IR 05000387/1990008
| ML17157A203 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 06/12/1990 |
| From: | Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17157A201 | List: |
| References | |
| 50-387-90-08, 50-387-90-8, 50-388-90-08, 50-388-90-8, NUDOCS 9006200105 | |
| Download: ML17157A203 (31) | |
Text
Report Nos.
License Nos.
Licensee:
U. S.
NUCLEAR REGULATORY COMMISSION
REGION I
50-387/90-08; 50-388/90-08 NPF-14; NPF-22 Pennsylvania Power and Light Company 2 North Ninth Street Al 1 entown, Pennsyl vania 18101 Facility Name:
Inspection At:
Susquehanna Steam Electric Station Salem Township, Pennsylvania Inspection Conducted:
March 18, 1990 - April 28, 1990 Inspectors:
G.
S. Barber, Senior Resident Inspector, SSES J.
R. Stair, Resident Inspector, SSES Approved By:
. Swetland, C ief Reactor Projects Section No.
2A, Date Ins ection Summar
A~:
operations, radiological controls, maintenance/surveillance testing, emergency preparedness, security, engineering/technical support, safety assessment/quality verification, and Licensee Event Reports (LERs), Significant Operating Occurrence Reports (SOORs),
and Open Item Followup.
Results:
During this inspection period, the inspectors found that the licensee's activities were directed toward nuclear and radiation safety.
One violation was cited regarding ineffective corrective actions for previous licensee-identified failures to make timely event notifications.
(See Section 2.2').
In addition, three unresolved items (See Sections 7.2.2, 8. 1.3, and 8. 1.4) and one non-cited violation (See Section 7.2. 1) were identified during the period.
An Executive Summary is included and provides an overview of specific inspection finding I.
EXECUTIVE SUMMARY II.
DETAILS SUMMARY Susquehanna Inspection Reports 50-387/90-08; 50-388/90-08 March 18, 1990
-
April 28, 1990
~Oeratioea Operators effectively controlled plant evolutions and identified plant problems.
However, operators failed to recognize the closure'of a.Zone III isolation damper as an ESF actuation and as a result this was not identified until approximately one week later resulting in a late ENS notification.
Late reporting constitutes a violation of 10 CFR 50.72 requirements.
Radiolo ical Controls Individual workers and Health Physics personnel implemented radiological protection program requirements.
Periodic inspector observation noted no major inadequacies in the licensee's implementation of the radiological protection program.
Maintenance/Surveillance The licensee exercised good control of maintenance and surveillance activities.
No scrams or ESF actuations were attributable to maintenance or surveillance activities.
Emer enc Pre aredness No significant emergency preparedness (EP) issues emerged during the period.
~Securit Routine observation of protected area access and egress control showed good control by the licensee.
Compensatory measures were implemented for degraded barriers.
En ineerin /Technical Su ort During a routine log review, the inspector noted the use of temporary fans to
"augment the exi sting ventilation system for the Unit 2 main steam pipe tunnel (MSPT).
No
CFR 50.59 safety evaluation regarding the fans was conducted.
The failure to perform a safety evaluation was a non-cited violatio A Unit 1 MSPT fan miswiring was identified by the licensee during the period.
It was caused by an inadequate modification in 1987 which was intended to correct what was believed to be a wiring error.
This issue remains unresolved pending additional review by the licensee.
Safet Assessment/Assurance of ualit Licensee Event Reports exhibited indepth review of the event and root cause analysis.
Immediate corrective actions taken were appropriate and long term
'orrective actions to prevent recurrence appeared to be effective.
Significant Operating Occurrence Reports (SOORs)
appeared to adequately identify potentially significant items for tracking and resolution.
A total of 55 SOORs were reviewed during the period, three of which were followed up in this report.
Nonconformance Reports (NCRs) reviewed during the period indicate that increased management attention is needed to minimize the number of outstanding conditionally released NCRs.
Oue dates for conditionally released NCRs were frequently extended without additional justification.
The safety basis for NCR disposition will be further reviewed in subsequent inspections.
This item is unresolved.
An accident analysis/design deficiency involving operator response to EHC system failures was identified at the Peach Bottom and Limerick Nuclear Stations.
The Susquehanna analysis contains similar inadequacies.
Further licensee review of the event must be performed to assure that the current analysis is bounding.
This item remains unresolve DETAILS SUMMARY OF OPERATIONS Ins ection Activities The purpose of this inspection was to assess licensee activities at Susquehanna Steam Electric Station (SSES)
as it related to reactor safety and worker radiation protection.
Within each inspection area, the inspectors documented the specific purpose of the area under review and the scope of inspection activities and findings, along with appropriate conclusions.
This assessment is based on observation of licensee activities, interviews with licensee personnel, measurement of radiation levels, or independent calculation and selective review of applicable documents.
Sus uehanna Unit
Summar Unit 1 commenced the inspection period operating at full power.
On March 20, a reduction to 13 percent power was performed in order to repair a
degraded no load disconnect in the units 230 KV switchyard.
See Section 2.2. 1 for details.
The unit was returned to 60 percent power on March 21 and held there in order to identify and plug a main condenser tube leak.
Full power was restored on March 26 and was maintained throughout the remainder of the inspection period.
Scheduled power reductions were conducted during the period for control rod pattern adjustments, surveillance testing, and maintenance.
One Engineered Safety Feature (ESF)
actuation occurred on April 17 resulting in a Secondary Containment HVAC isolation of a Zone III damper.
See Section 2.2 '
for details.
No scrams occurred during. the period.
Sus uehanna Unit 2 Summar Unit 2 operated at or near full power for all of the inspection period.
Scheduled power reductions were conducted during the period for, control rod pattern adjustments, surveillance testing, and maintenance.
No ESF actuations or scrams occurred during the period.
OPERATIONS Ins ection Activities The inspectors verified that the facility was operated safely and in conformance with,regulatory requirements.
Pennsylvania Power and Light (PP8 L) Company management control was evaluated by direct observation of activities, tours of the facility, interviews and discussions with personnel, independent verification of safety system status and Limiting Conditions for Operation, and review of facility records.
These inspection activities were conducted in accordance with NRC inspection procedure 7170 The inspectors performed normal and back shift inspections including weekend and holiday inspections on March 24 from 8:00 a.m. to 1:00 p.m.,
and on April 13 from 7:00 a.m. to ll:00 a.m..
2. 2 Ins ection Findin s and Review of Events 2.2.1 Unit
Power Reduction Due to De raded 230kv Switch ard No Load Disconnect The licensee determined that a power reduction was needed to repair a degraded no load disconnect (NLD) in the 230kv switchyard.
The power reduction began at 5:26 p.m.,
March 20 and ended with the generator off line at 6:00 a.m.,
March 21.
Repairs were made to the NLD and the plant was returned to 100 percent power at 1:00 a.m.,
March 24.
The licensee determined that this problem resulted from a mechanical failure at the hinge pin on the NLD.
Discussions with the vendor resulted in the identification of a manufacturing defect with this type of disconnect.
The vendor informed P.P.5 L. that an information letter was forwarded to them concerning the defect, however, P.P.5 L. apparently never received the letter.
According to the letter, this type of NLD should be changed out every 5 years due to early degradation.
The licensee is presently evaluating the impact on remaining NLD's of this type until repairs are made or replacements can be installed.
As an interim measure increased predictive maintenance monitoring of the NLDs is being performed.
2.2.2 As a result of previous problems in the Susquehanna switchyards, P.P.& L. has formed a task force to review and recommend improvements in all aspects of the design, construction/operation and maintenance of the bulk power system which could impact Susquehanna availability.
The inspector had no further questions on this event.
Zone III Heatin Ventilation and Air Conditionin Isolation At 8:50 p.m.
on April 17, the licensee entered a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Limiting Condition for Operation (LCO) related to secondary containment integrity for both Susquehanna Units 1 and 2 when Zone III ventilation was lost.
Zone III contains the common refueling floor and thus affects secondary containment integrity of both units'ontrol room indication was lost on the Unit 1 Zone III exhaust fan supply damper HD-17502A.
A field verification showed that the damper had failed in the closed positions A normally-energized solenoid valve supplies air to the damper to keep it open.
A blown fuse ( FU-7) was.identified
in the circuit and replaced by Instrumentation
.and Control ( IKC)
technicians.
This restored indication to the damper position.
An attempt to reopen the damper resulted in another blown fuse and a
loss of indication.
Further investigation determined that the solenoid coil for the damper air supply had failed.
The failed solenoid coil was replaced, fuse ( FU-7) replaced, and the damper reopened in accordance with associated operating procedures.
During investigation and repair of the Zone III ventilation system, the "B" standby gas treatment system (SGTS)
was placed in service which allowed the LCO to be exited at 10:35 p.m.
Normal system alignment was reestablished at 2:20 a.m.
on April 18, and SGTS was removed from service.
However, HD 17502A failed closed again at 3:40 a.m.
and SGTS was reinitiated.
The entire solenoid valve for HD 17502A"was replaced.
HD-17502A was declared operable after successful completion of its surveillance, and the L.C,O.
was cleared at 4:50 a.m.
on April 18.
The licensee determined that the original failure was random and the replacement coil failure was due to a
defective replacement part.
On April 23, following review of the event, the licensee, determined that the isolation of Damper HD-17502A constituted an Engineered Safeguard Feature (ESF) actuation.
This ESF actuation was not identified by the operations staff at the time of the event.
Hence, there was no 4-hour Emergency Notification System (ENS)
call made per
CFR 50.72.
Following discussion with the resident inspectors, the licensee made the required ENS call at 2:07 p.m.
on April 23 which was approximately 5 days and 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> after the event.
This is not the first case of late identification and NRC notification of ESF actuations.
There were two previous events 'in the last 8 months in which the licensee failed to identify ESF actuations in a timely manner.
The first instance occurred at 9:00 a.m.
on August 9, 1989 during performance of a Unit 1 surveillance test, when an auto-swap of the High Pressure Coolant Injection suction valves was not identified as an ESF actuation by shift personnel.
During the subsequent reportability evaluation on August 10, i.t was determined that an ESF actuation had occurred and the appropriate
CFR 50.72 notification was made at 11. 17 a.m.,
approximately 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br /> after the event.
The second instance occurred in Unit 2 on September 10 when a Drywell Purge Air Supply Outboard Isolation Valve automatic closure was not identified as an ESF actuation by shift personnel until approximately 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> after the event which exceeded the
CFR 50.72 requirement by 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> The licensee "stated that they believe the reportability problem arises when a component changes to its fail safe position from causes such as a blown fuse or a component failure.
These actuations are not initially identified as ESF actuations when the ESF logic has not been involved, such as from an actual sensor reaching its trip set-point.
The licensee also stated that although they are classifying these events as ESF actuations, there are inconsistencies in the industry and not all utilities do so.
The BWR Owners Group is presently developing guidelines to establish consistency throughout the industry and to attempt to resolve what constitutes an ESF actuation.
The inspector, stated that the issue of whether or not a
blown fuse or component failure constitutes an ESF actuation should be resolved in order to form a consisteqt approach to the reporting of ESF actuations.
However, effective corrective action including appropriate guidance and training for operators should have prevented this occurrence.
CFR Part 50 Appendix B, Criterion XVI, Corrective Action and the guality Assurance Program require the cause of adverse conditions to be determined and corrective actions taken to preclude recurrence.
The licensee's corrective actions for the two previous events were ineffective in preventing a recurrence of the failure to identify and report an ESF actuation in a timely manner.
This constitutes an apparent violation of 10 CFR Part 50 Appendix B.
(NC4 50-387/90-08-01).
3.
RADIOLOGICAL CONTROLS 3.1 Ins ection Activities pp8L s compliance with the radiological protection program was verified on a periodic basis.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
3.2 Ins ection Findin s
Observations of radiological controls during maintenance activities and plant tours indicated that workers generally obeyed postings and Radiation Work Permit requirements.
This is evident in the low number of,person l
c ntamination occurrences for the period from January 1 through April 30,
, ersona 1990.
There were a total of 56 personal contamination reports (PCRs)
generated for the period, which was below the licensee's goal of 78.
The licensee has set a goal for 1990 of less than 300 PCRs which includes a
Unit 1 refueling outage in the fall.
Postings and general housekeeping in radiological areas were acceptable and conformed to program requirement.
MAINTENANCE/SURVEILLANCE 4. 1 Maintenance and Surveillance Ins ection Activit On a sampling basis, the inspector observed and/or reviewed selected surveillance and maintenance activities to ensure that the specific programmatic elements described below were being met.
Details of this review are documented in the following sections.
4.2 Maintenance Observations The inspector observed and/or reviewed selected maintenance activities to determine whether the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, arid 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 required; 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 were implemented; and the equipment was verified to be properly returnee to service.
These observations and/or reviews included:
Installation of guality Raceways in Support of Plant Modification 88-3068A for 1C142A Instrument Air Dryer Panel A in Unit 1 per Work Authorization (WA) C00090 on April 3.
Annual Preventive Maintenance and Replacement of Cracked Head on Containment Instrument Gas Compressor 1K205B per WA P01372 on April Preventive Maintenance on Core Spray Pump Motors 1P206A and 1P206C per WA P01203 and WA P01205 on April 11.
Disassembly of Flow Element (FE)
11158C to Core Spray Room Cooler lE 231C and Clearing Blockage from Sensing Line per WA 503145 on April 11.
Inspection and Refurbishment of Diesel Generator OG501A per WA S03807 and WA 94379, performed on April 20.
4. 3 Survei 1 lance Observati ons 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:
SI-278-209 Weekly Functional Test of Average Power Range Monitor (APRM) Channel C, performed on March 20.
TP-055-008 Test to withdraw Control Rod Drive Mechanism 50-15 with Local Control Instrument, performed on March 29 and on April 6.
SO-216-002 Residual Heat Removal (RHR) Service Water Pump 2P506A Flow Surveillance, performed on March 29.
SO-149-005 Quarterly RHR Loop A4 B Valve Exercising Step 6.1.13 (F047A Valve Stroke timing), performed on March 20
~
SO-249-002 Quarterly RHR System Flow Verification of RHR Pump 2P202A, performed on April 5.
SI-183-217 Monthly Functional Test of Main Steam Isolation Valve Leakage Control System FSL-E32-1V654 and FSL-E32-N659, performed on April 12.
4.4 Ins ection Findin s
condltlons were
>dents S.
EMERGENCY PREPAREDNESS The inspector reviewed the listed maintenance and surveillance activities.
The review noted that work was properly released before its commencement; that systems and components were properly tested before being returned to service and that surveillance and maintenance activities activities were conducted properly by qualified personnel.
Where questionable issues arose, the inspector verified that the licensee took the appropriate action before system/component operability was declared.
No unacceptable
'fied.
5. 1 Ins ection Activit The inspector reviewed PP8L's conformance with selected aspects of
CFR 50.47 regarding implementation of the emergency plan and procedure I-L t
r
5.2-Ins ection Findin s
6.
No significant emergency preparedness (EP) issues emerged during the period.
SECURITY 6.1 Ins ection Activit PP&L's implementation of the physical security program was verified on a
periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundaries.
These inspection activities were conducted in acco'rdance with NRC inspection procedure 71707.
6.2 Ins ection Findin s
The inspector reviewed access and egress controls throughout the period.
No unacceptable conditions were noted.
7.
ENGINEERING/TECHNICAL SUPPORT 7. 1 Ins ection Activit The i,nspector periodically reviewed engineering and technical support activities during this inspection period.
The on-site Technical (Tech)
section, along with Nuclear Plant Engineering (NPE) in Allentown, provided engineering resolution for problems during the inspection period.
The Tech section generally addressed the short term resolution of problems while NPE developed modifications and design changes, as appropriate, to provide long term problem solutions.
The inspector attempted to verify that problem resolutions were thorough and directed at preventing recurrences.
In addition, the inspector reviewed short term.actions to ensure that the licensee's actions provided reasonable assurance that safe operation could be maintained.
7.2 Ins ection Findin s
7.2. 1 Portable Fans in the Main Steam Pi e Tunnel The inspector questioned the licensee on the need for portable fans on the turbine building side of the main steam pipe tunnel.
The fans were added in May 1985 to supplement the existing ventilation system.
They ensure. positive air movement from the ventilation supply to the thermocouples used for main steam isolation valve (MSIV) closure.
Ther'e are four dual-element thermocouples (TE-10100 A-D) with readouts in the control room (CR).
The thermocouples are located in the Turbine Building (TB) Main Steam Pipe, Tunnel (MSPT) at the end of the tunnel near the condenser bay.
Their purpose is to monitor the TB main steamline area temperatures.
High temperature
8" in the tunnel could indicate a breach in a main steamline (MSL).
On high temperature,,the MSLs and MSL drains are isolated by design.
The TE's were located to provide the earliest practical detection of MSL breaks and are located or shielded so that they are sensitive to air temperature and not radiated heat from hot piping.
They activate a
CR alarm at 157 degrees F and close the MSIV's at 174 degrees F.
(The trip logic. is 1 out of 2 taken twice for the MSIV's and two out of two for each drain valve).
The system is designed to detect
gpm leaks.
The portable fans in the MSPT function to aid HVAC flow through the tunnel.
The licensee concluded that the fans were temporarily needed to move a stagnant air mass immediately around the TE's due to the structural steel situated around them.
Temperatures documented at that area without the fans in-service have ranged from 150 F degrees to 167 degrees F.
With the alarm setpoint of 157 degrees F, there was often a nuisance alarm annunciating in the Control Room without the temporary fans in service.
The function of the temporary fans was to increase the margin to the alarm setpoint and minimize the nuisance alarms.
However, the effect of the fans on the required trip function was not evaluated.
The inspector acknowledged the desire to prevent nuisance alarms and/
or inadvertant MSIV closure but questioned the licensee on why a
safety evaluation was not written for a change to the facility that augments or supplements the design.
The licensee had not recognized the need for a safety evaluation since the installation was expected, to be temporary in nature.
The licensee stated that had they known the fans would remain for an extended period of time, they would have written a safety evaluation.
The inspector stated that temporary modifications must be processed in accordance with 10 CFR 50.59.
The licensee quickly agreed to write a safety evaluation (NL-90-016) that reviewed and approved the temporary fan installation.
The Plant Operations Review Committee (PORC)
approved NL-90-016 on April 5.
The licensee has an increasing sensitivity to temporary changes to ensure that changes to the facility as described in the Final Safety Analysis Report (FSAR) are performed in accordance with 10 CFR'50 '9.
The licensee agreed to write and approve individual safety analyses for temporary changes that augment or supplement inadequacies in the original design.
The inspector will continue to review the licensee's program for installation of temporary equipment in the power plant and the need for safety evaluations for these installations.
This is a non-cited violation that meets the requirement of 10 CFR 2 Appendix C.
(NON 50-387/90-08-02)
Main Steam Pi e Tunnel Fan Miswirin - Unit
The licensee began an investigation on April 11 to determine why the
"A" Reactor Building (RB) fan ( lV201A) would not keep the Main Steam Pipe Tunnel (MSPT) cool while the "B" RB fan ( 1V201B) would.
During the investigation, the licensee discovered that with a given fan running the opposite fan's cooling coils were in service.
For example, if fan 1V201B was in service and 1V201A was shutdown, the
"A" fan cooling coil return valve (HV-11045B) would open and the "B" coil return valve (HV-11045A) would be closed (these valves are designed to open when their respective fan starts).
This problem could be avoided by running both fans.
The licensee believed that the "B" fan was able to maintain tunnel temperatures because of leak-by through the "B" coil return valve ( labeled HV-11045A).
The licensee also believed this condition has existed since April, 1987 when the control cable to valves HV-11045A&B were swapped due to a perceived wiring error.
(Reference SOOR 1-87-104).
As an interim corrective action, the licensee has positioned service water return bypass valves 110067 and 110070 open (yellow-tagged)
to e'stablish a constant cooling water supply to both sets of cooling coils (mitigates effects of a fan failure).
On April 11, the licensee verified that with each single fan in service and cooling water valved into both cooling coils, MSPT temperature could be maintained.
On April 9, 1987, SOOR 1-87-104 was written to document a problem identified while working on cooling coil return valve actuators.
They were replaced under. Work Authorization (WA) S51137.
During restoration from this work, it was erroneously identified that when fan. 1V201A was placed in service, the "B" coil return valve would open;.and when fan 1V201B was placed in servic'e, the "A" coil return valve would open.
The investigation that followed incorrectly concluded that the valves had been wired backwards when in fact the plant labeling and some plant drawings were in error.
The licensee reversed the control cables for the coil return valves without implementing the review and approval established for control of plant modifications.
The resulting discrepant condition existed until the current problem was discovered on April ll, 1990.
Engineering Change Order (ECO)
number 90-6060 was submitted to engineering to re-wire'ontrols to each service water outlet valve so that it works in conju'nction with its associated fan.'ll print errors and labeling problems will also be corrected.
This ECO will reconfigure the water system to conform to the fan designation as it exists today.
The estimated completion date for the ECO is August 31, 199 In addition, a Plant Funding Request (PFR)
has.been initiated to permanently change the design of the system.
The current system design isolates service water to the cooling coils when its respective fan is shutdown.
Since only one fan is designed to be in service, the out of service cooling coils contain stagnant service water which may allow accelerated sedimentation and tube corrosion.
This new design will require service water flow through the cooling coils at all times.
This modification will also be implemented on Unit 2.
The licensee concluded that the error made in April 1987 (i.e.,
swapping control cables without verification of exi sting system configuration)
was an isolated event.
To address the potential of similar reversed wiring/labeling on other plant systems, especially those systems with redundant components, the Operations department will survey each operator to determine what redundant plant systems/
components (i.e.,
pumps, fans, etc.) are being run together when one subsystem should be sufficient. This condition may be indicated by a difference between Unit 1 and Unit 2 or may exist on both units.
Discrepancies identified will be dispositioned accordingly.
The effectiveness of the corrective action and the similarity to previous events will r emain unresolved pending review by the NRC.
(UNR 50-387/90-08-03).
SAFETY ASSESSMENT/QUALITY VERIFICATION 8. 1 Licensee Event Reports ( LERs), Significant Operating Occurrence Reports (SOORs),
and Open Item (OI) Followup 8.1.1 Licensee Event Re orts The inspector reviewed LERs submitted to the NRC to verify that the details of the event were clearly reported, including the accuracy of description of the cause and the 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
89-024-01 Diesel Generator
"C" Crankcase Overpressurization.
This event was reviewed in NRC Inspection Reports 50-387/89-30; 50-388/89-27; 50-387/90-03; and 50-388/90-03.
Unit 2
- 90-003-00 Automatic Depressurization System Declared Inoperable When Containment Instrument Gas Header Pressure Dropped Below 135 psig Due to a Pressure Relief Valve Liftin Onsite Followu of Licensee Event Re orts For those LERs selected for onsite followup (denoted by asterisks in Detail 8. 1. 1), the inspector verified that the reporting requirements of 10 CFR 50.73 had been met, that appropriate corrective action had been taken, that the event was adequately reviewed by the licensee, and that continued operation of the facility was conducted in accordance with Technical Specification limits'he following findings relate to the LERs reviewed on site:
LER 50-388/90-003 Automatic De ressurization S stem Declared Ino erable When Containment Instrument Gas Header Pressure Dro ed Below. 135 si Due to a Pressure Relief Valve Liftin On February 28, 1990, Unit 2 was operating in Condition 1 at 100 percent power, with the Containment Instrument Gas (CIG) System
"A" compressor in service.
The "A" and "B" Automatic Depressurization System (ADS) header backup nitrogen (bottles 2T212A-M and 2T213A-M, respectively)
supplies were pressurized to greater than 2100 psig.
The "A" header supplies instrument gas to Hain Steam Safety Relief Valves (MSRV) PSV-241-F013G,J, and M, and the "B" header supplies MSRVs PSV-241-F013K,L, and N.
These six MSRVs perform the ADS function.
The "B" CIG compressor was out of service for modifications.
At approximately 11: 10 a.m.,
on the above date, the CIG System automatically transferred from the CIG compressors (normal source)
to the backup nitrogen supply bottles due to decreasing pressure on both headers.
The transfer from the compressor to the bottles is an automatic action which occurs when CIG header pressure drops below 147 psig.
Specifically, valves SY-22644 and SV-22643 on the "A" header, and valves SV-22649 and SV-22648 on the "B" header changed position aligning the bottles to their respective headers.
Following the transfer, pressure on the "A" header continued to drop below 135 psig, rendering MSRVs F013G,J, and M inoperable.
As such, the ADS was declared inoperable, and Technical Specification Limiting Condition of Operation (LCO) 3.5. 1 action d.2 was.entered.
The pressure on "B" header was being maintained at 160 psig by the backup nitrogen supply.
Technical and Maintenance personnel were notified and an immediate investigation was commenced.
Initial checks of the
"A" and "B" CIG compressor skids did not reveal any leaks.
The "A" compressor was running, 100 percent loaded, and maintaining receiver pressure at 110 psig.
Normal receiver pressure is 160 psig.
Pressure was still decreasing on the "A" header.
Operations personnel proceeded to isolate the "A" compressor from the "A" header.
When this was done compressor receiver pressure rose to 160 psig.
Further investigations found that pressure relief valve, PSV-22643, located on the "A" backup nitrogen supply header, was stuck open.
Maintenance
personnel manually re-seated the valve and header pressure returned to normal.
No other nitrogen supplied systems (i.e.,
Main Steam Isolation Valves or Vacuum Relief Valves) were affected since they are supplied by a separate 90 psig nitrogen header.
The CIG system was manually re-aligned to its "A" compressor.
At 11:51 a.m.,
LCO 3.5. 1 action d.2 was cleared, returning ADS to operable status.
At 2:40 p.m.,
an ENS notification was made in accordance with 10 CFR 50.72(b) (2) (iii).
The cause of this event was determined to be the mis-operation of PSV-22643.
The valve is a Lonegran Model No.
LCT-11 one inch pressure relief valve The cause of the PSV lifting is indeterminate, however the most probable cause is that the PSV or supply piping was jarred.
This conclusion is based on the valve being located in a high traffic area and the PSV's setpoint ( 180
+ 3 percent)
being relatively close to the system's operating pressure (155-165 psig).
Secondly, once the PSV lifted, the valve should have re-seated.
Investigations into
,the cause of this occurrence were not completed at the time of sub-mittal of this LER.
The PSV was not immediately removed and inspected due to the "B" CIG compressor being out of service for a drain trap modification.
Removing the PSV would require isolation of the nitrogen bottles to the "A" train leaving only a single supply (A-CIG compressor A; B-nitrogen supply) for each train.
The "B" CIG compressor was returned to service on April 23, 1990, and the PSV was removed, disassembled, inspected and bench tested.
The licensee was not able to determine a cause for the valve sticking open.
Corrective actions completed subsequent to the LER submittal included replacement of the stem, spring, disc, and guide, and resetting the setpoint to 182 lbs.
The plant valve team is evaluating replacement of these PSVs with those from a different manufacturer in order to increase system reliability.
The licensee plans to submit a supplement to the LER to provide findings of their inspection and corrective actions to prevent a recurrence.
The inspector determined that the licensee's response to the event was deficient, in that the licensee should have provided greater assurance that the PSV continued to function properly, prior to returning the system to operable status and clearing the TS LCO.
However, the subsequent review of the event appeared to be adequate.
NRC review of the LER and discussions with the licensee confirmed that the appropriate reporting requirements were met.
Si nificant 0 eratin Occurrence Re orts Significant Operating Occurrence Reports (SOORs)
are provided for problem identification and tracking, short and long term corrective actions, and reportability evaluations.
The licensee uses SOORs to document and bring to closure problems identified that may not warrant an LE The inspectors reviewed the following SOORs during-the period to ascertain whether:
additional followup inspection effort or other NRC response was warranted; corrective action discussed in the licensee's report appears appropriate; generic issues are assessed; and, prompt notification was made, if required:
Unit
37 SOORs inclusive of 1-90-073 through 1-90-110 Unit 2
SOORs inclusive of 2-90-045 through 2-90-062 The following SOORs required inspector followup:
1-90-080 documented a power reduction due to a problem with a gang operated disconnect in the 230kv switchyard.
See Section 2.2. 1 for details.
1-90-094 documented the miswiring of the main steam pipe tunnel fans and their associated coolers.
See Section 7.2.2 for detai l s.
1-90-099 documented an ESF actuation involving a secondary containment isolation damper closure.
See Section 2.2.2 for details.
8. 1.3 Nonconformance Re ort NCR (RI-89-A-0086)
An allegation was received concerning the licensee's use of conditional releases for NCRs, the adequacy of NCR dispositions and the timeliness of rework to close some NCRs.
The inspector reviewed selected NCRs to insure that the provisions of AD-gA-120, Nonconformance'Reports-Control and Processing were met.
The review focused on tPe timeliness of closure, the use of conditional releases and the operability determinations used to determine equipment acceptability/operability.
The following NCRs were reviewed:
87-0002, Digital Thermom'eter Degradation (Closed)
, 87-0021, 87-0336, Electrical Isolation of Class lE and NonlE Circuits (Open)
HPCI Lube Oil Instrumentation guality Designation (Open)
87-0882, Post work visual inspection not performed on Containment Isolation Valve (Closed)
88-0085, Reactor Cavi ty Seal Life (Cl o sed)
89-0659, Rubber boot found submerged in the Unit 2 Suppression Pool (Closed)
89-0660, Appendix R Instrument Power Cables (Open)
NCR 87-0002 (1/6/87) documented that a digital thermometer failed its Measuring and Test Equipment (M&TE) acceptance criteria and, as such, called into question the acceptability of calibrations it was used to complete.
It was dispositioned "use-as-is" and was accepted by Quality Control (QC)
on Ma'rch 3, 1987.
The inspector noted timely review and thorough closure of this NCR.
NCR 87-0021 (1/23/87) questioned the electrical isolation capability between the Advanced Control Room Class 1E circuits and Display Control System (DCS)
Non Class 1E circuits.
The NCR is dispositioned and open ( 12/27/89).
This NCR attempted to consider the possibility of a fault propagating from a Class 1E circuit to DCS and then to a different 1E circuit.
A group was formed to review the diesel generator ground fault event that generated this NCR.
Various Potential and Current Transformer (PT & CTs) faults were investigated.
SEA-EE-180, 181, 182, 183, 184, and 204 found certain faults to be plausible.
For these faults, a rework designation was imposed which would require modification of the existing design.
The licensee has proposed the installation of current transformer protectors and qualified isolators between certain portions of the DCS and Class 1E systems.
This is an open NRC Licensing issue.
NCR 87-0336 questioned the use of non-safety (non-Q) related instru-mentation for the Unit
HPCI system.
This NCR remains open.
This NCR recognized that a drawing change performed on June 22, 1987 up-graded the HPCI lubricating oil (LO) instrumentation from a non-Q to a
Q status.
Although the original instrumentation was supplied by the vendor with "Q" certification, subsequent
"non-Q" maintenance may have degraded some instruments.
The disposition date was extended from 10/9/87 to 10/16/87 and then to 11/30/87 to allow Nuclear Plant Engineering (NPE) time to perform an interim safety assessment/con-ditional release of the HPCI LO instrumentation.
The licensee felt that the delay was acceptable since the original equipment was quali-fied, and any subsequent degradation would have little affect on the safety function (system integrity) of these instruments.
The condi-tional release was approved on November ll, 1987.
Certain instrumen-tation was dispositioned use-as-is while other pressure indicators and a level'witch were dispositioned for replacement, primarily be-cause their identity as original equipment could not be easily estab-lished.
Procurement delays have prevented replacement of all these instruments.
Additional management attention is needed to expedite delivery and to install the approved
"Q" instrumentation once it
arrives on site.
The original anticipated closure date was Parch 15, 1988.
Additional extensions have been made that show that the licen-see's use of the NCR program's conditional release section is abusive.
The use of a conditional release implies that quick closure is possible.
A conference call was held between NRC Region I and the licensee to discuss the status of the replacements and the current operability of the HPCI system.
Although the integrity of the gauges can be shown by engineering judgement to justify continued operation for a short period, neither prompt replacement nor more detailed engineering calculations were completed in a timely manner.
The two year instal-lation delay indicates that management oversight of this activity needs improvement.
NCR 87-0882 documented a missed pre-closure visual (VT-2) exam dis-covered after a 2-inch Masonelian outboard isolation valve (HV15711)
was reassembled.
This NCR listed a disposition date of 2/1/87 ( should have been 2/1/88) which was in error since the NCR was i ssued on 12/18/87.
The NCR was closed on 12/28/87.
One of the potential causes for the event was the failure to list the VT-2 on the Equip-ment Release Form (ERF)
and to promptly notify gC when the VT-2 could be performed.
The inspector has noted additional problems in com-pleting re'quired VT-2 exams which will be reviewed in future inspec-tions.
NCR 88-0085 questioned the failure to change out the reactor cavity seals on. the manufacturer's recommended five year replacement inter-val.
This NCR was closed on November 20, 1989.
The completion of this NCR was extended five times as noted on the front of the NCR.
The licensee used multiple engineering studies and calculations to justify not replacing the Reactor Cavity Seals on a five year fre-quency.
The licensee believed that the difficulty in replacing the seals by maintenance workers justified the engineering resource ex-penditure.
The licensee stated that the excessive amount of effort expended to justify the 12 and 24 year lifetimes could not be antici-pated.
The licensee has agreed to perform a more detailed upfront evaluation of potentially non-conforming conditions to ensure resource expenditure is commensurate with the safety significance of the problem.
NCR 89-0659, documents that a rubber boot with a yellow toe was ob-served in the suppression pool.
The NCR was issued on 10/25/89 and closed on 11/1/89.
The licensee's approach to this situation was to remove an equivalent amount (30 ft-squared) of potential strainer clogging electrical insulation from cable drops in the area.
The boot was apparently not retrieved because it would have delayed startup from the refueling outage.
The licensee questioned the use of Zetec insulation (which can clog the suppression pooling cooling strainers)
for this application.
Engineering analysis has justified sytem operability based on limiting the amount of Zetec used.
The
decision to remove an equivalent amount of insulation vice retrieving the boot while acceptable, was not considered to be the most safety conscious plan of action.
NCR 89-0660 documents that cables in certain fire zones were not in compliance with Appendix R separation criteria.
This NCR remains open.
Hourly fire watches were established and the cables are scheduled for rework under DCP'89-3039.
Inspector review of the above NCRs indicates that increased management attention is needed to control the use of conditionally released NCRs.
Certain NCRs (87-336, 88-0085) which had multiple extensions of the disposition date are of particular concern.,
NCR 88-0085 indicates that the licensee decided not to follow the manufacturer's replacement frequency for reactor cavity seals after, it had already been exceeded.
Thus, they were forced to request NPE extension of the. qualified life.
The licensee's use of conditionally released NCRs and their approach to problems impacting plant availability that are documented in NCRs is an unresolved item.
NRC will review of licensee actions taken to minimize the number of conditionally released NCRs outstanding along with the number of extensions for these NCRs.
In addition, the safety assessments used to document extensions and their safety basis will also be evaluated.
(UNR 50-387/90-08-04 (Common))
Potential Accident Anal sis Inade uac for an Electroh draulic Control EHC Re viator Failure The inspector 'questioned the licensee regarding their susceptibility to an accident response deficiency identified at Peach Bottom and Limerick.
Operator actions following an electrohydraulic control (EHC) system failure could bypass an assumed automatic main steam isolation valve (MSIV) closure.
The inspector reviewed section 15. 1.3 of the Susquehanna Final Safety Analysis Report (FSAR) and concluded that the following scenario could be applicable to Susquehanna Unit 1 and Unit 2.
The plant response to a main turbine EHC system failure which pro-vides maximum steam demand assumes that a main steam line (MSL) low pressure signal is generated which closes the MSIVs.
This causes a
reactor scram and also terminates the depressurization.
Further analysis depicted in FSAR Section 15. 1.3 shows that the EHC failure would result in reactor vessel level swell, a high reactor vessel level turbine trip and a reactor scram.
This scram would occur well before the MSL low pressure isolation setpoint was reached.
Scram response procedures (Step 1) direct the operator to immediately place the mode switch in shutdown.
This bypasses the MSIV isolation on low MSL pressure which is only in effect with the mode switch in run.
The turbine bypass valves would remain open due to the demanded 115 percent steam flow, continuing the reactor depressurization.
If no
additional operator action is taken the vessel could quickly depres-surize and, due to condensate system injection, would overfill.
However, procedures do specify appropriate operator actions, such as closing MSIVs on high vessel level.
Operators are trained on reactor vessel level control during continuing requalification training.
The'ffects of the potential vessel overfill event (e.g.
subcooled liquid in the main steam lines, the potential for subsequent two-phase flow through the safety relief v'alves, and the reactor vessel stresses resulting from the rapid cooldown) are of concern.
The EHC fai lure is treated as an "abnormal operational transient" in the FSAR.
As such, exceeding the code allowable reactor vessel stresses is not an acceptable result.
Further licensee review is needed to ensure that the current analysis bounds the potential adverse effects of the postulated failure.
This item will remain unresolved pending NRC review of further licensee assessment and analysis of the transient.
(UNR 50-387/90-08-05 (Common))
9.
EXIT MEETINGS 9. 1 Routine Resident Exit and Periodic Meetin s
The inspector discussed the findings of this inspection with station man-agement at the conclusion of the inspection period.
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 restrictions.
The inspector also held periodic meetings with licensee management throughout the period.
9.2 Attendance at Mana ement Meetin s Conducted B
Re ion Based Ins ectors
~Date s
Subject April 19 Emergency Drill Appraisal April 27 EOP Team Inspection
~ins ection
~Re ort Ro.
90-07; 90-07
90-80; 90-80 s
~Re ortin
~ins ector C. Gordon D. Florek
~4