ML23251A019

FOIA-2023-000163 - Responsive Record - Public ADAMS Document Report. Part 12 of 19

ML23251A019
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Issue date:	08/31/2023
From:	NRC/OCIO
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U.S. NUCLEAR REGULATORY COMMISSION REGION I Report Nos.: 91-17; 91-17 Docket Nos.: 50-220; 50-410 License Nos.: DPR-63; NPF-69 Licensee: Niagara Mohawk Power Corporation 301 Plainfield Road Syracuse, New York 13212 Facility: Nine Mile Point, Units 1 and 2 Location: Scriba, New York Dates: July 28 through September 7, 1991 Inspectors: W. L. Schmidt, Senior Resident Inspector R. R. Temps, Resident Inspector R. A. Laura, Resident Inspector Approved by:

Donald R. Haverkamp, Chi f Date Reactor Projects Section No. 1B Division of Reactor Projects Ins ection Summa: This inspection report documents routine and reactive inspections of operations, radiological controls, maintenance, surveillance, security, engineering and technical support and safety assessment/quality verification activities.

Results: See Executive Summary.

9110140058 911008 PDR ADOCK 05000220 G PDR

7 (a e EXECUTIVE

SUMMARY

Nine Mile Point Unit 1 and Unit 2 r

NRC Region I Inspection Report Nos. 50-220/91-17 and 50-410/91-17 July 28 - September 7, 1991 0 Wl p d g p f Ui 1 g ddg this period. This was evident in the proper and uneventful return of the unit to full power operation on July 28 following a ten day unscheduled outage,to identify and correct the source of unidentified drywell leakage. One example of poor performance was noted relative to the inspector identifying an improperly disabled control room annunciator.

Operators responded well to the fault in the B phase of the Unit 2 main transformer which resulted in a reactor scram and the loss of five non-safety related uninterruptible power supplies (UPS). A previously unresolved item (410/91-12-02) dealing with the inability of the standby gas treatment systems to perform their safety function, because of an inoperable secondary containment unit cooler, has been upgraded to an apparent violation.

Radiolo ical Controls: No weaknesses were identified as a result of routine inspector tours in radiologically controlled areas. Inspector entry to a contaminated high radiation area at Unit 2 was well supported by radiation protection personnel and proper radiological controls were in place and followed.

Maintenance: No safety concerns were identified at Unit 1 during the observed safety-related maintenance. At Unit 2, a preplanned outage for inspection of a defect in a HPCS nozzle was entered following the reactor scram of August 13. Inspection of the HPCS nozzle weld yielded satisfactory results and repair by weld overlay was not required. Other maintenance activities focused on repair and replacement of electrical equipment involved in the August 13 event. A potentially serious personnel safety error occurred when two site electricians removed a red markup without the requisite approval and proceeded to work on a non-safety-related electrical component in the switchyard. This issue is an unresolved item (410/91-17-01) pending NYPA completion of its root cause assessment and NRC review of whether the cause(s) found impact on safety-related work activities.

Emer enc Pre aredn: An Unusual Event (UE) and a Site Area Emergency (SAE) were declared during the period at Unit 2. Evaluation of NMPC's actions during the SAE was reviewed by region based specialists and incorporated into report 50-410/91-81.

~Securit: The security department was observed to implement proper vital area controls and vehicle search procedures.

'xecutive Summary (Continued)

En ineerin and Technical Su ort: An unresolved item (220/91-17-02) at Unit 1 was identified concerning improper setting of a breaker which supplies power to safety related battery board 12. A safety related check valve audit conducted at Unit 2 identified an unresolved item (410/91-17-03) concerning the corrective actions NMPC has taken for previously identified deficiencies related to service water check valves. NMPC did not document an identified nonconforming condition and consequently could not establish how similar service water check valves could be inspected for this issue or how the issue would be evaluated. Further, NMPC corporate design engineerin'g has been slow to respond to numerous service water check valve problems identified by site engineers. A previously identified unresolved item at both units (220/410/91-12-05) dealing with improperly controlled temporary modifications was upgraded to a violation. This followed inspector identification of other examples of improperly controlled temporary modifications (TMs) at both units. However, because NMPC has taken timely and effective corrective actions to address these issues a response to the violation was not deemed necessary.

Safet Assessment/ ualit Verification: The independent assessment groups investigation into the use of temporary modifications at the site was thorough and well documented. The investigation and the corrective action taken based on it was the main reason why a response to the violation on improper use of temporary modifications was not required.

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TABLE F CONTENT 1.0

SUMMARY

OF FACILITYACTIVITIES 1~1 1 ~ 2 Niagara Mohawk Power Corporation Activities NRC Actlvltles ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

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1 1.2.1 Inspection and Investigation of August 13 Reactor Scram - Unit 2 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 2 1.2.2 Routine Non-Resident Inspector Core Inspection Program 2 1.2.3 Safety Related Check Valve Audit - Unit 2 2 1.2.4 Meeting to Discuss Standby Gas Treatment Operability....... 3 2.0 PLANT OPERATIONS.......................,..... 3 2.1. Routine Plant Operations Review - Unit 1 3 2.1.1 Improperly Defeated Control Room Annunciator..... 3 2.1.2 Non-Conservative Error in Thermal Limits Calculations 4 2,1.3 (Closed) Unresolved Item 220/91-12-01: Control of 1 15 KV Offsite Power Lines 5 2.2 Routine Plant Operations Review - Unit 2 ~ ~ ~ ~ ~ ~ 5 2.2.1 (Open) Unresolved Item 410/91-12-02; Review of Unit Cooler Inoperability ..............,............ ~ ~ ~ ~ ~ ~ ~ 5 3.0 RADIOLOGICALAND CHEMISTRY CONTROLS (71707) . ~........... 6 3.1 Routine Radiological Control Observations - Units 1 and 2.......... 6 3.2 Unauthorized Temporary Modification to Condensate System - Unit 2 ... 7 4.0 MAINTENANCE 7 4.1 Observation of Maintenance Activities - Unit 1 7 4.2 Maintenance Activities - Unit 2..............

4.2.1 High Pressure Core Spray Nozzle Inspection and Preplanned

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~ 8 0 utage 8 4.2.2 Unauthorized Removal of a Red Markup 8 5.0 EMERGENCY PLANNING 5.1 Unusual Event: Loss of Process Computer Greater Than Eight

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Hours

~ ~ ~ 9 U 'it 2 e ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ o ~ ~ ~ 9 5.2 Reactor Scram and Declaration of Site Area Emergency......... ~ ~ ~ 9 6.0 SECURITY AND SAFEGUARDS ...................,......... 9 111

Table of Contents (Continued) 7.0 ENGINEERING AND TECHNICAL SUPPORT ~ ~ ~ ~ 9 7 .1 Unit 1 ~ ~ ~ 9 7.1.1 Improper Safety Related DC Breaker Setting ~ ~ ~ ~ 9 7..2 Unit 2 10 7.2.1 Service Water Pump Discharge Valves....., .. ~ ~ ~ ~ ~ ~ 10 7.3 (Open) Unresolved Item 220/410/91-12-05; Improper Control of Temporary Modification - Units 1 and 2 11 8.0 SAFETY ASSESSMENT AND QUALITYVERIFICATION..........

8.1 Routine Review - Unit 1 ............................

8.1.1 Review of Licensee Event Reports (LERs) and Special Reports

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13 13 13 8.2 Routine Review - Unit 2 8.2.1 Review of LERs

...................... ~..... 13 13 8.3 Inadequate Training on APs as Identified in ISEG Root Cause Evaluation Units 1 and 2 14 9.0 MANAGEMENTMEETINGS........ ~..........,........... 15 (The NRC inspection manual procedure or temporary instruction that was used as inspection guidance is listed for each applicable report section.)

0' DETAIL/

1.0

SUMMARY

OF FACILITYACTIVITIES 1.1 Nia ara Mohawk Power o rati n Ac ivitie The Niagara Mohawk Power Corporation (NMPC) restarted Unit 1 on July 28, 1991, following an unscheduled ten day outage to correct flange and valve packing leaks in the drywell. The unit operated at or near full power during the remainder of.the period, power was limited at times during the period to 95% due to lake temperature effects on condenser vacuum.

Following an unexpected battery charger breaker trip, an engineering evaluation determined that the DC battery charger output breaker overload trip to battery board 12 had not been properly set. As a result, a 24-hour shutdown limiting condition for operation was entered until the breaker trip setting was reset. A non-conservative error in information, supplied by General Electric, used in calculating thermal limits led to a 2-3% power derate until the correct information could be obtained to recalculate thermal limits.

Unit 2 operated at full power until August 13 when a fault in the main transformer caused a generator load reject, a turbine trip and, as designed, an automatic reactor scram. Operator response to the scram was complicated by the loss of several non-safety related UPSs as a result of the transformer fault. Loss of these UPSs caused a loss of control room annunciators and non-safety related instrumentation and control systems. NMPC declared a site area emergency in accordance with their emergency plan based on the loss of annunciators and a plant transient.

The non-safety related reactor feed water system became inoperable when power to the control system was lost; consequently, the operators used the reactor core isolation cooling system to initially control reactor vessel level. Operators were able to restore power to the affected UPS busses via the maintenance supply within 34 minutes of the loss. This also restored, the feed system to operation. Operators continued with a normal plant cooldown to cold shutdown.

Activities following the shutdown were focused on; completing event troubleshooting and root cause analyses, conducting the HPCS nozzle inspections, and other routine pre-planned maintenance. At the end of the period, NMPC was pursuing completion of these tasks in preparation for plant startup.

1.2 ~NR

• The inspection activities during this report period included inspection during normal, backshift, and weekend hours by the resident staff. There were 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> of backshift (evening shift) and 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> of deep backshift (weekend, holiday, and midnight shift) inspections during this period.

1.2.1 Ins ecti n n Investi ation of Au ust 1 Reactor cram - ni 2 As a result of the Unit 2 scram and declaration of a site area emergency (SAE) on August 13, an augmented inspection team (AIT), consisting of regional inspectors and a resident inspector, was dispatched by the Regional Administrator to the site. Also, NMPC management agreed that the unit would not be restarted without approval of the Regional Administrator, this commitment was documented in confirmatory action letter (CAL)91-012 dated August 13, 1991. On August 16, the AIT was supplanted by a headquarters incident investigation team (IIT) to investigate and develop the causes for the event. The decision to send the IIT to the site was documented in CAL 91-013, dated August 15, 1991. The IIT completed its preliminary on-site work on August 27.

On August 28, Region I and NRR staff members held a meeting in the Region I office with NMPC management to discuss issues that required resolution prior to restart, including NMPC's evaluation of the cause and corrective actions taken as a result of the event. A list of participants in that meeting and a copy of NMPC's presentation notes are provided as attachments (1) and (2) to this report.

1.2.2 Routine Non-Re ident In ector Core Ins ection Pr ram A routine unannounced inspection of NMPC's security program was conducted by two region based specialist inspectors the week of August 12. No major concerns were identified.

A routine inspection of NMPC's radiation protection program was conducted by a region based specialist inspector during the week of August 12. No major concerns were identified.

1.2.3 afet Related Check Valve Audit - ni 2 During the week of August 5, an audit of the Unit 2 safety related check valve program was conducted by individuals from NRR with regional specialist inspector and contractor support.

During the audit, an unresolved item related to ineffective corrective actions was identified and turned over to the resident staff for incorporation into this report (see section 7.2.1 below).

1.2.4 Meetin to Di cu tand Treatment On August 22, a meeting was held between the NRR staff and NMPC's licensing and engineering staff. NMPC presented their initial analysis and design concepts associated with final resolution of the secondary containment drawdown issue. A separate meeting report will be issued documenting this meeting.

2.0 PLANT OPERATIONS 2.1. Routine Plant 0 erations Review - Unit 1 During the inspection period, the inspectors observed control room activities including; operator shift turnovers, shift crew briefings, panel manipulations and alarm response, and routine safety system and auxiliary system operations conducted in accordance with approved operating procedures and administrative guidelines. The inspectors made independent verification of safety system operability by review of operator logs, system markups, control panel walkdowns and component status verifications in the field. The number of lit annunciators was observed to be low. Discussions were held with operators and technicians in the field to assess their familiarity with current system status and personnel response to events during the inspection period.

Performance during this period was observed to be good. Enhancements were made to the physical layout of the station shift supervisor (SSS) and assistant SSS (ASSS) offices to improve oversight of control room activities. The ASSS's desk was moved into the control area in back of the chief shift operator's (CSO) desk in the control room. The SSS's office was moved over to an adjacent space where there is increased visibility of control room activities. The inspector views these changes as positive actions.

2.1.1 Im ro erl Defeated ntr 1 R m Annun iator The inspector identified an instance of poor performance by operations personnel when he found an improperly disabled control room annunciator. During a plant tour on August 4, the inspector identified that annunciator relay (D-18), in panel 6 in the auxiliary control room, had been pulled and left laying in the bottom of the panel. There was no configuration control tag attached to the pulled relay or the panel. After initial discussions with the plant operators, the inspector determined that the control room staff was unaware that the relay was pulled or which annunciator circuit it was from.

0 After investigation, the station shift supervisor determined the relay for the non-safety related annunciator L2-2-5, offgas recombiner condenser II condensate drain high level. The relay was reinstalled and annunciator L2-2-5 alarmed and cleared repetitively. The relay was removed and a holdout tag was applied to maintain configuration control in accordance with AP 6.1, Control Of Equipment Temporary Modifications. A work request was generated to troubleshoot why the annunciator was alarming.

The safety significance of the improperly disabled annunciator circuit was relatively low because recombiner condenser level was maintained in the normal band. Further, other recombiner parameter indicators were normal. However, the inspector was concerned that an operator had not followed the alarm response procedure for this alarm and chose to pull the relay. Further, the inspector was concerned because the configuration control requirements of AP 6.1 Section 5.5 were not followed when the annunciator was defeated. Section 5.5 specifies that a malfunctioning annunciator be removed from service using a markup, the defeated annunciator be entered into the defeated annunciator log which requires a compensatory action assessment be performed, and a sticker be placed on the defeated annunciator window. The inspector considered this an example of a performance problem that is similar to a violation of the temporary modification procedure addressed in section 7.3 of this report.

These concerns were discussed with the operations staff and plant management. Preliminarily, they agreed with the inspector's concerns and have initiated corrective actions. Niagara Mohawk has been unable to determine who removed the annunciator relay and why. Meetings have been conducted with all operating crews stressing the importance of proper evaluation prior to disabling annunciator circuits.

2.1.2 N n- on rv tive Error in Therm 1 Limit l il i n On August 8, GE informed NMPC of the existence of a non-conservative error in information supplied for use in the Unit 1 thermal limit calculations. NMPC reviewed the information and conducted a SORC approved operability determination to allow for continued operation of the unit, following a reactor power derate of 2-3%, while the issue received further technical review. Reprogramming with the correct information was completed on August 9. NMPC management personnel properly assessed the impact of incorrect reactor engineering information supplied by General Electric (GE) and took conservative actions until the problem could be resolved. The new thermal limits were found to be well within the limiting safety values specified in technical specifications and the unit was returned to full power.

f 2.1.3 losed nre olved Item 220/91 1: ontrol of 115 KV Off ite Power Lines This unresolved item concerned an unplanned outage of the 115 KV line 3 initiated by NMPC power control and the FitzPatrick control room. NMPC Unit 1 operators were not informed that the line was deenergized by either NMPC power control or the FitzPatrick plant. This issue was left as an unresolved item pending inspector review of NMPC's corrective actions.

Extensive corrective actions were taken by NMPC to improve communication and coordination between NMPC power control, Unit 1, and FitzPatrick concerning 115 KV line outages. The inspector also noted that this issue had been addressed in 1989 following a loss of both offsite power lines for a short period of time. The inspector determined that following the previous instance, Unit 1 and FitzPatrick had taken adequate action to ensure that line outages were communicated. However, in this case the FitzPatrick control room failed to inform the Unit 1 control room when they secured the line. Further, the procedures covering the communications from NMPC power control to both units in the event of a line outage were not completed.

NMPC took several corrective actions to prevent recurrence. A change was made to NMPC regional power control operating instructions to require concurrence from Units 1 and 2 and FitzPatrick prior to any line outage that would affect loss of offsite reserve power sources. The inspector's assessment was that NMPC corrective actions appear to be comprehensive. This item was closed.

2.2 R utine Plant er i n Review - nit 2 During the inspection period, the inspectors observed control room activities including; operator shift turnovers, shift crew briefings, panel manipulations and alarm response, and routine safety system and auxiliary system operations conducted in accordance with approved operating procedures and administrative guidelines. The inspectors made independent verification of safety system operability by review of operator logs, system markups, control panel walkdowns and component status verifications in the field. Discussions were held with operators and technicians in the field to assess their familiarity with current system status and personnel response to events during the inspection period.

2.2.1 0 en Unresolved Item 41 / 1 2 Review f nit poler Ino e bili Inspection report 91-12 discussed a secondary containment unit cooler that was inadvertently left isolated following an aborted maintenance activity. The item was left open pending inspector review of the event and of the root cause analysis presented by NMPC in licensee event report (LER) 91-16.

e The inspector determined that the inability of the unit cooler to remove its designed heat load potentially affected the ability of the associated standby gas treatment train to draw down the secondary containment in the required technical specification time. NMPC stated, in LER 91-16, that SBGT Division II was technically inoperable for 14 days because of the isolated cooler.

Also, during the 14-day period, work was performed on the Division I train of SBGT and on the Division I emergency diesel generator which also made SBGT Division I inoperable.

Technical Specifications (TS) limited the duration of SBGT system inoperability to seven days for one train and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for both trains before a shutdown needed to be commenced. In each case, a plant shutdown was not commenced because the operators did not know of the inoperable unit cooler.

The inspector reviewed the LER for thoroughness, completeness, and root cause determination.

NMPC's investigation into the mispositioning was thorough. The LER stated that the loss of configuration control resulted from a lack of specific instructions in AP 4.2, "Control of Equipment Markups", on the process for voiding markups and the restoration actions necessary.

The inspector noted that NMPC's investigation into this event was indeterminate in regard to actual cause of the valve mispositioning. NMPC had not been able to ideentify definitively if a markup tag was hung and then removed from the valve. It appeared that AP 4.2 already had proper configuration controls in place to ensure the hanging and proper clearing, including repositioning of valves, of a markup, but that these controls were not properly used. Therefore, the root causes may not have been completely identified.

In summary, the inspector identified two apparent violations of NRC requirements resulting from this event. First, on three occasions, TS required shutdowns of the unit did not occur due to the undetected inoperability of the unit cooler. Secondly, configuration control was not maintained on the service water valves during the markup process. These apparent violations will be the subject of an enforcement conference. This item has been changed to an apparent violation (410/91-12-02).

3.0 RADIOLOGICALAND CHEMISTRY CONTROLS (71707) 3.1 Routine Radiolo ical Control bservation - nits 1 and 2 Normal inspector tours of the radiologically controlled areas identified no deficiencies or weaknesses with the practices being utilized.

t 3.2 nauthorized Tem ra Modificati n t on en te em - nit 2 The inspector determined that chemistry department personnel failed to follow station temporary modification and chemistry procedures during sampling of the condensate system. Specifically, while on tour in the condensate storage building, the inspector identified tygon tubing connected to several valves that was not on controlled plant drawing or treated as a temporary modification. In one instance, the inspector identified that a chemistry procedure recognized sampling from valves using temporarily attached tygon tubing and specified the removal of the tubing when done. In other instances, the inspector was unable to identify any procedure which recognized sampling from other points where tygon tubing'was found installed and that the condensate system valve lineup in N2-OP-4 indicated that valves should be shut and the test connections plugged.

When the finding was discussed with the Chemistry Supervisor, NMPC responded quickly to the concern stating that corrective measures would be taken. Corrective actions taken included removing the tubing and/or processing of the appropriate temporary modification. DER 2-91 0653 was issued documenting the finding and the actions taken by the chemistry department.

The issue of the unauthorized temporary modification is discussed further in section 7.3.

4.0 MAINTENANCE The inspectors observed and reviewed selected portions of preventive and corrective maintenance to verify compliance with regulations, use of administrative and maintenance procedures, compliance with codes and standards, proper QA/QC involvement, and equipment alignment and retest. The following activities were observed:

4.1 b ervation f Mainten nce Activiti - nit 1 The inspector observed the following maintenance activities and determined that they were properly conducted.

Disassembly of the 103 emergency diesel generator (EDG) cooling water heat exchanger to inspect for zebra mussels. No zebra mussel intrusion was found. The inspector verified operations personnel properly entered the TS limiting,.condition for operation with one EDG out of service and verified that the isolation used for this maintenance was proper.

Installation of a redundant flow meter in the service water radiation monitor. This modification allows one flowmeter to be isolated and cleaned without removing the monitor from service. One instrument and control and three mechanical maintenance technicians were working at the job site. The technicians were observed to be experienced and competent. The inspector's assessment was that this modification should reduce the amount of time the monitor was inoperable due to clogging of the flowmeter and was a positive initiative.

4.2 Maintenance Activities - nit 2 4.2.1 Hi h Pressure C re ra Nozzle Ins ection and Pre lanned uta e The inspector observed good pre-planning for and implementation of the ultrasonic testing on a flaw in the HPCS nozzle safe end weld. The flaw had been detected in this weld during the first refueling outage. NRC evaluation accepted the flaw as long as it was inspected for crack growth by NMPC prior to the end of September 1991. The pre-planned HPCS outage was started early on August 14 following the scram of the previous day. Results of the reinspection were satisfactory and indicated that the flaw had not propagated. Performance of a weld overlay repair procedure was not required.

A potentially serious personnel safety error occurred when two site electricians removed a red markup from a component without authorization from the control room and in violation of station requirements. During the repair to a switchyard disconnect operating linkage in the generator output 345 KV line, the electricians removed the red markup tag and proceeded to operate the disconnect. NMPC has initiated a root cause investigation for this event.

From discussions with the plant manager, it appeared that when the one individual lifted the red markup, it simply did not register to him that it was a red markup. Regardless of the color, red blue or yellow, the tag should not have been removed. Also, the electrician's assistant recognized the action as improper but did not voice his concern at the time. For the interim, the plant manager was requiring that all Unit 2 Electrical Department personnel review this incident and receive further training on proper markup controls.

The inspector noted that this event involved non-nuclear safety-related equipment but considered this to be a performance issue that had implications to the proper removal of markups used for safety-related systems. This issue willremain unresolved pending licensee completion of its root cause assessment and NRC review of whether the cause(s) found impact on safety-related work activities (410/91-17-01)

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e 5.0 EMERGENCY PLANING 5.1 nu ual Event f Pr cess Com uter r er Th n Ei ht Hours - Unit 2 NMPC took proper actions on August 6 when they declared an Unusual Event (UE) following the inoperability of the Unit 2 process computer (PC) for greater then eight hours. The declaration was required in accordance with Nine Mile Point site emergency procedure, S-EAP-2.

NMPC identified that the problem resulted from a faulty power source. During the time the PC was out of service, extra licensed and non-licensed personnel were assigned to the control room, although by procedure only one extra non-licensed individual needed to be assigned. Reactor power was also lowered by 2% from 100% to 98% to provide for extra margin from thermal limits, No performance deficiencies or regulatory concerns were identified.

5.2 Reactor Scram and Declaration f ite Area Emer enc On August 13, Unit 2 declared a Site Area Emergency (SAE), when the reactor scrammed from full power due to a fault in the B phase of the main transformer. The scram was further complicated by the loss of five non-safety related UPSs which resulted in the loss of a significant portion of the control room's annunciators and indications. The SAE was declared on the basis of loss of control room annunciators with a plant transient in progress. Evaluation of the response of the NMPC emergency planning function was reviewed by a regional specialist and incorporated into the restart readiness inspection team report 91-81.

6.0 SECURITY AND SAFEGUARDS During routine plant tours the inspectors observed good security response to vital area door alarms. Searches of vehicles and personnel entering the protected area were conducted properly.

7.0 ENGINEERING AND TECHNICAL SUPPORT 7.1 Unit 1 7.1.1 Im ro er afet Rel t D Breaker ettin The inspector reviewed NMPC's identification that during certain accident conditions the common DC output breaker from the battery charger and static inverter to battery board 12 would not have performed as designed. The inspector's initial assessment was that NMPC did not use good engineering practices in that the battery charger breaker setting was not reviewed when making modifications to the DC system. As a result of this identification, NMPC operations staff declared battery board 12 inoperable, which placed the unit in a 24-hour shutdown limiting condition for operation, and made the required 10CFR 50.72 notification.

10 An engineering evaluation was initiated on August 12, when a spurious trip of the subject breaker occurred during preoperational testing of the static inverter modification. During the testing, it was noted that the breaker tripped open with a load of approximately 274 amps. The breaker was cycled several times and the problem could not be repeated. A deviation/event report (DER) was initiated to document and investigate the spurious trip of the breaker.

The trip setting was increased to 460 amps and the breaker tested satisfactory. Battery board 12 was declared operable and the limiting condition for operation was exited prior to the expiration of the 24-hour limit. The associated breaker on battery board 11 was determined to .

be set properly. This is an unresolved item (220/91-17-02) pending NMP completion of the DER investigation and NRC review and assessment of the safety significance and root cause.

7.2 7.2.1 Service Water Pum Di char e Valve During the safety related check valve audit conducted the week of August 5, a specialist inspector questioned the adequacy of NMPC's corrective actions to prevent frequent failures of the service water pump discharge check valves (18-inch valves manufactured by Clow, now C&S Valve Company) This was based on reviewing various maintenance work requests (WRs) and

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engineering design changes (EDCs) concerning these valves. NYPA site engineers determined in March 1991 that there have been problems identified with these same check valves since 1986. The inspector noted that the root cause evaluations for these failures were still ongoing and NYPA design engineering had not yet defined clear long term corrective actions. Further, the inspector identified that NMPC had not received vendor manual updates from the manufacturer, as described below.

The first concern that was identified during the check valve audit involved the apparent failure of maintenance supervision and QA personnel to document a nonconforming condition as a condition adverse to quality. During valve disassembly in December, 1990, maintenance personnel found the disc to shaft anti-rotation key was missing on the 'E'ervice water pump discharge check valve 2SWP*V1E. This condition caused excessive torsional stresses on the disc to shaft dowel pins. The dowel pins were provided to align the disc/shaft assembly within the valve body. The inspector was informed that the maintenance supervisor reviewed the matter and decided not to issue a nonconformance report or some other record that would document the nonconforming material condition of the check valve. Further, QA/QC personnel witnessed portions of the work and signed off the work requests but they apparently did not review the reasons for not documenting the nonconforming condition. The inspector noted that there are five additional check valves of similar type installed at the unit. At the conclusion of the inspection, the licensee had not yet resolved actions taken on the additional valves.

11 A second concern involved the apparent slow corporate engineering response to the various problems identified by site engineering with the service water'pump discharge check valves. In March 1991 the licensee stated in an engineering design change, for valve 2SWP*V1C, that "In the past this valve and other service water pump discharge check valves have had similar or exacerbated problems namely: broken keys, worn keyways, sheared dowel pins, and excessively worn seal packs." Also at that time site engineering issued problem reports on these valves and recognized that additional design engineering support was needed to establish long term corrective actions. The inspector concluded that site engineering had made reasonable attempts to correct individual valves. The inspector noted that the licensee had been slow in developing long-term solutions to these problem reports. Further, at that time, the Unit 2 maintenance procedures and the vendor manual did not include the correct installation instructions for the disc/shaft dowel pins. The licensee determined that the C&S Valve Company had not sent this information to NMPC in 1985. However, at the time of this inspection, NMPC QA and design engineering had not completed their actions to correct and prevent recurrence of the problem with obtaining vendor information.

The inspector considered that the issues discussed above represented an unresolved item (410/91-17-03) pending further NRC resident inspector review of (1) the reasons for not documenting the missing shaft anti-rotation key in December 1990, (2) NMPC's corrective action plan for a timely and comprehensive root cause assessment and proposed solutions in response to the site engineering problem reports, and (3) the use of vendor information for these service water check valves.

7.3 en nre lvedItem22041 1 'Im r r n r I fTem ora M dific ion ni 1 n 2 This item was opened as a result of inspector identification of uncontrolled temporary modifications (TMs) at both units,-as described in inspection report 91-12. During this inspection report period the inspector identified several other temporary modification issues as documented in sections 2.1.1 and 3.2 of this report. Based on a review of these issues the inspector concluded that NMPC personnel were not following Administrative Procedure (AP) 6.1, Control of Temporary Modifications.

As a result of the inspector's findings, NMPC station management directed the Independent Safety Engineering Group (ISEG) to perform a root cause analysis to determine why these.

improper TMs were occurring. NMPC performed walkdowns of systems at both units to identify any other system configurations which might constitute potentially unauthorized TMs.

Additionally, NMPC conducted additional training with site personnel on TM requirements.

f 12 The inspector determined that the ISEG Report 91-38 was thorough. Further, the inspector's assessment of the reason why uncontrolled TMs were occurring was consistent with the ISEG root cause. The ISEG review concluded that AP-6.1 was sufficient to control TMs; however, the methods of controlling TMs changed as administrative procedures changed and a lack of specific training on the changes left confusion and misunderstandings on what constitutes a TM and when the TM procedure should be implemented. ISEG concluded that once the TM procedure was entered, the implementation was satisfactorily completed.

The walkdowns at both units resulted in the identification of numerous potentially uncontrolled TMs. System engineers at both units were assigned responsibility for dispositioning these discrepancies. This process was still underway at the close of the inspection period. The inspector's assessment is that the walkdowns were thorough and that the discrepancies identified were of low safety significance and not subject to TM controls.

The additional training consisted of discussions with non-operations department personnel and formal training of control room operators on TM requirements. NMPC utilized information developed by the ISEG review and the walkdowns to develop lessons learned which, following the initial training, will be incorporated into continuous training.

The inspectors determined that these uncontrolled TMs documented in inspection report 91-12 and in this inspection report, represent a violation (220/410/91-12-05) of TS 6.8;1 for both units, which required that procedures for administrative controls of temporary modifications be implemented. Specifically:

On July 1, 1991, at Unit 1, the installation of temporary ventilation equipment by fire department and operations personnel at fire panels 6 and 7 in the reactor building were not processed as a temporary modification. This was required by step 3.7.14 which states that the installation of temporary ventilation equipment such as blowers shall be processed as a temporary modification.

On July 15, 1991, at Unit 2, a temporary equipment alteration, between the makeup water system and service water radiation monitors 2SWP*CAB146A and B, installed and controlled by flushing procedure N2-RTP-130, Revision 02, dated 10/15/90, did not get removed by that procedure. Removal of the jumper was required by step 1.2.1 which states that a temporary equipment alteration installed and controlled by an approved procedure must be removed by that procedure.

The individual safety significance of each of these issues is low, however, they do represent the types of recent failures of station personnel to properly control temporary modifications. Based on the fact that NMPC has already responded to these concerns and the corrective actions, described above, were assessed to be adequate, no response to this violation was necessary.

I

13 8.0 SAFETY ASSESSMEÃT AND QUALITYVFAUHCATION 8.1 R utine Review - ni 1 8.1.1 Review of Licen ee Event Re ort ER nd eci 1 Re rts The following LER and special report were reviewed by the inspector and found satisfactory:

LER 91-07, initiation of reactor building emergency ventilation and isolation of the reactor building normal ventilation as a result of a damaged cable. This event was assessed and documented in IR 50-220/91-12. No further concerns were identified as a result of reviewing the LER. NMPC's corrective actions were thorough.

Special Report, dated July 24, 1991, concerning the inoperability of the number 12 suppression chamber water level transmitter. NMPC identified that the cause of the event was instrument drift between calibrations. The transmitter was calibrated and restored to service. The long term corrective action was to revise the surveillance procedure to require a narrower tolerance in the transmitter calibration table and require a test instrument with a higher degree of accuracy. The inspector determined that this problem was reported and dispositioned with good corrective actions taken, 8.2 Routine R view - ni 2 8;2.1 Review of LERs The following LERs were reviewed and found satisfactory:

LER 91-09 and Supplement 1 to LER 91-09, Engineered safety feature actuation due to a spurious high radiation level signal. The supplement was issued to document the results of a root cause evaluation performed to identify the cause of a high radiation level signal in the reactor building ventilation system. The initial LER stated that welding in the area near the radiation monitors microprocessor was thought to be the cause of the high radiation signal. Subsequent investigation, as reported in the supplement determined that the welding activity was responsible for the actuation and that the root cause was inadequate welder training program content. Specifically, that the individuals involved were not adequately trained in how to properly ground their welding equipment or how to run welding leads. The inspector determined that corrective actions listed in the supplement appear adequate to address the concerns raised by the event.

I 14 LER 91-10, Reactor core isolation cooling (RCIC) system isolation due to a spurious reactor building high area temperature signal. The immediate cause of the isolation was a spurious high reactor building temperature signal. Initial operator response to this isolation was delayed by 28 minutes, even though two control room annunciators actuated upon the isolation. The cause of the annunciators was mistakenly attributed to the concurrent performance of a monthly surveillance procedure, N2-ISP-LDS-M004, which performs functional testing on the reactor water cleanup equipment area temperature instruments. Only after the completion of the surveillance procedure and its associated alarms did the operators notice that the "RCIC Inoperable" annunciator alarm had not cleared. It was them realized that a RCIC isolation had occurred and measures were promptly taken to return RCIC to an operable status. The root cause of the 28 minute delay in discovering that the RCIC system had isolated was attributable to poor work practices. The inspector determined that corrective actions to address the licensed operator performance issues raised by this event were appropriate. Specifically, the need for operators to clearly identified the source of annunciators prior to acknowledgement and the need for appropriate communication between the CSO and personnel performing functions which bring in annunciators.

LER 90-26, Supplement 1, TS violation - instrumentation not environmentally and seismically qualified due to personnel error. The events described in this LER were reviewed in NRC inspection report 50-410/91-06 and a non-cited violation (91-06-02) issued at that time. Supplement 1 delineates that the root cause for the equipment condition was personnel error due to poor work practices. The supplement extensively details the cause of the event and provides event analysis of the potential consequences of having operated with the non-environmentally and non-seismically qualified components. The analyses concluded that no hazard to the health and safety of the public or plant personnel existed. Corrective actions taken appeared adequate in addressing the event.

8.3 Inad uate Trainin n AP as Identifi in I E R au e Evaluati n - nits 1 and 2 With respect to the ISEG root cause evaluation for uncontrolled TMs, discussed in section 7.3, the inspector notes that the issue of personnel not being fully aware of or trained on revisions to site APs is not new, as numerous examples of failure to train personnel on new procedures were identified during the Unit 1 restart program. Examples included inadequate training on AP 4.2, Control of Equipment Markups, and poor implementation of the reload system walkdowns.

This concern on inadequate training was discussed with senior site management who responded adequately by stating that it was being addressed through continuing training on site APs and by development of the Nuclear Division Policy and Directives Manual, which provides overall guidance on conduct of operations at the site.

15 9.0 MANAGEMFATMEETINGS At periodic intervals and at the conclusion of the inspection, meetings were held with senior station management to discuss the scope and findings of this inspection. Based on the NRC Region I review of this report and discussions held with Niagara, Mohawk representatives, it was determined that this report does not contain safeguards or proprietary information.

) 'l ATTACHMENT 1 NRC/NMPC Management Meeting - August 28, 1991 Nine Mile Point Unit 2 Restart Issues U.. Nuclear Re ilato Commi ion D. Brinkman, Senior Project Manager, Office of Nuclear Reactor Regulation (NRR)

R. Capra, Director, Project Directorate I-1, NRR C. Cowgill, Chief, Projects Branch No. 1, Division of Reactor Projects (DRP)

D. Haverkamp, Chief, Reactor Projects Section No. 1B, DRP C. Hehl, Director, DRP W. Kane, Deputy Regional'Administrator W. Lanning, Deputy Director, Division of Reactor Safety (DRS)

R. Laura, Resident Inspector, Nine Mile Point T. Martin, Regional Administrator J. Menning, Project Manager, NRR W. Schmidt, Senior Resident Inspector, Nine Mile Point D. Screnci, Public Affairs Officer R. Summers, Project Engineer, DRP Nia ara Mohawk Power Cor oration R. Abbott, Manager, Engineering, NMP-2 R. Burtch, Jr., Manager, Nuclear Communications R. Crandall, UPS System Engineer J. Endries, President J. Firlit, Vice President - Nuclear Generation D. Greene, Manager, Licensing A. Julka, Supervisor, Electrical P. Kaleta, Attorney - Swidler & Berlin M. McCormick, Jr., Unit 2 Plant Manager J. Perry, Vice President - Quality Assurance N. Spagnoletti, Licensing Project Manager K. Sweet, Maintenance Manager - Unit 1 R. Sylvia, Executive Vice President - Nuclear C. Terry, Vice President - Nuclear Engineering J. Vinquist, CEO and President, MATS, Inc.

M. Wetterhahn, Attorney - Winston and Strawn S. Wilczek, Jr., Vice President - Nuclear Support G. Wilson, Managing Attorney Qtherg B. Rule, The Associated Press A. Smith, Syracuse Newspaper R. Zueriche, Nucleonics Week

ATTACHMENT 2 NIAGARA MOHAWK POWER CORPORATION NINE IVIILE POINT UNIT 2 NUCLEAR STATION AUGUST 28, 1991 NRC MEETING

AGENDA Opening Remarks and Expectations B. R. Sylvia Overview of UPS R. J. Crandall Maintenance Program M. J. McCormick Assessment of Event R. B. Abbott Plant Response Assessment of Operator Response Equipment Failure Analysis Summary of Pre-Start-up Assessment Items Emergency Preparedness Effectiveness Safety Assessments Status of Plant/Outage Restart Items M. J. McCormick Closing Remarks B. R. Sylvia

OPENING REMARKS AND EXPECTATIONS Page 1

MEETING OB JECTIVE Provide summary to NRC of results achieved to date

'btain NRC Region I agreement with remaining action items to be completed prior to restart of Nine Mile Point Unit 2.

Page 2

1 Recover Or anlzation Executive VP Nuclear O'. Ralph Sy'lyia ', .

VP.Nuclear Generation Joseph Firlit Plant'Manager'Unit 2 Marty McCormick,- Jr'.

Advisory Board Event

~ Carl Terry Assessment Outage Manager

~ Stan Wilczek, Jr. Manager

~ Don Hosmer

~ Kim Dahlberg

~ Rick Abbott Jim Perry

~ John Vinquist Safety Assessment - Jim Spadafore Plant Response - Tom Tomlinson Equipment Failure Analysis

~ UPS Uninterruptible Power Supply - John Conway

~ Main Transformers -

Steve Doty

~ Electrical Distribution System - Anil Julka

~ Others as required Emergency Plan Effectiveness - Al Salemi Assessment of Operator Response - Jerry Helker NRC Interface - Al Pinter

I OVERVIEW OF UPS Page 4

UPS FUNCTIONS Loss normal AC Loss inverter Static Switch Transfer Protective trips Page 6

NINE MILE PDINUNIT 2 SIMPI. IFIEO ELECTRICAL ORAWING 13,688 VOLT BUS (883! i)68 VOLT BUS 688 VOLT BUS ALTERNATE TRANSFORMER TRANSFORMER 688 VOLT BUS NORMAL IB. IO. IG (T'YP)

TO GRIO SCRIBA SWITCHYARO TRANSFORMER 688 VOLT BACK-UP OC RESERVE POwER SUPPLY STATION SERVICE TRANSFORMER E'ORMAL UPS BACK-UP OC POWER SUPPLY IH TRANSFORMER FAULT(. 688 VOLT BUS TRANSFORMER BACK-UP OC POWER SUPPLY MAIN SET-UP TRANSFORMERS TRANSFORHER SPARE NORHAL IA. IC NORMAL (TYP)

STATION SERVICE TRANSFORMER 13.688 VOLT BUS (88ll TURBINE GENERATOR 4I(.P v(N.T BUS 688 VOLT BUS ALTERNATE TRANSFORMER TRANSFORHER RESERVE STATION SERVICE TRANSFORMER UPS-A- CONTROL ROOH INOICATORS UPS = UNINTERRUPTIBLE

-B- CONTROL ROOH INOICATORS POWER SUPPLY

-C- PLANT LIGHTING PLANT LIGHTING

-G- PLANT COMPUI'ERS

-H- HAIN STACK EOUIPHENT - NOT AFFECTED OUE TO DIFFERENT DESIGN

EVENTS OF AUGUST 13TH Low AC voltage Fast transfer Lost UPS loads Page 6

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SIMPLIFIED EXIDE UPS CONTROL LOGIC 128 VAC INVERTER OUTPUT POWER SUPPLY T

CONTROL

) CB POWER TO LOGIC POWER SUPPLY K5 NORMALLY CLOSED PRIOR TO DESIGN CHANGE 128VAC FROM MAINTENANCE POWER PHASE B TO GND OUT4 JBP

SIMPLIFIED EXIDE UPS CONTROL LOGIC 128VAC INVERTER OUTPUT POWER SUPPLY T

CONTROL

) CB POWER TO LOGIC POWER K5 SUPPLY NORMALLY CLOSED S1 SUBSEQUENT TO DESIGN CHANGE 128VAC FROM MAINTENANCE POWER PHASE B TO GND OUT7 JBP

SYMPTOMS FOUND All 6 CB 1, 2 tripped, CB 3,4 open Module trip lights on except "D" (reset by operators) lnverter Logic Alarm A, B, C OV/UV Alarm D, G Voltage Diff. Alarm D, G Page 7

TRIP ALARMS INDICATOR LIGHTS

1) DC Undervoltage (DCUV) Breaker Trip

2) DC Overvoltage (DCOV)

3) Inverter Leg Fuse Blown

4) AC Undervoltage (ACUV)

5) AC Overvoltage (ACOV)

Logic Alarm

6) Frequency Failure

7) Logic Failure

8) Clock Failed

9) Logic Power Supply Failure

10) Overload (10 minute delay) Module Trip Page 8

INITIALRESTORATION Operators restored maint. supply Sys. Engr. Restarted C, 0, G "B" bad CB-3 breaker "A" tripped AC supply twice A, B left on maintenance Page 9

TROUBLESHOOTING C UNIT Various operational and trip checks Spurious trip during testing

'attery test

'aint. supply voltage tests Slow drop to 84.6 VAC - DC drop to 16.9 VDC logic t trip Slow drop to 45 VAC - K5 dropout Transient drops (100-200 msec.) - Logic trip 3 of 4 Maint. supply off - No logic trip Replace batteries Slow drop to 43 VAC - K5 dropout No trip 25 Transient drops {100-200 msec.) No trips All normal trips tested except DCOV Page 10

TROUBLESHOOTING D UNIT

'attery test Replace CB-2 (worn out)

'aint. supply voltage tests Slow drop to 84.6 VAC - 17.3 VDC Logic trip Slow drop to 42 VAC - K6 dropout Transient drops (100-200 msec.) 4 times No logic trip 6th time logic trip (lower starting voltage) 6th and 7th time logic trip (higher starting voltage)

Maint. supply off - No logic trip Replace batteries 6 transient drops (100-200 msec.) No logic trips Normal running voltage check Page 11

TROUBLESHOOTING D UNIT (CONT.)

'ransfer to maint. (visicorder)

Replace sticky CB-3 breaker (later)

Page 12

OTHER CHECKS

'ormal running voltage checks A, B, G

'attery tests/replacement (All units)

'eplace CB-3 on "B" Unit

'eplace feeder breaker on "A" Unit (later)

Battery test results

~Uni AsF un Normal A+ + 0.70 e-B+ - 1.50

+ 0.54

+ 18.3

- 18.3

+ 18.3

- 6.20 - 18.3 C+ 0.60 + 18.3 0.04 - 18.3 D+ 0.06 + 18.3

+ 0.14 - 18.3

+ 18.30 + 18.3

+ 0.69 - 18.3 Page 13

e POSSIBLE CAUSES

'round induced noise

'igh frequency noise from maint. supply

'egraded voltage on maint. supply and degraded control battery condition

'ther-laboratory testing in progress Page 14

PLANNED CORRECTIVE ACTIONS Battery replacement

'ogic supply modification

'eplacement of C and D Units 1992

'ossible replacement of A, B, G Page 15

MAINTENANCE PROGRAM Page 16

MAINTENANCE PROGRAM

'uclear Division Directive

'dministrative Procedures Surveillance Modification Corrective maintenance Preventive maintenance Technical Procedures Surveillance procedures Preventive maintenance procedures RG 1.33 Reliability Components

'orrective Maintenance Procedures Page 17

PREVENTIVE MAINTENANCE PROGRAM BASED ON:

Vendor manuals

'Q Requirements Incorporated

'eferral Approval Process Technical Revisions for Completeness SR Components Functional Tests and Calibrations

'eriodic reviews Procedure reviews Vendor manual updates Periodic assessments Operational experience Page 18

VENDOR MANUALPROGRAM

'ngineering Procedure for review New manual reviewed Changes reviewed Procedure impact identified during review

~ EQ Vendor manuals and EQ test reports reviewed for maintenance requirements Coordination ensures implementation

'endor manual upgrade Manuals reviewed in detail Vendor contacts for GL 90-03 being established Page 19

UPS PREYENTlVE MAlNTENANGE PROGRAM

'ER 2-91-Q-0011 initiated 4/91 Based on industry experience Consistency of UPS preventive maintenance program to ensure completeness Prioritized consistent with available information

'reventive maintenance program in place Covered manufacturers recommendations except periodic ba'ttery replacement Tasks included:

- Cleaning and inspection

- Meter readings

- Filters checked, replaced

- Lamp tests Page 20

UPS PREVENTIVE MAINTENANCE PROGRAM (CONT.)

'rending of meter readings

- Load reduction problems

- Some loads transferred Page 21

UPS VENDOR MANUALISSUES UPS's unique with generic manuals Vendor manual and drawings didn't reflect configuration in field Vendor manual indicated logic power from inverter

'attery was power for logic status lights and not control Battery replacement requirement in obscure location of manual and not with other maintenance requirements

'attery replacement is four years in manual Page 22

t

>8QQQ 23<0 2.3 ?NVERTER The rectifier/charger or battery OC output is the inverter input power. This OC voltage is filtered by shunt capacitors contained in DC capacitor assemblies.

The quantity of capacitor assemblies required varies with the KW rating of the UPS aedule, as listed here:

~KM Rat1n'0 Ca acitor Assemblies A15 60 A15, A16 100, 180 A15 250 A15, A16 330 A15, A16, A17 400, 450 A15, A16. A17, A18 DC is converted to AC by SCR switching action of the fnverter~egs-,'Al, etc.

Each adjacent pair of legs (f.e., Al and A2, etc.) constitutes a bridge circuit which supplies quasi-square-wave AC to one of the prfmary windings of the power transformers, Tl or T2. The 30 and 60 KM modules have only one power trans-former, Tl. Component designators for 300 IS and larger inverters are preceded by the numeral 2: e.g.. 2T2.. Refer to Figure 2-2.

Secondary wfndings of Tl and T2 are connected so that the resultant output is a balanced 3-phase voltage. Each line-to-line and lfne-to-neutral voltage would

~

appear as a near sine wave consfstfng of 12 steps. This wave form is filtered to provfde a good sine wave at the output termfnals by the filtering action of AC output filters, A21 (if used, A22 through A24), and by reactors, L3 through L8, connected between adjacent pairs of.fnverter legs.

The inverter senses fts output voltage and regulates within 1% tolerance for a wide varfatfon in load and OC input voltage. Various other sensing circuits provide protectfon alarm fndfcatfons. See Tables 2-1 and 2-2 for alarm descrfptfons.

A redundant logic supply, powered by the fnverter output, a separate 120 VAC bypass source. and/or internal rechargeable sealed batter fes. allows logic testing wfth no input power applfed and keeps alarms indicating for as long as any source of AC control power fs avaflable.

A static fnCarmptar fs part of the fnverter sensing cfrcufts. Whenever an UPS module Crlpi, ft aast be dfsconnected automatically and faaedfately from the crftfeN Toaf bus. Not provfdfng famedfate disconnection could result in out-of-toleeci-dfsturbance of-the- sen&ve crftfcal load.. The UPS module provides instantaneous output isolation vfa internal logic respondfng to any one of a number of control or protection sfgnals that "programs off" all of the fnverter legs. This produces a force-cotrttutated interruption of the fnverter output. assumfng power contfnufQ at the load.

The followfng fs a lfst of ~or fnverter components and brief descrfptfon of thefr functfons.

2-5

b. A orfmary function fs the storage, vfa R-S flfp-flops, of most alarms and all trfp functions and one display eP bias'o$ dl:1-;,;$

en card-mounted LEDs.

2.3.2. 10 Stat1c Switch Control A13A34.

This control determfnes the conditfon of the fnverter, bypass source, and critical load. It then logically determines whether or not the critical load should be transferred to the bypass source, It also determines whether the UPS can or should be restarted depending on the UPS condit1on and the critical load bus.

2.3.3 Control Panel A14 Th1s panel conta1ns control and status display components for the entire UPS mod&-. See Ffgure 2-3 5 Table 2-3 for location and description of each.

2.3.4 GC Capacitor Module, A15 (some modules up to A18, see paragraph 2.3}

Each sl1de-fn,module contafns DC f1lter capacitors that are fused fn groups of seven capacitors.

2.3.5 AC Out ut Filter Panel A21 These Ac capacitors are connected fn delta across the fnverter output to filter output, waveform. The capacitors have 1ntegral fnterrupt overcurrent protect-ion.

" 2.3.6 Lead Ofvfsfon and Interface Panel A26.

This panel provides interface between the card cage, A13, and the following:

a. Load-dfvfsfon current transformer loep (contafns burden resistors and loop-shortfng relays.

b. Coamutatfon-lfmft current transformers '(contafns burden res1stors ).

c. Lnvtrter voltage sensfng (potential transformers, 3-phase).

d. .S)gael synchronfzfng node (aeunts sync node transformer).

e. B1arn leg fuse sensfng (contafns optocoupled electrfcal blown fuse senefng).

2.3.7 Lo fc Power and Rel Panel A27. 1 This panel contafns posftfve and negative 20 VGC power .supplies (PS1 and PS2).

These power supplfes are powered through relay A27K1, wh1ch selects fnverter output (preferred or bypass (alternate) source. Posftfve and negative 18-V sealed batterfes A27BT1-BT6) are counted on this panel 'and are kept charged

~ ~

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by the power supplfes. Cfrcuft broakor A27C81 dfsconnects the battery from 2-10

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I' ogfc power bus, and logic puwer supply switcn A27Sl disconnects the power supply's 120 VAC input power, The panel also contains card-mounted

{A27Al) r lays which ihterface the A13 controls with external items such as cfrcuft breaker motor operators, shunt trip coils, and remote monitor panel functions. Control battery discharge sensing fs located on the A27A1 card.

(These batteries should be replaced at 4-year intervals.)

2.3.8 S tern Terminal Board Panel A30.

This panel contains terminal boards for all external control connections.,

2.3.9 Remote Al arm A30A1.

The remote alarm panel provides indications of the,UPS module status and has no control function. Alarms initiated by the UPS module are as follows:

a. TRANSFERRED TO BYPASS

b. BATTERY DISCHARGE

c. UPS MINOR ALARN

d. UPS $ 4JOR ALARM

e. OC UNDERVOLTAGE MARNING.

Dry contact relay closure fndfcates alarm condition. Contact rating fs 10 VA max., 100 V max., 0.1 A max., resistive.

2.3.10 Statfc Switch Le A33.

The static switch leg contains static switch power SCRs, SCR gate dr fvers, and overtemperature sensfng cfrcufts. The static switch leg provides an unfnterrupted transfer of critical load between the fnverter source and the util f ty bypass source.

2.3.11 Static Swftch Control Panel A34.

Thfs control panel senses crftfcal load and bypass source busses for feeding statfc swftch control card A13A34.. Power supplfes (PS1 and PS2) produce posftfve and Negatfve 20 VDC for statfc switch .leg (A33) and renote monitor.

2.3.12 AC Ff lter Reactor L3-L8.

Each reactor fflters the AC output of each fnverter leg to power transformer Tl (and T2 when used).

2.3.13 AC Out ut Fflter Harmonic Reactors L9 throu L11.

These reactors (fn combfnatfon wf th A21)'flter the output waveform.

2-11

II I

SECTION 3 MAINTENANCE AND TROUBLESHOOTING

3. 1 PREVENTIVE MAINTENANCE.

3.1.1 General.

4 A record log should be kept which should include periodic meter readings, maintenance, and any alarms and subsequent actions taken. Early recognition .

of deteriorating performance is important DANGER HIGH VOLTAGE ONLY QUALIFIED PERSONNEL SHOULD ATTEMPT TO SERVICE THIS EQUIPMENT.

IF INJURY DOES OCCUR, APPLY STANDARD TREAT$1ENT FOR ELECTRICAL SHOCK.

3.1.2 Air Filters.

The air filters should be changed every 2 months(even more frequently if they are dirty). The filters are comercially availab'le. Filters may be safely replaced while the UPS is operating and without opening the doors. Front filters (if so equipped) are accessible by loosening the two screws at the top corners of the hinged filter housing. The retainer chain allows the filter housing to tilt forward approximately 15 cm (6 inches)

.for Wilter removal. Bottom filters are accessible by loosening the wing bolts (two per filter) located on the front channel below the cabinet access doors. Nhen the bolts are loosened (approximately 1.5 cm (4 inch), it may be necessary to reach under and pull the hinged filter door down from the front (there are three magnetic clasps). The filter can now be easily replaced.

3.1.3 Lamp Test.

A lamp test may be performed with UPS operating.

3.1.4 Ph sical Ins ction.

It is recatmnded that the UPS be inspected annually for tightness of connections and for evidence of component damage or overheating.

ASSESSMENT OF EVENT Page 23

0 PLANT RESPONSE

'CRAM Summary Report including Sequence of Events completed

'etermined this transient is bounded by the USAR transient analysis

'arious equipment problems identified Page 24

EQUIPMENT PROBLEMS

'oss of feedwater pumps Inability to open feedwater pump suction valves

'ondensate booster pump trip (B)/auto restart of (A) pump

'eactor water clean-up system water hammer and isolation RCIC Flow Controller malfunction

'CIC Injection testable check valve position indication problem when system secured

'CIC Injection testable check valve position indication problem with system in operation Page 26

EQUIPMENT PROBLEMS (CONT.)

'ifficultyin obtaining reactor water coolant sample

'oss of Division II H,-O, sample pump

'roup 9 isolation on radiation element Page 26

ASSESSMENT OF OPERATOR RESPONSE Operator response/actions during and following the event were appropriate and commendable All plant parameters were stabilized and controlled

'raining has been effective in preparing operators for events of this nature Emergency Operating Procedures (EOPs) appropriately addressed control of station parameters

'imulator training of EOPs, static scenarios and non-licensed operators was noted strength Cycling of drywell/secondary containment vacuum breakers not completed within two hours of SRV actuation (T.S. 4.6.4.b.l); completed within two hours of discovery; SCRAM procedure upgrade.

Page 27

.I ASSESSMENT OF OPERATOR RESPONSE (CONT.)

'xpressed desire for additional training on UPS Potential procedure inadequacy - RWCU system isolation on high delta flow during system start up {root cause pending)

'rocedure deficiencies Manual restoration of bypass power to UPS loads Reopening feedwater suction valves without first opening bypass valves Page 28

EQUIPMENT FAILURE ANALYSES TRANSFORIVIER:

'nternal fault occurred in the "B" phase main step up transformer

'ecent operating data reviewed, including gas in oil analysis, and no adverse trends noted

'o discrepancies were found with operating or ynaintenance practices

'ther Phase Transformers A, C and D and Station Service Transformer tested satisfactorily "B" Phase Transformer will be transported offsite for investigation and root cause analysis "D" Phase Transformer readied for service Page 29

EQUIPIVIENT FAILURE ANALYSIS CONT.

ELECTRICAL DISTRIBUTION:

'he protective relaying schemes actuated and performed their intended function to isolate fault

'he Class IE divisional buses were continuously powered during this event from both '116KV offsite power feeds

'he unit protection scheme tripped the turbine

'he 13.8KV normal switchgear buses made a fast transfer to the reserve station service transformer The main generator, bus work and associated equipment were tested and found not to be adversely affected Page 30

UIVIMARY OF PRE-START-UP ASSESSMENT EVENT ITEMS Hardware and/or procedure fixes for feedwater valves Operating procedure change on RWCU pending root cause

'CIC Flow Controller Valve Group 9 isolation Procedure change for restoration of power to UPS loads Complete UPS root cause and associated corrective actions

'omplete operator training on UPS Revise recovery portion of SCRAM procedure to trigger check of SRV actuation Page 3't

'V

~ EMERGENCY PREPAREDNESS EFFECTiVENESS

'imely and accurate declaration of Unit 2 Site Area Emergency

'ood coordination and effective interface with off-site agencies

'elay in callout of emergency response organization because of conflict in callout procedure Untimely initiation of emergency personnel accountability

'ome confusion at road blocks and security access points which delayed some emergency response organization personnel entry Page 32

~ EMERGENCY PREPAREDNESS EFFECTIVENESS PRE START-UP CORRECTIVE ACTIONS

'mplement revised notification procedure

'uclear Security informed to immediately initiate emergency personnel accountability upon announcement of a station evacuation

'emorandum to all emergency response designees to carry access authorization identification with them at all times. Nuclear Security also informed that access

~ authorization identification holders are considered essential personnel and are to be allowed on site

'mergency Preparedness developed an Action Plan to accomplish other corrective actions Page 33

EMERGENCY PREPAREDNESS EFFECTIVENESS CORRECTIVE ACTIONS PLANNED Review Emergency Termination Criteria Procedure (EPP-26)

'eview Emergency Classification Declaration Procedure (EAP-2)

Page 34

SAFETY ASSESSMENT

'rovides evaluation of plant event against licensing basis for plant safe shutdown

'ssesses balance of plant systems and their effect on plant operation and operators ability to mitigate the event Provides recommendations to evaluate plant design improvements Page 35

4 STATUS OF PLANTIOUTAGE Page 36

o Pe

STATUS OF PLANT/OUTAGE

'nspected High Pressure Core Spray (HPCS) System Nozzle

- No indication of flaw growth

- No repair of nozzle safe end weld required

- NMPC will provide 30 day letter on results of inspection Repaired Inboard Containment Purge Isolation Valve O Rebuilt seals in "B" feedwater pump Completion of plant readiness for restart activities Page 37

OUTAGE RESTART ITEMS

1. Complete 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> main transformer soak and oil analysis

2. Drywell closure 3 ~ Design changes for UPS 1A, B, C, D, G are field complete. Post maintenance testing (PMT) required on UPS 1B and 1G.

4. Suppression pool closure

5. Install new seal on steam tunnel door

6. Close out ESL log entries. Approximately 36 entries to close

7. Hydro Reactor Pressure Vessel, verify integrity of RCIC Flange e Page 38

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