IR 05000387/1984038
| ML17139C971 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 02/18/1985 |
| From: | Jacobs R, Plisco L, Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17139C969 | List: |
| References | |
| 50-387-84-38, 50-388-84-47, NUDOCS 8503070279 | |
| Download: ML17139C971 (28) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION Region I 50-387/84-38 Report Nos.
50-388/84-47 50-387 (CAT C)
k
.
~R-NPF-14 License Nos.
NPF-22 Licensee:
Penns lvania Power and Li ht Com any 2 North Ninth Street Allentown Penns lvania 18101 Facility Name:
Inspection At:
Sus uehanna Steam Electric Station Salem Townshi Penns lvania Inspection Conduc ed:
November
1984 Januar
1985 Inspectors:
H. Jacob
, Senior Resident Inspector date Approved By:
R.
Pl sco Resident Inspector
. Strosnider, Chief, Reactor Projects Section 1C, DRP date zing~ s~
date Ins ection Summar
Areas Ins ected:
Routine resident inspection (U1-175 hours, U2-107 hours)
of plant operations, maintenance and surveillance, licensee events, open items,
'ire protection program, cold weather preparations, nitrogen makeup line over-pressurization and scram. discharge volume vent and drain pilot valve inoper-abi l ity.
Results:
Unit
precommercial outage was well planned and conducted (Detail 5.2).
Fire protection program meets NRC requirements with two exceptions, noted below (Detail 7.0)-.
Two violations were identified in the fire protec-tion area:
inadequate control of combustible gas cylinders (Detail 7. 1.2)
and four fire brigade members had not received all required training (Detail 7.3).
8503070279 850227 PDR ADGCK 05000387 G
DETAILS 1.0 Followu on Previous Ins ection Items Closed Violation 387/82-40-01
No Surveillance Records For Reactor Core Isolation Coolin RCIC S stem On November 19, 1982, the inspector noted that no record of suppres-sion pool average temperature was generated to verify temperature to be less than or equal to 105 degrees F at least once per five minutes during RCIC testing, although required by Technical Specifications 4.6.2. 1.b. 1 and 6. 10. 1.d.
In response to the violation, the licensee revised the applicable procedures to provide a
log sheet for recording suppression pool water temperature for the cases where heat is added to the suppres-sion chamber.
In addition, each operating shift reviewed the vio-lation.
The inspector reviewed the rosters for each shift briefing of the violation and the surveillance procedure S0-159-010, Suppression Chamber Average Water Temperature Verification, Revision 0, which is utilized to record the temperature during testing.
The applicable test procedures, (i.e.
S0-150-002, Quarterly RCIC Pump Flow Verifica-tion),
have been revised to include a step requiring the performance of S0-159-010.
1.2 Closed Ins ector Followu Item 387/84-07-08
Emer enc Diesel Generator Failure Durin Testin In February, 1984, the Diesel Start Log was found to have inaccurate and unclear information, making it difficult to assess diesel sur-veillance test performance, and operating history.
The errors were corrected immediately.
On September 25, 1984, Operating Instruction OI-024-002, Diesel Gen-erator Start Log, became effective, and it revised the information required on the previous log sheets.
The revised instruction re-quiress more detailed information concerning each diesel start and clear instructions for completing the data.
Inspector monitoring of use of the new format has not identified any discrepancies.
1.3 Closed Unresolved Item 387/84-07-07 and 388/84-08-05
Deficiencies In FSAR Descri tion and Licensee Procedures In a previous inspection, several deficiencies were identified in the FSAR description and licensee procedures concerning onsite safety review committees.
Review of the FSAR and Administrative Directive AD-QA-102, Revision 5, Plant Operations Review Committee verified that the deficiencies had been correcte.4 Closed IE Circular 78-11 388/78-CI-11:
Recircul ation MG Set Overs eed Sto s
The inspector reviewed the test results from Unit 2 Startup Test ST-29.4, Revision 1, Verification of Recirculation MG Set High Speed Stops, which was performed October 9,
1984.
The startup test demon-strated that the recirculation pump MG set mechanical high speed stops were set at less than 105 percent rated core flow, thereby pos-itively establishing the setpoints of the mechanical stops as re-quired by the circular and Technical Specifications.
1.5 Closed Ins ector Followu Item 387/83-11-02
Reactor Bui ldin Ventilation Isolations The licensee determined that since the Reactor Building Ventilation isolation occurred due to radiation streaming in the vicinity of the Refueling Floor Mall exhaust radiation monitors while moving the steam dryer and moisture separator, a setpoint change would not be required.
The monitors setpoint was returned to less than or equal to 2.5 mR/hr; as required Technical Specification 3.3.2.
To prevent isolations in the future, Maintenance Procedure MT-062-007, Revision 0,
Steam Dryer Removal and Installation was revised to disable the radiation monitors prior to the movement of the steam dryer.
1.6 Closed Ins ector Followu Item 387/84-18-02
Unit 1 Hi h Heatu Rate On February 21, 1984, during Unit 1 startup, the heatup rate in re-circulation Loop B exceeded 100 degrees in a
one hour period accord-ing to the Heatup/Cooldown Log. It was later verified by other plant data that the heatup rate did not exceed 100 degrees per hour, but this was not determined unti 1 May 1984.
The licensee revised SO-100-011 and S0-200-011,
"Reactor Vessel Tem-perature and Pressure Recording" for Units
and 2 to:
1) require recording temperature parameters every 15 minutes instead of every
minutes during a heatup or cooldown; 2) require calculating the tem-perature difference with each recording; and, 3)
specify use of a
special log on the process computer to obtain the data.
Inspector review of S0-100-011, Revision
and S0-200-011, Revision 2 revealed no discrepancies.
2.0 Review of Plant 0 erations 2.1 0 erational Safet Verification The inspector toured the control room area 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 control room annunciators were reviewed.
Nuclear instrument panels and other reactor protective systems were examined.
Effluent 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 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, incident reports, and gA nonconformance reports.
The inspector also observed several shift turnovers during the period.
No unacceptable conditions were identified.
2.2 Station Tours The inspector toured accessible areas of the plant including the con-trol room, relay rooms, switchgear rooms, penetration areas, reactor and turbine buildings, radwaste building, ESSW pumphouse, Circulating Water Pumphouse, Security Control Center, diesel generator building, plant perimeter and containment.
During these tours, observations were made relative to equipment condition, fire hazards, fire pro-tection, adherence to procedures, radiological controls and condi-tions, housekeeping, security, tagging of equipment, ongoing main-tenance and surveillance and availability of redundant equipment.
No unacceptable conditions were identified.
3.0 Summar of 0 eratin Events 3.1 Unit
Unit 1 operated at or near 100 percent power for most of the inspec-tion period.
Scheduled power reductions were conducted throughout the period for control rod pattern adjustments and condensate demin-eralizer changeouts.
At 9:51 a.m.
on December 10, 1984, a power interruption to instrument bus lY218 resulted in a reactor power transient from 100 percent power to
percent power.
The instrument bus automatic transfer switch was unintentionally activated, causing a momentary power loss.
This resulted in the feedwater pumps and the 8 recirculation pump locking up at their pre-transient speed, and the A recirculation pump controller failed low.
Reactor vessel level reached a maximum of 50
k
inches before the operators manually tripped one feed pump.
Rapid and effective response by the control room operators prevented the reactor trip which would have occurred at
inches.
The unit was returned to 100 percent power at 4:50 a.m.
on December 11, 1984.
At 8:48 a.m.
on December 13, an individual control rod scrammed unex-spectedly while performing reactor protection system surveillance testing.
Control rod 30-39 scrammed from the fully withdrawn posi-tion when a
B division half-scram was inserted.
The operators immed-iately identified the condition when generator output decreased by 30 MWe, but no alarms were received.
Initial troubleshooting failed to identify a cause or reproduce the event.
The rod was returned to its original position at 9:28 a.m.
The scram pilot solenoid valve will be further evaluated to determine the fai lure mechani sm.
At ll:31 p.m.
December 16, control rod 34-19 drifted from the fully withdrawn position (Notch 48)
to notch position 40.
The rod was returned to its original position at 11:40 p.m.
At 2:31 a.m.
December 17, control rod 50-31 drifted to notch position 42, and was returned to position 48 at 2:37 a.m.
The licensee intends to repair these control rod devices during the first refueling outage.
On December 21, while attempting to add nitrogen to the drywell, mis-communications caused an overpressurization of the nitrogen makeup line when makeup was commenced before the valve lineup was completed.
The nitrogen makeup outboard isolation valve was damaged during the evolution.
During the investigation, the licensee performed a local leak rate test (LLRT) of the containment purge and vent valves and was unable to achieve test pressure.
Based on the test results, and the damaged valve, the unit was manually shutdown at 5: 13 p.m.
December
and reached cold shutdown at 11:20 a.m.
December 25.
(See Detail 9.0).
Unit 1 returned to criticality at 2:09 p.m.
December 29 after comple-tion of repairs to the containment purge and vent isolation valves.
Unit 1 continued power escalation, reaching full power on January 2.
On January 4, Unit 1 began the end of cycle power coastdown.
3.2 Unit 2 Unit
continued a
scheduled pre-commercial outage throughout the period.
Major activities performed during the outage include:
In-duction Heating Stress Improvement (IHSI), local leak rate testing (LLRT),
18-month surveillances, repairs to recirculation discharge valve stems, modifications to the Emergency Service Water System (ESW),
various valve repairs, and main condenser cleaning.
(See Detail 5.2).
Unit
began startup after the outage on January
and was made critical at 2:40 a.m. January.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 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
- 84-042/00, NgA Audit Identified Late Chemistry Samples 84-043/00, Auxiliary Boiler Arc-Over Caused Primary Containment Isolation
"~84-044/00, Rod Scram Time Measurements did not meet Technical Specification
~*84-045/00, Scram Discharge Volume Vent/Drain Valve Surveillance Completed Late 84-046/00, Fire Barrier Penetration Not Sealed Unit 2
"84-021/00, Turbine Trip/Reactor Scram on Moisture Separator
'B'rain Tank High Level
- 84-022/00, HPCI Inoperable With ADS Out of Service 84-024/00, SBLC Low Boron Concentration 84-025/00, Blocking Unanticipated Actuation of SGTS and CREOASS Due to 84-026/00, Fire Barrier Penetration Not Sealed 84-027/00, Fire Barrier Wrap Missing
- Further discussed in Detail 4.2.
- ~Previously discussed in Special Inspection Report 50-387/84-35; 50-388/84-4.2 Onsite Fol lowu of Licensee Event Re orts 4.2.1 LER 84-022 HPCI Ino erable With ADS Out of Service for Surveillance Testin Unit 2 This LER discussed an event which occurred on October 13, 1984 when the High Pressure Coolant Injection (HPCI) system and Automatic Depressurization System (ADS) were both in-operable for forty (40)
minutes.
This condition required entry into Limiting Condition for Operation (LCO) 3.0.3, which requires initiation of action to shutdown within one hour.
On October 10, 1984, the HPCI system was declared inoper-able due to high vibration detected during a
maintenance check of the HPCI bearings.
LCO 3.5. 1 was properly entered at 11: 15 p.m.,
which requires-all other Emergency Core Cooling Systems (ECCS)
The remaining ECCS and RCIC were operable during the period of HPCI inoperability, except for 40 minutes on October 13.
The ADS was declared inoperable during this period for the performance of a routine surveillance test of the RHR pump discharge pressure switches.
Technical Specification 3.3.3 currently requires ADS to be declared inoperable during this surveillance, and places the plant in a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shut-down LCO.
The ADS system was restored to operable status prior to the one hour action statement of LCO 3.0.3, and HPCI was returned to service at 12:15 p.m., October 13, 1984, after realignment.
4.2.2 The licensee plans to submit a
Technical Specification change to the NRC to provide relief from the present overly restrictive requirement.
This Technical Specification deficiency, which is generic in nature, was noted on June 24, 1984, in a
previous inspection and will remain open pending a
change to the Technical Specification (Inspector Followup Item 387/84-22-01, 388/84-28-01).
LER 84-021 Turbine Tri /Reactor Scram on Moisture Se arator B
Drain Tank Hi h Level This LER discussed a
reactor scram from 100%
power on September 30, 1984, due to a turbine trip on moisture sepa-rator 'B'rain tank high level during the performance of startup test ST 23.6, Maximum Feedwater Runout Capabil-ities.
During the testing, there was a rapid drop in the speed of the 'B'eactor feed pump, which resulted in a
reactor vessel level drop to
inches, initiating a
reactor recirculation pump runback.
During the subsequent pressure transient in the main steam system, the moisture separator
'B'rain tank level swelled beyond the high level turbine trip setpoint.
Two previous scrams due to high moisture separator drain tank level were reported in LER 84-017 (See Inspection Report 50-387/84-26; 50-388/84-33).
It was determined in the investigation for these two scrams that the drain valve in the associated crossaround piping had malfunctioned and a considerable volume of water had accumulated in the pipe.
Because of the two previous scrams, and the fact that the moisture separator drain tank level control system did not adequately respond to the September 30, 1984 transient, a
task team was established to evaluate the system operation and design.
After extensive testing and level control system adjustments, the team concluded that a contributing cause to the level trip was that the gain adjustment on the
'B'oisture separator level control valve controller was set too low, reducing the valve opening span to approxi-mately 45%.
Additionally, the drain tank emergency dump valves were not responding rapidly enough to prevent a
The level controllers were replaced and gains were readjusted and boosters were installed on the emergency dump valves to increase their response time.
Plant Modification Records (PMR)
84-3119A and 84-3119B, which added one 12 inch check valve in the drain line from the moisture separator drain tank to the feedwater heaters, were completed during the Unit
pre-commercial outage.
The check valves were added to reduce the quantity of water available to flash in the moisture separator during oper a-ting transients that cause pressure reductions in the moisture separator, thereby reducing the water level increase.
The licensee will continue to evaluate the performance of the system during the startup test program to determine if the problem has been resolved by the system modifications.
The licensee plans to report any additional corrective actions in an update to the LER.
LER 84-042 N A Audit Identified Late Chemistr Sam les As a result of an NgA audit of chemistry records, a number of instances were identified where chemistry samples were not taken within the time limit specified in Technical
'L
Specification (TS)
LCO action statements.
Seven samples during the period of December 1983 to March 1984 were taken and analyzed but not within the TS required time.
This is a similar problem to that discussed in LER 84-027 dated June 22, 1984 for which a
Notice of Violation was issued in Inspection Report 50-387/84-22; 50-388/84-28.
The missed samples cited in the NgA audit occurred in a
time period prior to the May 1984 missed samples described in LER 84-027.
Therefore, the corrective action taken as described in LER 84-027 and PP&L letter dated September 21, 1984, had not been implemented.
Additionally, the majority of the missed samples were under the cognizance of the same chemistry technician who is no longer employed by PP&L.
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 they 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 whether any information in the report should be classified as an abnormal occurrence.
Special Report
"C" Diesel Power Fluctuations dated November 5,
1984.
Special Report RCIC Injections (Unit 2) dated November 1, 1984.
Special Report Non-Valid Diesel Failure dated November 9, 1984.
Monthly Operating Report - October 1984, dated November 15, 1984.
Monthly Operating Report November 1984, dated December 10, 1984.
Special Report -
ECCS Injections (Unit 2) dated December 17, 1984.
Special Report
"A" Diesel Generator Impulse Pump dated December 21, 1984.
The above reports were found acceptable'.0 Monthl Surveillance and Maintenance Observation 5. 1 Surveillance Activities The inspector observed the performance of surveillance tests to determine that:
the surveillance test procedure conformed to tech-nical specification requirements; administrative approvals and tag-
L
outs were obtained before initiating the test; testing was accom-plished by qualified personnel in accordance with an approved sur-veillancee procedure; test instrumentation was calibrated; limiting conditions for operations were met; test data was accurate and com-plete; removal and restoration of the affected components was pro-perly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appro-priately resolved; and the surveillance was completed at the required frequency.
These observations included:
S0-151-002, Quarterly Core Spray Flow Verification, performed on November 28, 1984.
SE-259-087, LLRT of Penetration X-215 RCIC Turbine Exhaust Line, performed on November 14, 1984.
S0-200-011, Reactor Yessel Temperature and Pressure Recording performed on Oecember 18, 1984.
No unacceptable conditions were identified.
5.2 Maintenance Activities 5.2. 1 Unit 2 Precommercial Outa e
Unit 2 remained in Operational Condition 4 (Cold Shutdown)
until January 5,
1985, to conduct the pr ecommercial outage.
The outage began October 27, 1984, and was completed in 70 days, nine days beyond the original schedule.
The follow-ing major work was performed:
Induction Heating Stress Improvement ( IHSI) of 29 welds in the Recirculation, RHR and Reactor Water Cleanup (RWCU) systems; repair of the
'B'oop recirc discharge valve (2F031B)
due to stem galling; modification of the 'A'nd 'B'PCI injection valves (F015A and B) due to inadequate seating; modifications to the Emergency Service Water (ESW)
system to prevent water-hammer; condenser hotwell cleanout and inspection; modif-ications to the condensate demineralizers; rework of four HSIYs and feedwater check valves due to local leak rate test (LLRT) failures; and numerous other LLRTs and 18 month surveillance tests.
Rework of the MSIVs and feed system valves was not unexpected and was included in the initial outage schedul The primary reason for the delay in completing the outage was due to problems with the LPCI injection valve modi-fication.
The modification, which consisted of replacing the discs with ones which included a stellite wear strip on the disc guide slots and installing Haynes Alloy 25 wear strips on the guide in the valve body, was unable to be completed as designed.
Problems were encountered with the alloy used to install the wear strips in the valve body and one valve disc was cracked during installation of the stellite guide strips at the Anchor Darling facility.
The F015B valve was reinstalled with the new disc but the wear strips in the valve body were not received in time.
The F015A valve was reinstalled with the original unmod-ified disc and the new body wear strips.
The F015B valve passed the LLRT and leak check in November and was declared operational.
Subsequently, during the operational leak check at completion of outage maintenance on December 18, the F015B valve was found to be leaking by its seat.
Sub-sequent disassembly revealed galling between the stellite and stainless steel wear surfaces in the guide and guide slots.
Rework of this valve added about two weeks to the outage duration.
No other problems were encountered with the F015A valve.
Throughout the outage period, the inspector toured areas where maintenance or modification work was in progress, reviewed work packages at job sites, reviewed outage logs and schedules, and discussed outage progress with individ-uals from different work groups.
The inspector noted that, to the extent practical, housekeeping and cleanliness was maintained, radiological protection practice and coverage appeared adequate, work packages were thorough and well prepared, work was properly classified with respect to quality requirements, individuals appeared knowledgeable of their work scope and the operators understood the status of plant systems.
In general, the outage appears to have been well planned and was well controlled.
The inspector identified no unacceptable conditions.
6.0 Scram Oischar e Volume SDV Vent and Drain Pilot Valve Unit 1 At 2: 15 p.m.
on December 21, with Unit 1 at full power, the operators attempted to cycle the SDV vent and drain valves from the control room.
The valves would not close.
The licensee determined that the SDV vent and drain pilot valve, SV-1F009A, was malfunctioning and not allowing the air header to the vent and drain valves to bleed off.
At 2:45 p.m., the oper-ators isolated and vented the air header to the vent and drain valves,
allowing them to shut.
Licensee continued plant operation with the SDV vent and drain valves shut and initiated actions to replace the pilot valve.
At 9:45 p.m.,
the pilot valve was replaced with one from Unit 2, tested and the vent and drain valves reopened.
The pilot valve anomaly was reported to the NRC via the ENS at 6:45 p.m.
in accordance with the NRC Confirmatory Action Letter dated October 17, 1984.
The pilot valve is a Valcor 3-way dual solenoid valve (Part No.
V70900-45).
The Valcor valve was installed in October 1984 as a replacement to the existing ASCO solenoid pilot valve (Ref:
Inspection Report 50-387/
84-35; 50-388/84-44).
Inspection of the removed Valcor valve revealed a
small piece of particulate matter lodged between the valve inlet scat and disc, thus preventing the disc from closing and isolating the air supply.
This resulted in a constant air.supply to the a'ctuators of the SDV vent and drain valves preventing them from shutting.
The particulate matter appeared to be pipe dope which is used to prevent leaks at threaded con-nections.
The particulate has been sent to Loctite Corporation for analysis.
The particulate matter had apparently been lose inside the air system piping for the Control Rod Drive (CRD) system; it did not appear to be due to improper installation of the pilot valve.
After verifying that the removed valve was not damaged, the licensee reinstalled the valve in Unit 2.
The inspector discussed this occurrence with individuals from the Opera-tions and Technical sections, reviewed operating logs, Work Authorization V48444, and results of the quarterly SDV vent and drain valve surveillance S0-155-002, and observed portions of the pilot valve installation on Unit 2.
Since the potential exists for other loose particulates in the CRD section of the air system, the inspector questioned what measures were being taken to ensure the operability of this system.
The licensee indicated that, in response to the potential oil contamination in the air system which appar-ently contributed to the degradation of the discs in the scram pilot sol-enoid valves (Ref:
Inspection Report 50-387/84-35; 50-388/84-44),
a series of nine air blows were conducted on the Unit 1 instrument air sys-tem and nine pieces of tubing were removed for analysis.
No evidence of particulates was discovered.
Air flows were also conducted on Unit
and four tubing sections were removed from the CRD air system.
One piece of tubing on Unit
has a piece of particulate bonded to it which has also been sent to Loctite Corporation for analysis.
No loose particulate was found.
No other cleaning techniques appeared practical for the short term; the licensee is evaluating replacement of the Unit 2 CRD air system piping during the first refueling outage scheduled to begin February 9,
198 In the interim period, the licensee has increased the frequency for the quarterly SDV vent and drain valve cycling to weekly on both units.
Reactor scram procedures, EO-100-001 and E0-200-001, were changed to add a step to isolate and vent the air header in the unlikely event that the SDV vent and drain valves do not shut on a reactor scram.
For this to occur as a result of an air system problem, both backup scram valves would have to fail in addition to the vent and drain pilot valve.
The licensee's longer term actions for ensuring the cleanliness of the air system on Units
and 2 will be reviewed in a
subsequent inspection.
(387/84-38-01, 388/84-47-01).
With respect to the valve installation, the inspector noted that the seal-ant used to seal the threaded fittings was Loctite 58031, Nuclear Grade PST.
According to Information Notice 84-53, this appears to be the proper sealant.
No discrepancies were noted with the installation.
7.0 Fire Protection/Prevention Pro ram 7. 1 Plant Tour and Observation of Work Activities The inspector examined fire protection water systems, including fire pumps, fire water piping and distribution systems, post indicator valves, hydrants and contents of hose houses.
The inspector toured accessible vital and non-vital plant areas and examined fire detec-tion and alarm systems, automatic and manual fixed suppression sys-tems, interior hose stations, fire barrier penetration seals, and fire doors.
The inspector observed general plant housekeeping con-ditions and randomly checked tags of portable extinguishers for evidence of periodic inspections.
No deterioration of equipment was noted.
The inspection tags attached to extinguishers indicated that monthly inspections were performed.
All fire hoses examined were in good condition and properly labeled with the hydrostatic test date.
7.1.1 Yard Fire S stem While conducting the tour of the yard fire system several minor items were noted.
For example, post indicator valve 2PI/127 did not have a
readable local indicator, and one yard main fire department connection was leaking.
The inspector identified the conditions to the fire protection engineer, who initiated work authorizations for the items.
None of the items affected system operability or effec-tivenes In addition, it was noted that drawing C-38, Sheet 1,
had not been updated to include changes in the yard fire main made during the construction of the addition to the Service and Administration Building.
The fire protection engineer initiated a
drawing change notice to update C-38.
This appears to be an isolated case, since all other affected drawings were properly revised.
Com ressed Gas C linder Stora e
The inspector noted during the tour that approximately
compressed gas cylinders were being stored next to and tied to the outboard NSIVLCS piping on the 719'evel of the Unit 1 Reactor Building.
Two of the cylinders were labeled as hydrogen.
The other cylinders were oxygen and nitrogen, and one bottle was only labeled
"Flammable gas".
The in-spector checked the "Combustible/Hazardous Naterial Storage Request Log" and these and other various cylinders noted throughout the plant were not listed.
Administrative Oirective AO-QA-140, Revision 2,
Use and Storage of Combustible/Hazardous Naterials, states in Sec-tion 6. 1.4 that compressed gas cylinders shall not be stored in the plant except in properly installed racks designed for that purposely Exceptions to the requi rement must be approved by completing a Combustible or Hazardous Naterial Storage Request Form.
In addition, Attachment B,
Guidelines for Combustible and Hazardous Naterial Storage, Section 2.3.5 of the same procedure states that compressed gas cylinders must be properly secured and analyzed for possible missile effects in the event of an accident.
The inspector discussed the unauthorized storage with the Fire Protection Engineer and the Unit 1 Unit Supervisor.
The compressed gas bottles were subsequently removed from the Unit 1 719'evel.
The FSAR states in Section 9.5. 1. 1. 11 that with the excep-tion of the nitrogen cylinders for the containment instru-ment gas system and hydrogen and oxygen gas analyzer sys-tem, there is no permanent gas storage inside structure housing safety-related equipment.
In both Unit 1 and Unit
reactor building, the nitrogen cylinders are mounted vertically at elevations 719'nd 749'.
The hydrogen and oxygen cylinders are located in Unit
and Unit 2 reactor building at elevation 719'nd are mounted vertically in a listed seismic category I rac During the tour, the inspector observed the hydrogen and oxygen cylinders for the hydrogen and oxygen gas analyzer and verified they were in vertical racks, in a
caged area posted with special precaution signs.
The Fire Protection Review Report does not list any compressed gas cylinders in the combustible loading for the associated fire zone (1-4A).
A similar deficiency had previously been identified by the licensee and reportedly corrected.
On December 20, 1982, during an Annual gA Audit of the Fire Protection Program, audit finding 0-82-32-5 identified that unauthorized bot-tles were stored in various locations in the Reactor Build-ing, including the same area identified by the inspector.
In the resolution to the audit finding, the licensee stated that the gas cyl.inders for the containment atmosphere mon-itoring systems were acceptable, because of the seismic and permanent installation, but the remainder of the gas cyl-inders not seismically or permanently installed should be removed.
An NgA walkdown was conducted after action was taken on the audit finding and verified the gas bottles had been removed.
The finding was closed September 21, 1983.
The action required for the finding was only to correct the condition and not to address the prevention of recurrence.
The storage of the compressed gas cylinders on the 719'evel next to the MSIVLCS is a violation of station pro-cedures and in deviation from FSAR and FPRP commitments.
(387/84-38-02)
7.2 Fire Protection Administrative Controls and Or anization The inspector reviewed the following documents:
Technical Specifica-tions, Section 6; Administrative Directive (AD), AD-gA-110, Revision 2,
Station Fire Protection Program; Fire Protection Review Report, Revision 2,
dated November 1982; and Administrative Directives AD-gA-140 through 145 concerning various aspects of the fire protection program.
The plant superintendent is responsible for implementation of the site fire protection program.
One full time fire protection engineer (FPE) is onsite with the responsibility for coordinating the imple-mentation of all aspects of the fire protection program.
There is also a
system engineer who has engineering responsibility for fire protection system Pk
'L
The inspector verified that the licensee has developed administrative controls which include:
1) requirements for periodic audits; 2) fire brigade organization; 3)
requirements for periodic housekeeping in-spections; 4) identification of actions to be taken by individuals discovering a fire; 5) requirement for control of combustibles; and 6) requirements for control of ignition sources.
No unacceptable conditions were identified.
7'.1 Control of Combustibles The inspector reviewed AD-gA-140, Revision 2,
"Use and Storage of Combustible/Hazardous Materials" and verified that the licensee has developed administrative controls which require:
1) special authorization for use and stor-age of combustible, explosive or hazardous material in the plant; 2)
removal of wastes, debris and other combustible materials following completion of work; 3) all wood used in safety-related areas to be treated with flame retardant; and 4) housekeeping be properly maintained.
The inspector also reviewed licensee's Combustible/Hazard-ous Material Storage Request Log.
AD-gA-140 requires that work groups desiring temporary or permanent storage of combustible materials in the plant obtain approval by sub-mitting a Combustible/Hazardous Material Storage Request to the FPE.
Inspector review of this log identified that the Health Physics section appears to be the only station de-partment which is following the policy in this AD.
On a
station tour, the inspector noted a
number of examples where combustible material was stored unattended, but with-out a
coresponding Combustible/Hazardous Material Stroage request.
Examples include small oil cans in tool boxes belonging to operations, cleaning lockers belonging to labor support containing masolin, mops and other materials, temporary storage of combustible gas bottles (See Detai 1 7. 1.2),
flammable liquid storage cabinets, work staging areas, and cages with maintenance supplies belonging to Mechanical Maintenance.
Based on the log review, there was only one approved storage request for Operations, nine for Maintenance and none for the Instrument and Controls de-partment.
Health Physics had forty-four approved storage requests.
It is apparent that re-emphasis of station policy concerning storage of combustible materials, is needed.
It should be noted that no single plant area con-tained an excessive amount of combustible material which would significantly increase the area fire loadings.
The inspector discussed this concern with licensee management and will review licensee's control of combustibles in subsequent inspections.
(387/84-38-03)
7.3 Fire Bri ade Trainin The inspector reviewed the following licensee documents:
AD-QA-145, Revision 1, "Fire Brigade" FSAR Question 441.6 and PP&L Response Nuclear Training Procedure NTP-QA-53. 1,
"Susquehanna Fire Safety Training Program",
Revision
Units of Instruction for Harwood Fire School, Initial Fire Bri-gade Training Susquehanna Specific, and Fire Brigade Training for Second Quarter 1984 Training records for selected fire brigade members The inspector verified that the licensee has developed administrative requirements which include:
1)
requirements for announced and un-announced drills; 2) requirements for fire brigade training and re-training at prescribed frequencies; 3)
requirements for maintenance of training records; and 4)
requirements for local fire department training and coordination.
AD-QA-145, Section 6. 1 specifies the following requirements for initial assignment to the Fire Brigade:
1) successful completion of the initial Fire Brigade training course; 2)
physical examination; and 3) initial respirator (SCBA) qualification.
The initial Fire Brigade training course implements the licensee's commitment for fire brigade training as stated in the response to FSAR Question 441'.6.
During review of training records, the inspector noted that four fire brigade members (three from Operations and one from Security)
had not completed the initial fire brigade training course.
All four indi-viduals had completed training at the Harwood fire school, which pro-vides practical training and is required on an annual basis, but it does not substitute for the initial fire brigade training.
The licensee was unable to produce documentation which indicated that the initial Fire Brigade training course was waived for the affected individuals.
The inspector noted that Quality Assurance had iden-tified a similar finding during an audit of the Fire Protection pro-gram in September 1984, but Operations did not take action to either remove the affected individuals from the brigade or waive the train-ing requirements, until this discrepancy was identified by the inspector.
Assignment of individuals to the fire brigade without completion of the required training is a violation (387/84-38-04).
In response to the inspectors findings, the licensee removed the affected individuals from the Fire Brigade and reviewed training records for all brigade members.
The licensee indicated to the inspector that all other brigade members had completed the initial training.
7.4 Fire Fi htin Procedures The inspector verified that the licensee had prepared fire preplans (fire fighting strategies)
for all safety related areas.
The fire preplans were properly reviewed and approved and provisions exist for their periodic (every three years)
review and revision.
The inspec-tor verified locations of fire fighting equipment, as delineated in the preplans, by walkdown of several fire zones in the Unit
and
Reactor Buildings.
Two minor discrepancies were noted which were identified to the licensee.
The inspector compared Attachment F of Emergency Procedure EP-IP-041, Locations of Fire Fighting Equipment, with the actual location in the plant.
Several deficiencies in locations, and one omitted location were identified.
These were brought to the attention of the licensee who initiated corrective action.
7.5 Review of Surveillance Test and Maintenance Records Associated with Technical S ecification Re uirements The inspector randomly selected and reviewed 13 surveillance proced-ures and eight completed surveillances to verify that the associated fire protection and detection system surveillances met the Technical Specification requirements and the completed tests had been properly performed, acceptance criteria had been met and the tests had been completed within the required periodicity.
Several procedural items were identified:
Surveillance Procedure S0-013-033, Revision 1,
18. Month CO, System Functional Test did not contain a
procedural step to check the nozzles for flow, although it is an acceptance cri-teria'~
SM-113-004, Revision 0, Yearly Inspection, Hose Hydro and Flow Test of Yard Fire Hydrants, properly hydrostatically tests the hoses from the hose houses but does not ensure a tested hose is returned to the hose hous SM-113-008, Revision 0, Six Month Inspection and Weight of Halon Cylinders and Flow Verification, requires the use of a tempera-ture probe, but it is not listed in the requirements for special tools/equipment and the procedure does not reference recording the temperature.
A temperature correction is required to verify the acceptance criteria but no temperature correction step is evident in the procedure.
The inspector informed the licensee of the procedural items, and the licensee initiated action to modify the procedures.
The corrected procedures will be reviewed in a subsequent inspection (387/84-38-05).
7.6 Review of Periodic Ins ections and ualit Assurance Audits The inspector reviewed selected fire protection program audit reports to verify that the three periodic audits required by Technical Spe-cifications are conducted within the specified time period and ade-quately assess compliance with the administrative controls and imple-mentation of quality assurance criteria.
The audit results were properly documented and reviewed with manage-ment responsible in the areas audited, followup action was taken to correct the deficiencies, and the audits were performed by qualified individuals.
With the exception of two recurring deficiencies, noted in Section 7. 1.2 and 7.3, no unacceptable conditions were noted.
8.0 Cold Weather Pre arations The inspector reviewed licensee's preparations for cold weather operation to determine if licensee's actions would be adequate to prevent freezing problems..
Licensee'
actions for cold weather operation are delineated in Off Normal Procedure ON-000-001, Revision 0,
"Cold Weather Operation".
The areas of concern for freezing problems are the cooling tower basin, spray pond in-take structure and riser network, river intake structure, and piping sys-tems protected by heat trace systems.
Last winter, the licensee exper-ienced significant problems with freezing of the spray network in the spray ponder The problem was due to leakage past the spray network i,sola-tion valves causing the spray network piping to fill, and inadequate per-formance of the spray pond piping drain pumps (ref:
Inspection Report 50-387/83-29; 50-388/83-32).
In accordance with Unit 2 License Condition Attachment 1,
Item 4.c, the licensee is installing self priming drain pumps and relocating the drain pump suction line to enable pumping the spray network more efficiently.
Level detection devices are also being installed in the spray network piping.
These modifications were being completed at the end of this report period.
Prior to implementation of these modifications, the licensee, on a daily basis, has been removing accumulated water in the spray networks by blowing out the nozzles using a
diesel driven air compresso The inspector discussed cold weather preparations with shift supervision and reviewed ON-000-001.
Actions have been initiated in accordance with ON-000-001 and shift supervision was knowledgeable of the required actions.
The inspector had no further concerns.
9.0 Nitro en Makeu Line Over ressurization On December 21, while attempting to add nitrogen (N~) to the Unit 1 dry-well, the N,
makeup line was overpressurized.
The incident occurred due to miscommunications between an Auxiliary Systems Operator (ASO)
who was stationed at the N,
makeup connection and the contractor supplying the N, at high pressure (approximately 2000 psig)
before the valve lineup was completed.
As an apparent result, the six-inch N,
makeup outboard con-tainment isolation valve HV-15721 was damaged (the carbon steel backing ring was severely distorted).
and pressure increased in the drywell by about 0.2 psig even though the inboard drywell purge valve (HV-15722)
was closed (N, enters the drywell and suppression chamber via the purge lines).
During licensee's investigation of the incident, the licensee performed a
local leak rate test (LLRT)
on the drywell and suppression chamber purge valves.
The LLRT failed.
Since the N, makeup outboard con-tainment isolation valve was already damaged and the LLRT could not con-firm the integrity of the associated inboard valves (drywell and suppress-ion chamber purge valves),
the licensee commenced a reactor shutdown in accordance with Technical Specification 3.6.3 at 11:00 a.m.
on December 24.
Unit 1 was in Hot Shutdown at 5: 13 p.m.
and Cold Shutdown at 11: 19 p.m.,
December 21.
The inspector discussed the incident with Operations and Technical staff members, reviewed significant Operating Occurrence Report (SOOR) 1-84-479, operating logs, Operating Procedure OP-173-001,
"Containment Atmosphere Control System",
LLRT results for containment purge valve penetrations, a
safety evaluation concerning the containment purge valves and the inspec-tor attended Plant Operations Review Committee (PORC)
Meeting No.84-272 where the safety evaluation was approved.
Following the shutdown, the licensee performed leak checks on the contain-ment purge valves and determined that HV-15724, the suppression chamber outboard isolation valve was leaking.
The valve was disassembled and the licensee determined that the resiliant seat was scared (apparently unre-lated to the overpressurization).
New seats were installed on this valve and the inboard suppression chamber isolation valve.
The LLRT was again performed on the containment purge valves with satisfactory results.
As noted above, during the incident, drywell pr'essure increased by about 0.2 psig indicating that the drywell purge inboard isolation valve (HV-15722)
leaked by.
The containment purge valves are large (24 inch for the drywell and 18 inch for the suppression chamber)
Pratt butterfly valves Model 1200.
Since the drywell inboard valve passed an LLRT with no re-pairs, the pressure rise in containment was apparently caused by a flex-ing of the valve discs.
The valve passed the LLRT and stroke times on the valve were satisfactory which appears to indicate that the valve was not
permanently deformed, However, the 24 inch valves were not demonstrated as being qualified to shut against LOCA pressure from the full open position without exceeding valve stem allowable stresses.
The valves are presently blocked to prevent opening to greater than 50 degrees.
The
inch valves in Unit 1 will be modified to include new valve internals during the first refueling outage (commitment made in PP&L letter to the NRC dated April 13, 1983.
Because of the possibility that the purge valves may have been overstressed, the licensee has shut and deactivated the drywell and suppression pool inboard and outboard containment isola-tion valves and, in accordance with Technical Specification 3.6.3, will open the inboard purge valve only under administrative controls when needed for N, makeup.
The N~
makeup system components are rated to 150 psig.
There is a
one inch relief valve on the makeup line.
Since there is no pressure indica-tion in the N, makeup line, the licensee was unable to determine the maxi-mum pressure reached.
A gage on the N~ truck indicated 2100 psig when the truck operator stopped the N, flow.
However, normal pressure is approxi-mately 2000 psig and the N,
goes through a vaporizer, which is a large pressure drop, downstream of the pressure gage.
After the incident, all accessible portions of the line were inspected for physical damage.
New gaskets were installed in piping flanges.
The one inch relief valve was found stuck open and was repaired.
No other physical damage was found.
The incident identified several concerns for which the licensee is taking action to correct.
First, the incident occurred because the truck opera-tor started pumping the N, before the plant was lined up to accept it.
Hence, the plant did not have positive control of the evolution.
Second, there is no pressure indication on the makeup line and apparently the re-lief protection on the line was inadequate.
Previously the plant staff had issued a request for modification to install a four inch relief valve, but the design change was never implemented because of competing prior-ities.
To correct the above problems, the plant staff intends to install a pressure gage and shutoff valve on a
removable piping connection which would be used to connect the N, truck to the N, connection.
The shutoff valve would be operated by a plant operator.
The licensee also intends to provide proper relief protection for the N, makeup line.
By review of the inerting procedure, OP-173-001, the licensee determined that the possibility existed for overpressurization upon securing from inerting since the containment isolation valves are shut prior to securing the N, flow at the truck.
The licensee revised the procedure on December 27 to:
1)
ensure that the first operation for securing N,
makeup is to
shutoff flow at the truck; 2) install a temporary 0-150 psig pressure gage at the N,
connection prior to inerting; and 3) instruct the operator to have the N, vender stop flow prior to exceeding 80 psig at the gage.
OP-273-001, the N, inerting procedure for Unit 2, will be revised prior to inerting Unit 2.
The final disposition of the purge valves and the installation of the new removable piping connection will be reviewed in a
subsequent inspection (387/84-38-06).
10.0 Exit Interview On January ll, 1985, the. inspector discussed the findings of this inspec-tion with station management.
Based on NRC Region I review of this report and discussions held with licensee representatives on January 11, it was determined that this report does not, contain information subject to
CFR 2.790 restriction