IR 05000244/1998004

Insp Rept 50-244/98-04 on 980406-0517.No Violations Noted. Major Areas Inspected:Operations,Maint & Plant Support

ML17265A322
Person / Time
Site:	Ginna
Issue date:	06/09/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17265A321	List: IR 05000244/1998004 ML17265A320
References
50-244-98-04, 50-244-98-4, NUDOCS 9806120288
Download: ML17265A322 (30)

Text

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

License No.

DPR-18 Report No.

50-244/98-04 Docket No.

50-244 Licensee:

Facility Name:

Location:

Inspection Period:

Inspectors:

Approved by:

Rochester Gas and Electric Corporation (RGRE)

R. E. Ginna Nuclear Power Plant 1503 Lake Road Ontario, New York 14519 April 6, 1998 through May 17, 1998 P. D. Drysdale, Senior Resident Inspector C. C. Osterholtz, Resident Inspector G.'S. Vissing, Senior Project Manager, NRR L. T. Doerflein, Chief Projects Branch

Division of Reactor Projects 980b120288 980b09 PDR ADQCK 05000244

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EXECUTIVE SUMMARY R. E. Ginna Nuclear Power Plant NRC Inspection Report 50-244/98-04 This inspection included aspects of licensee operations, maintenance, and plant support.

The report covers a 6-week period of resident inspection,

~Oerations The licensee successfully resolved a discrepancy in the steam generator tube rupture (SGTR) emergency operating procedure (EOP).

The administrative procedure governing the emergency procedures committee provided adequate guidance to ensure changes to EOPs could be properly implemented.

The inspectors noted additional discrepancies in the emergency contingency action (ECA) procedures which indicated the licensee's procedural review process could be strengthened.

The administrative procedure governing the implementation of emergency and abnormal operating procedures contained a weakness in that it potentially allowed the authority of a licensed SRO to be overruled by two licensed ROs during the performance of anticipatory actions or when performing actions where procedural guidance is not available.

The licensee's actions to resolve this issue through the emergency procedure committee were considered appropriate.

The infrequently performed evolution to replace the pressurizer pressure defeat switch was well conducted.

Control room operators maintained good control of primary plant pressure, and interfaced well with the Instrumentation and Control (ISC) technicians performing the work. Good management oversight was also noted throughout the evolution.

The Quality Awareness/Quality Control (QA/QC) subcommittee meeting was effective in identifying areas for improvement in the corrective action and quality assurance programs.

Good participation by all attendees was also noted.

Maintenance Maintenance and surveillance activities were performed in accordance with procedural requirements.

Plant equipment received adequate post-maintenance testing prior to its return to service.

The licensee practiced good personnel and plant safety practices.

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as-found and as-left test data met the expected performance values and the acceptance criteria stated in the Updated Final Safety Analysis Report.

The licensee employed good troubleshooting techniques and effectively utilized new test equipment to identify a failure mechanism in the B-CCW pump power supply breaker.

The licensee was taking appropriate action in response to the failure of the B-SW pump breaker to close on May 12, 1998. The adequacy of the licensee's broader corrective actions in response to the May 8, 1998 Notice of Violation (see IR 50-244/98-03) will be evaluated in a future inspectio Executive Summary (cont'd)

Careful and deliberate actions were observed to have been taken by the IRC technicians which contributed to the successful replacement of the pressurizer pressure defeat switch.

The switch replacement appeared to correct previously observed intermittent swings in primary system pressure, and the licensee's intention to perform further laboratory analysis on the replaced switch was considered appropriate.

Plant Su ort Proper radiological controls practices were observed during tours of the RC TABLEOF CONTENTS EXECUTIVE SUMMARY

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IV I ~ Operations

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01.2 Summary of Plant Status

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03.1 Emergency Operating Procedure Periodic Reviews and Revisions

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Operator Knowledge and Performance 04.1 Oper'ator Performance During Replacement of the Pressurizer Pressure Defeat Switch Quality Assurance in Operations 07.1 QA/QC Subcommittee Meeting Miscellaneous Operations Issues

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08.1 (Closed) URI 50-244/97-10-02:Conflicting Cautions in Emergency Procedure ES-1.3..

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M1 Conduct of Maintenance....

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M1.2 General Comments on Surveillance Activities M2 Maintenance and Material Condition of Facilities and Equipment.....

M2.1 B-Component Cooling Water (CCW) Pump Power Supply Breaker F 'Ilure M2.2 B-Service Water (SW) Pump Power Supply Breaker Failure....

M2.3 Pressurizer Pressure Instrument Channel Defeat Switch Replacement....,.....

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R1 Radiological Protection and Chemistry Controls.................

R1.1 Radiological Controls and Contaminated Areas

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Table of Contents (cont'd)

IV. Management Meeting s

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X1 Exit Meeting Summary,

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X3 Management Meeting Summary

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L2 Review of UFSAR Commitments

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1 2 ATTACHMENTS Attachment 1 - Partial List of Persons Contacted

- Inspection Procedures Used

- Items Opened, Closed, and Discussed

- List of Acronyms Used

Re ort Details I. 0 erations

Conduct of Operations'1.1 General Comments Ins ection Procedure IP 71707 The inspectors observed plant operations to verify that the facility was operated safely and in accordance with licensee procedures and regulatory requirements.

This review included tours of the. accessible areas of the facility, verification of engineered safeguards features (ESF) system operability, verification of proper control room and shift staffing, verification that the plant was operated in conformance with the improved technical specifications (ITS) and appropriate action statements for out of service equipment were implemented, and verification that logs and records accurately identified equipment status or deficiencies.

Operator performance throughout the inspection period was good.

'1.2 Summar of Plant Status At the beginning of the inspection period, the reactor was operating at 100%

power. Throughout the period, no operational transients or changes in reactor power occurred.

On April 20, 1998, a failure of the B-component cooling water (CCW) breaker occurred during performance of a periodic test, causing entry into a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> limiting condition for operation (LCO). The B-CCW breaker was replaced with a spare breaker, tested, and declared operable on April 22, 1998 (see section M-2.1). On May 12, 1998, the B-service water (SW) pump breaker failed to shut while performing a SW pump swap-over.

The B-SW pump breaker was also replaced with a spare breaker, tested, and declared operable on May 15, 1998 (see section M2.2).

Operations Procedures and Documentation 03.1 Emer enc 0 eratin Procedure Periodic Reviews and Revisions a.

Ins ection Sco e (71707)

The inspectors performed a review of emergency operating procedures (EOPs),

functional restoration (FR) procedures, and emergency contingency action (ECA)

procedures, and also reviewed the licensee's resolution to a self-identified discrepancy in one EOP.

Topical headings such as 01, MB, etc., are used in accordance with the NRC standardized reactor inspection report outline.

Individual reports are not expected to address all outline topic Observations and Findin s On March 25, 1998, during performance of a biennial plume exposure exercise, the licensee discovered that EOP E-3, "Steam Generator Tube Rupture," did not contain appropriate guidance for initiating a reactor coolant system (RCS) cooldown during a SGTR event, should the non-ruptured steam generator be unavailable for cooldown due to a failed atmospheric relief valve (ARV). Step 14 of EOP E-3 only indicated that a faulted steam generator should be used if no intact steam generator was available for cooldown, without considering the possibility that an intact steam generator could be unavailable without necessarily being faulted.

The licensee indicated that E-3 would be amended and evaluated per procedure A-206,

"Emergency Procedures Committee," to allow the use of a ruptured steam generator for cooldown if no intact or faulted steam generator is available.

The inspectors reviewed procedure A-206 as well as the proposed revision to EOP E-3. The revision added additional guidance to step 14 of E-3 indicating that if a ruptured steam generator must be used for RCS cooldown, a procedural transition should be made to step one of ECA-3.1, "SGTR With Loss of Reactor Coolant-Subcooled Recovery Desired," which provides appropriate direction should a ruptured steam generator be required for RCS cooldown.

The E-3 procedure revision was approved by the emergency procedures committee and issued on May 1, 1998. The inspectors noted that procedure 'A-206 required that emergency procedure committee membership include representatives from operations, training, quality control, and nuclear safety and licensing.

Procedure A-206 also required that emergency procedure changes be reviewed for technical adequacy and safety significance.

During review of the ECA procedures, the inspectors discovered that ECA-3.3,

"SGTR Without Pressurizer Pressure control," steps 27 and 35 had the identical problem as E-3 step 14, in that no guidance was provided to perform. an RCS cooldown with a ruptured steam generator should there be no available intact steam generator.

The inspectors also discovered that ECA-3.3 step 3 considered that pressurizer spray would always be available, if instrument air was available, and did not consider the possibility of a pressurizer spray valve failing closed, with instrument air available.

The licensee indicated that these ECA-3.3 discrepancies would be formally tracked and evaluated by the emergency procedure committee to determine the appropriate corrective action.

Conclusions The inspectors concluded that the licensee successfully resolved a discrepancy in the steam generator tube rupture (SGTR) emergency operating procedure (EOP).

'he administrative procedure governing the emergency procedures committee provided adequate guidance to ensure changes to EOPs could be properly implemented.

The inspectors noted additional discrepancies in the emergency contingency action (ECA) procedures which indicated the licensee's procedural review process could be strengthene.2 Administrative Re uirementsfor lm lementin Emer enc and Abnormal Procedures a o Ins ection Sco e (71707)

The inspectors reviewed the administrative procedure governing implementation of

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emergency and abnormal procedures.

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Observations and Findin s The inspectors reviewed procedure A-503.1, "Emergency and Abnormal Procedures Users Guide." The inspectors noted that step 3.6.1.7 of A-503.1 required a senior reactor operator (SRO) to obtain the concurrence of two other licensed operators prior to performing any action required in an emergency for which procedural guidance is not available.

Also, step 3.6.10.2 of A-503.1 indicated that any anticipatory actions during EOP implementation deemed necessary by the SRO should only be performed with the concurrence of two other licensed operators.

During the performance of any actions while manipulating EOPs it is, desirable that all members of the operating crew are in agreement with the course of action to be taken.

However, the ultimate authority of the SRO exercising command over the crew should not be challenged by licensed board operators.

10 CFR 50.54(l)

requires individuals responsible for directing the licensed activities of licensed operators to be licensed SROs.

The licensee indicated that it was not the intent of A-503.1 to allow two licensed ROs to overrule a licensed SRO, but agreed that procedure A-503.1 did provide a means where an SROs authority could be challenged.

The licensee subsequently indicated that procedure A-503.1 would be reviewed and revised by the emergency procedure committee to eliminate the potential for a challenge to a licensed SROs authority.

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Conclusions The administrative procedure governing the implementation of emergency and abnormal operating procedures contained a weakness in that it potentially allowed the authority of a licensed SRO to be overruled by two licensed ROs during the performance of anticipatory actions or when performing actions where procedural guidance is not available.

The licensee's actions to resolve this issue through the emergency procedure committee were considered appropriate.

Operator Knowledge and Performance 04.1 0 erator Performance Durin Re lacement of the Pressurizer Pressure Defeat Switch Ins ection Sco e (71707)

, The inspectors observed operational performance during the replacement of the pressurizer pressure defeat switch in the control roo b.

Observations and Findin s On May 7, 1998, a significant infrequently performed evolution (SIPE) was conducted to replace the pressurizer pressure defeat switch, requiring control room operators to maintain manual control of primary plant pressure (see section M2.3).

Prior to the evolution, the licensee conducted a pre-job briefing for I&C maintenance and operations personnel to coordinate the switch replacement, and an additional'icensed operator was added to the operating crew who was dedicated to maintaining pressurizer pressure during the switch replacement.

The operations manager was in the control room during the entire evolution, and no other activities'ere allowed in the control room.

During the replacement, control room operators appropriately maintained primary pressure between 2210 psig and 2260 psig, and no alarms or anomalous conditions occurred during the entire evolution.

c, Conclusions The infrequently performed evolution to replace the pressurizer pressure defeat switch was well conducted.

Control room operators maintained good control of primary plant pressure, and interfaced well with the I&C technicians performing the work. Good management oversight was also noted throughout the evolution.

Quality Assurance in Operations 07.1 QA QC Subcommittee Meetin a.

Ins ection Sco e (71707)

The inspectors observed to the licensee's discussions on quality awareness and control during a recent meeting of the QA/QC subcommittee.

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Observations and Findin s On May 13, 1998, the QA/QC subcommittee of the Nuclear Safety Audit Review Board (NSARB) met to review and discuss the status of the QA program, audits and surveillances, major events, and significant program activities.

The meeting was chaired by the Vice President Nuclear Operations and was attended by licensee management personnel.

The meeting focused on the licensee's corrective action'rogram.

The ACTION Report system is currently undergoing revision from a single page to a four page format to make it more user friendly and to provide more information on the disposition, tracking, and close out of a report.

The revision is expected to be implemented in July 1998.

The top ten action reports (issues of highest priority) were also discussed.

The recent failure of the B-SW pump breaker

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was identified as the number one priority issue (see section M2.2).

The committee discussed Revision 24 of the licensee's QA plan, which was sent to the NRC for approval.

The change would allow a 25% grace period for periodic audits and surveillances identified in the QA plan.

Since the specific activities were not explicitly identified, the NRC determined, as documented in a request for information letter dated April 6, 1998, that there was a need to identify each activity that the licensee wished to apply the 25% grace period in the QA plan.

The licensee subsequently identified five annual audits that would apply a 90 day grace period.

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Conclusions The inspectors concluded that the QA/QC subcommittee meeting was effective in identifying areas for improvement in the corrective action and quality assurance programs.

Good participation by all attendees was also noted.

Miscellaneous Operations Issues 08.1 Closed URI 50-244 97-10-02: Conflictin Cautions in Emer enc Procedure ES-1.3 URI 50-244/97-10-02was opened in November 1997 to address conflicting.

cautions in EOP ES-1.3, "Transfer to Cold Leg Recirculation."

The caution prior to step 1 stated that, "Injection flow to the RCS shall be maintained at all times."

Another caution prior to step 6 stated that, "Any pumps taking suction from the RWST should be stopped upon reaching the RWST lo-lo level alarm."

The licensee's EOP coordinator discussed the conflicting cautions with the Westinghouse Owners Group and on May 1, 1998, a new revision to ES-1.3 approved by the emergency procedure committee was issued.

The revision eliminated both original cautions, but added a new caution prior to the steps in the procedure that direct alignment to high head recirculation when the Refueling Water Storage Tank (RWST) level drops to less than 15%. The new caution read: "Sump Recirculation Flow to RCS Must Be Maintained at AllTimes, Except During Alignment for High Head Recirculation."

The new caution resolved the discrepancy, indicating the need to maintain injection flow while also addressing the need to realign emergency pump suctions to the containment sump when RWST inventory depletes.

The inspectors considered the revision appropriate.

The noted conflicting cautions were considered a procedural weakness, but were not considered a

violation of regulatory requirements.

This unresolved item is closed.,

II. Maintenance M1 Conduct of Maintenance M1.1 General Comments on Maintenance Activities a.

Ins ection Sco e (62707)

The inspectors observed portions of plant maintenance activities to verify that the correct parts and tools were utilized; the applicable industry codes and technical specification requirements were satisfied; adequate measures were in place to ensure personnel safety and prevent damage to plant structures, systems, and components; and to ensure that equipment operability was verified upon completion of post maintenance testing.

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Observations and Findin s The inspectors'observed all or portions of the following work activities:

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W.O. 19702911, chemical and volume control system (CVCS) cation ion exchanger A drain valve V-1171, "Clean Valve, Replace Bonnet and/or Diaphragm."

Procedure M-37.16A, Rev.20, "Manually Operated Grinnel Diaphragm Valve Inspection and Maintenance," observed on April 24, 1998.

W.O. 197002909, leak on CVCS piping where two inch demineralizer outlet line goes to CVCS cation ion exchanger A-outlet block valve V-1177, observed on April 24, 1998.

The leak had sprayed bcron on the existing lines and an adjacent wall. Welding was required to repair the leak.

W.O. 19800961, remove C-service water (SW) pump for refurbishment, reinstall replacement pump using maintenance procedure M-10.11, "Major Inspection of Service Water Pump C," observed on May 6, 7, and 8, 1998.

W.O. 19800281, replace pressurizer pressure channel defeat switch in control room, observed on May 7, 1998.

The switch was replaced due to problems related to a pressurizer pressure controller failure on March 3, 1998 (see section M2.3 below, and IR 50-244/98-02).

W.O 19802217, troubleshoot and repair/replace B-SW pump supply breaker, observed on May 12, 13, and 14, 1998.

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Conclusions The inspectors concluded that the observed maintenance activities were performed in accordance with procedural requirements.

Equipment'received adequate post-maintenance testing prior to its return to service.

Good personnel and plant safety practices were observed during the maintenance wor M1.2 General Comments on Surveillance Activities a.. Ins ection Sco e (61726)

The inspectors observed selected surveillance tests to verify that approved procedures were in use, procedure details were adequate, test instrumentation was properly calibrated and used, technical specifications were satisfied, testing was performed by knowledgeable personnel, and test results satisfied acceptance criteria or were properly dispositioned.

b.

'Observations and Findin s The inspectors observed portions of the following surveillance activities:

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PT-12.2, B-EDG, increased surveillance due to maintenance rule (a)(1) status and output breaker failure, observed during three tests on April 9, April 24, and IVlay 11, 1998.

C.

Conclusions The inspectors confirmed that the procedure used was current and properly followed. The shift supervisor properly authorized the surveillance work to proceed.

The licensee confirmed the qualifications of the surveillance test personnel involved in the tests.

The B-EDG met all of the acceptance criteria specified in the test procedures for operability.

M2 Maintenance and Material Condition of Facilities and Equipment M2.1 B-Com onent Coolin Water CCW Pum Power Suo I

Breaker Failure a.

Ins ection Sco e (62707)

The inspectors reviewed the'icensee's actions in response to a failure of the B-CCW pump power supply breaker.

b.

Observations and Findin s On April 20, 1998, the B-CCW pump supply breaker (Westinghouse DB-50) failed to close after a successful closure had been accomplished in accordance with PT-2.8,

"Component Cooling Water Pump Quarterly Test." The surveillance'ad been successfully performed without incident, but when operations personnel attempted to restart the B-CCW pump following the PT, the power supply breaker momentarily cycled to the closed position but failed to latch and tripped free.

Operators entered Improved Technical Specification (ITS) Limiting Condition for Operation (LCO)

3.7.7.A, which allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for one CCW train to be out of service.

While the B-CCW train was inoperable, the licensee demonstrated good risk management by establishing "protected area" boundary markers in the A-EDG room,

and around the A-CCW pump area to prevent any work that could potentially jeopardize the operability of the operating CCW train.

The licensee did not attempt to close the breaker a second time so that the precise configuration of the failed breaker could be inspected and examined for better troubleshooting, and to aid in developing a coordinated plan for finding the root cause of the failure. Testing was performed with the breaker still in place in its cubicle, encompassing both the control circuitry as well as inspection of visible breaker mechanical and electrical components.

No apparent cause of the failure could be determined at the cubicle.

The breaker was therefore removed from its cubicle and taken to the electric shop for bench testing, The licensee installed test equipment to examine the breaker performance during troubleshooting in the electric shop.

The licensee purchased a high speed video camera and used it to assist in troubleshooting.

The use of the video camera permitted examination of small increments of motion in the breaker contacts, relays, tripper bar, closing coil, and X-coil. After examination of breaker performance, on the high speed video, the licensee discovered that the breaker's X-coil was de-energizing prior to the breaker reaching full engagement in the shut position.

The trace from the test equipment also indicated that the X-coil was de-energizing early.

While troubleshooting on the failed breaker continued, the licensee installed a spare DB-50 breaker in the B-CCW pump cubicle and verified that it had satisfactory X-coil timing using the high speed video camera.

The licensee successfully ran PT-2.8Q, and declared the B-CCW pump operable on April 22, 1998.

The licensee indicated that the failed breaker was one of the newer breakers the licensee had in stock, having been purchased in 1985. The licensee expanded the scope for failure mechanisms and root causes associated with the Westinghouse DB-50 power supply breaker due to the recent increase in Westinghouse DB-75 and DB-25 power supply breaker failures (see IR 50-244/98-03).

Further evaluation and root cause analysis of the failed B-CCW power supply breaker was still in progress at the end of the inspection period.

Conclusions The licensee employed good troubleshooting techniques and effectively utilized new test equipment to identify a failure mechanism'in the B-CCW pump power supply breaker.

B-Service Water SW Pum Power Su I

Breaker Failure Ins ection Sco e (62707)

The inspectors reviewed the licensee's actions following a failure of the B-SW pump power supply breake b.

Observations and Findin s On May 12, 1998, at 1:48 p.m. while swapping service water pumps following maintenance on the C-SW pump, operators received a safeguard breaker trip annunciator on the main control board and a white light indication for the B-SW pump.

The C-SW pump was being operated to provide a run-in time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to assure continuous operation of the pump and was still inoperable by ITS. It was the licensee's intent to place the B-SW pump in operation, but since the breaker failed, it was declared inoperable and the A-SW pump was operated.

This left only two pumps operable by ITS definition. However, ITS operability requirements were still satisfied since each SW train had an operable pump.

The breaker (Westinghouse model DB-25) was removed from its cubicle in the screen house and taken to the electrical shop for root cause investigation.

The licensee opened ACTION Report 98-0694to initiate an investigation to determine the, root cause and corrective actions for the failure. A team was assembled to analyze and inspect the breaker to determine the root cause of the failure. The approach to the investigation was to visually inspect the breaker without operating or disturbing any components.

The licensee had what they identified as a fault tree diagram to support the investigation, consisting of a block diagram identifying approximately 60 possible failure modes that could contribute to the failure of the breaker to close.

The team determined through visual inspection those possible failure modes that did not contribute to the failure of the breaker.

The team also implemented a test program to test the control circuitry of the B-SW pump, and as a result found no deficiencies in the control circuitry. However, as a precaution, the licensee replaced the breaker control switch.

Since the root cause investigation did not identify the root cause of the breaker failure, the licensee was considering either disassembling the breaker to Inspect its components or sending it to the manufacturer for analysis and refurbishment.

The inspectors observed investigation activities in the electrical shop and in the control room. The licensee was being guided by the vendor's manual, their own experience, and the aid of a consultant.

During troubleshooting, the licensee observed that a pin was missing from the breaker's operating mechanism.

A review of the work history of this breaker revealed that it had been sent to the Westinghouse Repair 5 Replacement Services (RRS) facility in Cheswick, PA in 1992 for refurbishment.

Documentation available in the licensee's maintenance department indicated that the breaker was apparently returned from the RRS without the pin in the operating mechanism.

The licensee also noted that the power supply breaker for the Technical Support Center (TSC) had been sent to the RRS for refurbishment and was returned with an oversized pin in the same location.

The breaker failure could not be reproduced by the plant staff when the pin was properly installed.

At the end of the inspection period, the licensee had not confirmed the root cause of the breaker failure, but it appeared that the cause was related to the missing operating mechanism pin. The inspectors determined that the licensee intended to consult with Westinghouse and was considering sending the breaker to the RRS for further evaluation and refurbishmen The inspectors noted that the B-SW pump breaker had previously failed on March 24, 1998, following annual preventive maintenance (see IR 50-244/98-03).

. On May 8, 1998, the NRC issued a Notice of Violation (NOV) for ineffective corrective actions for this and previous failures of the B-SW pump breaker.

The overall effectiveness of the licensee's actions for the May 12, 1998 failure and the broader corrective actions in response to the May 8, 1998 NOV will be assessed in a future inspection period.

C.

Conclusions The inspectors concluded that the licensee was taking appropriate action in response to the failure of the B-SW pump breaker to close on May 12, 1998.

The adequacy of the licensee's broader corrective actions in response to the May 8, 1998 Notice of Violation (see IR 50-244/98-03) will be evaluated in a future inspection.

M2.3 Pressurizer Pressure Instrument Channel Defeat Switch Re lacement a 0 Ins ection Sco e (62707)

The inspectors observed the replacement of the pressurizer pressure defeat switch in the control room.

b.

Observations and Findin s Following the inadvertent lifting of a pressurizer power operated relief valve (PORV)

on March 3, 1998 (see IR 50-244/98-02),the licensee determined that the pressurizer pr'essure defeat switch (P/429A) in the control room was faulty, and needed to be replaced.

Although the switch functioned normally after that event, small intermittent primary pressure swings (10 psi) were noted on the plant computer.

Consequently, the licensee prepared a work package to replace the switch.

The inspector observed portions of the replacement and testing activities in the control room.

ISC technicians followed the work instruction procedure steps with deliberate actions and maintained good communications with control room operators (see section 04.1). The switch replacement was temporarily postponed when the IRC technicians discovered that a grounding connection was missing for a shielded wire between controller PC431K and switch P/429A. The licensee evaluated this condition and determined that the connection should be restored to the configuration indicated on the wiring diagram for the switch, and the repair was accomplished.

The technicians also noted several terminal screws that were not fullytightened, and replaced one set of fork type terminal lugs with ring type lugs.

Following the replacement, pressurizer pressure remained stable and no intermittent pressure swings were observed.

The licensee indicated that a laboratory analysis would be performed on the replaced switch to determine the condition of its contacts and to evaluate the potential for 10 CFR 21 reportability of any faulty conditions note c.

Conclusions Careful and deliberate actions were observed to have been taken by the IKC technicians which contributed to the successful replacement of the pressurizer pressure defeat switch. The switch replacement appeared to correct previously observed intermittent swings in primary system pressure, and the licensee's intention to perform further laboratory analysis on the replaced switch was considered appropriate.

III. Plant Su ort R1 Radiological Protection and Chemistry Controls R1.1 Radiolo ical Controls and Contaminated Areas.

a.

Ins ection Sco e 71750 The inspectors performed tours of the radiologically controlled area (RCA) to verify appropriate radiation control practices were in place.

b.

Observations and Findin s The radiological survey maps located at the entrance to the RCA were detailed and maintained current. The radiological protection staff closely monitored personnel ingress and egress from the RCA including a discussion to ensure proper understanding of radiation work permit (RWP) requirements.

The inspector questioned plant workers in the RCA who were determined to be knowledgeable of their respective RWP requirements.

Radiation survey equipment was within the periodic calibration frequency.

Contaminated areas were properly posted with signs and boundary tape to minimize the potential spread of contamination.

The residual heat removal (RHR) pump and charging pump rooms remained contaminated with no current plans for decontamination.

The licensee indicated that the radiation dose that would be absorbed by personnel performing decontamination activities in these rooms did not warrant maintaining them clean.

Overall, the inspector determined that proper radiological controls were in place to minimize the spread of contamination and maintain worker exposure as-low-as-reasonably-achievable (ALARA).

C.

Conclusions Proper radiological controls practices were observed during tours of the RC IV. Mana ement Meetin s

X1 Exit Meeting Summary After the inspection was concluded, the inspectors presented the results to members of licensee management on May 29, 1998. The licensee acknowledged the findings presented.

The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.

No proprietary information was identified.

X3 Management Meeting Summary A public meeting between NRC Region I and RGKE management was held on April 22, 1998, at the Ginna Training Center, for the NRC to present the results of the Systematic Assessment of Licensee Performance (SALP) reported in Inspection Report 50-244/98-99.

The meeting was attended by Mr. Hubert J. Miller, Region I

Regional Administrator; Mr. Richard V. Crlenjak, Deputy Director, Division of Reactor Projects; and Mr. Lawrence T. Doerflein, Branch Chief, Reactor Projects Branch

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L2 Review of UFSAR Commitments While performing the inspections discussed in this report, the inspector reviewed the applicable portions of the UFSAR that related to the areas inspected.

The inspector verified that the UFSAR wording was consistent with the observed plant practices, procedure and/or parameter ATTACHMENTI PARTIALLIST OF PERSONS CONTACTED Licensee T. Alexander B. Flynn C. Forkell G. Graus J. Hotchkiss M. Lilley R. Marchionda R. Mecredy R. Ploof J. Smith J. Widay T. White G. Wrobel Nuclear Assurance Man'ager (Acting)

Primary Systems Engineering Manager Electrical Systems Engineering Manager ISC/Electrical Maintenance Manager Mechanical Maintenance Manager Quality Assurance Manager Production Superintendent Vice President, Nuclear Operations Secondary Systems Engineering Manager Maintenance Superintendent Plant Manager Operations Manager Nuclear Safety 5 Licensing Manager

Attachment I

INSPECTION PROCEDURES USED IP 40500:

IP 61726:

IP 62707:

IP 71707:

IP 71750:

IP 92901:

Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Surveillance Observation Maintenance Observation Plant Operations Plant Support Follow-up - Operations Closed URI 97-10-02 ITEMS OPENED, CLOSED, AND DISCUSSED Conflicting Cautions in Emergency Procedure ES-Attachment I

LIST OF ACRONYMS USED ARV CCW CFR CVCS ECA EDG EOP ESF FR IFI IR ITS LCO NRC NRR NSARB PORV PT pslg PWR QA QC RCA RCS RGKE RHR RO RP RRS RWP RWST SGTR SIPE SRO SW TSC UFSAR URI VIO Atmospheric Relief Valve Component Cooling Water Code of Federal Regulations Chemical and Volume Control System Emergency Contingency Action Emergency Diesel Generator Emergency Operating Procedure Engineered Safety Feature Functional Restoration Inspector Follow-up Item

Inspection Report

Improved Technical Specification

Limiting Condition for Operation

Nuclear Regulatory Commission

Nuclear Reactor Regulation

Nuclear Safety Audit and Review Board

Power Operated Relief Valve

Periodic Test

pounds per square inch gage

Pressurized Water Reactor

Quality Assurance

Quality Control

Radiologically Controlled Area

Reactor Coolant System

Rochester Gas and Electric Corporation

Residual Heat Removal

Reactor Operator

Radiation Protection

Repair and Replacement Services

Radiation Work Permit

Refueling Water Storage Tank

Steam Generator Tube Rupture

Significant Infrequently Performed Evolution

Senior Reactor Operator

Service Water

Technical Support Center

Updated Final Safety Analysis Report

Unresolved Item

Violation

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