IR 05000397/1988030
| ML17284A600 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 10/28/1988 |
| From: | Bosted C, Johnson P, Sorensen R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17284A599 | List: |
| References | |
| 50-397-88-30, NUDOCS 8811160375 | |
| Download: ML17284A600 (25) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report No:
Docket No:
50-397/88-30 50-397 Licensee:
Washington Public Power Supply System P.
0.
Box 968 Richland, WA 99352 Facility Name:
Washington Nuclear Project No.
2 (WNP-2)
Inspection at:
WNP-2 Site near Richland, Washington Inspection Conducted:
Augus 0 - September 30, 1988 Inspector:
Inspector:
Approved by:
C. J.
usted, Senior Resident Inspector i
~l R.
C.
orensen, Resident Inspector
~
~
i P.
H. /Johnson, Chief Reactbd Projects Section
Date Signed
<-i~ z j~z Date Signed l~fag/cpp Date Signed Summary:
Ins ection on Au ust 20 - Se tember
1988 (50-397/88-30 Areas Ins ected:
Routine inspection by the resident inspectors of control room operations, engineered safety feature (ESF) status, surveillance program, maintenance program, licensee event reports, special inspection topics, and licensee action on previous inspection findings.
During this inspection, Inspection Procedures 30703, 61702, 61715, 61726, 62703, 62704, 71707, 71709, 71710, 71881, 90712, 90713, 92700, 92701, 92702 and 93702 were covered.
Results:
No violations or deviations were identified.
During the start of RHR "B" pump on August 27, 1988 a water hammer event was observed and reported by the equipment operator (paragraph 10).
A weakness was observed in the licensee's delay in understanding the source of the problem and effecting corrective actions once the problem was identified.
Management demonstrated more aggressive pursuit of problem determination following a liquid nitrogen event (paragraph 14) which occurred at the end of the reporting period.
The liquid nitrogen event was promptly acted on and resources were allocated to determine the extent of the problem and identify the root causes.
881 i 1b0375 885028 PDR ADOCK 05000397
PNlJ
,
Persons Contacted DETAILS L. Oxsen, Assistant Managing Director for Operations D. Bouchey, 'Director, Licensing and Assurance
"C. McGilton, Operational Assurance Manager
"C. Powers, Plant Manager
"J. Baker, Assistant Plant Manager K. Cowan, Nuclear Safety Assurance Manager C.
Edwards, guality Control Manager
"R. Graybeal, Health Physics and Chemistry Manager J.
Harmon, Maintenance Manager A. Hosier, Licensing Manager D. Kobus, guality Assurance Manager R. Koenigs, Technical Manager S. McKay,'Operations Manager
"J. Peters, Administrative Manager
"W. Shaeffer, Assistant Operations Manager
"R. Webring, Assistant Maintenance Manager M. Wuestefeld, Assistant Technical Manager The inspectors also interviewed various control room operators, shift supervisors and shift managers, engineering, quality assurance, and management personnel.
"Attended the Exit, Meeting on September 30, 1988.
Plant Status At the start of the inspection period, the plant was operating at 100Fo power, and operated at this level through August 24.
High unidentified drywell leakage (greater than the Technical Specification 5 gpm limit)
was experienced at that time.
Subsequently, on August 25, the reactor was shut down due to the high leakage and an Unusual Event (UE) was declared by the licensee.
The licensee terminated the UE when the plant was cooled down and depressurized and the leakage was determined to be less than 5 gpm.
Following the shutdown, an inspection of the drywell determined that the the source of the increased leakage into the drywell was a packing leak on reactor core isolation cooling (RCIC) valve V-63.
The unidentified leakage before this packing leak occurred had slowly increased since the beginning of the fuel cycle to approximately 4 gpm.
The cause of this leakage was determined to be steam leaking past the seats of most of the safety relief valves (SRVs)
and through the vacuum breaker valves (located in the safety relief valve tailpipes) into the drywell atmosphere.
This condition had also been experienced during the previous operating cycle.
The plant remained shutdown for 11 days while RCIC V-63 was repaired, and the three most accessible and highest leaking SRVs were repaired.
During this outage all SRV tailpipe vacuum breakers were also overhauled.
While the plant was shut down, a shift of the residual heat removal (RHR)
system lineup resulted in a water hammer event (see paragraph 10 for
additional information).
The plant was restarted on September 6,
and on September 7, during checks of the acoustic monitors for the SRVs, one of the SRV monitors was observed to be not fully functional such that it would probably fail in the near future.
This monitor provides position indication for the SRV and was functional and indicating satisfactorily when tested.
However, from indications observed during testing, plant engineers determined that the monitor's power supply was degrading and expected failure of the monitor in the near future.
Plant management directed that the plant be shut down after it was,.determined that the monitor could not be replaced with the plant at normal operating temperatures.
The plant was again restarted on September.
8.
During the subsequent power escalation on September 9, while attempting to inert the drywell, liquid nitrogen was introduced into the drywell purge system and cracked the purge supply line (see paragraph 14 for additional information).
Power was increased to 100K on September 13 and remained at that level until the end of the reporting period.
3.
Previousl Identified NRC Ins ection Items 92701 92702 The inspectors reviewed records, interviewed personnel, and inspected plant conditions relative to licensee actions on previously identified inspection findings:
(Closed)
Unresolved Item (397/87-19-15):
Failure of Design Documents to Accurately Reflect Actual Plant Configuration Several plant drawings were checked against the installed equipment on the emergency diesel generators (EDGs)
and systems.
The drawings contained numerous inaccuracies and may not have reflected the actual plant conditions.
The inspector reviewed the updated drawings and confirmed that several changes were completed that corrected several small inaccuracies with the diesel skid drawings.
These errors were believed to be due to changes the vendor made prior to shipping the EDGs.
The inspector was also informed that in addition to updating the drawings, the systems were walked down by the system engineer.
This item is closed.
4.
0 erational Safet Verification 71707 Plant Tours The following plant areas were toured by the inspectors during the course of the inspection:
Reactor Building Control Room Diesel Generator Building Radwaste Building Service Water Buildings Technical Support Center Turbine Generator Building Yard Area and Perimeter
b.
The following items were observed during the tours:
0 eratin Lo s and Records.
Records were reviewed against Technical Specification and administrative control procedure requirements.
(2)
Monitorin Instrumentation.
Process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
(3)
for conformance with 10 CFR 50.54. (k), Technical Specificati'ons, and administrative procedures.
(4)
E ui ment Lineu s.
Valves and electrical breakers were veri-fied to be in the position or condition required by Technical Specifications and Administrative procedures for the applicable plant mode.
This verification included routine control board indication reviews and conduct of partial system lineups.
(5)
E ui ment Ta in
.
Selected equipment, for which tagging requests had been initiated, was observed to verify that tags were in place and the equipment was in the condition specified.
General Plant E ui ment Conditions.
Plant equipment was ob-served for indications of system leakage, improper lubrication, or other conditions that would prevent the system from fulfillingits functional requirements.
(7)
Fire Protection.
Fire fighting equipment and controls were observed for conformance with Technical Specifications and administrative procedures.
(s)
Plant Chemistr
.
Chemical analyses and trend results were reviewed for conformance with Technical Specifications and admi nistr ati ve control procedures.
Radiation Protection Controls.
Activities observed are discussed in paragraph 8.
(10) Plant Housekee in
.
Plant conditions and material/equipment storage were observed to determine the general state of clean-liness and housekeeping.
Housekeeping in the radiologically controlled area was evaluated with respect to controlling the spread of surface and airborne contamination.
(11) ~Securit
.
Activities observed are discussed in paragraph 9.
No violations or deviations were identifie ~
5.
En ineer ed Safet Feature S stem Walkdown (71707 71710 Selected engineered safety feature systems (and systems important to safety) were walked down by the inspectors to confirm that the systems were aligned in accordance with plant procedures.
During the walkdown of the systems, items such as hangers, supports, electrical power supplies, cabinets, and cables were inspected to determine that they were operable and in a condition to perform their required functions.
The inspectors also verified that the system valves were in the required position and locked as appropriate.
The local and remote position indication and controls were also confirmed to be in the required position and operable.
Accessible portions of the following systems were walked down on the indicated dates.
~Setem Dates Diesel Generator (DG) Systems, Divisions 1, 2, and 3.
August 30 September 20,
Hydrogen Recombiners September
Low Pressure Coolant Injection (LPCI),
Trains "A", "B", and "C" August 29,
September
Low Pressure Core Spray (LPCS)
High Pressure Core Spray (HPCS)
September 1,
August 26,
September 16,
Reactor Core Isolation Cooling (RCIC)
August 30 September
Residual Heat Removal (RHR), Trains August 30 September
Scram Discharge Volume System Standby Liquid Control (SLC) System Standby Service Mater System 125V DC Electrical Distribution, Divisions 1 and
September 1, 6,
September 6,
September
August 31 September 16,
250V DC Electrical Distribution August 31 September 16,
No violations or deviations were identified.
6.
Surveillance Testin 61726 a.
Surveillance tests required to be performed by the Technical Specifications (TS) were reviewed on a sampling basis to verify
that:
1) the surveillance tests were correctly included on the facility schedule; 2)
a technically adequate procedure existed for performance of the surveillance tests; 3) the surveillance tests had been performed at the frequency specified in the TS; and 4) test results satisfied acceptance criteria or were properly dispositioned.
b.
Portions of the following surveillance tests were observed by the inspectors on the dates shown:
'JL Dates Performed 7. 4. 6. 1. 2 Inside Primary Containment Verification August 29 7.4.2.1 'ower Distribution Limits 7.4.3.7. 10.3 Loose Parts Monitor August 21 P
August 21 7.4. 8. l. 1. 2. 12 HPCS DG Monthly Operability Test September
7.4.3.3. 1.51 HPCS Level 2 Initiation (A8C) CFT/CC September
7.4.6. 1.3. 1 Containment Personnel Airlock Leakage Test September
7.4.5. 1. 11 HPCS Operability Test September
During the performance of the above HPCS DG surveillance on September 7, the inspector noted a loud noise and sparks emanating from the front end of the engine, behind the generator.
Further investigation by licensee engineers and technicians revealed that the air start motors had attempted to engage while the DG was still running.
The technical investigation determined that a speed sensor, which provided inputs to the starting circuitry, had built up sufficient magnetic debris such that it was supplying an erroneous signal.
The licensee conducted a magnetic particle examination of the gear teeth on the air start motors and found no damage.
The sensor and those of the other DGs were cleaned and the HPCS DG was retested satisfactorily.
The preventive maintenance program for the DGs was revised to periodically monitor these sensors.
c.
The following completed surveillance tests were reviewed by the inspectors:
Procedure Dates Performed 7.0.1 Shift and Daily Instrument Checks September 6. 4. 0. 5. 6 ASME Section-XI Valve Operability September
7.4.3. 1. 1.20 RPS and EOC Recirculation Pump Trip 7.4.7.6.5.3 Annual Yard Hydrant Operability September
1 September
7.4.7.6. 1. 1.2 Monthly Fire Pump Operability Test September
7.4.8.2. 1.20 Weekly Battery Testing September
7.4.8.4.4.3 Electrical Protection September
Assemblies (Channel functional Test/Channel Check)
7.4.3. l. 1.70 Local Power Range Monitor (LPRM) Calibration September
No violations or deviations were identified.
7.
Plant Maintenance 62703 During the inspection period, the inspectors observed and reviewed documentation associated with maintenance and problem investigation activities to verify compliance with regulatory requirements and with administrative and maintenance procedures, required QA/QC involvement, proper use of safety tags, proper equipment alignment and use of jumpers, personnel qualifications, and proper retesting.
The inspectors verified reportability for these activities was correct.
The inspectors witnessed portions of the following maintenance activities:
Descri tion Dates Performed RHR-V-31B Disassembly per AT 6659 August 30 Reconnect Lead for Reactor Building Exhaust Fan REA-FN-1A Ground Relay per AT 6576 Transformer Replacement in Refueling Bridge per AT 5459 August 31 September
Tr oubleshoot 8 Repair Rod Block Monitor (RBM) per AV 1843 September
Replace Relay E-RLY-50GX/MCIE per AT 6557 September
Clean sump flow switches for Reactor Building Floor Sumps per AT 3848 September
No violations or deviations were identified.
Radiolo ical Protection Practices 71709 The inspectors periodically observed radiological protection practices to determine whether the licensee's program was being implemented in conformance with facility policies and procedures and in compliance with regulatory requirements.
Areas observed included control point operation; records of licensee surveys; and postings of radiation, high radiation, and contamination areas within the radiological controlled area.
The inspectors also observed compliance with Radiation Exposure Permits, proper wearing of personnel monitoring devices, and personnel frisking practices.
The inspectors verified that health physics supervisors and professionals conducted frequent plan't tours to observe activities in progress and were generally aware of significant plant activities, particularly those related to radiological conditions and/or challenges.
ALARA consideration was given to maintenance activities observed by the inspectors.
During a plant tour on September 25, the inspector noticed that a
contractor maintenance person was working within a posted contaminated area with an radiation protection (RP) technician observing the work.
Upon exiting the area, the worker, as observed by the inspector, did not remove his protective clothing in accordance with the standard requirements.
The worker removed his skull cap last, after he had removed his cotton gloves, with his bare hand.
(The donning and removal of anti-contamination clothing is a training process and is considered
"a skill of the trade".)
This was brought to the attention of both the individual, the monitoring technician, and the radiation protection (RP)
supervisor.
The individual was not contaminated, but the inspector was concerned that the individual was not fully aware of the correct methods for donning and removing the protective clothing.
The RP supervisor took steps to insure that the individual was made aware of the protective equipment requirements and that the RP technicians were more aware of those individuals working in the posted areas.
No violations or deviations were identified.
Ph si cal Securi t (71881 The inspectors periodically observed security practices to ascertain that the licensee's implementation of the security plan was in accordance with site procedures.
The inspectors observed that the number of guards was adequate for the requirements of the security plan; that the search equipment at the access control points was operational; that the protected area barriers were well maintained without breaks; and that personnel allowed access to the protected area were badged and monitored and the monitoring equipment was functional.
Night illumination inside the protected area was observed
i,
.
and obstructions were found to be lighted adequately.
Surveillance equipment was also observed during this inspection to verify proper operation.
No violations or deviations were identified.
Water Hammer in Residual Heat -Removal RHR Dischar e Pi in 93702 On August 27, an NRC team inspector was observing the equipment operators while shifting shutdown cooling lineup from RHR train "A" to train "B".
When the suction valve for RHR Pump "B" (RHR-V6B) was opened, the pump was observed to begin rotating backwards.
The equipment operator contacted the control room about this.
When the pump stopped rotating, the pump was started and a water hammer ensued with significant pipe displacement.
Several hours later, during another attempt to shift the RHR lineup for a test of the system, a secon'd water hammer was observed.
'Two additional troubleshooting attempts were made during the system engineer's evaluation of the problem before the system was declared inoperable.
On the last attempt, the, pump would not stop turning backwards until the suction valve was shut.
The system engineer determined that the pump discharge check valve was not closing and the discharge piping was draining backwards through the pump, causing the pump to rotate backwards until a void formed in the discharge piping, stopping flow.
A low discharge pressure alarm was also received on the last attempt that had not been received. previously.
The pump discharge check valves for all three RHR trains were designed for a horizontal application but were installed in vertical piping runs during initial plant construction.
To ensure that these check valves would close under all operating conditions, an overtravel stop was originally installed on the back side of the disc to prevent the disc from opening beyond its center of gravity and staying open.
However, during plant operation since initial plant startup, the ove'rtravel stop impacted on the inside of the valve, causing a minute indentation in the valve casing.
As the indentation enlarged with each impact, the amount of travel was increased slightly, and finally the overtravel stop became insufficient to keep V-31B from hanging, up in the open position.
The valve disc was found to travel beyond the center of gravity and hang up during several attempts to operate the valve manually after it was opened for inspection.
When the valve hung open it would cause the discharge piping to drain back through the RHR pump and then through either V-4 to the suppression pool or through V-6 back to the RPY.
This would cause a
partial void in the discharge header, resulting in a water hammer when the pump was started.
It was unclear to the inspectors during discussions with plant management whether plant management realized that a water hammer event had occurred with the potential for damaging piping and pipe supports.
Some initial confusion existed during early discussion regarding whether a water hammer or pump cavitation was the problem.
The licensee subsequently walked down the piping to inspect for damage and none was foun The problem was corrected by increasing the size of the overtravel stop on all three check valves.
The licensee appeared to be reluctant to determine the extent of the problem in the A 8 C trains of RHR until encouraged to do so by the NRC.
Inspection of the internals of V-31A and V-31C revealed that the problem was not as extensive with them as with V-31B.
However, their overtravel stops were built up with an additional spacer or with additional weld filler material as a precautionary measure.
During the repairs, several individuals were contaminated by a sudden increase in ai rborne activity, this was due to an apparent lack of control over airborne contamination while working on the opened up RHR system.
Whole body counts were administered to those involved and no ingestion of radioactive material was observed.
The licensee initiated a root cause assessment which concluded that certain work practices will need to be improved in future maintenance activities where airborne activity could be a problem.
This airborne contamination event will be followed up during the next NRC Radiation Protection inspection.
No violations or deviations were identified.
Verification of Containment Inte rit 61715 The inspector selected a representative sample of completed surveillances required by the Technical Specifications.
These surveillances dealt with various areas of the primary containment to ensure that the survei llances were performed, that they were performed properly, and that the procedures met the surveillance requirements.
Areas reviewed included personnel air lock operability, main steam leakage control operability, containment atmosphere control system operability, suppression pool operability, and the traversing incore probe (TIP) isolation system operability, among others.
No violations or deviations were identified.
Plant Startu
- From Forced Outa e
71707 On September 5, the inspector witnessed plant startup after an ll day forced outage for repairing various components.
The approach to criticality was conducted in a cautious and careful manner.
The inspector observed that the Control Room Supervisor was actively involved in the startup, was aware of the actions of the various operators, and frequently provided direction as required.
The STA/reactor engineer was observed to continually monitor the startup and provide guidance as requested.
Problems were experienced while withdrawing control rods but were handled using the applicable abnormal operating procedures.
One such problem involved a stuck control rod in the fully inserted position.
Numerous attempts to withdraw the control rod per PPM 4. l. 1.4, "Stuck Control Rod in the Fully Inserted Position",
by increasing CRD drive header pressure were unsuccessful.
Venting of the control rod hydraulic lines was undertaken per PPM 2. 1. 1.
Since this procedure required all other
control rods to be fully inserted, the insp'ector questioned the CRS regarding plans to conduct venting while other control rods were not fully inserted.
A procedure deviation was subsequently prepared and the control rod was successfully vented and withdrawn.
No violations or deviations were identified.
Core Power Distribution Limits 61702 Data from Traversing Incore Probe (TIP) data acquisition records and individual LPRM gain adjustment factors (GAFs) (calculated by the process computer using the Power plex code)
were reviewed by the inspector.
The actual implementation of the GAFs for the individual LPRMs per PPM 7.4.3. 1. 1.70 was also reviewed.
No violations or deviations were identified.
Li uid Nitro en Thermal Shock on Reactor Containment Pur e Line (93702)
On September 9, during the inerting of the reactor containment system, liquid nitrogen was introduced into the piping of the containment purge supply line.
The sudden drop in temperature caused thermally induced stress that resulted in a crack in the purge supply line around its welded connection to the nitrogen supply line.
Normally, liquid nitrogen is warmed by steam from the auxiliary steam system before it is introduced into the containment.
The system is designed such that the steam to the heat exchanger is regulated to maintain the nitrogen temperature at approximately 100-120~F.
Pressure of the nitrogen is automatically controlled at 30 psig.
During this event, because of mechanical problems with both the temperature and pressure controllers, the operator was using manual controls.
The drywell was inerted to less that the Technical Specification limits before the liquid nitrogen storage tank reach its low limits.
Additional nitrogen was ordered so that the containment oxygen levels could be lowered to the normal 1-2X (the Technical Specification require less than 3.5X).
While filling the nitrogen tank from the delivery truck, after the tank level had been increased, the operator was directed to start inerting again.
After the operator had established nitrogen flow, he noted that the nitrogen tank pressure was less than the required 190 psig.
The operator went over to the truck driver to ascertain what the driver was doing to lower the tank pressure and determined that the driver had reduced the tank pressure to decrease the time to unload his truck.
After a few minutes, the operator had the driver increase the nitrogen tank pressure.
The operator stated that he then proceeded back to his control station and shortly thereafter noticed that a relief valve on the reducing station was lifting because nitrogen to the reactor building had been isolated.
About the time the operator was having the driver increase pressure, a fire watch in the reactor building heard a loud banging noise and upon investigating observed nitrogen emanating from the purge line.
The watch called the control room and the control room
i operator isolated the nitrogen supply line.
Frost was observed on the nitrogen supply line and on the bottom of the 30 inch purge line up to the open containment purge isolation valves.
Reactor power was reduced to about 5X while the containment was deinerted and an entry was made to inspect the containment side of the purge line down stream of the purge isolation valve.
Engineering made an analysis of the worst case conditions and determined that several welds needed to be inspected.
Technicians inspected all welds inside the containment purge line and all welds between the nitrogen line and containment using the magnetic particle method, with no additional damage observed.
The licensee conducted a 'root cause assessment of the event and determined that the cause was shared between operator error and procedural and equipment failures.
The controllers were known by.the operator and his supervisor to be inoperable, but had not been raised to the shift manager level.
This limited the ability to have them repaired, and prevented any additional manpower from being assigned to the nitrogen control station.
Once maintenance was involved (after the injection of liquid nitrogen into the purge piping)', they determined that a fuse was blown in the control circuit to the low temperature cutout on the pressure controller and that the pressure controller had a defective valve diaphragm.
The steam valve controlling 'nitrogen temperature was overhauled and readjusted satisfactorily.
Procedures existed to fill the nitrogen tank and to operate the inerting station, but no prohibitions existed to prevent them from occurring simultaneously.
The licensee repaired the cracked purge piping and corrected the hardware problems in the nitrogen system after the drywell was inerted (following the purge line inspection).
A procedure deviation was issued for the nitrogen procedure to require two operators'to be at the nitrogen station when the controllers are operated in the bypass mode.
This was successfully accomplished on September 12, when the containment was inerted to the normal 1-2 X range following plant restart.
A formal root cause assessment was being prepared on this event but was not completed by the end of the reporting period.
Once this report is completed it will be reviewed during the routine inspection program.
No violations or deviations were identified.
15.
Control Room Emer enc Ventilation 93702 On September 2,
1988, engineers from Generation Engineering discovered that the control room heating, ventilation, and air conditioning (HVAC)
system was susceptible to a single failure for which MNP-2 was not analyzed.
The reactor was shutdown at the time and remained shutdown until the problem was resolved on September 5.
The control room HVAC system is arranged with one normal air intake and two remote air intakes that function during accident conditions.
Each remote air intake line has two radiation monitors and two electro-hydraulic valves in series which are normally closed and powered from different vital buses.
The normal air intake has two isolation valves which are normally open, but which close on an F, A, or 2 signal (high drywell pressure, low RPV level
or high radiation, any of which could be indicative of a LOCA in progress).
An FAZ signal also causes the isolation valves in both remote air intakes to open, the emergency supply fans to start, and the control room exhaust fan to trip, and places the control room HVAC in the pressurization mode, providing filtered air through filtration units.
When the radiation monitors in one remote intake line sense high radiation (after initial opening of the valves on an FAZ signal), they provide an alarm function and cause the isolation valves in that line to close, but the control room remains in the pressurization mode through the other remote air intake.
The licensee determined that during a design basis accident condition, with an offsite release, a single failure could occur such that an isolation valve in an operating remote intake'line would fail to open and a high radiation alarm/trip function could occur on.the other operating intake closing the only operating air supply valves.
Thus, the control room would be in the recirculation mode.
The control room HVAC has been analyzed for the pressurization mode of operation during post-accident conditions and found to provide acceptable radiation exposures to the control room operators due to the small amount of assumed air in-leakage which would potentially bypass the filtration units.
However, the recirculation mode during accident conditions could allow a greater amount of in-leakage of unfiltered air to the control room, since it would not keep the control room in a positive pressure condition.
The potential radiation dose to the control room operators had not been analyzed for this case.
The licensee concluded that the way to prevent a single failure from occurring was to remove the electrohydraulic operators fr'om the four remote air intake isolation valves and install manual operators.
This would prevent electrical short circuits ("smart shorts")
from causing the valves to close or fail to open, thus preventing a single failure during accident conditions.
In the event of a LOCA, an operator would be dispatched to close the appropriate set of isolation valves for an alarming condition on the radiation monitors for a given remote air intake.
Procedures were revised to reflect this modification and a dry run was conducted to ensure that this could be accomplished in a timely manner.
The licensee recognized that this modification was impacted by the Technical Specifications.
Since the automatic trip function of the radiation monitors on the remote air intakes had been rendered inoperable -- i.e. the isolation valves would no longer close on high radiation -- the radiation monitors were themselves inoperable and the action statement must be complied with.
This involved placing control room HVAC in the pressurization mode through one remote air intake and maintaining it in that mode, which was accomplished on September 5.
The plant restarted on September 5.
The licensee was preparing a Technical Specification amendment to allow securing from the pressurization mode during normal plant operatio '
This had not been by submitted to the NRC by the end of the inspection period.
No violations or deviations were identified.
16.
Plant Modification (37702 The inspector reviewed a plant modification on the transient incore probe (TIP) piping system which was performed during the previous annual outages.
Plant modification DCP 85-460 was performed to add automatic isolation valves to.the TIP purge lines.
The original design had a
single check valve located outside containment.
The modification added an ASME check valve inside containment and an ASME solenoid valve outside containment that would shut on an isolation signal.
The original modification package specified ASME III-2 valves and quality class g I Code B piping.
When the modification was finally installed under Revision OF, the class boundaries had been changed on the system to require the piping to be ASME III-2 valves and class g II Code D piping.
These changes were reviewed and approved by the plant operations committee.
The change in the class and code of the piping was not consider ed to be a reduction in the ability of the system to perform its intended function and is not considered a reduction in the safety of the pl ant.
No violations of NRC requirements or deviations were identified.
P 17.
Licensee Event Re ort LER Fol 1owu 90712 92700 The following LERs associated with operating events were reviewed by the inspectors.
Based on the information provided in the report it was concluded that reporting requirements had been met, root causes h'ad been identified, and corrective actions were appropriate.
The below LERs are considered closed.
LER NUMBER DESCRIPTION LER 87-29 Technical Specification Fire Rated Penetration Impaired During Modification LER 88-21 Nuclear Steam Supply Shutoff System (NSSSS)
Group
Isolation Due to Personnel Error No violations or deviations were identified.
'18.
Review of Periodic and S ecial Re orts (90713 Periodic and sp'ecial reports submitted by the licensee pursuant to Technical Specifications 6.9. 1 and 6.9.2 were reviewed by the inspector.
This review included the following considerations:
the report contained the information required to be reported by NRC requirements; test results and/or supporting information were. consistent with design predictions and
performance specifications; and the reported information appeared valid.
Within the scope of the above, the following reports were reviewed by the inspector s.
o Monthly Operating Report for August, 1988.
No violations or deviations were identified.
19.
Exit Meetin 30703 The inspectors met with licensee management representatives periodically during the report period to discuss inspection status.
An exit meeting was conducted with the indicated personnel (paragraph 1) on September 30, 1988.
The scope of the inspection and the inspectors'indings, as noted in this report, were discussed and acknowledged by licensee representatives.
.Licensee representatives did not identify as proprietary any of the information reviewed or discussed during the inspectio '