determined that there was a wiring error (reversal of two leads) and that there were voltage spikes origi-nated in the EHC circuitry that exceeded the design capacity of the capacitor.
Correction of the wiring error did not in itself eliminate the voltage spikes (in tne order of 300 volts). To prevent future capacitor failures a design change was made and approved to install a capacitor with a higher voltage rating (exceeding actual measured voltages).
Main Steamline Pipe Restraint in the Turbine Building c.
After the plant trip the licensee found two anchor bolts sheared on the main steamline restraint 3A-EBD-1-H16 and the nuts on the remaining bolts loose. The nuts on the adjacent restraint 3A-EBD-1-H17 were also found to be loose.
These pipe restraints are located in the turbine building and anchor the main steamline as it makes a 90 degree turn up to the main steam stop valves.
1946 061-6-
The design of the pipe restraints was re-evaluated by the licensee. To prevent possible recurrence, it was concluded that additional supports were required. Facility change 79-362 was implemented to provide additional support by increasing the number and size of the anchor bolts and thick-ness and size of the base plate on the existing kicker.
In addition, another kicker was added to each restraint. These modifications were completed prior to plant startup.
d.
Main Steamline Inspections The licensee conducted a tour of the main steamlines inside and outside containment to verify that no other pipe restraints were damaged as the result of the October 15, 1979 turbine reactor trip. This inspection did not identify any other damage to the steam line restraints.
6.
Loss of Offsite Power, October 15, 1979 a.
Muffler Failure On a turbine trip, breakers 34560 and 34561 trip open, thus dis-connecting the generator from the ring bus.
During the subject event 34560 and 34561 tripped normally, however, the muffler on 34560 ruptured during the trip. The muffler packing material is comprised of a copper mesh which is wound around the core of the muffler where the air blast enters when the breaker opens. As a result of the muffler outer shell rupturing, several feet of this copper mesh were expelled thus creating a potential electrical path from the normally insulated breakes assembly to the grounded breaker support structure. This did not cause an immediate problem since 34560 was (at this point) disconnected from electrical sources on both sides.
(See paragraph 6.b for subsequent loss of offsite power).
Investigation into the cause of the muffler shell rupture revealed that the area adjacent to the main weld on the shell was rusted badly and had split when the breaker air blast occurred during breaker opening. The licensee consulted with the breaker manufacturer (General Electric) on the problem.
General Electric's recommendation was to reinforce the muffler by installing stainless steel reinforcement bands on all the mufflers. These bands encase the entire muffler shell and are bolted on via ears on the band ends. The licensee subsequently installed bands on all the 345 KV breaker mufflers in the switch-yard. This corrective action should preclude any future 345 KV breaker problems due to muffler failures. Also, an operator is being dispatched to the switchyard during switching to check breaker status.
1946 062
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b.
Loss of Offsite Power Following a trip, procedures require reclosure of breakers 34560 and 34561 after the generator tie breaker is opened.
This reinstates the integrity of the ring bus and provides a path for two of the offsite sources to reach buses
'J'
and
'K'.
As mentioned previously 34560 was grounded, therefore when 34560 and 34561 were closed, bus
'J'
protective relaying sensed the ground and opened 34560, 34561, and 34563. This resulted in an immediate loss of offsite power to the
'J'
bus which feeds startup Transformer 01.
The
'K' bus was unaffected and startup Transformer 02 had power to it through the entire event. Since the unit was being fed from startup Transformer 01 normal power was lost in the plant, because there is no automatic fast transfer of loads from startup Transformer 01 to 02 on a 345 KV bus fault.
In response to the loss of power, the Diesel Generators started automatically and provided power to Essen-tial Buses C1 and D1.
c.
Delay in Restoring Offsite Power At the time of the event unit power was being supplied from startup Transformer 01.
The secondary of this transformer in turn was connected via 13.8 KV breakers to 13.8 KV Buses "A" and "B", which via step down transformers "AC" and "BD" feed the 4160 volt essential buses "C1" and "D1".
Startup Transformer 02, via a pair of 13.8 KV breakers, can also supply power to the unit as outlined above. Following the loss of the
'J' bus, which is the 345 KV feeder to Startup Transformer 01, the operators attempted to close the 13.8 KV breakers (KX02A and HX02B) from Startup Transformer 02 to 13.8 KV Buses
"A" and "B".
After several attempts to close the breakers electricians were dispatened to investigate the problem.
It was discovered that by tapping on the breaker charging switch mechanism, it was possible to get the breakers to close thereby restoring power to the plant from offsite.
Initial investigation of the problem by the licensee and the switchgear manufacturer (Westinghouse) did not reveal a cause.
The licensee's staff continued to sequentially remove the 13.8 KV breakers and test them on the " Test Block." During a sub-sequent test, breaker HX02A failed to close. This was one of the two breakers that would not close during the subject event.
Following careful removal, so as not to disturb the mechanism, it was discovered that the switch holder / slider mechanism, was slightly bent and was hanging up.
This mechanism was replaced in kind with one from a spare breaker. The licensee then removed and retested HX02B. This was the other 13.8 KV breaker that failed to close during the event. Removal and inspection of the charging switch / slider mechanism on this breaker revealed no abnormalities.
The mechanism was cleaned, lubricated and reinstalled. To ensure 1946 06,3-8-
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charging switch closure on all the 138 KV breakers, the licensee removed, inspected, cleaned, and tested all of the 13.8 KV Trans-former Tie Breakers, Reactor Coolant Pump Breakers and Circula-ting Water Pump Breakers.
In addition spacer washers have bes,
added under the charging switches. This will reduce the amount of stroke necessary (by the slider) to close the charging switch.
The inspector witnessed the removal, inspection and test of many of these breakers. The switchgear was in good condition and cleanliness was good.
It would appear that the two breakers failed due to separate problems, HX02A due to a bent slider and HX02B due to incomplete closure of the charging switch. As mentioned above, spacers have been added behind the switch. The licensee is continuing their discussion with the manufacturer to determine if any other mechanical or maintenance changes should be made.
7.
Diesel Generator Problems When the two diesel generators started on loss of offsite power, two problem areas were identified and corrected. These were:
Failure of Component Cooling Water Pump No. 2 and Service Water a.
Pump No. 3 to Auto Start Following the automatic start of the Emergency Diesel Generators it was noted that Service Water Pump No. 3 and Component Cooling Pump No. 2 did not start after a normal 40 second delay. Subse-quent investigation into the problem revealed that an incomplete weld on one of the pivot pins of the pantograph linkage in the No. 2 Emergency Diesel Generator 4160 volt tie breaker cell had failed. This linkage connects the cell switches (auxiliary switches) to the breaker mechanism. Normally when the breaker closes the cell switches close and a 40 second time delay times out before the subject pumps are started. Failure of the linkage prevented the cell switches from operating and the pumps from starting automatically. Following identification of the problem, the licensee inspected the welds on all of the 4160 volt essential breakers. No incomplete welds were detected in any of the other 4160 volt breakers.
b.
Frequency Annunciator for DG No. 1 During the loss of offsite power and after DG No. I had completed its sequence of loading, the inspector noticed that annunciator, DG #1 frequency, was in the alarm condition.
The licensee manned the diesel generators local panni with a licensed operator to monitor the status of the DG's so prompt corrective action was available in case it was necessary.
1946 064-9-
Failure of the annunciator to clear after the DG was started and running was an annunciator circuit problem. During the time interval when offsite power was lost, the DG performed as designed. The licensee is pursuing the intermittent annun-ciator problem and has issued MWO 79-3306 and MWO 79-3486 to further investigate and correct the problem with DG No. I frequency annunciator.
8.
Reactor Coolant Pump Component Cooling Water Interlocks a.
October 15, 1979 Event After offsite power was restored, Reactor Cooling Pump (RCP) 1-2 was restarted at approximately 2:15 p.m.
The other three RCP's could not be started from the control room by the reactor oper-ator.
In investigating the problem the licensee found the fuses blown in the DC power supply for the Component Cooling Water (CCW)
interlock circuits to the three RCP's.
The fuses were replaced and subsequently RCP 2-2 was restarted at 7:15 p.m. and RCP 1-1 was restarted at 8:00 p.m.
The fuses on RCP 2-1 continued to blow again and the pump was not started until the next day at 01:35 a.m., after the problem was corrected.
The apparent cause for the blown fuses was attributed to defective Couch relays.
The Couch relays in the CCW interlock circuits were replaced. The relays removed from the circuits exhibited corrosion around the neutral pin providing a possible ground loop.
Several of the old relays were cut open to inspect the contacts. Each relay indicated some degree of contact damage, with the contacts in the relay from the RCP 1-2 circuit badly burned and one contact fused (this would explain why the fuses blew again after being replaced).
The relay contact damage was attributed to possible relay chatter during pericds of low CCW flow. Actual CCW flow rate and the low flow setpoint are very close. Any perturbation in CCW flow can cause the relay to activate many times because of the small dif ference between act ual flow and low flow setpoints without actively tripping the pump because of the time delay in the cir-cuits. The corrosion around the neutral pin in the relay would also contribute to contact damage because of potential ground loops.
It was noted that these relays were the originally installed equipment and had been in service several years.
The corrosion around the relay neutral pin was attributed to water being sprayed on or in the control cabinet during pre-operational testing or construction period.
This was supported by the presence of dried water residue inside the cabinet.
1946 065
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The proper sizing of the power fuses was verified by calcu-lation and testing.
b.
October 25, 1979 RCP Trip On October 25, 1979 after the unit startup on October 22, 1979, RCP 2-2 tripped during switching of loads on bus E5 (see para-graph 9 for details). The cause of the pump trip was determined to be blown power fuses in the CCW interlock circuit.
As a result of the licensee's investigation it was determined that several grounds existed in the emergency lighting circuits.
When the loads on bus E5 were switched to MCC-1, the 125 VDC bus, the new loads introduced a ground to the 125 VDC circuit that blew the 6 ampere fuses in the CCW interlock circuit.
The licensee conducted an extensive ground search to eliminate all grounds in the lighting circuits. The original events were reinacted again. No fuses were blown during the load transfers. This testing was witnessed by the inspector.
The licensee also conducted additional testing on the CCW inter-lock circuits and identified the need to add arc suppression diodes across the relay contacts.
The arc suppression elimin-ates the potential for arcing when the relays open to deenergi-ze an Agastat time delay relay that trips the RCP on a loss of CCW flow.
FCR 78-348 was also implemented to lower the low CCW flow set-point required to energize the CCW interlock circuit. This was done to reduce the actuation of the Couch relays due to small CCW flow perturbations.
In addition to the four CCW interlock circuits for the RCP's, the licensee identified 26 Class IE circuits using the Agastat Couch relay combinations. Relay arc suppression circuits were added to these controls as a preventive action.
A separate deficiency not related to the RCP 2-2 tripping was discovered in the fuse wiring on RCP 1-1 and RCP 2-2.
A fuse supposedly wired to RCP 1-1 was wired to RCP 2-2.
The licensee corrected this wiring error.
All the above work was completed before the unit proceeded to Mode 1 on November 20, 1979.
9.
Reactor Coolant Pump Trip -Reactor Trip, October 25, 1979 On October 23, 1979, the reactor power was reduced and Reactor Coolant Pamp (RCP) 1-1 was tripped due to apparent failure of two of the three 1946 066
_,1 _
shaft seals. Operation at 70% power with three operating RCP's contin-ued under the provisions of Technical Specifications, Section 3.4.1.
At approximately 12:36 p.m. on October 25, 1979 station personnel deenergized the 480 V E5 bus to remove station transformer T 1 from service to install a new cable on BY-2 under an approved facility change.
At approximately 12:38 p.m. RCP 2-2 tripped. The reactor tripped on
"High Flux / Number of RCP's On" setpoint of 55% with two RCP's running.
RCP 2-2 tripped due to a blown fuse in the DC power supply for the Component Cooling Water (CCW) interlock circuit.
(See paragraph 8.b for details on the results of the licensee's investigation and the corrective action).
The inspector reviewed th2 transient data (see attached figure 2.)
No items were identified that were not identified and corrected by the licensee.
10.
Loss of Telephones During the period when offsite power was not available, the licenses noted that the internal three digit telephones would not function.
Other licensee phone systems did work such as the Gaitronic and outside four digit phones.
Subsequently the phone company reported that they received a fault signal on the NRC red phone during the time power was lost.
Investigation into the problem showed that the power sources for the phones were tied to nonessential lighting circuits that were lost when offsite power was lost.
The licensee's phone system was modified to provide a backup power source on loss of offsite power. The NRC has initiated similar action to provide a backup power source for the red phone.
11.
Corrective Action in Response to Bulletin 79-02, Revision 1, Supplement 1 The inspector reviewed the corrective action taken by the licensee as a result of their review of the actions required by Bulletin 79-02, Revision 1, Supplement 1.
The licensee's review indicated that eleven pipe restraints did not meet the criteria for continued operation.
The inspector verified that the appropriate upgrading of these restraints was completed prior to the unit entering Mode 3 on November 20, 1979.
The repair work was done during the October 25 to November 20, 1979 outage, 1946 067
- 12 -
.
The below listed hangers were modified to comply with IEB 79-02, Revision 1, Supplement 1.
Hanger No.
FCR No.
41-HBC-44-H5 79-379 33-A-HCB-2-H44 79-380 34-GCB-5-H17 79-381 34-HCC-38-H19 79-381 3A-EBD-19-H43 79-387 6C-EBD-14-H43 79-388 31-CCB-21-H22 79-389 33A-GCB-4-H5 79-390 34-GCB-5-H2 79-391 36-HBC-39-HS79-392 41-HBC-36-H26 79-393 No items of noncompliante or deviations were identified.
12.
Exit Interview The incpectors met with licensee representatives (denoted in Para-graph 1) on October 20, 1979 and at other times to summarize the purpose and the scope of the inspections and the inspection findings.
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