IR 05000387/1989021
| ML17156B333 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 08/28/1989 |
| From: | Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17156B332 | List: |
| References | |
| 50-387-89-21, 50-388-89-19, NUDOCS 8909080180 | |
| Download: ML17156B333 (18) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
Docket Nos.
50-387/89-'21; 50-388/89"19 50-387; 50-388 License Nos.
- Licensee:
Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Facility Name:
Susquehanna Steam Electric Station Inspection At: Salem Township, Pennsylvania Inspection Conducted:
June 25, 1989 July 29,,
1989 Inspectors:
G.
S. Barber, Senior Resident Inspector, SSES J
~
R. Stair, Resident Inspector, SSES Approved By:
P. Sweiland, Chief Reactor Projects Section No.
2A, Division of Reactor Projects FiPF Ff ate'nspection Summary:
Areas Inspected:
Routine inspections were conducted in the following areas:
plant operations, physical security, plant events, surveillance, and maintenance.
Results:
During this period, Operations Department personnel generally conducted activities in a professional manner and operated the plant safely.
Routine review of maintenance and surveillance activities noted good control and performance.
Two recirculation pump trips occurred on Unit 2.
The first trip was due to a worker bumping a high drive motor temperature switch.
His admission of his error was viewed as an indication of positive safety culture.'he second trip was due to a bad winding in the transformer that supplies the motor generator voltage regulator exciter.
Two trips have been caused by this transformer in the pas I
Two partial RPS actuations occurred on Unit 1.
The first occurred due to the premature tripping of an RPS breaker and the second occurred due to a ground fault on the same breaker.
The licensee believes that both events may be related.
A security allegation regarding degraded access controls was substantiated.
However, it was found to be of low safety significance since the licensee. took prompt and effective corrective action.
A required log entry was.missed.
Non-conformance reports documented the non-performance of required visual inspections on the turbine exhaust rupture discs.
The method used to specify the post work testing was ineffective.
One item was closed regarding corrective action for findings generated from a licensee report on the loss of spent fuel water.
An unresolved item was opened to document three additional concerns identified by the inspector.
Licensee Event Reports ( LERs) were found to provide clear and accurate descriptions of the events and corrective actions take TABLE OF CONTENTS 1.0 Introduction and Overview 1. 1 NRC, Staff Activities (30703, 71707, 90712, and 92701)
1.2 Unit 1 Summary 1.3 Unit 2 Summary 1.4 Persons Contacted 2.0 Routine Periodic Inspections
.
2. 1 Scope of Review 2.2
"B" Recirculation Pump Trip Unit 2 (93702)
2.3
"B" RPS Bus Breaker Trip Unit 1 (93702)
2.4
"B" RPS Bus Ground Fault - Unit 1 (93702)
2.5
"A" Recirculation Pump Trip -. Unit 2 (93702)
3.0 Surveillance and Maintenance Activities 3. 1 Surveillance Observations (61726)
3.2 Maintenance Observations (62703)
4.0 Licensee Reports 4.1 In-office Review of Licensee Event Reports (90712)
4.2 Significant Operating Occurrence Reports (92700)
5.0 Followup on Previous Inspection Items 5.1 (Closed) IFI.50-387/85-26-01, NSAG Evaluation of Loss of Water from Spent Fuel Pool Events 6.0 Security Allegation Regarding Degraded Vital Area
.
Access Control (81700)
7.0 RCIC and HPCI Rupture Disc NCRs (71707)
8.0 Zone 3 Railroad Access Bay Supply Damper
.
Misl abel ing (71707)
9.0 Resident Monthly Exit Meeting (30703).
Page
10
13
15
DETAILS 1.0 Introduction and Overview 1. 1 NRC Staff Activities The purpose of this inspection was to, assess licensee activities at the Susquehanna Steam Electric Station (SSES) as'hey related to reactor safety and worker radiation protection.
Within each area, the inspectors documented the specific purpose of the area under review, the scope of inspection activities, and the inspection findings, along with appropriate conclusions.
This assessment is based on actual observation of licensee activ'ities, interviews.with licensee personnel, measurement of radiation levels, independent calculations and/or selective review of applicable documents.
I~li
Unit 1 operated at or near full power throughout the inspection period.
'Scheduled power reductions w'ere conducted during the period for control rod pattern adjustments, surveillance testing, and scheduled maintenance.
Two reactor protection system breaker trips occurred during the period resulting in half scram logic actuations, and engineered safety features systemsactuations (see Sections 2.3 and 2.4).
Unit 2 operated at or near full power throughout most of the inspection period with two exceptions:
On June 30, power was reduced to 60 percent in order to allow access to the condenser bay to repair area fans.
Full power was restored on July 1.
On July 22, a trip of the "A" recirculation pump motor-generator set caused a runback to 55 percent power due to the corresponding decrease in core flow.
Repairs were made and the unit returned to full power on July 24 (see Section 2.5).
Additionally, scheduled power reductions were conducted during the period for control rod pattern adjustments, surveillance testing, and scheduled maintenanc.0 Routine Periodic Ins ections (71707, 93702)
2.1 ~R The NRC resident inspectors periodically inspected the facility to deter-mine the licensee's compliance with the general operating requirements of the Technical Specifications (TSs) in the following areas:
review of selected plant parameters for abnormal trends; plant status from a maintenance/modification viewpoint, including plant housekeeping and fire protection measures; control of ongoing and special evolutions, including control room personnel awareness of these evolutions; control of documents, including logkeeping practices; implementation of radiological controls; implementation of the security plan, including access control, boundary integrity, and badging practices; control room operations during regular and backshi,t hours, including frequent observation of activities in progress, and periodic reviews of selected sections of the unit supervisor's log, the control room operator's log and other control room daily logs; followup items on activities that could affect plant safety or impact plant operations; areas outside the control room; and, selected licensee planning meetings.
The inspectors conducted backshift and weekend/holiday inspections on July 4 and 21, 1989.
The inspectors reviewed the following specific items in more detail.
2.2
"B" Recirculation Pum Tri
- Unit 2 The licensee identified that the Unit 2 "B" Recirculation (Recirc)
Pump tripped at 10: 13 a.m.,
June
(SOOR 2-89-078).
Plant Control Operators (PCOs) received
"Recirc MG B Drive Motor Breaker Trip" and "Recirc MG Gen B Lockout Trip" Alarms and confirmed that "B" Recirc Pump had tripped.
PCOs followed the off-normal procedure (ON-162-002)
and also verified that the Single Loop Power to Flow Map showed that the plant did not enter Region 1 or 2.
Thus, no scram or change in recirc flow or rod position was required to prevent power osci llation :
2.3 The root cause of the event was personnel error.
The on-shift Assistant Unit Supervisor was in the area and a Catalytic worker notified him that he had bumped an instrument with the scaffolding he was erecting and heard the machine slow down.
When the high drive motor temperature switch was bumped the drive motor breaker tripped and 25 seconds later the field breaker tripped thereby, tripping the pump itself.
One anomalous condition was noted by the licensee during the transient.
The recorder indication for total core flow oscillated repeatedly between approximately 10 percent and 40 percent flow after the recirc pump tripped.
The inspector noted the flow oscillation while he was in the control room but, also noted that there were no supporting indications for the flow oscillation.
No core instabilities were noted since local and global reactor power, level and pressure remained constant.
The inspector reviewed the event and noted that the honest and open reporting by the individual involved saved the licensee a great deal of investigation time.
The licensee should continue to encourage these actions.
No inadequacies were noted.
"B" RPS Bus Breaker Tri
- Unit
The licensee identified that the "B" Reactor Protection System (RPS)
breaker 8B tripped open at 8:04 a.m., July 2.
The trip caused a half scram logic actuation, primary containment isolations (Division 1 5 2), Standby Gas Treatment System (SBGT) initiation and Control Room Emergency Outside Air Supply System (CREOASS) initiation.
Systems responded as designed except for the Containment Gas Analyzer "A" outboard sample isolation valves (15742A & 15752A) which should have closed, but indicated intermediate position with both amber and red indication lights orat.
The inspector confirmed that the valves were actually closed and that the position indication was faulty.
Significant Operating Occurrence Report (SOOR) 1-89-247 documented the event, but did not provide any assessment as to the cause of intermediate position indication.
The licensee should ensure that future SOORs provide assessments of anomalous conditions.
In addition to the first half scram actuation, two subsequent half scrams were received at 8:27 a.m.
and 9:33 a.m.
on July 2 during troubleshooting.
Both were received after resetting the half scram and the nuclear 'steam supply shutoff system (N4S) isolations during the restoration phase.
Breaker 8B was tested and found to be tripping under a normal load of 65 amps even though the rating was 100 amps.
A new breaker was bench tested and installed.
No further half. scrams or N4S isolations were received.
The licensee reported this event under lOCFR50.72 (b))2)(ii) within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and is planning to followup with a Licensee Event Report.
The inspector had no further questions
'on this issu. 4
- "B" RPS Bus Ground Fault - Unit
The licensee identified,that the "B" RPS Bus Electrical Protection Assembly (EPA) breakers tripped at 10:05 a.m., July 5.
This caused a "B" RPS half scram, reactor water cleanup (RWCU) isolation, recirc pump cooling water isolation, Ventilation Zones
8 3 trip, auto start of SGTS and CREOASS, and isolation of various sample valves.
The licensee confirmed that the required isolations occurred using procedure ON-159-002 and the Safety Parameters Display System (SPDS).
During post event troubleshooting, other breaker trips occurred which caused additional half scrams and N4S isolations.
All of the half scrams and isolations were reset.
The cause of the breaker trips was traced to a defective insulator connected to the back of RPS Breaker 8B.
The root cause of this event was equipment fai lure.
The electrical insulator was cracked, deteriorated and discolored at a small section on the end adjacent to the breaker mounting plate.
This defect provided a
path to ground from the bus bar to the breaker mounting plate.
Electricians reve'rsed the insulator and reinstalled it with the i'ntact end toward the breaker mounting plate.
The licensee originally believed this item to be unavailable in the warehouse as an individual spa "e part or as a separate part of a breaker assembly.
This forced tne licensee to use the original part in the reversed confi'guration.
After repairs were affected, the plant resumed normal full power operation.
The licensee later determined that ten insulators-were available in the warehouse.
Preliminary licensee investigation concluded that this event was similar to the loss of "B" RPS bus on July 2.
The licensee's final evaluation will be provided in their LER.
NRC will review the gener ic aspects of the events and the disposition of the defective insulator in a subsequent inspection.
2.5 The licensee determined that this event was reportable per 10CFR50.72 (b)(2)(ii) and made the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> notification on the ENS line.
No inadequacies were noted.
"A" Recirculation Pum Tri
- Unit 2 On July 22, at 5: 18 p.m., the "A" reactor recirculation pump motor generator (NG) set field breaker tripped resulting in a trip of the drive motor breaker.
Reactor power decreased to approximately 55 percent power cor-responding to the core flow decrease during the first 6 seconds of the transient and stabilized at approximately 60 percent within the next two minutes.
Region" II of the power-to-flow curve was not entered and no evidence of core instability was observed throughout the transien ON-264-002 "Loss of Reactor Recirculation" was implemented and operators inserted the predesignated control rod array placing the reactor control rod distribution to just below the 80 percent rod line.
The insertion of the rods decreased reactor power to approximately 51 percent where it was maintained until troubleshooting and repair s were completed to allow restart of the MG set and recirculation pump.
During the transient, the feedwater system responded properly and adjusted feedwater flow to correspond to the changing power levels.
Maximum reactor vessel level recorded was 42 inches with a normal level of 35 inches being restored within 90 seconds.
The operators noted that the Voltage Regulator Power Supply Transformer
,Line Fuse was blown.
This is a 4. 1 KV tell-tale fuse which taps into the A 5 B phases of the MG set generator output.'hen this fuse blew, the power supply to the exciter field voltage regulator was interrupted resulting in an exciter field under-voltage which tripped the generator field breaker.
The licensee's investigation determined the cause of the blown fuse to be a failure of the voltage regulator power supply trans-former 2T due to a primary winding short.
The fuses and transformer were replaced, and the MG set restarted.
Full power w'~s restored at 6:30 a.m.
on July 24, 1989.
3.0 Since two previous recirculation pump trips have occurred as a result of failure of the 2T transformer, June 11, 1987 and October 4, 1986, the licensee is evaluating the possibility of replacing the transformer with a different brand with a better operating t istory.
The inspector discussed the event with the licensee and reviewed the Significant Operating Occurrence Report (SOOR)
on the event.
The inspector was satisfied that plant response was normal and that the licensee actions were appropriate and timely.
Surveillance and Maintenance Activities (61726, 62703)
On a sampling basis, the inspector observed and/or reviewed selected surveillance and maintenance activities to ensure that specific programmatic elements described below were being met.
Details of this review are documented in the following sections.
3.1 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine that the following criteria, if applicable to the specific test, were met:
the test conformed to Technical Specification requirements; administrative approvals and tagouts were obtained before initiating the surveillance; testing was accomplished by qualified personnel in accordance
with an approved procedure; test instrumentation was calibrated; limiting conditions for operations were met; test data was accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
)
These observations and/or reviews included:
S0-153-004, quarterly Standby Liquid Control Flow Verification, performed on July 17, 1989.
S0-255-001, Weekly Control Rod Scram Accumulator Surveillance, performed on July 28, 1989.
SR-200-001; Determination of Core Thermal Limits, performed on July 27, 1989.
SR-278-001, Daily verification of APRN Scram and Rod Block Settings, performed on July 27, 1989.
No unacceptable conditions were identified.
3.2 Naintenance Observations The inspector observed and/or reviewed selected maintenance activities to determine that the work was co nducted in'accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes or standards.
The following items were considered, as applicable, during this review:
Limiting Conditions for Operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and quality control hold points were established where appro-priate; functional testing was performed prior to declaring the involved component(s)
operable; activities were accomplished by qualified personnel; radiological'controls were implemented; fire protection controls wer'e implemented; and the equipment was verified to be properly returned to service.
These observations and/or reviews included:
Standby Liquid Control Accumulator Pressure Check per NT-053-003, performed on July 17, 1989.
Excavation of Penetration X-43-2-2007 to "D" Diesel Generator Bay per CWO C 90408, performed on July 17, 1989 '
i Installation of Plant modification 88-3016I on C Diesel Generator, per Construction Work order C 90512, on July 18, 1989.
No inadequacies were noted.
4.0 Licensee Re orts (90712, 92700)
4. 1 In-office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the NRC office to verify that details of the event were clearly reported, including the accuracy of description of the cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite-followup. The following LERs were reviewed:
Unit
89-004-00, Chemistry Analysis not performed prior to Purging the Orywell 89-017-00, HP Survey Hissed 89-018-00, Controlled Substance discovered in Protected Area No inadequacies were noted.
4.2 Si nificant 0 eratin Dccurrenc~e Re orts Significant Operating Occurrence Reports (SOORs)
are provided for problem identification, tracking, short and long term corrective actions, and reportability evaluations.
The licensee uses'SOORs to document and bring to closure problems identified that are both major or minor in nature.
The inspectors reviewed the following SOORs during the period:
1-89-256, dated July 16, 1-89-257 dated July 18, 1-89-260, dated July 14, 1-89-265 dated July 28, 1-89-267 dated July 18, 2-89-084 dated July 13, 2-89-085 dated July 18 and 2-89-086, dated July 22.
The following SOORs required-inspector followup:
2-89-086, documented the trip of the "A" recirculation pump moto'r generator set and corresponding runback of the unit.
See Section 2.5 for details.
5.0 Followu on Previous Ins ection Items (92701)
e The inspector reviewed licensee action, if applicable, on previous inspection findings to ensure that the licensee took appropriate action in response to the findings or by self initiative, and that the licensee's action was adequate and timel.1 (Closed) IFI 50-387/85-26-01, Nuclear Safety Assessment Group (NSAG)
Evaluation of Loss of Mater from Spent Fuel Pool Events An item was opened to follow licensee actions to, address a loss of spent fuel inventory due to the unexpected opening of leakage paths.
The inspector reviewed the licensee's response to IE Bulletin (IEB) No. 84-03,
"Refueling Cavity Mater Seal," which was issued on August 24, 1984 to notify licensees of an accident in which the refueling cavity water seal failed and rapidly drained the refueling cavity, and to request certain actions to assure that fuel uncovery during refueling remains an unlikely event.
In the licensee's response to the IEB, they concluded that due to the redundant design of Susquehanna's seals and the keeper/wedge design to hold the seals, leakage from the reactor well water seals was a very low probability event, if the seals were maintained properly.
Rapid drainage of the reactor well due to gross failure was not considered credible, since multiple failures were required.
The licensee did not evaluate the potential consequence..
of a refueling cavity water
".eal failure since rapid drainage was not considered credible.
They also did not discuss evaluation of the potential effect on stored fuel and fuel in transfer and the emergency operating procedures'he licensee's NSAG organization performed an audit of the bulletin response and determined it was inadequate.
The inspector agreed.
The inspector reviewed the NSAG report and~noted that the corrective action recommen-dations were thorough and comprehensive.
The licensee's review of this item would be considered complete by the inspector when all 28 items of the NSAG report were addressed.
The inspector reviewed the 28 open items documented in NSAG report 84-13 dated December 18, 1984.
These items included preventative maintenance, inservice inspection, leakage detection/monitoring system improvements, training and other enhancements that were provided to improve the licensee's capability to prevent or mitigate a loss of spent fuel water level.
The inspector reviewed each open item with a member of the licensee's NSAG group and provided the following comments.
1.
Item 841304, Train personnel on loss of SFP level, was closed based on a verbal commitment from the training department that training would be provided to operators in the future.
The reasonable assurance standard was not met.
The licensee could not determine the scope of the training, the number of operators either attending or missing the training or whether the training was adequate at the time the item was closed out.
The inspector conveyed to the licensee the importance of having reasonable assurance that the desired acti'on was completed prior to closing the open ite.
Item 841310 Add SFP Instrumentation, proposed adding additional instrumentation to improve monitoring capability for level, temperature and radiation.
Upon further review, the licensee concluded that adequate instrumentation exists.
The inspector reviewed the availability of accessible instrumentation on 818'levation of the reactor building.
The inspector noted that on a loss of Unit 1 SFP level the direct radiation shine would not allow monitoring at the local panels adjacent to the SFP.
The licensee should evaluate the instrumentation needed for this event and ensure remote monitoring capability exists for a loss of SFP level event.
3.
Item 841314, Replace reactor (RN) cavity seals, proposed changeout of the Presray cavity seals based on their five year service life.
The licensee believes that the seals need not be replaced on this interval but on some other interval.
The vendor, -Presray, did not agree with the conclusion but agreed to visit the site to inspect the seals the next time one failed in service.
The current seals are between 9 and 10 years old for Unit 1 and less for Unit 2.
NSAG agreed to close this item based on the fact that long term resolution would be provided by NCR 88-0085 and Engineering Work Request (EMR) M80270.
The inspector questione~'the continued use of the seals beyond Presray's recommen-dation unless sound technical justification to the contrary exists.
This justification should assess the specific effects of the environment on the service life, along with inherent material deterioration due to environmental effects.
Since the majority of the actions specified in the NSAG report were completed to the inspector's satisfaction, the original item and Temporary Instruction 2515/66 will be closed.
However, further action is needed.
The adequacy of the service life of the seals needs to be resolved before the next refueling.
Future resolution of the preceding three open issues related to cavity seal failures wi 11 be tracked as one item.
These issues are considered unresolved pending further licensee action and NRC review.
(387/89-21-01 (Common) ).
6.0 Securit Alle ation Re ardin De raded Vital Area Access Control (81700)
On Sunday, November 20, at 4:23 a.m.,
access controls for vital area bar riers were placed in a degraded condition.
These, controls were sub-sequently restored to a normal status in 4 minutes.
The event was caused by a personnel error when a controller in the Security Control Center (SCC)
was demonstrating Security Data Management System (SDMS) access controls features to a trainee.
The controller meant to process commands up to the last command to access certain doors but inadvertently executed the last command.
The controller recognized the error and began restoring the doors to a normal condition on an individual basis.
The Security Shift Supervisor (SSS)
recognized the problem in the Alternate Security Control Center (ASCC) and directed the ASCC controller to restore all of the affected doors to a normal status with one command.
The command was successful and compensating measures were put in place within the required time interva An alleger contended that the event occurred without the establishment of timely compensatory measures. 'n addition, the alleger contended that the licensee failed to log the event and make a required one hour notification.
The inspector reviewed the circumstances surrounding the event and noted that it occurred because of a personnel error during a training evolution.
The event was compensated in a timely fashion and the licensee implemented eight specific long term corrective actions to prevent recurrence.
The inspector reviewed SY-SI-045, Reporting of Safeguard Events and concluded that a
one-hour report per 10CFR73.71 was unnecessary.
However, a security event log entry should have been made in accordance with Step 6.3. 18 of SY-SI-045.
Therefore, based on the above, with regard to the required log entry, this allegation was considered substantiated.
However, it was of low safety significance because it was properly compensated and it resulted from an unintentional error while manipulating SDMS for training purposes.
The licensee's corrective action was very prompt and comprehensive.
In accordance with 10 CFR 2 Appendix C, the inspector determined the missing log entry to be a non-cited violation (50-387/89-21-03).
The inspector has no further questions on this issue and considers it resolved.
7.0 RCIC and HPCI Ru ture Disc NCRs Non-conformance reports (NCRs) were issued for the Reactor Core Isolation Cooling (RCIC) and High Pressure Coolant Injection (HPCI) systems on June 30 and July 27, respectively.
The NCRs were issued after the HPCI work, when it was noted that a visual exam (VT-2) was not performed after replacing each turbine's exhaust rupture disc.
The replacements were performed as a
regular part of the preventive maintenance (PM) program.
The inspector reviewed the Work Authorizations (WAs) for both HPCI and RCIC and noted that they specified rupture disc replacement as a part of the preprinted output.
However, they did not specify that a VT-2 exam was required by administrative procedures.
For the RCIC WA, the VT-2 requirement had been added to the recommended operational testing section of the WA (P82688)
by hand on May 23.
The work was completed on Hay 30 but the VT-2 was not performed due to personnel error.
For the HPCI WA, no VT-2 testing was specified in the WA (P83160).
This test should have been specified in conjunction with the work plan but was not.
This occurred due'o an oversight of the requirements by main-tenance personnel who wrote the WA.
For RCIC, the Work Group (WG)
supervisor failed to notify QC about the required inspection.
However, there were other reviews that should have corrected this error in process.
The work group supervisor signed off the WA without adequate review since the VT-2 was specified and the inspection records for the performance of the VT-2 were not included.
In addition, three other reviews (WG, OPs, QA)
did not notice the lack of VT-2 documentation.
The inspector is concerned that the licensee's control of post-work testing was inadequate.
In both cases rupture disc replacement was a part of a pre-printed WA yet the VT-2 requirement must be added by the WA preparer and several reviewers failed
to verify required post-work testing.
This item is considered unresolved pending inspector review of licensee corrective action for these NCRs.
(UNR 50-387/89-21-02).
8.0 Zone
Railroad Access Ba Su
Dam er Mislabelin On July 26, the licensee identified that the supply damper (XD-175B) for the railroad access bay was mislabeled.
A Nuclear Plant Operator (NPO)
who was dispatched to close the damper thought he could hear flow through the damper with it in the closed position.
Contractor ventilation specialists in the immediate area were summoned to check damper dif-ferential pressure (DP)
~
The damper indicated 0.0 inches of water DP with it indicating closed and a small positive DP with it indicating opens Thus, confirming that the damper had been mislabeled.
The inspector was informed of the mislabeling of the supply damper and accompanied the plant superintendent, system engineer and day shift
'upervisor into the plant to evaluate the potential causes for the mislabeling.
The manufacturer normally cuts a groove (benchmark)
in the positioning spindle to mimic the damper's position inside the duct work.
The inspector observed the supply damper and noted that the benchmark appeared to have been cut in after the damper had been installed.
The edges were rough and the depth of cut was uneven.
A marker had been used to connect the two cuts to mimic the damper's position.
The position
. labels had been incorrectly installed and both indicated a partial open position.
There was no reasonable way to infer proper damper position based on this indication.
The mislabeling was corrected by the licensee.
The exhaust damper was observed to be properly labeled by manufacturer's bench mark.
The 1-icensee confirmed the exhaust damper position indication with flow measuring instrumentation.
The licensee is continuing to investigate the cause but believes it to be a modification 'error.
The inspector reviewed the event to determine its safety significanc'e.
The railroad access bay can be characterized as either zone 3 or no zone ventilation system.
It is considered zone 3 when both the supply and return dampers are open and no zone when they are closed.
Zone 3 also provides refueling floor ventilation.
The worst case postulated scenario for the mispositioning would occur when there was an extremely large release from the refueling floor with both zone 3 supply fans shutdown.
This is a very unlikely event since zone 3 must be kept running during operations and refueling.
The released activity would have to,diffuse down the supply duct and out to the railroad access bay through the mis-labeled damper., If the main door was open it could diffuse to the environment.
The most probable effect would be on the Standby Gas Treatment (SBGT) system draw down time.
The open damper would allow SBGT to see a
larger suction volume.
However, the inherent flow restriction of the duct work would minimize the effects of the volume increase.
The licensee is evaluating the effects of the increased volum "
The inspector assessed the safety significance of this event to be low since there have been no large releases from the refueling floor and since zone 3 out of service time is intentionally minimized.
The inspector has no further questions on thi s issue.
9.0 Resident Monthl Exit Meetin At the conclusion of the inspection period, the inspector discussed the findings of this inspection with station management.
Based on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain information subject to
CFR 2.790 restriction l
~