IR 05000244/1998007
| ML17265A373 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 07/20/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17265A371 | List: |
| References | |
| 50-244-98-07, 50-244-98-7, NUDOCS 9807240244 | |
| Download: ML17265A373 (28) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
License No.
DPR-18 Report No.
50-244/98-07 Docket No.
50-244 Licensee:
Rochester Gas and Electric Corporation (RGRE)
Facility Name:
R. E. Ginna Nuclear Power Plant Location:
1503 Lake Road Ontario, New York 14519 Inspection Period:
May 18, 1998 through June 21, 1998 Inspectors:
P. D. Drysdale, Senior Resident Inspector, Ginna C. C. Osterholtz, Resident Inspector, Ginna R. A. Laura, Senior Resident Inspector, Pilgrim R. J. Arrighi, Resident Inspector, Pilgrim Approved by:
L. T. Doerflein, Chief Projects Branch
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Division of Reactor Projects
'7807240244 980720 PDR ADOCK 05000244
EXECUTIVE SUMMARY R. E. Ginna Nuclear Power Plant NRC Inspection Report 50-244/98-07 This inspection included aspects of licensee operations, engineering, maintenance, and plant support.
The report covers a 5-week period of Ginna resident inspection, and the results of inspections by resident inspectors from the Pilgrim Nuclear Power Plant.
~Oeretione The locked valve program was not.well defined, was not effectively implemented, and operator training was lacking in this area, as evidented by a broad variation of responses from operators interviewed about how valves should be locked.
No locked valves were found out of their required positions, and no safety consequences resulted from discrepancies observed in the implementation of the program.
r The licensee's corrective action process was weak in that it did not maintain a formal tracking system to assure operability assessment follow-up activities are taken to completion.
However, the number of incomplete actions planned for follow-up to operability assessments was low, and the licensee intended to implement a follow-up tracking system as part of a planned revision to their corrective action program.
Maintenance Plant equipment received adequate post-maintenance testing prior to its return to service.
Good personnel and plant safety practices were observed during the maintenance work.
The licensee successfully replaced the 9-A reactor trip relay within the time constraints of the ITS LCD. However, the inability to identify that an incorrect replacement part had been requisitioned until just prior to installation indicated deficiencies in the licensee's work planning and requisitioning of spare parts.
In addition, potential inventory control deficiencies may have existed in the plant stockroom.
~En ineerin The licensee's containment recirculation fan cooler tests and subsequent performance analysis represented good progress toward completion of the GL 89-13 program.
The performance analysis appeared to support the licensee's conclusion that a 54 month preventive maintenance cleaning cycle for each cooler would maintain their heat removal capacity within design limits for accident heat loads.
Although actual test results indicated that the CS system has not operated outside its design basis, the lack of specific flow calculations for the CS system chemical eductor flow requirements represented a weakness in the plant's design basis record Executive Summary (cont'd)
The licensee made procedure and programmatic changes to assure that maintenance team debriefings were pr'operly conducted, and to improve the accuracy of field information conveyed to EP managers during exercises.
Debriefings conducted during the recent plume exposure exercise were effective and significantly improve TABLE OF CONTENTS EXECUTIVE SUMMARY
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IV I. Operations
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Conduct of Operations....... ~..... ~.......
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01,1 General Comments..... ~... ~...
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01.2 Summary of Plant Status Operational Status of Facilities and Equipment 02.1 Locked Valve Program Review. ~...
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Operations Procedures and Documentation
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03.1 Operability Assessment Follow-up Tracking Operator Training and Qualification 05.1 (Updated) IFI 50-244/97-09-01: Administration of In-Plant Job Performance Measures (JPMs)
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08.1 (Closed) IFI 50-244/98-02-02:Corrective Actions for Pressurizer Pressure Transient
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08.2 (Closed) IFI 50-244/97-07-02:Operable Boration Flow Path Requirements in MODES 5 and 6.. ~,...............
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.:. 5 I. Maintenance I
M1 Conduct of Maintenance...
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M1.1 General Comments on Maintenance Activities...
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M1.2 General Comments on Surveillance Activities M2 Maintenance and Material Condition of Facilities and Equipment
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M2.1 Replacement of Reactor Trip Relay RT-9-A
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E2 Engineering Support of Facilities and Equipment E2.1 Thermal Performance Analysis and Preventive Maintenance Frequencies for Containment Recirculation Fan Coolers (CRFCs)
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E2.2 Containment Spray System Periodic Surveillance Testing and Sodium Hydroxide Eductor Performance Requirements..
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I P8 Miscellaneous EP Issues -;..................................
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. (Closed) IFI 50-244/97-04-01;Maintenance Team Debriefings During Emergency Preparedness Exercises.................
Table of Contents (cont'd)
V. Management Meetings.....
X1 Exit Meeting Summary............
L2 Review of UFSAR Commitments.....
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I 1 3 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.
01.2 Summar of Plant Status At the beginning of the inspection period, the reactor was operating at 100%
power.
Minor'reductions in reactor power were performed on May 19, May 26, and May 27 to perform a turbine driven auxiliary feedwater pump (TDAFW) surveillance, and nuclear instrument axial offset calibrations.
On June 17, 1998, the A-train of the reactor protection system was removed from service for approximately four hours to replace a failed reactor trip relay (see section M2.1) ~
Operational Status of Facilities and Equipment
,. 02.1 Locked Valve Pro ram Review a.
Ins ection Sco e (71707)
The inspector examined locking devices on plant valves and assessed the effectiveness of the licensee's locked valve program.
b.
Observations and Findin s H
During an inspection of the A-emergency diesel generator (A-EDG) room on June 2, 1998, the inspector observed that the installed locking chain on valve V-12398F (A-Diesel Generator Fuel Oil Day Tank Level Instrument Root Valve), was incorrectly installed in that the chain could have been removed without unlocking its padlock.
The inspector immediately notified the control room operators who dispatched an auxiliary operator to properly install the lock and chain.
Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline.
Individual reports are not'xpected to address all outline topic On June 8, 1998, an auxiliary operator determined that the locking device on valve V-1249 (Monitor Tank Pump Discharge Isolation Valve to Waste Discharge Line)
was not properly installed.
The licensee subsequently performed procedure A-52.2,
"Control of Locked Valve and Breaker Operation," to verify that all valves outside containment required by procedure to be locked had their locking devices properly installed.
This action was completed on June 9, 1998.
During the same day, the inspector independently evaluated the locking chains on seventy-four plant valves outside containment.
The inspector observed that seven containment isolation valves (CIVs) had chains installed with excess slack which could allow valve movement from 1/2 to 2/3 of full handwheel rotation.
All of the valves were in their required locked closed position; however, two valves (V-7448 and V-7452)
had enough slack in their chains to allow full value position change without unlocking their padlocks.
The inspector also identified that procedure A'-52.2 incorrectly labelled valves V-1560 and V-1562. The licensee initiated a procedure change notice to correct these errors.
The inspector discussed his observations with the shift supervisor and control room foreman.
The operations manager subsequently directed operators to re-perform the A-52.2 procedure to assure that all valve chains were properly secured in accordance with the procedure and that they could not be removed from valve handles.
The reverification was completed on June 10, 1998.
The inspector interviewed several operators and observed that there was very little understanding of the requirements for valve locking devices, as provided by procedure A52.2. Operators indicated that the only training they received on locked valves was focused on the method to check a valve's position, and did not include any instruction on how to properly lock a valve.
The operations manager also indicated that a training work request would be initiated to evaluate the need for additional operator training in this area.
C.
Conclusions The locked valve program was not effectively implemented and operator training was lacking in this area, as evidented by a broad variation of responses from operators interviewed about how valves should be locked.
No locked valves were found out of their required positions, and no safety consequences resulted from discrepancies observed in the implementation of the program.
Operations Procedures and Documentation 03.1 0 erabilit Assessment Follow-u Trackin a.
Ins ection Sco e (71707)
The inspectors reviewed the licensee's tracking of follow-up activities for operability assessment b.
Observations Findin s and Conclusions The inspector reviewed a synopsis of all ACTION Reports'that had operability assessments associated with them and identified that the licensee did not have a mechanism in place to flag those operability assessments that still had outstanding actions needed to resolve all operability concerns.
The licensee indicated that these follow-up activities were presently being pursued individually, but that a tracking process would be implemented on July 1, 1998, and would include a process to track follow-up activities after operability assessments were completed.
The licensee indicated that six recent operability assessments pertaining to safety-related equipment still had follow-up actions that needed to be completed.
The assessments included completion of valve testing, approval of engineering analyses, correction of system drawings, and optimizing diesel generator control relays.
The inspector concluded that the licensee's corrective action process was weak in that it did not maintain a formal tracking system to assure operability assessment follow-up activities were taken to completion.
However, the number of incomplete actions planned for follow-up to operability assessments was low, and the licensee intended to implement a follow-up tracking system as part of a planned revision to their corrective action program.
Operator Training and Qualification 05.1 U dated IFI 50-244 97-09-01:Administration of In-Plant Job Performance a
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Ins ection Sco e (92901)
The inspector reviewed the licensee's JPM examination bank and the process for administering in-plant JPMs.
Observations and Findin s The inspector reviewed approximately 100 in-plant JPMs in the examination bank.
The inspector noted that 42 of the JPMs reviewed contained some type of deficiency.
Most of the deficiencies involved incomplete or inappropriate cues for the examination administrator to provide to the operator.
For example, JPM J079.001, "Startup and Align Diesel Driven Air Compressor," cued the operator that the valves and switches were in the "required position," instead of cuing the operator that the valve turns in the direction attempted, or that a switch had been moved left/right or up/down.
Other JPMs, including J006.003, "Perform Local Valve Lineup to Make Up Nitrogen to Accumulator," contained no cues at all for valve manipulations.
Several other less common, but more significant JPM deficiencies were also n'oted.
JPM J083.002, "PPCS Out of Service Requirements,"
had no steps, identified as critical in order to successfully accomplish the task.
Other JPMs, such as
J078.004, "Check Nitrogen Supply to the Atmospheric Relief Valves," only required the operator to find and read a pressure gage without having to manipulate any equipment or interpret any data in order to successfully complete the JPM.
The inspector also noted that JPM J012.007, "Locally Trip Reactor and Turbine,"
allowed twenty-two minutes for an operator to locally trip the reactor and turbine, should the reactor and turbine not automatically trip when required.
The licensee agreed with the inspector that a "minimallycompetent" operator could trip the reactor and the turbine in less than ten minutes.
The inspectors reviewed the noted JPM weaknesses with a tr'aining department representative.
The licensee indicated that the entire JPM bank would be reviewed and upgraded over the next several months.
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Conclusions The inspector concluded that multiple deficiencies in the in-plant JPM bank contributed to previously noted weaknesses in the administration of requalification examinations.
The licensee intended to enhance the quality of the in-plant JPM bank; however, pending review of these enhancements, this item willremain open (IFI 50-244/97-09-01).
IVliscellaneous Operations Issues 08.1 Closed IFI 50-244 98-02-02:Corrective Actions for Pressurizer Pressure Transient a.
Ins ection Sco e (92901)
The inspectors reviewed the human performance evaluation system (HPES) report the licensee completed in response to a recent pressurizer pressure transient.
b.
Observations and Findin s IFI 50-244/98-02-02was opened in March 1998 to evaluate the licensee's review of human performance aspects pertaining to the event that occurred on March 3, 1998, in which pressurizer pressure increased to the opening setpoint of a power-operated relief valve (PORV).
On April 20, 1998, the licensee completed the HPES report which focused on the root causes and contributing factors to the event, and determined the necessary corrective actions.
The report determined that the root cause of the event was a failure of control room operators to monitor, detect, and respond to main control board indications and primary plant computer system (PPCS) alarms caused by the failure of a pressurizer pressure defeat switch.
Factors that contributed to the event included an operator distraction caused by their use of a recently installed auto log system, and a six minute delay in the alarm for the equipment out of service monitor following the failure of the pressurizer pressure defeat switc i
The licensee implemented corrective actions in response to the HPES which included the following:
Operations management reinforced to the operating crews the importance of promptly acknowledging all PPCS alarms, and to terminate any administrative activities when alarms or abnormal indications are received.
Detailed laboratory analysis was performed on the failed pressurizer pressure defeat switch.
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The operating shift that experienced the event discussed the event with other shifts.
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Operations evaluated the impact of process changes in the control room such as the auto log computer system and the equipment out of service monitor.
The HPES also included a detailed event time line using block diagrams that were helpful in understanding the sequence of events.
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Conclusions The inspectors concluded that the HPES performed in response to the pressurizer pressure transient of March 3, 1998, was very thorough, and clearly identified the sequence of events and contributing factors.
The final report adequately described the significant event precursors and identified the most probable root causes.
The corrective actions to increase operator awareness of control room indications appeared adequate.
This item is closed (IFI 50-244/98-02-02).
08.2 Closed IFI 50-244 97-07-02:0 erable Boration Flow Path Re uirements in MODES 5 and 6 a.
Ins ection Sco e (92901)
The inspectors reviewed the reactor boration flowpath requirements for operating MODES 5 and 6.
b.
Observations and Findin s IFI 50-244/97-07-02was opened in June 1997 to follow-up NRC questions concerning a safety evaluation that supported the removal from the technical requirements manual (TRM) of a requirement to maintain an operable boron injection flowpath in MODES 5 and 6. This requirement was removed from the TRM after the licensee adapted the Improved Technical Specifications (ITS) in February 1996.
The ITS contained requirements for maintaining a minimum shutdown margin in MODES 5 5 6, and the ITS basis for the required boron concentration (3.9.1)
addressed operator actions following a dilution accident during refueling operations (Mode 6). The basis indicate that an operator has at least 48.8 minutes before
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shutdown margin would be lost and before the reactor could go critical. This was considered sufficient time for operators to isolate the dilution source (by closing valves or stopping the reactor makeup water pumps).
Additionally, the ITS basis for shutdown margin (3.1.1) indicated that 15 minutes was an adequate amount of time for an operator to correctly align and start required systems and components, should boration be required following a loss of shutdown margin in Mode 5.
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Conclusions The inspectors concluded that sufficient time would be available for operators to take action to mitigate the consequences of a dilution accident in Modes 5 and 6, and that removal of the TRM requirement for an operable flowpath in MODES 5 5'6 was adequately justified. This item is closed (IFI 50-244/97-07-02).
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 e'quipment operability'was verified upon completion of post maintenance testing.
b.
Observations and Findin s The inspectors observed all or portions of the following work activities:
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W.O. 19703724, CPI-AXIAL-N44A,Axial offset calibration of nuclear instrument N44A, observed on May 27, 1998
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W.O. 19802322, Replacement of auto/manual controller for spray valve PCV-431 A
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M-71.8, Operational Check and/or Calibration of Foxboro 62H Controller and 67H Auto/Man Station
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W.O. 19802447, corrective maintenance on check valve 3504B, B-train turbine driven auxiliary feedwater (TDAFW) pump steam supply check valve, observed on June 3, 1998
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W.O. 19802556,A-train reactor trip relay RT-9-A replacement, observed on June 17, 1998 (see section M2.1)
c.
Conclusions Following the maintenance activities described above, all equipment received adequate post-maintenance testing prior to its return to service.
Good personnel and plant safety practices were observed during the maintenance work.
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
'I The inspectors observed portions of the following surveillance activities:
PT-16Q-T, "AuxiliaryFeedwater Turbine Pump - Quarterly;" observed on May 19, 1998 PT-12.2, "Emergency Diesel Generator B;" observed on May 20, 1998 PT-32A, "Reactor Trip Breaker Testing, A-Train;" observed on June 17, 1998 c.
Conclusions The inspectors confirmed that procedures used were current and properly followed.
The shift supervisor properly authorized surveillance work to proceed.
The licensee confirmed the qualifications of the surveillance test personnel involved in the tests.
The equipment tested met all of the acceptance criteria specified in the test
'procedures for operability.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Re lacement of Reactor Tri Rela RT-9-A a.'ns ection Sco e (62707)
The inspectors observed the licensee replace a failed reactor trip breaker relay, and evaluated problems associated with incorrect parts that were requisitioned for the wor Observations and Findin s On June 14, 1998, operators noted that the "target" for reactor trip breaker relay RT-9-A (input from reactor coolant system flow) was exposed indicating a potentially open reactor trip breaker.
No interruption in reactor operation was apparent at the time, but operators were not able to reset the relay.
Troubleshooting was initiated to investigate the cause of the target indication.
Upon investigation, the licensee determined that the relay had failed from high
'emperature and needed to be replaced.
On June 17, 1998, the licensee prepared a work package to replace the relay, and conducted pre-job briefings to assure that the replacement could be accomplished with the six hours permitted by ITS LCO 3.3.1, Condition R, while the A-train reactor trip system was inoperable.
1&C technicians conducted shop testing on the replacement relay, and determined that it was acceptable for installation.
However, just prior to the actual installation, an I&C technician noted that the replacement relay was a shorter length than the relay that was removed.
Upon investigation, the licensee determined that the replacement relay coil was rated for a 120 VAC application, whereas, the failed relay was installed in a 125 VDC system.
The licensee indicated that the incorrect relay had been specified on the parts requisition sheet in the work package, and prepared a revised requisition sheet for a relay rated for 125 VDC. However, after issuing that relay from the stockroom, the licensee stated that it's contact configuration was different from the installed relay, and that it could not be installed within the allotted LCO time since a formal engineering justification and a wiring configuration change would take too long.
Consequently, the licensee requisitioned a third relay having the same contact configuration and coil voltage rating as the installed relay.
The installation was then completed, and reactor trip breaker testing was satisfactorily accomplished within the LCO time limits. The licensee initiated three ACTION Reports to investigate the problems experienced in planning and executing this work.
The inspector asked the stockroom manager to identify the specific location where the first replacement relay (120 VAC) was stored in the stockroom.
The manager identified the storage location by a location number written on the requisition sheet.
However, that location contained only 125 VDC relays.
The manager was not able to explain why a 120 VAC relay had been stored in that location.
Several days later, the inspector asked a stockroom employee to obtain the requisition sheet for the 120 VAC relay, and to identify it's storage location in the stockroom.
The employee identified a location which contained all 120 VAC relays, but that was different from the location previously identified by the stockroom manager.
The employee could not explain why another location was previously identified since it'
location number was not written on the requisition sheet he believe pertained to the 120 VAC relay.
The l&C planner who prepared the work package indicated that he had incorrectly designated a 120 VAC relay, and that information was designated on the first requisition sheet.
At the end of the inspection period, the investigation into inadequate planning and apparent inventory controls in the stockroom was still in progress.
However, it appeared to the inspector that safety-related material may
have been improperly stored in the stockroom, and,released for an improper application in the plant.
c.
Conclusions The licensee successfully replaced the 9-A reactor trip relay within the time constraints of the ITS LCO. However, the inability to identify that an incorrect replacement part had been requisitioned until just prior to'installation indicated deficiencies in the licensee's work planning and requisitioning of spare parts.
In addition, potential inventory control deficiencies may have existed in the plant stockroom.
Pending further evaluation in this area, this will remain an inspection follow-up item (IFI 50-244/98-07-01).
III. En ineerin E2 Engineering Support of Facilities and Equipment E2.1 Thermal Performance Anal sis and Preventive Maintenance Fre uencies for Containment Recirculation Fan Coolers CRFCs a.
Ins ection Sco e (37551)
The inspector reviewed the licensee's thermal performance test results and engineering analysis used to justify a 54-month cleaning interval for the CRFC coolers.
b.
Observations and Findin s As part of the licensee's Generic Letter (GL) 89-13 program for safety-related heat exchangers, all four CRFC's cooler tubes at the Ginna Station were replaced with new material during the March 1993 refueling outage.
Since then, all coolers have performed satisfactorily during normal plant operation; however, the GL 89-13 program specifies periodic cleaning and thermal performance monitoring to assure that safety-related heat exchangers will remove design basis heat loads under limiting accident conditions.
Therefore, the licensee cleaned the C-and D-CRFC.
coolers during the November 1997 refueling outage, and then performed detailed thermal performance monitoring of all four CRFC coolers coils in March 1998 (see IR 50-244/98-03).
The results of the performance tests allowed the licensee to compare the performance of the cleaned coolers with the coolers not cleaned to determine the rate at which the coolers became fouled over a 5-year period.
The licensee utilized a recently published guideline developed by the Electric Power Research Institute (EPRI) for service water heat exchanger testing (TR-107397),
which focused on the "heat transfer" method for performance monitoring.
The licensee used the statistical model employed by the EPRI guidance to predict CRFC cooler performance over time. The results of their analysis were documented in DA-ME-98-081, "CRFC A, B, C, and D Thermal Performance Test Data
Reduction, Fouling, and Uncertainty Analysis and Justification of 54 Month Cleaning Interval," dated April 21, 1998. The inspector reviewed this analysis and noted that it predicted with 95% certainty that the rate of CRFC cooler fouling was low enough=over a 5-year period to maintain the coolers below their design fouling limit of 0.001 hr-ft'- F/BTU. Using this result, the licensee concluded that a staggered 54-month cleaning interval (every third refueling outage) for the CRFC coolers would be acceptable, and would maintain an adequate heat removal capacity for accident
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Conclusions The inspector concluded that the CRFC thermal testing, and subsequent performance analysis using current industry guidance, represented good progress toward completion of the licensee's GL 89-13 program.
The performance analysis appeared to support the licensee's conclusion that a 54-month preventive maintenance cleaning cycle for all coolers would maintain their heat removal capacity within design limits for accident heat loads.
Containment S ra S stem Periodic Surveillance Testin and Sodium H droxide Eductor Performance Re uirements Ins ection Sco e (37551)
The inspector reviewed the licensee's periodic surveillance tests for the containment spray (CS) system, and evaluated test flow acceptance criteria for the sodium hydroxide (NaOH) eductors with regard to design basis functional requirements.
Observations and Findin s The licensee used periodic test PT-3Q, "Containment Spray Pump Quarterly Test,"
for the inservice pump and valve tests required by ASME Code Section XI for the containment spray system, Procedure PT-3Q operated the CS system in a test configuration by taking a suction from the refueling water storage tank (RWST) and discharging CS pump flow back to the RWST through a recirculation test line. The test configuration also used RWST water to test the chemical eductors that would be used to inject NaOH from the chemical addition tank into the main CS flow stream during a design basis loss of coolant accident (LOCA). The chemical addition tank is isolated during the PT-3Q test to prevent contaminating the system with NaOH.
PT-3Q contained acceptance criteria which specified that the eductor flow must be R30 gpm as verified from main control board flow instrument Fl-930. The inspector also noted that Fl-930 was a fixed dual scale instrument that indicated flow for both water ahd NaOH. The current test acceptance criteria basis for the minimum eductor flow referenced a design basis file for the CS system.
However, the referenced file did not contain any document or information that correlated 30 gpm of water to the minimum NaOH flow (and total mass) required for design accident conditions.
The inspector noted that actual PT-3Q test results typically
produced approximately 40 gpm eductor flow using RWST water.
This value correlated to approximately 30 gpm NaOH flow on the Fl-930 instrument, and 30 gpm water flow correlated to approximately 22.5 gpm. NaOH flow. The licensee was not initiallyable to substantiate a basis for the. minimum acceptable water flow or to correlate that value to the minimum NaOH flow required to neutralize the post-accident containment sump water, and to capture airborne iodine.'he licensee initiated an engineering design analysis activity to investigate the basis for the minimum eductor flow specified in the PT-3Q acceptance criteria, and to verify that the system conditions used during the test could be correlated to post, accident conditions in the CS system.
The static head on the RWST water during the test provided approximately 40 psi motive force to the chemical eductors, whereas, the NaOH tank was normally pressurized under approximately 2 psi of N~.
On June 9, 1998, the licensee issued DA-ME-98-104, "Containment Spray Sodium
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Hydroxide Eductor Performance Assessment,"
which concluded that a minimum of 20 a 2 gpm NaOH must be delivered to the CS system during accident conditions, and that an observed test flow ~37.5 gpm, with the RWST at 88% full, would be sufficient to assure a satisfactory periodic test.
The licensee indicated that a change to PT-3Q would be initiated to change the minimum acceptable eductor flow to 38 gpm. The licensee's historical search of past PT-3Q test results indicated that the eductor flow had never dropped belo'w 38 gpm, and therefore, that parameter was not a concern for past operability of the CS system.
The inspector considered that the lack of CS system design flow calculations necessary to correlate test acceptance criteria to accident functional requirements represented a weakness in the plant's design basis records.
Conclusions Although actual test results indicated that the CS system has not operated outside its design basis, the lack of specific flow calculations for the CS system chemical eductor flow requirements represented a weakness in the plant's design basis records.
An evaluation of the licensee's 10 CFR 50.54(f) review project, will be conducted in a future inspection period.
Inspection Follow-up Item (IFI 50-244/98-07-02).
IV. Plant Su ort P8 Miscellaneous EP Issues P8.1 Closed IFI 50-244 97-04-01 Maintenance Team Debriefin s Durin Emer enc Pre aredness Exercises a ~
Ins ection Sco e (92904)
The inspector evaluated the licensee's follow-up corrective actions to a weakness noted in the quality of maintenance department debriefings during emergency preparedness (EP) exercises.
b.
Observations and Findin s During the licensee's full-participation EP exercise in June 1997, the NRC identified that post-job debriefings between the Maintenance Assessment Manager and maintenance repair teams were not conducted upon their return from the field, as prescribed by procedure EPIP 1-12, "Repair and Corrective Action Guidelines During Emergency Situations." Radiological information from the field could have helped the RP/Chemistry Manager in planning for additional maintenance during the exercise.
The licensee subsequently issued a memorandum to the Maintenance Assessment Manager and the RP/Chemistry Manager to remind them of their responsibility to conduct the debriefings des'cribed in EPIP 1-12. The licensee also revised procedure EPIP 5-7, "Emergency Organization," to add an additional step in the responsibilities of the Maintenance Assessment Manager to perform debriefings when repair teams return from the field. In addition, the licensee revised the Emergency Coordinator checklist in EPIP 5-7 to prescribe meetings and debriefings in the Technical Support Center using the more formal format already utilized in routine daily management.
meetings.
That format was more conducive to obtaining accurate and concise information in a minimum amount of time.
The inspector reviewed the changes to EPIP 5-7 and considered them adequate to proceduralize management responsibilities.
The inspector also observed several debriefings conducted during the annual plume exposure exercise conducted on March 25 and May 6, 1998. Those briefings were thorough and provided sufficient detail for EP managers to make informed decisions based on field reports of plant equipment and radiological conditions.
C.
Conclusions The licensee made procedural and programmatic enhancements to assure that maintenance team debriefings were properly conducted as prescribed by EPIP 1-12, and to improve the accuracy of field information conveyed to EP managers during exercises.
Debriefings conducted. during the recent plume exposure exercise were effective and significantly improved.
This failure to follow procedure EPIP 1-12
constitutes a violation of minor safety significance, and is not subject to formal enforcement.
This item is closed (IFI 50-244/97-04-01).
V. Mana ement Meetin s
X1 Exit Meeting Summary After the inspection was concluded, the inspectors presented the results to members of licensee management on July 1, 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.
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 B. Flynn C. Forkell G. Graus A. Harhay J. Hotchkiss G. Joss R. Marchionda P. Polfleit R. Ploof.
J. Smith J. Widay T. White G. Wrobel Primary Systems Engineering Manager Electrical Systems Engineering Manager ISC/Electrical Maintenance Manager Chemistry &. Radiological Protection Manager Mechanical Maintenance Manager Results and Test Supervisor Production Superintendent
.
Emergency Preparedness Manager Secondary Systems Engineering Manager Maintenance Superintendent Plant Manager Operations Manager Nuclear Safety 5 Licensing Manager INSPECTION PROCEDURES USED IP 37551:
IP 40500:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 92901:
IP 92902:
IP 92903:
Onsite Engineering Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Surveillance Observation Maintenance Observation Plant Operations Plant Support Follow-up - Operations Follow-up - Mainten'ance
'ollow-up
- Engineering
Attachment I
ITEMS OPENED, CLOSED, AND DISCUSSED
~Oen ed IFI 50-244/98-07-01 Deficiencies in work planning and spare parts requisitioning.
Potential inventory control problems.
IFI 50-244/98-07-02 Closed IFI 50-244/98-02-02 Evaluation of the licensee's 10 CFR 50.54(f) review project.
Evaluation of the licensee's human performance evaluation conducted in response to the pressurizer pressure transient of March 3,'1998.
IFI 50-244/97-07-02 Requirements for an operable boration flowpath in MODES 5 5 6.
IFI 50-244/97-04-01 Discussed Maintenance team debriefings during EP exercises.
e IFI 50-244/97-09-01 Quality of the in-plant JPM bank
Attachment I
LIST OF ACRONYMS.USED ASME CCW, CFR CIV CRFC CS CW d/p dpm ECCS EDG EP EPRI ESF IFI IR IST ITS JPM LCO NRC NaOH NRR PORV PORC PPCS ppm PT pslg RGtkE RP RPSC RWST SW
~TDAFW UFSAR American Society of Mechanical Engineers Component Cooling Water Code of Federal Regulations Containment Isolation Valve Containment Recirculation Fan Cooler Containment Spray System Circulating Water differential pressure disintegrations per minute Emergency Core Cooling System Emergency Diesel Generator Emergency Preparedness Electric Power Research Institute Engineered Safety Feature Inspector Follow-up Item
Inspection Report
Inservice Test
Improved Technical Specification.
Limiting Condition for Operation
Nuclear Regulatory Commission
Sodium Hydroxide
Nuclear Reactor Regulation
Power-Operated
Relief Valve
Plant Operations Review Committee
Plant Process Computer System
parts per million
Periodic Test
pounds per square inch gage
Rochester Gas and Electric Corporation
Radiation Protection
Radiological Protection and Chemistry
Refueling Water Storage Tank
Turbine-Driven Auxiliary Feedwater
Updated Final Safety Analysis Report
4 gg
0