IR 05000323/2005005
| ML17156A320 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna, Diablo Canyon  |
| Issue date: | 05/30/1985 |
| From: | Borchardt R, Bprchardt R, Jacobs R, Plisco L, Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17156A319 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-1.G.1, TASK-TM 50-387-85-12, 50-388-85-12, NUDOCS 8506100701 | |
| Download: ML17156A320 (27) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
50-387/85-12 50-388/85-12 Docket Nos.
50-387 CAT C
50-388 CAT C
Licensee Nos.
NPF-14'PF-22 Licensee:
Facility Name:
Penns 1vania Power and Li ht Com an 2 North Ninth Street Allentown Penns 1 vania 18101 Sus uehanna Steam Electric Station Inspection At:
Salem Townshi Penns lvania Inspection Conducted:
March 23 1985 - Ma
1985 Inspectors:
R.
H. Jac s, Senior Resident Inspector
~FED Q date L.
R. Pli co, Resident Inspector gg'o 4'+
da e
R.
W. Borch dt, esident Inspector Salem Nuclea Po er Station Approved By:
J.
rosni er, Chief Reactor Projects ction 1C, DRP date Ins ection Summar A~A*:
i
- i (
h; 2-plant operations, licensee events, open items, surveillance, maintenance,),Unit 1 refueling outage, Information Notice Followup, GE SIL Followup, and TMI ction Plan Items.
gggggPP7Pi 85D60~
PgR ADGCK 05+>~~~
Results:
Review of Standby Gas Treatment System fire dampers identified that the dampers were not included in the periodic surveillance procedures.
'This was a violation.
(Detail 1. 10); Review of licensee followup to IE Information Notice 84-12 identified the licensee adequately reviewed and evaluated the concern (Detail 6. 1); Review of licensee response to GE SIL 402 found discrep-ancies requiring reevaluation of the nitrogen inerting system (Detail 6!'2).
DETAILS 1.0 Followu on Previous Ins ection Items 1. 1 Closed Licensee Identified Item 387/82-32-07
RPS Modification Not Pro erl Com leted.
The licensee's failure to properly complete a Reactor Protection System (RPS) Modification resulted in the October 5, 1982 discovery by the licensee that a violation of a Unit 3 license condition) had occurred.
The violation involved the failure to properly ground a
number of RPS cables that had been identified earlier in Construc-tion Deficiency Report (CDR) 80-00-28.
The inspector reviewed Licensee Event Report 82-026/01T-1 and an investigation conducted by the Nuclear Safety Assessment Group(
(Project Report No. 11-82) dated November 1,
1982.
Both of these documents concluded that this violation was caused by a loss of management control during the turnover from Bechtel to the PPEL work control system prior to the fuel load of Unit 1.
Adequate corrective actions have been taken by the licensee including a
100%
reinspection of all work associated with the subject RPS modifications and the development of administrative controls to prevent reoccurrence.
1.2 Closed Ins ector Follow-u Item 387/82-42-02
- Test Exce tion Re orts TERs Nos.
113 and 140 Were Not Resolved TER 140 was replaced with TER 372 which concerns the offgas system dewpoint measurements.
TER 372 is discussed further in this inspection report and it has been assigned open item number 85-12-01.
The resolution of TER 372 will be reviewed in a future inspection.
TER 113 was reviewed and closed in inspection report 387/83-25.
1.3 Closed Unresolved Item 388/83'-08-01
- Startu Tests Would Be Retested Which Include ST 37. 1 ST 8.4 ST 25.3 ST 10. 1 ST 22r'nd ST 31.1 TER 372 ST 37. 1:
TER 372 states that the Guard Bed inlet dewpoints could not be verified.
The verification of Offgas Guard Bed A and B inIlet flows, temperatures, and dewpoints have been incorporated
~into Nonconformance Report (NCR) Number 85-0105.
TER No. 372, 483 and 484 remain open and are required to be resolved prior to the closeout of NCR 85-0105.
The results of the Offgas System
retesting associated with NCR 85-0105 will be reviewed in a future inspection report.
This item is considered unresolved (50-387/85-12-01).
Unacce table Stead State Limit C cles Were Observed When RHR Heat Exchan er A'as At 174 si The RHR steam condensing mode tune-up was reperformed on March 31, 1983.
The test results met all acceptance criteria and the TER was closed on December 11, 1983.
ST 1.2 re uired an anal sis for "No RWCU" test.
The inspector reviewed the completed test which was approved by the licensee on March 8, 1983.
No problems were identified.
ST 25.3:
Inboard MSIV F022C did not meet the minimum closure time re uirement The MSIV closure testing was satisfactorily completed as part of ST 25.2 on May 30, 1983, and the results were approved 'on October 23, 1983.
ST 10. 1:
SRM/IRM overla test would be com leted rior to commercial o eration ST 10. 1 verified proper SRM/IRM overlap and the results were approved on October ll, 1983.
No problems were identified.
ST 22.3 ST 24. 1: Retest of ressure re ulator would be com leted rior to commercial o eration ST 22.3 "Pressure Regulator Test Bypass Valves Controlling" test results were approved on March 8, 1983 and ST 24. 1, "Stop Valve Testing", test results were approved on October 23, 1983.
No unacceptable conditions were identified.
TER 473 ST 31. 1: Standb as treatment s
stem durin loss" of offsite ower would be retested rior to commercial o eration I
Test procedure TP-70-001 "Testing of Standby Gas Treatment'ystem on Loss of Power" was satisfactorily completed on May ll, 1983.
The test verified that the Standby Gas Treatment System would operate properly during loss of offsite power'.
TER 473 was closed on June 8, 1983.
The inspector had no further question.4 Closed Unresolved Item 387/83-08-02
- Several Startu Tests and TERs to be Resolved Prior to Commerical 0 eration The inspector reviewed the resolution of open Test Exception Reports (TERs) identified in Inspection Report 50-387/83-08.
The TERs were reviewed for proper administrative control and technical resolution.
Flow coastdown of recirculation system,did not meet acceptance criteria.
During the performance of~ST 27.2 "High Power Generator Load Rejection", the licensee
'etermined that the recirculation pump flow coastdown was slower than the acceptance criteria.
During a generator'load rejection transient, the recirculation pump trip and flow coast down mitigate the reactivity effects of the pressure increase by reducing core flow and enabling the void fraction to add negative reactivity.
In a letter to NRR dated September '6, 1984, the licensee requested a change to Unit 1 Technical Specifications.
This submittal discusses the impact of the slower recirculation pump coastdown on a Loss of Coolant
"
Accident, overpressurization, recirculation pump trip, ge'ne-rator load rejection, and feedwater controller failure.
For all other events the slower coastdown has a less severe effect.
The licensee has proposed new Minimum Critical Power Ratio limits to be consistent with the new GE analysis.
Becaus'e this technical concern is currently under review by NRR this TER is considered closed.
The inspector reviewed the following TERs and associated startup tests to verify that each TER had been adequately, resolved and that the resolution of each item has been documented and properly approved by the startup test organization, Test Review Committee, Plant Operations Review Committee and the Plant Superintendent.
TER 375 of ST 30. 1 TER 457, 458, 459 of ST 32.2 TER 464 of ST 35. 1 TER 466 and 467 of ST 17.3 ST 35. 1 - General Electric completed their review and approved ST 35. 1 on January 15, 1983.
The ins ector had no further uestions.
p q
1.5 Closed Unresolved Item 387/83-19-02
- Incor oration of Plant Chan es Into Plant Drawin s and Procedures The inspector was originally concerned about how the licensee assured that changes made to Unit 1 immediately before issuance of the operating license were incorporated into plant drawings and'rocedures.
The procedural controls used to incorporate approved
drawing changes for both Unit 1 and Unit 2 were reviewed and found to be acceptable.
The drawing change process during the construction phase is governed by Bechtel manual "Project Configuration Management Procedures (CMP)
Manual".
CMP-6. 1 "Design Change Control Configuration Control Records" details four levels of configuration control which coincide with different phases of the construction process leading up to fuel load.
Station Administrative Procedure AD-DA-410 "Plant Modification Program" was also reviewed to verify that plant drawings and procedures are revised as a,result of plant modifications.
Plant modifications that have an effect on procedures are documented on a
procedure review sheet which causes revisions to be generated for applicable procedures.
In addition, wide dissemination of modification information is made through use of an operationalI readiness form. This form is reviewed by the plant staff section heads for the Security, Instrument and Controls, Maintenance, I
Operations, Document Control Center, and Technical Departments~.
The section head is then responsible for conducting any necessary training for the section.
Closed Unresolved Item 387/83-21-04
- 0 erabilit of Chlorine Detectors During 1982 and 1983, a large number of Licensee Event Reports i(LERs)
were written describing the failure of the control structure ventilation system chlorine detectors to operate correctly.
The chlorine detectors failed due to the wick becoming clogged which then prevented the electrolyte solution from flowing properly.
"
During these failures an actual high chlorine condition would not have been detected by the failed detector.
However, an independent detector would have caused the control structure ventilation system to isolate if required.
Technical Specifications require both
~
chlorine detectors to be operable.
With one detector inoperabl'e, the licensee must restore the inoperable detector within seven days or initiate at least one control room emergency outside air supply system.
In an effort to more quickly identify detector fai lures, the licensee added the chlorine detectors to the daily operator's rounds.
In addition, Work Authorization (WA) S36886 was completed during December 1983.
This WA replaced the electrolyte solution and installed a
new o-ring in order to prevent dust from fouling the wick.
The licensee is also increasing the preventative maintenance frequency on the detector to prevent failures.
These actions have resulted in an improved performance record for these detectors although similar failures still occasionally occur (three instances in 1984).
The recent failures appear to have been quickly identified
and corrected.
At no time have both of the chlorine detectors been out of service at the same time as a result of the subject failure mode.
The inspector had no further questions.
1.7 Closed Ins ector Follow-u Items 387/83-23-05
- Demineralizer Oil Clo in from Reactor Feed Pum s
1.8 On November 2, 1983, Unit 1 tripped from 100% power due to Main Steam Isolation Valve (MSIV) closure and a main steam line high radiation signal.
The licensee's evaluation of the scram concluded that the condensate demineralizer s had been contaminated with oil from,the reactor feed pump (RFP)
due to a blockage in the RFP seal leak off line.
When the demineralizer resin was mixed during resin transfers or cleaning, the oil from the RFP was distributed throughout the bed and a small amount eventually released.
This released oil was'ctivated as it passed through the core and eventually caused the main steam line high radiation detector to generate a MSIV closure signal.
The inspector reviewed the licensee's actions to prevent the oil problem from recurring.
The installation of an Ultrasonic Res'in Cleaner, revision of resin operating procedures which reduce the number of transients on the resin beds and better operator awareness have combined to significantly improve the plant performance in this area.
The plant has not experienced a repeat of this problem for greater than one year
~
In addition, the licensee has made changes to the Unit 2 RFP shaft seal arrangement to prevent a similar problem on Unit 2.
Closed Follow-u Item 387/83-20-14 388/83-25-14
- 0 erations Did Not Distribute OMISS Re ort 1.9 During an operational readiness assessment, the inspector noted a
lack of promptness on the part of the Opertions Department to distribute the technical information received through the Operations Modifications Information Summary Sheet (OMISS).
The licensee responded to this weakness in a letter dated March 20, 1984.
Administrative Procedure AD-QA-410 "Plant Modification Program" now requires the OMISS to be completed and reviewed by the appropriate supervisors prior to the closeout of the modification package.
',,This requirement will ensure prompt dissemination of information relating to the modification prior to placing the modification in service.
In addition, formal training is given to applicable personnel by the Nuclear Training Group.
Closed Violation 387/84-22-02
- Missed Chemistr Sam les Re uired b
Technical S ecification Action Statement This violation was a result of the licensee's failure to obtain, chemistry samples that were required to meet a Technical
Specification Limiting Condition for Operation within the allowed time limits.
The licensee responded to this violation in a letter dated September 21, 1984, and concluded that, based upon the chemistry samples that were eventually analyzed no adverse consequences, resulted from the late sampling.
The analyzed data indicated'that there was no detectable activity in the RHR Service Water Effluent Line or the Turbine Building Ventilation Exhaust.
Corrective",
actions to prevent recurrence included initiation of an "In Effect" LCO sampling tickler file, revision of the chemistry LCO sample log and the Chemistry Supervisor's counseling of the responsible
'echnicians.
In order to ensure that chemistry sampling frequency is not exceeded the "Chemistry LCO Sample Log" now includes a "Date/Time Next ',Sample Due" column.
This column will, act as a reminder to the on-shift supervisor that an LCO sample is due.
The compliance with chemistry LCO requirements will continue to be inspected on a routine basis.
0 en Follow-u Item 387/85-09-02
- Standb Gas Treatment S stem Lineu Discre ancies In March 1985, the inspector identified that there were self-,
actuating fire protection dampers in the ducting between the SGTS trains and the recirculation plenum in the Reactor Building.
Misoperation of these dampers could affect system operability.',
At the time of the inspection, the licensee had been unable to provide specific data regarding the design and operation of these damp'ers.
The affected fire dampers are RUSKIN 1BD23A fire damper assemblies and are classified on RUSKIN drawing 3520N as Q and seismic compon-ents.
The temperature rating of the fusible link is 140 F.
The dampers are FPD-3-27-8-1SC, 2SC, 3SC, and FPD-3-30-8-1SC.
Per the FSAR, the design rating of the SGTS for maximum inlet air temperature is 125 F.
The licensee initiated an Engineering Work Request (EWR)
to evaluate the adequacy of the damper fusible link temperature.
In response to the inspector's questions regarding periodic inspections of these fire dampers, the licensee determined that these dampers were not included in surveillance procedures SM-113-009 or SM-213-009.
These procedures are used to implement Technical Specification surveillance requirement 4.7.7. 1 which
~,
requires an 18 month visual inspection of all safety related fire dampers, and hence, these dampers have apparently not been inspected per this requirement.
This is a violation (387/85-12-02).
This follow-up item remains open pending the licensee addressing the remaining deficiencies in the SGTS system as discussed in Inspe'ction Report 50-387/85-0 Closed Unresolved Item 387/84-06-01 388/84-05-01:
Loose l
Self-Adherin Mountin Bases in 4. 16 KV Switch ear During a previous inspection, the inspector noted that the plastic mounts glued to the internal surfaces of 4.16KV switchgear, used to secure wire bundles, were pulled loose in many of the cubicles on both the Unit 1 and Unit 2 switchgear.
The licensee determined that the self-adhering mounting bases are acceptable and are only utilized to train and support the cables in the panels for neatness and are not used for seismic supports.'onconformance Reports (NCRs)84-462 and 84-463 were issued to, document the deficiency.
The inspector reviewed completed NCRs84-462 and 84-463, which, replaced the detached mounts with a different self-adhering material with superior strength qualities.
1.12 Closed Unresolved Item 387/85-09-03
Use of Fuel Loadin Chamber durin Refuelin In February 1985, during Unit 1 core defueling, the licensee experienced problems with the fuel loading chambers (FLCs) used in place of source range monitors (SRMs) to maintain on scale source range indication.
The FLCs used at Susquehanna are Boron
proportional counters and the inspector and the licensee determined that these FLCs are apparently appropriate for use only during initial fuel load.
The licensee requested and received on April 30, 1985, an emergency technical specification change to permit loading up to eight fuel bundles without source range indication.
This enabled the licensee to obtain on scale source range indication on the installed SRMs without the need for FLCs.
2.0 Review of Plant 0 erations 2.1 0 erational Safet Verification The inspector toured the control room daily to verify proper manning, access control, adherence to approved procedures, and com-pliance with LCOs.
Instrumentation and recorder traces were observed and the status of controk room annunciators were reviewed.
Nuc~lear instrument panels and other reactor protective systems were examined.
Effluent minitors were reviewed for indications of releases.
Panel indications for onsite/offsite emergency power sources were examined for automatic operability.
During entry to and egress from the'pro-tected area, the inspector observed access control, security boundary integrity, search activities, escorting and badging, and availability of radiation monitoring equipmen '
The inspector reviewed shift supervisor, plant control operator, and nuclear plant operator logs covering the entire inspection period.
Sampling reviewed were made of tagging requests, night orders,I the bypass log, Significant Operating Occurrence Reports (SOORs)
and gA nonconformance reports.
The inspector also observed several shift turnovers during the period.
The operations activities observed were performed in accordance with the applicable procedures and requirements and found acceptable.
Station Tours The inspector toured accessible areas of the plant including the control room, relay rooms, switchgear rooms, cable spreading rooms, penetration areas, reactor and turbine buildings, security, control center, diesel generator building, ESSW pumphouse, plant perimeter and containment.
During these tours, observations were made relative to equipment condition, fire hazards, fire protection,'dherence to procedures, radiological controls and conditions, I
housekeeping, security, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment.
On April 9, 1985, the inspector noted that radiation levels were several times higher than background in an area surrounding a piping drain funnel on the 779 foot elevation of the Unit 1 Reactor Building.
A similar funnel on Unit 2 was posted as a contamination and radiation area.
The inspector notified the Health Physics I
foreman who had the area surveyed.
Although the general area ('18 inches from source) did not meet the posting criteria for a radiation area (greater than 2.5 mr/hr), the piping did contain".
several
"hotspots".
Administrative procedure AD-00-710, Revision 1,
Radiation Survey Program, defines a "hotspot" as any radiation I
reading which exceeds by a factor of four (4) the general backg'round radiation levels of the area and/or exceeds 50 mr/hr at contactI.
The on contact readings on the piping were approximately 30 mr/hr as compared to the general area readings of 1-2 mr/hr.
The foreman had the piping posted as a "hotspot".
Inspection surveys of other plant areas found that this inadequate posting was an isolated case ahd no further action was required.
During a tour of the Unit 1 Reactor Building on April 24, the inspector observed that the watertight door to the 'B'ore Spray System room at elevation 645 feet was impacting a
2 inch core spray drain pipe, when the door was swung wide open.
The affected piping is not safety related and is connected to discharge relief valve PSV F012B.
This pipe would direct water to a drain funnel if this valve lifted.
The piping was not deformed.
The licensee prepared a Work Authorization to prevent the door from impacting the pipe.
I
3.0 Summar of 0 eratin Events i
3.1 Unit 1 Unit 1 continued with the first refueling outage which commenc'ed on February 9,
1985.
The unit commenced refueling the core on May 3, 1985.
3.2 Unit 2 After completion of repairs to the condensate system and stator cooling leak, the reactor was started up and made critical at ll:43 p.m., March 24, 1985.
(See Inspection Report 50-387/85-09; 50-388/85-09).
On April 15, 1985, at 1:00 a.m., control rod 02-23 went full in from position 48 during the performance of surveillance test SI-258-203, Reactor High Pressure Scram Switch.
No indications or alarms were received during the insertion.
The operators noted that thermal power decreased from 3293 to 3263 MW.
At 1:50 a.m.,
the control rod was withdrawn.
Investigation found that a fuse was blown for the associated
"A" scram pilot solenoid valve, and it was replaced.'n April 21, 1985, at 1: 15 a.m.,
the spray pond bypass valve failed to open as designed while starting the "A" ESW loop in accordance with OP-054-001.
Investigation found two sliding links open in the, bypass valve auxiliary control circuit.
(See Special Inspection Report 387/85-1'6; 388/85-15).
On April 26, 1985, at 10:00 a.m.,
a controlled shutdown of Unit'
was begun to perform repairs on the main generator stator cooling system.
The unit was scrammed at 7:00 p.m.
and in Condition 4 'at 9:45 p.m., April 27.
On May 2, the reactor was started up and 'made critical at 10:35 a.m.
The generator was synchronized at 12:48 p.m.
May 3, 1985.
4.0 Licensee Re orts 4.1 In Office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the NRC:RI 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 follow-up.
The following LERs were reviewed:
Unit
85-008/00, 85-009/00,
- 85-010/00,
,1 Engineered Safeguards Features Actuated by Grounded Cable During Modlflcatlon Work Inadvertent Engineered Safeguard Features Actuation due to IRM Spikes Induced by Welding SGTS and CREOASS Start due to Shine from Drained Reactor Vessel
"'85-011/00, SGTS and CREOASS Start due to Radiography Unit 2 85-010/00,
- 85-011/00, Unplanned Engineered Safeguards Feature Actuation Due to Faulty Circuit Breaker Both SGTS Trains Inoperable Requiring Reactor Power
)eduction 85-012/00, Inadvertent ESF Actuation During Instrument Calibration 85-013/00, Standby Liquid Control System Isolated for Maintenance
. *Previously discussed in Inspection Report 50-387/85-09; 50-388/85-09.
- Further discussed in Detail 4.2.
4.2 Onsite Followu of Licensee Event Re orts For those LERs selected for onsite followup (denoted by asterisks in Detail 4. 1), the inspector verified the reporting requirements Iof
CFR 50.73 and Technical Specifications had been met, that appro-priate corrective action had been taken, that the event was reviewed by licensee, and that continued operation of the facility was con-ducted in accordance with Technical Specification limits.
4.2.1 LER 85-011 Unit
Standb Gas Treatment S stem SGTS and Control Room Emer enc Outside Air Su
S stem
)
CREOASS Star t due to Radio ra h
On March 23 and April 2, 1985, radiography being performed on the refueling floor caused the refuel floor radiation monitor to trip.
This caused an isolation of ventilation Zone 111 and started the SGTS system and CREOASS.
On)
March 23 al 1 systems performed properly.
On April 2, however, the radiography (RT) only caused the Division II or 'B'adiation monitor to trip.
The
'B'GTS fan started and subsequently tripped on low flowI The 'B'eactor Building recirculation fan, which wasIlin
STANDBY, failed to start.
The 'A'GTS fan was manually started.
The RT was suspended and HVAC systems returned to normal.
The inspector discussed this occurrence with the system engineers, reviewed SOORs 2-85-092 and 096, and operator logs and observed SGTS testing on April 4.
The cause of the recirculation fan not starting was due to a damaged backdraft isolation damper (BDID 17521) which allowed flow across the recirculation plenum.
The standby recircula-tion fan will start after a time delay if it senses that the lead fan i,s not running.
With flow across the recirculation plenum due to the damaged BDID, sufficient differential pressure existed across the plenum to clear the low differential pressure switch, and hence, theII standby fan did not get a start signal.
The 'B'GTS fan tripped on low flow because a suction path did not exist.
This occurred because the outside air damper does not open for two minutes, no recirculation fan was running to[
assist in supplying flow to SGTS, and Zone III differen-tial pressure stayed at a vacuum which kept the modulating damper PDDM 07554B between the recirculation plenum and the inlet to SGTS, closed or nearly closed.
The low flow trip, set at 2000 CFM, was needed while SGTS was operated with one fan in AUTO LEAD and the other in AUTO STANDBY.
Both fans are now operated in AUTO LEAD per the Technical Specifications, so the low flow trip is not needed.
The low flow trip has since been removed and BDID 17521 has been repaired.
Since this occurrence, therle has been a large amount of SGTS testing including drawdown and inleakage testing of various zone combinations (i.e. iZones I and III, Zones II and III, and Zones I, II and III)%.
The above problems have been corrected.
4.3 Review of Periodic and S ecial Re orts Upon receipt, periodic and special reports submitted by the licensee were reviewed by the inspector.
The reports were reviewed to determine that the report included the required information, that test results and/or supporting information were consistent with'esign predictions and performance specifications, that planned'orrective action was adequate for resolution of identified problems, and whether any information in the report should be classified as an abnormal occurrence.
The following periodic and special reports were reviewed:
Monthly Operating Report - March 1985",
Special Report 1985, and 5.0 Monthl Surveillance and Maintenance Observation Special Report Non-Valid Diesel Failure, dated March 26, 1985; Special Report HPCI Injections, dated April 19, 1985;
- Non-Valid Diesel Failure, dated April 30",
Special Report Non-Valid Diesel Failure, dated Nay 3, 1985.
These reports were found acceptable.
5. 1 Surveillance Activities The inspector observed the performance of surveillance tests to determine that: the surveillance test procedure conformed to technical specification requirements; administrative approvals and tagouts were obtained before initiating the test; testing was accomplished by qualified personnel in accordance with an approved surveillance 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 included:
S0-252-002, Quarterly HPCI Flow Verification, April 3, 1985; S0-259-010, Suppression Chamber Average Water Verification, performed on April 3, 1985; performed on Temperature SE-153-001, Standby Liquid Control System Eighteen Month Initiation and Injection Demonstration, performed on April 1985; S0-070-002, 18 Month Pressure Drop Verification of Standby Treatment System (SGTS),
performed on April 24, 1985; and
<17,
'Gas S0-070-007, 18 Month Secondary Containment Verification Ch Zones I, II and III performed on April 26, 1985.
eck I/
On April 3, during the performance of surveillance test S0-252-002, the'nspector noted that the HPCI "Oil Tank Hi-Lo Level" alarm~ was activated prior to and during the test.
The alarm was sealed
~in, therefore, an actual alarm condition would not have been noted".
The operators stated that the level switch ( LSHL-25660) was not operating properly and that a Work Authorization (WA) had been~i submitted.
The oil level was checked locally by the Reactor Building NPO and found to be normal.
After further review, the inspector found that a discrepancy had been identified by the
~j licensee between'he General Electric (GE) and Bechtel drawings and that the level switch wiring had been installed incorrectly.
The responsible system engineer submitted drawing changes to revise the drawings and the incorrect wiring was corrected by I&C personnel on WA V-56030 on April 19, 1985.
The level switch does not provide any automatic functions and did not affect operability.
On April 26, the inspector observed the performance of surveillance S0-070-007, 18 Month Secondary Containment Verification Check on Zones I, II and III.
This test involved initiating an isolation signal for ventilation Zone I, II and III which causes supply and exhaust fans to trip, supply and exhaust isolation dampers to shut, recirculation, SGTS and CREOASS fan start.
The acceptance criteria is that each train of SGTS (tested separately)
be able to establish a 0.25 inch vacuum in all three zones within 92 seconds and that each train be able to maintain this vacuum at a
SGTS flow rate of less than or equal to 4000 cfm for over one hour.
During the testing of Division 2 ('B'rain), the drawdown time was 92 seconds, but the train operated at a flow rate of greater than 4000 cfm while maintaining the 0.25 inch dp.
The licensee adjusted a balancing damper on Zone III ventilation which enabled the flow to be maintained at approximately 3500 cfm.
Division 2 was retest'ed with the following results:
drawdown time improved to 80 seconds and maintenance flowrate was about 3350 cfm.
During Division 1 testing, the drawdown time was 59 seconds, and the nominal flow rate to maintain the required vacuum was about 3400 cfm.
During the Division 1 and 2 testing, the CREOASS fans started and then tripped.
The cause of the trip was low delta temperature (dt)
across the filter bank heaters.
The purpose of the trip is to
)
indicate that the heaters are not functioning.
The licensee changed the low temperature trip setpoint from 10 F to
F and increased the time delay from four to 14 minutes.
5.2 Maintenance Activities Auto Start of Diesel Generator on Loss of Control Power On March 29, 1985, the 'C'iesel Generator (D/G) automatically started and then tripped on mechanical overspeed.
The cause of ~the
auto start and tripping was due to loss of DC control power.
Modification PMR 82-872, 125 volt DC (VDC) Common Transfer Swi'tch was being installed which required terminating cable leads in DC panel 1D634.
The cause of the loss of control power was due t'o a lug breaking on an adjacent breaker to the breaker being worked on.
There have been three prior occurrences of broken lugs in 125
~VDC panels, which affected safety systems on Unit 2, during performance of this modification.
(Ref:
LER 85-008)
The inspector discussed this occurrence with technical staff person-nel, inspected several DC panels and reviewed Non-Conformance Report (NCR) 85-0025.
There are eight 125 VDC panels affected by thi's modification:
four on Unit 1 and four on Unit 2.
Following two occurrences of broken lugs in these panels, NCR 85-0025 was written on January 26, 1985.
As a result, all Class 1E terminations were visually inspected to determine which were deformed or otherwise nonconforming.
The inspection results were that most lugs were at least slightly bent.
Four were identified as cracked or cold worked and work authorizations (MAs) were written to replace them.
Before one of these lugs was'eplaced, it was broken while modification work was in progress leading to the incident described in LER 85-008 concerning loss of logic power to Unit 2 HPCI and the B loop of, core spray.
The lug which was broken on March 29 was attached to br'eaker number 5 in panel 1D634 and had been identified as bent but not cracked.
At the time, construction electricians were performing work on an adjacent breaker.
The affected lug has been replaced.
There is very limited access within these panels and due to the nature of the loads supplied by these panels, they cannot be deenergized with either unit in operation.
The lugs have been !bent apparently due to previous cable pulling work and installation 'of new components.
On April 2, the inspector discussed his concern with the repeated breaking of terminal lugs in these panels with the Station Superintendent.
At that time, three panels remained to'e worked.
The Station Superintendent indicated that the workers had been sensitized to this concern, work practices had been examin'ed and terminations in these panels will be reinspected after completion of this modification.
Modification work was completed in the remaining panels without further incident.
The inspector will review the results of the reinspection.
(387/85-12-03)
6.0 IE Bulletin and Information Notice Followu 6.1 IE Information Notice 84-12: Failure of Soft Seat Valve Seals IE Information Notice 84-12, Failure of Soft Seat Valve Seals, was provided to the licensee on February 27, 1984, as a notification of the failure of soft sea@'0'alve seals (molded ethylene-proplyene~'and extruded vulcanized rubber) to meet the leakage limits of Appendix J
of 10 CFR Part 50.
No specific action was required in response to the information notice.
The inspector reviewed the licensee's actions to ascertain whether; the information notice was received by licensee management, a ",review for applicability was performed, the notice was distributed to the appropriate personnel at the corporate and site levels, and appropriate corrective actions have been taken or are schedule'd to be taken.
The Information Notice discussed several occurrences at LaSalle Unit 1 where the inboard feedwater check valves (Anchor/Darling Val,ye Company) failed to meet the leakage limits of Appendix J of 10,', CFR 50.
When the check valves were opened for inspection, the sofIt seat showed damage around the pressure-relieving vent grooves, some! wear on the soft seat face, and slight wear on the body seat.
Further discussions with the Senior Resident Inspector at LaSa~lle identified that, although the cause of the seal failures has not been definitely determined, it is believed to be related to the service conditions encountered by the valves during plant operation since LaSalles feedwater injection temperature is significantly higher (430 F) than at Susquehanna (282 F).
Several additional localIleak rate failures have been experienced at LaSalle since the issuance of the'nformation Notice.
Susquehanna Units 1 and 2 each have two 24 inch Anchor/Darling I900 lb. tilting disc check valves with a dual seat design.
The valves were modified in September 1981 from a hard seat configuration Ito a resilient seat.
The valves have a hard surface (stellite) seat ring integral to the valve body and soft surface resilient seat (ethylene-propylene)
integral to the valve disc.
The valves ( 141F010 A/B) serve as the inboard feedwater containment isolation valve per GDC 55.
The outboard containment isolation valve (HV141F032 A/B) is a 24 inch, Atwood/Morrill 900 lb. motor oper'ated stop check with a hard seat design.
The motor operated stop check valve also prevents reverse flow into the feedwater system from', the RCIC, HPCI, and RWCU line.
The 'licensee reviewed the lnformat.ion Notice and issued an internal written response on November 6, 1984.
The response concluded tPat no corrective action was required, with the exception of adding)
extruded-vulcanized resilient seals to the Defective Device List.
The licensee stated that adequate testing is performed every 18I to 24 months in accordance with the LLRT procedures SE-159-026, SE-;259-026, SE-159-027, and SE-259-027.
The licensee also noted that i",
further review may be necessary, pending receipt of further informa-ation concerning LaSall Test Date The inspector reviewed the LLRT data for both Units 1 and 2 to determine if there had been any evidence of seal leakage.
The data is tabulated below:
F010A F0100
~Lk Leakrate SCCM Unit
Unit 2 7/30/81 3/28/82 10/14/82 2/15/83 2/20/83 4/08/85 4/14/85 4/21/85 7/01/83 10/07/83 11/01/84
205 230 Failed 799 (Retest)
137 460 481
113 Although the historical data is limited, it is apparent that t e same type of repeated failures seen at LaSalle have not occurred at Susquehanna.
Only one LLRT has failed to meet the acceptance.[
criteria thus far in plant life.
Based on the inspectors review of LLRT data and discussions with the Techical Group, the Information Notice reviews and corrective actions have been thorough and complete.
~l 6.2 Gf Service Information Letter SIL 402 Fol 1owu Wetwel1/Dr well
~inertin SIL 402 recommended the implementation of five actions to evaluate the potential for injecting cold nitrogen into containment.
By letter dated September 24, 1984, PPEL provided its response to 'this SIL to the NRR.
Inspection review of this letter identified a, number of discrepancies described below.
fvaulate Inertin S stem Desi n
The letter indicated that a
cursory design review of the inerting systems was performed and indicated that the Susquehanna systems utilize an atmospheric vaporizer and that system piping is uninsulated from the vaporizer to the containment.
The inspector determined that the above description is accurate for the makeup system but not the inerting system.
The letter stated that the response was applicable to loth the nitrogen makeup system and the inerting system.
The inerting system used a truck-mounted nitrogen rig from a vendor, and the,~
vaporizer is powered by diesel fuel.
In addition, the inerting'ystem piping is insulate Evaluate Inertin S stem 0 eration - The letter stated that opera-tion of the Unit 1 inerting system was performed to assure that the vaporizer, low temperature shutoff valve and other components, have functioned properly.
The inspector determined that the inerting system has no low temperature shutoff valve.
The makeup system does, although the valve is not included in a periodic calibration program.
7. 0 TMI The inspector discussed the above discrepancies with the Station Superintendent and requested that a supplemental response be submitted to correct the above errors and reevaluate the system.
Based on this review, the inspector is unable to conclude that", the potential for injection of cold nitrogen is acceptably low. his item remains unresolved.
(387/85-12-04)
Action Plan Re uirements 7.1 1.G.1. - Trainin Durin Low Power Testin Unit 2 The licensee committed in FSAR Table 18.2-1 to ensure that each shift observed at least one of each of the following transients during start-up testing:
(1) reactor scram; (2) pressure regulator transient; (3) turbine trip or load rejection; (4) water level transient; (5) recirc flow transient; and (6) operate the HPCI or RCIC system.
This commit-ment was met during Unit 1 startup testing for operators on shift during that test program; and, with some exceptions, the same operators were used during Unit 2 startup testing.
During discussions with NRR and the licensee in March 1984, it was agreed that only new operators were required to observe the above startup tests on Unit 2.
The inspector reviewed training records on fifteen operators who had not been licensed during the Unit 1 startup program.
All of these opera-tors observed each of the above transients from the control room.
The licensee also committed in FSAR Table 18.2-1 to perform additional testing on the RCIC system and integrated testing of reactor vessel level and pressure instruments.
The inspector reviewed Technical Procedure TP 5.68, Revision 0, RCIC Loss of 'AC Power Operations and DC Seperation Demonstration, performed on November 10, 1983, and TP 4. 14, Revision 0, Nuclear Boiler Level Instrument Test, performed on October 10, 1983.
The inspector also reviewed results of the integrated pressure instrument test which was performed in conjunction with the Integrated Leak Rate Test, P259.2A performed in November 1983.
No discrepancies were noted.
8.0
~Alla ation On April 22, 1985, Region I received an allegation concerning two workers who were allegedly fired for refusing to sign a dose extension form to enable them to work on a "hot" job.
The inspector made a preliminary review of this matter and determined the following:
.
Two Catalytic boiler makers were released from the site the previous Friday for refusing to accept assigned work.
These individuals and'thers had been asked to sign quarterly dose extension forms to allow their quarterly dose limit to be extended to 2 '
rem to permit work on the Unit 1 steam dryer.
The purpose for signing the dose extension forms was to prevent delays in the work by pulling the workers off the dryer when lower administrative dose limits are exceeded.
The work entailed attaching an instrumentation package to the dryer to permit monitoring the dryer for movement when the reactor is in service.
The workers would be exposed to radiation fields on the order of 500-1000 mrem/hour.
,The inspector discussed ALARA planning for this job with health physics personnel and reviewed some ALARA planning documents.
It appeared hat the licensee had taken sufficient actions to try to reduce the radiation fields and further dose reduction was not practical.
Dose extensioqs to 2.5 rem are permissible in accordance with licensee procedures and. NRC regulations.
The individuals who refused to sign the dose extension were apparenIly released because bulk work for the outage was nearly complete and other work suitable for their skills was not available.
Based on the above information, Region I determined that further followup was unnecessary.
Waterhammer in Unit 2 RHR S stem At 8:37 a.m., April 27, while attempting to place the 'B'oop of RHR in service for shutdown cooling, a waterhammer occurred.
The operators were warming the RHR system in accordance with OP-249-002, Revision 3, RHR Operation in the Shutdown Cooling Mode.
The procedure specifies warming both the suction line and the injection line separately by establishing flow from the reactor vessel through the RHR piping to the main con-,',
denser, radwaste or suppression pool.
The licensee was following the procedure section which established a flow path to the main condenser via a four inch line which taps off the RHR crosstie piping between RHR Iloops
'A'nd 'B'.
The procedure specifies maintaining warmup flow until '~the RHR crosstie temperature reaches 205~F and RHR conductivity is within specification.
The operators completed the procedure steps which warm the suction piping, without problems and aligned system valves to warm the LPCI injection piping.
The flowpath for this portion of the procedure involves establishing flow from the recirculation system discharge piping back through the LPCI testable check valve (thi s vaIlve is opened by continuously supplying air to it) and the equalizing line, the LPCI injection and throttling valves to the crosstie piping to the main condenser.
The heat exchanger outlet and bypass valves are shut during this warmup.
A waterhammer occurred while securing from thisII',
lineup, when the heat exchanger bypass valve F048B was cracked open.
When the F048B valve was opened, reactor vessel level dropped from about 48 inches to 13 inches causing a reactor scram (all rods were already inserted).
This corresponds to several thousand gallons of water.
7he RHR injection piping had apparently voided and the water flashed to I steam.
During the warming process, the testable check valve F050B valve
showed dual indication.
It is unknown how the voiding actually occurred.
It is possible that the testable check, in a partially closed condi-tion, was not passing sufficient flow to maintain the system full as water was draining to the condenser which was under vacuum.
After the waterhammer, operations personnel inspected the RHR piping for damage.
None was found.
They checked that the RHR piping was filled and vented from a high point vent and at 9:45 a.m., started the 'D'HR pump.
Another waterhammer occurred and the shutdown cooling isolation valves (F008 and F009) isolated (apparently on high flow) causing the RHR pump to trip.
This waterhammer occurred because the system piping was still voided, The operators checked the high point vent on the injection line (previously they had checked a vent at a higher elevation in the contain-ment spray line) and steam issued from the vent.
Subsequently, the opera-tors cooled down the RHR piping to about 160'F using keep fill and
',
other system vents.
Nuclear Plant Engineering (NPE) performed a walkdown of the suction and injection piping.
No evidence of piping or hanger damage was found.
A temporary change to OP-149-002 was written to modify the procedure steps that warm the injection line.
The procedure was changed to discharge RHR water to radwaste via the one inch heat exchanger vent line.
Subsequently, the RHR system was placed in shutdown cooling at 7:45 p.m., April 27.
The inspector discussed the event with Operations, Technical I&C and NPE personnel, and reviewed the following documents:
OP-249-002, P&ID N-2151 RHR System, SOORs 2-85-121 and 122, GE Service Information Letter No.
175 and operator logs.
Revision 3 to OP-149-002, issued February 8, 1985, modified the procedure to include steps to enable warming the LPCI injection line by backflow from the recirculation system.
This portion of the procedure had not previously been performed at Susquehanna.
It was included to prevent a
thermal transient at the RHR/Recirculation pipe tee.
175 dated June 15, 1976, indicates that under some conditions a fatigue, analysis has shown that this tee can be overstressed after repeated thermal cycles.
As a result of the waterhammer concern, the licensee is modifying the procedure to delete that portion addressing injection line warmup.
An engineering work request was prepared to request NPE to address the thermal cycle concern with the RHR/recirculation pipe tee.
The licensee has checked the calibration of several instruments whicb might have been affected by the waterhammer.
Instruments checked included suction and discharge pressure instruments, flow transmitter and two pressure switches used to sense an RHR pump runnng for ADS.
No evidence of these instruments being affected by the waterhammers was found.
Voiding in the RHR system during warmup operations appears to be a
generic problem.
Information Notice 84-81 addresses similar problems at other BMRs.
This issue will receive further review.
(388/85-12-01)
(
10.0 Exit Interview
On May 15, 1985, 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 on Nay 15, it was deter-mined that this report does not contain information subject to
CFR 2.790 restriction ~'I~
-}It,~'4 ~