IR 05000387/1989024
| ML17156B439 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 10/23/1989 |
| From: | Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17156B438 | List: |
| References | |
| 50-387-89-24, 50-388-89-22, NUDOCS 8911070155 | |
| Download: ML17156B439 (61) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
,
REGION I
Report Nos.
50-387/89-24; 50-388/89-22 License Nos.
Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Facility Name:
Susquehanna Steam Electric Station Inspection At: Salem Township, Pennsylvania Inspection Conducted:
July 30, 1989 - September 9,
1989 Inspectors:
Approved By:
G.
S. Barber, Senior Resident Inspector, SSES J.
R. Stair, Resident Inspector, SSES P.
Kaufman, Project Engineer M. Thadani, Licensing Project Manager, NRR T.
Koshy Specialist Inspector,DRS Reactor Projects Section No. 2A, Division of Reactor Projects long ~
Inspection Summary:
Areas Inspected:
Routine inspections were conducted in the following areas:
plant operations, physical security, plant events, surveillance, and maintenance.
Results:
During this period, Operations Department personnel generally conducted activities in a professional manner and operated the plant safely., Routine review of maintenance and surveillance activities noted good control and performance.
Two reportable events involving high pressure coolant injection (HPCI) occurred during the period.
The first event in Unit 1 was due to a personnel error while performing a surveillance procedure.
A step in the procedure was mistakenly performed out of sequence, resulting in an automatic transfer of the
+911070155 8~000>+7 PDR ADOCK 0 pDC Q
HPCI suction path from the Condensate Storage Tank to the Suppression Pool.
The other event in Unit 2 was due to a conservative determination that HPCI was inoperable as a result of degraded stop valve operation during a daily exercise of the valve.
The system was subsequently determined operable based on engineering judgement.
A reactor recirculation system runback to 56 percent power occurred on Unit 2 due to spikes on the "B" narrow range level instrument.
Plant response appeared normal" and licensee actions were appropriate.
Unusual Reactor Pressure Vessel inservice inspection ( ISI) indications for Unit
were identified during a licensee review of the ISI data.
As a result, regional specialist inspectors responded to the site.
A separate inspection report documents their findings.
.Allegations regarding reporting of design deficiencies were reviewed.
Two of these were substantiated with respect to the reportability of leak detection (LD) system design basis inadequacies and inboard main steam isolation valve (HSIV) operability for certain design base accident conditions.
Another allegation regarding reportability of a diesel generator ground fault was not substantiated.
A Unit 2 containment atmospheric control system isolation occurred due to pufling incorrect fuses.
This item requires further corrective actions by the licensee.
A potentially significant exposure of a contractor individual occurred when the individual placed a contaminated mi llipore filter in his shirt pocket.
Regional specialist inspectors visited the site to review this event.
The results of this review are documented in a separate inspection report.
A miswiring of the "A" Control Structure Chiller led to chiller damage during an 11 minute run without lubricating oil.
A task force was formed to evaluate and determine causal factors leading to this occurrence, and to prevent a recurrence.
A Unit 1 shutdown occurred due to the potential inoperability of the suppression pool-to-drywell vacuum breakers.
The licensee determined that the existing operability analysis was inadequate.
This was a good example of the licensee's typically conservative actions.
Licensee Event Reports (LERs) were found to provide clear and accurate descriptions of the events and corrective actions take TABLE OF CONTENTS Page 1.0 Introduction and Overview
.
.
.
.
.
.
.
.
.
.
.
.
....
.
.
.
.
.
.
.
1.1 NRC Staff Activities (Module Nos.
30703, 71707, 90712, 92701, 60710, 64704, and 37700)
1.2 Unit 1 Summary 1.3 Unit 2 Summary 2.0 Routine Periodic Inspections
.
2.1 Scope of Review 2.2 HPCI Automatic Suction Path Swap to Suppression Pool - Unit
2.3 Shutdown due to Potential Inoperability of Vacuum Breakers - Unit 1.
2.4 HPCI Declared Inoperable Due to Stop Valve Behavior - Unit 2 2.5 Runback on Level Spikes - Unit 2 3.0 Surveillance and Maintenance Activities 3.1 Surveillance Observations (Module No. 61726 and 71711)
3.2 Maintenance'Observations (Module No. 62703)
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
4.0 Licensee Reports
.
4.1 In-office. Review of Licensee Event Reports (Module No. 90712)
4.2 Review of Monthly Operating Reports (Module No. 90713)
5.0 Unusual Reactor Pressure Vessel ISI Indications - Unit
.
~
~
~
~
~
.'.
,
6.0 Unexpected CAC Isolation Due to Improper Fuse Pulling - Unit 2
.
7.0 Possible Localized Overexposure Due to Concentrated Reactor Water Sample
.
8.0 Reportability of Design Deficiencies - Allegation Followup
.
8.1 Reportability of EDG Failure (NRR-87-0011)
8.2 Engineering and Design Deficiency Reporting Weaknesses 8.3 Improper Closure of Appendix R Nonconformance Report-Allegation (RI-89-A-0040)
9.00 A Control Structure Chiller Miswiring 10.0 Emergency Plan Drill
.
.
10
22 11.0 Management Meeting - Integration of PRA and Reliability Engin into Maintenance
.
12.0 Resident Monthly Exit Meeting eering
23
DETAILS 1.0 Introduction and Overview NRC Staff Activities 1.2 The purpose of this inspection was to assess licensee activities at Susquehanna Steam Electric Station (SSES)
as it related to reactor safety and worker radiation protection.
Within each area, the in-spectors documented the specific purpose of the area under review, scope of inspection activities and findings, along with appropriate conclusions.
This.assessment is based on actual observation of licensee activities, interviews with licensee personnel, measurement of radiation levels, or independent calculation and selective review of applicable documents.
Unit 1 Summar Unit I operated at or near full power for most of the inspection period.
Scheduled power reductions were conducted during the period for control rod pattern adjustments, surveillance testing, and maintenance.
On September 8, the unit was shutdown due to a deter-
'mination by the licensee that the'suppression pool-to-drywell vacuum breakers were potentially inoperable.
See Section 2.3 for details.
One Engineered Safety Features (ESF) actuation occurred on August 9, when the suction path to the High Pressure Coolant Injection (HPCI)
system automatically transferred to the suppression pool.
See Section 2.2 for details.
1.3 ~2 Unit 2 operated at or near full power until August 24, when a
runback to 56 percent power occurred due to level spikes on the
"B" narrow range reactor vessel level instrument.
Full power was restored on August 25.
See section 2.5 for details.
On August 10, the licensee declared the HPCI system inoperable due to erratic stop valve operation.
See section 2.4 for details.
The unit operated at full power for the remainder of the inspection period.
Shutdown for the Unit 2 third refueling outage began on September 9, at approxi-mately 6:00 p.m..
One ESF actuation occurred on August 29 when the incorrect fuses were pulled resulting in an isolation of the supply and return valves to the hydrogen/oxygen analyzers.
See Section 6.0 for details.
2.0 Routine Periodic Ins ections 2.1 Sco e of Review The facility was inspected periodically to determine the licensee'
compliance with the general operating requirements of the Technical Specifications (TS) in the following areas:
review of selected plant parameters for abnormal trends; plant status from a maintenance/modification viewpoint, including plant housekeeping and fire protection measures; control of ongoing and special evolutions, including control room personnel awareness of these evolutions; control of documents, including logkeeping practices; implementation of radiological controls; implementation of the security plan, including access control, boundary integrity,,and badging practices; control room operations during regular and backshift hours, including frequent observation of activities in progress, and periodic reviews of selec.ed sections of the unit supervisor's log, the control room operator's log and other control room daily logs;
.
followup items on activities that could affect plant safety or impact plant operations; areas outside the control room; and, selected licensee planning meetings.
>The inspectors inspections on f'rom 3:00 a.m.
August 27.
conducted deep backshift and weekend/holiday August 25, from 2:00 a.m. to 6:00 a.m.,
September 1,
to 6:00 a.m.
and, from 2:00 p.m. to 7:00 p.m.,
The inspector s reviewed the following specific items in more detail.
2.2 HPCI Automatic Suction Path Swa to the Su ression Pool Unit
At 9:00 a.m.
on August 9, during performance of Instrument and Control (I&C) Surveillance SI-152-308, (Quarterly Calibration of Condensate Storage Tank Low Level Channels LSLL-E41-N002 and LSLL-E41-N003),
an IKC technician mistakenly performed step 6. 1. 15 (close states link ¹1) prior to performing step 6. 1. 14 (disconnect multimeter and remove test equipment),
resulting in a transfer of the High Pressure Coolant Injection System (HPCI)
suction path from the Condensate Storage Tank (CST) to the Suppression Pool.
The 18C technician immediately removed the multimeter and contacted the operating crew who restored the HPCI suction to the CS The licensee's compliance group reviewed the event at 10:00 a.m.,
August 10 and determined that this event was reportable under
CFR Part 50.72(b).
This was based on the fact that the auto transfer of the HPCI suction valves is an Engineered Safety Feature (ESF) of the HPCI system and that spurious actuation of the logic and repo-sitioning of the suction valves constitutes an ESF actuation.
An Emergency Notification System (ENS) call was therefore made at 11: 17 a.m.
on August 10, 1989.
No HPCI initiation or injection occurred and no other system components were affected as a result of this ESF actuation.
2.3 The inspector reviewed the Significant Operating Occurrence Report (SOOR)
on this event and discussed specifics of the event and corrective actions with the licensee.
As a result, the inspector determined that the licensee's corrective actions in response to the event were appropriate and conservative.
However, the inspector was concerned that the operations staff did not conclude that an ESF actuation had occurred and therefore a delay of approximately one day in the ENS notification occurred.
This item was discussed with the licensee who agreed that the operations staff should have identified the reportabi lity requirement.
Tlute inspector determined that this oversight constitued a licensee identified violation of 10 CFR 50.72 which will not be cited under the conditions of 10 CFR 2.
(387/89-24-03)
Shutdown Oue to Potential Ino erabilit of Vacuum Breakers - Unit 1 On September 8,
1989, the licensee determined that a modification to the test circuitry for each of the 10 suppression pool-to-drywell vacuum relief valves which had been incorporated during the Unit
fourth refueling outage was deficient.
The modification replaced the previous rubber instrument tubing and elbows with braided stainless steel tubing and new elbows, but failed to provid'e an orifice in each new elbow to the actuating cylinders.
The actuating cylinders serve to open the valves for testing and to dampen the valves closing stroke during all modes of operation.
The licensee had generated a Non-Conformance Report concerning the missing orifice and determined that during the design of the modification, the orifice had been overlooked.
This was not realized until development of a similar Engineering Change Order for Unit 2.
The licensee considered the valves poten-tially inoperable without the orifice present because of the potential damage to the valve without dampening the valve closing velocity to the extent accomplished by the orifice.
The licensee determined that the existing analysis was inadequate and therefore considered that the conservative approach was to enter Technical Specification Limiting Condition For Operation 3.0.3 and shut down the unit to correct the modification.
Shutdown commenced at 5:07 p.m. on, September 8.
The orifices were installed and the plant was returned to service on September 1.4 HPCI Declared Ino erable Due to Sto Valve Performance - Unit 2 At 8:20 a.m.
on August 10, the licensee declared the High Pressure Coolant.Injection (HPCI) System inoperable following a daily exercise of the HPCI turbine stop valve in which the valve opened to approxi-mately 18 percent, closed and opened again after four seconds to 100 percent full open.
A 14-day limiting condition for operation (LCO)
was then entered and the appropriate NRC notification made.
A review by the licensee's technical staff later that day determined that the system was not inoperable since during actual operation, steam forces acting on the disc following its initial lift aids lube oil pressure in assuring that the valve will remain open while the lube oi.l supply switches to the shaft driven pump.
Pressure to open the stop valve during these exercises is applied strictly by the auxiliary oil pump.
Since the valve has always lifted off its seat initially, the licensee believed that it would continue to do so.
During the refueling outage scheduled to begin September 9, the licensee plans to dismantle the system for inspection and repair.
The LCO was therefore exited and HPCI was returned to operable status at 10:45 p.m.
on August 10.
A weekly exercise ( ycling) of the turbine stop valve has been implemented for both units to improve lube oil, control, and stop valve response, as well as to identify any potential lube oil system problems.
This testing'f the HPCI turbine stop valve was initiated on July 27, 1984 after observing the same response during previous surveillance tests performed on December 6,
1988 and May 25, 1989.
During a subsequent exercise on August 5, the valve failed closed after an initial lift.
The valve was later cycled successfully three
, succeeding times that day and the three following days'he weekly exercise was increased to daily on Unit 2 in order to ensure HPCI operability.
No similar problems have been seen on Unit l.
The inspector discussed the event with appropriate members of the licensee's staff; reviewed the written report of the event, the technical operability evaluation, and traces of the stop valve operation from two previous surveillance tests and four stop valve exercises.
Discussions with the licensee assured the inspector that a failure of the stop valve during the daily exercise would result in the appropriate LCO entering and declaring HPCI inoperable.
As a
result, the inspector considered the licensee's actions in response to this problem acceptable and that the licensee is providing reason-able assurance that the HPCI system is capable of performing its intended functio.5 Runback on Level S ikes - Unit 2 At 10:58 a.m.
on August 24, 1989, spikes in the "B" Narrow Range reactor water level instrument occurred causing a reactor recirculation system runback and a feedwater level control system setback to 18 inches.
The reactor recirculation system runback was due to reactor water level being sensed at 13 inches or less on the "B" instrument.
The feedwater level setback was due to the actuation of the level setdown switch when the indicated level on channel B decreased to below 30 inches.
When the runback was observed, the operators took manual control of the reactor recir-culation pumps and ran recirculation flow back to 41 million pounds per hour and 56 percent power since they believed that the automatic recirculation system runback was not quick enough to keep up with the feedwater runback.
Region II of the power-to-flow map was entered at the end of the runback.
This is an instability region of the map, and to exit it requires either increasing flow or driving in control rods.
The operators increased flow to 5Q percent in order to exit Region II and noted that no instability (power osci llations) occurred.
Feedwater level control was placed on the "A" narrow range level instrument while troubleshooting the "B" level instrument.
At 10:40 p.m.
power ascension commenced.
The inspector reviewed traces of the system parameters relating to the event to ensure that plant response to the event was per design.
Discussions with operators and the Shift Technical Advisor pertaining to the event, and review of the Significant Operating Occurrence Report determined that licensee actions were appropriate.
Further licensee investigation is planned to determine the cause of the spiking.
The inspector had no further questions about the event.
3.0 Surveillance and Maintenance Activities On a sampling basis, the inspector observed and/or reviewed selected surveillance and maintenance activities to ensure that the specific programmatic elements described below were being met.
Details of this review are documented in the following sections'.1 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine that the following criteria, if applicable to the specific test, were met:
the test conformed with Technical Specification requirements; administrative approvals and tagouts were obtained before initiating the surveillance; testing was accomplished by qualified personnel in accordance with an approved
procedure; test instrumentation was calibrated; limiting conditions for operations were met; test data was accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
These observations and/or reviews included:
S0-024-001D, Monthly Diesel Generator (DG) Operability Test of the "D". Diesel Generator, performed on August 14, 1989.
SI-179-201, Monthly Functional Test of Main Steam Line Radiation Monitors RIS-012-1K603 A,B,C,D, performed on
. August 14, 1989.
S0-024-001A,
"A" DG Operations Surveillance Retest performed on August 15, 1989.
S0-024-013, Offsite Power Source Operation Test performed on August 15, 1989.
No unacceptable conditions were identified.
3.2 Maintenance Observations The inspector observed and/or reviewed 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, as appli-cable, during this review:
Limiting Conditions for Operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and quality control hold points were established where required; functional testing was satisfactorily performed prior to declaring the involved component(s)
operable; activities were accomplished by qualified personnel; radiological controls were implemented; fire protection controls were implemented; and the equipment was verified to be properly returned to service.
These observations and/or reviews included:
Performance of calibration check for HPCI transmitter/converter per Work Authorization (WA) P92584, on August 25, 198 l
0
~ >I
~ ~
~
Performance of actuator inspection/maintenance on Emergency Service Water Valves HV-01112D and HV-01122D per WA S93154, on August 31, 1989.
Retubing of the Gaseous Radwaste Recombiner Closed Cooling Water Heat Exchanger 1E-107 per Construction Work Order (CWO)
C99350.
Installation of Heat Trace Cable on Offgas Recombiner Vessel 1S-125 per CWO C90415.
No inadequacies were noted.
4.0 Licensee Re orts 4.1 In-office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the NRC office to verify that details of the event were clearly reported, including the accuracy of description of the cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup. The following LERs were reviewed:
Unft
89-019-00, Identification of Damaged Fire Barrier Penetration Seals.
89-020-00, Unplanned ESF Actuations as a Result of Circuit Breaker Termination/Mounting Hardware Failures in the Reactor Protect>on System Distribution Panel.
89-021-00, Mislabeled Damper Position Resulted in a Prohibited Alignment.
Discussed in NRC Inspection Report 50-387/89-15.
89-022-00, ESF Actuation due to Spurious Auto-Transfer of HPCI Suction Valves.
Discussed in Section 2.2.
No inadequacies were noted.
4.2 Si nificant 0 eratin Occurrence Re orts Significant Operating Occurrence Reports (SOORs)
are provided for problem identification tracking, short and long term corrective actions,,
and reportabi lity evaluations.
The licensee uses SOORs to document and bring to closure problems identified that do not merit an LER.
The inspectors reviewed the following SOORs during
I J
l
~
~ 4
'
f ~
'
the period:
1-89-264, 1-89-268, 1-89-269, 1-89-270, 1-89-271, 1 89 272 1 89 273 1 89 274 1 89 275i 1 89 276 1 89 277 1 89 278 1"89-279, 1-89"280, 1-89-281, 1"89"282, 1-89-283, 1"89-284, 1-89-285, 1-89-286, 1-89-287, 1-89-288, 1-89"289, 1-89"290, 1"89-291, 1"89-292, 1-89"293, 1-89"294, 1-89-295, 1"89-296, 1-89-297, 1-89"298, 1"89-299, 1"89-300, 1-89-302, 1-89-303, 2-89"087, 2-89-088, 2-89-089, 2"89"090, 2-89-091, 2-89-092, 2-89-093, 2-89"094, 2-89-095, 2"89-096, 2"89"097, 2-89-098, 2"89"099, 2-89-100, 2-89-101, 2"89-102, 2"89-103, 2"89-104, 2-89-105, 2-89-106, 2-89-107, 2-89-108, 2-89-109, and 2-89-110.
The following SOORs required inspector followup:
1-89-273 documented an unplanned ESF actuation involving the transfer of the HPCI suction supply valve from the condensate storage tank to the suppression pool.
See Section 2.2 for details.
1-89-287 documented a wiring error which resulted in the "A" Control Structure Chiller starting whenever Drywell Fan 1V418A was running.
See Section 9.0 for details.
2-89-091 documented HPCI stop valve erratic operation upon opening.
See Section 2.4 for details.
2-89-092 documented declaring HPCI inoperable due to erratic stop valve operation.
See Section 2.5 for details.
2-89-103 documented a recirculation pump runback to 56 percent power.
See Section 2.4 for details.
2-89-104 documented an unexpected Containment Atmosphere Control System Isolation.
See Section 6.0 for details.
2-89-105 documented the potentially significant exposure of a consul-tant due to the failure to follow the requirements of an RWP and poor radiation work practices.
See Section 7.0 for details.
5.0 Unusual Reactor Pressure Vessel ISI Indications Unit
The licensee identified unusual Reactor Pressure Vessel (RPV) In-Service Inspection (ISI) indications during a post outage review of ISI data.
The review was conducted to document completion of the first 10 year ISI period.
The inspection had been performed on the RPV during the Spring 1989 refueling outage in a manner similar to the pre-service inspection (PSI).
A total of 96 small indications were observed on weld BA of the RPV vice 34 observed over the same area during PSI with a zero degree scan of the area.
Similar examination techniques were used in both the ISI and the PSI.
Weld BA is a vertical weld connecting rolled steel plates at the RPV beltline above weld AA which connects these rolled plates to the RPV
6.0 bottom head.
The i'ndications were approximately 57 inches up from weld AA adjacent to the weld BA centerline in the vicinity of the recirculation pump drive flow penetrations.
The majority of indications were outside the double bevel weld area.
Others were indeterminate for the 0 degree scan because of the double bevel configuration.
The 45 degree scan did not show any of the 94 indications observed on the 0 degree scan.
No cracks were observed on either scan.
Therefore, the licensee concluded that the vessel was operable.
The inspector concurred with the licensee's operability conclusion but asked why the discrepancies had not been resolved earlier.
The inspector recommended that the licensee conduct a
conference call with the NRC regional office to discuss the indications.
A conference call was held on July 31, to discuss the ISI indications.
The NRC questioned the licensee on the details of the indications.
The licensee answered the questions asked and committed to review the cause of the event with General Electric (GE).
GE prepared the ISI report that documented the unusual indications.
Regional specialist inspectors were dispatched to review this event in more detai.l.
Their findings are documented in NRC Inspection Report 50-387/89-26.
Unex ected CAC Isolation Due to Im ro er Fuse Pullin 7.0 The licensee identified that the wrong fuses were pulle'd for a containment purge valve Local Leak Rate Test (LLRT) causing a Division II isolation at 4: 12 a.m.,
August 29.
As a part of the LLRT, operators were directed to pull fuses for a containment purge valve.
They were supposed to pull fuses in panel 2C661A3 instead they pulled fuses in 2C661B3 which isolated the containment atmospheric control (CAC) System.
The operators mistakenly went to the lower relay room instead of the upper relay room.
The fuse pulling closed the Division II CAC supply and return valves to the hydrogen and ox'ygen (H2/02) analyzer and the containment radiation monitor (CRM).
The CRM was not operating at the time of the isolation.
However, the H2/02 analyzer was operating and had to be shut down.
The licensee made the required ENS notification.
The fuses were reinstalled in cabinet 2C661B3 and the system was restored to its normal lineup.
The fuses in the proper location were then removed in order to perform the LLRT.
The licensee had not completed evaluating the cause and corrective actions to prevent a recurrence at the end of this inspection period.
NRC will review these during followup of the required Licensee Event Report, Un lanned Ex osure Due to Concentrated Reactor Water Sam le The licensee identified that a contractor had apparently received a high localized skin exposure to his chest area at approximately 3:00 p.m.,
August 31.
The contractor was sampling reactor water for an Electric Power
10.
8.0 and Research Institute (EPRI) fuel pin integrity project.
The sample technique involved processing 124 liters of reactor water over a 48-hour period through a millipore filter that was coated with ion exchange resin.
This filter was used to concentrate the ionic radionuclides as well as the particulate radionuclides.
After its retrieval, the contractor placed the filter in a plastic planchette and placed it in his shirt pocket.
The contractor failed to survey the sample and a licensee chemistry technician accompanying him failed to note the missed survey.
They proceeded to the chemistry laboratory to analyze the sample.
The time in transit was approximately 7 minutes.
A radiation survey was conducted of the sample three hours later. It indicated 1 R/hr gamma and 16 rads/hr beta on contact.
A large skin dose was projected.
Licensee do'se assessment specialists were. dispatched to the site to assess the dose.
They ran a
VARSKIN computer program after receiving the isotopic breakdown of the sample.
The initial, conservative estimated skin dose calculated for a 10-minute exposure was 450 rems which exceeded the
CFR 20.403(a) reportability limit of 150 rems to the skin.
The licensee made the required ENS notification at 6:00 a.m.,
September 1.
The State of Pennsylvania was also informed.
The licensee issued a press release and contacted the exposed individual to arrange for a medical baseline assessment.
The medical exam showed no erythema or unusual blood changes.
NRC Region I dispatched health physics and chemistry inspectors to the site on 'September 1 to review the licensee's investigation and assessment activities.
The details of their inspection are provided in Special Inspection Report 50-387/89-28.
Re ortabilit of Desi n Deficiencies - Alle ation Followu
~Back rroouunndd An allegation was reported to NRC licensing in June 1987.
The allegation identified a technical concern related to Class 1E and non-Class 1E electrical separation and the potential for common mode failure.
This specific technical concern is being addressed by an action plan developed by the licensee.
NRC is monitoring the licensee's action plan activities.
The following additional concerns were identified were by the alleger:
(1)
The Emergency Diesel Generator (EDG) failure which occurred on May 26, 1986, was not reported to the hlRC, as required.
(2)
In general, engineering and design deficiencies at Susquehanna are not being properly reported to the NRC, as require Subsequent to the initial allegation, other concerns related to the reportabi lity of engineering/design issues have been received by NRC.
To evaluate these concerns, an NRC inspection was conducted at the Susquehanna site on July 19-21, 1989.
The NRC reportability requirements contained in 1QCFR Part 50, Section 50.72, 50.73, 50.9, 10CFR Part 21, and Technical Specifications were used to assess these identified concerns and the licensee's reportability program.
NUREG-1022, Revision 1 and NUREG-0302, Revision 1 were also utilized as guidance in evaluating the licensee's reportabi lity determination process.
Re ortabilit of EDG Failure NRR-87-0011 Discussion The alleger provided a lengthy report of the connected events and identi-fied several concerns associated with an Emergency Diesel Generator (EDG)
event on Unit 1, which occurred on May 26, 1986.
This inspection addressed the licensee's reportability evaluation for this event.
NRC is reviewing and evaluating other concerns from a technical standpoint.
A synopsis of the allegation that addresses the inspection area is provided below.
Details of Alle ation On the morning of May 22, 1986, a routine surveillance of the "D" diesel generator was being conducted after maintenance on its electrical generator.
Shortly after startup, an improperly assembled field coil connection open-circuited under load.
Locally, the operator noted a flash at the generator and manually shutdown the engine.
Control room operators received generator field ground alarms on all four diesel control panels, even though the other three diesels were not operating and their fields were not energized.
Shortly thereafter, the operators noted a sudden loss of a large number of Plant Monitoring System (PMS) computer points and notified Computer Maintenance of the problem.
Computer Maintenance entered the computer room to check on the problem, smelled smoke, and found a small but active fire ongoing on several glass-epoxy computer cards in the Input/Output (I/O) cabinet of one of the data acquisition processors.
The fire was quickly extinguished by the technician who discovered it.
The alleger became aware of this event and supplied a
copy of the Significant Operating Occurrence Report (SOOR)
and an internal licensee report of the event to the NRC.
Because the "D" diesel appeared to be inoperable, Operations began performing surveillances on the remaining three diesels.
When the "A" diesel was started, ground fault alarms were received on both the "A"
diesel which was running and the "B" diesel which was not running.
The
"A" diesel was shut down and Computer Maintenance disconnected the computer input card, which was determined to have all four diesels'ield current inputs supplied to that one card which had been damaged by the field coil inductive spike and subsequent fire.
The "A" diesel was subsequently successfully run without alarms after the removal of the input card.
When the "C" diesel was started, it also received a ground fault alarm and was stopped.
While the search for the ground was on-going, the ground fault disappeared and did not return.
The "B" and "C" diesels were then successfully tested.
Review and Findin s
The test performed on the "0" diesel generator on May 26, 1986, was not a surveillance test as specified by the licensee's Technical Specifications, to establish the operability of the emergency onsite power source.
The subject test was a post maintenance test.
The inspectors verified this through the review of the control room operations log.
The inspectors reviewed the safety significance of the above failure and physically inspected the area where the failure had occurred.
It was confirmed that a loose nut on the slip ring caused the fault which then spread to the redundant diesel generator circuit at the non-safety related computer input signal card.
A control room log further establishes that the "C" diesel was able to run in the presence of the ground alarm.
The log entries confirmed the emergency diesel generator's capability to perform its intended function for.approximately six minutes before being shutdown to investigate the alarm;,
The inspector concluded that the "C" emergency diesel generator remained operable, in spite of the instrumentation circuit failure.
Conclusion Since the "A", "B" and "C" diesels were successfully run after the fault occurred and the 0 diesel was not in service at the time of the test, the inspectors concluded that the licensee decision to not report the event was justified.
The licensee's assessment of the event, which was docu-mented in SOOR 1-86-176, was found to be thorough and the process effective in reaching the conclusion.
Therefore, this allegation was not substan-tiated with regard to event reportabilit.2 En ineer in and Desi n Deficienc Re ortin Weaknesses Discussion The alleger had an overall concern with the licensee's reporting program, as it relates to the reportabi lity of engineering and design
~ deficiency issues.
The alleger supplied the NRC with several Significant Operating Occurrence Reports (SOORs)
and Nonconformance Reports (NCRs) that identified engineering and design deficiencies, which the alleger believed to be reportable to the NRC.
Review and Findin s
The inspectors reviewed the licensee's reportability program and procedures to determine the adequacy in implementing NRC reporting requirements.
The inspectors reviewed selected SOORs and NCRs, which contained complex engineering issues, to verify the effectiveness of the licensee's reportabi lity determination process.
In addition, the training of engineering personnel relative to NRC reportability requirements was evaluated and guality Assurance oversight of this area was also assessed.
Assessment of Re ortabilit Pro ram and Procedures Reporting responsibilities are presently divided between the Susquehanna site and the corporate office in Allentown, Pennsylvania.
The control of each group's reporting requirements is defined in Nuclear Service Instruction NSI-gA-3.1.7,"Reportability Evaluation" and Administrative Procedure AD-gA-424,"Significant Operating Occurrence Reports."
The licensing group in the corporate office is responsible for making both verbal and written Part 21 reports and 10CFR50.9(b)
reports to the NRC as directed by the Vice President-Nuclear Operations.
The compliance group on site is responsible for reporting events under
CFR 50.73.
Shift supervision is responsible for immediate or prompt reportabi lity notifications required under the provisions of 10 CFR 50.72.
Final determination as to reportabi lity requirements is the responsibility of the Assistant Superintendent of the plant.
The inspectors concluded that the instruction and procedure clearly identify the licensee's reportabi lity evaluation program.
These documents include lines of responsibility and required interactions between the various groups prior to making NRC notifications.
However, clarification is required to procedure AD-gA-424 to indicate that a
SOOR may be closed, even though all corrective actions have not been completed.
The only time this is permitted is when an NCR has been generated against the same item that is specified in the SOO The NCR will remain open pending completion of all required corrective actions.
Assessment of Trainin The inspectors evaluated the licensee's engineering personnel training requirements to determine if any type of training, relative to NRC reporting requirements, was required of these individuals.
The technical training requirements for individuals within the Nuclear Plant Engineering (NPE) group are identified in Engineering Procedures Manual EMP-gA-236, "Nuclear Design Technical Training Requirements".
The technical training matrix for Nuclear Design personnel requires procedural reading of Nuclear Department Instruction NDI-gA-5.2. 1,
"Significant Operating Occurrence Reports" (SOORs).
This instruction provides the necessary guidance to personnel for identifying and communicating reportable defects and items of noncompliance.
Additional internal mechanisms used by the licensee to encourage employees to express their concerns and identify problems are the Nuclear Safety Concerns posXings 'ocated on bulletin boards throughout the corporate office and the Susquehanna plant.
The posting indicates the various methods available, to individuals who have safety concerns, to report their concerns.
The licensee held a seminar with Nuclear Plant Engineering (NPE)
personnel to discuss NRC repor tabi lity requirements on October 13 and 21, 1988.
The licensee officially added a formal operability/reportabi lity training course AD029, Operability/Reportability Related Programs, to the NPE training curriculum on April 14, 1988.
This training is designated as
"company assigned,"
which means that this training is not required.
As of July 1, 1989, only 2 NPE personnel out of 87 have completed this training course.
Another eight NPE personnel are scheduled for this course on August 8, 1989.
The inspectors concluded that NPE personnel are trained in processes for identifying safety concerns.
However, the formal NRC reportabi lity deter-mination training for NPE'ersonnel should be implemented more aggres-sively to increase the effectiveness of reporting engineering/design deficiencies.and to heighten overall awareness to the reporting of engineering/design deficiencie Review ualit Assurance Audits of Re ortabilit Determinations The inspectors reviewed the licensee's audits of reportability evaluations.
The inspectors found that the licensee has established procedures to audit the reportability of significant events.
Specifically, the audit reports dated June 27, 1988 and March 30 and June 29, 1989 were reviewed, and found to be complete with respect to the reportabi lity determination and resolution of any issues raised by the audits.
In addition, the frequency of audits indicates that the management is involved with reportability determinations.
Exam les Reviewed For Re ortabilit A.
SOOR 1-89-239/Non-Conformance Report No.89-0064 GE Service Information Letter (SIL) No.
477 and NRC Information Notice 88-51 informed the BWR Owners that the Main Steam Isolation Valves (MSIVs), which are equipped with springs and stored air to close the valves in a Design Basis Accident (DBA) event, may not close under spring actuation alone (if stored air energy source was lost).
This situation was contrary to the Susquehanna 1 and
FSAR Section 6.2.4.2 which states that the MSIVs would close:
1)
with force supplied by either springs or air pressure; 2)
with no additional supply from the containment instrument gas; 3)
with external pressure of 53 psig on the air cylinder.
The licensee performed an analysis of the operation of the MSIV by setting up a force balance of the movable parts of the MSIV to determine a net positive closure force.
The MSIV stroke time for closure without air was calculated to be about ll seconds under the elevated containment pressure (DBA) event.
The licensee's analysis showed that the MSIV would not close within the time period assumed in safety analyses using either air or spring force during an elevated drywell pressure condition resulting from a design basis event.
The calculations also showed that the MSIVs would close within the assumed time period if both air and spring force were available to the MSIVs.
Technical Specifications require that the MSIVs be demonstrated operable by verifying full closure in 3 to 5 seconds.
The General Electric (GE) specifications for operability state that the valves shall be capable of operating within the specified limits under conditions of normal operation which include a containment pressure of 0 psig.
The licensee was able to determine that for a containment pressure of 0 psig the MSIVs would close in 3 to 5 seconds at normal conditions of containment operation.
Based on the closure time
analysis, the l,icensee concluded that the MSIVs calculated closure times did not violate the Technical Specifications.
On February 9, 1989, NCR 89-64 documented that the slow operation of the inboard MSIVs with spring pressure only did not conform with the stated FSAR design basis.
The licensee, therefore decided to change the FSAR requirement of MSIV opening under "air or spring" pressure to
"air and spring" pressure.
The licensee further determined that the change in the FSAR statement that the MSIVs will close under the air and spring force does not constitute a significant safety issue because the affected MSIVs are the inboard valves only and the out-board MSIV' will close fully with springs only.
The licensee, there-fore, concluded that this condition was not reportable.
The inspectors reviewed the licensee's reportabi lity determination and concluded that their conclusions were generally appropriate except as applied to the reporting of a condition that was outside the design basis.
The FSAR describes the design basis of the MSIVs and the licensee could not establish the acceptability of the inboard MSIVs in meeting this basis.
Leak Detection S '-tern Desi n Basis Inade uac
- Alle ation 89-A-86 The inspector conducted a meeting with the licensee at I;00 p.m.,
August 22 to follow up on licensee actions taken as a result of a Main Steam Line Differential Temperature Leak Detection System Miswiring.
During the meeting, the inspector questioned the licensee on an allegation made regarding the reportabi lity of non-conservative setpoints for the Steam Leak Detection System.
>The steam leak detection ( LD) system uses reactor building room temperatures, flow and pressure measurements to detect, annunciate and isolate leakage in the reactor coolant pressure boundary (RCPB).
This includes ambient and differential temperature monitors installed in each room containing equipment which interfaces with the RCPB.
The LO system acts to isolate affected systems on elevated room temperatures.
The licensee performed an analysis of the steam leak detection system temperature setpoints in response to a previous violation involving mislocation of the temperature elements for the Main Steam Tunnel Differential Temperature modules.
The licensee's violation followup included reviewing the LD design basis analysis to assure the steam leak detection setpoints are correct.
The existing setpoints were calculated from Technical Specification (TS) Allowable Values and Trip Setpoints.
To confirm the values for the TS parameters, the licensee's Nuclear Design Mechanical group developed computer models for the rooms covered in the TS.
The Compartment Transient Temperature Analysis Program (COTTAP) was used to calculate the temperature rise in the room due to a steam leak.
The program accounts for condensation, heat transfer through the walls, and many other factors not considered
in the original analysis.
This model is more sophisticated than the model that was used to produce the original setpoints, The calcu-lation for the HPCI room indicated that the steam leak detection system sensitivity listed in the FSAR was not consistent with the results calculated per the COTTAP program.
This condition was mentioned in the licensee's written violation response for the miswiring of the main steam tunnel differential temperature modules.
Two conditions for the steam leak detection temperature setpoints in FSAR section 5.2.5. 1.3(1) were not consistent and cannot be met by the current system.
The first condition is that the system be capable of detecting a
GPM leak in a timely manner.
The second condition is that the setpoints provide sufficient margin above the post-LOCA design maximum room temperature to prevent inadvertent system isolations.
The calculation of the temperature rise in the HPCI Equipment Room indicates that a
5 gpm leak would be detected only after a time greater than 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> given the existing setpoints.
Lower'.ng the existing setpoints to allow detection of a 5 gpm leak in a reasonable time (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) would violate the second FSAR condition.
A setpoint suitable for a 5 gpm leak would be below the post-LOCA design maximum thereby eliminating the margin required by the FSAR and possibly causing undesired system isolations during a HPCI start condition.
The licensee determined that the COTTAP results of the HPCI Room temperature calculations contradict the current design conditions in FSAR section 5.2.5.1.3(1).
This condition has existed in the FSAR since the initial design of the plant.
This determination made it
<necessary for the licensee to establish a realistic design basis for steam leak detection temperatures to the assure safety of the plant and to assure that the isolation setpoints conform to the design basis.
On July 14, 1989, the licensee concluded that the leak detection system was beyond its design basis and developed a corrective action plan to ameliorate this condition.
Their corrective action included performing a detailed temperature analysis, calculating new high temperature and differential temperature setpoints, issuing the set-point change package and reestablishing the design basis for the leak detection system.
The inspector agreed in principle with their resolution of the technical approach but not with the licensee's reportability evaluation.
The design basis of the LO system is to detect
gpm leaks on a timely basis and to isolate the affected system.
This was clearly not being met by the existing setpoint and therefore should have been reportable under 10CFR50.72 with the power plant in a condition outside the design basi The inspectors also reviewed the following additional SOORs and NCRs to determine the effectiveness of the licensee's reporting program:
SOOR 1-86-176, May 26, 1986 EDG Event NCR 89-0036, Adequacy of Appendix R Circuits NCRs listed in this report under (RI-89-A-0040) Allegation The inspectors found the licensee's evaluations, relative to determination of safety significance and reportabi lity, to be generally justifiable for not reporting these issues to the NRC.
Conclusion Based on this review, the inspectors concluded that the licensee has an established method of reporting events to the NRC, including engineering/design deficiencies.
The reporting methodology and lines of responsibility are defined in approved procedures.
The procedures provide an effective means of communications between the offsite organization and plant personnel, such that potential repor tabi lity/
operability issues are raised to the operations organization in the proper manner.
Added management attention is warranted in the 'scheduling and completion of Operability/Reportabi lity training for NPE personnel.
To date, only a few NPE individuals have completed this training.
The inspectors reviewed two issues that should have been reported to the NRC.
The licensee's reportabi lity evaluations and judgments were generally well documented.
However, the licensee has defined reporting criteria for unanalyzed/outside the design basis conditions which state that conditions are not reportable when the safety significance is determined to be acceptable or when no event challenged the discrepant system.
As a result, some 'known i'ssues remain unreported while the licensee conducts detailed engineering reviews/reanalyses to determine the safety significance and propose corrective actions.
Prompt notification to NRC allows for timely multi-disciplinary and management review of events by several NRC organizations.
While the importance of event reports is clear for emergency response activities, NRC's reporting requirements also address conditions which necessitate NRC's prompt understanding of the justification for continued plant operation (JCO) and/or the potential generic applicability of the condition and the JCO to other facilities.
Therefore it is important for licensee's to determine the reportability of identified conditions based on the design basis
(FSAR and other available documents)
and analyses existing at the time of identification.
The safety significance must be promptly determined based on the real and potential impact on the current analyses.
The inspector considered both the NSIV stroke problem discussed in paragraph A above, and the HPCI room high temperature isolation sensitivity discussed in paragraph B above to be conditions outside
.
the existing design basis.
Pending NRC management review of licensee's bases for the reportability thresholds defined in administrative proceures, this issue remains unresolved.
(UNR 387/89-24-01 COMMON)
8.3 Im ro er Closure of A endix R Nonconformance Re ort Alle ation RI-89-A-0040 Discussion On June 5,
1989, an NRC Region I based specialist inspector received an allegation which deals with the inadequate closure of a nonconformance report (NCR) 89-0036.
Details of Alle ation NCR 89-0036 identified a concern with of the adequacy of the associated Appendix R circuit analysis because certain assumptions made for this analysis were invalid.
Specifically, certain associated circuits were not analyzed because it was assumed that these circuits were isolated from the safe shutdown equipment, when in fact, no such isolation exists.
The alleger claimed that the NCR was improperly dispositioned because the licensee did not review all the associated circuits (about 200).
The licensee reviewed only the three circuits used as an example in the NCR and when they determined that these three circuits were not impacting the Appendix R equipment they dispositioned the NCR "use as is".
In addition, the alleger claims that the NCR was dispositioned on the basis of an Engineering Work Request (EWR) which requested an evaluation of the Appendix R circuits.
The alleger's concern was that EWR's are not required to be closed by a formal mechanism at a specified time.
Therefore, closure of the NCR was improper.
Review and Findin s
In order to establish the validity of this concern, the inspectors reviewed the licensee's program to process nonconformance reports.
NCRs are processed according to the following two procedures.
NDI-QA-8.1.5, Revision 4, "Nonconformance Control and Processing" and AO-QA-120, Revision 5, "Nonconformance Report Control and Processing".
The former procedure is for the corporate office and the latter is for the site organization.
NCR 89-0036, which was referred to by the alleger was, in fact, not closed out by the licensee.
It was the allegers contention that the signature on block 15 of the NCR marked the end of the engineering actions and therefore closed the NCR.
The inspectors obtained a controlled copy of the subject NCR.
Contrary to the allegers contention the NCR was not officially closed.
Blocks 18 and 19 of the NCR, which deal with the disposition and QC acceptance, were still open on the NCR.
This indicates that the NCR is not closed.
Moreover, the NCR tracking system, Plant Maintenance Information System (PMIS) indicated the NCR to be open.
The concern addressed in the NCR, the separation of associated circuits in the instrumentation area is an ongoing subject of review by NRC Licensing (NRR) and the associated circuit analysis is currently being addressed by NRR.
Conclusion Based on the above facts, the inspectors concluded that the allegation was not substantiated.
Even though the allegation was not supported, the inspectors reviewed the following additional randomly selected NCRs to assess the effectiveness of the licensee's NCR program.
89-0293 EQ splice concerns 89-0005 Lack of calibration for test set 89-0001 Qualified life of solenoid valves 89-0037 Test connection for HPCI turbine stop valve These NCRs were dispositioned according to the procedures noted above.
The dispositions of the technical concerns were adequate except for the concerns identified below:
NCR 89-0293, dated March 27, 1989, addressed a concern about the adequacy of a motor termination connection.
This discrepancy was corrected by replacing it with an environmentally qualified Raychem termination.
As this equipment was required to be environmentally qualified, the licensee generated SOOR 1-89-51.
The licensee has two procedures for processing SOORs.
NDI-QA-5.2. 1, Revision 3, "Significant Operating Occurrence Reports" AO-QA-424, Revision 8, "Significant Operating Occurrence Reports"
The former one is for the corporate office and the latter is for the plant staff at the Susquehanna site.
However, these two procedures do not address'the review by a cognizant engineer for the disposition of the NCR.
The subject NCR that addresses the operability of an environmentally qualified piece of equipment, was not required to be forwarded to the Equipment gualification Engineer for review.
However, the equipment qualification coordinator at the site, prevented the closure of this NCR and forwarded it to the corporate office for proper
.E(} review.
9.0 An evaluation was required to assess the operability of the pre-existing questionable motor termination.
The Eg engineering group is presently evaluating the qualification of the previous configuration.
In order to avoid potential oversights, as mentioned above, a formal procedural control is warranted to ensure that NCRs get the level of engineering review required to evaluate and disposition deficient conditions.
The licensee's NCR and SOOR procedures referenced above do not adequately address the need for such a rsview.
This is an unresolved item pending NRC review of the licensee's actions to incorporate cognizant engineering review of NCRs and SOORs.
(387/89-24-02, COMMON)
The concern about unqualified splices was the subject of NRC Information Notice 86-53.
Even after 2 1/2 years, the licensee is still finding questionable splices/terminations.
The licensee stated that 2 or 3 more terminations have to be addressed if the above referenced questionable splice can not be qualified.
The licensee is currently evaluating a test report on a similar configuration to establish qualification.
Management committed to take prompt corrective actions if this approach is determined to be unsatisfactory.
This is an unresolved item pending NRC review of the licensee'
action to establish operability for the exi sting splice and the final corrective actions.
This is an update to item (388/89-05-02, COMMON)
"A" Control Structure Chiller Miswirin On August 19, 1989, while attempting to perform a post maintenance run of the "A" Control Structure Chiller, a start failure due to lack of oil pressure occurred.
A second start attempt was successful.
However, coincident with the start, the annunciator for Drywell Fan 1V418A alarmed at panel 1C681.
Operations attempted to stop the chiller by cycling breakers 1B236-123 (breaker for 1V418A), and 1A203-10 ("A" control structure chiller), placing the chiller control switch on panel OC681 in stop, and depressing the local on-off switch without success.
The "A" chiller was finally shut down when the plant control operator (PCO)
moved the control switch for the drywell fan from start high to auto hig Investigation by the licensee determined that a previous modification (PMR.88-3016H) to the control structure chiller used a terminal point already in use by the drywell fan circuitry.
This occurred as a result of the terminal point being indicated as a spare on drawing number M334-52(3)-4 which was used to perform the modification.
However, connection diagram M
334-52(3)-13(B8) Interim Drawing Change Notice (IDCN) ¹113 and connection list E-362-02 Revision 19 on Schematic E-224 sheet
show the point as part of the lV418A fan circuitry.
The licensee believes that the miswiring may have been the cause of damage to the chiller during a July 28 run without the oil pump operating for 11 minutes.
The licensee removed the chiller from service and declared it i,noperable pending rewiring and an engineering evaluation.
A print change notice and Construction Work Order were subsequently issued to correct the placement of the wire lead to an actual spare.
The licensee formed a Task Force to evaluate and determine causal factors leading to this occurrence and to make recommendations to prevent recurrence.
The inspector determined that the licensee's immediate corrective actions were appropriate.
In addition, the inspector noted that the apparent cau e
of this occurrence was due to a failure of the individual(s) preparing the
~ modification to identify that the.terminal point chosen for use was not a spare as clearly indicated by the connection diagram and list.
The pre-implementation walkdown and cold check which are to be performed prior to installation failed to identify the wiring error as well.
Although this appears to be a significant failure of the system for implementing modifi-cations, in view of the many modifications performed using this system versus the minimal number of failures (breakdowns)
which have occurred, the inspector considers the system to exhibit some weaknesses but overall to be effective.
10.0 Emer enc Plan Drills The inspectors observed portions of both the health physics practice drill on August 1, 1989, and the annual health physics drill on August 22, 1989.
Overall, the inspectors considered the drills challenging and capable of assessing individual and group performance.
Some minor problems were noted by the inspectors and discussed with the licensee.
The inspectors reviewed the licensee's critiques on drill performance and attended the critique for the August 22 drill.
The critiques were found to be thorough and informative, providing meaningful insight into problems encountered and weaknesses identified.
Areas identified for potential enhancements were scenario development weaknesses which caused problems for the response organization, communications hardware which did not exactly simulate what would actually be used, and the page system used for calling EOF personnel which did not activate the pagers.
No unacceptable conditions were note.0 Mana ement Meetin
- Inte ration of PRA and Reliabilit En ineerin into Maintenance The licensee met with the NRC in the Region I office to discuss their initiatives in the maintenance area.
'The licensee plans to prioritize maintenance on components and systems based on the plant Probabilistic Risk Assessment and Reliablity Engineering evaluations.
Predictive maintenance on components and systems will be based on the component failure effects on scram frequency and on safety system inoperability.
Attendees of the meeting are listed on Attachment 1.
The licensee presentation is provided in Attachment 2.
12.0 Resident Monthl Exit Meetin During the resident exit meeting, the inspector discussed the findings of this inspection with station management.
Based on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain.information subject to
CFR 2.790 restriction Attachment
Management Meeting
"Maintenance Interface with PRA" 9/6/89 NRC Name Title P.:Swetland N. Blumberg B. Boger J. Durr Licensee Chief, Reactor Project Section 2A, DRP Chief, Operational Programs Section Acting Director, DRS Acting Deputy Director, DRS C.
H.
M.
C.
.M.
S.
Coddington Webb Fogarty Boschetti Detamore Hoopes Fi gard Kel ly Barber Senior Project Engineer-Licensing Superintendent, Nuclear Maintenance Support Reliability Engineer Risk Analyst Engineer Supervisor - Systems Engineering Senior Nuclear Maintenance Engineer Supervisor of Maintenance Nuclear Maintenance Engineer Susquehanna, Senior Resident Inspector
ATTACHMENT 2 IRC MAIN'.%NANCE MEETING AGENDA INTEGRATION OF PRA & RELIABILITYENGIIEERDK INTO SUSQUEHANNA MAINTENANCE SEPTEMBER 6, 1989 o
INTRODUCTION Bob Hoopes o
HISTORICAL PERSPECTIVE 6 MOTIVATION FOR MAINTENANCE IMPROVEMENTS Bob Hoopes o
PRA 6 RELIABILITYENGINEERING CAPABILITIES I
Mike Detamore o
~ DEVELOPMENT OF PREDICTIVE MAINTENANCE TECHNIQUES Vince Kelly o
IMPLEMENTATION AT SUSQUEHANNA Bob Hoopes and Ed Figard rehagh136a:pas
SUSQUEHANNA CYCLE CAPACITY FACTORS UNIT 1 100
86
70
Bo¹-
46
36
Goal = 77.0%
st Cycle w/o Tie-in Outage F=63.4%
st Cycle CF=56.0%
2nd Cycle 3rd Cycle CF=71.4%
CF=70.3%
4th Cycle CF=74.5%
Lifetime CF = 67.0%
1983 1984 1985 1986 1987 1988 1989
Lg I
SUSQUEHANNA CYCLE CAPACITY FACTORS UNIT 2 100
90
80
70 Goal = 77.0%
1st Cycle CF=70.8%
2nd Cycle CF=74 9%
3rd Cycle CF=81.7%
46 Q
36
20 Lifetime CF = 75.4%
1983 1984 1985 1986
'i987 1988 1989
~ Protected, based on the Unit 2 3RIO schedule (63 days).
SUSQUEHANNA CYCLE CAPACITY FACTORS UNIT 1 100 td
$0'
I0 Ufetlme CF ~ 67.05 Coal = 77.0W
'
dd
~t Cycl~ w/o Tle-in Outage Fad 3.4X at Cycl~ CF=56.05 2n4 Cycl~
3rd Cycl~ CF~71 4%
CF=70.3%
ith Cyci~ CF~PR~'
1983 1984 1985 1986 1987 1988 1989 t00 IO dd IO
'75
'Q
65 Cl eo dd
Ufetlme CF = 75AX Coal ~ 77.0%
1st Cycl~ CF=70.84 2nd Cycle CF=74.9%
3rd Cycle CF=51.7%'983 1984 1985 1986 1987
'1988 1989
'rotected, baaed on the Unit 14RIO ANQ Unit 2 3RIO achedulea (53 daya each).
Refer to Appendhc 3 for data and calculatlon SUSQUEHANNA LIFETlME CAPAClTY FAt TPRS SO
0 Q
~ %40 a.
eo
~~
60 66.8 6/11 1986 60.4 4/22 UNIT 2 70.7 10/28 54.5 UNIT 1 11/23 73.0 8/23 1988 57.0 ei1 1989 NOTE: lncludea actual net generation through 2l89 and projected through each unit's 1888 rafuelinp and inapection outag LC I
GK BWR CAPAClTY FACTORS
'0
<o
0
U '5 U
C$
eo GE Domestic~
81/82/83 82/83/84 83/84/85 84/85/85 85/85/87 88/87/88 3 YEAR AVERAGES Source: General Electric
g
o
ogp L4
20 Cl 1S
E V
d 21.3 4/22 UNIT 1
'19 2 11/23 18.0 0/1 16.2 10/2&
UNIT 2 11.3 6/23-SUSQUEHANNA LIFETIME MID-CYCLELOSS FACTORS (M}
27.3 e/11 9,8 11/9 1S85
'tS88 1987 1988 1989 NOTE: 8aied on actual net generation through 2/89 and projected generation through each unit'I 1989 refueling and inspection outage. (See Appendix 3)
INDIVIDUALPLANT EVALUATION(IPE)
I BACKGROUND A. SUBMIT ED AS A DEMONSTRATION IPE UNDER THE IDCOR PROGRAM, V/ILLBE ENHANCED AND REVISED TO COMPLYWITH NUREG 3335.
I B. A LEVEL II PRA.
C. THE PP&L APPROACH FOCUSES ON OPERATOR AND PLANT PERFORMANCE ANDATTEMPTS TO REPRESENT THESE FACTORS AS REALISTICALLY AS POSSIBLE.
D. M/E EMPLOYTHE SUPPORT STATE METHODOLOGY AND MAINTAININHOUSE ACCIDENTANALYSIS CAPABILITY.
E.
AS PART OF THE IPE V/E ANALYZEBOTH SAFETiY RELATED 8. 8OP SYSTEMS o
USE FAULTTREE MODELS AND PlANT DATA (WHERE AVAILABLE)
IPE - CONT.
II APPLICATIONS A. SYSTEM DESIGN CHANGES B.
MAINTENANCESCHEDULING PRIORITY C.
EMERGENCY OPERATING PROCEDURES (SBO, ATWS)
D. VARIOUSTECHNICALSPECIFICATION EVALUATIONS E.
OPERATOR TRAININGPRIORITY
PLANT RELIABILITYMODEL I
RELIABILITYANALYSISBEGINNINGS INDUSTRYPERFORMANCE PLANTSPECIFIC PROBLEMS II PLANT RELIABILITYMODEL A.
PROBABILITYTHATSSES UNIT 1 V/ILLGENERATE 100% ELECTRICALOUTPUT FOR A ONE MONTH PERIOD B.
8 MODULES
- POWER CONVERSION
- REACTOR RECIRCULATION
- DRYWELLCOOLING
- EXTRACTIONSTEAM/FW HEATING
- CONDENSATE/FEEDWATER - CONDENSER/CONDENSER AIR REMOVAL
- MAINSTEAM
- REACTIVITYCONTROL C.
EACH MODULE IS EVALUATEDINDIVIDUALLY, THEN INTEGRATED WITH EXISTING MODULES TO BUILDTHE OVERALLPLANT MODEL D. CURRENT STATUS
- 6(8 MODULES COMPLETED
- 2,500 COMPONENTS MODELLED
PLANT RELIABILITYMODEL - CONT.
III ANALYSISMETHOD A. STUDY SYSTEM DESIGN/OPERATION/PERFORMANCE B.
PERFORM FMEA ON SYSTEM COMPONENTS C.
DEVELOP SYSTEM LOGIC MODEL (GO MODEL)
D. ASSIGN COMPONENT FAILURE RATE DATA E.;RUN GQ DATA F.
EVALUATERESULTS
- RELIABILITYCALCULATION/COMPARISONWITH PLANT PERFORMANCE
- SINGLE FAILURES RESULTING IN A POWER REDUCTION
- SINGLE FAILURES RESULTING IN SCRAM/SHUTDOWN IV APPLICATION DESIGN REVIEW
la
COMPONENT PRIORITY CLASSIFICATION PRIORlTY 1 COMPONENTS WHOSE FAILURE ALONE RESULTS IN A:
o DIRECTPLANTSCRAM o SHORT DURATIONALLOWED OUTAGE TIME CAUSING A FORCED SHUTDOWN o COMPLETE LOSS OF A SAFETY SYSTEM FUNCTION
PREDICTIVE MAINTENANCE PROGRAM o
DEFINITIONS AND OVERVIEW o
CURRENT STATUS AT SSES o
FUTURE PLANS AT SSES
CONDITION MONITORING TASKS THAT ARE PERFORMED TO ANALYZE EQUIPMENT PERFORMANCE AND DETECT DEVELOPING DEGRADATION/ ABNORMALITIES
EQUIPMENT CONDITION LEVEL CURVE OPERATING HOURS NEW INSTALLATION OR REBUILD DETECTING PROBLEMS WITH PREDICTIVE MAINTENANCE~
TECHNOLOGY NOISE, VIBRATIONS OR OTHER VISUAL WARNINGS (HUMAN SENSES j SERIOUS COMPONENT OR MACHINE FAILURE
MAINTENANCE-PAST o
PREVENTIVE MAINTENANCE SIMPLE TASKS TO EXTEND SERVICE LIFE TIME-DIRECTED OYERHAULS I
o PREDICTIVE MAINTENANCE MONITOR EQUIPMENT HEALTH TO DETERMINE DEGRADATION o
CORRECTIVE MAINTENANCE FIX IT WHEN IT BREAKS FIX IT BEFORE IT BREAKS BUT IN PROCESS OF DEGRADATION
DISADVANTAGES o CORRECTIVE MAINTENANCE (FIX IT WHEN IT BREAKS)
LOSS OF PRODUCTION INCREASED CHALLENGES TO SAFETY SYSTEMS
-'NCREASED MAINTENANCE COSTS ( PARTS AND LABOR )
o PREVENTIVE MAINTENANCE ( TIME-DIRECTED OVERHAUL)
EQUIPMENT IN GOOD CONDITION OVERHAULED INCREASED UNAVAILABILTYOF COMPONENT
.
INCREASED MAINTENANCE COSTS
MAINTENANCE-FUTURE o
PREVENTIVE MAINTENANCE SIMPLE TASKS TO EXTEND SERVICE LIFE
TIME - QIRECTEQ MAJOR OVERHAULS o
PREQICTIVE MAINTENANCE MONITOR EQUIPMENT HEALTH TO DETERMINE IF HEALTH IS DEGRADING o
CORRECT MAINTENANCE FIX IT WHEN IT SREAKS FIX IT BEFORE IT BREAKS BUT IN IN PROCESS OF DEGRADING
MAINTENANCE-TODAY PAST TODAY (TRANSlTION )
FUTURE
PREDICTIVE MAINTENANCE GOALS / BENEFITS o
IMPROVE EQUIPMENT, PLANT RELIABILITY AND AVAILABILITY o
REDUCE CHALLENGE TO SAFETY SYSTEMS o.,INCREASE PERSONNEL SAFETY o
PREVENT OVERHAUL OF EQUIPMENT. IN GOOD CONDITION BY INTEGRATING INTO OVERALL MAINTENANCE PROGRAM
PREDICTIVE MAINTENANCE
.CURRENT STATUS AT SSES 100 Cl UJ 1z LLl hl L
Q LQ,I Ri Q
L Q
lX
!L
~O 65%
50%.
30%
VIB OIL THERM TECHNIQUE MOV
PREDICTIVE MAINTENANCE CURRENT STATUS AT SSES o
VIBRATION MONITORING BEGAN DURING PLANT START-UP PROGRAM NEW EQUIPMENT, FORMAL PROGRAM ESTABLISHED IN 1986/1987 ROUTINE DATA COLLECTION IS PERFORMED QUARTERLY REPORT DOCUMENTS EQUIPMENT STATUS AND "SAVES" o
EQUIPMENT PURCHASED IN 1986 l
- APPLICABLE COMPONENTS IDENTIFIED (1989)
USED MOSTLY. AS A DIAGNOSTIC TOOL o
OIL ANALYSIS
-
STARTED IN 1983/1984 PILOT. PROGRAM IS IMPLEMENTED 60 COMPONENTS (1989)
o MOV PERFORMANCE MONITORING STARTED IN 1984/1986 USED MOSTLY AS A DIAGNOSTIC TOOL FORMAL PROGRAM HAS BEEN DRAFTED (1989)
FUTURE PLANS AT SSES o
VIBRATION MONITORING REVISE MONITORING LIST BASED ON PRA RE INSTRUMENTATIONOF CRITICALEQUIPMENT IMPLEMENT o
OIL ANALYSIS EXPAND PILOT PROGRAM TO APPLICABL'E EQUIPMENT o
THERMOGRAPHY ROUTINE DATA COLLECTION/ PROGRAM o
MOV IMPLEMENT ROUTINE DATA COLLECTION / PROGRAM
ALL TECHNIQUES INTEGRATE INTO MAINTENANCE BASIS VIA MAINTENANCE IMPROVEMENT PROGRAM
FUTURE PLANS AT SSES YIBRATlON OIL THERMOGRAPHY COP MOV OTHER INTEGRATED MONITORING PROGRAM / SYSTEM
COMPONENT ANALYSIS FAILURE HISTORY PM TASK EVALUATION SURVEILLANCEEVALUATION TEST PROCEDURES INDUSTRYSTANDARDS r
IOM RECOMMENDATIONS
MAINTENANCEREVIEW MEETING MECHANICALMAINTENANCE ELECTRICALMAINTENANCE l8C GROUP
'LANTSTAFF TECHNICAL
~ MAINTENANCESUPPORT SYSTEMS ENGINEERING GOAL: PRESCRIBE THE 'RIGHT'
MAINTENANCEFOR THE COMPONEN INPUT ANYREQUIRED CHANGES TO THE PM PROGRAM FEEDBACK I POP TO MONITOR EFFECTIVENESS