IR 05000209/2003022
| ML17156A128 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna, 05000209  |
| Issue date: | 04/15/1985 |
| From: | Jacobs R, Johnson T, Plisco L, Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17156A129 | List: |
| References | |
| 50-387-85-09, 50-388-85-09, NUDOCS 8504190380 | |
| Download: ML17156A128 (34) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
50-387/85-09 50-388/85-09 Docket Nos.
50-387 CAT C 50-388 CAT C
License Nos.
NPF-14 NPF-22 Licensee:
Facility Name:
Inspection At:
Penns lvania Power and Li ht Com an 2 North Ninth Street Allentown Penns lvania 18101 Sus uehanna Steam Electric Station Salem Townshi Penns lvania Inspection Conduct d:
Februar
March 22 1985 Inspectors:
y
.
H Ja obs Senior Resident Inspector R. Plisco, Resident Inspector P. Johnson, Senior Resident Inspector, P ach ottom v/ix/~s-date 4//JIB.
date
~ical&
date Approved By:
Strosnider, Chief Reactor Projects Section 1C, DRP 5r'(siss date Ins ection Summar
R i
id i
i t-2 j;
U plant operations, ESF system walkdown, surveillance, licensee events, open items, Unit 1 refueling outage, Unit 2 reactor scram, Confirmatory Action let-ter followup.
Results:
ESF system walkdowns of Standby Gas Treatment System and Unit 2 RCIC verified system operability although labeling and procedure discrepancies were identified (Detail 2.3);
review of fuel loading chambers indicated they were not properly calibrated for use in an irradiated core (Detail 6.2).
No violations were identified.
8504i90380 8504i6 PDR ADOCK 05000387
DETAILS 1.0 Followu on Previous Ins ection Items Closed Licensee Identified Item 387/83-12-06
- Vent Monitorin Sam le Pum s.Ino erable Closed Ins ector Followu Item 387/82-25-02
- Prevention of Power Loss to Airborne Radiation Monitor Control Terminals In Licensee Event Report (LER)83-065, dated May 25, 1983, the licen-see reported, that due to procedural deficiencies and stack monitor-ing system operator interface design problems, the Turbine Building, Reactor Building and Standby Gas Treatment System (SGTS)
vent sample pumps were inoperable for a period of five hours and fifteen minutes, and the required backup sampling was not performed.
The licensee committed to a
number of corrective actions in LER 83-065, which included revising the alarm response procedure for the stack monitoring system, adding an annunciator log in the control room to record all inner-ring alarms, and reviewing the stack monit-oring system operator interface design.
The inspector reviewed alarm response procedure AR-015-001, Revision 1, Stack Monitoring System Hi-H'i Radiation, which has been revised to provide more detail to the operator and to reflect the possible causes for the alarm.
Administrative Procedure AD-gA-303, Shift Routine, Revision 4,
now requires the offgoing night shift operator to review all control room panels prior to shift turnover and log any lit annunciators on the Annunciator Log.
Each shift reviews and updates the log as necessary.
The log sheet includes a description of, the alarm, panel and window location, cause, and corrective action which has been initiated.
The inspector reviewed the revised procedure and has wit-nessed the implementation of the log during control room tours.
The licensee has performed an initial review of the stack monitoring system interface with the operators and other concerns with the cur-rent system design.
Corrective actions have not yet been initiated.
The corrective actions will be completed during the course of the SPING Enhancement Project which is still under evaluation by licensee management.
The SPING Enhancement project also includes the modification needed to prevent an unannunciated power loss to the control terminal dis-cussed in Inspector Followup Item 387/82-25-02.
The two NRC open items noted will be closed, but due to continued difficulties with the vent monitoring system, the inspector will con-tinue to review the corrective action implemented as a
result of SPING Enhancement project.
(387/85-09-01)
1.2 Closed Ins ector Fol 1 owu Item 387/84-35-01:
Fol 1 owu on Commit-ments in Confirmator Action Letter 84-18 The licensee has completed all of the corrective actions required by Confirmatory Action Letter 84-18, dated October 17, 1984, concerning scram pilot solenoid valve failures.
The details of the licensee's actions are discussed in Detail 7.0 of this report.
1.3 Closed Unresolved Item 387/83-29-03 388/83-32-02
- Modifications to the Ultimate Heat Sink Plant Modification Record (PMR)
84-3092 installed two self-priming centrifugal spray array draindown pumps in each Emergency Service Water division to allow water that may have leaked into the spray piping to be pumped out without the need to fill the piping above the centerline.
Secondly, level detection devices were installed in each of the four spray arrays, which provide local level indication and a
remote high level alarm function.
The modifications were completed on January 5,
1985.
The inspector observed portions of the pump in-stallation activities and reviewed the completed PMR package.
The completed modifications, in addition to the in-place administrative controls, should prevent the spray pond array freezing condition which occurred in January 1984.
The licensee had additionally committed to install an auto-start feature to the draindown pumps by the end of 1985.
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 compliance with LCOs.
Instrumentation and recorder traces were observed and the status of control room annunciator s were reviewed.
Nuclear instru-ment panels and other reactor protective systems were examined.
Ef-fluent monitors 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 equipment.
The inspector reviewed shift supervisor, plant control operator, and nuclear plant operator logs covering the entire inspection period.
Sampling reviews were made of tagging requests, night orders, the bypass log, significant Operating Occurrence Reports (SOORs)
and gA nonconformance reports.
The inspector also observed several shift turnovers during the perio.2 Station Tours The inspector toured accessible areas of the plant including the con-trol room, relay rooms, switchgear rooms, cable spreading rooms, pen-etration areas, reactor and turbine buildings, security control cen-ter, diesel generator building, ESSW pumphouse, plant perimeter and containment.
During these tours, observations were made relative to equipment condition, fire hazards, fire protection, adherence to pro-cedures, radiological controls and conditions, housekeeping, secur-ity, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment.
No unacceptable conditions were identified.
2.3 ESF S
stem Walkdown 2.3. 1 Standb Gas Treatment S stem On Nar ch 20, 1985, the inspector independently verified the operability of the Standby Gas Treatment System (SGTS)
by performing a walkdown of accessible portions of the system.
The engineered safety feature status verification included the following:
Confirmation that the system checkoff list and opera-ting procedure are consistent with the plant drawings and as-built configuration, Identification of equipment conditions and items that
" might degrade performance, Identification of properly functioning instrumentation while the system was operating, Inspection of breaker and instrumentation cabinet interiors,
Verification that valves and breakers were properly aligned.
The following references were used for this review:
Technical Specifications FSAR Section 6.5 Bechtel Drawing VC-175, Sheet 3 of 13, Revision 17, HVAC Control Diagram, Reactor Building, Standby Gas Treatment System
Operating Procedure, OP-070-001, Revision I, Standby Gas Treatment System Bechtel Electrical Schematics, E-201, Sheets 1-12, Standby Gas Treatment System PP&L Design Description Manual, Chapter
Unit of Instruction, SY0176-3, Revision
The inspector determined that the system was properly aligned in accordance with the operating procedure and plant drawings.
The inspector identified the following items:
No instrument root valves were included in the check-off list (COL).
In response to previous issues, the licensee has undertaken a
program to label instrument root and rack valves for safety-related system instru-mentation and include the valves in check-off lists.
SGTS instrument root and rack valves have been labeled and the licensee stated that these valves will be added to the COL.
In general, labeling of SGTS components is inadequate.
System dampers, certain switches and other components are not permanently labeled.
The licensee stated the labeling on SGTS components will be reviewed and cor-rected as necessary.
The glass protecting the spring mechanism for damper HD 07522A is broken.
The licensee
.indicated a
Work Authorization (WA) would be prepared to correct this.
The local mechanical shut/open indicator on damper HD 07522B is backwards.
The licensee corrected this con-dition.
Dampers PDD 07554 A/B, Recirc.
plenum to SGTS train dampers, were not included in either the COL or OP section which aligns the system for automatic opera-tion.
The licensee stated that this wi 11 be cor rec-ted.
These dampers automatically align on system initiation.
The labels on a few instruments switches do not match the component description in the COL or OP
~
The licensee indicated that this wi 11 be reviewe The operability of the SGTS room heating and cooling system is not addressed in the OP.
It is aligned in accordance with OP-30-002.
It is unclear whether the operability of this system can affect the proper oper-ation of the SGTS and hence, whether it should be in-cluded in the SGTS OP and be required for SGTS opera-bilityy.
The licensee indicated that this area will be reviewed.
The breakers for panels 1Y216, 1Y226, lY236 and1Y246, which supply power to SGTS instrumentation and con-trols and other safety-related functions, are not labeled other than by breaker number.
The licensee's actions to correct the above discrepancies will be reviewed in a
subsequent inspection.(387/85-09-02)
RCIC Unit 2 The inspector performed a walkdown of portions of the Reac-tor Core Isolation Cooling (RCIC)
system in order to inde-pendently verify the operability of the Unit 2 RCIC system.
The RCIC system walkdown included verifications of the fol-lowing items:
inspection of system equipment conditions, confirmation that tha system check-off list and opera-ting procedures are consistent with plant drawings, verification that system valves, breakers and switches are properly aligned, verification that instrumentation is properly valved in and operable, verification that valves required to be locked have appropriate locking devices, verification that control room switches, indications, and controls are satisfactory, verification that the surveillance procedures imple-ment the technical specification surveillance require-ments.
The following references were reviewed:
Technical Specification Sections 3.7.3, 4.7.3, 3.3.5, 4.3.5, 3. FSAR secti on 5.4. 6 P&ID M-2150, Unit
RCIC Turbine-Pump, Revision 9,
dated October 25, 1983 PAID M-2149, Unit 2 RCIC, Revision 12, dated December 22, 1983 OP-250-001, RCIC System, Revision 3,
dated March 12, 1985 RCIC System Alarm Response Procedures, AR-208, Revi s-ion 2, dated March 20, 1985 GE Elementary, Ml-ES1-90 Surveillance Procedures (1)
S0-250-001, Monthly RCIC Pump Discharge Line Filled, And Valve And Flow Controller Alignment Verification; Revision 1,
dated September 21, 1984 (2)
S0-250-002, Monthly RCIC Pump guick Start and Flow Verification, Revision 2,
dated September 21, 1984 (3)
S0-250-003, 18 Month RCIC System and Logic Func-tional Check, Revision 2,
dated October 25, 1984 (4)
S0-250-004, RCIC Valve Exercising, Revision 0,
dated November 9, 1983 (5)
S0-250-005, 18 Month RCIC Flow Verification, Re-vision 0, January 7,
1985 The inspector determined that the system was properly aligned in accordance with the operating procedure and plant drawings.
The following minor deficiencies were noted with RCIC PAID'
M-2149, 2150 and System Operating Procedure OP-250-001:
Valves 249F037, 249F036, 249F057, 249F082, 249 F083, 249009 are indicated as
"LOCKED" on the RCIC systemcheck-off list (Attachment B), however they are not indicated as locked on the RCIC sys-tem PKIDs.
The valves were verified as locked during the walkdown
~
Valves 249F060 and 249F059 are indicated as
"LO" (locked open)
on the P&ID M-2149.
These valves are motor operated from the control room with the use of a key locked switch.
On the system check-off list the valves are listed as
"OPEN",
not
~
locked open.
In addition, during system walkdown, the following items were noted in RCIC room, Unit 2, 645 foot level:
valve identification tags RV-PI-2R004 and 2RV-PT-2N007/PI-2R003 were detached from their respec-tive component.
Two buckets and one can of RCIC sump lube oil were in the RCIC room.
subsequ 3.0 Summar of 0 eratin Events The inspector discussed these items with the Station Superintendent on March 22.
The Station Superintend-ent indicated that lube oil buckets would be removed and that the above P&ID discrepancies would be re-.
viewed and corrected as necessary.
Licensee's actions to correct these discrepancies will be reviewed in a
ent inspection.
(388/85-09-01)
3.1 Unit
Unit
was shutdown at 1:45 a.m.
February 9, to commence the first refueling outage.
Operational Condition 5 was entered at 1:45 a.m.
February 12, 1985.
Defueling of the Unit 1 reactor vessel commenced on February 18 and was completed on March 5.
Control Rod Drive (CRD) Mechanism removals were begun on February 20.
CRD replacement was suspended on February 22 due to the inadvertent loosening of flange bolts on an untargeted CRD.
CRD removal proceeded on February 25 (See Detail 6.3).
During reactor vessel inservice inspection on March 4, the licensee discovered a crack-like indication on one of four steam dryer support blocks.
The steam dryer also had indications along the upper support ring and in welded seams (See Detail 6.5).
3.2 Unit 2 The 100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> warranty run was completed at 12:30 a.m.
February 9,
marking the completion of the Startup Test Program.
Unit 2 was de-clared in commercial operation at 12:Ol a.m.
February 12, 198 On February 12 - 17, reactor power reductions were performed to iso-late and repair a
main condenser tube leak in the
"B" waterbox.
Power was restored to 100 percent by 4:00 p.m.
February 17.
On March 10, both trains of SBGTS were declared inoperable and Unit 2 commenced a
power reduction in accordance with Technical Specifica-tion 3.0.3.
"B" SBGT was restored and reactor power restored to 100 percent.
On March 18, a stator cooling leak was discovered on the Main Genera-tor beneath the neutral connection to the grounding transformer, and a
power reduction began on March 20 in preparation to commencing a
forced maintenance outage.
At 7:06 a.m.
March 21, the Main Turbine tripped from 17 percent due to high vibrations.
At 8:00 a.m.
a leak at the C Feedwater Heater Drain Cooler Bypass Valve was identified, and it could not be isolated.
At 1:38 p.m.
the B Auxiliary Boiler experienced an arc over causing a voltage transient which resulted in a trip of the B Recirculation Pump.
The A recirculation pump had been secured previously for maintenance.
In response to the trans-ient the operators manually scrammed the reactor from
percent power and shutdown to Condition 4.
(See Detail 3.3).
3.3 Unit 2 Reactor Scram Due to Condensate Pi in Crack On March 18, 1985, a stator cooling system leak was discovered on the Main Generator beneath the neutral connection to the grounding trans-former.
The Unit was operating at 100% power.
The licensee decided to reduce power, shutdown the Main Turbine and repair the stator cooler leak.
At 6:00 p.m.
March 20, the power reduction began.
At 7:06 a.m.
on March 21, while making preparations to shutdown the Main Turbine, the Main Turbine tripped from 17% power on high vibration.
At 8:00 a.m.,
a leak was discovered at the feedwater heater drain cooler inlet bypass valve HV-20659C.
Its packing was damaged and other damage to piping and valves in the area was noted.
The opera-tors made several attempts to isolate the leakage, but due to motor operator damage, the leak was not isolable from the condensate sys-tem.
The licensee decided to perform a reactor shutdown to perform the condensate system repairs.
Prior to shutting down the reactor, at 1:38 p.m.
March 21, the
"B" Auxiliary Boiler "flashed-over" causing a
sever e voltage transient.
During the transient the
"B" Recirculation Pump, the Reactor Water Cleanup Pumps, the off-gas system, and other systems tripped, the
'A'ecirculation Pump was previously secured for preventive maintenance.
In response to the transient, the operators manually scrammed the reactor from 14% power.
The Unit was depressurized and reached Con-dition 4 at 4:22 a.m.
March 22, 198 Investigations of the condensate system piping found that significant damage had occurred in the area of the 2C cooler drain bypass piping.
Three hangers were damaged.
The motor operator and valve for the inlet bypass isolation were damaged, and the weld at the bypass line connection to the
'C'ondensate Header (6 inch line) was cracked.
After review of the event the licensee determined that during the power reduction process, excessive flow had been present through the orifice in the bypass line causing the vibration and subsequent dam-age.
Although some procedural precautions had been inplace, addi-tional training was conducted by the licensee.
Nuclear Plant Engi-neering is evaluating the need for additional restraints on the by-pass line.
During the shutdown, repairs were completed on the condensate system and the stator cooling leak.
Additionally, due to failures during the shutdown, repairs were performed on the 'D'nboard MSIV (2FO 220),
the 'A'ource Range Monitor, and the 'E'RV Acoustic Monitor.
These repairs required deinerting primary containment.
After completion of repairs, the reactor was started up and made critical at 11:43 p.m.
March 24, 1985.
4.0 Licensee Re orts 4.1 In Office Review of Licensee Ev'ent Re orts'he inspector reviewed LERs submitted to the NRC:RI office to verify that details of the event were clearly reported, including the accur-acy of description of the cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup.
The following LERs were reviewed:
Unit
"* 85-001/00, SGTS Start on Refuel Floor High Radiation Signal
- 85-002/00, Diesel Generator Failure
- 85-003/00, Reactor Scram Caused by Ice in Isophase Bus Ducting
" 85-004/00, B and D Diesel Generators Inoperable 85-005/00, Simulated Thermal Power Time Constant not Included in Surveillance Test 85-006/00, Monthly Composite Sample Analyses Not Completed Due to Personnel Error 85/007/00, Reactor Water Cleanup Isolation
Unit 2
"~ 85-001/00, HPCI Stop Valve Sheared 85/002/00, ESF Actuation Due to Loss of RPS Bus 85-003/00, Unit
Reactor Scram Due to High Turbine Vibration 85-004/00, ESF Actuation RMCU Isolation Valves Closed 85-005/00, Vacuum Breaker Surveillance Test Completed Late 85-006/00, Unanticipated ESF Actuation, RHR Shutdown Cooling Valves
"* 85-007/00, SGTS Train Inoperable During Containment Purge 85-008/00, Loss of Single Train Safety System and 'B'oop of Core Spray
- " 85-009/00, Reactor Mater Level Switches Out of Tolerance
- Previously discussed in Inspection Report 387/85-01; 50-388/85-01
- 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 inDetai 1 4. 1),
the inspector verified the reporting requirements of
CFR 50.73 and Technical Specifications had been met, that appro-priate corrective action had been taken, that the event was reviewed by the licensee, and that continued operation of the facility was conducted in accordance with Technical Specification limits.
4.2. 1 LER 85-009 Reactor Mater Level Switches Out of Calibration on Unit,2 On February 12, 1985, while performing the 18 month cali-bration on reactor vessel level switches, three switches were found to be outside the allowable Technical Specifica-tion trip setpoints.
Two of the three switches actuate the RPS scram on low vessel water level (Level 3) and the other provides a
RCIC turbine trip on high level (Level 8).
In-strument and Controls (I&C) technicians determined that the switches had drifted out of tolerance and they were recali-brated.
The inspector discussed this occurrence with the IKC Fore-man and reviewed the following documents:
SOOR 2-85-049, dated February 15, 1985 Surveillance Procedure SI-280-305, Revision 1 and test results dated February 12, 1985 and November 13, 1984 These instruments are Barton Model 288A level switches.
There have been a
number of previous occurrences of this type level switch drifting outside its allowable trip set-point, (see Inspection Report 50-387/84-07; 50-388/84-08 dated May 1, 1984), although these particular switches have not previously experienced excessive drift.
Due to poten-tial instrument drift problems, the licensee has been per-forming the
month calibration of level switches on a
quarterly basis.
The inspector reviewed the previous cali-bration dated November 14, 1984, which did not show drift-ing problems on the affected level switches.
I&C also per-formed a calibration instead of the monthly functional in March 1985.
One switch, for Level
LIS-B21-N024D was found outside the
"AS FOUND" tolerance, but still within the acceptance criteria.
I&C intends to perform another calibration during the next scheduled functional test.
I&C is also reevaluat;ng the drifting problems on Barton 288A switches to determine if other actions can be taken to en-sure the switches do not drift beyond allowable trip set-points.
LER 85-001 Unit 2 HPCI Sto Valve Sheared This LER describes an occurrence on January 12, 1985, when, following startup test on HPCI, the operators were unable to trip the HPCI turbine by pushing the trip pushbutton.
HPCI was stopped by closing the steam supply isolation valve.
An investigation revealed that the hydraulically actuated turbine stop valve actuator shaft was broken at the valve shaft to actuator shaft coupling.
The shaft broke because the valve position indication bracket had come loose and wedged itself between the actuator housing and the shaft coupling.
The position indication for this valve is used with the GE Transient Analysis Recording System and is not required for system operability.
The actuator shaft was replaced and HPCI returned to service on January 13.
The inspector examined the position indicator bracket on the failed stop valve, reviewed SOOR 2-85-013, and dis-cussed this occurrence with the system engineer.
The con-trol valves, stop valves, vessel injection and steam ad-mission valves on both HPCI and RCIC use external brackets to hold position indicating units.
The licensee examined
the remaining brackets and determined that the actuation of the valve would probably not be affected even if any of these brackets came loose because they are not located be-tween the valve and the actuator.
The inspector also exam-ined the brackets on Unit
RCIC and noted that they were of a different configuration than that used for the HPCI stop valve.
The bracket on Unit 2 HPCI stop valve was re-designed to provide a
more positive method of securing it to the shaft coupling.
Requests for modificaion have been prepared to evaluate and redesign, as necessary the remain-ing Unit 1 and 2 position indication brackets.
LER 85-007 Standb Gas Treatment S stem Train Ino erable This LER describes an event on January 30, 1985, when the
'A'rain of SGTS was being used to purge the Unit 2 con-tainment.
Unit
Technical Specifications (TS)
require both trains of SGTS be operable when the purge system is in use.
This requirement was verified prior to commencing the purge.
Sometime during the purge, the 'B'GTS heater failure alarm annunciated.
Operations personnel attributed the alarm to blocking associated with maintenance on the
'B'rain.
The 'B'rain inlet damper (HDM 07553B)
was blocked open for motor replacement, but the 'B'rain was considered operable.
'hen the heater failure alarm occurred, Operations declared the 'B'GTS train inoperable.
However, they failed to recognize that both SGTS trains were required by Technical Specifications to be operable to continue purging.
Hence, purging continued until approximately 11:08 p.m.
January 30.
The actual cause of the heater fai lure alarm was later de-termined to be due to the system configuration.
With the
'A'rain in service and the 'B'rain inlet damper open, sufficient flow was established to makeup the low flow switch in the 'B'ogic.
Since the heaters were not in service (heaters come on when the fan is running),
proper delta temperature conditions were not established and the
'B'GTS train was locked out on heater failure.
The inspector discussed the event with technical staff per-sonnel and reviewed SOOR 2-85-034 and 1-85-045, Ventilation diagram VC-175, Electrical Schematic E-201, Sheet 8,
and Operating-Procedure OP-273-001 for containment purge.
The Operating Procedure included prerequisites that both SGTS trains be operable whenever containment is purged.
The
Unit
TS are different from Unit 2 in that both SGTS are not required during purging of Unit 1.
This may have con-tributed to the operator's not recognizing that purging should have been stopped.
A TS change was submitted in May 1984 to make Unit
and
TS alike, and the amendment to implement that change is expected to be issued within the next two months.
Additionally, this event will be reviewed by all operations personnel.
This is a
licensee identified violation which meets the criteria of
CFR 2 Appendix C.
Hence, the NRC will not issue a notice of violation.
LER 85-001 SGTS Start on Refuel Floor Hi h Radiation
~Si nal This LER discusses a
Zone III (Refuel Floor) ventilation isolation and coincident auto start of the Standby Gas Treatment System (SGTS)
and Control Room Emergency Outside Air Supply System (CREOASS)
which occurred during the re-moval of the Unit 1 steam dryer.
On February 13, 1985, with Unit 1 in Operational Condition 5 for its first refueling outage, the licensee was removing the steam dryer from the reactor vessel.
The maintenance procedure used to move the dryer, MT-062-007,
"Steam Dryer Removal and Installation",
included steps for the instal-lation of jumpers in the refueling floor wall exhaust and high exhaust trip units.
The jumpers were installed to prevent a
Reactor Building isolation during the dryer re-moval.
Isolations had occurred on previous movements due to radiation streaming in the vicinity of the Refueling Floor Wall Exhaust radiation monitors.
(See followup of Inspector Followup Item 387/83-11-02 in Resident Inspection 50-387/84-38; 50-388/84-47).
Unit 1 Technical Specification Table 3.3.2-1 does not re-quire the affected sensors be operable during Operational Condition 5, except during core alterations and operations with a
potential for draining the reactor vessel.
The dryer removal process does not involved core alterations or an operation with a
potential for draining the reactor vesse ~+ ~
When the steam dryer removal was completed, the jumpers were removed in accordance with the maintenance procedure.
Within two minutes, Zone III had isolated on an exhaust duct high radiation signal and the SGTS and CREOASS started.
Operations personnel directed that the jumpers be reinstalled.
The maintenance procedure did not require a
radiation survey of the area or a review of the instrumen-tation prior to the jumper removal.
After the jumpers were reinstalled, the ESF systems were restarted.
Stack par-ticulate, iodine and noble gas monitor data showed no abnormal release rates.
In addition to the above event, two additional similar re-portable occurrences took place in March.
On March 13, 1985, a Refueling Floor High Exhaust Radiation Monitor Iso-lation occurred while draining the Unit 1 reactor cavity during outage activities.
The reactor was defueled and the cause of the trip was attributed to shine from contaminants on the bottom of the reactor cavity.
No airborne activity was detected.
General Area radiaition levels are 10 MR/HR.
On March 23, 1985, the Refueling Floor High Fxhaust Radia-tion Monitors tripped again during radiography being per-formed on the refueling floor.
The radiography had caused high radiation fields in the vicinity of the radiation monitors.
As stated in LER 85-001, licensee actions to prevent recur-rence of the Zone III isolations and SGTS and CREOASS starts are still being investigated and will be provided in an update to the LER.
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 deter-mine that the report included the required information; that test results and/or supporting information were consistent with design predictions and performance specifications;, that planned corrective action was adequate for resolution of identified problems, and whet-her any information in the report should be classified as an abnormal occurrence.
The following periodic and special reports were reviewed:
Monthly Operating Report - January 1985 Monthly Operating Report - February 1985 The above reports were found acceptabl,0 Monthl Surveillance and Maintenance Observation 5. 1 Surveillance Activities The inspector observed the performance of surveillance tests to de-termine 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 pro-cedure; 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:
- RE-OTP-012, Calibration of LPRMs, performed on Unit 2 on March 7,
1985 S0-264-001, Recirculation Pump Discharge Valve and Bypass Valve Operational Test, performed on Unit 2 on March 21, 1985 No unacceptable conditions were identified.
5.2 Surveillance Procedure Review The inspector conducted a review of surveillance procedures and sur-veillance results associated with the Standby Gas Treatment System (SGTS).
This review was conducted to ascertain whether the survei 1-lances are being performed properly, with approved procedures and that the procedures correctly implement Technical Specification re-quirements.
The following items were reviewed:
Technical Specification Sections 4.6.5. 1 and 4.6.5.3 S0-070-001, Revision 2, Monthly Operational Check of Standby Gas Treatment System, and test results dated February 9, 1985 SO-070-002, Revision 2,
18 Month Pressure Drop Verification of the Standby Gas Treatment System, and test results dated February 8, 1985 S0-070-004, Revision 0,
Month Standby Gas Treatment System Filter Cooling Mode Operability Test, and test results dated February 4,
1984
S0-170-006,Revision 0,
18 Month Secondary Containment Verifica-tion Check Zone I and Zone III, and test results dated February 14, 1984 S0-270-006, Revision 1,
18 Month Secondary Containment Verifica-tion Check Zone II and Zone III, and test results dated February 19, 1984 S0-070-007, Revision 1,
18 Month Secondary Containment Verifica-tion Check Zones I, II and III, and test results dated February 13, 1984 SE-070-009, Revision 1,
SGTS HEPA Filter and Charcoal Absorber In-Place Leak Test and test results dated August 22, 1984 SE-070-010, Revision 1,
Radioactive Penetration and Retention Test for the SGTS Charcoal Assembly and test results dated September 21, 1984 This review concluded that surveillance testing of the SGTS meets the Technical Specification (TS)
requirements.
One procedure, SO-170-006, used for verifying secondary containment integrity of Zones I
and III contained an incorrect acceptance criteria.
The Technical Specification requirement is that, with Zone Ii operable, one train of SGTS must be able to drawdown Zones I and III to greater than or equal to 0.25 inches vacuum water gauge in less than 15 seconds.
The acceptance criteria in SO-170-006 incorrectly-specified the drawdown time as 60 seconds which was the requirement prior to Amendment 21 to the Technical Specifications (issued March 23, 1984).
Since issuance of Amendment 21, SO-170-006 had not been performed and the licensee indicated that this procedure is being revised and that this acceptance criteria will be corrected.
SO-170-006 is an option-al test which may be performed in lieu of a three zone drawdown test.
The licensee performed S0-070-007, which is the three zone drawdown test, instead of SO-170-006 to demonstrate the drawdown requirement for SGTS.
6.0 Refuelin Outa e
6. 1 Refuelin Outa e
Summar The Unit 1 first refueling outage began on February 9,
1985.
The unit reached cold shutdown on February
and core off load began February 18.
Some delays were encountered early in the refueling due to water clarity and there were problems inserting blade guides when a recirculation pump was running to support Induction Heating Stress Improvement ( IHSI).
Other problems were encountered when trying to
use Fuel Loading Chambers (FLCs) to get onscale source range monitor-ing (SRM) indication when fuel bundles were removed around the SRMs.
(See Detail 6.2).
These problems did not create major delays and defueling was completed on March 3, two days ahead of schedule.
As the core was being defueled, 24 control rod drives were removed and new drives installed (after the surrounding fuel bundles were re-moved)
(See Detail 6.3).
During the refueling,,
the inspector ob-served activities on the refuel floor and in the control room.
The inspector reviewed Procedure RE-081-032, Refueling Operations, and verified that activities were conducted in accordance with that pro-cedure.
The inspector also reviewed shift logs and a
special sur-veillancee log book which was maintained in the control room to verify compliance with T.S. refueling requirements on a shiftly basis.
The inspector identified no unacceptable conditions during these reviews.
Major outage work to date has consisted primarily of work on Division II systems and balance of. plant work.
Major work items being per-formed include:
replacement of A and B loop RHR throttling valves 1F017A and B with valves having better throttling characteristics; local leak rate testing; installation of Reg.
Guide 1.97 instrumen-tation; Inservice Inspection; Induction Heating Stress Improvement of 136 welds in the Recirculation, RHR and RMCU systems; replacement of wetwell/drywell vacuum break r internals; disassembly and inspection of the main generator rotor, HP turbine and major turbine valves; implementation of modifications to the ESW system to correct single failure and waterhammer concerns; environmental qualification upgrades and numerous other work items.
6.2 Fuel Loadin Chamber FLC Problem During Unit 1 core defueling, the licensee experienced problems using fuel loading chambers (FLCs)
in place of source range (SRM) detec-tors, when insufficient fuel remained in the core to enable the SRMs to read greater than three counts per seconds (cps).
On February 25, with about one-half the core off loaded, Instrument and Controls (I&C) technicians connected a
FLC to the 'D'RM and placed it incore quadrant D.
The 'O'LC was declared operable on February
and fuel movements were conducted in this quadrant.
On February 27, a
FLC was connected to the 'A'RM and moved into core quadrant
'A'.
I&C had trouble obtaining satisfactory response levels on both FLCs because the counts were low.
I&C swapped the FLCs and performed troubleshooting in an attempt to obtain satisfactory response, how-ever count rates remained at low levels (less than approximately 20).
On March 3,
while removing the last four fuel bundles from the
'D'uadrant, the shift observed FLC counts increasing as the bundles were removed.
Counts increased from 21 to 29 counts.
As the last bundle was removed, the 'D'LC increased to 500 cps.
Defueling was halted and I&C investigated this unexpected detector response by mov-ing the 'D'LC from the edge of the core to a position adjacent to
ea
the fuel while monitoring FLC response.
Response increased from
cps at the core edge to 430 cps as the detector was moved closer and then decreased to 26 cps adjacent to a fuel bundle.
Both the A and DFLCs were moved to various locations with similar responses, i.e.
counts increased when moving towards fuel bundles, but decreased when adjacent to a bundle.
The licensee concluded that the FLCs saturate when too near a fuel bundle.
For the remainder of the defueling, the licensee moved the FLCs to different locations to ensure they weren'
saturated prior to moving fuel bundles.
Defueling was completed March 5.
No other FLC's were used.
The inspector reviewed this occurrence to determine how FLCs were calibrated and determined to be operable, and the nature of the FLC response problems.
The inspector discussed this occurrence with licensee management, IKC, Reactor Engineering and technical staff and reviewed the following documents:
Reactor Engineering, Unit 1 and Shift Supervisor Logs, Work Authorizations (WAs) Nos.
556571, 556563, and 556290, used for calibrating the FLCs, Refueling Floor Shiftly Surveillance Log, Attachment A to RE-081-032, GE Field Engineering Memo Nos.
72-11 and 72-16, concerning assembly and operational adjustment of fuel loading chambers, GE Startup Test Instruction STI-3, Fuel Loading dated August 1979, Test results of Unit 2 Startup Test 3. 1, Revision 3, Installa-tion of Neutron Sources and Fuel Loading Chambers.
The FLCs used at Susquehanna are Boron 10 proportional counters.
ILC personnel calibrated these detectors by performing noise and signal curves using guidance provided in GE Field Engineering Memo 72-11.
They were calibrated using a
Work Authorization.
No procedure exis-ted to perform this calibration.
The noise curves were taken in the spent fuel pool, near an irradiated fuel assembly.
During the cali-bration, IKC was unable to establish a
10 turn difference in discrim-inator settings for the noise and signal curves as specified in Memo 72-11.
The turns difference was seven for the 'A'LC and 'D'LCs.
I&C indicated that they contacted GE about not obtaining 10 turns difference and GE indicated it was not a problem.
The high voltage setting for both detectors was 675 volts.
The 1972 memo also indi-cates that it is essential to verify that counts saturation does not occur before trip setpoints are reached.
The memo indicates that this check be done by withdrawing control rods adjacent to the detec-torss in order to reach a flux level at least 50% greater than the
a e>
~
trip setpoint.
A saturation check was not performed on the FLCs at Susquehanna.
IAC personnel indicated that when these FLCs were used during initial fuel loading, they were assisted by GE personnel who did not indicate that a saturation check was necessary.
The inspec-tor also examined the noise and signal curves taken during initial fuel load of Unit 2.
The turns difference in discriminator setting was greater than,10 during that calibration.
The cause of the inadequate FLC performance is apparently related to the gamma field when the FLC is near an irradiated fuel bundle.
Us-ing the pulse height di scriminator, in the SRM instrumentation, it is possible -to discriminate against gammas; but, since the noise curve is generated away from fuel bundles and the discriminator set-ting is only slightly higher than that determined by the noise curve, no attempt is made to discriminate against gammas.
It appears that it was intended that the FLC be used only during initial fuel loading when no gamma field exists.
In response to the inspector's concerns, the licensee agreed to de-velop a
procedure for FLC setup and operational checkout.
The in-spector also expressed concern to the station superintendent about the viability of using FLCs in an irradiated core.
The station superintendent indicated that the licensee would pursue other methods of obtaining onscale indication besides use of FLCs.
This matter remains unresolved pending further review.
(387/85-09-03)
6.3 Control Rod Drive Mechanism Removals During removal of the second Control Rod Drive (CRD) from the reactor pressure vessel at 12:40 a.m.
on February 22, 1985, six out of eight flange bolts were inadvertently removed from a CRD not designated for removal.
The CRO was not uncoupled from its control rod and two fuel assemblies remained in the cell surrounding the affected CRD.
Technical Specification 3.9. 10.2 states that any number of control rods and/or control rod drive mechanisms may be removed from the core and/or reactor pressure vessel provided that the following require-ments are satisfied:
reactor mode switch locked in Shutdown or Refuel at least two SRM's operable (in the affected and adjacent quad-rant)
all other control rods either inserted or have the surrounding four fuel assemblies removed
the four fuel assemblies surrounding each control rod or CRD to be removed are removed.
With the requirements of T.S. 3.9. 10.2 not satisfied, CRD removal is to be suspended and action is to be initiated to satisfy the above requirements.
During the day shift on February 21, CRD 02-23 was uncoupled from its control rod and released by Operations for removal.
On the following night shift, the workers underneath the reactor vessel in bubble suits, after completing an uncoupling verification on CRD02-23, be-came disoriented after exchanging tools for the next step in the pro-cedure, and began removing the flange bolts for CRD 02-27.
The supervisor was unable to detect the error on his remote video monitor due to the limited camera coverage.
Six out of eight flange bolts were removed before the workers realized they were working on the incorrect mechanism.
The crew noted CRD 02-27 was incorrect because the position indicator probe (PIP)
was still connected.
The PIP had been previously removed from CRD 02-23 to facilitate the installation of the removal strongback.
The crew immediately reported the error to their supervisor, who relayed the information to the Shift Super-visor.
LCO 3.9. 10.2 was entered because fuel remained in positions 01-28 and 03-26, while bolts were removed on CRD02-27.
The six bolts were replaced and further CRD removal evolutions were suspended by the Shift Supervisor.
The licensee approved procedure change approval form (PCAF) 1-85-0145 on February 22, which added a caution in Maintenance Procedure MT-055-003, Control Rod Drive Removal, to reverify the CRD serial number with supervision via the communication system prior to unbolting the flange.
Additionally, stricter controls were placed on the commun-ication requirements between the supervisor and worker, so the super-visor could read the procedural steps to the workers and the workers could keep the supervisor informed of the work completed.
Training sessions were held to discuss the procedure revisions and the previous event.
Streamers were also placed on the released CRD's to aid in their identification.
After completion of the corrective actions the licensee continued with CRD replacements on February 25, 1985.
6.4 Faci lit Modification Activities The inspector observed portions of selected modification activities to determine that:
Limiting Conditions for Operation were met while components or systems were removed from service; required administra-tive reviews and approvals were obtained prior to initiating the work; the installation conformed to the drawings and other design documents; and activities were conducted using formal work control procedures and gC hold points were established where require r~~(a
Portions of the following activities were observed:
ADS Manual Inhibit Switch Logic Modification (PMR 82-523), per-formed in Unit
Lower Relay Room panel 1C631 on February 26, 1985.
ESW Mater Hammer Modification (PMR 82-592),
performed in the ESSW Pumphouse, Control Structure and Reactor Building on March 19 - 21, 1985.
The modification activities observed were performed in accordance with the applicable requirements and found acceptable.
6.5 Crack Indications on In Vessel Com onents
. During inservice inspection ( ISI) in the Unit 1 reactor vessel, crack indications were discovered in a
number of components.
The most significant indications were discovered on one of four steam dryer support blocks, which is welded to the vessel, and the steam dryer assembly.
The licensee prepared NCRs 85-0113 and 85-0117 to document the indications on the dryer and support block respectively, and formed a task force to further evaluate these problems.
The present status of these problems is di'cussed below:
Steam Dr er Su ort Block The support block located at the 184 de-gree azimuth showed a
large crack indication which extended across the top and down both sides of the block.
The block is approximately
inches by 5 inches by 11 inches in dimension, is made of inconel and is welded to an inconel plate which is welded to the vessel.
The block is one of four which support the steam dryer (the dryer seismic supports rest on these blocks).
The crack extends into the weld but has been verified by ultrasonic testing (UT) to not extend into the inconel plate base metal.
The cracking was confirmed by UT and pene-trant (PT)
testing.
The licensee has extracted samples of the cracked material and the samples are presently under evaluation at GE laboratories in California.
The cause of the crack is presently un-known. It was suspected that the dryer was rocking on these blocks but a dryer fitup test did not support this theory.
The licensee intends to cut/grind out the old block and reweld a
new block.
Vis-ual examination (and PT of the block at 4 degree azimuth) did not indicate problems with the remaining blocks.
Steam Dr er Assembl Visual examination of the steam dryer revealed fourteen indications, most of which are located on the upper support ring, the horizontal surface where the dryer block is welded to the upper support ring and in a previously repaired seam weld on a dryer bank.
The dryer has been moved to the Unit 2 dryer separator pit where the licensee will be performing additional examinations to determine the extent of the cracking and if repair is require Other Crack Indications The licensee identified crack like indica-tions in the C
and 'D'ore Spray (CS) junction boxes and one noz-zle in the 'A'eedwater sparger.
Upon closer examination the indi-cations in the 'C'S junction box and the feedwater sparger have been dispositioned as non relevant.
The licensee is also evaluating some indications in the top guide and the upper sleeve portion of three dry tubes.
Some further examination is planned.
The lead responsibility for disposition of these issues has been transferred to NRR.
The inspectors and the Region are closely monitoring the progress of these in-vessel problems in support of NRR.
These matters will be further reviewed.
(387/85-09-04)
6.6 S ill in Unit 1 Dr well During the performance of Induction Heating Stress Improvement (IHSI)
on the A Recirculation. (recirc)
loop on March 7,
1985, a spill of approximately 4000 gallons of reactor coolant occurred in the Unit
drywell.
In order to establish cooling flow for IHSI on welds in normally blanked pipe connections, a
temporary pump system was at-tached in parallel with the 'A'ecirc pump and on the pump side of the recirc suction and discharge valves'he temporary system was designed and had been tested for 150 psig pressure.
The system in-cluded some hard piping as well as two 150 psig hoses and hose con-nections.
The temporary system was in operation for about
hours when the hose in the pump discharge line slipped off its hose con-nection causing the spill.
Normally, the spill would have been limited to the contents of the temporary loop and the volume between the 'A'ecirc loop suction (1F023A)
and discharge (1F031A)
valves.
However, the recirc suction valve had been inadvertently left open and hence, the reactor vessel (which was defueled)
and the reactor cavity (which was full) were open to the temporary loop.
Operations received a drywell floor drain sump Hi-Hi Alarm and then noticed level in the floor drain sump level recorders was pegged high.
Oper-ations then shut the recir c suction valve stopping the spill.
All water drained to the floor drain sumps and was processed by radwaste.
The drywell was evacuated when the spill occurred.
No one was con-taminated.
The inspector reviewed this event to determine the cause of the mis-positioned recirc suction valve, the adequacy of procedures and the temporary system, and the radiological consequences of the spill.
The inspector discussed the event with licensee personnel and re-viewed the following documents:
SOOR 1-85-094 dated March 7, 985 Procedure TP-164-007, Temporary Pump for Reactor Recirculation IHSI Process, Revision 0, dated March 5, 1985
IWKa
Procedure TP-161-003, IHSI Process, Reactor Mater Cleanup; Re-vision 0, dated February 6,
1985 Area Survey Maps for Unit 1 Drywell Elevation 704 taken on March 6 and March
P&ID M-143, Reactor Recirculation The cause of the mispositioned recirc suction valve was due to an inadequate temporary procedure change.
TP-164-007 Step 6. 1.2 directs the operator to close the valve F023A (recirc suction).
On March 6, PCAF 1-85-206 to TP-164-007 was approved to provide a flowpath for RWCU from the A recirc loop to permit IHSI to be performed on RMCU welds in accordance with TP-161-003.
TP-161-003 required F023A to be opened to provide the flowpath for RWCU, but the PCAF did not require F023A to be reclosed when TP-164-007 was reentered.
The licensee issued Revision 1 to this TP which eliminated this PCAF and provides an extra check on the position of F023A.
'With respect to the adequacy of the temporary system, the system was rated for 150 psig and pressure tested to about 140 psig.
The licen-see stated that the discharge pressure at the pump when running was about 100 psig.
The cause of the hose connection giving way is prob-ably due to vibration or pressure oscillations.
The licensee reeval-uated the system design and substituted hoses with higher pressure ratings and stronger clamps.
The inspector examined the pump head curves.
The shutoff head of the pump was about 70 psig and the head of water from the cavity would add an additional 48 psig.
Hence, the maximum pressure seen on the temporary loop would be expected to be less than 150 psig.
Area survey maps after the spill indicated smear
. levels up to
mRad/hr.
Extensive deconning was performed and smear levels were returned to near normal.
The modified temporary system was used to support IHSI on the 'A'nd 'B'ecirc loops without further inci-dent.
The inspector had no further concerns.
7.0 Confirmator Action Letter Followu Based on an October 16, 1984 meeting held at NRC Headquarters in Bethesda, Maryland concerning failures of ASCO scram pilot solenoid valves, and on discussions with the resident inspectors, Confirmatory Action Letter (CAL)
84-18 was issued by NRC Region I
on October 17, 1984.
The CAL describes corrective actions that the licensee had taken or planned to take with respect to the scram pilot solenoid valve problems.
The licensee respond-ed to the CAL in letters dated November 19, 1984 and January 9,
198 All scram pilot solenoid valves in Units
and 2 were rebuilt with disc holder subassemblies fabricated with Viton-A materials.
The back-up scram valve disc holder subassemblies were also changed to Viton-A material.
(Special Inspection Report 50-387/84-35; 50-388/84-44).
The licensee conducted individual rod scram testing on both Units 1 and
and were demonstrated operable as required by Technical Specification sur-veillance Requirement 4. 1.3.2.6.
(Resident Inspection Report 50-387/
84-34; 50-388/84-41).
The licensee submitted a program for monitoring SPSV operability and re-sponse times, as well as acceptance criteria for returning to the normal surveillance requirements, to NRC Region I
in letter PLA-2361 dated November 19, 1984.
This program was reviewed and approved by the NRC.
The special survei llances were conducted at six week intervals and por-tions of the tests were witnessed by the inspectors.
The test results were also reviewed, and all operability acceptance criteria were satis-fied.
The tests were performed for two intervals, without any anomalies, and the licensee returned to the normal quarterly surveillance interval.
The licensee provided a
description of the General Electric (GE)
and Franklin Research Center (FRC) evaluation program and the results to NRC Region I.
The short term evaluation results were submitted to the NRC on November 19, 1984 and the final results were submitted December 7,
1984, and January 24, 1985.
The results were reviewed by NRC Region I.
Both evaluations concluded that the failure of the SPSV's was due to ad-hesion of the polyurethane disc holder subassembly seat to the exhau t port orifice, blocking the solenoid exhaust path.
The FRC report cited the probable failure mechani sm as hydrolytic decomposition of the poly-urethane seats due to a combination of water and elevated temperature.
It asserts that water vapor was present in the system and that device opera-ting temperatures approached the contaminated system design limit of 140 degrees F.
The GE report indicates the failure was caused by the contam-ination of the seals with a synthetic diester oil (SDO),
a plasticizer.
Both studies recommended the polyurethane seats be replaced with a mate-rial capable of operating at high temperatures and in the presence of con-taminants (oil and/or water).
GE recommended Viton-A as the replacement material.
In qualifying ASCO solenoid valves for Class 1E service, GE has shown that Viton-A has significantly better temperature (400 degrees F)
and contaminant resistance than polyurethane.
As part of its investigation, the licensee performed air sample analysis of sections of the CRD Instrument Air Header and no significant traces of contaminants were identifie '~e
During repair/changeout of upstream air isolation valves (116)
to the scram pilot solenoid valves, licensee technicians noticed that the new replacement valves were lubricated with grease.
guestions were raised as to the possibility of this grease causing the softening of the seat mate-rial in the SPSVs.
The Technical Staff forwarded a
new valve for chemical analysis of the lubricant and found it had a synthetic diester oil base.
The licensee currently plans to replace the brass cock isolation valves with ones without the SDO base lubricant and perform a freon flush of the piping system.
Additionally, red brass portions of the piping system will be reworked to remove any possible contaminants on the pipe threads.
The repairs/replacements will be performed under PMR 85-1004 for Unit
and 85-1005 for Unit 2.
Based on the information provided to NRC Region I, and resident inspection review, the licensee corrective actions described in CAL 84-18 have been completed.
8.0 Exit Interview On March 29, 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 March 29, it was determined that this report does not contain information subject to 10 CFR 2.790 restriction l
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