IR 05000461/1999002
| ML20204F440 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 03/18/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20204F432 | List: |
| References | |
| 50-461-99-02, 50-461-99-2, NUDOCS 9903250294 | |
| Download: ML20204F440 (28) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGIONlli Docket No.:
50-461 License No.:
NPF-62 Report No:
50-461/99002(DRP)
Licensee:
Illinois Power Company Facility:
Clinton Power Station Location:
Route 54 West Clinton, IL 61727 Dates:
January 7 - February 16,1999 Inspectors:
T. W. Pruett, Senior Resident inspector K. K. Stoedter, Resident inspector j
C. E. Brown, Res: dent inspector D. E. Zemel, Illinois Department of Nuclear Safety
Approved by:
Thomas J. Kozak, Chief Reactor Projects Branch 4 Division of Reactor Projects
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EXECUTIVE SUMMARY j
l Clinton Power Station NRC Inspection Report 50-461/99002(DRP)
This inspection included aspects of licensee operations, maintenance, engineering, and plant
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support. The report covers a 6-week period of resident inspection.
Ooerations The inspectors determined that operations personnel responded appropriately to a loss
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of offsite power (LOOP) event involving a Notice of Unusual Event (NOUE) declaration in that procedures were used in-hand, peer checks were frequently conducted, three-way communication techniques were good, and off-shift personnel were effectively utilized without becoming a distractbn to the operating crew (Section 01.1).
The inspectors determined that the licensee's initial critique of the LOOP event was not
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suf'wiently critical to identify issues involving operator knowledge weaknesses, procedure discrepancies, timeliness of event declaration, and delays in the shift turnover process. Following discussions with the inspectors, the licensee initiated an event review team and conducted an effective assessment of the issues and concerns (Section O1.1).
The inspectors determined that the licensee's review of procedures to support closure
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of Case Specific Checklist (CSC) Restart item II.3," Review and Revise Abnormal Operations Sections of Operations Procedures," was ineffective in that the assessment did not determine that approximately 244 procedure changes associated with 113 operations procedures involved technical issues which needed to be addressed prior to restart or prior to the next time the procedure was used (Section O.1).
The inspectors determined that operations personnel did not meet the guidance in NRC
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Emergency Preparedness and Radiation Protection Branch Position (EPPOS) No. 2,
" Timeliness of Classification of Emergency Conditions," for declaration of the January 6, 1999, NOUE. Specifically, operations personnel declared the NOUE 26 minutes after the initiation of the LOOP even though the guidance in NRC EPPOS No. 2 specified that event declaration should occur within 15 minutes. Additionally, expectations for the
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timeliness in declaring emergency action levels in response to events were not specified in procedures for preparing and conducting emergency exercises (Section 01.1).
The inspectors identified operator knowledge weaknesses regarding the interlocks
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associated with the 4160V vital bus feeder breakers (Section 01.1).
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.The inspectors determined that in most cases, the annunciator response procedures did
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not reference the Technical Specifications associated with the alarming condition (Section O3.1),
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The inspectors identified one Non-Cited Violation for the failure to translate design
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requirements into annunciator response procedures. Specifically, the design requirements for the operation of the 4160V 1 A1 main and reserve feeder breakers
' following a trip of the emergency diesel generator were incorrectly translated into Procedure 5060.01, " Alarm Panel 5060 Annunciators - Row 1" (Section 03.1).
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The inspectors concluded that the licensee did not log EDG starts or formally track
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lightly-loaded run times for each EDG which could result in the licensee failing to take necessary actions to ensure EDG reliability. One Non-Cited Violation was identified concerning this issue (Section O3.2).
Maintenance The inspectors determined that the licensee conducted a thorough evaluation and
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inspection of the Division IV nuclear system protection system battery after electrical maintenance personnel caused an accidental short circuit during maintenance on this battery (Section M1.2).
The inspectors determined that training and oversight of new molded case circuit
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breaker test personnel did not ensure that expectations for using the smallest gage wire during testing were implemented (Section M1.3).
The inspectors identified one violation, for which enforcement discretion was exercised,
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concerning the failure to perform late preventive maintenance items / tasks or process deferral requests prior to returning systems and components to an available status (Section M8.1).
The inspectors determined that the licensea's assessment of corrective action
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effectiveness for CSC Restart item V.1," Develop Process to Review Deferrals of Preventive Maintenance items," was not sufficiently critical to identify deficiencies associated with implementation of the deferral process for late preventive maintenance items. Consequently, CSC Restart item V.1 will remain open pending a review of the licensee's root cause analysis and corrective actions associated with implementation of the PM deferral process (Section M8.1).
Enaineerina The inspectors identified one Non-Cited Violation pertaining to the licensee's
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identification that design basis requirements had not been adequately translated into maintenance procedures and instructions involving the replacement of the Division I and 11 shutdown service water pump oil coolers. The licensee's corrective actions to review the generic implications of the Division I shutdown service water pump bearing failure on other large safety-related motors was timely and conservative (Section E4.1).
The inspectors identified one Non-Cited Violation for the failure to make a required
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10 CFR 50.72(b)(2)(iii) report to the NRC within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of discovery that the shutdown service water system would not have performed its intended safety functions (Section E4.1).
The inspectors determined that the licensee had resolved the concerns associated with
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CSC Restart Item IV.7," Resolve Emergency Diesel Generator Concerns" (Section E8.3).
Plant Support The inspectors determined that radiation protection personnel demonstrated
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conservative decision making by using a video camera and robot to minimize exposure to only 9 millirem during recovery of a radiography source (Section R1.1).
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Report Details Summarv of Plant Status The plant remained shut down during the inspection period. Major activities involved degraded voltage modifications, repair activities on the shutdown service water system, and response to a loss of offsite power (LOOP) on January 6,1999, which resulted in a Notice of Unusual Event (NOUE).
l. Operations
Conduct of Operations 01.1 Loss of Offsite Power Resul,in Notice of Unusual Event (NOUE)
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inspection Scoce (71707. 93702)
The inspectors observed and assessed the licensee's response to a NOUE involving a
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LOOP on January 6,1999.
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Observations and Findinas initial Conditions Power was being supplied to the vital busses via the emergency reserve auxiliary transformer (ERAT) which is fed by a 138 kv supply line. The reserve auxiliary
transformer (RAT), which is supplied by three 345 kv lines, was out-of-service. The non-vital buses were powered via a main power transformer back-feed lineup from the 345 kv source.
Sequence of events The sequence of events for major actions are as follows:
1:19 p.m.: A guy wire for an offsite 138 kv power line pole was pulled out of the ground which caused a fault condition. The fault condition resulted in a loss of the 138 kv supply line to the ERAT, which caused an under voltage condition on the vital buses.
Because the RAT was out of-service, all three emergency diesel generators (EDGs)
automatically started. The non-vital buses remained energized via a main power transformer back-feed lineup from the 345 kv source.
l 1:45 p.m.: The licensee declared an NOUE due to the loss of the ERAT and the l
unavailability of the RAT.
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2:13 p.m.: Operations personnel placed the reactor water cleanup (RT) system in the i
decay heat removal mode of operation.
I 2:43 p.m.: Operations personnel commenced restoration of the RAT.
4:00 p.m.: Operations personnel restored residual heat removal (RHR) train B to service in the shutdown cooling mode of operation.
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5:21 p.m.: Operations personnel completed loading of all three EDGs to resolve unloaded operation concerns.
5:49 p.m.: Operations personnel re-energized the RAT and commenced preparations to turnover to the oncoming shift.
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/:48 p.m.: Shift turnover was completed.
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9:32 p.m.: Operations personnel completed a parallel and transfer of the loads on the Division i EDG to the RAT.
10:10 p.m.: Operations personnel completed a parallel and transfer of the loads on the Division II EDG to the RAT.
11:06 p.m.: Operations personnel completed a parallel and transfer of the loads on the Division lll EDG to the RAT. The licensee terminated the NOUE.
Operator performance during event
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The inspectors determined that operations personnel appropriately classified tt e event.
Procedures were used in-hand and actions were accompanied by peer checks. Off-shift personnel responding to the event did not become a distraction and were effectively utilized. In most instances good three-way communication techniques were used.
Event critique The licensee initiated Condition Report (CR) 1-99-01-024 to investigate the LOOP event and an individual in the operations support organization was assigned the responsibility of conducting the root cause analysis associated with the CR. On January 7, the licensee conducted a critique with the operating crew to establish a sequence of events, i
identify activities that were considered effective / ineffective, and to asses.s whether or not the plant responded as designed. The inspectors determined that severalissues pertaining to the event were not discussed during the critique, including: off-normal procedures used during the event contained several long-stand.ng technical errors; the completion of a shift turnover delayed restoration of electrical power by approximately 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />; cumulative unloaded run times on the EDGs were not accurately tracked by operations personnel; the NOUE was not declared within 15 minutes after the LOOP event; completed off-normal procedure actions were not documented; operator knowledge of 4160 volt breaker interlocks was poor; the high pressure core spray (HPCS) pump low pressure alarm annunciated during the transfer of suct!on sources from the reactor core isoleSon cooling (RCIC) tank to the suppression pool; and, the shift manager / interim station emergency director did not approve notifications sent to the NRC. Even though several other issues associated with the event were discussed by the licensee during the critique, the inspectors determined that the number of
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inspector identified issues that were not discussed during the critique were reflective of
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On January 11, the inspectors questioned the director-operations regarding the lack of discussion during the critique on the issues noted by the inspectors and questioned why an event review team had not been initiated to evaluate the actions taken by the licensee. Following the discussion, the director-operations established an event review
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team to investigate the licensee's response to the LOOP event. The inspectors determined that initiation of the event review team was appropriate for ensuring that an effective assessment of the LOOP event was conducted.
Review of off-normal procedures As mentioned above, the inspectors determined that the off-normal procedures used during the event response contained severallong-standing technical errors. For example, Procedure 4200.01, "Los.s of AC Power," contained multiple data sheets 'with inaccurate information regarding the nomenclature of safety-related relays. In addition, certain relays were omitted from the data sheets and certain relays were specified on the data sheets which did not exist. The inspectors determined that in many cases, the technical inadequacies in this procedure had been known by operations personnel for 5 - 7 months but were not corrected.
The inspectors reviewed the backlog of comment control forms (CCFs) for the remaining off-normal procedures and determined that the licensee had not incorporated multiple changes to resolve technicalinadequacies in plant procedures. Examples included: (1) CCF 1997-3334: The generic actions and actions for a loss of the non-vital buses are not adequate for a RAT loss, (2) CCF 1998-1975: If temperature is less than 32 degrees Fahrenheit ( F), the common shutdown service water backwash line could freeze. This common mode failure can be prevented by running the backwash continuously using the above freezing water to keep the piping from freezing, and (3) CCF 1998-1752: A caution statement needed to be added to the associated procedure indicating that starting the EDG will automatically start emergency core cooling pumps resulting in a water hammer.
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Following a discussion concerning the inspectors' observations, the licensee initiated a review of the procedure backlog in an effort to identify technical issues which needed to be incorporated into plant procedures. The backlog of procedure change requests included approximately 3,000 CCFs and 100 CR action items. As of February 12, the licensee had identified 244 technical procedure changes affecting 113 operations procedures which needed to be incorporated prior to restart or prior to the next use of the procedure. As of February 16, the licensee had identified 66 technical procedure changes affecting 48 maintenance procedures which needed to be incorporated prior to restart or prior to the next use of the procedure.
The licensee's failure to ensure procedures were technically adequate to support startup was of particular concem in that the licensee had briefed the inspectors in December 1998 on their readiness to close CSC Restart Item II.3, " Review and Revise Abnormal Operations Sections of Operations Procedures." Given the licensee's ineffective assessment of corrective actions regarding the review of procedures for technicalinadequacies, CSC Restart item II.3 will remain open pending the compietion of the licensee's procedure backlog evaluation and the assessment of the impact of the backlog on plant restart.
Automatic isolation valve checklist The inspectors and the licensee identified examples of automatic valve isolations that occurred during the LOOP event. However, Procedure 4002.01, " Automatic isolation,"
and Procedure 4200.01," Loss of AC Power," did not provide clear guidance for
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operations personnel on expected valve isolations during a LOOP event. In addition, the procedures did not specify all the loads that were shunt tripped on a momentary loss of power or that tripped on a second level under voltage signal. The licensee planned to implement procedure revisions to address the concerns with insufficient guidance regarding automatic valve isolations and devices which are expected to receive a shunt trip.
Effectiveness of shift turnover The inspectors observed that the completion of shif t turnover during the restoration of offsite electrical power created a delay of approximately 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> in the parallel and transfer of loads from the EDGs to the RAT. The licensee stated that the restoration of the required AC sources was conducted in a controlled manner in that the off-going and on-coming shift managers did not want the turnover to be a distraction to the safe completion of the recovery of AC sources, the shift managers wanted a fresh crew to continue the recovery efforts, and the plant was in a stable condition for conducting the turnover. In addition, the licensee stated that the manner in which the on-station shift turnover was conducted was not efficient and that enhancements to the process were warranted.
Emergency preparedness issues The inspectors determined that the NOUE was not declared until 26 minutes after the initiation of the LOOP event. The inspectors determined that the delay in the event declaration was not consistent with the guidance in NRC Emergency Preparedness and Radiation Protection Branch Position (EPPOS) No. 2, " Timeliness of Classification of Emergency Conditions." The EPPOS No. 2 guidance specified that 15 minutes is a
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reasonable period of time for assessing and classifying an emergency condition once indica: ions are available to control room operators that an emergency action level has been exceeded. The licensee stated that the delay in event declaration occurred due to the priorities of accident mitigation and response. Specifically, the shift manager did not review the event classifications until he was satisfied that the plant was in a stable condition and that control room personnel were responding appropriately. The inspectors determined that the shift technical advisor and shift resource manager were available to review the action levels but were not utilized in addition, the inspectors cetermined that expectations for declaring events within 15 minutes were not specified in Procedure AP-04,' Preparation and Conduct of Emergency Drills and Exercises."
The inspectors determined tnat the Shif(.nanger had not approved notifications sent to the NRC operations center during the event. The licensee stated that no procedural requirements existed which mandated tha'ine event notification forms be approved by the shift manager; however, shift managers were expected to approve notifications sent to the NRC. The licensee, based on its review of the event, determined that the emergency communicator thought that the hourly updates to the NRC were unofficial r;otifications and therefore, did not require shift manager approval. Additionally, the communicator considered the verbal communications to the NRC to also be informal.
The inspectors concluded that the lack of a review of event notifications by the shift manager contributed to the transmission of inaccurate information to the NRC which specified that fuel pool cooling was in operation when it had been secured. Corrective actions planned by the licensee included training operations personnel on communications and notifications to offsite agencies.
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Documentation of completed actions in main control room journal l
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Tne inspectors determined that the completion of actions taken in accordance with off-normal procedures were not documented in the main control room journal. The licencee also determined that log keeping during the event was marginal and that the legibility of the logs was poor. The corrective actions for log keeping practices during the NOUE were incorporated into CR 1-98-12-279 which was initiated in response to NRC concerns regarding entries.a the main control room journal (See NRC Inspection Report 50-461/98020).
Operator knowledge issues During the event, the inspectors observed that operations personnel were not knowledgeable of the 4160V breaker engineered safety feature interlocks and the operation of the offsite source oermissive push button. Specifically, operations personnel were not aware of the breaker interlocks associated with the RAT, ERAT, and EDG feeder breakers to the 4160V vital busses. The licensee initiated correctiva actions to develop and provide training to operations personnel on the operation of the breakers.
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Conclusions The inspectors determined that operations personnel responded appropriately to the LOOP event and NOUE declaration. Procedures were used in-hand and peer checks were frequently conducted. Three-way communication techniques were good. Off-shift
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personnel were effectively utilized without becoming a distraction to the operating crew.
The inspectors' determined that the licensee's initial critique of the LOOP event was not sufficiently critical to identify issues involving operator knowledge weaknesses, procedure discrepancies, timeliness of event declaration, and delays in the shift turnover process. Following discussions with the inspectors, the licensee initiated an event review team and conducted an effective assessment of the issues and concerns.
The inspectors determined that the licensee's review of procedures to support closure of CSC Restart item 11.3 was ineffective in that the assessment did not determine that approximately 244 procedure changes associated with 113 operations procedures involved technical issues which needed to be addressed prior to restart or the next time the procedure was used.
The inspectors determined that operations personnel did not meet the guidance in NRC EPPOS No. 2 for declaration of the January 6,1999, NOUE due to a LOOP.
Specifically, operations personnel declared the NOUE 26 minutes after the initiation of the LOOP even though the guidance in NRC EPPOS No. 2 specified that event declaration should occur within 15 minutes. Additionally, expectations for the timeliness in declaring emergency action levels in response to events were not specified in procedures for preparing and conducting emergency exercises. The inspectors also identified operator knowledge weaknesses regarding the interlocks asweiated with the 4160V vital bus feeder breakers.
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Operations Procedures and Documentation O3.1 Review of Off-Normal Procedures a.
Insoection Scope (71707)
The inspectors reviewed 6 off-normal procedures and 12 annunciator response procedures for technical accuracy and to determine if the guidance in the procedures reflected conservative decision-making. The review excluded an evaluation of open CCFs.
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Observations and Findinas Off-normal Procedures The following Off-Normal Procedures were reviewed:
4001.01, " Reactor Coolant Leakage" 4004.01," Instrument Air Loss" 4005.01," Loss of Feedwater Heating" 4007.02, " Inadvertent Rod Movement" 4008.01, " Abnormal Reactor Coolant Flow" 4009.01," inadvertent Opening Safety / Relief Valve" The inspectors did not identify any significant issues with conservative decision-making or the technical adequacy of off-normal procedures.
Annunciator Response Procedures The inspector reviewed the following annunciator response procedures:
Procedure 5013.05, Window SD, "High liigh Level Fir / Equip Drn Sump-Aux Bldg" Procedure 5042.02," Alarm Panel 5042 Annunciators - Row 2" Procedure 5050.02," Alarm Panel 5050 Annunciators - Row 2" Procedure 5060.01," Alarm Panel 5060 Annunciators - Row 1" Procedure 5062.06, " Alarm Panel 5062 Annunciators - Row 6" Procedure 5063.02, " Alarm Panel 5063 Annunciators - Row 2" Procedure 5063.08, " Alarm Panel 5063 Annunciators - Row 8" l
Procedure 5064.02, " Alarm Panel 5064 Annunciators - Row 2" l
Procedure 5066.03, " Alarm Panel 5066 Annunciators - Row 3" l
Procedure 5068.01,-" Alarm Panel 5068 Annunciators - Row 1"
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Procedure 5067.02, " Alarm Panel 5067 Annunciators - Row 2" l
Procedure 5067.07, " Alarm Panel 5067 Annunciators - Row 7" Procedure 5063.08, " Alarm Panel 5063 Annunciators - Row 8"
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The following concerns were identified:
In most cases, the annunciator response procedures did not reference the TS associated with the alarming condition. The licensee stated that previous changes to
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the annunciator response procedures to incorporate the applicable TS reference were
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narrowly focused and initiated CR 1-99-02-171 to resolve the concern.
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Procedure 5013.05, Window SD,"High High Level Fir / Equip Drn Sump-Aux Bldg," did l
not specify that flooding in the auxiliary building steam tunnel could cause the I
annunciator to alarm. The licensee agreed with the inspectors observation and initiated a CCF to enhance the procedure.
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Procedure 5050.02, Window 28, " Loss of CONT PWR VD System Division I," was poorly human factored in that the automatic actions section directed that specific functions be accomplished which would require the use of equipment which had been disabled. The licensee initiated a CCF to restructure the procedure to specify how actions which involved disabled equipment would be accomplished and which actions were automatic.
Procedure 5052.02, Window 2M," Auto Start Cont Room HVAC M-U Air Fan B,"
specified high airbome contamination as a possible cause. However, the procedure did not include a reference to Emergency Operating Procedure 9," Radioactivity Release Control." The licensee initiated a CCF to enhance the procedure.
Procedure 5060.01, Window 1B, " Auto Trip Breaker," specified that the automatic action for an EDG output breaker trip during an EDG trip or under voltage condition was an automatic closure of the 4160V bus 1 A1 main breaker or the 4160V bus 1 A1 reserve breaker if the main breaker was unavailable. The licensee informed the inspectors that the actual EDG design was that closure of either the main breaker or the reserve breaker required the operator to press the offsite source permissive pushbutton within 15 seconds of an EDG trip and that this was not accurately translated into the procedure, Criterion lli of Appendix B to 10 CFR Part 50 requires that measures shall be established to ensure that the design basis is correctly translated into procedures.
The failure to ensure the operation of 4160V 1 A1 main and reserve breakers was correctly translated into Procedure 5060.01 is a violation of Criterion til of Appendix B to
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10 CFR Part 50. This Severity Level IV violation is being treated as a Non-Cited Violation consistent with Appendix C of the NRC Enforcement Policy (NCV 50-461/99002-01). The licensee initiated immediate revisions to correct Procedure 5060.01, Window 18. In addition, the licensee planned to develop and implement training for operations personnel on the operation of the 4160V EDG and 1 A1 main and reserve feed breakers.
Procedure 5068.01, Window 1 A, "CNMT FLOOR DRAIN SUMP LEAKAGE HIGH," did not specify that the failure of the discharge check valve of the non-running containment floor drain sump pump could cause water from the running containment floor drain sump pump to be returned to the sump resulting in an annunciation of the alarm. The licensee concurred with the inspectors observation and initiated a CCF to enhance the procedure.
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Conclusions
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The inspectors determined that in most cases, the annunciator response procedures did
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not reference the TS associated with the alarming condition, in addition, one Non-Cited Violation was identified for the failure to translate design requirements involving
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operation of the 4160V 1 A1 main and reserve feeder breakers following a trip of the EDG into annunciator response procedures.
O3.2 Review of Emeraency Diesel Generator Loos a.
Inspection Scoce (71707)
The inspectors conducted a review of Procedure 3506.01, " Diesel Generator and Support Systems," and EDG logs to ensure that valid start attempts and cumulative lightly-loaded run times were being tracked.
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Observations and Findinas The licensee did not log 24 EDG starts between May 1,193 and January 29,1999. In addition, the inspectors identified several inconsistencies with u..T.pete ' EDG start logs that included: the licensee did not complete all required information, shii management
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did not review computer generated logs, and the system manger did not rt. view EDG start logs within 5 days. The licensee confirmed the inspectors' observations and initiated CR 1-99-02-005 to address these issues.
Technical Specification 5.4.1.a requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Appendix A," Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors," of Regulatory Guide 1.33," Quality Assurance Program Requirements,"
Revision 2, dated February 1978. Section 1 of Appendix A to Regulatory Guide 1.33, recommends administrative procedures for log entries. Section 8.3.2 of Procedure 3506.01 specified, in part, that the EDG start fog be completed for any start or attempted start of the EDG, including automatic or unplanned starts. The inspectors determined that the failure to log all attempts to start an EDG was a violation of TS 5.4.1.a. This Severity Level IV violation is being treated as a Non-Cited Violation consistent with Appendix C of the NRC Enforcement Policy (NCV 50-461/1999002-02).
This violation is being tracked in the licensee's corrective action program as CR-1-99-02-005.
Section 4.0 of Procedure 3506.01 stated, in part, that the EDG should be loaded to greater than 75 percent of fullload whenever possible. Operation under light load (ksss than 20 percent full load) should be minimized to reduce turbo charger gear train wear and to prevent buildup of fuel oil and lube oil in the exhaust (wet stacking). After cumulative lightly-loaded operation at synchronous speeds for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or idle speed for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, the EDG should be loaded to a minimum of 40 percent of fullload for at least 30 minutes before shutdown.
The inspectors determined that the licensee did not formally track the EDG cumulative lightly-loaded run time. The system manager had been informally tracking the lightly-loaded run time from the diesel generator start logs and would advise operations personnel when the cumulative lightly-loaded run time approached 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. However, operations personnel were only cognizant of the lightly-loaded run time during each EDG run. The inspectors determined that without formal tracking, the potential existed to exceed the 4-hour cumulative lightly-loaded run time due to successive EDG starts.
On February 9,1999, the director-operations stated that procedures would be revised to
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ensure EDG start logs were completed and to improve the ability of operations personnel to track cumulative lightly loaded run hours for each EDG, c.
Conclusions The inspectors concluded that the licensee did not log EDG starts or formally track lightly-loaded run times for each EDG which could result in the licensee failing to take necessary actions to ensure EDG reliability. One Non-Cited Violation was identified concerning this issue.
Miscellaneous Operations issues (92901)
08.1 { Closed) Licensee Event Report 50-461/99-002: Offsite faults on inservice offsite electrical supply line causes LOOP to safety-related busses. The inspectors onsite review of Licensee Event Report (LER) 50-461/99002 was conducted during the assessment of the events described in Section 01.1.
i 11. Maintenance
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M1 Conduct of Maintenance M1.1 General Comments (61726. 62707)
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Portions of the following maintenance and surveillance activities were observed or reviewed by the inspectors:
Procedure 8410.04 Molded Case Circuit Breaker Component Functional Testing and Maintenance Procedure 8528.01 SSW Pumps A & B Motor Maintenance Procedure 9080.14 Diesel Generator 1C 24-Hour Run and Hot Restart Procedure 9382.15 Division IV 125 Vdc Battery Service Test MWO C981214025 Install Control Room ERAT SVC Controls AR FO9728 MCCB Functional Test and Maintenance AR FO9569 EDG Outboard Bearing Oil Usage During 24-hour Run AR FO9745 Metal Cover Dropped Across Battery Terminals AR FO4489 Repair SX Pump 1 A Motor The inspectors determined that observed activities were conducted with the procedure present and in active use. Specific observations pertaining to these maintenance and surveillance activities are discussed in Sections M1.2 and M1.3 of this report.
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M1.2 Division IV Nuclear System Protection System Battery a.
Inspection Scope (62707. 61726)
The inspectors reviewed the licensee's actions in response to a short circuit on the Division IV nuclear system protection system (NSPS) battery caused by maintenance activities.
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Observations and Findinas On January 22,1999, electrical maintenance (EM) personnel accidentally placed a metal cover across the terminals of the master load unit which was connected to the Divi.:on IV NSPS battery. The resulting short circuit caused a 5000 amp discharge for approximately 45 seconds. The event terminated when EM personnel dislodged the metal cover.
The licensee and the manufacturers' representative conducted a physical examination of the Division IV NSPS battery. The examination included the battery cell plates, connection points between the cell plates, cell connectors, and mounting hardware.
Following the examination, the licensee and the manufacturers' representative d9veloped a thorough action plan for repairing, recharging, and testing the battery. On February 3,1999, the inspectors observed testing on the Division IV NSPS battery. No abnormal indications were observed during the test.
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Conclusions The inspectors determined that the licensee conducted a thorough evaluation and inspection of the Division IV NSPS battery after EM personnel caused an accidental short circuit during maintenance on this battery.
M1.3 Molded Case Circuit Breaker Testina Observations a.
Inspection Scope (61726)
The inspectors observed molded case circuit breaker (MCCD) testing.
b.
Observations and Findinas
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On January 26,1999, the inspectors observed MCCB testing conducted in accordance l
with maintenance Work Order C990107015 and Procedure 8410.04, " Molded Case
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Circuit Breaker / Bucket Component Functional Testing and Maintenance." The inspectors observed an EM use 4/0 gage wire to connect a 15-amp MCCB to the test gear. The licensee typically used 4/0 gage wire to connect 220-amp breakers to the test gear. The EM stated that the instantaneous trip test value for the MCCB was 1875 amps and that a large wire was needed to carry the current.
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The inspectors documented a similar instance of the use of large MCCB test wire sizes
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in NRC Inspection Report 50-461/98011. Engineering personnel determined that using larger gage wire would shif t the tested values in a conservative manner. However, the EM supervisor had stated that the smallest wire size above the specified size would be
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used so that a table could be developed for use with the specific test gear. The use of
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the smallest wire size was intended to ensure repeatable tests for trending and comparison purposes.
The EM supervisor stated that the EM had recently been qualified to conduct MCCB testing but had forgotten the verbal instructions to use the smallest wire that would test the MCCB. The EM supervisor. stopped work and retrained the EM personnel before restarting MCCB testing, c.
Conclusions The inspectors determined that training and oversight of new MCCB test personnel had not been adequate to ensure expectations for the use of the smallest gage wire during
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testing were implemented.
M8 Miscellaneous Maintenance issues M8.1 (Open) Case Specific Checklist Restart item V.1. "Develoo Process to_ Review Deferrals of Preventive Maintenance Items" The inspectors reviewed the licensee's submitted closure package for CSC Restart item V.1," Develop Process to Review Deferrals of Preventive Maintenance items."
Scheduling and deferral of preventive maintenance (PM) items was consideced a
weakness by the independent safety assessment (ISA) team and the NRC special
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evaluation team (SET). The ISA and SET teams determined that: PM deferrals were not submitted to allow enough time for engineering personnel to process the request prior to exceeding the late date, engineering personnel did not provide adequate technical justification for the PM deferrals, plant procedures did not provide sufficient guidance on processing deferrals, and several PM items / tasks were inappropriately credited for meeting part or all of TS surveillance requirements (SRs).
Following the ISA and SET inspections, the licensee and inspectors continued to identify examples of late PM items / tasks without deferrals, multiple enmples of TS SRs conducted within the plus 25 percent grace period, and PM task scheduling errors which resulted in TS violations.
Licensee initiated corrective actions The licensee completed a review of all safety-related PM items / tasks to ensure that they had either been completed or had deferrals dispositioned in accordance with Procedure 1034.01," Preventive Maintenance.orogram." The licensee determined that PM deferrals were processed in a timely manner, that a cumulative effect review had been conducted by engineering personnel, and that deferral justifications were conducted using the guidance in Procedure M.02," Review of Preventive Maintenance Documents."
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The licensee developed performance indicators to aid in the review of the PM item backlog. Work management personnel conducted daily reviews of PM and TS SR activities to ensure items either did not exceed the scheduled late date or that the
appropriate deferral justification was completed. The performance indicators also projected PM activities that would be completed following the due date or late date.
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Performance indicators were discussed weekly during the daily leadership meeting and monthly during the performance indicator meeting.
The licensee assigned additional personnel to aid in scheduling and tracking of PM items / tasks and TS SR activities. Additionally, a data base for tracking PM items / tasks was created to aid in the identification of PM items / tasks with the potential to exceed the assigned due or late date. Preventive maintenance items used to satisfy TS SRs were identified and placed in the surveillance tracking system. Procedure 1011.06, " Routine Surveillance Tracking and Scheduling," was revised to address monitoring of PM items / tasks used to satisfy TS SRs.
The licensee indicated that changes to the PM and TS SR scheduling processes had been effective in that no new CRs had been initiated since July 1998 involving late PM items / tasks or missed PM deferrals, performance indicators were regularly utilized, and a completed audit of PM deferrals in November 1998 only identified 39 out of 790 PM deferral requests which did not have adequate engineering justification. Following the audit, the licensee initiated CR 1-98-11-278, revised the affected deferrals, and provided training to engineering personnel on the deferral process.
Between July and September 1998, the licensee failed to perform three required TS SRs due to scheduling errors and inadequate software management (see LERs 50-461/98022,50-461/98024, and 50-461/98027). The licensee initiated several corrective actions in response to the LERs, which included, training personnel on self-checking, changing plant procedures to require that changes to computer generated reports be validated and verified prior to use, and increasing the work management staff.
Inspectors' review of corrective actions The inspectors determined that the licensee's evaluation of CR 1-98-11-278 did not result in identifying the cause associated with the inadequate engineering justifications which were identified in the November 1998 audit. The licensee stated that even though the CR did not addrnss the cause of the inadequate justifications, the corrective action to conduct training ior engineering personnel, which included supervisors completing the deferral review, was sufficient to address this issue. In addition, following a discussion with the inspectors in February 1999, the licensee provided the training required in CR 1-98-11278 to work management personnel involved in the PM deferral process.
The inspectors reviewed approximately 15 safety-related or maintenance rule component PM deferrals submitted in December 1998 and January 1999 and identified 6 examples of inadequate engineering justifications. In each case, the PM deferral was processed by an engineer prior to attending the training described in CR 1-98-11-278.
The inspectors compared a list of system engineering personnel to the attendance list for PM deferral training attached to CR 1-98-11-278 and identified that 6 out of approximately 40 system engineers had not attended the training. Work management personnel stated that a review would be conducted to ensure the affected engineers did not process PM defenals until they had received the requisite training.
The inspectors identified that Procedure 1034.01 did not reference the guidance engineering personnel were to implement in Procedure M.02 while completing and
processing a PM deferral. The licensee initiated a revision to Procedure 1034.01 on January 30,1999, to include a reference to Procedure M.02.
Section 8.2.4 of Procedure 1011.06 specified, in part, that a senior reactor operator (SRO) will provide written concurrence for changes to the surveillance data base and that the concurrence may occur after the change has been implemented so as not to impede work activities. The inspectors determined that the timeliness of the SRO review was not prescribed in Procedure 1011.06. On January 28,1999, the inspectors reviewed eight surveillance data base changes processed in December 1998 and January 1999 and determined that four of the changes had not received written concurrence by an SRO. The changes to the surveillance data base were submitted on December 15 and 22, and January 7. Additionally, the four remaining surveillance data base changes were initiated by work management on December 7,1998, but not approved by an SRO until December 23,1998. On February 11, work management personnel stated that the SRO review of the surveillance data base cnanges had not always been timely, that the change sheets had all been approved, and that additional resources had been assigned to ensure future changes would be processed in a timely manner.
Technical Specification 5.4.1.a requires that written procedures be established, implemented, and maintained covering the activities recommended in Appendix A to RG 1.33. Appendix A of Regulatory Guide 1.33 recommends that the licensee have procedures for performing maintenance activities. Section 8.6.6.1.3 of Procedure 1034.01 specified that prior to returning systems or components to servi. or declaring them operable or available, late PM items / tasks required for operability shall be scheduled and completed. For PM items / tasks which cannot be completed, a deferral must be submitted and approved prior to declaring the system or component operable or available. On February 3,1999, the inspectors identified three instances where the licensee credited the use of systems and components to support key safety functions even though late PM items / tasks had not been completed and a PM deferral had not been processed.
In January 1999, the licensee credited the availability of the plant service water
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system as a method of reducing shutdown risk when the shutdown service water system was inoperable. However, four late PM items / tasks associated with the system had not been completed and an engineering justification for deferral of the items was not conducted because the licensee had previously determined that the plant service water system was not required for the current mode of operation.
On January 31,1999, the licensee approved the deferral of PM items / tasks for
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the inservice 480 volt unit substation 1 AP18E involving orotective relaying without an engineering justification. The licensee had previously determined that i
deferral of the item did not need to be justified because it was not required for the current mode of operation. The inspectors determined that the licensee did a
not assess the impact of a fault condition in conjunction with a failure of the j
protective relays. The licensee subsequently determined that a failure under fault conditions could interrupt electrical power to the reactor water cleanep pumps being used to provide an alternate method of decay heat removal.
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On February 3,1999, the inspectors determined that the engineering justification
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for PM deferral 99-0005 had not been processed for switchyard breaker 4518.
The inspectors determined that the switchyard breaker was in service even though breaker PM items had not been completed. The licensee initially stated that an engineering justification was not needed because switchyard breakers are not required to be operable or available per the TS. Following the inspectors review, the deferral was returned to engineering for revision.
The inspectors determined that the failure to perform late PM items / tasks or process deferrals for late PM items / tasks prior to returning systems and components to an
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available status was a violation of TS 5.4.1.t However, because this violation was based upon activities prior to the events leading to the current extended plant shutdown and satisfies the criteria in Section Vll.B.2," Violations identified During Extended Shutdowns or Work Stoppages," of the " General Statement of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (NCV 50-461/99002-03).
On February 4,1999, the licensee initiated level-3 CR 1-99-02-088 to review the existing status of late PM items / tasks originally considered by the licensee not to be required to support the current mode of plant operation. During the review of CR 1-99-02-088, the licensee determined that four plant service water PM items / tasks and two breaker PM items / tasks were necessary to support current plant operations and initiated a maintenance activity to perform the late PM item or processed a PM deferral.
On February 11, the inspectors questioned work management personnel as to why 36 late PM items / tasks for in-service components affecting the switchyard, circuit breakers, main power transformers, traveling screens, and plant service water system had not been conducted or why a PM deferral had not been processed. Work management personnel stated that the assessments of late PM items / tasks following the inspectors'initialidentification of the issue had been narrowly focused and did not involve the appropriate level of engineering review to disposition the issue. The licensee subsequently upgraded CR 1-99-02-088 to level-2 in order to perform a root cause analysis and reinitiated a review of the late PM items / tasks for in-service systems and components. On February 12, the licensee determined that 27 of the 36 PM items / tasks identified by the inspectors were required to support the current mode of operation and initiated actions to perform the late PM items / tasks or process a PM deferral.
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The inspectors determined that the licensee's assessment of corrective action effectiveness for CSC Restart item V.1 and CR 1-99-02-088 was not sufficiently critical i
to identify deficiencies associated with implementation of the deferral process for late
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PM items / tasks. Specifically, the licensee's effectiveness review did not identify that engineering personnel were not trained, that Procedure 1034.01 did not reference Procedure M.02, that SRO reviews of surveillance data base changes were untimely, and that PM deferrals had not been processed for PM items / tasks necessary to support l
the current mode of plant operation. Consequently, CSC Restart item V.1 will remain open pending a review of the licensee's root cause analysis and corrective actions
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associated with implementation of the PM deferral process.
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111. Enaineerina E4 Engineering Staff Knowledge and Performance E4.1 Shutdown Service Water Bearina Failure a.
Inspection Scope (37551. 62707)
The inspectors reviewed the licensee's corrective actions in response to high vibration readings on the Division i shutdown service water (SX) pump during the performance of Procedure 9069.01, " Shutdown Service Water Operability Test."
b.
Observations and Findings On January 9,1999, the licensee recorded high vibration levels during Division i SX pump periodic testing and initiated CR 1-99-01-062. On January 12, the licensee declared the Division i SX pump inoperable due to the vibration readings exceeding the allowable value and because oil sample results indicated a bearing failure. Previous oil sample results and vibration data for the Division i SX pump had not indicated a developing problem.
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The licensee and vendor representative conducted an inspection of the Division i SX pump and determined that the upper guide bearing was severely damaged, the upper
'hrust block was extensively pitted, the lower roller bearings were pitted, and the thrust bearing thermocouple case was bent and had contacted both the thrust bearing and the conduit in the motor frame. The licensee and the vendor representative stated that the cause for the beming damage was shaf t current through the bearings due to metal to metal contact of the thermocouple case between the motor frame and thrust bearing.
Following restoration of the Division l SX pump, the licensee conservatively decided to inspect the Division 11 SX pump and evaluate the condition of all other large motors. On January 23, the licensee measured a resistence of 0.7 ohms from the upper guide bearing to ground on the Division Il SX pump motor. The resistence measurement indicated that the Division 11 SX, pump was susceptible to the same failure mechanism as the Division i SX pump. Based on further inspection of the Division ll SX pump, the licensee identified pitting of the thrust plate, damage to the upper guide bearing, a breakdown in the insulation between the thermocouple casing and motor frame, and metal to metal contact between the thermocouple casing and the motor frame. In November 1998, oil samples from the Division 11 SX pump revealed a tin concentration in the alert range. Vibration, pressure, and flow data were still within allowable values.
The licensee's corrective actions involved a change in the frequency of oil sampling from once per 18 months to once per 6 months.
l ne licensee determined that the fault condition was probably introduced during the replacement of the SX pump oil coolers in November 1996 and January 1997.
Specifically, the maintenance packages used to install the new oil coolers had not directed checking the resistance to ground from the upper bearings to ensure the thermocouples did not create a grounding path. At the time of the maintenance activities, checking whether or r ot the thermocouples would provide a ground path was considered a " tool box" skill (i.e., skill of the craft).
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Criterion lli of Appendix B to 10 CFR Part 50 requires,in part, that measures be established to assure that the design basis is correctly translated into specifications, drawings, procedures, and instructions. m addition, Criterion lil specifies that appropriate design control measures ba applied to items such as maintenance and
repair activities. The inspectors determined that the failure to ensure the absence of a path to ground from the upper bearings, af ter maintenance activities to replace the Division I and 11 SX pump oil coolers, was a violation of Criterion 111 of Appendix B to 10 CFR Part 50. However, this non repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-461/99002-04).
The normal expected running life time for the SX pump motors was between 60,000 and 70,000 houro. The Division l SX pump had run about 667 hours0.00772 days <br />0.185 hours <br />0.0011 weeks <br />2.537935e-4 months <br /> following replacement of the oil cooler. The inspectors determined that the Division I SX r/mp had failed in less than the design basis run time of 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> specified in Updated Safety Analysis Report Sections 6.2, " Containment Systems," 9.2.1.2, " Shutdown Service Water System," and 9.2.5, " Ultimate Heat Sink."
The Division ll SX pump had run approximately 1600 hours0.0185 days <br />0.444 hours <br />0.00265 weeks <br />6.088e-4 months <br /> af ter replacement of the oil cooler. The licensee determined that the fault condition probably did not exist at the time of the cooler replacement. However, the licensee believed that the fault condition probably existed at the time of the oil sample in November 1998. The Division ll SX pump had operated for approximately 192 hours0.00222 days <br />0.0533 hours <br />3.174603e-4 weeks <br />7.3056e-5 months <br /> following the collection of the November 1998 oil sample. On January 27, the licensee informed the inspectors that there was reasonable doubt that the Division il SX pump would have operated for 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br />.
10 CFR Part 50.72(b)(2)(iii) requires that a report be made within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of the time of discovery of any event or condition that alone could have prevented the fulfillment of the safety function of systems that are needed to remove residual heat and mitigate the consequences of an accident. On January 29, the inspectors quectioned the licensee as to why a potential common failure mechanism, which would have prevented the fulfillment of the SX system safety function, had not been reported. The licensee stated that it had not considered the requirement to report the condition before the inspectors'
inquiry. The licensee subsequently agreed that the condition was reportable and made a 4-hour report to the NRC. Additionally, the licensee initiated CR 1-99-02-242 and used the circumstances surroundir.g the failure to make the appropriate 50.72 report for the SX pump condition as a lessons learned for licensee personnel. The inspectors determined that the failure to make the required report within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of discovery that the SX system could not have performed its intended safety functions was a violation of 10 CFR 50.72(b)(2)(iii). This Severity Level IV violation is being treated as a Non-Cited Violation consistent with Appendix C of the NRC Enforcement Policy (NCV 50-461/1999002-05). This violation is beMg tracked in the licensee's corrective action program as CR-1-99-02-242.
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Conchsions The inspectors identified one Non-Cited Violation pertaining to the licensee's identification that design basis requirements had not been translated into maintenance procedures and instructions involving the replacement of the Division I and il SX pump oil coolers, in addition, the inspectors identified one Non-Cited Violation for the failure of
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I the licensee to make a required 10 CFR 50.72(b)(2)(iii) report to the NRC withia 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of discovery that the SX system would not have performed its intended safety function.
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E8 Miscellaneous Engineering lasues (92903)
i E8.1 (Closed) Violation 50-461/95003-01b: This violation involved the failure to ensure that a condition adverse to quality, hardening of grease in 480V Asea Brown Boveri (ABB)
K-Line breakers, was promptly identified and corrected. The NRC also documented
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violations relative to inadequate corrective actions taken to address breaker failures due
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- to degraded lubricants in NRC Inspecticn Raport 50-461/97003(DRS).
As of January 7,1999, the licensee completed the following corrective actions to address the concern associated with the 480V K-Line breakers:
(1)
All 33 480V safety-related ABB K-Line circuit breakers were refurbished by the end of 1998. Tests conducted on the refurbished K-Line breakers included detailed receipt inspection per the 480V ABB breaker standard receipt inspection
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checklist and post-maintenance testing, which involveo energizing the loads associated with the breakers. All refurbished breakers had been functionally tested satisfactorily prior to placing them in service.
(2)
Of the 196 nonsafety related ABB K-Line 480V circuit breakers,86 were
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classified critical or "important to plant operation." The licensee planned to l
replace or refurbish 53 of the 88 breakers prior to plant restart. The licensee stated that the remaining 35 critical breakers will be dono after plant restart. In
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addition,71 new breakers were received to augment the pool of spare breakers.
These breakers were being used to facilitate the refurbishment effort.
(3)
The licensee improved the breaker lubrication program and breaker PM procedures and associated training was provided to maintenance staff. The licerisee also revised PM procedures to incorporate the Special Investigation Team recommendations made following the 4160V breaker failure in August 1997.
(4)
To provide better focus on breaker issues, the licensee re-established the breaker team. The team developed and implemented a breaker issue resolution plan to monitor and trend breaker performance and provide better technical and management oversight of breaker activities.
The inspectors reviewed the licensee's corrective actions and p!ans to address the degraded breaker lubrication issues and considered them acceptable.
E8.2 (Closed) Unresolved item 50-461/95003-03: This unresolved item concerned an example of ineffective resolution of a design problem that resulted in a breaker malfunction. The design problem involved the failure to includo a resistor in series with the breaker position indicating lights on eighteen 480V main femd breakars.
The electrical design drawings showed the correct resistor type breaker indicating light units; however, the licencee had incorrectly installed non-resistor type indicating lights during construction. The concern was that when a breaker indicating light bulb shorted out during bulb replacement, a full voltage developed across the trip coil due to lack of a
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series resistor and caused the breaker to trip. Of the 18 main feed breakers affected by this condition,4 were safety-related. Plant modification APF 010, dated March 1995, was initiated to replace the existing 18-breaker position indicating lights with GE type
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ET-16 models. Modification APF 010 partials #1,9 and 10, using MWRs D27561
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through D27564, were completed and post-modification testing was conducted I
successfully on January 1,1997. No enforcement concerns were identified by the
inspectors during the review of this issue.
E8.3 (Closed) Licensee Event Report 50-461/98-037: Surveillance procedure did not properly implement calibration requirements for drywell and p rimary containment l
hydrogen and oxygen analyzers. During a review of the TS, the licensac identified that
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TS SR 3.3.3.1.2, which involved performing a channel calibration of the drywell and
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primary containment hydrogen and oxygen analyzers every 92 days, was not properly
implemented. The licensee had been crediting a periodic self-calibration of the
analyzers to satisfy the TS SR; however, the self-calibration did not include the main I
control room indication. The licensee determined that the cause of the event was a lack I
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of information validation and verification.
Technical Specification 3.3.3," Post Accident Monitoring Instrumen'.ation," requires that l
the post accident monitoring instrumentation be operable while in Modes 1 and 2.
l Tet anical Specification SR 3.0.1 states that SRs shall be rn,t during applicable modes for each individual limiting condition for operation unless otherwise stated and that the failure to meet a SR shall be a failure to meet the limiting condition for operation.
Technical Specification SR 3.3.3.1.2 requires that the licensee perform a channel calibration every 92 days. The failure to puform the required channel ca'ibration was considered a violation of TS SR 3.3.3.1.2. However, this non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-461/99002-06).
in response to this issue, the licensee implemented procedure changes to require that
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the channel calibration be performed every 92 days and to eliminate the discussion that the periodic self-calibration can be used to satisfy TS SR 3.3.3.1.2. The inspectors considered the licensee's corrective actions adequate.
i E8.4 (Closed) Case Soecific Checklist item IV.7: Resolve EDG concerns. The licensee submitted documentation to the NRC pertaining to the resolution of five EDG concerns on November 19,1998. Issues involving EDG operation and testing were described in the SET report and in NRC Inspection Reports 50-461/96011,50-461/98003, 50-461/98014, and 50-461/99002.
Operation of the Division lli EDG while in droop mode inspection Report 50-461/96011 described that the licensee's previous practice of considering the Division 111 EDG operable during surveillance testing was inappropriate.
Specifically, the Division ll1 EDG surveillance procedure required that a three percent change in speed droop be inserted into the engine's mechanical governor to allow the EDG to be paralleled to the grid. However, the insertion of speed droop resulte '
the HPCS system being unable to deliver 5010 gpm of flow to the reactor vessel at a t
differential pressure of 363 psid as required by TS SR 3.5.1.4.
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The SET report described that the Division lli EDG design was not in accordance with Regulatory Guide (RG) 1.108, Revision I, " Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants," and RG 1.9,
" Selection, Design, and Qualification of Diesel Generator Units Used as Standby Electric Power Systems at Nuclear Power Plants." Specifically, the SET stated that the RGs specified that EDGs be designed with the ability to automatically transfer from the droop to the isochronous mode of operation if a LOOP and a loss of coolant accident (LOCA)
signal were received concurrently during testing and that this ability be tested. Since, the Division til EDG was designed with a mechanical governor, the EDG was unable to automatically transfer between the droop and isochronous modes of operation without operator action. The licensee's inability to test this feature was described in NRC inspection Report 50-461/98014.
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In response to this issue, the licensee declared the Division ill EDG inoperable and conducted an additional review from which tha licensee determined that the reliance on manual actions to transfer the Division ill EDG from the droop to the isochronous mode of operation constituted an unreviewed safety question. On August 24,1998, the licensee submitted a TS amendment to address the unreviewed safety question which would allow operator action to be taken to transfer the Division ill EDG from the droop mode to the isochronous mode of operation if a LOOP /LOCA signal was received during testing. The NRC approved the licensee's TS amendment on January 20,1999.
The impact of extreme outside air temperatures on EDG operation Inspection Report 50-461/98003 described that operation of the EDGs and the diesel ventilation (VD) system was adversely affected by extreme outside air temperatures.
During extreme cold temperatures, the inspectors determined that the VD fans would demand increased horsepower which could impact EDG loading. The licensee determined that the increased horsepower had little effect on EDG loading since the current loading calculations included excessive margin. However, operation of the VD system under extreme high temperatures could result in a cotential common mode failure of all of the EDGs due to the failure to provide adequate electricalisolation between safety-related and nonsafety-related components. To reolve this concern, the
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licensee installed electrically coordinated fuse protection between the components on j
September 20,1997, December 19,1997, and August 24,1998, which prevented the possibility of this common mode failure.
During the review of high temperature concerns, the licensee determined that the Division i EDG's ability to carry LOCA loads when outside air temperatures reached 112'F was questionable since the continuous loading of the EDG exceeded the expected EDG capacity. In response to this issue, the licensee developed a methodology that utilized the 2000-hour EDG rating instead of the continuous EDG rating since temperatures would not be expected to be at or above 112 F for greater than 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br />. Calculations which supported the licensee's methodology had not been approved at the conclusion of the inspection due to the need to complete degraded voltage modification testing to support calculation finalization. However, the inspectors expected the results of the calculations to support the licensee's methodology.
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Emergency diesel generator air start capacity
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Inspection Report 50-461/98014 described the licensee's position on demonstrating the ability of the EDGs to perform five successive starts without recharging the air receivers.
The inspectors initially concluded that the licensee was required to demonstrate the ability of the EDGs to perform five successive start attempts with an air receiver pressure of 200 psig. However, engineering personnel stated that the air receivers were
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required to have the capacity to support five successive start attempts from 250 psig and to have a multiple start capability from 200 psig.
The inspectors consulted with NRC personnel in the Office of Nuclear Reactor Regulation (NRR) and Region Ill. Personnel in NRR agreed with the engineering department's position that the EDG air receivers must provide sufficient capacity for five start attempts from 250 psig and that the licensee was in compliance with NRC regulations. Therefore, this issue was considered resolved.
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Emergency diesel generator governor overshoot and undershoot The SET report described an instance where the Division Ill EDG frequency was not maintained at 60 hertz during testing due to overshoot and undershoot. In response to this issue, the EDG system engineer supplied the inspectors with a copy of TS Task Force Traveler-163, Revision 2. The TS traveler, which was approved by the NRC, explained that momentary overshoot and undershoot of EDG frequency and voltage did not impact EDG operability since this type of behavior is expected when an EDG is not connected to its safety-related bus. On July 31,1998, the licensee submitted a TS amendment to incorporate the changes in TS Task Force Traveler-163, Revision 2 into the Improved TSs. The NRC approved the amendment on January 20,1999.
Performance of EDG testing at 110 percent load Inspection Report 50-461/98020 described that surveillance proceoures used to test the EDGs at 100 and 110 percent load were inadequate in that the procedures did not contain acceptance criteria which considered the impact of instrument inaccuracies.
The licensee reviewed EDG surveillance tests conducted prior to 1996 and identified at least two examples where the EDGs did not meet the 110 percent loading requirements delineated in TS SR 3.8.1.14a.
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As part of the corrective actions for this issue, the licensee implemented procedure changes to incorporate instrument inaccuracies into the acceptance criteria and to ensure that the 100 and 110 percent loading requirements were met. However, a subsequent event disclosed that implementation of the new acceptance criteria resulted in potentially exceeding the allowed short term rating of the EDGs. To resolve this issue, the NRC approved a TS amendment which allowed EDG testing to be conducted at 90 to 100 percent of the continuous rating instead of 100 percent, and at 105 percent of the continuous rating instead of 110 percent to allow for the incorporation of instrument inaccuracies.
Resolution of Division lli low frequency issues During the developrnent of the Manual Chapter 0350 closure package for item IV.7, the licensee requested, and the NRC concurred, that discussions regarding the resolution of
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w Division 111 EDG low frequency issues be relocated to Item VI.1, " Provide Reasonable
Assurance that Safety-Related SSCs Will Perform their intended Safety Functions as
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Described in the Design and Licensing Basis." Therefore, this issue will be reviewed
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during closeout activities for Case Specific Checklist item VI.1.
The inspectors considered the licensee's corrective actions regarding the resolution of multiple EDG issues sufficient to support plant restart.
IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Recovery of Stuck Radicaraohv Source
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a.
inspection Scope (71750)
The inspectors observed activities to recover a radiography source that could not be retracted into the shielded position, b.
Observations and Findinas
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On January 9,1999, while performing radiography in a shielded compartment, radiography personnel heard an unexpected noise in the vicinity of the radiograph. After a failed attempt to retract the source, radiography personnel notified the radiation
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protection supervisor who subsequently stopped radiographic operations and secured the job-site.
The radiation protection supervisor developed a written plan to use a video camera to diagnose the problem. The video showed that the pipe being radiographed had fallen off the pipe stands and was resting on the source guide tube thereby preventing retraction of the source. A second plan was written to use a robot to remove the pipe
from the source guide tube and retract the source into the radiography camera. The total dose expended to retract the source was approximately 9 millirem.
c.
Conclusions The inspectors determined that radiation protection personnel demonstrated conservative decision making by using a video camera and robot to minimize exposure to only 9 millirem during recovery of a radiography source.
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V. Manaaement Meetinos X1 Exit Meeting Summary
. The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on February 16,1999. The licensee acknowledged the findings
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presented. 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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l X3 Management Meeting Summary
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On January 14,1999, a meeting was held on-site to discuss licensee restart activities and improvement initiatives as well as NRC activities associated with implementation of Manual
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Chapter 0350," Staff Guidelines for Restart Approval." Specific topics included operational i
readiness, engineering readiness, corrective action program, recirculation pump seal root cause l
analysis, and quality assurance oversight.
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On February 5,1999, a meeting was held in the NRC Region Ill office to discuss licensee
- restart activities and improvement initiatives as well as NRC activities associated with
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implementation of Manual Chapter 0350," Staff Guidelines for Restart Approval." Specific topics included concerns associated with conduct of operations and the status of licensee actions to address the remaining restart issues listed in the Manual Chapter 0350 Case Specific Checklist.
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l PARTIAL LIST OF PERSONS CONTACTED Mcensee j
l H. Anagnostopoulos, Director - Plant Radiation and Chernistry J
G. Baker, Manager - Quality Assurance i
V. Cwietniewicz, Manager - Maintenance
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- J. Goldman, Manager - Work Management J. Gruber, Director - Corrective Action G. Hunger, Plant Manager - Clinton Power Station W. Maguire, Director - Operations J. McElwain - Chief Nuclear Officer R. Phares, Manager - Nuclear Safety and Performance Improvement J. Sipek, Director - Licensing D. Smith, Director - Security and Emergency Planning
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D. Warfel, Manager - Nuclear Station Engineering Department
INSPECTION PROCEDURES USED iP 37551:
Engineering Observations IP 61726:
Surveillance Observations IP 62707.:
Maintenance Observation IP 71707:
Plant Operations IP 71750:
Plant Support and Observations IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901:
Followup - Operations
. IP 92902:
Followup - Maintenance l
IP 92903:
Followup - Engineering IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors l
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ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-461/99002-01 NCV ~ Inadequate annunciator response procedures.
50-461/99002-02 NCV Failure to have adequate EDG logs for lightly loaded conditions.
50-461/99002-03 NCV Failure to perform late PMs or process deferrals.
50-461/99002-04 NCV Failure to ensure the absence of a ground path following maintenance on the SX system.
50-461/99002-05 NCV Failure to make the required report within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of discovery that the SX system would not perform its intended safety function.
50-461/99002-06 NCV Failure to perform required channel calibrations on the drywell and containment hydrogen and oxygen analyzers.
Closed 50-461/99002-01 NCV inadequate annunciator response procedures.
50-461/95003-01b VIO Failure to ensure that hardening of grease in 480V ABB K-Line breakers was promptly identified and corrected.
50-461/95003-03 URI Potential ineffective resolution of a design problem that resulted in a breaker malfunction.
50-461/99002-02 NCV Failure to have adequate EDG logs for lightly loaded conditions.
50-461/99002-03 NCV Failure to perform late PMs or process deferrals.
50-461/99002-04 NCV Failure to ensure the absence of a ground path following maintenance on the SX system.
i 50-461/99002-05 NCV Failure to make the required report within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of discovery that the SX system would not perform its intended safety function.
50-461/99002-06 NCV Failure to perform required channel calibrations on the drywell and containment hydrogen and oxygen analyzers.
50-461/98-037 LER Failure of surveillance procedure to implement calibration requirements for the drywell and containment hydrogen and oxygen analyzers.
50-461/99-002 LER Offsite faults on inservice offsite electrical supply line causes LOOP to safety-related busses.
CSC ltem IV 7:
Resolve EDG concerns.
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ITEMS OPENED, CLOSED, AND DISCUSSED (cont'd)
Discussed.
CSC ltem 11.3:
Review and revise abnormal operations sections of operations procedures, i
i CSC ltem V.1:
Develop process to review deferrals of preventive maintenance items.
- CSC ltem V1.1:
Resolution of Division ll1 low frequency issues.
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LIST OF ACRONYMS i
ABB'
Asea Brown Boveri
- AR Action Request CCF Comment Control Form i
CSC Case Specific Checklist CR Condition Report
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EDG Emergency Diesel Generator
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EM Electrical Maintenance ERAT Emergency Reserve Auxilary Transformer HPCS High Pressure Core Spray
ISA Independent Safety Assessment LOCA Loss of Coolant Accident LOOP Loss of Offsite Power MCCB Molded Case Circuit Breaker MWO Maintenance Work Order NOUE Notice of Unusual Event NSPS Nuclear System Protection System
' PM Preventative Maintenance RAT'
Reserve AuxiliaryTransformer RCIC.
Reactor Core Isolation Cooling
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- RT-Reactor Water Cleanup SET Special Evaluation Team SR Surveillance Requirement l-SRO
- Senior Reactor Operator l
SX Shutdown Service Water TS'
Technical Specification VD'
Diesel Ventilation
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