IR 05000400/1987034
| ML18022A582 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 10/13/1987 |
| From: | Burris S, Fredrickson P, Maxwell G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18022A581 | List: |
| References | |
| 50-400-87-34, NUDOCS 8710260326 | |
| Download: ML18022A582 (13) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
ATLANTA,GEORGIA 30323 OCT 14 1S87 Report No.:
50-400/87-34 Licensee:
Carolina Power and Light Company P. 0.
Box 1551 Raleigh, NC 27602 Docket No.:
50-400 Facility Name:
Harris
License No.:
NPF-63 inspection Conducted:
August 20 - September 24, 1987 r",-e-:
P. Burris e
Approved JP.
E.
Fr ickson, Section Chief
'ivision of Reactor Projects Date Sign d Date Signed
/<
Date Signed SUMMARY Scope:
This routine, announced inspection involved inspection in the areas of Operational Safety Verification, On Site Plant Nuclear Safety Committee, Monthly Surveillance Observation, Monthly Maintenance Observation, and Information Meeting.
Results:
One violation was identified, Failure to comply with Containment Isolation Technical Specifications Paragraph 3.
8710260326 87iOi4 PDR ADOCH, 05000400
REPORT DETAILS 1.
Persons Contacted Licensee Employees G.
G. Campbell, Manager of Maintenance J.
M. Collins, Manager, Operations G.
L. Forehand, Director, QA/QC L. I. Loflin, Manager, Harris Plant Engineering Support G. A. Myer, General Manager, Milestone Completion D. L. Tibbitts, Director, Regulatory Compliance R.
B.
Van Metre, Manager, Harris Pl.ant Technical Support R. A. Watson, Vice President, Harris Nuclear Project J.
L. Willis, Plant General Manager, Operations Other licensee employees contacted included technicians, operators, mechanics, security force members, engineering personnel and office personnel.
2.
Exit Interview The inspection scope and findings were summarized on September 24, 1987, with the Plant General Manager, Operations.
No written material-was provided to the licensee by the resident inspectors during this reporting period.
The licensee did not identify as proprietary any of the materials provided to or reviewed by the resident inspectors during this inspection.
The violation identified in this report has been discussed in detail with the licensee.
The licensee provided no dissenting information at the exit meeting.
Operational Safety Verification (71707, 71710)
Plant Tours The inspectors conducted routine plant tour s during thi s inspection period to verify that the licensee's requirements and commitments were being implemented.
These tours were performed to verify that systems,'alves and breakers required for safe plant operations were in their correct position; fire protection equipment, spare equipment and materials were being maintained and stored properly; plant operators were aware of the current plant status; plant operations personnel were documenting the status of out-of-service equipment; security and health physics controls were being implemented as required by procedures; there were no undocumented cases of unusual fluid leaks, piping vibration, abnormal hanger or seismic restraint movements; and all reviewed equipment requiring calibration was currents
Tours of the plant included review of site documentation and interviews with plant personnel.
The inspectors reviewed the shift foreman's log, control room operator's log, clearance center tag out logs, system status logs, chemistry and health physics logs, and
.control status board.
During these tours the inspectors noted that the operators appeared to be alert and aware of changing plant conditions.
The inspectors evaluated operations shift turnovers and attended shift briefings.
They observed that the briefings and turnovers provided sufficient detail for the next shift crew.
The inspectors verified that various plant spaces were not in a condition which would degrade the performance capabilities of any required system or component.
Site security was evaluated by observing personnel in the protected and vital areas to ensure that these persons had the proper authorization to be in the respective areas.
The security personnel appeared to be alert and attentive to their duties and those officers performing personnel and vehicular searches were thorough and systematic.
Responses to security alarm conditions appeared to be prompt and adequate.
Unidentified Leakage Unusual Event On August 31, the licensee notified the NRC duty officer and state and local officials concerning the declaration of an Unusual Event (UE).
The reactor coolant system unidentified leakage rate had exceeded the one gallon per minute allowed by TS Section 3.4.6.2.
When the event was declared the unidentified leakage was 1.09 gpm, and the reactor was operating in the power range (Mode 1).
At 2: 15 a.m.
the shift foreman held a meeting with the plant operators and informed them of the plant conditions and the plans to shutdown.
The inspectors were present during the shift briefing and noted that the operators were fully cognizant of the plant conditions and the procedural requirements concerning shutting the unit down.
Following the briefing the operators began reducing the electrical loads'n the turbine generator, and by 4:30 a.m.
the plant was operating in Mode
(Hot Standby).
The plant was placed in Hot Standby to comply with the Action Statement of TS Section 3.4.6.2.
After the plant was placed in Hot Standby, licensee personnel and the resident inspectors conducted visual inspections inside the containment building.
The inspections were conducted to locate the source or sources. of the excessive unidentified leakage.
During the inspections three unidentified leaks were found which appeared to be the most likely sources of the excessive leakage.
The first leak was attributed to a valve packing leak on a block valve (RC-117)
for one of the pressurizer power operated relief valves.
The second leak was from the mechanical flange which connects the reactor vessel head vent line to the vent system piping.
The last
leak was from a test connection on a chemical and volume control system line near valve 1CS-498
'uring the inspections six other unidentified leaks were found.
However, these six appeared to be leaking at a less significant rate than the three previously mentioned.
The six leaks included a
residual heat removal valve 1RH-39, two chemical and volume control valves 1CS-497 and 1CS-502, and three safety injection valves 1SI-259, 1SI-260 and 1SI-101
~
Work Requests were issued to authorize repairing all of the leaks.
Maintenance work crews were assigned to complete the various tasks to reduce or stop the leakage associated with the above valves and piping connections.
During the evening of August 31, the tasks were completed and at 9:00 p.m.
the plant unidentified leakage rate was reduced to
.7 gpm.
The licensee terminated the UE and declared the plant to be no.longer operating under the Action Statement of TS Section 3.4.6.2.
At 2:36 a.m.
on September 1,
the licensee began a reactor start-up; the reactor was critical by 3:27 a.m.,
and by 10:56 a.m.
the plant was operating at power and was electrically connected to the power grid.
During this UE, the inspectors observed that control room personnel utilized the site Emergency Plant Procedure PEP-301, Rev.
when making the appropriate notifications concerning the event.
These personnel, at, periodic intervals throughout the duration of the event, updated appropriate officials.
b.
Loss of Main Feedwater Pump During an Unusual Event On August 31, at 4:08 a.m.,
while placing the plant in Hot Standby due to the UE described above, with one
"A" main feedwater pump running, supplying steam generator feed requirements for eight percent power, the plant experienced a
loss of the running main feedwater pump.
Loss of the running main feedwater pump generated an engineered safety feature (ESF)
signal, starting the motor-driven auxiliary feedwater pumps.
All safety systems operated as required.
The licensee's investigation revealed that the main feedwater pump tripped due to excessive osci llations in main feedwater flow.
The osci llations were attributed to the sensitivity of the main feedwater regulating valves and the current secondary plant configuration, which requires throttling main feedwater flow with the main feedwater pump discharge valves.
At 3:30 p.'m. with the plant in Hot Standby and the "B" main feedwater pump supplying steam generator feed, the plant experienced a loss of the running main feedwater pump.
The operators attempted a restart of the main feedwater pump, however, it tripped again.
The main feedwater pump trip was attributed to the valve stem on the "A" main
c
~
feedwater miniflow valve becoming sheared.
The licensee determined that val ve stem failure was a
resul t of vibration caused by throttling on the pump discharge valve.
The licensee repaired the valve stem and placed the feedwater system back in operation on September 1.
All safety systems required to start actuated as designed.
k Loss of Containment Isolation On September 11, the licensee reported to the NRC Duty Officer that the plant was experiencing problems with one of the steam generator blowdown valves; and subsequently shutdown the unit and repaired the valve on September 13.
The valve, 1BD-11, is the containment isolation valve for the
"A" steam generator blowdown system piping.
On August 13, the valve had been found to be stuck in the open position and could not be closed either manually or automatically.
The failure to either isolate the steam generator blowdown line or shutdown the unit subsequent to the failure of 1BD-11 is a violation of TS 3.6.3.
The steam generator blowdown system was designed in accordance with
CFR 50, Appendix A,Section V, Criteria
(GDC 57), "Closed System Isolation Valves."
Systems designed under this requirement incorporate the system piping as the initial containment barrier, and therefore, are allowed to have only one isolation valve which is required to be located outside containment.
The inspectors reviewed TS 3.6.3,
"Containment Isolation Valves,"
which states,
"each containment isolation valve shall be operable with isolation times less than or equal to required isolation times".
The following are also required actions as stated in the TS:
"With one or more of the containment isolation
.valve( s)
inoperable, maintain at least one isolation valve OPERABLE in each affected penetration that is open and:
a.
Restore the inoperable valve(s) to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or b.
Isolate each affected penetration within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by use of at least one deactivated automatic valve secured in the isolation position, or c.
Isolate each affected penetration within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by use of at least one closed manual valve or blind flange, or d.
Be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in.
COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />."
The TS implements the licensee's administrative procedure,
"Plant Program,"
PLP-106, Rev.
0.
Procedure PLP-106 identifies all containment isolation valves and stipulates the, required testing criteria necessary to meet TS 3.6.3.
Steam generator blowdown system valve 1BD-ll (four inch isolation valve) is listed in Attachment 5 of PLP-106 with a Note 6 specifying that "For this valve, the closed system in which it is located is considered to be an operable isolation valve for the purposes of compliance with the ACTION statement".
The licensee's interpretation of Note 6 in PLP-106 on August 13, was that the "closed systems" acting as an isolation valve met the operability requirements of TS 3.6.3, and that containment integrity was maintained.
This incorrect position resulted in continued operation of the unit with 1BD-ll isolation valve stuck open.
On August 28, the Onsite Nuclear Safety organization identified that
- operation in this condition might constitute an unreviewed accident analysis and that operation with 1BD-11 open and inoperable could be outside the bounds of GDC-57 and TS 3.6.3.
Based on the accident analysis concern, on September 9,
the licensee closed 1BD-7 (four inch valve),
a valve in one of the two "A" steam generator blowdown lines inside the containment building.
With 1BD-7 closed, a flow path still existed through 1BD-1 (two inch valve)
from the steam generator through 1BD-ll.
By closing lBD-7, the safety significance of the failed open 1BD-11 was reduced from a volumetric flow rate standpoint; however, the unit remained in violation of TS 3.6.3.
On September 11, while operating at 100%
power, after further accident analysis review with 1BD-7 shut, the licensee decided to shutdown the unit and brought the plant to Hot Standby.
The next day.
majntenance technicians began repair activities on 1BD-ll.
On September 13, repairs were completed, the valve tested, and declared operable.
The licensee maintained its incorrect position on TS 3.6.3 through this entire event.
.The inspectors discussed the above scenario with plant management and informed them that allowing the plant to operate in Modes 1, 2, 3 or 4 from August 13, until September 13, with 1BD-ll stuck open, was a
violation of TS 3.6.3.
This failure to either isolate the affected blowdown line or shutdown the. unit in accordance with TS 3.6.3 is identified as a violation, Failure to comply with Containment Isolation Technical Specifica-tions, 50-400/87-34-0 d.
AFW Design Deficiency On September 15, the On-Site Nuclear Safety Review Group (ONS)
identified to site management a potential problem with the initial design of the auxiliary feedwater system.
After being notified, plant management met with design personnel representing CP8L, EBASCO, and Westinghouse.
During the meeting a review of the main feedwater line break analysis was performed.
The review revealed that plant design specified the same electrical d.c.
power supply ("B" electrical train battery) for the electrical circuit breaker control circuit for the "B" motor-driven auxiliary feedwater pump arid for the control power for the turbine-driven auxiliary feedwater pump.
An event which may cause loss of the "B" train d.c.
bus would produce a
limiting single failure where both the
"8" motor-driven and the turbine-driven auxiliary feedwater pumps could fail to operate.
This condition would result in only the "A" motor-driven auxiliary feedwater pump supplying feedwater for the proposed accident condition (loss of main feedwater with one faulted steam generator and two intact steam generators).
Westinghouse and EBASCO concluded that the previously-analyzed failures did not consider loss of the
"B" motor-driven and the turbine-driven auxiliary feedwater pumps at the same time.
Subsequently, management decided to shut the plant down and place it in Hot Shutdown unti 1 resolution could be achieved.
Implementation of a Plant Change Request (PCR) which improved system reliability was completed on September 24, and the plant commenced a
startup at this time.
Details of the PCR are discussed in paragraph 4.
One violation or was identified in the areas inspected.
4.
.On Site Plant Nuclear Safety Committee (40700)
During the week of September 20, the inspectors attended two special Plant Nuclear Safety Committee (PNSC) meetings concerning the status and content of Plant Change Request PCR-2292, "Auxiliary Feedwater Isolation Conflict Upon =Loss of "B" DC Bus".
The PCR was drafted to resolve design issues involving auxiliary feedwater (AFW) flow capabilities concurrent with a
loss of the
"B" DC bus, as discussed above (Paragraph 3).
During the first meeting, PNSC members reviewed documentation from the Westinghouse Engineering design group to ensure that all aspects of this problem were addressed concerning any potential unreviewed safety questions.
The PNSC voted unanimously to accept the Westinghouse resolution as a fix for the electrical design issue.
The inspectors attended a second speci'al PNSC meeting where a revision to PCR-2292 was discussed; the PNSC members voted to implement the revision.
The change to the PCR required altering the electrical control circuit for the
"B" auxiliary feedwater pump.
The implementation of the PCR will be evaluated by the inspectors during future inspection No violations or deviations were identified in the areas inspected.
5.
Monthly Surveillance Observation (61726)
The inspectors witnessed the licensee conducting maintenance surveillance test activities on safety-related systems and components to verify that the,licensee performed the activities in accordance with licensee requirements.
These observations included witnessing selected portions of each surveillance, review of the surveillance procedure to= ensure that administrative controls were in force, determining that approval was obtained prior to conducting the surveillance test and the individuals conducting the test were qualified in accordance with plant-approved procedures.
Other observations included ascertaining that test instrumentation used was calibrated, data collected was within the
. specified requirements of Technical Specifications, any identified discrepancies were properly noted, and the systems were correctly returned to service.
During this inspection period the inspectors reviewed and witnessed the performance of Operational Surveillance Test (OST)-1019,
"Reactor Coolant Pump(s) Operability Verification Weekly Interval Modes
and 4," Rev.
1.
The purpose of this OST was to verify that at least two of the reactor coolant pumps were in operation during Mode 3.
This was done by verifying that the individual reactor coolant pumps were running or had the correct breaker alignment and 'indicated power available, in accordance with Technical Specifications (TS) 4.4. 1.2. 1.
No deficiencies were identified during the witnessing of this surveillance.
b.
During one of the back shift tours the inspectors reviewed and witnessed operation personnel's performance of OST-1073,
"1B-SB Emergency Diesel Generator Test, Monthly Interval, Modes 1-2-3-4-5-6,"
Rev.
1.
This test was performed to meet the requirements of TS 4.8. 1. 1.2.a. 1, 4.8. 1. 1.2.a.2, 4.8. 1. 1.2. 1.a.3, 4.8.1.1.2.a.4, 4.8.1.1.2.a.5, 4.8.1.1.2.a.6, 4.8.1.1.2.b.l; the diesel generator portion of 4.8. 1.2, the inservice inspection requirements on 1B-SB diesel generator fuel oil pump and its discharge check valve as required by TS 4.0.5,
.FSAR commitments 7.3. 1-008 and 8.3. 1.-37, and the TDI Owners Group test requirements.
The inspectors did not identify any areas of concern during the performance of this test.
C.
The inspectors interviewed maintenance personnel and reviewed the test procedure. prior to the performance of Maintenance Surveillance Test MST-I0167,
"Excore Nuclear Instrumentation System Intermediate Range N35 Operational Test" and MST-I016XX, "Excore Nuclear Instru-mentation Intermediate Range N36 Operational Test".
These tests were performed to meet the physics test, start-up test and
month
surveillance requirements of TS 4.10.3.2, 4.10.4.2 and 4.3.1
~ 1 and fulfil1 s part of FSAR commitment 3.1.17-002 and 7.2.2-015.
The inspectors witnessed the installation of the test equipment used for test data acquisition and observed the test personnel during the conduct of the test.
No deficiencies were identified during the test performance.
d.
During the week of September 20, the inspectors witnessed portions of Operational Surveillance Test OST-1823, Rev.
2,
"1A-SA Emergency Diesel Generator 18 Month Operability Test,"
Modes 5 and 6.
The test was performed to meet Technical Specification requirements 4.8. F 1.2.f.2, 4.8. 1. 1.2.f.4 (a)
and (b), 4.8. 1; 1.2.f.6 (a), (b) and (c),
4.8.1.1.2.f.7, 4.8.1.1.2.f.8, 4.8.1.1.2.f.9, 4.8.1.1.2. f.10, 4.8.1.1.2.f.ll, 4.8.1.1.2.f.12, 4.3.2.2.10, and 4.8.1.1.2bl.
The inspectors verified that test prerequi sites were met, test precautions and limitations had been satisfactorily reviewed and completed, as necessary, test equipment used was calibrated, personnel performing the test were qualified in accordance with plant administrative controls, operation procedures for equipment operation were used in conjunction with this test, and proper approval was obtained prior to commencing the test.
During the test'performance the inspectors verified that the 1A-SA emergency diesel generator (EDG)
and its associated electrical control and power circuits met the listed tested criteria which included the following major items:
Ability of EDG 1A-SA to reject a load of greater than or equal to 1078 kW and maintain voltage at 6900, plus or minus 690 volts, and maintain frequency at 60, plus or minus 6.75 Hz.
Frequency will be stable within ten seconds at 60, plus or minus 1.2 Hz, without any loss or degradation of any safety-related loads.
Simulated loss of offsite power on the 1A-SA bus with load shedding, diesel automatic start and subsequent automatic load pickup via the sequencer.
Stable conditions of voltage and frequency must be maintained for at least five minutes.
Diesel generator. must be run for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at a load of 6800 to 7000 kM for the first two hours, and then a load of 6200 to 6400 kM for the remaining 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />.
Diesel generator'
ability to synchronize, transfer and return loads with offsite power source.
Diesel generator lockout features.
Load rejection without tripping or exceeding voltage limit The inspectors noted that operations personnel conducted the test in a professional manner and documented any items of concern during performance, of the test.
The test was successfully completed and signed off as satisfactory by operations management on September
'o violations or deviations were identified in the areas inspected.
6.
Monthly Maintenance Observation (62703, 62700, 37700)
The inspectors reviewed the licensee's maintenance activities during this.
inspection period to verify the following:
maintenance personnel were obtaining the appropriate tag out and clearance approvals prior to commencing work activi,ties, correct documentation was available for all requested parts and material prior to use, procedures were available and
. adequate for the work being conducted, maintenance personnel performing work activities were qualified to accomplish these tasks, no maintenance activities reviewed were violating any limiting conditions for operation during the specific evolutions, the required QA/QC reviews and QC hold points were implemented, post-maintenance testing activities were completed, and equipment was properly returned to service after the completion of work activities.
a.
The inspectors observed inservice inspection (ISI)
personnel collecting baseline readings
.on several secondary system piping pieces.
ISI personnel were using ultrasonic test equipment to measure the pipe wall thickness.
The measurements were taken at about every two inches on all of the pipe pieces'urface area.
The reading were recorded and evaluated and will be used by ISI personnel for future reference to determine effects of erosion/corrosion on secondary system piping.
Between September 15, and September 21, the ISI group took these piping wall thickness measurements on
selected secondary system piping spool pieces.
The ISI personnel utilized site procedure ISI-107, Rev.
0,
"SHNPP Erosion Corrosion Program for Steam Piping" for guidance.
This procedure was developed by the licensee as part of the ISI program for evaluating secondary piping system erosion corrosion control.
b.
The inspectors evaluated the implementation of two. of the Wor k Requests (WR) which authorized the repairs to those leaks identified by the licensee on August 31.
The first, WR/87-BBGIl, allowed repairs to stop a leak on safety injection valve ISI-101.
The leak was corrected by tightening the valve stem packing.
The second, WR/87-BBGM1, authorized technicians to stop a
leak which was emanating from a mechanical flange on the vent line for the reactor vessel head vent.
The leak was corrected by tightening the flange fasteners.'
The "B" main feedwater pump miniflow control valve 1FW-39 valve stem sheared off.
WR/87-BBJA1 authorized repairing the valve stem in accordance with a
special welding procedure.
The weld was satisfactorily completed; the valve was tested, and then was declared operational.
The licensee issued another Work Request, WR/87-BBJA3, to authorize the purchase of a replacement valve stem for 1FW-39.
No violations or deviations were identified in the areas inspected.
7.
Information Meeting (94600)
On September 8,
the Senior Resident Inspector and the Region II Reactor Projects Section Chief for Carolina Power and Light Co. facilities conducted an information meeting with a
committee representing the Triangle J
Council of Gove't nments.
The mission and functional organization of the NRC was described to the committee, as related to the construction, preoperation, start-up and operation of the 'Harris Plant.
Other subjects which were discussed included the daily activities of the resident inspectors, Technical Specifications, Licensee Event Reports, Systematic Assessment of Licensee Performance, and the recent emergency planning exercises for Harris.