IR 05000335/1991012
| ML17223B239 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 07/15/1991 |
| From: | Crlenjak R, Elrod S, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17223B238 | List: |
| References | |
| 50-335-91-12, 50-389-91-12, NUDOCS 9108120064 | |
| Download: ML17223B239 (14) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-335/91-12 and 50-389/91-12 Licensee:
Florida Power
& Light Co 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 Facility Name:
St. Lucie 1 and
License Nos.:
DPR-67 and NPF-16 Inspection Conducted:
May 29 -
une 17, 1991 Inspecto s:
. A.
E rod, S
or si ent nspector gne
. A. Scott, R
ent Inspector
~
~
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Approved By:
R. V. Cr nba
, Sects C ref Division of Reactor Projects D te gne ae one SUMMARY Scope:
This routine resident inspection was conducted onsite.in the areas of plant operations review, maintenance observations, surveillance observations, review of nonroutine events, and followup of previous inspection findings.
Results:
During this period, operations personnel performed several power changes well.
Surveillances were performed with good control.
A non-cited violation occurred concerning a fire watch patrol and an unresolved item developed concerning starting of the other emergency diesel generator (EDG)
when an EDG under post-maintenance test fails due to the preventive maintenance (PM) for which it was removed from service.
Licensee management found a weakness in the process for approving temporary changes and temporarily strengthened the process while a permanent solution was researched.
Several maintenance items were properly addressed by the licensee.
Within the areas inspected, the following non-cited violation (NCV)
and unresolved item (URI) were identified:
NCV 335/91-12-02, Late TS-Required Fire Watch Patrol, paragraphs 2b and 6.
URI 335,389/91-12-01, Applicability of TS Requirement to Run an Operable EDG Upon Failure of One EDG to Pass a Post-Maintenance Test, paragraph 2b.
9108120064 910717 PDR ADOCK 05000336
REPORT DETAILS Persons Contacted Licensee. Employees
- D. Sager, St. Lucie Site Vice President G. Boissy, Plant Manager J. Barrow, Fire Prevention Coordinator
- H. Buchanan, Health Physics Supervisor
- C. Burton, Operations Superintendent R. Church, Independent Safety Engineering Grou
- R. Dawson, Maintenance Superintendent R. Englmeier, Site guality Manager R. Frechette, Chemistry Supervisor
- J. Holt, Plant Licensing Engineer
- C. Leppla, I&C Supervisor L. McLaughlin, Plant Licensing Superintendent A. Menocal, Mechanical Maintenance Supervisor
- L. Rogers, Electrical Maintenance Supervisor N. Roos, Services Manager C. Scott, Outage Management Supervisor D. West, Technical Staff Supervisor J. West, Operations Supervisor W. White, Security Supervisor
- D. Wolf, Site Engineering Supervisor G. Wood, Reliability and Support Supervisor E. Wunderlich, Reactor Engineering Supervisor p Chairman Other licensee employees contacted included engineers,.
technicians, operators, mechanics, security force members, and office personnel.
NRC Employees
- S. Elrod, Senior Resident Inspector
- M. Scott, Resident Inspector
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
Review of Plant Operations (71707)
Unit 1 began and ended the inspection period at power - day 41 of power operation since its return from CEA testing.
Unit 2 began and ended the inspection period at power - day 193 of power operatio Plant Tours The inspectors periodically conducted plant tours to verify that monitoring equipment was recording as required, equipment was properly tagged; operations personnel were aware of plant conditions, and plant housekeeping efforts were adequate.
The inspectors also determined
. that appropriate radiation controls were properly established, critical clean areas were being controlled in accordance with procedures, excess equipment or material was stored properly, and combustible materials and debris were disposed of expeditiously.
During tours, the inspectors looked for the existence of unusual fluid leaks, piping vibrations, pipe hanger and seismic restraint settings, various valve and breaker positions, equipment caution and danger tags, component positions, adequacy of fire fighting equipment, and instrument calibration dates.
Some tours were conducted on backshifts.
The frequency of plant tours and control room visits by site management was noted to be adequate.
The inspectors routinely conducted partial walkdowns of ESF, ECCS, and support systems.
Valve, breaker, and switch lineups and equipment conditions were randomly verified both locally and in the control room.
The following accessible-area ESF system walkdowns were made to verify that system lineups were in accordance with licensee requirements for operability and equipment material conditions were satisfactory:
Unit 1 and
EDG fuel oil tanks and transfer pumps, Unit 2 containment, and Unit 1 ICW intake structure.
During the Unit
ICW intake structure walkdown, the inspectors identified a structural concrete problem.
They observed a crack in the 1C pump pedestal and some general degradation in the other two pedestals.
The plant history included some concrete degradation of other outside concrete structures wetted by salt water.
Licensee NCR 1-607 identified the as-found conditions and satisfactorily addressed immediate operability.
The NCR further specified the inspection method and reporting requirements for the concrete intake structures, which were very similar to methodology previously used on the Unit I CCW platform.
The corporate engineering group has been applying lessons learned from similar Turkey Point experience.
Plant Operations Review The inspectors periodically reviewed shift logs, operations records (including data sheets),
instrument traces, and records of equipment malfunctions.
This review included control room logs and auxiliary logs, operating orders, standing orders, jumper logs, and equipment tagout records.
The inspectors routinely observed operator alertness
and demeanor during plant tours.
They observed and evaluated control room staffing, control room access, and operator performance during routine operations.
The inspectors conducted random off-hours inspections to ensure that operations and security performance remained at acceptable levels.
Shift turnovers were observed to verify that they were conducted in accordance with approved licensee procedures.
Control room annunciator status was verified.
Except as noted below, no deficiencies were observed.
During this inspection period, the inspectors reviewed the following tagouts (clearances):
2-6-25 Unit 2 MV 14-20,
"A" CCW header valve from the SFP HX, 2-6-46 Unit 2 SIT sample valves, and 2-6-54 Unit 2 EDG Fuel Oil Transfer Pump 2A.
On May 13, with Unit 1 at full power, operators ran the monthly 10-hour fan surveillance of the 6B shield building fan.
The fan vacuum precluded opening the door while the fan was running.
At the same time, one of the shield building fire protection alarm groups was out of service, requiring a fire patrol at least once per eight hours.
The operator thought the TS meant
"once per shift".
The patrol was not performed for about 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />, 45 minutes.
This is a
violation of TS 3.3.3.7 but is not being cited because the criteria cited in section V.G.1 of the NRC enforcement policy were satisfied.
This item is identified as NCV 335/91-12-02, Late TS-Required Fire Watch Patrol.
On June 14, with Unit 1 at power, Unit 1 procedure LOI-0-46, Rev 0, TC 1-91-104, Silica Removal From Unit 1 Systems, was being performed by operators to reduce the silica concentration in the RWT and in the water contained in the HPSI/LPSI SI flow path piping.
One feature of this LOI was RWT recirculation at about
gpm through a small-diameter flow path associated with an SIT and possessing automatic isolation valves that isolate upon an SI signal.
A temporary change to this LOI was made to shift the recirculation path to a larger line that would pass about 1500 gpm but had an isolation valve operable from the control board instead of an automatic isolation valve.
This larger line was normally isolated by locked-closed valves and used to fill or drain the refueling canal during refueling operations, but would provide better RWT mixing from the larger flow rate.
Two shifts later, the system was aligned and recirculation commenced.
After about two hours of RWT recirculation, the NPS reviewed the evolution and questioned if the injection flow available after subtracting the large recirculation flow would support the Unit 1 accident analysis.
This issue was raised since, for Unit 1, the larger recirculation line tapped off a common LPSI flow line and hence would affect both safety trains.
Recirculation was immediately
stopped and the system restored to its normal configuration.
Licensee engineering analysis determined that the plant accident response was still within accident analysis limits, but with a
reduced margin.
The performed analysis was based on conditions existing at the time and was not suitable for general application throughout this fuel cycle.
The licensee initiated a review of the temporary change process.and, meanwhile, was requiring all TCs to be additionally processed by the NPS instead of each unit's ANPS only.
While this condition was found to not violate TS in this instance, it demonstrated a
weakness in the control process.
The licensee's handling of the matter reflected favorably on the site operations management.
The NRC is interested in the secondary system impact on plant safety.
Power level changes or other manipulations of the steam side of the plant can increase the probability of challenges to reactor systems..
At this site, the licensee routinely changes power level to clean the main condenser saltwater side, which becomes overgrown with lower forms of marine life.
Beginning in the last inspection period and continuing into the early part of this inspection period, the licensee has been attempting to resolve main condenser performance problems.
Both units had minor dissolved oxygen problems (see below).
Both units were developing higher-than-normal condenser back pressures.
The indications lead to three possibilities:
earlier-than-expected biofouling of the condensers, air leaks into the condensers, and other contaminants in the condensers.
Secondary chemistry levels of dissolved oxygen (DO) and iron products were closely monitored, primarily due to SG tube degradation considerations.
In April for Unit 2 and then in May for Unit 1, DO began to rise above a somewhat arbitrary administrative level of 10 ppb.
As DO level rose to an EPRI guideline action level (as reflected in licensee corporate chemistry procedure JNO-CHEN, Rev 12),
and following careful licensee review, site procedures were temporarily changed to allow operation at slightly higher DO levels.
The changed procedures were:
ONOP 1-0610031, Rev 8, Secondary Chemistry Off-Normal; ONOP 2-0610030, Rev 11, Secondary Chemistry Off-Normal; and C-51, Rev 16, Maintaining Condensate and Feed System Chemistry.
The EPRI guidelines allow operation at elevated levels (10 to
ppb have been observed to date with an additional action level in the procedures of 30 ppb not to be exceeded)
with proper overview.
The chemistry department has been monitoring iron product levels in the water and those have not increased.
Iron product level increases would indicate material changes in the system pipes or SG tube Condenser parameters that affect performance are as follows:
Back Pressure
- this is the difference between the vacuum that can be drawn in the condenser and an absolute vacuum.
As back pressure increases, condenser efficiency declines.
When back pressure reaches 4.0 inches of Hg, Westinghouse recommends that power be reduced to. prevent excessive moisture and temperature in the vicinity of the turbine blading.
Intake water had warmed to the middle/low 80 degrees Fahrenheit.range, which increased back pressure.
The warmer water also increased biofouling rates, which further increased back pressure.
Biofouling - this is marine growth on the the tube sheets and in the tubes.
The licensee installed plastic cylindric traps that fit into the tubes, at the condenser tube sheet, to reduce in-tube biofouling and increase the intake area of each tube.
The Environmental Protection Agency has banned the use of chlorine and restricted the use of hypochlorite in marine growth retardation.
The licensee used a weak hypochlorite solution to maintain condenser operability.
The hypochlorite system had been recently overhauled and was gradually being returned to service.
Steam jet air ejectors (SJAE) - this device removes non-condensable gases from the shell (steam)
side of the secondary condenser.
These gases are not desirable in the condensate.
Oxygen particularly is not desired due to the potential steam generator damage it may cause.
The SJAEs are affected by air inleakage and condenser problems.
As Unit 2 condenser performance declined, the licensee called in a contractor with sensitive equipment for the detection of hotwell air leaks.
No major air leaks were present.
This led the plant staff to conclude that biofouling had occurred earlier than anticipated.
The licensee cleaned the tube sheets of two Unit 2 water boxes.
This consisted of raking the sheet where the tubes attach without cleaning the individual tube internals.
This reduced cleaning approach was done to reduce the time required for cleaning and hence the period required at reduced power.
This cleaning did not increase condenser performance as much as desired.
The licensee postulated that with the high intake water temperatures, the SJAEs were becoming steam bound.
This steam binding reduced SJAE efficiency and resulted in increased non-condensible gas levels in the condenser.
Coincident with this cleaning, the licensee discovered that the hypochlorite system was not operating at full capacity.
The plant staff had been running the system approximately 25 percent below the maximum allowed EPA levels.
System efficiency was improved over the next week-.
At the end of the last inspection period and continuing into this one, the licensee reduced power to more thoroughly clean the Unit 2 water boxes.
The tubes were shot with brushes after the tube sheet was raked.
The brushes, which each resembled a stiff baby bottle brush with a curved cap on one end, removed growth from the tube internals.
The brushes were forced through the tubes by high water pressure.
The brushes were 'also used on the central portion of the tube sheet around the intake pipes for the SJAEs.
Despite the cylindric trap over the tube ends, several of the brushes had to be rodded out of tubes that were blocked with marine growth.
Additionally, an unexpected muddy silt was found in some of the tubes.
Some silt was generated and transported to the condensers as a result of the ongoing construction to rebuild the structures surrounding the cooling water intakes.
Additionally, a recent storm may have stirred the bottom of the ocean and contributed to this observed silting.
At the end of the first week of the inspection period, the licensee had completely cleaned two water boxes in the Unit 1 condenser.
There was less silt present than found in the Unit 2 tubes.
Unit 2 is closest to the water intakes.
During the last week of the inspection period, the utility had again cleaned the complete Unit 2 condenser (raked the tube sheet-and brushed/shot all the tubes).
The Operations staff performed the three power changes for waterbox cleaning well.
During a monthly stroke surveillance of valve MV 2508, the valve was found to be stuck.
Normal switch (electrical)
and manual operator actuation would not open the valve.
The valve is in one of three possible emergency boration flow paths.
Initial troubleshooting by the electrical department revealed that the valve internals were frozen.
Although scheduled for MOVATS testing and torque switch adjustments under the licensee's Generic Letter 89-10 program implementation, the valve's actuator had been routinely addressed by the preventive maintenance program (grease sampled).
The valve was taken out of service.
This did not place the system in an LCO, but did warrant verifying which other equipment was in service such as charging pumps and BAN tanks.
The technical staff developed a
FRG approved plan for the NOV.
Since the valve was on the suction of the charging pumps and a freeze seal on that three-inch line (charging pump to MOV) filled with boric acid would be difficult at power, the FRG limited the work scope.
Initial attempts were made to open the valve without valve disassembly.
Mith the actuator still installed, mechanical agitation with a bounceless hammer and the limited addition of heat to the valve body failed to loosen the valv The actuator was then removed so that a special tool could be installed on the stem for jacking and shock loading the valve stem.
The valve was loaded axially to a maximum specified value of 10,500 lbs. without any stem or gate movement.
Separately, the electrical department checked the valve operator.
The spring pack and torque switch worked satisfactorily.
Based on the measured and observed values from the above components and calculations, the licensee stated that the actuator had generated a
nominal closing thrust of 5,000 to 7,000 lbs.
The licensee had no spare valve to install in the NV 2508 position.
They also had no ready spare parts for the valve.
At the end of the inspection period, they were awaiting parts (seats for the existing valve and a
new replacement valve) prior to any further repair actions.
On June 12, a piece of scaffolding fell and disabled the 2C AFW pump by breaking a turbine bearing oil line.
This happened while the scaffolding was being installed to repair a root valve leak on a
steam line located in the steam trestle space above the pump.
The pump was not operating at the time.
The loss of the pump delayed the start of EDG PHs and subsequent surveillance test run of the 2A EDG.
As a partial corrective action, the licensee intends to not install scaffolding in the upper level of the trestle spaces without FRG approval.
On June 14, following completion of various PMs, the 2A EDG was started at 4: 16 a.m. for post-maintenance operability and periodic surveillance testing.
The operator received a fail-to-start alarm for one of the two engines and, after about eight minutes, stopped the EDG because the engine cylinder head temperatures were still about 100 degrees Fahrenheit.
The face plate on the governor was found binding the speed control knob.
This was quickly adjusted.
The licensee intends to machine slightly larger the hole in the face plate to prevent future binding.
The 2A EDG was restarted at 7:18 a.m.
and satisfactorily tested per OP 2-2200050, Rev 33, Emergency Diesel Generator Periodic Test and General Operating Instructions.
The surveillance test was performed properly and the Fuel Oil Transfer Pump ASNE Code Section 11 data was collected.
Unit 2 TS 3.8.1.1 action statement
"b" requires that if the EDG became inoperable due to any cause other than preplanned preventive maintenance or testing, demonstrate the OPERABILITY of the remaining OPERABLE EDG by performing Surveillance Requirement 4.8.1. 1.2a.4
[start the OPERABLE EDG from ambient] within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
This start of the other OPERABLE EDG is required regardless of when the inoperable EDG is restored to OPERABILITY.
When the 2A EDG failed to start on June 14, the licensee did not run 2B EDG within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as discussed
above because the EDG start attempt was
"associated with" (i.e.,
following) preplanned preventive maintenance and the failure.to start was caused by preplanned preventive maintenance.
This is URI 335,389/91-12-01 pending further NRC review of whether the TS leeway concerning not starting the other EDG within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> applies only when removing one EDG for PM or test or whether it also applies when the EDG subsequently fails a
post-maintenance operability validation.
c.
Technical Specification Compliance Licensee compliance with selected TS LCOs was verified.
This included the review of selected surveillance test results.
These verifications were accomplished by direct observation of monitoring instrumentation, valve positions, and switch positions, and by review of completed logs and records.
Instrumentation and recorder traces were observed for abnormalities.
The licensee's compliance with LCO action statements was reviewed on selected occurrences as they happened.
The inspectors verified that related plant procedures in use were adequate, complete, and included the most recent revisions.
d.
Physical Protection The inspectors verified by observation during routine activities that security program plans were being implemented as evidenced by: proper display of picture badges; searching of packages and personnel at the plant entrance; and vital area portals 'being locked and alarmed.
Aside from the EDG URI, operational practices were satisfactory during this inspection period.
The efforts to maintain proper secondary chemistry were laudable.
3.
Surveillance Observations (61726)
Various plant operations were verified to comply with selected TS requirements.
Typical of these=-were confirmation of TS compliance for reactor coolant chemistry, RWT conditions, containment pressure, control room ventilation, and AC and DC electrical sources.
The inspectors verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated, LCOs were met, removal and restoration of the affected components were accomplished properly, test results met requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The following surveillance tests were observed:
I8C 2-0110068, Rev 2,
Six Month Operational CEA Block Circuit Functional Test (NPWO 7107/62),
AP 2-10125A, Rev 21, Surveillance Data Sheets, Data Sheet 0'10 for valve MV 14-20, MP 2-M-0018, Rev 24, Mechanical Maintenance Safety-Related Preventive Maintenance Program, Appendix A,
PMs 5301 and 5302, 2A EDG Lubricating Oil Sample, OP 2-2200050, Rev 33, EDG Periodic Test and General Operating Instructions,.for 2A EDG, and OP 2-2200050, Rev 33, Data Sheet 1,
2A EDG Fuel Oil Transfer Pump quarterly Pump Code Run.
The observed surveillances were performed satisfactorily.
4.
Maintenance Observation (62703)
Station maintenance activities involving selected safety-related systems and components were observed/reviewed to ascertain that they were conducted in accordance with requirements.
The following items were considered during this review:
LCOs were met; activities were accomplished using approved procedures; functional tests and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; and radiological controls were implemented as required.
Work requests were reviewed to determine the status of outstanding jobs and to ensure that priority was assigned to safety-related equipment.
Portions of the following maintenance activities were observed:
a.
NPWO 3153/61 was the wor k control document for the repacking the 1C charging pump plunger packing cartridges.
The packing cartridge tolerance stackup in relation to its installed position in the pump's power head generated some questions during the work.
The shop personnel contacted a
mechanical department equipment engineer who satisfactorily resolved the issue.
The resolution included procedure change TC 1-91-105 to associated procedure 1-M-0041, Rev 13, Charging Pump Maintenance.
b.
NPWO 7034/62 was the work control document for repairing the 2B main feedwater regulating valve, FCV-9021, that had begun to operate erratically within its control band.
The I&C shop had completed the appropriate sensitive systems forms, conducted a tailboard meeting with operations personnel, and obtained a
FRG-approved NPWO scope change.
The work was performed satisfactorily with minimal risk to plant operation.
The associated 15-percent feedwater bypass valve, LCV-9006, did not operate well in the automatic mode and NPWO 7111/62 was generated to have it repaire NPWO 7120/62 was the work control document for resetting the 2B1 and 2B2 RCP vibration alarms.
The reliability support group, aligned under the maintenance department, had issued memorandum RSM/PSL 4'116 of May 31, 1991, that directed the alarm change.
The RCP vibration increases of between 0.5 and 1.5 mils (thousandths of an inch displacement),
occurring since unit startup in May, were expected and the vibration absolute magnitudes were not approaching vendor guideline limits.
The memorandum stated that spectral analysis of the vibration signature did not indicate any abnormal patterns.
The overall licensee effort regarding understanding intricate pump vibration parameters was good.
PCM 092-288D, NPWO 2776/62 (mechanical),
and NPWO 6480/62 ( ISC) were the work control.documents for repairing Unit 2 SE 05-01B, 2A2 SIT sample valve, located in the containment building.
The valve had begun to leak at the end of a sample gathering period.
The valve was a Target Rock brand pilot-operated solenoid valve.
To maintain SIT and containment TS required integrity, SE 05-01B had to be isolated by other valves in the sampling system as shown on drawing 2998-G-078, sheet 153, Sampling System Flow Diagram.
Isolation of the series of SIT sample valves on a
common header created an operational concern because the valves had to be alternately manipulated to sample the various SITs.
Two of the SITs'solation valves were leaking slightly, requiring routine filling and sampling.
With SE 05-01B failing the site LLRT administrative limit, but not any plant total bypass limits, a plan was developed to repair the valve.
Because leak down of a SIT level below TS limits was not desired, a
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time constraint was placed on the repair to leave a time margin for SIT parameter maintenance.
Because operations held the clearances on the associated valve and controlled SIT parameters, operations was the job lead with the maintenance department providing around-the-clock repair coverage.
The inspectors were present during the removal of the valve from the containment system piping and for valve disassembly.
Observations concerning the work follow:
ISC removal of the valve was well controlled with good ALARA considerations; Mechanical Maintenance disassembly of the valve was executed properly with good overall knowledge and understanding; The valve fai lure was identified by the valve vendor as expected maintenance as opposed to a material problem; and Health Physics support of both the valve removal and valve repair was goo The mechanical maintenance valve technical manual, used on the job with some minor confusion, did not contain a detailed valve drawing.
A later search of available valve drawings produced a "G" size vendor drawing with some detail.
That drawing represented the level of information transmitted by the vendor.
Mechanical maintenance discussed with their planning department the need for using the highest level of detail available in work package generation.
Site engineering, who was upgrading valve drawings within technical manuals under an ongoing long-term program, planned to ask the vendor for additional, more detailed, drawings.
SE 05-01B was satisfactorily tested and returned to service.
First, the valve was shop tested with air per the valve technical manual.
Once the valve was reinstalled, operations satisfactorily stroke tested it.
An LLRT produced only 30 cubic centimeters of test air leakage instead of 'the before repair leakage of 9,000 cubic centimeters.
5.
Fire Protection (64704)
Fire protection inspection occurred during this inspection period as discussed in paragraph 2.
Onsite Followup of Written Nonroutine Event Reports (Units I and 2)
(92700)
LERs were reviewed for potential generic impact, to detect trends, and to determine whether corrective actions appeared appropriate.
Events that the licensee reported immediately were reviewed as they occurred to determine if the TS were satisfied.
LERs were reviewed in accordance with the current NRC Enforcement Policy.
a.
(Closed - Unit I)
LER 335/91-03, Manual Reactor Trip Following A Turbine Runback.
This event is discussed in IR 335/91-10.
The LER adequately reports it.
This item is closed.
b.
(Closed - Unit I) LER 335/91-04, Late TS Required Fire Watch Patrol Due to Personnel Error.
This item is discussed in paragraph 2b of this report.
The LER adequately reports it.
This item is closed.
7.
Followup of Unresolved Items (Closed - Units I and 2)
URI 335,389/90-13-02, Unclear UHS Valve Cycling Criteria.
This item concerned a condition where marginal performance (measured in seconds)
of a valve in the UHS barrier was not promptly corrected.
The reasons included both technical reasons, such as the flow rate through the partially-open butterfly valve being adequate, and licensee recognition that the TS action statement allowed many hours to take compensating measures.
The surveillance'requirements appeared to be far harsher than,
and inconsistent with, the associated TS action statement requirements.
The item was unresolved pending NRC review of the relationship between the surveillance and the action s'iatement.
The inspector reviewed the TS, the FSAR, and the test history, and witnessed test performance on April 18, 1991.
The April 18 test was conducted per OP 0360050, Rev.7, Emergency Cooling Water Canal - Periodic Test.
The valves performed well and baseline valve stroke times were obtained based on control room operation and indication per ASME Code Section 11.
The inspector confirmed that the TS action statement was based on operational considerations and that the stroke time was based on valve construction.
Now that the valves are in the ASME Code Section
program, the test techniques and subsequent actions are clearer.
This item was not considered to be a violation of TS and is closed.
Exit Interview (30703)
The inspection scope and findings were summarized on June 14, 1990, with those persons indicated in paragraph 1 above.
The inspector described the areas inspected and discussed in detail the inspection findings listed below.
Proprietary material is not contained in this report.
Dissenting comments were not received from the licensee.
Item Number Status Description and Reference 335,389/90-13-02 closed URI - Unclear UHS Valve Cycling Criteria, paragraph 7.
335,389/91-12-01 open URI - Applicability of TS Requirement to Run an Operable EDG Upon Failure of One EDG to Pass a Post-Maintenance Test, paragraph 2b.
335/91-12.-02 closed NCV - Late TS-Required Fire Watch Patrol, paragraphs 2b and 6.
Abbreviations, Acronyms, and Initialisms AFW ALARA ANPS AP ASME Code ATTN BAM CCW CEA CFR Auxiliary Feedwater (system)
As Low as Reasonably Achievable (radiation exposure)
Assistant Nuclear Plant Supervisor Administrative Procedure American Society of Mechanical Engineers Boiler and Pressure Vessel Code Attention Boric Acid Makeup (tank etc.)
Component Cooling Water Control Element Assembly Code of Federal Regulations
DPR ECCS EDG EPA EPRI ESF FCV FRG gpm Hg HPSI HX ISAAC ICW IR lb LCO LCV LER LLRT LOI LPSI MOV MOVATS MP MV NCR NCV NPF NPS NPWO NRC ONOP OP PCM PM ppb ppm RCP Rev RWT SFP SG SI SIT SJAE St.
TC TS UHS URI Demonstration Power Reactor (A type of operating license)
Emergency Core Cooling System Emergency Diesel Generator Environmental Protection Agency Electric Power Research Institute Engineered Safety Feature Flow Control Valve Facility Review Group Gallon(s)
Per Minute (flow rate)
Mercury (element)
High Pressure Safety Injection (system)
Heat Exchanger Instrumentation and Control Intake Cooling Water
[NRC] Inspection Report pound TS Limiting Condition for Operation Level Control Valve Licensee Event Report Local Leak Rate Test Letter of Instruction Low Pressure Safety Injection (system)
Motor Operated Valve Motor Operated Valve Test System
.Maintenance Procedure Motorized Valve Non Conformance Report Non-Cited Violation (of NRC requirements)
Nuclear Production Facility (a type of operating license)
Nuclear Plant Supervisor Nuclear Plant Work Order Nuclear Regulatory Commission Off Normal Operating Procedure Operating Procedure Plant Change/Modification Preventive Maintenance Part(s)
per Billion Part(s per Million Reactor Coolant Pump Revision Refueling Water Tank Spent Fuel Pool Steam Generator Safety Injection (system)
Safety Injection Tank Steam Jet Air Ejector Saint Temporary Change Technical Specification(s)
[NRC] Unresolved Item