IR 05000387/1987016
| ML17146B040 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 11/16/1987 |
| From: | Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17146B038 | List: |
| References | |
| 50-387-87-16, 50-388-87-16, NUDOCS 8711230453 | |
| Download: ML17146B040 (26) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.'0-387/87-16 50-388/87-16 Docket Nos.
50-387 50-388 License Nos.
NPF-14 NPF-22 Licensee:
Penns lvania Power and Li ht Com an 2 North Ninth Street Allentown Penns 1 vania 18101 Facility Name:
Inspection At:
Sus uehanna Steam Electric Station Salem Townshi Penns lvania Inspection Conducted:
Au ust
1987 - Se tember
1987 Inspectors':
Approved By:
L.
R. Plisco, Senior Resident Inspector J.
R. Stair, Resident Inspector A.
R. Blough, Chief, Reactor Projects Section 3B, DRP Date Ins ection Summar Areas Ins ected:
Routine resident inspection of plant operations, physical security, plant events, previous inspection findings, surveillance, mainten-ance, ESF System Malkdown, open item followup, and Unit
Refueling Outage Activities'esults:
A crack was discovered on the Steam Dryer (Detai-1 6. 1);
an Unusual Event was declared on September 23 following ejection of a main steam line plug (Detail 3.4);
a spill occurred in the Unit 1 'B'ore Spray room during system filling (Detail 3.5);
and, personnel were contaminated during hookup of a
packing extraction tool (Detail 3.6).
.
One violation was identified in which secondary containment integrity was compr'omised when Zones I and III were cross-tied (Detail 3.3).
8711230453 87iii8 PDR ADOCK 05000387 Q
TABLE OF CONTENTS
~Pa e
1.0 Followup on Previous Inspection Findings
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2.0 Routine Periodic Inspections
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2.1 Operational Safety Verification 2.2 Station Tours 2.3 ESF System Walkdown 3.0 Summary of Facility Activities
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3.1 Unit 1 Summary 3.2 Unit 2 Summary 3.3 Secondary Containment Ventilation Zones Cross-tied (Unit 1)
3.4 Unusual Event Declared Due to Main Steam Line Plug Ejection 3.5 Spill in the 'B'ore Spray Pump Room 3.6 Area and Personnel Contamination 8.
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4.0 Licensee Reports 4. 1 In-Office Review of Licensee Event Reports 4.2 Onsite Followup of Licensee Event Reports 4.3 Review of Periodic and Special Reports 5.0 Surveillance and Maintenance Activities
16 5.1 Monthly Surveillance Observations 5.2 Monthly Maintenance Observations 6.0 Unit 1 Third Refueling and Inspection Outage
7.0 Management Meetings
DETAILS 1.0 Followu on Previous Ins ection Findin s
1. 1 Closed Ins ector Followu Item 388/84-22-02
HPCI Surveillance Procedure Decficiencies During an observation of the performance of the Unit 2 HPCI 18-month system and logic functional test, S0-252-003, several procedural deficiencies were identified.
In addition, the inspector noted that the ECCS initiation light color convention was neither consistent between units, nor within the licensee's specifications.
The procedural deficiencies were corrected by the licensee and re-viewed in Inspection Report 50-388/86.-09.
During the Unit 2 first refueling outage the modifications were completed which corrected the human factors 'deficiencies.
The inspector verified that the'CCS initiation lights were replaced with green lights and that the asso-ciated procedures had been revised.
1.2 Closed Violation 387/86-06-04
Im ro erl Controlled Maintenance Work in the Recirculation Plenum In March 1986, while observing maintenance in the reactor building recirculation plenum, the inspector noted that access hatches to both the recirculation fan supply and discharge sides of the recirculation plenum were open at the same time during fuel movement.
The work had been authorized by shift supervision with the understanding that the access hatches would only be opened to allow entry.
Upon notification that both the supply and discharge recirculation access hatches were open, the operations shift supervisor immediately halted fuel movement.
The maintenance crew was directed to stop work on the recirculation plenum and reinstall the personnel access hatches, thereby reestablishing secondary containment integrity.
Prior to recommencing the preventive maintenance activities in the recirculation plenum a
new work authorization was prepared which included detailed written instructions to control the removal and installation of the plenum access hatches.
The licensee responded to the violation on June 5,
1986 (PLA-2656)
.and also described the event in LER 86-010 dated, April 25, 1986.
The violation response and the LER stated that future work inside the recirculation plenum would be controlled by detailed written instruc-tions on how to gain and secure access into the plenum to ensure secondary containmen The inspector reviewed maintenance instructions MI-PS-005, Guidelines for Minimizing the Likelihood of Violating Secondary,. Containment Integrity, and MI-PS-001, Work Plan Standard, which were revised to better describe actions for work that could impact secondary contain-ment.
MI-PS-005 now contains a
paragraph concerning prec'au-tions necessary for work inside the recirculation plenum.
In addi-tion, the inspector reviewed the three PM's which exist for work inside the recirculation plenum and verified they contain cautions requiring an approved work plan.
Closed Unresolved Item 388/86-11-01
Ino erabi lit of All ECCS S stems While Shutdown On June 12, 1986, while in Operational Condition 4, an operator dis-covered that all low pressure ECCS Systems were technically inoper-able due to a
series of equipment releases for maintenance work.
Licensee evaluation of the event, which was independently verified by the inspector, found that no Technical Specification LCO violations had occurred.
Although the operators were unaware of all the LCO's that they had entered, the systems were restored prior to the Action Statement being violated.
The plant staff determined the cause of the event to be inadequate technical review by the responsible Work Group.
During preparation of the Equipment Release Form (ERF) for work on the reactor vessel level switch ( LIS-B21-2N031D),
the planner failed to observe that switch 1B was an initiation contact for the RHR system.
In addition, Operations review of the ERF also did not reveal this error.
The Nuclear Safety Assessment Group conducted an independent investi-gation of the event'.
The results of the investigation were issued on September 30, 1986.
NSAG concluded that the primary cause of the incident was that the station's practice of performing engineered safety system work by divisions was violated.
Although problems in the work release and equipment status control system contributed to the event, NSAG found that none of these would have made any differ-ence had work been confined 'to Division I.
The contributing causes were determined to be poorly researched ERF's, no system existed to track the overall status of ESF equipment, the instrument channel was not tripped when the low level detector was removed from service, and Technical Specification ambiguities concerning operability of the ECCS systems.
NSAG provided a list of recommendations to correct the problems identified and prevent recurrenc The plant staff responded to the NSAG report on April 7, 1987.
Al-though the plant staff agreed with the general conclusions and recom-mendations of the NSAG report, they differed with the determination of the root cause.
The plant staff believes it to be failure of the work groups to properly identify all of the effects of removing an instrument from service.
However, the plant stated that they will continue the practice of performing work on only 'one division at a
time and it would continue to be formally included in station work practice documents.
The licensee implemented many changes in response to this event.
Improvements were made to the ERF process including preparation of an instrument/Technical Specification cross-referencce, preparation of pre-reviewed ERF's, and traini.ng to work group planners.
A performance enhancement team was also formed to review the entire ESF preparation process.
One change already implemented was revising the ERF form to include a Unit Coordination signature block to ensure their review.
Since the event the licensee has also implemented a
computerized'ystem Status File system to monitor potential LCO's.
The licensee also started use of an outage status board, showing the status of the major systems.
The licensing group evaluated the applicable Technical Specification sections and determined that no changes were required to provide additional clarity.
However, the licensee plans to change the FSAR to enhance the presentation on cross-divisionalized initiation logic and to proposed a Technical Specification interpretation to ensure appropriate actions are followed when the LPCI initiation logic is out-of-service.
The inspector reviewed the completed SOOR package, NSAG report, and the plant staff resp'onse and had no further questions.
Closed Ins ector Followu Item 387/87-02-01
Reactor Water Cleanu Isolation Valve Leaka e Verification On January 9,
1987, the licensee identified that the Unit 1 Reactor Water Cleanup (RWCU) Suction Outboard Isolation Valve (HV-1441F004)
was leaking by its seat, although within Technical Specification limits.
Following discussions with NRR and Region I, it was deter-mined that it was more prudent to repair the valve, and resolve the adequacy of the containment isolation function capability by an al-ternate test method until the commencement of the next available out-age when a
post-maintenance LLRT would be performed.
The licensee submitted a
one time IST Relief Request to NRR.
The cause of the leakage was determined to be a piece of a nut lodged in the seat of the valve.
Following repair of the valve, an alternate leak test (pressurization test)
was then satisfactorily performed with no evidence of leakage note On April 5, 1987, following a forced outage, the local leak rate test (LLRT) was performed on the valve and was determined to be within the acceptance criteria.
Technical Specification 3'. 1.2 states that the primary containment leakage rates shall be limited to a
combined leakage rate of less than or equal to 3.3 GPM for all containment isolation valves in hydrostatically tested lines which penetrate the primary containment, when tested at 49.5 psig.
The LLRT results were 2.6 GPM, which was determined to be more than normal, therefore the valve was reworked again and the valve disc was replaced.
The as-left LLRT showed minimal leakage.
The inspector reviewed the LLRT results, and LLRT procedure, and dis-cussed the results with the responsible engineer.
The LLRT verified that the isolation valve had been acceptable following the initial rework.
The inspector had no'further questions.
Closed Ins ector Followu Item 387/87-03-01:
Com arison of Licensee Anal tical Results to BNL Results of Mater Sam les Verification of the licensee's measurement capabilities on actual plant water samples was performed by splitting samples with the licensee and Brookhaven National Laboratory (BNL).
The feedwater samples were taken for metal analysis and the reactor water was taken for chloride and sulfate analysis.
The feedwater samples were spiked with a standard solution of iron, copper, nickel and chromium and the reactor water sample was spi ked with a
standard solution of chloride and sulfate.
The analyses from the licensee and BNL were completed and a compari-son was made.
The comparisons of the split sample analyses found that the licensee's chloride and sulfate results were biased low.
The metal analyses found a slight low-bias which may have been caused by the one point calibrations the licensee was utilizing.
The licen-see was provided with a copy of the split sample.comparison results, as part of the NRC's non-radiological chemistry program.
Closed Ins ector Followu Item 387/87-06-01:
Post Maintenance LLRT on HPCI Isolation Valve On March 5,
1987, a
licensee mechanical maintenance technician received steam burns while replacing packing on the Unit
High Pressure Coolant Injection (HPCI)
outboard steam supply isolation valve (HV-155-F003).
Review of the event determined that while replacing packing on the valve, the length of pipe between the in-board and outboard isolation valve had not been adequately depressur-ized, and the packing blew out when the technician removed the packing gland.
Subsequent to the blow-out of the packing, the valve required a complete repack to be performed.
Although the licensee's
administrative programs required a post-maintenance local leak rate test ( LLRT), alternate testing was performed to prevent an unneces-sary shutdown.
The data accumulated during the alternate testing did not constitute a substitute for an LLRT, but did indicate that the
.
valve was consistent with it's pre-work condition.
The test data was reviewed by NRC, and Region I management determined the licensee's actions to be acceptable.
On April 4, 1987, the as-found LLRT was performed during a forced outage.
The measured leakage through the F003 valve was approxi-mately 157 liters/minute, which was excessive.
The total Band
'C'ype LLRT leakage was 48.7 liters/minute and the Technical Specifi-
.cation limit was approximately 190 liters/minute.
Subsequent testing verified that the minimum leakage through the penetration was approx-imately 17 liters/minute which was acceptable.
The F003 valve was reworked and post-maintenance (as-left)
LLRT results
'were approxi-mately 2 liters/minute.
The inspector reviewed the test data and could not determine if the valve was leaking excessively prior to the packing replacement, or if the failure occurred following the rework during the one month of plant operation.
The alternate testing performed after the valve repack was not conclusive with respect to invalidation of the local leak rate test.
The pressurization test was performed only to make a qualitative assessment of leak tightness using steam at reactor pressure.
The strongest test data to support the valve character-istics which remained unchanged was the stroke time consistency.
Although the total penetration measured leakage was well within the acceptance criteria, future requests for LLRT relief should be reviewed more closely, especially when involving steam isolation valves.
The inspector reviewed the local leak rate test results and had no further questions.
2.0 Routine Periodic Ins ections 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 annunciators was reviewe Nuclear Instrument panels and other reactor protection 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 protected area, the inspector observed access con-trol, 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 inspection period.
Sampling reviews were made of tagging requests, night orders, the bypass log, Significant Operating Occurrence Reports (SOORs),
and gA nonconform-ance reports.
The inspector observed several shift turnovers during the period and routinely attended work planning meetings.
In addi-tion, the inspector conducted midnight shift inspections on August 26, 1987, and weekend/holiday coverage on August 23, August 29, and September 26, 1987.
2.2 Station Tours The inspector toured accessible areas of the plant including the con-trol room, relay rooms, switchgear rooms, cable spreading rooms, penetration areas, reactor and turbine buildings, diesel generator buildings, ESSM pumphouse, the security control center, and the plant perimeter.
During these tours, observations were made relative to equipment condition, fire hazards, fire protection, adherence to procedures, radiological controls and conditions, housekeeping, security, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment.
On August 24, 1987, the inspector noted that the seals on the airlock doors between the Unit
and Unit 2 reactor buildings and turbine buildings were damaged.
Both units were at full power.
The Unit
outer airlock door seal damage had been previously identified by the licensee evidenced by an Equipment Deficiency Tag attached to the door.
However, the Unit 2 inner and outer doors were both damaged and no previous identification was evident.
One door had portions of the seal pulled away from the door frame, and the other door had been temporarily repaired with tape holding the seals in place.
The tape was placed over the seating surface.
The inspector immediately informed the shift supervisor, who initiated action to have the seals repaired.
On August 25, the inspector inspected the airlock doors and found them repaired and acceptable.
In addition, on August 27, the Superintendent of Plant issued a
memorandum to all station per-sonnel requesting them to exerci se caution while transporting tools, materials or equipment through the airlock doors.
The inspector verified that pressure within the secondary containment was less than 0.25 inches of vacuum water gauge 'uring this period.
Technical Specifications only require at least one door in each access to the secondary containment zones to be close On August 25, 1987, the Region I
Regional Administrator, William T. Russell, toured the site and met with licensee management.
During his tour, the Regional Administrator noted several discrep-ancies, a list of which is included on Attachment 1.
During the Regional Administrator's tour, he noted that the Emergency Service Water (ESW)
supply and return lines to the Unit 1 'A'oop Core Spray Room Coolers had leaks around several flexible pipe con-nections.
The leaks appeared to be from the weld areas (See Attachment 1).
On September 8,
1987, at 4:30 a.m. after starting the 'B'SW pump for suppression pool cooling, the HPCI Turbine Rupture Disc Logic
'B'larm was received in the control room.
Investigation by the AUS found a significant leak from a flex pipe supply the 'B'ore Spray Room Cooler.
The leak was spraying water onto the HPCI instrument rack located in the CS pump room.
The loop was declared inoperable and work requests were initiated to repair the leaks.
At 5:00 p.m.
the same day, another operator noted that there was a leak on the
'C'ore Spray Room Cooler flexible pipe.
Inspection of all the ECCS room -.coolers was conducted and degradation on other room coolers was noted.
In addition, corrosion was noted on the carbon steel flange on several of the coolers, and the transition weld to the flexible pipe.
Licensee inspections of the Unit 2 coolers did not identify any discrepancies on the flexible pipes.
During his walkdown of the Unit 2 Core Spray System, the inspector verified that no active leaks from the ESW Supply and Return Lines to the room coolers were visible, although corrosion was noted on the flange connections and weld transition areas.
The licensee is investigating the cause of these failures and con-ducting the necessary repairs.
This item will remain unresolved pending review of the licensee's corrective actions (387/87-16-01).
2.3 ESF S stem Walkdown Unit 2 Core S ra S stem On September 30, 1987, the inspector independently verified the operability of the Unit 2 Core Spray System by performing a complete walkdown of the accessible portions of the system.
The engineered safety system status verification included the following:
Confirmation that the licensee's system check-off lists and operating procedure are consistent with the plant as-built drawings and as-built configuration.
Identification of equipment conditions and items that might degrade performanc Verification of proper breaker positions at local electrical boards and indications on control boards.
Verification of properly valved in and functioning instrumenta-tion.
Verification that valves were in proper position, power was available, and appropriate valves were locked.
The inspector determined that the system was properly aligned in accordance with the operating procedure and the equipment conditions indicated the components were well maintained.
No unacceptable conditions were identified.
3.0 Summar of Faci lit Activities Unit
operated at or near full power for most of the inspection period until 1:02 a.m.
on September 12, when Unit
was manually scrammed to commence the Third Refueling and Inspection Outage.
The unit reached Condition 4 at 8:36 p.m.
on September
and core off-load commenced on September 18.
On September
defueling was completed.
On September 14, the licensee determined that a
mode change from Condition 4 to Condition 5 could not be performed based on Technical Specification 3.0.4 because an insufficient number of Intermediate Range Monitors were available to meet Technical Specification 3.3.6 requirements for Rod Block Monitoring Instrumentation.
This situa-tion arose as a result of the licensee's performance of the required 60-month performance discharge test, rendering one division of the
VDC batteries inoperable.
The licensee requested and received a
one-time relief from the requirements of Technical Specification Section 3.0.4 (See Detail-6.0).
.2 On September 23, an Unusual Event was declared at 4:25 a.m.
due to an ejected Main Steam Line Plug.
The plug was removed from the reactor vessel and the Unusual Event terminated at 3:20 p.m. the same day (See Detail 3.4).
Unit
operated at or near full power for most of the inspection period.
Scheduled power reductions were conducted throughout the period for control rod pattern adjustments, surveillance testing and scheduled maintenanc At 4:22 a.m.
on September 2,
a Division II Reactor
.Water Cleanup (RWCU) isolation occurred due to exceeding the setpoint for differ-ential temperature (dt) between the RWCU Penetration Room and outside supply air.
As a result the outboard isolation valve closed and the RWCU pumps tripped.
Actual dt was 30 degrees F,
2 degrees above set-point, due to ambient temperature dropping to 46 degrees.
The high dt resulted from the Zone II heaters being deenergized due to warm ambient temperatures on previous nights.
The zone heaters were re-energized and RWCU restored.
At 9: 18 p.m.
on September 2,
an internal electrical arc-over of the
'B'uxiliary Boiler caused an overcurrent trip of its 13.8 KV supply breaker and resultant electrical transient on the T-20 startup trans-former.
As a result, the Divisi.on II Containment Atmosphere Control (CAC) valves received a spurious signal to close.
In addition, the Unit
and Unit 2 'B'ontainment Radiation Monitor Steam Selector Valves closed, Unit 1 Reactor Recircul'ation Pump Motor-Generator Set scoop tubes locked up, Unit 1 offgas system isolated, the Containment Instrument Gas (CIG) System swapped to its bottle supply and the
'A'eactor Building Closed Cooling Water (RBCCW)
pump auto-started.
No loads were being fed by the 'B'uxiliary boiler at the time of arc-over.
All affected systems were returned to normal service.
3.3 Cause of the arc-over was determined to be a
broken conductivity element combined with no load operation over a period of six hours.
The element was replaced and the boiler prepared for operation.
Secondar Containment Ventilation Zones Cross-tied Unit
On September 4,
1987, at 3:30 a.m., with Unit 1 at 90 percent power, during preparation for opening Railroad Bay Door 101, the licensee discovered that Reactor Building Ventilation Zones I and III had been cross-tied from August 31 to September 4.
Zone I comprises the Unit 1 reactor building while Zone III comprises the Unit
and
common refueling floor.
During normal operations, the railroad access bay is aligned to Zone III through HVAC manual isolation dampers ND-17513 and XD-17514.
Also, Zone I is normally isolated from the railroad access bay in that the removable walls are normally installed and sealed.
Operating Procedure OP-134-002, Reactor Building HVAC Zone I and Zone III, requires verification that Zones I and III are isolated from the Railroad Access Bay prior to opening Railroad Bay Door 101 to the outside.
It was during this verification following replace-ment of the removable railroad bay walls that manual isolation
dampers XD-17513 and XD-17514 were found open.
A review of operators logs determined that both dampers were left open on August 31, thus tying Zone III ventilation to the Railroad Access Bay.
Additionally, on August 31, the removable railroad bay walls on reactor building 719 elevation had been taken down for access to Zone I in order to facilitate removal of equipment.
Zone I and Zone III were therefore cross-tied through these open dampers and the 719 elevation removable wall during the period specified above.
This constitutes a violation of Technical Specification 3.6.5. 1 (387/87-16-02)
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Technical Specification 3.6.5. 1 requires that secondary containment integrity be maintained while in Operational Condition 1.
In accord-ance with Technical Specification 1.37 and 4.6.5. 1, included in the requirement for secondary containment integrity, is that all secon-dary containment penetrations between zones, are either.closed or capable of being closed by an automatic isolation system.
This is the second event in the last two inspection periods in which Zones I and III were cross-tied for a period in excess of.that al-lowed by Technical Specification 3.6.5.
through the same manual isolation dampers.
The first instance occurred from July 30, 1987 to August 10, 1987, and was left as Unresolved Item (387/87-12-02).
The licensee indicated that he believes that the two events are unre-lated in that a
cause for the first occurrence could not be deter-mined.
The inspector stated that the two events are related in that both involved control of plant equipment; i.e.,
the isolation dampers.
Licensee actions, taken in response to the first event, to upgrade the control of the dampers could reasonably have been expec-ted to prevent the second event.
Therefore, even though the second event was licensee identified, it does not meet the criteria of
CFR 2 Appendix C for NRC to waive issuance of a Notice of Violation for the item.
This event occurred as a result of misinterpretation of the Equipment Release Form (ERF) issued for the removal of 719 elevation removable wall due to its poor wording and inadequate communications.
The ERF was phrased such that it requested operations to align the Railway Bay Ventilation to Zone I while the removable walls were not sealed and intact.
However, since the only ventilation system alignment to the railroad bay is through the Zone III manual isolation dampers, the operator believed the ERF was requesting that the Zone III isola-tion dampers be opened while the 719 elevation removable wall was down.
In addition, verbal communications with the Unit Supervisor and Plant Control Operator failed to clarify the desired evolution, that is to isolate the railroad bay in accordance with OP-134-002 for the purpose of removing the 719 elevation wal.4 The inspector reviewed operator logs, system status logs, newly revi'sed Operating Procedure OP-134-002, Reactor Building HVAC Zone I and Zone III, and Equipment Release Forms (ERFs)
and discussed the event with the licensee.
In addition, LERs87-024 and 87-026 issued by the licensee on September
and October 5,
1987, respectively, were reviewed to determine the adequacy of the licensee's corrective actions and to determine the validity of their root cause determina-tion.
The corrective action taken following the event discovered on August 10, clear damper open/close position labeling, was apparently inadequate in that it failed to prevent a
recurrence less
. than one month later.
Corrective action taken following the second event includes:
instruction on the correct wording to be used when reques-ting wall removal, modification of OP-134-002 to assure the verifica-tion of closure of the Zone III manual isolation dampers whenever the railroad access bay wall is to be removed, training of the operations staff on these changes, and stressing the importance of clear commun-ications'~
These actions together, if implemented properly, may be adequate to prevent a recurrence of the type of event caused by oper-ator error, however, they will be ineffective for the type of event which involves mispositioning by other individual(s)
whether delib-erate or not and do not incorporate a more positive means of control of these dampers or alert operators that the dampers are misposit-ioned.
As a result of review of the operators daily logs and control room tours, the inspector verified that
.25 inch of vacuum water gauge was maintained for secondary containment throughout the period of concern resulting in no significant increase in risk to public health and safety from normal operations.
If an accident would have occurred requiring isolation of Zone II and/or Zone III, the possi-bilityy existed that some air could have been drawn into Zone I and discharged to the atmosphere unfiltered but monitored by the reactor building exhaust monitors.
The inspector requested the licensee to perform an analysis to ascertain the ability to maintain secondary containment integrity during accident conditions.
The licensee per-formed a preliminary analysis and determined that Standby Gas Treat-ment System draw down time and capability would not be adversely affected and that any potential release through Zone I unfiltered exhaust would be within design basis limits.
Unusual Event Declared Due to Main Steam Line Plu E ection Unit
At 8:50 p.m, on September 22, the 'C'ain Steam Line Plug was ejected from the main steam line, where it was installed to perform MSIV LLRTs.
A pressure increase to accommodate testing was in pro-gress.
When MSL pressure reached 38 psig, the plug was ejected into the reactor vessel.
Upon ejection, the 1/4" stainless steel lanyard and one air hose tore apart and the plug became suspended by its two remaining hoses and a 1/2" nylon rope tying the hoses to the reactor
cavity handrail.
The plug came to rest against the side of the reactor vessel several feet below the main steam line nozzle.
As a
result of the plug ejection, a large air bubble rose to the top of the refuel pool above the reactor cavity and caused water to overflow the sides of the pool onto the refueling floor, but within previously roped off contaminated.
areas.
In addition, the main steam lines flooded with water up to the inboard MSIVs and the licensee added approximately 3,000 gallons of makeup water.
All activities in the drywell and on the refuel floor were suspended and all personnel removed from the refuel floor elevation.
It was determined that no process radiation monitor levels changed during the transient.
The licensee was not moving fuel during LLRT testing of the MSIVs.
The Unit 1 unit supervisor climbed onto the refueling bridge at 9:30 p.m.
and determined that the 'C'ain steam line plug was blown out.
At approximately 2:00 a.m.,
PORC convened and approved a work plan to secure and retrieve the plug from the reactor vessel.
At 4:25 a.m.,
an Unusual Event was declared based on the 'General'ategory of EP-IP-001, Emergency Classification, which involves the potential degradation of the level of safety of the plant.
This determination was made since the possibility existed that during retrieval efforts the plug could conceivably be dropped onto the fuel.
The unusual event lasted until 3:20 p.m. during which time the licensee secured and retrieved the main steam line plug, raising it over the reactor vessel studs and lowering it to the reactor cavity seal plate outside the reactor vessel.
Discretionary manning of the Technical Support Center (TSC) was per-formed and the duty manager assumed the role of Emergency Director.
All required notifications were made by the Unit 2 plant control operator who was designated as the communications coordinator.
Dur-ing efforts to secure and retrieve the plug, communications were established between the refueling floor, the control room and the TSC.
Following removal of the plug, the licensee performed visual inspec-tions of the MSL nozzle, reactor vessel, and the MSL plug for damage and for missing parts/debris in the vessel.
Neither damage, nor loose parts were discovered, although the inflatable rubber seal had been retrieved ear lier from the pool surface since it had come off when the plug was ejected.
The licensee is presently investigating the event to determine its cause and to, develop corrective actions to prevent its reoccurrence.
This item is unresolved pending review of the licensee's investigation (387/87-16-03).
3.5 S ill on the 'B'ore S ra Pum Room At 6: 15 a.m.
on-September 30, the 'B'ore Spray Loop was being filled by the Condensate Transfer System to perform SE-151-311, Core Spray Loop 'B'SME Hydrostatic Test, when approximately 1300 gallons of water spilled onto the floor of the pump room through the suction relief valve, PSV-1F032B.
The condensate transfer system was isola-ted and an investigation revealed that the leak was caused by tempor-ary scaffolding erected for the Unit
Refueling Outage which was resting against the discharge check valve's ( 1F003B)
handle preven-ting it from closing.
This allowed the suction side of the 'B'ore Spray Loop to pressurize to the relief valve setpoint of 103 psig since keep fill system pressure is 150 psig.
The scaffolding was subsequently moved enough to allow the discharge check valve to fully close, the room decontaminated, and work resumed.
No individuals were contaminated during this event; however, approximately 700 square feet of area in the pump room was contaminated at levels up to 60,000 dpm per 100 square centimeters.
The inspector reviewed the event and toured the 'B'ore Spray Pump Room to verify that the temporary scaffolding was no longer interfering with the valve handle's free movement.
In addition, the inspector reviewed AD-gA-903, Scaffold Erection Review and Inpsection, to ascertain that con-trols exist to preclude interference with plant equipment that may affect plant operations and safety.
Section 4.4 specifically stated that it is the installer's responsibility to verify that scaffolding and associated bracing do not interfere with plant operations or endanger the safe operability of the plant system.
3.6 An inspection tag on the scaffolding indicates that the scaffolding was inspected on September 18 following installation and was verified to not interfere with plant operations and not endanger operation of plant systems.
This item is unresolved pending review of licensee'
corrective actions to prevent recurrence.
Due to the licensee's practice of issuing a
press release on the event, an Emergency Notification System (ENS) call was made as required by
CFR 50.72 (387/87-16-04).
Area and Personnel Contamination At 1:00 p.m.
on September 30, while connecting an air hose between a
temporary service air header located in the drywell to a
packing extraction tool in Unit 1 Reactor Building elevation 719 feet, four individuals and approximately 300 square feet of area were contamin-ated.
It was determined that inadequacies in the hose control pro-gram led to the use of a contaminated hose for the air supply to the packing extraction tool.
In addition, poor communication between the
individual connecting the hose to the service air header and the individuals outside the drywell led to the air supply being valved in prior to the hose being connected to the packing extraction tool, blowing contaminated moisture and air into the area.
This caused a
hurried endeavor to connect the hose to the packing extraction tool which resulted in the hose being attached to the wrong connection and contaminated moisture and air being blown out of the tool at another connection.
The results were that 300 square feet of area was contaminated at levels up to 10,000 dpm per 100 square centimeters and four individ-uals became contaminated.
On two of the individuals contamination was restricted to their clothing with peak readings on their shoes of 120,000 dpm and 280,000 dpm per 100 square centimeters respectively.
The remaining two individuals received peak skin contaminations of 20,000 dpm per 100 square centimeters to one individual's hands and 200,000 dpm per 100 square centimeters to the other individual's right forearm.
All four workers were checked for internal contamina-tion and none was detected.
The workers, their clothing, and the area were subsequently decontaminated.
The licensee temporarily evacuated the drywell and stopped all work within until the area was decontaminated and a
new policy concerning the use of hoses was implemented.
In discussions with the inspector, the licensee stated that they have implemented a
hose control program for the drywell whereby all clean air hoses will use quick disconnect fittings and other hoses will use Chicago fittings.
This policy is to be expanded to include the overall site.
In addition, a training exercise was conducted for personnel involved in the use of hoses in the drywell.
At this time, the licensee's hose control program is documented only in the form of written memos with plans for implementing a written procedure sometime in the future.
Due to the licensee's practice of issuing a
press release on the event, an ENS call was made as required by
CFR 50.72.
The inspector had no further questions.
4.0.
Licensee Re orts 4.1 In-Office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the NRC:RI office to verify that details of the event were clearly reported, including the 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
"87-024, Reactor Protection System Electrical Protection Assembly (EPA) Breaker Spurious Trip
""87-025, Reactor Building Heating, Ventilating and Air Conditioning Zones I and III Cross-tied Unit 2 87-007, HPCI System is Declared Inoperable Due to a Malfunctioning Steam Supply Valve
- Further discussed in Detail 4.2
- "Previously discussed in Inspection Report 50-387/87-12; 50-388/87-12 4.2 Onsite Followu of Licensee Event Re orts For those LERs selected for onsite followup (denoted by asterisks in Detail 4. 1),
the inspector verified that the reporting requirements of 10 CFR 50.73 had been met, that appropriate corrective action had been taken, that the event was adequately reviewed by the licensee, and that continued operations of the facility was conducted in accordance with Technical Specification limits.
The following find-ings relate to the LERs reviewed on site:
4.2. 1 LER 87-024:
Reactor Protection S stem Electrical Protection Assembl EPA Breaker S urious Tri On July 22, 1987, at 5:04 a.m.,
with Unit 1 operating at 100 percent power, the primary power supply to the
'A'eactor Protection System (RPS)
Panel lY201A was lost when the 'C'lectrical Protection Assembly (EPA) breaker trip-ped.
The following were observed to occur, as designed, when the EPA breaker tripped following loss of RPS power; isolations of Reactor Water Cleanup and Heating, Ventila-tion and Air Conditioning Zones I and III systems occurred;"
Standby Gas Treatment and Control Room Emergency Outside Air Supply Systems initiated; and other secondary isola-tions, trips and indications took place.
The cause of the EPA breaker trip is undetermined.
All functions of the EPA logic card were tested and found within tolerances, with no evidence of spurious trip out-puts.
The molded case breaker was operated several times and reset properly after each trip.
The trip occurred as an RPS channel half-scram was being reset during a weekly Average Power Range Monitor Functional Test surveillance, and is surmised to have been a spurious load induced tri Operations personnel transferred the 'A'PS to its alter-nate power supply and the affected systems were restored.
Subsequent investigation and functional testing determined that no breaker or logic card problems existed.
Therefore, the licensee was not able to develop corrective action to prevent a
recurrence.
Full power operation. of the unit continued uninterrupted.
Although six previous occurrences of EPA breaker trips resulted in ESF actua-tions, this is the first instance which appears to be due to a
spurious load induced trip.
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.
The following periodic and special reports were reviewed:
Monthly Operating Report -
August, 1987, dated September 11, 1987.
The above report was found acceptable.
5.0 Surveillance and Maintenance Activities 5. 1 Monthl Surveillance Observations 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-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 frequenc These observations included:
TP-054-065, Pump Curve and Flow Data for 'A'nd 'C'SW Pumps performed on'eptember 11, 1987.
No unacceptable conditions were identified'.2 Monthl Maintenance Observation The inspector observed portions of selected maintenance activities to determine that the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes or standards.
The following items were considered during this review:
Limiting Conditions for Operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and gC hold points were estab-lished where required; functional testing was performed prior to declaring the particular component operable; activities were accom-plished by qualified personnel; radiological controls were imple-mented; fire protection controls were implemented; and the equipment was verified to be properly returned to service.
These observations included:
'B'iesel Generator Maintenance performed from August 31 to September 16.
PMR 86-9073, Installation of new suction end bells on 'A'nd
'C'SW Pumps performed on September 9 and 10.
No unacceptable conditions were identified.
6.0 Unit 1 Third Refuelin and Ins ection Outa e
6. 1 Refuelin Outa e
Summar The Unit 1 Third Refueling and Inspection Outage began on September 12, 1987 at 1:02 a.m.
when the unit was manually scrammed from
percent power.
The unit reached Operational Condition 4 (cold shut-down)
on September 12.
Operational Condition
(Refueling)
was entered on September 14, after a 14-hour delay caused by removal of the Division 2 24 VDC batteries for testing which left an inadequate number of Intermediate Range Monitors (IRMs)
available
'to meet Technical Specification (TS)
requirements for entry into Condition 5.
The issue was resolved by Emergency Technical Specification relief from the NRC allowing entry into Condition 5 (See Detail 6.2).
The reactor vessel head was removed on September 15 and core offload commenced on September 1 On September 18, a crack was discovered in the steam dryer hood of a weld seam.
This crack is similar to others discovered and repaired in a previous Unit 1 outage in 1983.
A thorough inspection of the dryer was performed to verify that no other cracks were present.
Plans are presently being formulated to perform repairs underwater due to a contact reading of 10R/hour on the dryer (See Detail 6.3).
Refueling was suspended on September
due to damage to the Unit
fuel mast.
At 4:25 a.m.
on September 23, an Unusual Event was de-clared prior to retrieving a main steam line plug due to the poten-tial for dropping it onto the fuel.
The plug was blown out of the main steam line during LLRT testing of the MSIVs the previous night (Detail 3.4).
Defueling recommenced on September 25 with core off-load'completed on September 29.
Major outage work to date has consisted of work on Appendix R modifi-cations, core spray and RHR LLRTs, snubber testing, heat exchanger inspections,
VDC and 250 VDC battery replacements, and CRD change-outs.
6.2 Emer enc Technical S ecification Relief On September 13, 1987, the licensee reported that due to an outage scheduling error, they were unable to enter Operational Condition
(Refueling).
While the unit was in Operational Condition 4,
one division of the
YDC batteries was rendered inoperable when they were released to perform the Technical Specification required
month performance discharge test.
With the batteries inoperable, the associated Intermediate Range Monitors ( IRMs) required by Technical Specification Table 3.3.6-1 were rendered inoperable.
With less than six of the eight IRM's operable entry into Operational Condition
was precluded by Technical Specification 3.0.4 which prohibits entry into an Operational Condition when relying on provisions contained in the action requirements'.
The licensee had not foreseen this Tech-nical Specification requirement in the planning process, and reques-ted Emergency Technical Specification relief to avoid delaying the outage unti 1 the batteries were sufficiently recharged to declare them operable.
The licensee formally requested the license Amendment on September 14, 1987 (PLA-2916) in Proposed Amendment 102.
The request refer-enced NRC Generic Letter 87-09 which discussed unnecessary restric-tions on mode changes by Specification 3.0 '
and inconsistent appli-cation of exceptions to the Specification.
Following several tele-phone discussions with NRC Region I and NRR, it was determined that there was no safety significance in granting the relief and it was technically justifiabl NRR granted the Emergency Relief by telephone on September 14, 1987 and confirmed the relief by letter dated September 15, 1987.
Using the one time relief, the licensee entered Operational Condition 5 at 8:48 p.m.
on September 14, 1987.
The formal Technical Specification Change and associated Safety Evaluation were issued on September 23, 1987 (TAC No. 66177).
6.3 Steam Dr er Crack On September 18, 1987, upon removal of the reactor vessel ste'am dryer, a crack was discovered on the steam dryer hood in a.weld seam.
The crack was three-quarter inch wide by fifty-seven inches long.
A previous repair had been performed
'on a similar crack 180 degrees from the location of'he new failure.
The previous crack. was dis-covered on. December 9,
1983 (See Inspection Reports 50-387/83-25 and 50-387/84-22).
In addition, a
simi lar failure was predicted by General Electric following evaluation of the cause of the steam dryer support block failure (See Inspection Report 50-387/87-12).
The licensee has formed a task force to perform an assessment of the repair method.
Due to the high radiation fields in the area of con-cern ( 10 R/HR on contact)
an underwater repair procedure is being evaluated.
NRC Region I is reviewing the licensee's repair procedure and a
Region-based specialist will follow the repai r activities.
7.0 Mana ement Meetin On October 8,
1987.,
the inspector discussed the findings of this inspec-tion with station management.
Based on NRC Region I review of this report'nd discussions held with licensee representatives, it was determined that this report does not contain information subject to
CFR 2.-790 restrictions.
On September 29, 1987, NRC Commissioner Rogers visited the site and met with licensee managemen REGIONAL ADMINISTRATOR VISIT TOUR DISCREPANCIES Health Ph sics Office Posted Survey Maps are undated, leaving potential for incorrect information displayed.,
Posted Maps and most recent survey map of RWCU room were not con-sistent.
Unit 1 Reactor Buildin Elevation 779 Three instrument root valves (OP1-PDIS-14587A, OP2-PDIS-14587A, OP2-PDIS-14588A)
had active packing leaks.
RWCU Precoat Pump (1P222)
had slight grease buildup near the air inlet.
Elevation 749 Area Radiation Monitor (RIT 13708 Channel 8) did not have consistent readings between the low range detector (0.3 mR/Hr)
and the high range (500 mR/Hr).
Fasteners were not tightened on the'KV switchgear panels (front and back).
A packing leak was evident on SLCS valve 148012 and the packing was taken all the way up.
Boron crystals were built up underneath.
Pull box cover off near RPS MG Set (Conduit AIM089).
RPS breakers susceptible to inadvertent tripping.
Elevation 719 Packing leaks noted on 6 HCU's.
Some terminal boxes on HCU's not tightened.
Elevation 683 Cable wrap off of cable above equipment area door.
Metal shavings noted on valve limit switch near RBCCW heat exchanger
.
Attachment 1'levation 645 Core Spray Room Cooler air intake dirty.
Core Spray Room Cooler ESW flex hoses (supply and return) leaking at weld.
Grease buildup in Core Spray Room Cooler Blower (1V211D).
A RHR pump motor thermocouple cover off.
One snubber (PSA-100)
in 'A'HR room was installed upside down (in overhead under grating where it will collect debris).
Control Structure White substance in top of battery cells (250 VDC).
Latches broken on Control Rod Drive panel in upper relay room.