IR 05000263/1999003
| ML20196D369 | |
| Person / Time | |
|---|---|
| Site: | Monticello  |
| Issue date: | 06/18/1999 |
| From: | Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | Wadley M NORTHERN STATES POWER CO. |
| Shared Package | |
| ML20196D375 | List: |
| References | |
| 50-263-99-03, 50-263-99-3, NUDOCS 9906240265 | |
| Download: ML20196D369 (2) | |
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{{#Wiki_filter:==SUBJECT:== MONTICELLO INSPECTION REPORT 50-263/99003(DRP)
Dear Mr. Wadley:
On May 20,1999, the NRC completed an inspection at the Monticello reactor facility. The enclosed report presents the results of that inspection.
During the 6-week period covered by this inspection, the conduct of operations at the Monticello facility during routine activities was professional and safety-conscious. Evolutions, such as surveillance tests and routine plant power changes, were well controlled, deliberate, and performed in accordance with procedures. -However, the conduct of operatbns during two transients that resulted in reactor scrams, and the subsequent recovery actions, was not good and is of concem. Problems identified following these events included; reactor operators inappropriately bypassing a reactor feedwater pump high level trip during a reactor water level transient, training that reinforced the acceptability of taking an action not documented in an approved procedure, a lack of a questioning attitude by your staff on the acceptability of performing an activity that affected quality without an approved procedure, and an inadequate procedure that resulted in an operator not placing the mode switch in shut down in a timely manner which exacerbated recovery from a scram. We recognize that your staff identified these issues and the t your management staff has recognized the importance of reversing this recent negative performance. You have initiated actions to correct these issues and these actions appear appropriate. The effectiveness of these corrective actions will be demonstrated by future performanca at the plant.
During this inspection period an issue in the engineering area wts also identified that is of concem. This issue involved, the weak evaluation of the proper operating pressure of solenoid valves associated with the safety relief valve air system.
Based on the results of this inspection, the NRC has determined that four violations of NRC requirements occurred. These violations are being treated as Non-Cited Violations (NCVs), consistent with Appendix C of the Enforcement Policy. The NCVs are described in the attached inspection report. if you contest the violations or severity level of the NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C.
20555-0001, with copies to the Regional Administrator, Region lil, and the Director, Office of Enforcement, United States Nuclear Reguhtory Commission, Washington, D.C. 20555-0001.
9906240265 990618 PDR ADOCK 05000263 G PDR , .
, ,j In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter, its enclosure and your response (if you choose to provide one) will be placed in the NRC Public Document Room.
Sincerely, /s/ R. D. Lanksbury Roger D. Lanksbury, Chief Reactor Projects Branch 5 Docket No. 50-263 License No. DPR-22 Enclosure: Inspection Report 50-263/99003(DRP) cc w/ encl: Site General Manager, Monticello Plant Manager, Monticello S. Minn, Commissioner, Minnesota Department of Public Service Distribution: CAC (E-Mail) RPC (E-Mail) Project Mgr., NRR w/ encl J. Caldwell, Rill w/ encl B. Clayton, Rllt w/ encl SRI Monticello w/enci DRP w/enci DRS w/ encl /[[ Rill PRR w/enci PUBLIC IE-01 w/enci Docket File w/enci GREENS LEO (E-Mail) DOCDESK (E-Mail) 'd :) 0 0.\\ 0 DOCUMENT NAME: G:WONT\\ MON 99003.DRP To receive a copy of this document, Indicate in the box:"C" = Copy without enclosure "E"= Copy with enclosure"N"= No copy OFFICE Rlli E Rlli
[_ NAME Kunowski/djp2Dfh Lanksbury PAL DATE 06/t9/99 06/15/99 OFFICIAL RECORD COPY J
E , . ., U. S. NUCLEAR REGULATORY COMMISSION REGIONll! ' Docket No: 50-263 License No: DPR-22 Report No: 50-263/99003(DRP) Licensee: Northern States Power Company Facility: Monticello Nuclear Generating Station Location: 2807 West Highway 75 Monticello, MN 55362 Dates: April 9 through May 20,1999 Inspectors: S. Burton, Senior Resident inspector D. Wrona, Resident inspector S. Ray, Senior Resident inspector, Prairie Island Approved by: Roger D. Lanksbury, Chief Reactor Projects Branch 5 Division of Reactor Projects 9906240266 990618 PDR ADOCK 05000263 G PDR - . a
' ' . EXECUTIVE SUMMARY Monticello Nuclear Generating Station NRC Inspection Report 50-263/99003(DRP) ' This inspection included aspects of licensee operations, engineering, maintenance, and plant i support. The report covers a 6-week period of resident inspection.
Ooerations The licensee declared associated equipment inoperable and entered the appropriate - Technical Specification limiting conditions for operation when the 13 emergency service water (ESW) pump did not start during routine surveillance testing. A Non-Cited Violation for a failure to make a non-emergency 4-hour report to the NRC within the specified time was identified. Following the retum of the 13 ESW pump to an operable condition, the inspectors identified that the operators were not aware that the pump discharge check valve continued to leak and could affect operability. (Section 01.2) ) The licensee did not evaluate the impact of a temporary modification to the high
= pressure coolant injection system steam drains prior to performance of surveillance testing. During the testing, the configuration of the modified drains resulted in the receipt of an alarm that was normal for the condition, but not indicated as " expected" in the surveillance test procedure. (Section O1.3) A reactor scram occurred on low reactor water level due to a failure of the digital i = feedwater control system. Although several complications were associated with scram recovery actions and resulted in inadvertently flooding the main steam lines, reactor water level was eventually stabilized in the normal shutdown band. Proper NRC notifications were made. (Section 01.4) Operators were initially unaware that the main steam lines had flooded due to their - reliance on an improperly programmed SPDS level indication in conjunction with some deficiencies in operator knowledge associated with reactor vessel water level instrumentation. Main steamlines were inadvertently flooded when operators inappropriately bypassed reactor feedwater pump high level trips during a scram recovery. Operators had used an informal method for combating similar transients that had been encouraged during simulator training. The training department failed to proceduralize the informal method and operators failed to challenge the use of this , non-proceduralized method. A non-cited violation was issued for the failure to update Technical Specification required procedures, specifically, the use and operation of the reactor feed pump trip bypass switch. (Section 01.5) ' A reactor startup on Apr!l 28 was performed in accordance with approved procedures.
= Pre-job briefings for the startup were thorough and comprehensive. (Section 01.6) Operators exacerbated a reactor scram when they failed to place the mode switch in . shutdown in a timely manner, resulting in a main steamline isolation. A Non-Cited Violation was identified in that procedural guidance for a reactor scram did not direct operators to place the mode switch in shutdown after a scram and before reactor pressure dropped below 840 pounds per square inch gauge. (Section 01.7)
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?I , . . , Enoineerino Engineers failed to evaluate the safety relief valve air system components when they - identified conditions that had the potential to render the system inoperable. The issue was characterized by the inspectors as a Non-Cited Violation. (Section E1.1) The licensee's safety review of the Installation of a fabric cover over the spent fuel pool
was weak in that it did not address whether water buildup on the top of the fabric could cause it to fall into the spent fuel pool and block the spent fuel pool cooling flow path.
(Section E1.2)
Investigations into the cause of the 13 emergency service water pump trip were . appropriately scoped. No discrepancies were identified with troubleshooting activities or the operability determination. (Section E1.3) l
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, . , , i Report Details Summary of Plant Status
Except for a brief reduction to 95 percent power on April 13,1999, for maintenance on the feedwater control system, the unit operated at approximately 100 percent power from the beginning of the inspection period until April 22. On April 22, the unit scrammed on low reactor water level due to a malfunction of the feedwater control system. The unit was restarted on l April 29, and operated at approximately 100 percant power from April 30 through May 8. On May 8, the unit was manually scrammed due to problems in the offgas recombiner system and remained shutdown for the remainder of the inspection period.
1. Operations
Conduct of Operations 01.1 General Comrnents (71707) j The inspectors observed various aspects of plant operations, including compliance with Technical Specifications (TSs); conformance with plant procedures and the Updated Safety Analysis Report (USAR); shift manning; communications; management oversight; proper system configuration and configuration control; housekeeping; and operator performance during routine plant operations, the conduct of surveillance tests, . and plant power changes.
The conduct of operations was professional and safety-conscious. Evolutions such as surveillance tests and routine plant power changes were well controlled, deliberate, and performed in accordance with procedures. Shift tumover briefings were comprehensive and were typically attended by the operations superintendent, and representatives from the scheduling, security, instrument and control, electrical, and mechanical maintenance departments. Housekeeping was generally good and discroponcies were promptly , corrected. Safety systems, including containmcat isolation valves and portions of the j emergency service water (ESW) system, were found to be properly aligned. Specific events and noteworthy observations are detailed below.
01.2 Failure of the 13 ESW Pumo to Start Durina Testina a.
Insoection Scooe (71707) On April 12,1999, the 13 ESW pump failed to start during a routine quarterly surveillance test. The inspectors assessed the licensee's followup to this issue. The inspectors reviewed the following documents as part of this assessment: Procedure 0255-11-1ll-3, Revision 20, "13 Emergency Service Water Pump and
Valve Operability Test," performed en April 12,1999, and NUREG 1022, Revision 1, " Event Reporting Guidelines 10 CFR 50.72 cnd
50.73."
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Observations and Findinas i At approximately 7:55 a.m. on April 12,1999, operators attempted to start the 13 ESW pump in accordance with instructions contained in Procedure 0255-11-111-3. When the pump handswitch was placed in the start posit?on, the operator stationed at the pump heard a hum from the motor and noted that the pump shaft did not turn. After a short time, the motor starter thermat overloads tripped open. The licensoe initiated Condition Report (CR) 99000999 to address this issue.
The fc: lowing equipment normally supplied by service water that would be supplied by the 13 ESW pump in the event of a loss of offsite power included the high pressure coolant injection (HPCI) room cooler (V-AC-8A), the "A" train of control room ventilation (CRV) (V-EAC-14A), the "A" residual heat removal (RHR) room cooler (V-AC-5), the "A" core spray (CS) pump (a Division "A" pump), and the "C" RHR pump (a Division "A" pump).
Due to tne Divisicn "A" RHR and the Division *A" CS being inoperable, the licensee entered TS, Section 3.5.A.4, which required in part that an orderly shutdown of the reactor be initiated and the reactor placed within 24 hours in a condition in which the affected equipmer.t was not required to be operable within 24 hours. The licensee commenced performing the prerequisites for a reactor shutdown, but the13 ESW pump and all equipinent associated with it were declared operable prior to the need to reduce ! power.
During the review of this condition, the inspectors questioned if the inoperable HPCI system was reportable. The licensee reviewed the requirements, determined that the condition was reportable, and subsequently mada a four-hour non-emergency report to the NRC Operations Center. Section (b)(2)(iii)(D) of 10 CFR 50.72 required, in part, that the licensee notify the NRC as soon as practical and, in all cases, within four hours, of any event or condition that alone could have prevented the fulfillment of the safey function of systems that are needed to mitigate the consequences of an accident.
Contrary to the above, the licensee failed to make a report within four hours of HPCI being declared inoperable. This Severity Level IV violation is being treated as a Non-Cited Violation (NCV), consistent with Appendix C of the NRC Enforcement Policy.
This violation has been entered in the licensee's corrective action program under CR 99001008, *4 hour report for HPCI inoperability not made within 4 hours as required by 10 CFR 50.72" (NCV 50-263/99003-01(DRP)). On April 15,1999, the inspectors asked the operators about the status of the 13 ESW pump and its associated discharge check valve. The operatem stated that they twelieved that the check valve was functional and that there was no concern with the 13 ESW pump. Subsequently, they consulted with the system engineer and were informed that the check valve continued to leak and that the engir eer was planning to run the 13 ESW pump periodically to ensure sitt did not build up (the cause for the April 12th failure to start) and render the pump inoperable. The licensee placed Information Tag 99-15 on the 13 ESW pump handswitch in the control room to alert operators to the fact that the check valve was leaking and that it could affect pump operability. The inspectors were concemed that the operators were not aware of this condition and its effect on safety-related plant equipment.
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_ The troubleshooting and engineering evaluation associated with this issue is discussed in Section E1.3 of this report.
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Conclusiq_rls The licensee ' declared associated equipment inoperable and entered the appropriate Technical Specification limiting conditions for operation when the 13 emergency service water pump did not start during routine surveillance testing. A Non-Cited Violation for a - failure to make a non-emergency four-hour report to the NRC within the specified time was identified. Following the retum of the 13 ESW pump to an operable condition, the inspectors identified that the operators were not aware thei the pump discharge check valve continued to leak and could affect operability.
01.3 Hiah Drain Pot Level'Dur% HPCI Testing a.' insoection Scoce (71707) l During performance of routina HPCI surveillance testing, a high drain pot level annunciator that was not specified as " expected" per the procodure was received. The inspectors inten;iewed operators and reviewed the following documents: Surveillance Test Procedure 0058, Revision 11,"HPCI Steam Line High Area
Temperature Test and Calibration Procedure, and Group 4 isolation Valve Closure Test," performed on April 19,1999, Annunciator Response Procedure C.6-003-B-10, Revision 3. "HPCI Turbine inlet = Hi Drain Pot Level," ] NUREG 1022, Revision 1, " Event Reporting Guidelines 10 CFR 50.72 and + 50.73," and CR 99001089, "HPCI Declared inoperable Due to inlet Drain Pot High Level - During Recovery from Procedure 0058, 'HPCI Hi Area Temp Test'." b.
Qbagvations and Findinos in accordance with the instructions contained in Procedure 0038, the HPCI system was declared inoperable, the appropriate 1 S limiting condition for operation was entered, and the steamlir. a vas isolated. While the HPCI steam!ine was being restored, and prior to it being declared operable, Annunciator 3-B-10 for high HPCI drain pot level was p' received in the control room. Operators reviewed Annunciater Response Proadure C.6-003-B-10 end performed the specified actions. Shift management reviewed this issue and determined that although Procedure 0068 did not specify that this annunciator could come in, it was expected due to condensation in the HPCI steamline that accumulated while the steamline was isolated. Shift management also detemiined that since the annunciator was an expected response to the system configuration due to planned survaillance testing, a non-emergency 10 CFR 50.72 report was not requi ed. The inspe.ctors reviewed the reporting requirements associated ' with this issue and identified no discrepancies. Operators indicated in interviews that - the HPCI turbine inlet high drain pot level annunciator was received due to the manual .1 valve in place of an automatic valve in the drain system. Although the replacement of '
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l . '. the automatic valve with the manual valve was identified as a temporary modification and a temporary information tag was placed on the main control room panel, the licensee did not evaluate the impact of this condition on Procedure 0058. The licensee
initiated CR 99001089 to track the minor discrepancy associated with Procedure 0058.
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Conclusions The licensee did not evaluate the impact of a temporary modification to the high pressure coolant injection system steam drains prior to performance of surveillance ' testing. During the testing, the conf:guration of the modified drains resulted in the receipt of an alarm that was normal for the condition, but not indicated as " expected"in the surveillance test procedure.
01.4 Reactor Scram Due to Feedwater Control System Failure a.
Insoection Scope (93702) The inspectors responded to an unplanned reactor scram that occurred at 1:31 a.m. on
April 22,1999. The inspectors subsequently reviewed USAR requirements, system ' response, immediate and subsequent operator actions, event notifications, event review and analysis, and corrective actions that were recommended by the licensee.
b.- Observations and Findiagg The reactor scrammed on low reactor water level, caused by a malfunction in the digital feedwater control system. All systems functioned as expected during the transient with the exception of the digital feedwater control system, which in tum affected one of the two feedwater level indicators and some of the steam flow and feed flow indicators on ' the main control room panels. Operators responded to tne event by attempting to take manual control of the feedwater master controller, which proved unsuccessful. Reactor water level was eventually stabilized within the normal shutdown band. The event had several complications which are discussed below and in Section 01.5. The licensee notified the NRO of the reactor scram, associated Group ll and lli isolations, and inoperable reactor core isolation cooling (RCIC) system and HPCI systems. The inspectors reviewed the licensee's event notifications and found them proper and performed within the prescribed time requirements.
j Subsequent troubleshooting on the feedwater control system identified that the failure ! was the result of degraded power supplies. The failure had affected both feed water regulation valves, feedwater system controls, and the indicators mentioned above.
Additionally, licensee post-trip reviews identified other issues which included the following: reactor water level had actually risen to approximately 150 inches and had
flooded the main steam lines, operators had, without procedural guidance, bypassed the feedwater pump high - level trip during the event, and operators relied on an invalid and nonsafety-related safety parameter display - system (SPDS) reactor water level indication.
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These issues are discussed in further detail in Section 01.5.
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Conclusions ~ A reactor scram occuned on low reactor water level due to a failure of the digital ) feedwater control system. Although several complications were associated with scram recovery actions and resulted in inadvertently flooding the main steam lines, reactor water level was eventually stabilized in the normal shutdown band. Proper NRC notifications were made.
' 01.5 Main Stearrjlines Flooded After. Scram a.
Insoection Scoce (7WOZ)
During the review of the reactor scram that occuned on April 22,1999, the licensee determined that reactor water level had risen above the mein steam lines. The inspactors reviewed the sequence of events that resulted in the steamline flooding; contributing factors to the event; and HPCI, RCIC, and main steam system operability determinations that were performed to retum associated systems to service prior to ] start-up.
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Observaligas and Findinos The following is a list'of control room panel reactor water level indicators that when operable and on-scale were capable of providing level indication during this event: two safeguards indicators with a range of -50 to +50 inches, = two feedwater indicators with a range of 0 to +60 inches, and
i + one vessel flood indicator with a range of -50 to +350 inches.
l A nonsafety-related SPDS system, which receives inputs from the above instrumentation, calculates water level based on several factors, and displays the results, was also avalleble.
Prior to the scram, operators noted a failurs which resulted in one feedwater regulating ) valve closing and the second feedwater regulating valve locking up, observed one
feedwater level instrument fall downscale and the other feedwater level instrument and the safeguards indicators rapidly decreasing, and attempted to increase reactor . foedwater flow. Approximately 27 seconds after the first. indication of tre malfunction, the reactor scrammed on low reactor water level. During the next 51 seconds, operators took actions to restore reactor water level. Actions included verification of reactor water level using the operabk instruments discussed above, attempts to take manual control of feedwater regulating valves, and bypassing the feedwater pump high j level trip (use of the bypass switch is discussed below). During this time, the main n turbine tripped on high reactor water level,48 inches. Within a few seconds of the main i ^ turbine tripping,' the operable feedwater and safeguards indicators on the control panels went off-scale high, leaving the SPDS and the vecsel flood indicator as the only , remaining useable reactor water level indications. Although the unccmpensated vessel flood indicator tracked level throughout the event, it indicated significantly different than the SPDS feedwater indicators. Nine seconds after the main turbine tripped and after verification of reactor water level using SPDS, operators closed the feedwater regulating
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i valves. Approximately 35 seconds later, and after operators recognized that reactor water level was increasing due to leakage past the feedwater regulating valve, the j feedwa'er block valves were given a signal to close. Reactor water level was then verified by the operators using SPOS, and assumed to be at 80 inches and stable due to the issues discussed below. Subsequently, systems were restored to service, reactor water level restored to normal, and a reactor cooldown commenced.
Flooding of the main steamlines was a result of the combination of the digital feedwater control system failure, misleading SPDS indication, and, primarily, the bypassing of the . feedwater pump high level trip. The operators bypassed the feedwater pump top because of the uncertainties about reactor water level due to the abnormal feedwater l levelinstrument indication and because of previous tr aining. A contributing factor to the ! uncertainty was a deficiency in operator knowledge tssociated with instrument failure I mechanisms and instrumentation interrelationships. This particular use of the bypass j switch was not prohibited nor govemed by procedhres. Training department personnel had indicated that the use of the bypass switch in similar situations was not only acceptsbla, it was encouraged; however, they failed to proceduralize these accepted j actions. Additionally, operators failed to challenge the training department recommendation associated with the use of the bypass switch when it was not proceduralized. Subsequently, p; ant management reviewed this practice, considered procedure changes, and determined that it was unacceptable. Technical i Specification 6.5 requires,in part, that detailed written procedures covering actions to be { takan to correct specific and foreseen potential or actual malfunctions of systems or components shall be prepared and followed. Contrary to this, the reactor operators used the feedwater high level trip bypass switch to correct an actual feedwater system malfunction without a detailed written procedure directing this action. This is a violation i of TS 6.5 and is being treated as a Non-Cited, Severity Level IV Violation, consistent i with Appendix C of the NRC Enforcement Policy. This violation was entered in the licensee's corrective action program under CR 99001163, " Reactor Water Level Above Main Steam Lines Following Scram" (NCV 50-263/99003-02(DRP)). Misleading reactor water levelindications were a result of the failure of the digital ) feedwater control system, problems associated with SPDS, and instrument der.diy ~ compensation methodologies. When the feedwater control system failed, associated instrumentation also failed with one reactor water level instrument indicating low. When water level exceeded 50 inches, the safeguards instrumentation on the control panel j indicated off-scale high. At this time, SPDS showed three useable instruments: two temperature compensated feedwater instruments and the uncompensated vessel flood instrument. SPDS indications visible to the operators showed feedwater instrumentation as " green " indicating that it was validated and the reactor flood-up instrument as " yellow," indicatJng that the instrument was not validated. The green indication for the reactor water level instrumentation was a result of SPDS program logic which saw two valid level indications which were of the same type and similar value. The actual situation was that the reactor water level was above the reference legs and the instruments were at the maximum Indication; however, duu to a piogram error, SPDS still showed these inputs as useable. Operators were unaware of this condition and were under the impression that the SPDS feedwater indication was valid up to 95 inches. The operators also observed the vessel flood instrument and noted that it was tracking, but did not trust the instrumentation because the color was " yellow" and because the instrument is not compensated and did not indicate the same level as the " good" feedwaterinstruments. Because SPDS did not have a similar instrument to
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< . '. " validate" the flood-up instrument, it always indicated " yellow." This de'iciency in operator knowledge, and the SPDS programming which erroneously indicated that the ' compensated instrumentation was valid when it indicated above scale, resulted in the , operators belief that level had been controlled and stabilized at 80 inches when in fact, reactor water level rose to approximately 150 inches.
Corrective actions included repair of the digital feedwater control system, procedure changes, including instructions governing the use of the feedwater pump high level trip bypass switch and SPDS, addition of an operator aid to the bypass switch, additional training on feedwater level instrumentation and the digital feedwater control system, a review of steamline flooding events, training on the use of the SPDS, and modifications to SPDS prograrnming. The plant manager also discussed management expectations during plant transients with each of the operation crews prior to them assuming duties following plant restart. Thesta discussions included the need to maintain a questioning attituda, expectations of procedural usage, and when it would be acceptable to use devices such as protective feature bypasses. Following the scram discussed in Section 01.7, the licensee initiated a " common cause team," which included plant personnel, an industry consultant and personnel from other utilities, to assess operational performance associated with these events. The licensee performed operability determinations and system walkdowns, looking for indications of pipe movement or damage due to water or water hammer, for the main steam, HPCl, and RCIC systems. Initial reviews by the licensee and the NRC indicated that this event was of low safety significance due to credit given to operators for being able to reestablish feedwater flow. Further reviews related to the probabilistic risk and relative impact on core damage frequency when both HPCI and RCIC systems were inoperable during the trans!ent will be evaluated by the NRC during a review of the licensee event report which the licensee had planned to subrnit for this event, c.
Congj,usions Operators were initially unaware that the main steam lines had flooded due to their reliance on an improperly programmed SPDS level indication in conjunction with some deficiencies in operator knowledge associated with reactor vessel water level Instrumentation. Main steamlines were inadvertently flooded when operators inappropriately bypassed reactor feedwater pump high level trips durir.g a scram recovery. Operators had used an informal method for combating simi!ar transients that had been encouraged during simulator training. The training department failed to proceduraiize the informal method and operators failed to challenge the use of this non-proceduralized method. A non-cited violation was issued for the failure to update Technical Specification requked procedures, specifically, the use and operation of the reactor feed pump trip bypass switch.
01.6 Reactor Startp.AOn Acril 2R,19_M a.
Inspection Scope (71707) The inspectors observed all or portions of activities associated with restart of the reactor following the unplanned shutdown on April 22,1999. Activities observed included various pre-job briefings, drywell closure, reactor restart, reactor heat-up, synchronization of the main turbine to the grid, and power ascension.
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OJservations and Findinas l Pre-job briefings associated with the reactor startup. Briefings were thorough and - comprehensive, and the shift managers involved with the briefings were clear about their expectations with respect to procedural usage, safety, and being slow and deliberate during all activities. During the first attempt to take the reactor critical on the evening on April 28, operators encountered difficulty in demonstrating operability of the containment atmospheric sampling system due to a failed solenoid valve. Operators recognized that repairs to this system would extend the time to place the mode switch into run and would result in exceeding allowable surveillance test intervals. The few control rods that had been withdrawn were inserted and the mode switch returned to shutdown until surveillance test procedures were completed. Startup activities continued with a new shift on April 29. Reactor startup, heatup, mode changes, and turbine synchronization of the main generator to the electrical distribution grid were performed in accordance { v/ith procedures.
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Conclusions A reactor startup on April 28 wcs performed in accordance with approved procedures.
Pre-job briefings for the startup were thorough and comprehensive.
01.7 Reactor Scram as a Result of Steam Jet Air Elector Hiah Pressure isolatior1 _ a.
Insoection Scoce (71707 & 93702) Inspectors responded to and followed up on events associated with a reactor scram that I occurred on May 8,1999.
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Observations and Findinas On May 8, at 1:31 p.m., the steam Jet air ejector suction valves closed due to an offgas high pressure trip signal. The high pressure trip signal was the result of a recombination of hydrogen and oxygen in the off-gas system piping, extemal to the recombiner.
Operators evaluated the event, reduced power, and inserted a manual scram at approximately 1:39 p.m. The licensee initiated CR 99001340 to identify, track, and resolve issues associated with problems in the offgas system.
A step in Procedure C.4-A, Revision 13, " Reactor Scram," required the operator to place the mode switch in the " shutdown" position. However, after inserting the manual scram signal, the operator was slow to perfum this step. Failure to place the mode switch in the " shutdown" position exacerbated the event. When reactor pressure decreased below 840 pounds per square inch - gauge (psig) with the mode switch in the "run" position, the main steamline i. solation valves automatically closed, as designed.
Restoration of main condenser vacuum and resetting the low condenser vacuum scram took approximately 2.5 hours. During the interim, operators controlled reactor pressure by cycling relief valves which utilize the suppression pool as the heat sink. Suppression pool cooling was established to maintain suppression pool temperature. Remaining actions associated with the scram were uncomplicated and performed in accordance with approved procedures. The licensee initiated CR 99001300 to identify, track, and resolve issues associated with the reactor scram.
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m . '. The inspectors reviewed Procedure C.4-A and noted that information was not available in the procedure to direct operators to change the position of the switch prior to reactor pressure decreasing below 840 psig. Additionally, the operator had approximately eight minutes prior to inserting the manual scram to review and consider his actions.
Appendix B, Criterion V, " Instructions, Procedures, and Drawings," of 10 CFR Part 50, requires, in part, that activities affecting quality be prescribed by documented instructions of a type appropriate to the circumstances. Contrary to the above, Procedure C.4-A did not ensure operators placed the mode switch to the " shutdown" position prior to a main steamline isolation when reactor pressure dropped due to the scram. This Severity Level IV violation is being treated as an NCV, consistent with
Appendix C of the NRC Enforcement Policy. ~ This issue is in the licensee's corrective j action program as CR 99001300 (NCV 50-263/99003-03(DRP)). l c.
Conclusion Operators exacerbated a reactor scram when they failed to place the mode switch in shutdown in a timely manner, resulting in a main steamline isolation. A Non-Cited j Violation was identified in that procedural guidance for a reactor scram did not direct i operators to place the mode switch in shutdown after a scram and before reactor pressure dropped below 840 psig.
! 11. Maintenance i M1 Conduct of Maintenance ) M1.1 General Comments on Maintenance Activities a.
insoection Scooe (62707) The inspectors observed performance of all or portions of the activities contained in following Work Orders (WOs): WO 9802133, "MO-2021 Drywell spray outboard isolation valve," performed on
March 16,1999 WO 9905429, "13 ESW Pump Tripped after Being Started for Test," performed + on April 12,1999 WO 9905432,"13 ESW Pump Didn't Tum When Started," performed on - April 12,1999 Operations Manual B.5.1.2-05, Section E.3, Revision 4, "LPRM [ local power - range monitor] Calibration," performed on May 4,1999 WO 9904053, "CRD-4-1 does not check closed leaks," performed on May 18, - 1999
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Observations and Findinas The work performed during these activities was professional and thorough. All work , was performed in accordance with approved procedures and the workers were knowledgeable of their assigned tasks. When applicable, appropriate radiological work permits were followed. The. inspectors observed supervisory and engineering involvement in the activities and adequate foreign material exclusion controls. On one occasion, inspectors noted that maintenance technicians demonstrated good attention-to-detail when they performed system line-up verifications that were not required by the WO.
M1.2 General Comments on Surveillance Test Activities a.
Insoection Scooe (61726) The inspectors observed or reviewed the performance of all or portions of the activities contained in the following surveillance test procedures: Surveillance Test Procedure 0108, Revision 37, HPCI System Tests with
Reactor Pressure < 150 psig," performed on April 29,1999 Surveillance Test Procedure 0108, Revision 37, " Reactor Core isolation Cooling + System Tests with Reactor Pressure <150 psig," performed on April 29,1999 Surveillance Test Procedure 1371, Revision 4, "Drywell Prestart inspection," - performed on April 29,1999 Surveillance Test Procedure 2154, Revision 5, " Predicted Critical for Plant = Startup," performed on April 29,1999 Surveillance. Test Procedure 0075, Revision 8, " Control Rod Drive Coupling - Test," performed on April 29,1999 Surveillance Test Procedure 2163, Revision 24, " Plant Restart Check List," + performed on April 29,1999 Surveillance Test Procedure 0004, Revision 20 " Reactor Water Low Level + Scram & Lo-Lo Level isolation Trip Unit Test and Calibration Procedure," performed on May 19,1999 b.
Observation and Findinas in general, the inspectors found that the activities specified in the surveillance test procedures were performed in a professional and thorough manner and completed in accordance with the applicable procedures. Personnel were knowledgeable and generally demons! rated effective three-way communications, self-checking, and peer-checking. When conducted, pre-job briefs were comprehensive. The inspectors frequently observed supervisors and system engineers monitoring job progress. Quality control personnel were present whenever specified in a procedure. When applicable, appropriate radiation control measures were in-place.
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, . 111. Enaineerina E1 Conduct of Engineering E1.1 Qualification of Safety Relief Valve (SRV) Solenoid Valves a.
Insoection Scope (37551) I Because of previously identified concems with the operability of the SRV bellows leakage detection system (see inspection Report 50-263/99002, Section 01.2), and because the licensee indicated that reactor depressurization was the largest contributor to plant risk using both Fussell-Vesely and Risk Achievement Worth methodologies, the inspectors reviewed the design and operation of the SRVs and supporting systems.
b.
Observations and Findinas j
During a review of the design of the SRV air system, the inspectors noted that the l configuration was such that the portion of the system contained within the drywell was ! isolated without a viable relief path. This resulted in a susceptibility for the system to become overpressurized if heating in the drywell were to occur. The inspectors also noted that the air system relief valve, which was located outside the drywell and , upstream of the check valves for the drywell portion of the system, had a setpoint of j 120 psig per Operations Manual B.8.4.3-02, Revision 0, "Altemate Nitrogen System."
Further review of Operations Manual B.3.3, Revision 7, " Reactor Pressure Relief," indicated that both the accumulators and the ASCO-model solenoid valves were rated for 125 paid. Because of the small margin between the relief valve setpoint and the design pressure of the accumulator and solenoid valves, the inspectors asked the licensee about system operability.
The licensee indicated that this condition had been considered previously and provided an operability evaluation that was performed as part of the response to Generic Letter (GL) 96-06, " Assurance of Equipm< nt Operability and Containment Integrity During Design-Basis Accident Conditions." The inspectors noted that the letter indicated that the pressure in this portion of the system could reach 123.3 psid. Due to the small, 1.7 psig, margin to the valve and accumulator design pressures the inspectors reviewed the calculations. In intemal correspondence, engineering personnel noted that nominal values of 135 degrees - Fahrenheit (*F) for drywell temperature and 105 psig for air ' system pressure were used in the analysis.
, A recalculation of system pressure by the inspectors using the ideal gas law and the nominal values used in the operability determination resulted in the loss of the 1.7 psig margin that the licensee's calculation had demonstrated. Additionally, operability . ' considerations in the GL 96-06 response did not appear to fully consider other variables such as voltage and line losses associated with temperature changes, solenoid voltage and ampere requirements with a higher differential pressure than 125 psid, ar,d insulation degradation effects due to temperature and radiation.
Additionally, licensee intemal correspondence stated, "For future relief devices or equipment upgrades on these lines, the setpoint of the over-pressurization device may .want to be considered as the initial pressure." The inspectors interviewed the engineer who performed the calculation and questioned what logic was used for determining 14-m
, . '.. , i nominal values and why the range of values expected to occur during normal operations were not used for the calculation. The engineer indicated tW9L 96-06 allowed the use of American Society of Mechanical Engineers Code, Sech (1,3ppendix F, for interim operability determinations and qualification of piping, ad that the code allowed the use i of nominal values. The engineer had obtained the nominal pressure control valve j setpoint form the Component Master List and the drywell temperature from the USAR l loss-of-coolant accident assumptions. When asked if he recogn: zed that by using normal operating parameters the 1.7 psig margin required for component operability versus piping operability would be depleted, the engineer stated that the engineering department recognized this, but the calculation was for the GL 96-06 response and not performed to the level of detail for determinating operability or full qualification.
Although the engineering department had identified that other conditions existed that had the potential to render the system inoperable, it failed to document an analysis in a condition report or operability evaluation that demonstrated the availability of the SRVs.
Additionally, a modification to restore the system to full qualification was under development because of the small margin ident!fied. Criterion lil, " Design Control," of Appendix B,10 CFR Part 50 states in part that " design control measures shall provide for verification or checking the adequacy of design, and that design control measures shall be applied to stress, thermal, hydraulic, and accident analysis." The failure of the licensee to verify the adequacy of the design of the SRV air system, when mathematical and process errors were identified during the review of calculations performed for GL 96-06, is a violation of Criterion 111 and is being treated as a Non-Cited, Severity Level IV Violation, consistent with Appendix C of the NRC Enforcement Policy. This violation has been entered into the licensee's corrective action program under CR 99001142, "GL 96-06 Operability of SRV Operator Solenoid Valves" (NCV 50-263/99003-04(DRP)). Subsequently, operability of the solenoids and accumulators was reconsidered by the licensee and documented in CR 99001142. Calculations determined that the maximum differential pressure that the system could experience wa; around 177 psig versus the 123.3 psig indicated in the GL 96-06 response. Solenoid valve testing included heating the valve in an oven, verifying operations at higher differential pressures and elevated temperatures, electrical line loss / resistance calculations for elevated temperatures, and voltage tests at higher differential pressures and temperatures. Based upon the testing performed and engineering judgment, the licensee was able to declare the system operable but degraded, and planned to restore the system to full qualification during the j next scheduled outage as part of modification 98QO10, Part C. Final resolution will be documented with commitment number M97013A associated with the response to GL 96-06. Plant management reinforced with engineering personnel that operability was required for the normal range of parameters encountered during routine operations.
Other corrective actions included providing training to the engineering staff on lessons learned related to this issue, and modifying operating procedures to ensure that parameters utilized when determining operability were not exceeded.
During the review of requirements associated with SRVs, the inspectors considered the licensee's response to IE Bulletin 80-25," Operating Problems with Target Rock Safety-Relief Valves at Boiling Water Reactors." The inspectors noted that the system design and setpoints were modified subsequent to the response. The licensee was unable to immediately determine if any commitments or design applications associated with the response to the bulletin were changed. The licensee was adJressing this issue
- , '. under Supervisory Action 99001197. Action 99001197 will compare the new analysis ! and design changes to the origina; response and ensure that the system still meets l design commitments. Initial review of this issue indicated that the current operability evaluation may encompass the intent of IE Bulletin 80-25, which required that the SRV air system remain operable under varied conditions within the drywell.
c.
Conclusion i Engineers failed to evaluate the safety relief valve air system components when they identified conditions that had the potential to render the system inoperable. This issue was characterized by the inspectors as a Non-Cited Violation.
E1.2 Weak Safety Review of a Chanoe to the Soent Fuel Pool a.
Inspection Scope (37551) . The inspectors noted that the licensee had recently installed a fabric cover over the spent fuel pool and reviewed Safety Review Item (SRI) 99-008, " Provide a Removable Covering for Foreign Material Exclusion Considerations Regarding the Spent Fuel Pool," Revision 0 b.
Observations and Findinas The SRI described the evaluation for installing the cover over the spent fuel pool and , l contained a screening form which documented the licensee's basis for concluding that the change did not involve any issues for which a formal safety evaluation in accordance with 10 CFR 50.59 was required. The evaluation considered fire loading, spent fuel pool ventilation, spent fuel pool evaporation, material properties of the fabric considering the temperature and radiation fields to which it would be exposed, and other aspects of the change.
The inspectors determined that one issue had not been adequately addressed. The inspectors were concerned that a buildup of water on the top of fabric could cause the fabric to fall into the spent fuel pool and possibly block the spent fuel pool cooling system flow path. The water could possibly come from a piping system rupture in the area of the fuel pool (such as a fire protection or demineralized water supply line) or l from condensation after a loss of coolant or steam break accident. In a post-accident situation, the area might not be accessible for removal of the fabric from the pool.
- The engineer who had prepared the SRI stated that he had not considered that possibility. However, the SRI stated that the fabric was somewhat porous, which could prevent a buildup of water on top of it. In addition, an examination of the supports and configuration of the fabric cover indicated that excessive weight would probably not result in a failure that would cause a large portion of the fabric to end up in the spent fuel pool. The inspectors determined that the installation did not pose a significant ' safety concem. However, the licensee's SRI did not address all the potential failure mechanisms for the new installation.
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. c.
Conclusions The licensee's safety review of the installation of a fabric cover over the spent fuel pool was weak in that it did not address whether water buildup on the top of the fabric could cause it to fall into the spent fuel pool and block the spent fuel pool cooling flow path.
E1.3 Troubleshootino and Evaluation of the 13 ESW Pumo Failure to Start j a.
Insoection Scooe (37551) The inspectors assessed the licensee's troubleshooting and evaluation of the failure of the 13 ESW pump to start as discussed in Section 01.2 of this report. The following documents were reviewed as part of this assessment: WO 9905429, "13 ESW Pump Tripped after Being Started for Test," performed
on April 12,1999, WO 9905432,"13 ESW Pump Didn't Tum When Started," performed on April 12, a 1999,and CR 99000999, "13 ESW Pump Failed to Start for Testing on 4/12/99."
a b.
Observations and Findinos As discussed in Section 01.2 of this report, the 13 ESW pump failed to start during routine surveillance testing. Condition Report 99000999 addressed this issue. Initial investigations conducted by the licensee to determine the cause were appropriately scoped and included initiating WOs to investigate the pump motor and breaker, and an investigation to determine if the pump shaft was bound. The licensee determined that the motor and breaker operated as designed and that the pump shaft was bound. The system engineer noted that the pump discharge piping was cooler than the discharge piping of other similar equipment and concluded that the pump discharge check valve was leaking. The licensee considered items such as ice in the pump assembly, l macro-fouling, silt buildup or foreign material in the pump assembly, and determined that silt buildup due to the leaking check valve was the cause of the bound pump shaft.
Immediate corrective actions included flushing the ESW pump and periodically running j the 13 ESW pump to ensure it does not bind up. The 13 ESW pump discharge check ' valve was repaired after the reactor was shutdown as discussed in Section 01.4 of this report.
The inspectors reviewed portions of the troubleshooting activities and the operability determination as documented in CR 99000999 and identified no discrepancies.
c.
Conclusion Investigations into the cause of the 13 emergency service water pump trip were appropriately scoped. No discrepancies were identified with trouble >ahooting activities or the operability debrmination.
p , - . . IV. Plant Suonort i R1 Radiological Protection and Chemistry Controls R1.1 General Comments (71750) i During routine tours of the plant and observations of plant activities, the inspectors found that access doors to locked high radiation areas were properly secured, areas were properly posted, and personnel demonstrated proper radiological work practices.
The inspectors reviewed various survey data and radiation work permit (RWP) use and I found that personnel were logged onto the correct RWP for the work being performed.
Personnel logged into RWPs were wearing proper protective clothing and kept radiation , protection personnelinformed of activities as required by the RWP. Additionally, the Inspectors found surveys to be timely and accurate.
S1 Conduct of Security and Safeguards Activities S1.1 General Comments (71750) During routine activities or tours, the inspectors monitored the licensee's security program to ensure that observed actions were being implemented according to the approved security plan. The inspectors noted that persons within the protected area displayed proper photo identification badges and those individuals requiring escorts were properly escorted. The inspector also verifed that checked vital areas were locked and alarmed. Additionally, the inspectors also verified that observed personnel and packages entering the protected area were searched by appropriate equipment or by hand.
F2 Status of Fire Protection Facilities and Equipment F2.1 : General Comments (71750) During normal resident inspection activities, routine observations were conducted in the area of fire protection. Fire extinguishers and fire hoses were properly stored and inspected by licensee personnel. No notable degradation of equipment was nott d.
V. Management Meetings X1 . Exit Meeting Summary I i The inspectors presented the inspection results to members of licensee management at the , l conc!usion of the inspection on May 20,1999. The licensee acknowledged the findings presented.
l _ The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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__ . ' . ' PARTIAL LIST OF PERSONS CONTACTED i Li.ansan. c B, Day, Plant Manager . M. Hammer, Site Manager. . . K. Jepson, Superintendent, Chemistry & Environmental Protection i M. Lechner, Acting General Superintendent Operations L. Nolan, General Superintendent Safety Assessment E. Reilly, General Superintendent Ma!ntenance C. Schibonski, General Superintendent Engineering A. Ward, Manager Quality Services - ' . L. Wilkerson, Superintendent Security { J. Windschill, General Superintendent, Radiation Services \\ lNSPECTION PROCEDURES USED IP 37551: .Onsite Engineering IP 61726: Surveillance Observations i IP 62707: -Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities lP 92902: Followup - Maintenance IP 92903: Followup - Engineering . l i-e
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ITEMS OPENED AND CLOSED ) Opened 50-263/99003-01 NCV Report of HPCI inoperability not made within 4 hours as required i by 10 CFR 50.72 (Section 01.2) ] 50-263/99003 02 NCV Failure to provido a detailed procedure for the use of the feedwater pump high level trip bypass switch (Section 01.5) 50-263/99003-03 NCV Inadequate procedural controls for the use of mode switch (Section 01.7) ) 50-263/99003-04 NCV Failure of licensee to verify the adequacy of the design of the SRV air system (Section E1.1) Closed 50-263/99003-01 NCV Report of HPCI inoperability not made within 4 hours as required by 10 CFR 50.72 (Section 01.2) 50-263/99003-02 NCV Failure to provide a detailed procedure for the use of the feedwater pump high level trip bypass switch (Section 01.5) i 50-263/99003-03 NCV Inadequate procedural controls for the use of mode switch (Section 01.7) 50-263/99003-04 NCV Failure of licensee to verify the adequacy of the design of the SRV , air system (Section E1.1) , Discussed None
[ ., ' . LIST OF ACRONYMS USED ALARA As-Low-As-Reasonably-Achievable AOV Air-Operated Valve CFR Code of Federal Regulations. CR - Condition Report CRD Control Rod Drive CRV Control Room Ventilation CS Core Spray
- F Degrees Fahrenheit DRP Division of Reactor Projects ESW Emergency Service Water FW Feedwater HCU Hydraulic Control Unit HPCI High Pressure Coolant Injection IFl Inspection Followup Item IP inspection Procedure LER Licensee Event Report LLRT Local Lesk Rate Test LPRM Local Power Range Monitor
MCC Motor Control Center mrem /hr millirem per hour MSIV Main Steam Isolation Valve NCV Non-Cited Violation NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation , NSP Northem States Power ' PDR-Public Document Room i psig pounds per square inch RCIC reactor core isolation cooling
RFP Reactor Feed Pump RHR Residual Heat Removal RWP' Radiation Work Permit i I .SBLC Standby Liquid Control SPDS Safety Parameter Display System SRI Safety Review item SRV ~ Safety Relief Valve SSPV Scram Solenoid Pilot Valve SW Service Water 'TS Technical Specification URI Unresolved item USAR Updated Safety Analysis Report VIO Violation WO - Work Order -
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