IR 05000250/1998013
| ML17355A259 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 03/08/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17355A258 | List: |
| References | |
| 50-250-98-13, 50-251-98-13, NUDOCS 9903240252 | |
| Download: ML17355A259 (34) | |
Text
U.S. NUCLEAR REGULATORYCOMMISSION
REGION II
Docket Nos:
License Nos:
50-250, 50-251 DPR-31, DPR-41 Report Nos:
50-250/98-13, 50-251/98-13 Licensee:
Florida Power and Light Company Facility:
Turkey Point Nuclear Plant, Units 3 &4 Location:
9760 S. W. 344 Street Florida City, FL 33035 Dates:
December 27, 1998 - February 6, 1999 Inspectors:
C. Patterson, Senior Resident Inspector R.. Reyes, Resident Inspector E. Girard, Regional Inspector (Section M1.3)
T. Scarborough, Nuclear Reactor Regulation (NRR)
(Section M1.3)
Approved by:
L. Wert, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure 9'P03240252 990308 PDR ADQCK 05000250 G.
EXECUTIVE SUMMARY Turkey Point Nuclear Plant, Units 3 8 4 NRC Inspection Report 50-250/98-13, 50-251/98-13 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support.
The report covers a 6-week period of resident inspection; in addition, it includes the results of an inspection by regional and Nuclear Reactor Regulation (NRR) Motor Operated Valve (MOV) inspectors.
~Oerations
~
The conduct of operations was professional and safety conscious.
Equipment clearance activities, unloading of new fuel, and Non-licensed Operator rounds were meticulously conducted in accordance with procedural controls.
(Sections 01.1-01.4)
Equipment operability and material condition for the component cooling water (CCW)
system was good. The CCW system was correctly aligned for normal and emergency operating conditions.
Housekeeping deficiencies were noted in the CCW pump room and on the metal grating above the pump rooms. (Section 02.1)
Color markings of the operating ranges for some control room instrumentation were not consistent with parameters contained in logs and procedures.
(Section 03.1)
The licensee was well prepared for cold weather conditions. The cold weather procedure provided adequate guidance to maintain equipment operational.
The licensee revised procedures to clarify cold weather procedure entry conditions.
(Section 03.2)
The Corporate Nuclear Review Board provided effective independent review of plant activities. (Section 07.1)
Maintenance Component cooling water system valve surveillance testing was completed satisfactorily.
(Section M1.1)
Thermal performance testing of the CCW heat exchangers was satisfactorily performed.
A change to the surveillance procedure was made to clarify the use of a single RTD for inlet temperature measurements on all three heat exchangers.
(Section M1.2)
The licensee was establishing a program with the intent of meeting GL 96-05 "Periodic Verification of Design-Basis Capability of Safety-Related Motor-Operated Valves" to provide the continued assurance that Motor-Operated Valves within the scope of GL 96-05 are capable of performing their design-basis safety functions.
(Section M1.3)
Turbine stop valve testing was performed satisfactorily.
(Section M1.4)
Enrnineering
~
The Event Review Team established after a High Head Safety Injection pump failed due to gas binding was effective. Corrective actions established for a previous similar event required venting and running pumps to detect further problems and ensured compliance with Technical Specifications.
(Section E2.1)
~
Although operability evaluations were completed when several instances of low Intake Cooling Water flow were experienced during testing, the root cause and effects of the low flowconditions were not fullyevaluated by the licensee.
Technical Specification requirements for the ICW system were met during the testing.
(Section E2.2)
The licensee conducted a challenging emergency preparedness drill in preparation for the annual exercise. (Section P5.1)
~
The diesel fire pump operability test was well performed.
(Section F2.1)
Re ort Details Summa of Plant Status Unit 3 operated at full power from the beginning of the period until a downpower to 40 percent power on February 2, 1999 to conduct turbine stop valve testing and condenser water box cleaning.
The unit returned to full power the next day. The unit has been on-line since October 29, 1998.
Unit 4 operated at full power until a downpower to 65 percent power on January 14, 1999 to conduct turbine stop valve testing. The unit returned to full power the same day. The unit has been on-line since October 14, 1997.
Conduct of Operations 01.1 General Comments 71707 Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations.
In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections below.
0 1.2 New Fuel Unloadin and Transfer 71707 9 hei sobs On January 26, 199, t nspector erved the licensee unload new fuel from fuel containers and transfer the fuel to the Unit 4 new fuel room. The fuel was being stored in preparation for the Unit 4 refueling outage.
The inspectors reviewed the procedures and radiation work permit (RWP) used at the job location. There was good coordination among the different groups performing the, work, including mechanical maintenance, operations, reactor engineering, and health physics.
01.3 Non Licensed 0 erator Tour 71707 The inspectors observed a Senior Nuclear Plant Operator (SNPO) conduct a tour inside the auxiliary building and record logsheet readings.
The SNPO was actively looking for plant deficiencies during the tour. Log readings were taken using the hand held computer.
Deficiencies noted were promptly communicated to the control room. At the completion of the tour, the inspector observed the SNPO upload the hand held computer data from the auxiliary building to the control room. The inspectors obtained a printout of the logsheet from the control room. The process of taking log readings was compared to instructions provided in plant procedure, O-OSP-201.2, SNPO Daily Logs, dated June 15, 1998. The SNPO actions and notifications were as specified in the procedur.4 E ui ment Clearance 71707 Ins ection Sco e
The inspectors reviewed the clearance on the Unit 3 main control board for repair of containment air particulate monitor channel (R-11) and radioactive gas monitor channel (R-12) sample pump. Additionally, the inspectors observed an operator perform a valve lineup and rack-in a 4160 volt breaker as part of an intake cooling water (ICW) pump clearance.
b.
Observation and Findin s Clearance 3-99-01-010 issued January 4, 1999, was reviewed. Technical Specification (TS) Table 3.3-4 Action 26 requires that when both the containment particulate and gaseous radioactivity monitors systems are inoperable, the containment purge, exhaust, and instruments air bleed valves are to be maintained closed.
The inspector verified that the six valves tagged were the appropriate valves to be kept closed.
On January 14, 1999, the inspectors reviewed an equipment clearance in progress and observed an operator perform an intake cooling water system valve lineup and return a breaker back to service.
Procedure 3-OP-005, 4160 Volt Buses A, B, and D, Section 7.8, was used to return the breaker to service.
The breaker was being returned to service following maintenance on the intake cooling water system.
Good communications with the control room and good procedure adherence was observed throughout the valve lineup and breaker work. Utilizing system prints, the inspectors verified the proper valve lineup was completed for normal operation.
C.
Conclusion Clearance activities were properly performed for work associated with containment monitors and the intake cooling water system.
Good procedural compliance was observed during restoration of an electrical breaker.
Operational Status of Facilities and Equipment 02.1 Com onent Coolin Water S stem En ineered Safe Feature Walkdown Ins ection Sco e 71707 and 61726 The inspectors performed a detailed system walkdown on the Component Cooling Water (CCW) System and reviewed and observed the monthly flow path verification surveillance.
b.
Observations and Findin s On January 6, 1999, the inspectors observed the responsible system engineer perform portions of the monthly surveillance test on the component cooling water system on Unit 3 and Unit 4. The surveillance is described in procedure 3/4-OSP-030.3,
Component Cooling Water System Flowpath Verification, and was performed to comply with Technical Specification (TS) 4.7.2.b(1).
The inspectors verified the system prints were consistent with the procedures used for the flowpath verification. The procedure included valve and breaker alignments. The inspectors performed an independent flowpath verification on selected valves, breakers, and components on Unit 4. The inspectors walked down the Unit 3 and Unit 4 CCW systems.
The inspectors observed some maintenance tools and miscellaneous materials in the CCW pump rooms and on the metal grating roof which appeared to have been left behind from recent work. Overall material condition of the CCW system was good. The inspectors reviewed the housekeeping issues and some deficiencies noted with scaffolding with the Operations supervisor.
Allitems were resolved and no safety issues were identified.
Conclusions Equipment operability and material condition for the component cooling water (CCW)
system was good. The CCW system was correctly aligned for normal,and emergency operating conditions.
Housekeeping deficiencies were noted in the CCW pump room and on the metal grating above the pump rooms.
03.1 Operations Procedures and Documentation Control Room Instrumentation Markin s Ins ection Sco e
71707 b.
The inspector examined operating band markings on control room instrumentation and compared them to the operating limit parameters described in logs and procedures.
n Observation and Findin s The inspector compared various control room instrument readings to the limits contained in the Reactor Control Operator (RCO) logs. The maximum value specified in the logs for the CCW Heat Exchange Outlet Temperature, Tl-607A and TI-607B, was 104.99 degrees Fahrenheit ( F). However, the green tape on the instrument had a range of 70 to 110 degrees.
Therefore, the temperature instrument could indicate a
temperature in the normal operating band that would be above the maximum permitted by the logs.
The inspector reviewed procedure O-ADM-209, Equipment Tagging and Labeling, dated June 24, 1998.
Section 5.8 of the procedure provides the instrument operating parameters and setpoint color coding. The color green indicates a normal parameter range.
The inspector discussed the apparent discrepancy noted above with Operations Management.
Additional review indicated that there was a lack of correlation or inconsistent application of color coding relative to the log sheet values for some control room instruments.
For example, some instruments have color codes for the normal operating range, alarm set point, and equipment trip; but these values did not
correspond to the log sheet minimum and maximum limits. This could result in Operators not promptly identifying equipment operating outside of specified parameters.
The licensee initiated CR 99-0075 to address this issue.
Conclusion Color markings of the operating ranges for some control room instrumentation were not consistent with parameters contained in logs and procedures.
Cold Weather 0 erations Ins ection Sco e 71707 The inspectors reviewed the licensee's procedures and readiness for operation in cold weather.
Findin s and Observations Off-normal operating procedure, O-ONOP-103.2, Cold Weather Conditions, dated April8, 1998, is to be entered when any of the following conditions exist:
1)
AuxiliaryBuilding temperature less than 65 F, 2)
Actual outside air temperature less than 55'F, 3)
Outside air temperature is predicted to go below 32'F.
This procedure ensures compliance with TS 3.5.4 and 4.5.4, Refueling Water Storage Tank (RWST); and TS 3.1.2.4 and 4.1.2.4, Borated Water Source.
Additionally, the procedure provides guidance for protecting other plant equipment in a cold weather environment.
Outside ambient temperature and auxiliary building temperature were taken during the routine operator rounds.
This was the primary method used to determine if entry into the cold weather procedure is required. Temperature measurements were obtained in accordance with Form 418, Inside SNPO Log Readings, and Form 419, Outside SNPO Log Readings.
The procedures required the operator to inform the shift supervisor if the auxiliary building temperature decreased to 65 F. However, there was no warning or instructions to the operator regarding actions to take if the outside temperature fell below 55'F. The procedure did prescribe actions to take if ambient temperature fell below 43 F or rose above 96 F. The inspectors questioned several operators on what actions needed to be taken if ambient temperature fell below 55'F.
In general, operators were aware that the cold weather procedure needed to be entered at an outside temperature of approximately 50 to 55'F.
The inspectors reviewed the cold weather procedure with the Operations supervisor and the above procedural discrepancy was discussed.
Subsequently, Operations revised the procedure to include actions if the ambient temperature fell below 55'F. The inspectors subsequently verified that the procedure change had been implemented.
The inspectors walked down the AuxiliaryBuilding with an operator checking the boric acid storage tank room, charging pump room, and other locations that were vulnerable
when exposed to a cold weather condition. Additionally, the RWST area and several diesels mentioned in the cold weather procedure were walked down. Power supplies, heaters, temperature measurement devices and recorders required for cold weather operation were verified.
C.
Conclusions The licensee was well prepared for cold weather conditions. The cold weather procedure provided adequate guidance to maintain equipment operational.
The licensee revised procedures to clarify cold weather procedure entry conditions.
Quality Assurance in Operations 07.1 Cor orate Nuclear Review Board CNRB 40500 On January 19, 1999, the inspectors attended a portion of the CNRB. Presentations were on plant status, reactivity management, condition report trends, and other issues.
Probing questions were asked by CNRB members.
The CNRB provided effective independent review of plant activities.
II. Maintenance M1
M1.1 Conduct of Maintenance Com onent Coolin Water CCW Valve IST Surveillance Ins ection Sco e 61726 The inspectors observed the quarterly Inservice Test (IST) on two CCW system vacuum valves.
b.
Observations and Findin s On January 8, 1999, the inspectors observed operators perform surveillance 3-OSP-206.2, Quarterly Inservice Valve Testing, Section 7.11, Component Cooling Water dated October 18, 1998.
Included in this surveillance are redundant vacuum valves 3-1019 and 3-1020. These valves perform a quality related function. The valves prevent vacuum effects during a CCW surge tank outsurge and help maintain maximum available net positive suction head.
Testing of the valves required the operator to push down on the valve stem, then release and record on attachment 1 of the procedure.
The inspector noticed that valve 3-1020 returned to its closed position at a relatively faster velocity than valve 3-1019. The operator noted this observation on the attachment 1. Review of the procedure revealed that there was n'o specific defined acceptance criteria for the vacuum valves. There was, however, a check-off to describe the test results as satisfactory or unsatisfactory.
The inspectors discussed the valve test observations and the acceptance criteria issue with the IST supervisor.
Additionally, the inspectors reviewed the operation of the
vacuum valves with engineering and reviewed the portion of modification PCM 96-093 which described the operation of the vacuum valves. The inspector determined that there were no time response requirements for the valves. The licensee subsequently revised the procedure to specify an acceptance criteria.
Conclusions Component cooling water system valve surveillance testing was completed satisfactorily.
Com onentCoolin Water CCW Heat Exchan er Performance Test Surveillance lns ection Sco e 61726 and 37551 The inspector observed the CCW surveillance for Unit 3 and Unit 4 as described in procedures 3/4 - OPS - 030.4, Component Cooling Water Heat Exchanger Performance Test, dated April7, 1998.
Observations and Findin s On January 27, 1999, the inspectors observed thermal performance surveillance testing for all six CCW heat exchangers for Unit 3 and Unit 4. During the temperature measurement portion of the procedure, the inspector noted the resistance temperature device (RTD) for the 3A ICW inlet temperature was used as the inlet temperature for all three heat exchangers on Unit 3. Data sheets in the procedure indicated that the 3B and 3C inlet RTDs would be used to obtain inlet temperatures for those heat exchangers.
Since ICW is supplied to all three heat exchanger from a common manifold, the inspectors concluded that there was no technical problem with using the 3A RTD for all three heat exchangers.
The procedure inconsistency was reviewed with Engineering and the inspectors were informed that a procedure change would be made to better describe the use of the same RTD for all three heat exchangers.
During ICW flow rate measurements for the 4A heat exchanger, the technician did not question indications that the flow gage may not have been properly indicating flow until prompted by the inspector.
A Plant Work Order was processed to address the apparent gage problem. Additionally, a more detailed review of the 4A heat exchanger temperatures verified that no abnormal thermal performance was present.
Calibration of all 12 Unit 4 RTDs was independently verified by the inspector.
Calibration of the Unit 3 and Unit 4 ICW flowgages was also independently verified.
Additjonally, for Unit 4, the inspectors independently verified the calculations for the maximum allowed ICW temperature for the best two and worst two heat exchangers.
The inspectors reviewed the thermal performance data of all six CCW heat exchangers with engineering.
No issues were identified with the thermal performance test results.
Conclusions Thermal performance testing of the CCW heat exchangers was satisfactorily performed.
A change to the surveillance procedure was made to clarify the use of a single RTD for inlet temperature measurements on all three heat exchanger e M1.3 Im Iementation of Generic Letter GL 96-05 "Periodic Verification of Desi n-Basis Ca abilit of Safet -Related Motor-0 crated Valves" Ins ection Sco e Tem ora Instruction2515/140 This inspection was conducted to assess the licensee's implementation of GL 96-05 and provide information pursuant. to completion of a safety evaluation of the licensee's response to this GL. GL 96-05 requested licensees to establish programs to periodically verify that safety-related motor-operated valves (MOVs) are capable of performing their safety functions within the current licensing bases.
t Prior to this inspection, the licensee responded to the recommendations of GL 96-05 in letters to the NRC dated November 6, 1996, and March 11, 1997, and described the long-term MOV periodic verification program for Turkey Point.
In addition to its specific plans for MOV periodic verification, the licensee noted in its letter dated March 11, 1997, that it was monitoring an industry-wide program developed by a Joint Owners Group (JOG). The JOG Program on MOV Periodic Verification was reviewed by the NRC staff and determined to be acceptable for addressing valve aged-related degradation with certain conditions and limitations documented in a safety evaluation issued October 30, 1997. The JOG program consists of three phases:
(1) an interim MOVstatic diagnostic test program with a test frequency based on the risk significance and capability margin of each GL 96-05 MOV; (2) a program of repetitive MOVdynamic tests at participating nuclear power plants with a total of more than 100 MOVs to be tested over a 5-year period; and (3) a long-term periodic test program based on the results of the MOV dynamic tests.
This inspection assessed the licensee's program to determine whether it was consistent with the licensee's commitments and with the recommendations of GL 96-05. The inspection was conducted through reviews of MOV program documents and interviews with licensee personnel.
Observations and Findin s Commitments to GL 96-05 Tl 2515/140 Para ra h 03.01 In its response to GL 96-05, the licensee stated that it had reviewed the effectiveness of its MOV periodic verification program and had enhanced the program to incorporate guidance and information provided in GL 96-05 and industry experience.
The licensee stated that the resulting program included a preventive maintenance program, and a mixture of static and dynamic (in-situ) diagnostic testing, to ensure that potential age-related degradations were identified. The licensee indicated that industry experience and initiatives, such as the JOG effort on periodic verification, would be monitored to ensure that the Turkey Point MOVprogram incorporated industry experience and lessons learned.
The licensee did not specifically commit to implement the JOG program. The licensee demonstrated that it was participating in the JOG program by testing assigned MOVs under dynamic condition GL 89-10 Lon -Term Actions TI 2515/140 Para ra h 03.02 In NRC Inspection Report (IR) 50-250, 251/97-08 (dated September 5, 1997), the NRC closed its review of the program implemented by the licensee in response to GL 89-10,
"Safety-Related Motor-Operated Valve Testing and Surveillance," based on the licensee's actions to verify the design-basis capability of its safety-related MOVs. In IR 97-08, the inspectors noted several long-term planned actions by the licensee to ensure proper MOVperformance.
During this inspection, the inspectors verified that the licensee was implementing the long-term planned actions discussed in IR 97-08.
In GL 89-10, the NRC staff recommended that MOV performance be trended on a long-term basis.
In Engineering Evaluation PTN-ENG-SEMS-97-0007, the licensee specified that it would trend MOVtrouble and breakdown, stem coefficient of friction, actuator inspection results, and grease condition. The inspectors noted that the licensee's guidance for MOVtrending did not provide details of how these parameters would be monitored and evaluated to identify trends in specific aspects of MOV performance, such as actuator output.
GL 96-05 Pro ram Tl 2515/140 Para ra h 03.03 In PTN-ENG-SEMS-97-007, the licensee described its GL 96-05 program to ensure continued design-basis capability of safety-related MOVs. The licensee specified that its GL 96-05 program included (1) stem lubrication every cycle for all MOVs, (2) static testing every cycle for MOVs in severe environments and every 3 cycles for MOVs in non-severe environments, (3) actuator inspection and,refurbishment every outage for MOVs in severe environments and every 3 cycles for MOVs in non-severe environments, (4) dynamic testing every 3 cycles for high and medium risk-significant MOVs with low margin (< 20%), (5) trending of MOVperformance, and (6) performance of additional MOV testing as deemed appropriate.
In reviewing the program and implementing documents, the inspectors found that the licensee's GL 96-05 program was being developed and implemented in accordance with the licensee's quality assurance program.
The inspection findings for specific aspects of the licensee's GL 96-05 program were as follows:
Sco eof MOVs includedin GL96-05 Pro ram Engineering Evaluation PTN-ENG-SEMS-97-007 indicated that the GL 96-05 program at Turkey Point was applicable to all MOVs that had been included in the GL 89-10 program.
The licensee's Plant Manager Action item (PMAI) Corrective Action Form PM98-04-055 (October 30, 1998) reported that the scope of the GL 96-05 program at Turkey Point had been evaluated and determined to include the appropriate MOVs. The licensee indicated that any MOVs not capable of returning to their safety positions would be declared inoperable when moved to their nonsafety position. The GL 96-05 program at Turkey Point included 111 safety-related MOVs.
Based on their review, the inspectors considered the scope of MOVs included in the licensee's MOV program to be consistent with the recommendations of GL 96-0 MOV Desi n Basis The licensee was maintaining its MOVcalculations up to date with respect to new information on MOV capability. For example, the licensee provided PTN-BFJM-90-079 (Revision 19, September 16, 1998), "NRC Generic Letter 89-10 MOVActuator Evaluation," that had been revised to incorporate the recent guidance from the actuator manufacturer on MOV motor actuator output. This indicated that the licensee was maintaining an up-to-date design basis for GL 96-05 MOVs.
De radation Rate for Potential Increase in Valve Thrust or Tor ue 0 eratin Re uirements PTN-ENG-SEMS-97-007 described the determination of safety significance and capability margin for GL 96-05 MOVs, and specified the process for selecting the MOVs to be dynamically tested.
This document indicated that the licensee planned to dynamically test a target population of approximately 10% of the wedge and double disc gate valves that were practical and useful to test in each unit every 3-cycles.
It further indicated that high and medium safety significance MOVs could be excluded from this testing if they had 20% or greater thrust margin.
Although the licensee had not committed to implement the JOG program to address GL 96-05, the licensee was participating in the program by performing dynamic tests on assigned MOVs. For example, JPN-PTN-SEMS-98-025 provided an evaluation of dynamic testing that the licensee had been performed on MOV-4-863B. The results of this test were designated for submission to the JOG program.
The documents reviewed by the inspectors did not indicate how or if data received from the JOG program would be utilized.
The inspectors were not able to determine whether the dynamic testing specified in the licensee's documents would be sufficient to identify potential valve age-related degradation for each GL 96-05 MOVor whether the capability margins of each MOV would be sufficient during the period while testing was being performed to establish the degradation rates.
The inspectors identified this as an area requiring additional NRC assessment.
Further details of the MOVcapability margins, representative MOVs to be tested, and the dynamic testing schedule willbe necessary for the NRC to complete this review.
De radation Rate for Potential Decrease in MOV Motor Actuator Out ut The licensee specified various parameters that were to be monitored to identify potential degradation in MOV performance.
However, the inspectors found that the licensee had not provided specific guidance as to how these parameters would be monitored and evaluated, such that motor actuator degradation trends in both the opening and closing directions could be identified and appropriate corrective action taken. The inspectors identified this as an area requiring additional NRC assessmen U dated Guidance from the Actuator Manufacturer Turkey Point Condition Report (CR) 98-1107 (July 31, 1998) described the licensee's actions in response to new guidance from the MOVactuator manufacturer on ac-powered MOV output capability. This guidance had been provided in Limitorque Technical Update 98-01 and its Supplement 1.
As described in CR 98-1107, the licensee evaluated the operability of each safety-related MOV in response to this guidance'and determined that all of its GL 96-05 MOVs continued to be capable of performing their design functions.
However, the licensee identified several MOVs which would have to be reset or modified to return their design capability margin, and specific MOVcalculations and evaluations which would have to be revised.
On Unit 3, the licensee performed setting adjustments of applicable MOVs during the fall 1998 outage and plans to complete MOV modifications during the spring 2000 outage.
On Unit 4, the licensee plans to perform setting adjustments of applicable MOVs during the spring 1999 outage and to complete MOVmodifications during the fall 2000 outage.
The licensee was aware of an ongoing evaluation of dc-powered MOV actuator output by the actuator manufacturer.
Periodic Test Method The licensee used periodic static and dynamic diagnostic testing to monitor the capability margin of its GL 96-05 MOVs. The static testing was required every 3 cycles for MOVs in non-severe environments and every cycle for MOVs in severe environments.
The dynamic testing was required every 3 cycles on high and medium safety significant (risk) MOVs with less than 20% design thrust margin.
In PTN-ENG-SEMS-97-007, the licensee summarized its risk ranking of safety-related MOVs using probabilistic and deterministic insights. The licensee indicated that during spring 1999 it was planning to update its MOV risk ranking methodology to reflect an accepted generic industry method applicable to its plant. The inspectors identified that the licensee's risk ranking methodology would require further NRC review and comparison to the industry methodology.
The inspectors identified this as an area requiring additional NRC assessment.
MOV Performance Evaluation The inspectors reviewed the monitoring and evaluation of MOVdynamic test results documented in Test Procedures97-045, 97-046,98-039, and 98-054.
In addition, they reviewed recent quantitative and qualitative trending of MOVperformance described in the latest Motor Operated Valve Report (March 18, 1998). The inspectors found that the licensee was adequately evaluating MOV performance and providing feedback of MOV information into its program in these examples.
MOVTest Interval The inspectors found that the licensee had initiated an MOVstatic and diagnostic test program, including participation in the JOG program. The licensee's dynamic test program focused on low-margin wedge and double disc gate valves for identification of
potential age-related degradation.
In PTN-ENG-SEMS-97-007, the licensee specified that the Turkey Point MOV periodic verification program would be re-evaluated and revised as necessary after the first 3-cycle test period.
Based on the areas which were identified as requiring further NRC assessment in previous paragraphs, the inspectors were not able to determine at this time whether the periodic test interval would ensure that each GL 96-05 MOVat Turkey Point had continued design-basis capability until the next scheduled test.
Conclusions r
Based on their review, the inspectors concluded that the licensee was establishing a program with the intent of meeting GL 96-05 to provide the continued assurance that MOVs within the scope of GL 96-05 are capable of performing their design-basis safety functions. The inspectors identified three areas which required further assessment before the NRC staff could complete a safety evaluation accepting the licensee's response to GL 96-05:
MOVcapability margins, representative MOVs to be tested for each group (including all GL 96-05 valves and not only wedge and double disc gate valves),
and the dynamic testing schedule to be used to establish appropriate degradation rates.
Monitoring and evaluating MOV parameters to identify degradation trends.
MOV risk ranking.
The NRC plans to address the above areas through a request for additional information.
Unit 3 and Unit 4 Turbine Sto Valve Testin 61726 On January 14, 1999, power was decreased to 65% on Unit 4 to perform turbine stop valve testing.
Previously, the licensee had experienced slight power variations during this testing. To minimize the risk of a turbine trip during the turbine steam header transition, the licensee planned and completed testing on only.the right side stop valves.
The testing was completed and no issues developed.
Unit 4 returned to 100% power on January 14, 1999.
On February 2, 1999, Unit 3 reactor power was decreased to 40% to perform turbine stop valve testing. The control valve test controllers had been recently modified during the fall outage.
This was the first time that the controllers were tested coming down from full power.
During the test, the electronic circuitry on the controllers failed. The licensee completed the stop valve testing by manually cycling the controllers. Testing on the right side and left side stop valves was completed.
No power variations occurred and the modification functioned as hydraulically designed.
The licensee was pursuing corrective actions on the electronic circuitry. A similar modification is planned for Unit 4 during the upcoming outage.
The inspectors reviewed the planned power change evolutions with Operations and observed the power changes in control room. Additionally, the inspectors reviewed the test procedures and discussed the testing with engineering and operations rrianagement.
The inspectors concluded the testing was completed satisfactor III. En ineerin E2 Engineering Support of Facilities and Equipment E2.1 Gas Intrusion into Hi h Head Safet In'ection Sl Pum Ins ection Sco e 71707 The inspectors reviewed the failure of the 4B High Head Safety Injection (HHSI) pump that was identified on January 5, 1999.
Observations and Findin s On January 5, 1999, during the performance of surveillance procedure, 0-OSP-202.3, Safety Injection Pump and Piping Venting, dated September 28, 1998, the 4B HHSI pump did riot develop discharge pressure and the motor amperes were low. Allof the other pumps (3A, 3B, and 4A) operated satisfactorily. The licensee declared the 4B pump inoperable and entered a 30 day limiting condition for operation (LCO) per TS 3.5.2 Action C. An estimated 8 cubic feet of gas was vented from the pump casing.
An Event Review Team (ERT) was formed to address the problem. Condition Report (CR) 99-0007 was written.
The ERT noted that during periodic venting of the system header on December 5, 1998, a small quantity of gas had been identified in the discharge header.
CR 98-1819 was written to document this problem. Corrective action for CR 98-1819 increased the venting frequency on the discharge header from once a month to weekly. During the periodic venting of the header, gas continued to be identified. The licensee suspected back leakage from RCS cold legs through normally closed motor operated valves MOV-4-843A and MOV-4-843B. These valves were stroked on December 28, 1998, to attempt to better seat or flush the valve seats.
This did not resolve the problem.
The ERT noted that a similar incident had occurred on the 4B HHSI pump on December 18, 1995.
CR 95-1256 documented the gas intrusion into the pump.
No single root cause was conclusively identified for the 1995 event.
As part of the corrective action for the 1995 problem, the licensee added steps to procedure 0-OSP-202.3, Safety Injection Pump and Piping Venting, to conduct weekly venting of the pump casings and monthly venting of the system headers along with one minute runs of the pumps.
The running of each pump insured that the maximum time interval between verification of pump operability did not exceed 30 days.
The ERT initiated a number of actions to address the latest problem. The other three pumps and headers were vented and the pumps run daily. Ultrasonic testing and radiographs were performed to identify any potential piping containing gas.
A review of maintenance performed on the system was conducted.
Analysis of the gas indicated the source of gas was due to back leakage from the safety injection (Sl) accumulators that are pressurized with nitrogen. The leakage path was determined to be from the Sl accumulators through a 3/4 inch diameter IST test line, into the mini-recirculation line, and into the 4B HHSI pump casing.
This path involved nitrogen leakage past multiple
barriers (closed valves and check valves) which was previously considered not to be credible.
The inspectors conducted an independent review of the piping configuration.'ccessible portions of the piping were traced out in the plant using the plant drawings.
For the event on January 5, 1999, the licensee developed a time line of HHSI pump runs. The 4B HHSI pump was last run on December 20, 1998, to fillthe 4A Sl accumulator.
The other pump's availability was reviewed during this time with the system engineer.
No other HHSI pumps were inoperable or taken out of service from December 20, 1998 until January 5, 1999. Thus the 30 day LCO time limitfor one inoperable HHSI was not exceeded.
The 4B HHSI was declared operable after review of the ERT actions by the Plant Nuclear Safety Committee on January 11, 1999.
The inspectors attended each of the ERT meetings.
Each CR was reviewed as well as industry experience.
The inspectors reviewed the licensee's document, JPN-PTP-SEMJ-89-056, to address NRC Bulletin 88-04, Potential Loss of Safety Related Pumps, and engineering evaluation PTN-ENG-SEMS-98-029, to respond to an industry issue concerning potential loss of injection and charging capability from gas intrusion. The licensee had considered leakage past multiple barriers but this was not thought to be credible. The inspector reviewed the TS requirements for HHSI pump LCO times and surveillance requirements for system venting. TS 3.5.2 permits operation with one of the four HHSI pumps inoperable for 30 days. TS 4.5.26.1 requires once every 31 days that the system is verified full of water by venting the ECCS pump casing and accessible discharge piping. AllTS requirements were met.
On January 26, 1998, the inspector observed the venting of the HHSI system discharge header vent valves 4-942J and 4-942F. Venting at 942F was conducted for about 11 minutes. The bulk of gas bubbles was eliminated after 10 minutes of venting. A few bubbles remained when venting was stopped but this was greatly reduced from the initial venting and was thought to be from the nitrogen inleakage Venting at 4-942J was performed for 20 seconds.
After some initial gas bubbIes when the vent valves were opened a solid stream of water was observed.
The licensee continued to experience gas intrusion into the Sl system, but periodic venting and pump runs maintained the operability of the system.
Plans were developed for the upcoming unit refueling outages to cut and cap the 3/4 inch IST lines to eliminate this problem.
Conclusion The Event Review Team established after a HHSI pump failed due to gas binding was effective. Corrective actions established for a previous similar event required venting and running pumps to detect further problems and ensured compliance with Technical Specifications.
Low Intake Coolin Water ICW Flowrate Issues Ins ection Sco e 37551 The inspectors reviewed the resolution of several instances of low ICW flowrates experienced during Inservice Testing (IST).
Observations and Findin s Procedures 3/4-OSP-019.1, Intake Cooling Water Inservice Test, dated December 22, 1998, describe the IST. To perform the testing, the two ICW headers are put in a split configuration.
One header provides ICW to the secondary system.
The other header has two CCW heat exhangers and two pumps.
In this configuration, testing is performed on the components of the second header which meets the requirements to remove design basis heat load and was considered the operable header.
The procedure requires that during the testing, a minimum 15,400 GPM of ICW must be maintained through the two CCW heat exchangers on the operable header to meet design basis heat removal.
Several incidents had occurred where ICW flowrate through the operable header had fallen below the minimum required 15,400 GPM specified in the procedure.
An On the Spot Change (OTSC), had been recently written for these procedures to address low ICW flowrate during surveillance testing. The inspectors reviewed five Condition Reports (98-521,98-532, 98-985, 98-1005, and 98-1285) which described instances in which low flow conditions had been identified during IST surveillance testing. These CRs were dated from March 1998 until October 1998.
Operability assessments had been completed for each low flow condition. Each CR added corrective actions to those which had been previously identified. Despite the repeated occurrences, no root cause evaluation had been completed.
Corrective actions included procedure changes to ensure the CCW heat exchangers and the header strainers were cleaned prior to performing the IST. Additionally, the procedure sequences were changed to perform ICW header balancing if required.
The inspectors reviewed the low flow issues and corrective actions with engineering.
The condition reports only addressed meeting the 15,400 gpm during IST. The licensee's accident analysis assumes a minimum assured ICW flowrate of 15,200 gpm through the operable header.
The inspectors questioned the capability of the ICW system to meet the minimum flowrate requirements at all times (not just during the IST).
Subsequently, the licensee determined that the ICW system configuration during IST reduced the potential flowto the two CCW heat exchangers on the operable header.
During an actual design basis accident, there would be more ICW flowthrough the operable header.
Additionally, Engineering stated that the IST procedure was incorrect in specifying a 15,400 GPM minimum flowduring the testing. Additional flowwas available if required, and the test was being performed in a more conservative configuration. The inspectors noted that the previous operability assessments for low flow conditions had not utilized this conservatism for justification of operability.
Conclusions Although operability evaluations were completed when several instances of low Intake Cooling Water flowwere experienced during testing, the root cause and effects of the low flowconditions were not fullyevaluated by the licensee.
Technical Specification requirements for the ICW system were met during the testin IV. Plant Su ort P5 Staff Training and Qualification in EP P5.1 Emer enc Pre aredness Drill a.
Ins ection Sco e 71750 The inspector participated in an emergency preparedness drill in the Technical Support Center (TSC) and in the control room simulator on January 13, 1999.
b.
Observation and Findin s In preparation for the annual exercise planned for February 10, 1999, the licensee conducted a simulator plant accident.
Two of the three fission product barriers were simulated to fail and challenge the final containment barrier. The inspector observed good status briefings by the emergency coordinator.
Activities were appropriately focused on preventing a release and protecting the public.
The inspector discussed with the licensee the lack of direct reactor power indications in the TSC, TSC review of press releases, priority of operations support center teams, and
'he alternate site evacuation route.
Each of these items were also addressed by the licensee during the drill or drill critique.
Conclusions The licensee conducted a challenging emergency preparedness drill in preparation for the annual exercise.
F2 Status of Fire Protection Facilities and Equipment a.
Ins ection Sco e 71707 61726 The inspector observed surveillance testing of the Diesel Driven Fire Pump.
b.
Observations and Findin s On January 18, 1999, the inspector observed operators perform surveillance 0-OSP-016.23, Diesel Driven Fire Pump Operability Test, dated July 16, 1998. The licensee performs this test to comply with requirements in the Fire Protection Program.
A thorough pre-job briefing was performed in the control room. The watch engineer and a non-licensed operator reviewed the procedure along with four operators that were observing for training purposes.
During the surveillance, the inspector questioned the operators on items relating to the surveillance procedure, acceptance criteria, and operation of the diesel.
The inspectors concluded that the operators were
knowledgeable of the procedure, acceptance criteria, and operation of the diesel.
During operation of the diesel engine, the inspector obtained data directly from the engine gages and verified the surveillance acceptance criteria was met. The inspector walked down the diesel engine and the diesel engine room. Three material condition deficiencies were noted involving equipment in the room. Plant Work Orders were subsequently initiated to address the items.
The inspectors verified the surveillance test prerequisites which requires calibrated equipment and ensures the diesel engine is not operated within two hours prior to performing the test.
Conclusions The diesel fire pump operability test was well performed.
V. Mana ement Meetin s and Other Areas X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on February 9, 1999.
An interim exit meeting was held on January 14, 1999, for the Region based MOV inspection.
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.
PARTIALLIST OF PERSONS CONTACTED Licensee T. Abbatiello, Quality Assurance Manager G. Hollinger, Licensing Manager R. Hovey, Site Vice-President D. Jernigan, Plant General Manager T. Jones, Operations Manager J. Kirkpatrick, Protection Services Manager R. Kundalkar, Vice President, Engineering and Licensing M. Lacal, Training Manager M. Pearce, Work Control Manager R. Rose, Maintenance Manager E. Thompson, Licensee Renewal Project Manager D. Tomaszewski, Acting Site Engineering Manager J. Trejo, Health Physics/Chemistry Supervisor A. Zielonka, Thermolog Project Manager
'ther licensee employees contacted included office, operations, engineering, maintenance, chemistry/radiation, and corporate personne ~
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NRC C. Patterson, Senior Resident Inspector R. Reyes, Resident Inspector L. Wert, Branch Chief
INSPECTION PROCEDURES USED IP 37551:
IP 40500:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
TI 2515/1 40:
Onsite Engineering Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Surveillance Observations Maintenance Observations Plant Operations Plant Support Activities Implementation of Generic Letter (GL) 96-05, Periodic Verification of Design-Basis Capability of Safety-Related Motor-Operated Valves
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