IR 05000369/1981023
| ML20033D199 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 10/23/1981 |
| From: | Bryant J, Burke D, Graham M, Jape F, Myers D, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20033D190 | List: |
| References | |
| 50-369-81-23, 50-370-81-11, NUDOCS 8112070363 | |
| Download: ML20033D199 (15) | |
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- UNITifD STATES
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g NUCLEAR REGULATORY COMMISSION
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e REGION 11 o,
101 MARIETTA ST., N.W., SUITE 3100
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ATLANTA,3EORGIA 30303
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Report Nos. 50-369/81-23 and 50-370/81-11 Licensee: Duke Power Company
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422 South Church Street
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Charlotte, NC 28242
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Facility Name: ficGuire 1 and 2 i
Docket Nos. 50-369 and 50-370 License Nos. NPF-9 and CPPR-84 I
Inspection at Lake Norman, North Carolina Inspectors:
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M. J. Grahamu (/
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D. Burke U
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Date Signed Approved by:
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J fa'nt,'SectTo( A hief, Division of Resident
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d Reactor Projects Inspection SUMt1ARY Inspection on July 15. - September 15, 1981 Arec Inspected This routine announced inspection involved 360 resident inspector-hours on site in the areas of operations, maintenance, surveillance, startup testing,'and test program administration.
f Results
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Of the five areas inspected..no violations or. deviations were identified in three
. areas; four violations were found in two areas (Operations - failure to follow logging procedure. housekeeping and, FWST level not tripped; Startup testing -
highest worth control rod not trip tested).
8112070363 011
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DETAILS 1.
Persons Contacted Licensee Employees
- ll. D. McIntosh, Station Manager
- G. W. Cage, Operations Superintendent
- D. Rains, Maintenance Superintendent
- T. McConnel, Technical Services Superintendent
- R. J. Wilkinson, Superintendent of Administration
- 8. H. Hamilton, Performance Engineer
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D. Marquis, Reactor Engineer R. Tropasso, Reactor Engineer
- S. R. Frye, Operations Engineer
- D. Bradshaw, Operations Engineer
- M. D. Kinray,- Operations Engineer i
- G. D. Gilbert, Operations Engineer
- C. M. Fish. Contract Services
- K. F. Frye, Contract Services
- W. Sample, Projects and Licensing
- D. B. Lampke, Projects and Licensing
- D. Franks, Quality Assurance
- G. A.-Copp, Licensing, Corporate
- J. W. Leggette, Site Safety Review Group J. Molinda, Westinghouse Other licensee employees contacted included technicians, operators, mechanics, security force members, and office personnel.
- Attended exit interview
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Exit Interview The inspection scope and findings were summarized on August 21 and 28, and on September 2 and 15, 1981 with -those persons indicated in Paragraph 1 above.
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Licensee Action.on Previous Inspection Findings Not inspected.
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Unresolved Items
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Unresolved items 'were.not identified during this inspection.
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5.
Operational History At the beginning of the inspection interval, Unit 1 was in outage for inspection and repair of the "D" Reactor Coolant Pump primary seal. On July 20, 1981, heatup to criticality was initiated and precritical testing was performed.
On July 26, a body to bonnet leakage of the first Decay Heat Removal System isolation valve on the cold leg suction line forced another ou tage.
The reac vi coolant system was drained for repair of the isolation valve. On August 3, heatup to criticality was begun, and initial criti-cality was achieved on August 8.
Zero Power Physics Testing was performed frcm August 8 to August 19, followed by extensive testing of the auxiliary feedwater system as required by license condition (11). One unplanned reactor rip occurred on August 17 during the stuck rod test zero power testing due to a feedwater pump trip.
On August 24, while performing a special test on pump runout, a pressure transient in the turbine driven auxiliary feed water system damaged pressure instrumentation located at the inlet of the pump.
Following evaluation of the transient the equipment was repaired, including installation of relief valves in the suction lines of the pumps.
Testing of the auxiliary feed system was resumed and successfully completed.
Special natural circulation testing, as required by licensee condition (11) was performed from August 28 to August 31. This testing was interrupted by one inadvertent reactor trip due to test conditions on August 31.
On Septenber 8, following an outage to effect valve repairs, the licensee entered the power ascension program.
The turbine generator was tied into the grid for the first time on September 12, 1981.
On September 14, during performance of the loss of control room test, an unplanned safety injection was experienced. At the end of the inspection interval the unit was in outage for evaluaticn of the safety injection.
6.
Operational Safety Verification Throughout the inspection interval the inspectors observed operation in the control room and throughout the plant.
Control room and tagging logs were reviewed and the status of instrument calibration, equipment tags, and annunciators was verified.
Compliance with selected technical specification parameters was independently verified where possible during each mode of operation.
Inspection of certain Unit 1 systems was performed to verify operability, when required.
Equipment was inspected in the control room and in the field, and included the pressurizer power operated relief valves (PORV's),
the Emergency Diesel Generators (D/G's) and the Auxiliary Feedwater Systems.
The Auxiliary Feedwater System was found to be aligned per procedure. The D/G systems were operable as required; the discrepancies identified in paragraph A below are being corrected by the 1Mnsee. The D/G fuel oil day tank levels and auxiliary equipment met the TS 1equirements.
The inspector observed D/G B starting air pressure indicating a normal 230 psig on local instrument channel 81; however, 82 indicated some 250 psig, indicating that the channels and possibly the compressor control pressure switch require calibra tio.
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. Areas of inspector concern are discussed in the following paragraphs.
a..
Review of annunciated alarms in the-Unit 1 control room. During inspector followup on annunciated alams in the reactor control room on t
August 25, 1981, certain alarms were found not to be identified and.
explained in the reactor operator's (RO) logbook.
Diesel Generator.A Panel Trouble Alarm A-6 on Panel 1AD11 was annunciated but not do::umented as required by Station Directive 3.11.
This is a violation of Technical Specification 6.8.1.a which requires = implementation of the plantprocedures(369/81-23-01).
The. inspector questioned the operators and staff with regard 'to the reason for the annunciated ' alarm, and three different reasons for the alarm were given. The inspector examined the D/G A panel in the D/G room, and observed an annunciated D/G starting air pressure low alarm-on the panel. However, the starting air pressure indicated some 235 psig, and PS 5132 alarms at 210 psig and resets at 230 psig. - The
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licensee is checking the instrumentation alarm setpoints, since the alarm shauld not be annunciated.-
The building ventilation malfunction alarm on D/G A panel was tagged out with anrunciation power removed.
While in the A D/G room, the. inspector requested that the licensee test the reflash capability of the D/G A panel trouble alarm-in the control room, to assure that additiona' alarms on the panel which could affect D/G A operability would be annunciated in the control room and not blocked by the outstanding alarm. When tested, the alann did not reflash as designed; the licensee is investigating this= failure.
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On August 26,- the inspector reviewed Work Request (WR) 103341~which documented the D/G A starting air pressure low alarm malfuncation..
The WR was written on June 2,1981 with an expected completion date of 6/4/81; however, at the time of the ' inspection, no evidence of followup work on the WR.could be. found.
Similarly, WR 103919 written, ~ July _17, 1981, concerning the A D/G building ventilation malfunction alarm was still outstanding. The licensee stated. that these WR's will be expedited.-
Additional' control room alarms which were annunciated and.not fully -
addressed in the.R0 logbook included A-1.(ESS malfunction / breaker open)
on panel 1AD11 and C-3 (BIT recirculation flow low) on panel ~1AD9.-
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Housekeepi_ng
- On tours of theIUnit 1 Auxiliary Building,.the inspector. noted the
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presence of cigarette butts and trash in-a number of locations. The.
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. Auxiliary building as a whole is designated a cleanliness Level IV area-in 'accordance.with Station Direc+.ive 3.11.0.. As such,' smoking 'or the s
use of tobacco products-is prohibited and trash shall be collected and
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. removed. - However, the inspector. noted the follnwis.g on tours between '
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September 11 and 14.
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(1) Cigarette butts and paper in the pipe chase by column 45BB of electrical penetration room 702.
(2) Food wrappers and rags in the cable trays of battery room 701.
(3) A wooden bench, cleaning materials and rags in cable trays in cable spreading room 701.
This is a violation of 10 CFR 50, Appendix B and the accepted QA program section 17.2.5 as implemented by Station Directive 3.11.0 (50-369/81-23-02).
This is a repeat of violation 50-369/81-17-03 identified in June 1981.
Furthermore, the licensee's corrective actions to avoid a further violation appears to be questionable since
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l their written response, dated August 20, 1981, stated that the station had achieved full compliance. The licensee's response to the violation should address this aspect of the viJlation as well.
c.
SR0 in the Control Room On August 26, 1981, the SRO in the control room left the room which contains the control panels for a period of approximately 16 minutes to perform tasks in the shift supervisors' office. This was identified by
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the SR0 himself as an apparent violation of Station Directive 3.1.17
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and Technical Specification 6.2.2.b which requires in part that".... in modes 1, 2, 3 and 4, at least one licensed senior reactor operator shall be in the control room".
Station Directive 3.1.17 states "at the controls", the standard interpretation for the activities of the R0 in the control room. This interpretation had been extrapolateo to apply to the SR0 in the control room.
Past NRC interpretations of "SR0 in the control room" have included defining the control roan as the area around the controls, the entire i
roan, and the shif t supervisors office adjacent to the control area.
The definition was discussed with the licensee along with the possi-bility of applying a less stringent interpretation of the problem by the individual leaving the control room, and subsequent awareness of the problem by other licensed personnel, the inspector concluded that
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d.
Return to Criticality during test program During Zero Power Physics Testing'on August 14, 1981 some leaks developed in the pressurizerLlevel instrument tubing.
Repairs were canpleted with the reactor in Mode 3, and the system was returned to cri tical i ty. _ The procedure used in the startup was the controlling procedure for unit startup. Although this procedure includes.all of the necessary' checklists _ to cover the required surveillance items, the operators on duty started the procedure at the section which was consistent with reactor coolant system' operating conditions. The first part of the' procedure was ~ not executed, resultig in failure to meet several surveillances required by. Technical Specification.-
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On August 16, 1981, the reactor was restarted following a trip that was
L part of the Zero Power test program. This time the Reactor Trip l
Recovery procedu e was used for the startup. The Reactor Trip Recovery
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procedures did not include all surveillance requirements.
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f In both cases, the licensee failed to meet the surveillance require-ment.s of Technical Specification 4.3.1' 1 for functional testing of the
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Manual Reactor Trip, Intermediate Range, and source range instru-
mentation.
Further, throughout both startups the "B" train of control
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j room-ventilation was out of service. placing the unit in an action
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statement with respect to Technical Specifications. Therefore, modes
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were. changed in an action statement in violation of Technical Speci-fication 3.0.4.
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The failure to comply with the specifications above was apparently
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caused by' failure of the operators to recognize that they were changing
modes, wii.h all associated requirements, even though work was being" performed under the direction of the Zero Power Test Coordinator. The licensee. identified the-problem and discussed the issue with all
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operator crews.
Inspector; discussions with operators indicate that the
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operators are :now more aware of their ' role during testing.
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addition, the ructor trip recovery procedure was changed to include
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.all applicable surveillance items. The inspector concluded that
adequate corrective action has been taken to preclude recurrence' of the
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licensee identified violations. This closes -LERs R0-369/81-127 and
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-R0-369/81-128.
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FWST Level Indication Not Tripped l
On August 10, 1981, operators noted that channel 1 of the -FWST-level indication was performing erratically. The channel was declared =
inoperable, placing-the unit on an action statement with respect to -
Technical specification 3.3.2,'which requires the. channel to be tripped
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within one hour of being declared inoperable.-
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The electrical. technicians on duty were unfamiliar with the' system,. and were unable to find ' appropriate drawings or procedures to trip the
channel within one hour.
The operators began shutting.down the unit in
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accordance with the Technical Specification:3.0.3.cThis specification
[f required the-unit 'to be.placed:in hot standby within one hour when the 1imits of the. action, statement were exceeded.- Failure to. trip the I
affected FWST level channel' is indicative.of the technicians' lack of
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Technical Specification' 6.3 requires that cach member of the l unit-staff
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<shall meet or exceed the minimum qualifications of ANSI N18.1-1971 for-E comparable positions.. ~Section 4.1 of ANSI 18.1-1971; requires plent^
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- personnel to have a combination of; education, experience, 'and skills -
commensurate' with their level _ of responsibility to provide: reasonable 2 cassurance that actions during' all inormal.and abnormal conditions will-
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be such that the plant is: operated in a safe and efficient manner.
- Hence, Lthis. constitutes' a violation (50-369/81-23-03);.
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The license 2 took short term carrective action by placing the channel in the tripped condition within one additional hour.
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corrective action planned includes a series of procedures available for all LCO's requiring direct action after equipment failures.
This corrective action had not been completed at the end of the inspection interval.
The licensee reported this item as LER R0-369/81-126.
f.
Trip During Zero Power Testing
On August 17, 1931, while performing Zero Power Physics Testing, a series of equipment failures resulted in a transient in the primary system requiring manual reactor trip. The operators were in the process of swapping the position of Shutdown Banks A and B and the highest worth control rod to perform the stuck rod test. A turbine driven feed water pump +. ripped, resulting in intiation of auxiliary feed. The auxiliary feed flow caused a cool down of about 10 F of the primary coolant. Special Test Exception 3.10.1 limited the amount of
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rod insertion while remaining critical.
Emergency boration was I
initiated by the operators. The rods were pulled to maintain criticality until a urgent failure of the control rod drive position indication occurred, blocking movement. As criticality and power level could not be readily adjusted using boron alone, the operators tripped the reactor.
The cause of the feedwater pump trip was apparently a steam flow perturbation. The cause of the rod position indication failure was apparently the use of fuses which failed at elevated temperatures. Use and reuse of the rod drives caused the fuses to fail.
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replaced the fuses and returned the unit to criticality without incident.
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Pressurizer Level Instrumentation
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On August 14, 1981, a leak developed in the reference leg of the I
Channel 3 pressurizer level detector.
In order to repair the leak, it was necessary to isolate the detector, thereby disabling two channels of Pressurizer Pressure whose detectors share a common sensing line with the level detector. Two of the four inputs to the solid state.
protection system were therefore inoperable.
It was necessary to go to Mode 3 (hot standby) and drop below P-11 (1955 psi) to permit blockage
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l of the pressurizer pressure' safety injection signal.
The instrument line was repaired, the instrumentation calibrated and returned to service.
This closes LER R0-369/81-140.
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Severe Weather
.On July 16, 1981 a _ waterspout was seen in the Lake'Normam area. The inspector verified that AP/0/A/5500/29 Natural Disaster was implemented-as required.
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7.
Initial Criticality The inspector cbserved portions of the unit startup test and TP/1/A/6100/01 Initial Criticailty, leading up to the achievment of initial criticality on August 8.
The operational activities of the performance engineers and operations crw were observed, and selected Technical Specifications were verified.
The inspector identit?ed no concerns beyond those addressed by regional based specialist inspectors in Inspection Report 50-369/81-24.
8.
Zero Power Physics Testing Zero power testing was run at ficGuire from August 8 through August 19, 1981.
Significant delay was caused by incompatibility between the in-core instrumentation output and the licensee's computer for the calculation of flux aaps. After prograiming and software changes were completed, testing
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proceeded more smoothly. The inspector observed portions of all zero power
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physics testing activities at one or more configurations:
flux mapping, determination of moderator temperature coefficient, rod worth measurement, boron endpoint determination, stuck rod, and ejected rod tests.
One apparent violation was identified in this area.
TP/1/A/2150/10, Stuck Rod Worth !!easurement, was performed on August 17, 1981.
In order to conduct this test, Special Test Exception 3.10.1 of the Technical Specifi-cation must be applied. This exception states, "The shutdown margin requirement... may be suspended for measurement of control rod worth...
provided reactivity equivalent to at least the highest estimated control rod worth is available for trip insertion from operable control rods". The associated surveillance requirement, T.S. 4.10.1.2, further describes the surveillance required to verify operability of control rods as follows:
"Each full length rod not fully inserted shall be demonstrated capable of full insertion when tripped...within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to reducing the shutdown margin to less than the limits."
On August 17, the test was performed with Shutdown Bank A mostly inserted, all other banks fully inserted, and rod F-10 fully out. Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of beginning the test, the reactor had been tripped, per procedure, to verify
, operability of control rods prior to suspending the shutdown margin.
However, F-10 was not tested at that time. Therefore, the licensee was in apparent noncompliance with TS 4.10.1.2.
(Violation 50-369/81-23-04).
The inspector noted that this omission in testing was apparently due to a misinterpretation of the Technical Specification rather than ignorance of its existence.
Further, while the reactor was in the test configuration, a perturbation on the secondary side caused a. feed pump to trip, resulting in conditions leading to a manual reactor trip. At that time F-10 was tripped, and inserted completely into the core.
When the test was repeated, the licensee amended the test procedure so that F-10 was tested to comply with 4.10.1.2.
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Natural Circulation Testing The inspector observed portions of the natural circulation special testing on all shifts to verify compliance with license conditions, the program described in the SER, and response to the Tiil Action items. The following tests were observed and found to be perfomed satisfactorily and the completed test packages were reviewed.
TP/1/A/2150/20A Natural Circulation Verification TP/1/A/2150/208 Natural Circulation Verification TP/1/A/2150/20C Natural Circulation Verification TP/1/A/2150/21 Effect of S/G Isolation on f!atural Circulation TP/1/A/2150/23 Natural Circulation with Simulated Loss of Offsite Power The inspector noted that all shifts observed each portion of TP/1/A/2150/20 as required by the licensee's commitments.
License condition (11) dated (b)
is closed.
Natural circulation testing proceeded as anticipated with one exceptien.
During performance of TP/1/A/2150/21, Effect of S/G Isolation on Natural Circulation, while isolation, the reactor tripped.
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caused by inadequate equalization of pressure across the loop's t1SIV prior to returning the steam line to service. The high steam line differential pressure resulted in a safety injection signal which produced a reactor trip. No safety injection occurred as the safety injection is disabled througout natural circulation testing. TP/1/A/2150/21 was repeated later in the day without incidence. The inspector noted that the ENS network was used per 10 CFR 50.72 on the trip.
The inspector had no further questions in this area.
10. Unit 1 Startup Testing The inspectors witnessed portions of the following power escalation testing on all shifts and reviewed the test results and evaluations. The perfor-mance of each test was evaluated against the requirements of ANSI N18.7-1972 Section 6.0, " Test and Inspection Procedures," ANSI N45.2-1971, Section 12,
" Test Control", FSAR Chapter 14 and Regulatory Guides 1.6,1.9 and 4.1.
Findings are noted below. The inspector also observed that additional testing beyond the scope of the procedures was performed for troubleshooting of the systems. These test were as follows:
TP/2600/12 Steam Dump. Test 5% - Satisfactory TP/4250/04C Turbine Overspeed Trip - Electrical overspeed trip is being reset to higher than the mechanical overspeed trip TP/2600/13 Steam Generator Level Control Test 10% - Satisfactory TP/2650/03 Loss of Control Room - Control of the auxiliary feed water flow Was not satisfactory frur the auxiliary shutdown panel which resulted in an excessive cooldown rate and subsequent safety
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injection.
Re-test was required and performed on September 17.
This test will be addressed in detail in subsequent reports.
11.
Security Event On July 31, 1981, the inspector responded to a licensee identified security event.
This event and inspector actions are discussed in Inspection Report.
50-369/81-26.
12. Auxiliary Feed Pump Testing Licensee Condition (11) dated (e) requires supplemental testing of the auxiliary feed water system. This testing, TP/1/A/2000/01 Auxiliary Feed System Functional Test II, was completed August 28, 1981. The inspector observed portions of the testing in progress, and reviewed the completed test package. No violations were identified. The license condition is closed.
In the course of the testing of the turbine driven auxiliary feed pump, the -
suction piping was overpressurized on August 25, 1981.
Following auxiliary feedwater (CA) flow and balance testing in accordance with procedure TP/1/A/2000/01, the TD (turbine driven) AFW pump was secured from full flow conditions (recirculation valve closed) by turning the pump off. Due to an apparent slow closure of the pump discharge check valves (2 in series),
steam generator pressure of approximately 1050 psig momentarily fed back through the TD pump to its suction piping which was designed for 135 psig.
The overpressurization blew out instrumentation lines and equipment and the gaskets of a gate valve in the pump suction line, to relieve the pressure which was estimated to have reached scme 600 psig in the line.
The instrument lines were repaired and the valve gaskets and bolts were replaced; instrumentation was replaced as necessary and recalibrated. The piping and valves were visually examined from the pump to the suction check valve (ICA8) which isolated the overpressure from the motor driven AFW pump suction lines. To prevent recurrence, the licensee installed a 3/4 inch Dresser relief valve (135 psig setpoint) on each of the three suction lines to the AFW pumps. The relief valves were similar in size and weight to the high point manual vent valves (ICA-167,168, and 128) which were removed to install the relief valves.
The suction line was also inspected, with nomal'
operating pressure on the system, following repairs; no leaks were ooserved.
Since this appeared to be the first time the TD AFW pump was secured from'
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full flow conditions with the recirculation valve closed, the licensee. is reviewing plant procedures to assure that the recirculation valve is verified open during low flow conditions before the pumps are secured.
In addition to the above, the inspectors stated that the following items will be reviewed by the NRC to assure operability of the AFW systems:
1.
Satisfactory completion of the AFW pump performance tests (PT's). This item has been ' completed on all three pump l
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Satisfactory stroke testing of the CA valves in the TD AFW pump suction line, including the motor operated valves (MOV's) to the Nuclear Service Water System (e.g.-1CA116, etc.).
This item has also been completed with the performance of PT/1/A/4252/08.
3.
Perform AFW pump shutdown test with recirculation valve closed to
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assure corrective actions were adequate to prevent recurrence. This also verifies that the discharge check valves are functioning properly.
This test, TT/1/A/9100/37, CA Overpressure Test, was performed on August 28 and no back pressures were noted; the relief valve on the suction line did not have to open.
The inspector observed the test in progress.
4.
Examine the discharge check valves during the next convenient outage to
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assure that the valves are not degrading or binding.
The suction check valve (ICA8) will also be inspected to verify that the overpressuri-zation did not damage the disc or internal components.
Examination of the check valves will be an open item (369/81-23-05).
5.
Review and evaluation of the removal of tha high point vent valves (ICA-167,168,128) on the AFW pump suctbn lines.
If venting is required, procedures should specify venting methods (e.g. - loosen or remove relief valve).
Pending closure of the above identified -inspector followup item, LER R0-369/81-136 is closed.
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13. License Conditions The inspector verified completion of all conditions of the licGuire license required for operation above 1% and 5% power.
a.
License Concition (11)
NUREG 0737 dated requirement (a) Westinghouse letters were verified by the inspector to document review of-power ascension procedures.
(Closed). This also closes TMI Action Item 80-RD-10.
b.
Dated requirement (b)
Natural circulation tests were performed.
Inspector review is discussed in paragraph 9.
(Closed).
c.
Dated requirement (e)
Auxiliary feedwater pump evaluation was performed.
Inspector review is discussed in paragraph 12.
(Closed). This also closes TMI Action-Item
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80-RD-17..
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d.
Dated requirement (f(2))
The full range in-core thermocouple backup display was observed by the inspector to be installed and operable.
(Closed).
This also closes TMI Action Item.
e.
Dated requirement (1)
The inspector reviewed the procedures for use of the head vents and verified that changes had been made to the standard shutdown procedure to vent the primary system through the head vents. This provides an ongoing test program.
(Closed).
f.
Dated requirement (e)(1)
The anticipatory reactor trip modification package was reviewed by the inspector.
(Closed).
g.
Dated requirement (n(3)
The emergency plan implementing) procedure changes were verified complete and adequate.
(Closed.
14. Maintenance Selected maintenance activities were reviewed in depth to verify that work was performed according to procedure, by qualified personnel, and that modifications made were done following appropriate. design review. The following maintenance activities were reviewed:
a.
NC Pump "D" inspection and reassembly.
No damage to the seals was identified by either the licensee or the vendor. New seals were used to reassemble the pump; however, the problem of seals cocking during starting and stopping persists. The performance of NCP "D" continues to be evaluated by the licensee.
b.
ND-1 repair and design modification.
' After two outages due to body-to-bonnet leakage of ND-1, the first isolation valve on the Decay Heat suction line from the cold leg, a modification was made to the valve body. A groove was cut 'into the seating surface to permit the eventual _ addition of Furmanite should the valve leak again.
The design change was reviewed, and the inspector
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noted that further design modification packages will 'be required at the addition of the Fumanite.
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YC-88' repair d.
NV-484 repair and modification. Modifications similar to those on ND-1~
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e.
NV-220 inspection and repair.
On August 12, 1981, maintenance personnel broke the flange on NV-220, the discharge relief valve for the PD charging pump. The valve had not
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been adequately isolated from its normal discharge volume, the VCT, resulting in a primary coolant direct path to the auxiliary building floor drain. Some drainage from the line was expected, and maintenance personnel failed to identify that the drainage was in excess of anticipated. The leak from the primary system was within the capacity of automatic make-up so approximately three hours elapsed before the operators noted that unidentified leakage was in excess of the.1 gpm allowable under Technical Specification 3.4.7.2.
This noncompliance was identified by the licensee in LER R0-369/81-139.
l The licensee's corrective action to this item was to caution both operations and maintenance personnel.on the implications of draining systems during operation.
The inspector f. s noted that future work on
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s.ystems interfacing with the reactor coop.nt se, tem would better be controlled by the health physics organizatV6n. At the time sof this-event, no radiation was present in the primary system.
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The following work requests were reviewed and the activities observed.
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Equipment
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194771 UHI valves 104508 RN-89 repair
105116 RN-190 repair 104716 CA-32 Troubleshooting 15. Surveillance Testing The surveillance tests detailed below were analyzed and/or witnessed by tne'.
inspector to ascertain procedural and performance adequacy.-
The completed test procedures examined were analyzed for embodiment of the necessary test prerequistes, preparations, instruction, acceptance criteria and sufficiency of technical content..
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The selected tests ' witnessed were examined to ascertain that current, written approved procedures were available and.in use, that test-equipment in use was calibrated. that test ' prerequisites were met, system restoration.
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was completed and test. results were adequate.
The selected procedures perused attested conformance with applicable
. Technical Specifications, they appeared.to have received the required
- administrative review and they apparently were performed within.the '
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surveillance frequency prescribed.
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Procedure TITLE Date PT-1-A4250-06 CA Valve Verification 7/21/81 PT-1-A4242-01 TDAFDUP#1 Performance Test 8/10/81 PT-1-A4252-01A MDEFWP Performance Test 7/21/o1 1P-0-A3030-05 Containment Spray Pressure 9/2/81 Calibration IP-0-A-3007-04 NI IR OP Calibration 9/3/81 Pressurizer Level Channel Calibration Turbine Trip / Reactor Trip PT/1/A/4206/01B N1 Pump 1B Performance Test The inspector employed one or more of the following acceptance criteria for evaluating the above items:
10 CFR 50 ANSI N18.7 McGuire Station Directives Duke Administrative Policy Manual Certain Performance Test (PT) completed packages were reviewed to verify steam operability in accordance with the Technical Specifications over a period of plant history. PT's reviewed included completed PT/a/A/4252/01, PT/1/A/4252/01A, and PT/1/A/425201B for the Auxiliary Feedwater (AFW)
Systems. The motor driven AFW pump tests (01A arid 01B) were performed monthly as required by TS 4.7.1.2; however, the inspector noted that Section 12.2 of the PT's, which verifies valve positions, was often not cmpleted.
The verification is performed by PT/1/A/4700/10, Shift Turnover Vt.rifi-cation, which verifies the PT Section 12.2 valve positions every shift The inspector had no further questions.
The inspector also noted that PT/1/A/4252/01 for the turbine driven (TD) AFW pumps is performed at some 1500 psig (discharge pressure), resulting in 845 gpm flow.
TS 4.7.1.2.2 states that the TD AFW pump shall be demonstrated operable by developing a discharge pressure greater than or equal to 1210 psig at a flow greater than or equal to 900 gpm when the steam pressure is greater than 900 psig. The licensee will review PT/1/A/4252/01 and the TD AFW piping to detemine if 900 gpm can be achieved during pump testing. The pump head curve and IWP requirements are verified by performance of PT/1/A/4252/01.
The licensee identified the following surveillances as having been omitted during the inspection interval:
Suction pressure instrumentation on the auxiliary feedwater system turbine driven pump and the radiation detector E!!F-36 test.
These violations were identified in LERs R0-3G9/135 and R0-369/104.
Corrective action was imediate for the specific cases, and the licensee completed a review of all TS surveillance requirements for instrumentation to verify coverage in the periodic test program. These LERs are close.-
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Within the areas inspected, no violations or deviations were identified.
16. Test Program Administration The licensee's program for conducting the power escalation test program was reviewed.
Discussions were held with personnel responsible for admini-stration of the testing program.
In general, the program was found to agree with that ' described in chapter 14 of the FSAR.
During the inspection period, testing was ongoing.
Discussions with licensed operators and supervisors indicated that they are aware of the test conditions and knowledgeable of their rcle in performing the tests.
During the di cussions, licensee management outlined a program that has been instituted to reduce the number of persannel errors and to reduce the problems experienced durv3 the transition from nonlicensed to licensed opera tion. The program ir.Juded the following actions:
a.
Management meetings with all grsonnel regarding compliance with regulations.
b.
An additional operations engineer was assigned shift coverage to assist the normal crew.
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Copies of all event reports are provided line management for their use and communication to employees.
d.
Experienced supervisors from the Oconee Nuclear Station have been temporarily assigned shift ccverage at 11cGuire to assist and observe operations.
e.
A trend analysis program is being conducted of events and incidents.
Results of the program could not be determined since it has been in effect for about one month.
liithin the areas inspected, no violations or deviations were identified.
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