IR 05000369/1986028

Insp Repts 50-369/86-28 & 50-370/86-28 on 860821-0921. Violation Noted:Failure to Meet 10CFR50.72 Reporting Requirements & Failure to Maintain Unit 1 Pressurizer Code Safety Valve Operability Per Tech Spec 3.4.22

ML20211J372
Person / Time
Site:	Mcguire, McGuire
Issue date:	11/03/1986
From:	Guenther S, William Orders, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20211J270	List: IR 05000369/1986028 ML20211J265 ML20211J296
References
50-369-86-28, 50-370-86-28, NUDOCS 8611110117
Download: ML20211J372 (11)

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/ *o NUCLEAR REGULATORY COMMISSION

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Report Nos.:- 50-369/86-28 and 50-370/86-28 Licensee: Duke Power Company 422 South Church Street Charlotte, NC 28242 Facility Name: McGuire Nuclear Station Docket Nos.: 50-369 and 50-370 License Nos.: NPF-9 and NPF-17 Inspection Conducted: August 21 - September 20, 1986 Inspectors: / I W. T. Orders, Resident Ingector Dats Signed h

S.F.'Guenther,AccompanfingPersonnel l YO D'ats Signed Approved by: //[J[/8 T. A. 'Peebles, Section Ct/Jef Date Signed Division of Reactor ProjActs Sumary Scope: This routine unannounced inspection was conducted on site in the areas of operations, surveillance testing, maintenance activities, and event follow-u Results: Three violations were identified: Failure to meet 10 CFR 50.72 reporting requirements (two examples); Failure to maintain -Unit 1 Pressurizer Code Safety Valve operability per Technical Specification 3.4.2.2, and failure to perform required surveillance testing (two examples).

8611110117 861105 PDR ADOCK0500g9 G

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REPORT DETAILS Persons Contacted Licensee Employees

• T. McConnell, Plant Manager

• B. Travis, Superintendent of Operations D. Rains, Superintendent of Maintenance

• B. Hamilton, Superintendent of Technical Services L. Weaver, Superintendent of Administration

• M. Sample, Superintendent of Integrated Scheduling N. McCraw, Compliance Engineer

• N. Atherton, Licensing and Compliance Other licensee employees contacted included construction craftsmen, technicians, operators, mechanics, security force members, and office personne * Attended exit intervie . Exit Interview The inspection scope and findings were summarized on September 26, 1986, with those persons indicated in paragraph 1 above. The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspectors during this inspectio Three violations were identified: failure to report (369,370/86-28-01)

paragraphs 4 and 7b; inoperable Unit 1 safety valve (369/86-28-06)

paragraph 7b; and surveillance not performed (369,370/86-28-01) paragraph Three unresolved items were discussed: blocking of safety functions (369/86-28-07) paragraph 7b; component cooling water system operation (369/86-28-03) paragraph 7a; and testing not performed (369,370/86-28-09)

paragraph 7 Three inspector followup items were discussed: solenoid failure

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370/86-28-02) paragraph 4; testing of safety valve technique 369,370/86-28-04) paragraph 7b; Unit 2 Safety valve as-found verification 370/86-28-05) paragraph 7b; hydrogen ignition problems (369,370/86-28-08)

paragraph 7 . Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable or nay involve violations or deviations. Three new unresolved items were identified during this inspection period; they are. discussed in paragraph . .

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2 Plant Operations The inspector reviewed plant operations during the report period to verify conformance with applicable regulatory requirements. Control room logs, Shift Supervisors logs, shift turnover records and equipment removal and restoration records were routinely perused. Interviews were conducted with plant operations, maintenance, chemistry, health physics, and performance personne Activities within the control room were monitored during shifts and at shift changes. Actions and/or activities observed were conducted as prescribed in applicable station administrative directive The complement of licensed personnel on each shift met or exceeded the minimum required by Technical Specifications (TS).

Plant tours taken during the reporting period included but were not limited to the turbine buildings, auxiliary building, Units 1 and 2 electrical equipment rooms, Units 1 and 2 cable spreading rooms, and the station yard zone inside the protected are During the plant t!ours , ongoing activities, housekeeping, security, equipment status and radiation control practices were observe Unit 1 Operations Unit 1 began this reporting period in the final. stages of a refueling outag The. unit entered Mode 3 (hot shutdown) on August 31, but had to return to Mode 5 (cold shutdown) on September 2, when a pressurizer code safety valve (INC-1) lifted prematurely'during a reactor coolant system leak test. This incident is discussed in detail elsewhere in this repor INC-1 was replaced and the unit was again heated to Mode 3 on September 6 and taken critical on September The reactor had to 'be shutdown on September 8 when an intermediate range nuclear instrument (NI-36) failed to respond to increased neutron flux levels. Critical operation and zero power physics testing were resumed on September 9, but were interrupted again on September 11, when both trains of the hydrogen mitigation system were found to be inoperable. The details of this incident are also discussed elsewhere in this repor Physics testing was completed on September 13 and the unit was placed on the line on September 14. The unit had reached 50 percent power on September 16, when a condenser tube failure forced a reduction in power to about 10 percent while repairs were made. The details surrounding this event, including the effects on secondary chemistry and an associated contaminated liquid waste discharge to a conventional waste holding pond, are discussed elsewhere in this repor Unit 1 achieved full power operation on September 18 and remained there for the remainder of the reporting perio . . . .. . . - .- - . - .- - - .- -.

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i b it 2 Operations

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-Unit .2 began the reporting period at 100 percent power, and continued at full- power until August 27,. when a. feedwater containment isolation valve

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(2CF-26) failed closed. The operators were unable to reopen the valve or restore feedwater flow to the. "D" steam generator and, therefore, manually tripped the reactor prior to reaching the automatic . trip setpoint on low-steam generator water level.- The reactor trip induced a shrink in steam L generator water level which~ prompted ths operators to manually start the

turbine-driven and a motor-driven auxiliary feedwater (CA) pump; the second CA pump started automatically on low level in the "D" steam generator. The I

required four-hour NRC notification of the reactor protection system

. actuation was made pursuant to 10 CFR 50.72; .however, the inspector

' determined from the NRC Operations Center that no notification of the engineered safety feature actuation (i.e., CA) had been made. The; inspector

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informed : the Shift Supervisor, prior to expiration of the four-hour interval, that the CA actuation was reportable,~ but the licensee failed to make the required report within the allowed time perio This is a violation of 10 CFR 50.72 (369, 370/86-28-01).

' The solenoid valve which had failed and caused 2CF-26 to close was replaced and the unit was -returned to service. the next day. -When attempting to transfer. from the upper to the lower feedwater nozzle during the power -

escalation, '2CF-26 failed to open on demand and the same solenoid valve was found to have failed again. The repeated failure of_the same solenoid valve is .being investigated by the inspector and will be tracked as an Inspector Follow-up Item (IFI) 370/86-28-02. The faulty solenoid was replaced and the

~ unit proceeded to 100 percent power where it remained for the balance of the reporting perio . Surveillance Testing Routine su'rveillance activities were analyzed and/or witnessed by the

~ inspector to verify procedural and performance adequacy and conformance with applicable Technical Specifications. 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 completed and test results were adequat Apparent inadequacies associated with safety-related surveillance activities were detected during this report period. Details are delineated elsewhere in this repor . Maintenance Observations Routine maintenance activities were reviewed or witnessed by the' resident inspector to ascertain procedural and performance adequacy and conformance with applicable Technical Specifications. The selected activities witnessed were examined to ascertain that, where applicable, current written approved

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procedures were available and in use, that prerequisites were met, equipment restoration completed and maintenance results were adequat . Event Follevup Component Cooling System Water Hammer On August 31, 1986, Unit I was in Mode 4 (Hot Shutdown) with the "B" residual heat removal (ND) train in service to maintain reactor coolant system temperature. An auxiliary shutdown panel control verification test was being performed which required a swap from the "B" to the "A" ND train. Enclosure 4.5 of OP/1/A/6200/04, " Residual Heat Removal",

directs the operations necessary to effect that swap and begins by instructing the operator to establish 2000 to 5000 gallons per minute of component cooling water (KC) flow through the ND heat exchanger by-slowly throttling open valve 1KC-56A. A note immediately preceding that action step instructs the operator to ensure that adequate KC flow is established to prevent flashing and water hammer of the KC lines when ND flow is establishe Operations Management Procedure 1-2, "Use of Procedures", provides general statements of philosophy which state that individuals using procedures should assure that they understand what is to be done and the anticipated results prior to performing a ste Furthermore, if the desired or anticipated results are not achieved, the individual should not procee The KC system lineup had been altered prior to August 31, such that opening valve 1KC-56A would not, in and of itself, establish KC flow through the ND heat exchanger. The operator initiated ND flow through the heat exchanger, with no KC flow, thereby inducing a series of water hammers and causing approximately 500 gallons of water to overflow the KC surge tank. This incident remains under investigation and will be carried as an Unresolved Item (369/86-28-03). The affected portions of the KC and ND systems were subsequently inspected to verify that no damage had occurred as a result of the water hammer Pressurizer Code Safety Valve Failure Unit 1 entered Mode 3 at 9:18 p.m. on August 31, 1986, in preparation While conducting the reactor coolant tor a p(ost-refueling startup.NC) leak test procedure (PT/1/A/4150/001A) at 1:05 system September 2, INC1, one of three pressurizer safety valves, lifted prematurely at about 2370 psi and rapidly decreased NC system pressure to approximately 1800 psi prior to reseatin NC system pressure j stabilized after INC-1 seated, and a plant cooldown to Mode 5 was commenced shortly thereafter to establish conditions necessary for

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replacement of the defective safety valve.

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This incident raised two major concerns regarding (1) the operability of the remaining safety valves installed on both Units 1 and 2 (Unit 2 was operating in Mode 1 at the time), and (2) the control room operator actions which were taken during the event. Both these concerns are discussed belo The pressurizer safety valves were manufactured by the Crosby Valve and Gage Company (Style HB-BP) and were required to lift at 2485 psi +/-

1%, and to reseat after decreasing pressure (blowdown) by between 5 and 10% below the relief setpoin Both the lifting pressure and th blowdown setpoints exhibited by INC-1 during this event were outside their allowable bands. The lifting pressure setpoint is adjusted by means of an adjusting bolt and locknut and the blowdown is adjusted by means of an adjusting rin The licensee reviewed the equipment history for INC-1 and determined that the valve had last been maintained, reassembled, adjusted and tested during the Unit I refueling outage in 198 At that time the valve lifted at successively decreasing pressures (2500, 2461 and 2430 psi) which, when averaged, satisfied the 2485 psi +/- 1% acceptance criteria. The documentation also indicated that the blowdown adjusting ring had been reset to the notch position stamped on the valve bonne The amount of valve blowdown is not routinely teste The licensee bench tested valve INC-1 after removing it from the system and found that it lifted consistently at about 2320 ps This additional data, when evaluated in light of the , valve's previous lifting points during preinstallation testing and on Saptember 2nd, indicated a definite decreasing trend during successive valve cycle The licensee concluded that INC-1 had been installed in the system prior to finding its stable setpoint and indicated that the valve

testing procedure would be revised to' incorporate a check for any trend l in the lifting pressure setpoint (IFI' .369, 370/86-28-04). The l- equipment histories for the other Unit 1 and 2 safety valves were i reviewed, and no trend was evident in the lifting setpoints for those I valve ,

The licensee also disassembled 1NC-l' ' nd' foudd that its blowdown i adjusting ring had been incorrectly set to 134 notches beyond its specified setpoint, thereby explaining the' ~ excessive bloQdown experienced on September 2nd. All the safety valves installed on Unit l 1 were physically inspected to verify that their blowdown adjusting l rings were correctly set. The blowdown ring on one other valve (INCn2)

l was _ found at 66 notches beyond its required setpoint and was promptly t

corrected. Both INC-1 and INC-2 had been adjusted by the same "

individual during the previous refueling ' outag The. equipment histories for the Unit 2 safety valves revealed that two of-the valves

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had been adjusted by the manufacturer's representativo andethe third by a licensee employe Both individuals felt confident-tnat the

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adjustments had been made correctly; neither individual had been-involved with the incorrectly adjusted valves on Unit ' The~ licensee

- felt' confident that all three Unit 2 valves were operable and that continued power operation was justified, however, it is planned that the blowdown. adjustment ring settings will be verified at the next availableopportunity(IFI 370/86-28-05).

In summary, it must be concluded that valve INC-1 was inoperable from the 1985 refueling outage until it was removed from the system on September 4,1986. This is a violation of Technical Specification 3.4.2.2 (369/86-28-06).

The second NRC concern regarding this incident involved the operator actions ta_ ken to block the low pressurizer pressure safety injection signal during the rapid depressurization transient. Under normal circumstances, without operator action, a decrease in pressurizer pressurs below 1845 psi would be indicative of a loss of coolant accident (LOCA) and would result in an engineered safeguard features (ESF) actuation / safety injection (SI). This ESF signal can be manually blocked by the operator to allow normal cooldown and depressurization of the reactor coolant system after pressure is decreased below 1955 psi. The Controlling Procedure for Unit Shutdown (0P/1/A/6100/002) is the only procedure which authorizes the low pressurizer pressure SI signal to be blocked; a unit shutdown was not in progress at the time of this inciden Discussions with the control room operators indicated that during the transient control room annunciators alerted them that a safety valve was open and led them to believe that an NC system pipe rupture had not occurred. One of the control room operators' primary concerns during

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the incident was the safety of Operations and Health Physics personnel

! who, as part of the test in progress, were conducting NC system leakage i inspections inside containment. The only egress path from containment l led directly past the pressurizer relief tank (PRT), which accepts and condenses the discharged steam from- any open safety valv If PRT pressure had increased to 100 psi the rupture disc would have burst allowing the INC-1 discharge to escape directly to the containment atmosphere jeopardizing the safety of the personnel in containment and possibly blocking thei.r exit pat The operators evaluated the available parameters, including pressurizer i pressure, pressurizer level, safety valve annunciators, subcooling margin, and decay heat load / power history, and decided that the safety of personnel inside containment was best served by blocking the low pressurizer pressure SI signal. The operators indicated that they were l unsure how an SI initiation would affect the length of time remaining

prior to PRT rupture disc failure and that ample subcooling margin l existed to allow subsequent manual SI initiation if INC-1 had not I reseated prior to reaching saturation pressure at approximately 1200 psi.

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Discussions with licensee management indicated that Duke Power Company's general policy, which had been made known to the operators during their training program, was not to block any safety funct1on ( ', trom automatically initiatin However, pursuant to 10 CFR 50.54(X)

under emergency conditions; the . Shift Supervisor is authorized to

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deviat'e from an ' established ' procedure if deemed necessary to protect health'and safety. The licensee defended and supported the operators'

s actions during the event, but conceded, after evaluating the transient, that blocking the SI signal did not enhance the safety of the personnel T

A inside containment. They concluded if INC-1 had blown for one more

-minute, the PRT ruptufe disc would have burst and caused a high containment pressure SI signal and that the rupture disc would not'have burst any sooner even it SI had initiated on low pressurizer pressur The licensee'" indicated that the incident would be discussed with all

? the operators and that the general policy of allowing safety systems to initiate automatically would be reinforce Pending the completion of an ongoing investigation, this will be carried as an Unresolved Item i (369/86-28-07).

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Although the licensee _ exercised the allowances afforded by 50.54(X),

they did not repcrt the fact as is required by 50.72(b). This is a g second example of violation (369, 370/86-28-01), Failure to meet reporting requirement Hydrogen Mitigation System Failure Unit 1 was in Mode 2 (Startup) conducting zero power physics testing late on September 10, when the quarterly Hydrogen Mitigation (EHM)

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, Current Check Surveillance procedure (PT/1/B/4350/23A) determined the h "A"' train of containment hydrogen igniters to be inoperable. Several

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hours later it was determined that the "B" EHM train had also failed

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the surveillance. test and the requirements of Technical Specification I (TS) 3.0 3 were applicable. The unit was placed in Mode 3 pending

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ti investigation of the EHM System failure and replacement of the hydrogen

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Seventy-two hydrogen igniters are installed in the Unit 1 containmen Per TS 4.6.4.3, two surveillance tests are routinely performed to monitor system performance and ensure operability. Each igniter is t' physically -verified to reach a specified minimum temperature during each refueling outaje. This test was last performed on the Unit 1 igniters duri,1g the June-September 1986 outage, and only one failed igniter was found and replaced. A quarterly test is performed during unit operation to verify that a minimum number of igniters are energized. This is done by measuring the amount of current drawn by each string of igniters and comparing that current measurement to predetermined baseline with all igniters working. The results of this

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l surveillance on September 10-11 revealed that approximately twelve of

, the 72 installed igniters had faile \

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As an interim measure to allow the completion of zero power physics testing and low power turbine testing, the licensee replaced all the failed igniters and performed the requisite testing to restore EHM system operabilit Since the licensee could not rule out end-of-service life as a possible failure mode for the igniters, they took the initiative to replace all the Unit 1 igniters (except for one which was not readily accessible) prior to commencing long-term power operation. This was completed on September 1 Unit _2 has the same EHM system configuration as Unit I and was operating at 100 percent power during this time period. The following factors were evaluated to justify continued Unit 2 operation with the currently installed hydrogen igniters:

- the most recently completed quarterly surveillance tests showed satisfactory EHM performance;

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the Unit 2 igniters had' been in service for significantly less time than those in Unit 1; and

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none of the failed Unit 1 igniters exhibited symptoms of catastrophic failure due to moisture intrusion - a known failure mod The licensee is continuing to investigate the cause of the igniter failures and is evaluating the possibility of instituting a routine replacement program to prevent exceeding service life limitation This will be tracked as an Inspector Follow-up Item (369, 370/86-28-08).

d. Control Building Ventilation Functional Testing On July 2, 1986, Operations personnel declared Control Building Ventilation / Chilled Water (VC/YC) system train "A" inoperable to allow Construction and Maintenance Department (CMD) personnel to perform maintenance activities per Nuclear Station Modification (NSM)

MG-1-1303, Revision CMD personnel completed the modification activities on VC/YC system train "A" later that day and returned the red tags for the work to Operations personnel who signed the work request accepting operational control of the equipment, and subsequently declared VC/YC system train "A" operabl On July 3, Performance (PRF) persor.nel, who had previously been involved in performance retests associated with NSM MG-1-1303, contacted the Operations representative involved with the coordination and implementation of the NSM and determined that the modification work on VC/YC system train "A" was completed and the train was declared operable without a performance retest being don They notified control room personnel who declared VC/YC system train "A" inoperable pending performance of the requisite retes .

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NSM MG-1-1303 involved installing interposing relays in 24 control circuits involving 24 different component Seventeen work requests were written for the implementation of the NSM, and two work requests were written to document the performance retest under a temporary tes The retest designation on all 17 implementation work requests was marked "no".

Station Directive 3.2.1, '.' Identifying, Scheduling, and Performance of Plant Testing", states that a functional verification shall be performed on Quality Assurance.(QA) Condition-1 Systems and Technical Specification related components following maintenance. The McGuire Quality Standards Manual for Structures, Systems and Components identifies VC/YC as a QA Condition-1 (safety-related) syste The failure to perform the required VC/YC train "A" functional verification following maintenance on July 2,1986, is similar to an earlier incident cited in NRC Inspection Report Nos. 50-369/84-34 and 50-370/84-31 involving a failure to perform adequate post-modification testing of the upper head injection accumulator system in April 198 Pending the completion of an ongoing investigation this item will be carried as an Unresolved Item (369, 370/86-28-09).

8. Failure to Perform Required Surveillance On August 1,1986, at 7:35 a.m., with Unit 2 at full power, diesel generator (D/G) 2B was verified operable prior to declaring D/G 2A inoperable. At 7:45 a.m., D/G 2A was declared inoperable to allow inspection of the turbocharger. According to TS 3.8.1.1, the operable D/G is to be verified operable once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. At 3:35 p.m., personnel failed to verify th operability of D/G 2A. At 7:15 P.M. that evening, personnel realized the test on D/G 2B had not been performed as required. At 7:23 p.m., D/G 2B was verified to be operabl On August 7,1986, McGuire Unit 2 was at full power when at 9:14 p.m., start capability on D/G 2A was verified prior to declaring D/G 2B inoperable to allow maintenance on the D/G oil. system. On August 9, at 12:10 p.m., D/G 2B was redundantly declared inoperable due to other maintenance work. On 4 August 9, at 8:22 p.m. an operability test was performed on D/G 2B which was then logged operable as far as work on the D/G oil system was concerne Personnel were aware that D/G 2B was still inoperable due to other ongoing maintenance, but a D/G 2A operability test was not performed by 2:10 a.m.,

as required. At 2:51 p.m., D/G 2A was verified operabl On July 26, 1986, in preparation to reload the Unit i reactor core, the channel operational test was performed for both channels of the source range neutron flux monitor system. This test was performed to satisfy the "within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of the initial start of reactor core alterations" requirement of TS 4.9.2.b. The test was performed three times for both channels due to a I

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delay in the initial fuel loading. The last test was performed on July 27, 198 TS 4.9.2.c became effective when the first fuel assembly was loaded into the reactor core. 'The next due date for the seven day requirement of

.TS 4.9.2.c was August 3, 1986. On August-5, the appropriate shift personnel were contacted to determine if the source range operational test had been performed in preparation for entering Mode At that time ~it was discovered' that 'the tests had not been done. The tests were successfull completed prior to the unit entering Mode The above delineated examples singularly and collectively constitute

.vil i o at ons of regulatory requirements as described below:

Technical Specification 3.8.1.1, requires in Modes 1, 2, 3 and 4, that two diesel generators be operable. With one diesel generator inoperable, the remaining diesel must be verified OPERABLE within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter. Both diesel generators must be returned to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the plant must. be in at least H0T 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 hour3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> Contrary to those requirements, on August 1 'and August' 10, 1986, diesel generators 28 and 2A, respectively, were not verified to be OPERABLE within the 8. hours as require ,

Technical Specification 3.9.2 requires in Mode 6 that, at a minimum, two source range neutron flux monitors be OPERABLE and operating with alarm setpoints at 0.5 decade above the steady-state count rate, each with continuous visual indication in the control room and one with audible indication in the containment and control room. It is'also required that each source range neutron flux monitor be demonstrated OPERABLE by performance of: A CHANNEL CHECK at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, An ANALOG CHANNEL OPERATIONAL TEST within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> prior to the initial start of CORE ALTERATIONS, and An ANALOG CHANNEL OPERATIONAL TEST at least once per 7 day Contrary to those requirements, while in Mode 6, an analog channel operational test required to be performed on August 3 was not performed until August 5, 198 The above examples collectively constitute a violation (369, 370/86-28-10).

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