IR 05000387/1990003
| ML17157A139 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 04/13/1990 |
| From: | Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17157A138 | List: |
| References | |
| 50-387-90-03, 50-387-90-3, 50-388-90-03, 50-388-90-3, NUDOCS 9004250018 | |
| Download: ML17157A139 (35) | |
Text
Report Nos.
License Nos.
Licensee:
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION I
50-387/90"03; 50-388/90-03 NPF-14; NPF-22 Pennsylvania Power and Light Company 2 North Ninth Street Al 1 entown, Pennsyl vania 18101 Facility Name; Inspection At:
Susquehanna Steam Electric Station Salem Township, Pennsylvania Inspection Conducted:
February 11, 1990 March 17, 1990 Inspectors:
G.
S. Barber, Senior Resident Inspector, SSES J.
R. Stair, Resident Inspector, SSES H. J.
Kaplan, Senior Reactor Engineer Approved By:
P.
Swetland, ief Reactor Projects Section No.
2A, Date Ins ection Summar
~l*: R l
l
- l
dl R
operations, radiological controls, maintenance/surveillance testing, emergency preparedness, security, engineering/technical support, safety assessment/quality verification, and Licensee Event Reports (LER),
SOORs, and Open Item Followup.
Results:
During this inspection period, the inspectors found that the licensee's activities were directed toward nuclear and radiation safety.
No violations or deviations were identified.
An Executive Summary is included and provides an overview of specific inspection findings, PO042 Ooze 9/~4 <3, PDR ADOC}: 0 000387 PDC
SUMMARY Susquehanna Inspection Reports 50-387/90-03; 50-388/90-03 February 11, 1990
"
March 17, 1990
~oerations Operators were generally effective at monitoring and controlling plant activities and evolutions during the inspection periods The following specific activities were reviewed:
Fire detection system equipment failed resulting in the corresponding zones being declared inoperable.
Required continuous firewatches could not be established within the one hour requirement since the event occurred on backshift.
This is considered an unresolved item.
The Unit 1 High Pressure Coolant Injection (HPCI) was declared inoperable due to problems with the opening of the HPCI turbine stop valve.
Short term corrective actions taken by the licensee to correct the problem appear appropriate.
Additional engineering effort is needed to provide long term corrective action.
The Unit 2 High Pressure Coolant Injection (HPCI) was declared inoperable due to the system's failure to provide stable flow control.
The licensee actions in response to the problem were considered appropriate..
Radiolo ical Controls Individual workers and Health Physics personnel implemented radiological pro-tection program requirements.
The inspector did not observe any major in-adequacies in the licensee's implementation of the radiological protection program.
An area and personnel contamination event occurred while blowing down a Contain-ment Instrument Gas collection tank.
Inadequate knowledge of a recent modifi-cation by the operator contributed to the event.
Maintenance/Surveillance The licensee exercised good control of maintenance and surveillance activities.
No scrams or ESF actuations were attributable to inadequate control of main-tenance or surveillance activitie Executive Summary (continued)
The licensee's review of surveillance procedures for Post Accident Monitoring instrumentation discovered that the containment high range pressure instruments for both units were not included in surveillance procedures.
This is considered a licensee identified violation per
CFR 2.
Emer enc Pre aredness No major emergency preparedness (EP) issues emerged during the period.
The minor EP issues that were discussed during the period showed that the licensee considered emergency preparedness an important facet of overall performance.
~Securit Routine inspector observation of the licensee's protected area access and egress control noted no major weaknesses.
Compensatory measures were implemented for degraded barriers.
En ineerin /Technical Su or t Control rod (CR) 50-15 failed to withdraw during a weekly surveillance.
The licensee believes that excessive leakage past internal collet piston seals prevents the development of the necessary force to withdraw the rod.
A test procedure to increase drive water pressure in an attempt to move the rod was unsuccessful'he NRC and an internal group in the licensee's Nuclear Plant Engineering Department have concerns regarding the electrical distribution's system design basis.
The last integrated electrical loading calculation was performed in 1984.
The adequacy of voltages supplied to the 120 volt distribution was questioned by the NRC.
Safet Assessment/
ualit Verification Licensee Event Reports (LERs) exhibited indepth licensee review of the event and root cause analysis.
Immediate corrective actions taken were appropriate and long term corrective actions to prevent recurrence appeared effective.
Significant Operating Occurrence Reports (SOORs)
are used as a tool for the identification, reporting, and disposition of potentially significant occur-rences which are related to the design, operation, and maintenance of Susquehanna Steam Electric Station.
Inspector review and followup of specific SOORs demon-strated thorough analysis of events by the license DETAILS SUMMARY OF OPERATIONS Ins ection Activities The purpose of this inspection was to assess the licensee'
activities at Susquehanna Steam Electric Station (SSES)
as it related to reactor safety and worker radiation protection.
Within each inspection area, the inspec-tors documented the specific purpose of the area under review, the scope of inspection activities and findings, and appropriate conclusions.
The assessment of activities was based on actual observation of the licensee's activities, interviews with the licensee's personnel, measurement of radiation levels, independent calculation, and selective review of appli-cable documents.
Sus uehanna Unit
Summar Unit 1 entered the inspection period in startup following completion of modifications to the Reactor Protection System buses.
At 3:40 a.m.
on February 11, the reactor was made critical and at 1: ll p.m.,
the unit was placed on line.
Full power was reached at 1: 10 a.m.
on February
and was maintained for the remainder of the period.
No Engineered Safety Feature actuations occurred during the period.
Sus uehanna Unit 2 Summar Unit 2 entered the inspection period in Cold Shutdown following the auto-matic reactor scram on February 6 and pending completion of modifications to the Reactor Protection System buses.
Startup commenced on February
with the unit being placed on line at 9:04 a.m.
on February 13.
Full power was reached on February 16 and was maintained for the remainder of the period.
No Engineered Safety Feature actuations occurred during the period.
A routine attempt to drain condensate from the Containment Instrument Gas system moisture collecting tank resulted in an area and personnel contami-nation on the 719 foot elevation of the reactor building.
OPERATIONS (71707)
Ins ection Activities The inspectors verified that the facility was operated safely and in conformance with regulatory requirements.
Pennsylvania Power and Light (PPKL) Company management control was evaluated by direct observation of activities, tours of the facility, interviews and discussions with personnel, independent verification of safety system status and Limiting Conditions for Operation, and review of facility records.
These inspection activities were conducted in accordance with NRC inspection procedure 7170 The inspectors performed normal and back shift inspection including weekend and holiday inspection on March 2 from 2:00 a.m. to 6:00 p.m.,
March
from 3:00 a.m. to 6:00 a.m.,
and March 17 from 7:00 a.m. to 5:00 p.m.
2.2 Ins ection Findin s and Review of Events 2.2.1 Failure of Fire Detection Trans onders Unit
At 8:30 p.m.
on January 13, a failure in the ground fault circuitry shared by transponders 102 and 103 of the plant's fire detection system resulted in fire detection signals in those zones.
Trans-ponders 102 and 103 were declared inoperable.
The licensee determined that the power failure/ground fault alarm which was received was caused by a problem within the sensing circuitry of the transponder, since no ground fault or power failure existed.
The licensee replaced the existing circuit card with a spare which was later discovered to be defective since it caused sporadic alarming.
The spare was then removed and the original card reinserted pending replacement.
At the time of reinstallation of the original card, components on the card failed and the associated fire detection zones were declared inoperable.
The failed transponder cards ground fault circuitry was repaired and the fire detection system was returned to service at 4: 15 a.m.
on January 14.
Technical Specification 3.7.7 requires that a continuous fire watch be established within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> following the determination that required fire rated assemblies are inoperable.
However, continuous fire watches were not established until 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> and 15 minutes following the deter-mination of fire detector inoperability.
This was due to the unavail-ability of additional firewatch personnel during off hours.
The licensee estimated that an additional 7 individiuals were called out to establish the continuous firewatches in the ten fire zones affected.
Six of the ten zones were in the main control room fire area which was continuously manned.
The licensee had previously established an hourly roving firewatch in the area for degraded fire barrier penetrations.
This action partially mitigated the lack of a continuous firewatch during the initial 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> and 15 minute period.
The licensee believes that it is impractical to maintain additional firewatch personnel on site around the clock in anticipation of a failure of the Simplex fire detection system.
Calling out personnel to fill additional required positions cannot be accomplished within the one hour time frame.
A possible Technical Specification change to address this situation is being evaluated.
The inspector determined that the licensee's actions were appropriate under the circumstances.
The failure to provide continuous firewatches
within the required one hour is considered a licensee identified violation.
The inspector reviewed this licensee identified violation relative to
CFR 2 criteria for exercise of discretion.
This matter will be considered unresolved pending NRC review of the licensee corrective action to prevent recurrence.
(UNR 50-387/90-03-01)
Hi h Pressure Coolant Injection HPCI Ino erable Oue to Sto Valve Problems - Unit
At 5:30 p.m.
on February 15, HPCI was determined to be inoperable due to erratic behavior of the turbine stop valve.
HPCI had been out of service for routine instrumentation and control ( I&C) preven-tive maintenance activities since 7:00 a.m.
on February 15.
The
day HPCI flow surveillance SO-152-002 followed completion of the IEC activities.
A review of the General Electric Transient Analysis and Review System (GETARS) plots of the HPCI turbine stop valve position for two MPCI starts identified that the valve failed to open.
At 5:30 p.m., following review of the surveillance test run data, the licensee determined that HPCI was not capable of being restored to operable status without taking action to correct the stop valve response.
The continued inoperability was determined to be reportable.
An NRC four (4) hour notification was made at 6:22 p.m.
due to inadver-tent loss of a single train safety system.
The licensee determined that high stop valve balance chamber pressures in conjunction with hydraulic and steam forces resulted in the failure of the stop valve to open.
A stable opening of the stop valve is dependent on the upward forces just exceeding the downward forces on the valve at the point in time when the disc just leaves its seat.
The weight of the disc, spring force and frictional forces are relatively constant with time.
These forces are of considerably less magnitude than the steam or hydraulic forces.
Therefore, the hydraulic force and steam force under the main disc are the major forces of consideration and must just exceed the balance chamber force for stable opening of the stop valve.
These forces are dependent on system variables and will change with time.
The initial HPCI surveillance test was performed under cold conditions (prior to admitting steam)
and subsequent tests were performed under hot conditions.
A 10 feet section of pipe between the steam admission valve and stop valve allows the balance chamber to return to ambient conditions between surveillance of the HPCI system.
This design accounts for a 30 psig balance chamber pressure difference between hot and cold runs.
The purpose of the balance chamber is to keep the stop valve closed when HPCI operation is not desired and to prevent the valve from opening too fast, potentially resulting in valve damage due to back slamming.
The licensee had previously determined that acceptable
balance chamber pressures ranged from 170 psig to 225 psig at hot conditions.
At'ess than 170 psig, the valve may slam open due to low balance chamber pressure.
At greater than 225 psig, the valve may not open.
The Unit 1 HPCI stop valve was previously set using this criteria at approximately 217 psig with several successful tests.
The first cold run performed on February 15, was measured at 216 psig, but the valve failed to open.
The second hot run was also unsuccessful with chamber pressure measuring 240 psig.
The licensee believes that the previous balance chamber adjustment may not have been adequate since it may not have accounted for maximum heatup at the stop valve.
The licensee subsequently reduced balance chamber pressure to approxi-mately 198 psig to 207 psig and ran two successful consecutive tests within approximately 3 minutes of one another.
The licensee believes that this action ensured that maximum heatup conditions were accounted for in the adjustment.
HPCI was then declared operable and returned to service on February 16.
The licensee believes that the system is presently operable, but is concerned about long term system reliability.
As such, the licensee is planning to modify the system during the fall 1990 refueling outage, similar to the modifichtion performed on Unit 2.
This modification removes stop valve opening dependency on balance chamber pressure by sequencing the opening of the stop valve.
In this manner, the stop valve begins to open when the control valve is in a fully closed position versus the open position as at present.
The sequencing of the stop valve balances below seat steam pressure against balance chamber pressure before the control valve begins to open.
Thus, the opening of the stop valve is mainly dependent on hydraulic forces.
Additionally, with the control valve closed, greater hydraulic force is initially available for the stop valve, since no oil is being drawn through the control valve.
Experience with this modification already in place in Unit 2 indicates that the stop valve opens smoothly and is apparently unaffected by the steam forces on the valve even with substantially higher balance chamber pressures.
The inspector discussed this event with the licensee and reviewed the licensee's documentation including anticipated corrective actions to prevent recurrence.
The inspector questioned the adequacy of the licensee's interim corrective actions for the HPCI stop valve, since insufficient assurance existed that the stop valve would continue to open at the new balnce chamber setpoint.
The inspector questioned the licensee on the need for increased surveillance frequency in order to provide this assurance.
The licensee reconsidered and stated that they would perform another surveillance test in April 1990 and again in Nay 1990 in order to verify that the system will function as desired.
The inspector had no further questions on this even Hi h Pressure Coolant Injection HPCI Ino erable Due to Failure to Provide Stable Flow Control - Unit 2 On February 16, with Unit 2 operating in Condition 1 at 100 percent power, and a quarterly High Pressure Coolant Injection (HPCI) flow surveillance test being performed, the HPCI flow controller failed to provide stable flow control in the automatic mode.
Flow oscillations were minor and on the order of 2 to 4 percent of total flow.
However, HPCI was declared inoperable at 1: 10 p.m.
since the HPCI system require-ments could not be confirmed and the test could not be properly performed.
Instrumentation
& Control (IEC) personnel performed a controller calibration and observed no controller problems that would cause the oscillation.
The controller gain, reset, and rate settings were in agreement with the data sheets and were left as found.
The governor needle valve was adjusted to optimize hydraulic stability.
The quarterly flow surveillance was re-performed on February 16, after the governor needle valve adjustment.
No oscillations in turbine speed and minimal osci llations in flow were observed.
The test was successfully completed with satisfactory results.
HPCI was restored to an operable status at 8:40 p.m..
This event was determined reportable per
CFR 50.73(a)(2)(v)
in that HPCI was determined to be inoperable resulting in the loss of a single train safety system.
Since the remaining Emergency Core Cooling Systems (ECCS) required by Technical Specification 3.5. 1 were operable, adequate core cooling was assured in the event of a loss of coolant accident.
The licensee had noted the minor system osci llations during a
pump performance test on December 20, 1989 and had generated a work authorization in order to investigate the cause and corrective action.
18C personnel were observing the surveillance on February
in order to see if the osci llations recurred and were on hand to take corrective action.
The cause of this event was attributed to instability in control system electro-hydraulic mechanical turbine governor response due to the governor needle valve requiring readjustment.
The intent of the needle valve adjustment is to provide control system stability under variable HPCI system conditions.
The licensee believes that further action is not warranted due to the low severity of the problem since HPCI was able to inject the required flow under these conditions and since the corrective action appears adequate.
The inspector discussed this event with the licensee and additionally reviewed all written documentation pertaining to the event.
No previous similar events have occurred at SSES.
The inspector con-sidered the licensee's actions in response to the event appropriately
3.
RADIOLOGICAL CONTROLS (71707)
3. 1 Ins ection Activities PP5L's compliance with the radiological protection program was verified on a periodic basis.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
3.2 Ins ection Findin s and Review of Events 3.2.1 Contamination Due to Im ro er CIG Tank Blowdown Unit 2 An area and personnel contamination occurred while blowing down a
Containment Instrument Gas (CIG) collection tank at 8:30 a.m.,
on March ll.
A Nuclear Plant Operator (NPO), while on rounds, noticed that the CIG collection tank showed an indicated water level.
This tank was installed as a
new modification to upgrade the existing automatic drain traps to a manually blown down moisture collection tank with local level indication.
The previously used drain traps often leaked excessively causing a loss of nitrogen (N2) pressure from the drywell.
The new moisture collection tanks were intended to provide an absolute barrier to prevent N2 leakage.
Procedures require blowing down the tank when level reaches
percent full.
The operator opened the drain valve, blowing down the contents into a floor drain.
A loud gas sound was heard, so, he shut the valve.
When he looked around the corner he noted dust coming from the floor drain.
Health Physics (HP) was contacted.
HP surveyed the area and the individual and found both to be contaminated.
A whole body count was performed and a body burden of 5.6 percent was assigned along with a skin dose of 6 millirems.
Inhaled dust resulted in assigning 9 MPC-hours to the individual.
The operator was decon-taminated and returned to duties after assessment of the contamination's effects.
The area was roped off, controlled and decontaminated.
A minor problem occurring during the effort in that an air dryer swap occurred blowing a small amount of gas into a contaminated area.
This action created a small dust cloud which spread into an adjacent area that was recently decontaminated.
Shiftly blowdown of air tanks was placed on hold pending evaluation of the adequacy of the modifi-cation by engineering and health physics.
The entire area was sub-sequently deconned.
The licensee reviewed this event and determined it was not reportable.
The cause of this event was attributed, in part, to large amounts of contamination in the drain which blew back dust particles when nitrogen was blown into it from CIG.
Additionally, the operator was not completely,familiar with the new modification and was not fully instructed on the proper method of blowing down the system to remove
condensation.
The operating level of the new moisture collection tanks was not marked on the level indicator (sight glass).
Corrective actions taken by the licensee included:
positioning/labeling of level indication to make viewing of the sight glass easier for the operator and to indicate the operating band.
revising the operating procedure to require isolating and depressurizing the collection tanks prior to gravity draining them.
assuring operators are familiar with the proper method for draining the collection tanks.
Corrective actions being evaluated included:
implementing a health physics survey practice of surveying the inside of drains, in addition to the outside.
reviewing post modification operations training and procedures to assure their adequacy.
covering the drain funnel with a clear plastic cover.
The inspector discussed the event and the corrective actions being implemented and evaluated with the licensee.
The inspector found the licensee's actions in response to the event adequate'.2.2 ALARA Goals The inspector reviewed selected aspects of the licensee's efforts in 1989 to reduce occupational radiation exposure to as low as reasonably achievable (ALARA).
During 1989, the licensee conducted several outages, including two refueling outages.
The licensee attained an aggregate exposure of 704 man-rem.
The licensee had established 1989 goal of 720 man-rem.
Therefore, the licensee met their 1989 ALARA goal.
No unacceptable conditions were identified.
4.
MAINTENANCE/SURVEILLANCE (62703, 61726)
4. 1 Maintenance and Surveillance Ins ection Activit On a sampling basis, the inspector observed and/or reviewed selected surveillance and maintenance activities to ensure that specific programmatic elements described below were being met.
Details of this review are documented in the following section.2 Maintenance Observations The inspector observed and/or reviewed selected maintenance activities to determine if the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes or standards.
The following items were considered, as applicable, 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 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:
Troubleshooting and Repair of the Unit 1 Turbine Building Chiller (1K102B), performed on March 2.
Six year Preventive Maintenance of the Division 1 Swing Bus Motor-Generator Set Generator (1G202),
per Work Authorization (WA)
P93790, performed on March 9.
Hydrostatic Pressure Test of Reactor Building Closed Cooling Water Heat Exchanger (2E-201B) per WA C99852, performed on March 9.
Eighteen Month Inspection of Emergency Diesel Generator OG501C per WA A94547, commenced on March 12.
4.3 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine if the following criteria, if applicable to the specific test, were met:
the test conformed to 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 frequenc These observations and/or reviews included:
"B" Loop Residual Heat Removal (RHR) Pressurization Monitoring and Low Pressure Coolant Injection (LPCI)
Injection Valve (HV-251 F015B) stroking, performed on February
.
SO-184-001 Monthly Functional Test of Main Steam Isolation Valve (MSIV) Closure Reactor Protection System (RPS)
Instrumentation, performed on March 2.
SO-024-001 Monthly Diesel Generator (D/G) Operability Test of D/G
"A" for Post Maintenance Start and Emergency Service Water (ESW) Valve Adjustment, performed on March 7.
SI-252-207 Monthly Functional Test of the High Pressure Coolant Injection (HPCI) System Emergency Area Cooler Temperature Channels TSH-E41-2N602A&B, performed on March 7.
SI-252-212 Monthly Functional Test of the High Pressure Coolant Injection (HPCI) System Pipe Routing Area Temperature Channels TSH-E51-2N603C&D, performed on March 7.
SI-252-213 Monthly Functional Test of the High Pressure Coolant Injection (HPCI) System Pipe Routing Area Differential Temperature Channels TDSH-E51-2N604C&D, performed on March 7.
4.4 Ins ection Findin s
The inspector reviewed the above listed maintenance and surveillance activities.
The inspector noted that work was properly released before its commencement; that systems and components were properly tested before being returned to service and that surveillance and maintenance activities were conducted properly by qualified personnel.
Where questionable issues arose, the inspector verified that the licensee took the appropriate action before system/component operability was declared.
No unacceptable conditions were identified.
4.5 Review of Surveillance Related Events 4.5.1 Re uired Instrumentation Surveillances Not Performed Units 1 & 2 At 11:00 a.m.
on February 2, with Unit 1.operating in Condition
at 0 percent power and Unit 2 operating in Condition 1 at 100 percent power, the licensee determined that the Containment High Range pressure instruments (Post Accident Monitoring (PAM) Instrumentation)
were not included in surveillance procedures, this the requirements of Technical Specification 4.3.7.5 (Item
Primary Containment Pressure)
were not met.
These instruments were declared inoperable and the appropriate Limiting Conditions for Operation were entered.
These instruments are one of two ranges which monitor primary containment pressure.
The LOCA range instruments are 0-250 psig and were not found in the surveillance program, This was discovered during a review of selected, previously-completed surveillance procedures which test PAM instruments.
The licensee determined the cause of the event to be lack of procedure development because the licensee's surveillance program was essentially complete when these primary containment high range instruments were added to the plant design (November, 1982)
by the architect engineer via a design change package.
The subject instruments were calibrated by utility personnel (non-licensed)
following installation but were not identified at that time as requiring surveillance.
At the same time a task force was created to perform a complete review of the Technical Specification surveillance requirements.
This review was completed, the program was formalized and a surveillance program coordinator assigned to assure continued review and update as necessary.
In addition, during the task force review, an in-house engineering document (Engineering Work Request)
was generated on June 29, 1984 to identify all PAM Instruments for purposes of developing required surveillance procedures.
This document was requested since a portion of the PAM instruments were installed via the previously mentioned design change package and drawings/design documents were in the process of being updated.
Instrumentation monitoring both ranges (High and LOCA) of primary containment pressure were listed on this document but only the LOCA range was ultimately included in the surveillance program.
The procedures for surveillance of the LOCA range were already in existence when the PAM list was received by the task force.
Upon review/incorporation of these instruments into the program, the high range was apparently over-looked.
This event is considered an isolated incident.
Only the high range of primary containment pressure indication was not tested per surveillance requirement 4.3.7.5 of the Technical Specifications This instrumentation provides no safety system initiation or isolation function but provides high range post accident monitoring.
When the instruments were calibrated on February 2, 1990 they were all found to be in calibration.
Thus they would have provided accurate indication in the event of an accident.
Also, the LOCA range instruments (0-65 psia)
were operable and available for containment pressure monitoring since initial plant operations.
The safety impact of this event would not have been greater at any other
plant operating condition.
The Primary Containment High Range Pressure Transmitters for Unit 1 and Unit 2 were immediately calibrated via approved work documents.
Procedures were initiated and placed into the surveillance scheduling system.
All as found data was within the specified tolerances for these instruments.
The Engineering Work Request, identifying Post Accident Monitoring Instrumentation, was reviewed to verify all other identified instrumentation was in compliance with the Technical Specifications.
The licensee reviewed their administrative programs to determine if changes were warranted as a result of this event.
They determined that the administrative programs presently in place (i.e. Plant Modification Program and Surveillance Testing Program)
provide the necessary mechanisms to ensure Technical Specification Surveillance requirements are met.
The surveillance program ensures that proper reviews are performed when any changes to the plant design or Technical Specifications are implemented.
The Plant Modification Program includes reviews by any affected work groups to ensure necessary procedure changes are initiated resulting from plant modifications.
In addition, on-going reviews of surveillance procedures, drawings, and surveillance authorizations are performed by the Surveillance Program Coordinator as an added measure.
The inspector discussed the details of this event with the licensee and found the licensee's actions appropriate.
The inspector concurs with the licensee's belief that this event appears to be an isolated occurrence that resulted from an oversight in 1984.
The failure to include"these Containment High Range Pressure Instruments in the surveillance program is considered a licensee identified violation per
CRF 2.
(NON 50-387/90-03-02)
(Common)
5.
EMERGENCY PREPAREDNESS (71707)
5. 1 Ins ection Activit The inspector reviewed the licensee's compliance with 10CFR50.47 regarding implementation of the emergency plan and procedures.
In addition, the licensee's event notifications and reporting requirements per lOCFR50.72 and 73 were also reviewed.
5.2 Ins ection Findin s
No major emergency preparedness (EP) issues emerged during the period.
Minor EP issues that were discussed during the period, showed that the licensee considered emergency preparedness an important facet of overall performanc.
SECURITY (71707)
6. 1 Ins ection Activit The licensee's implementation of the physical security program was verified on a periodic basis, including adequacy of staffing, entry control, alarm stations, and physical boundaries.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
6.2 Ins ection Findin s
The inspector reviewed access and egress controls throughout the period.
No unacceptable conditions were noted.
7.
ENGINEERING/TECHNICAL SUPPORT 7. 1 Ins ection Activit The inspector periodically reviewed engineering and technical support activities during this inspection period.
The on-site Technical (Tech)
section, along with Nuclear Plant Engineering (NPE) in Allentown, provided engineering resolution for problems during the inspection period.
The Tech section generally addressed the short term resolution of problems while NPE scheduled modifications and design changes, as appropriate, to provide long lasting problem correction.
The inspector reviewed problem resolutions to determine if they were thorough and addressed preventing recurrences.
In addition, the inspector reviewed short term actions to ensure that the licensee's actions provided reasonable assurance that safe operation could be maintained.
7.2 Ins ection Findin s
7.2.1 Failure of Control Rod 50-15 to Withdraw - Unit
The licensee identified that control rod (CR) 50-15 failed to withdraw at 6:00 a.m.,
February 15.
CR 50-15 was being exercised per SO-156-001 to verify rod movement.
The rod was driven from position 48 (fully withdrawn) into position 46 (approximately 6 inches inward) but failed to respond to the subsequent rod withdraw command.
Reactor engineering was consulted.
The licensee decided to insert the rod an additional notch and attempt to withdraw it back to position 46.
The rod was inserted to position 44 and allowed to stabilize.
The rod was commanded to withdraw and again it did not.
Thus, the rod was declared inoperable.
A work authorization (WA) was submitted to identify and correct the cause and the required action of Technical Specification (TS) 3. 1.3. l.b. 1.
was implemente After a proper safety evaluation, the licensee wrote a test procedure to attempt to withdraw CR 50-15.
The test procedure provided for the application of 350 psig to the internal seals of the CR while mini-mizing loss of supply header pressure, in conjunction with maximizing return header prcssure'he test was performed and the rod failed to move.
The licensee continues to demonstrate movement of the control rod weekly by withdrawing the rod to the blank or double bar position and allowing the rod to settle.
This operation verifies movement and allows the rod to return to the original position.
The inspector discussed the issue with the cognizant systems engineer, the lead nuclear engineer and the compliance group.
The original and changed procedure for weekly control rod exercising was reviewed along with the test procedure.
'The licensee's long term contingency plans were also reviewed.
No unacceptable conditions were identified.
En ineerin Discre anc Re ort EDR
- Electrical Distribution Calculation Concerns RI-89-A-0119 The inspector reviewed the licensee'
actions to resolve concerns involving the adequacy of electrical distribution design calculations.
The concerns were originally presented by Nuclear Plant Engineering (NPE) Allentown and were confirmed by an NRC inspector in Inspection Report 50-387/89-29.
Inspector review identified some additional concerns.
There are currently five concerns:
1.
The licensee calculated that the minimum voltage needed to operate a damper motor was 122. 19 volts.
The damper motor was supplied from a bus that normally provides 120 volts nominal.
This matter was considered an unresolved item.
2.
Many design assumptions for electrical voltage/load calculations made by Bechtel during the initial design/construction period were never verified.
3.
Many completed voltage/load calculations that were completed have become obsolete.
4.
Old preliminary electrical calculations have never been completed.
5.
The degraded grid setpoint that was established to prevent overloading the equipment on starting is set below the initial voltage assumed in the Dapper calculational mode The above concerns were discussed by the NRC and licensee during a con-ference call conducted on March 14.
The licensee concluded that their analysis conformed to the Branch Technical Position ESB-1 and, as such, met the electrical design accepted by the NRC in supplement 1 of the safety evaluation report.
The NRC noted the licensee's position and agreed with the licensee's conclusion.
However, outstanding concerns still exist regarding the design adequacy of the electrical distribution system.
These concerns will be the subject of further reviews in subsequent inspections.
7;2.3 Emer enc Diesel Generator Failure Followu In September and October of 1989, the "B" and "C" emergency diesel generators suffered crankcase over pressure (explosion) events that resulted from excessive overheating of pistons from friction.
Details of these events and earlier licensee actions are included in NRC Inspection Report 50-387/89-30.
This inspection was performed fol-lowing a review of the licensee'
diesel generator analysis failure report SEA-CW-037 to confirm the licensee's metallurgical findings and to inspect damaged pistons from an engine that had not incurred an explosion, The inspector reviewed the metallurgical aspects of failed diesels
"B" 5 "C" as documented in the licensee's report SEA-CW-037.
On the bases of this review and the inspector's microscopic examination of representative samples of critical components ( liners and pistons),
the inspector concurred with the licensee's conclusion that the failures do not appear to be related to any metallurgical deficiencies or anomalies.
Areas of= the pistons and liners had been subject to overheating, minor cracking, wear and/or metal transfer (Cr 5 Sn)
during service or during the crankcase explosion.
The unaffected parts were found to have been manufactured from grey cast iron of normal structure and free of original casting defects.
Further investigation by the licensee into the causes of the "B" and "C" diesels crankcase over pressure events led to the partial disassembly of the "E" diesel engine to examine it for possible pre-cursors to a crankcase explosion event.
This examination revealed four pistons and cylinder liners with excessive wear and scuffing which if continued might lead to an event similar to that incurred by the "B" and "C" EDG units.
The inspectors observed extensive tin scraped from the non-thrust side of the pistons which was plated onto the cylinder liners.
Significant amounts of granular-appearing carbon deposits were observed in the areas of the compression and upper oil rings'n addition, the, upper piston compression rings showed excessive wear.
The inspectors determined that during EDG operation, the operators at times found it necessary to drain substantial quantities of water
from the EDG engine air intake manifolds.
Investigation revealed that the EDG combustion air intercoolers receive maximum unregulated flow of cooling water at all times.
Intake air manifold temperatures were reported which were consistently below the minimum specified temperatures established by the manufacturer.
It is believed that the source of the water drained from the engine air intake manifolds is condensate from the incoming highly humid combustion air.
The
- inspectors raised the question as to whether the excessive moisture in the combustion air would form highly acidic vapors which might lead to the piston tin removal problem.
The previous concerns of the inspectors were again expressed to the licensee for the excessively high engine cylinder firing pressures reported by the licensee in SEA-CW-037 as being a potential cause for the piston/cylinder wall distress problem which lead to the overpressure failure events.
The licensee is continuing their investigations and analyses to further confirm the root causes of these events.
In 'the meantime, the licensee initiated implementation of twelve EDG enhancement commitments made in report SEA-CW-037.
The licensee is of the opinion that these failures do not constitute a plant operability concern at the present time.
The failed diesels have been rebuilt, tested, and placed back in service.
There are four operable EDG units and offsite power sources as required by the technical specifications.
Further, the licensee considers that the nature of the EDG failure is such that it is not considered to be
"common mode"; therefore, simultaneous loss of EDG units is not projected.
The inspector has no further questions at this time.
8.
SAFETY ASSESSMENT/EQUALITY VERIFICATION 8. 1 Licensee Event Reports (LER), Significant Operating Occurrence Report (SOORs),
and Open Item (OI) Followup (90712, 92700)
8.1.1 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:
, j
Unit
90-001 Fire Detection Simplex Circuit Failure Causes Failure to Comply With Technical Specifications.
This event is reviewed in Section 2.2.2.90-003 Reactor Coolant Conductivity Sampling Frequency Not Completed Within Allowances of Technical Specification 4.4.4.
This event is reviewed in Section 8. 1. 1. 1.
- 90-004 Design Bases of Inboard MSIVs Concluded to be Inconsistent With Actual Valve Operating Characteristics and Realistic Accident Conditions.
This event is reviewed in NRC Inspection Reports 50-387/89-24 and 50-387/89-36.90-005 90-006 90-007 Station Alert Declared When Reactor Coolant Temperature
,Exceeded 200 Degrees F due to the Temporary Loss of the Normal Method of Decay Heat Removal.
This event was reviewed in NRC Inspection Report 50-387/90-05
'eactor Water Cleanup System Isolated When Power Was Lost to its High Differential Flow Instrument.
This event was reviewed in NRC Inspection Report 50-387/89-36.
HPCI Turbine Stop Valve Failure to Open Properly.
This event is reviewed in Section 2.2.3.90-008 Required Instrumentation Survei llances Not Performed.
This event is reviewed in Section 2.2.4.
- 90-009 Failed Reactor Pressure Switch - Operation Prohibited by Technical Specification During Retest.
This event is reviewed in Section 8.1.1.1.
Unit 2 90-001 HPCI Failure to Provide Stable Flow Control in Automatic Mode.
This event is reviewed in Section 2.2.4.90-002 Unplanned ESF Actuation - Generator Load Reject and Reactor Scram.
This event was reviewed in NRC Inspection Report 50-388/89-35.
No inadequacies were note Onsite Followu of Licensee Event Re orts For those LERs selected for onsite followup (denoted by asterisks in Detail 8. 1. 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 findings relate to the LERs reviewed on site:
LER 50-387/90-003 Reactor Coolant Conductivit Sam lin Fre uenc Not Com leted Within Allowances of Technical S ecification 4.4.4.
At 4:32 p.m.
on February 3, with Unit 1 at 0 percent power in Condition 4, the Reactor Mater Cleanup System (RWCU) was shut down as part of a planned evolution to support Reactor Protection System (RPS) Electrical Protective Assembly (EPA) breaker testing.
The shutdown of the RWCU System removed the reactor coolant continuous recording conductivity monitor capability.
As a result, an increased surveillance activity for coolant conductivity sampling was effected.
Samples were required once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in accordance with Technical Specification 4.4.4.c.2 for plant Condition 4.
With RWCU shutdown, the only other viable source of Coolant for conductivity sampling was from the Residual Heat Removal Shutdown Cooling System (RHR SDC).
The RHR SDC System, however, had been previously shutdown at 3:55 p.m. to support the same testing.
At 5:25 p.m.
on the same day, the capability of restoring RWCU and RHR SDC was lost due to a power failure as described in LER 90-005.
With the inability to restore these systems, no available source remained for drawing a reactor coolant conductivity sample.
At 5:53 p.m.,
as also described in LER 90-005, the inability to restore RHR SDC resulted in an unplanned entry into plant condition 3.
As a consequence, an increased coolant conductivity sampling frequency of once every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> was required in accordance with Technical Specification 4.4.4.c. 1.
At 9;53 p.m., the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time limit expired without the plant being able to meet the sampling requirements due to the fact there was still no available source for drawing a coolant sample.
At 10:40 p.m.,
during recovery from the LER 90-005 event, RWCU was placed back in service.
However, there was insufficient pressure to obtain a reactor coolant sample.
At 11:02 p.m.
At 11:30 p.m.,
Chemistry took a coolant sample and verified conductivity to be within acceptable limit The licensee attributed the cause of this event to a planned shutdown of the RWCU and RHR SDC Systems which removed the main and alternate coolant conductivity sampling sources followed by a subsequent power failure preventing restoration of these systems.
Without an available sampling source, Technical Specification 4.4.4.c. 1 could not be met.
This event was determined to be reportable per
CRF 50.73(a)(2)(i)(B),
in that Unit 1 failed to comply with Technical Specification 4.4.4.c. 1 by not being able to meet the increased surveillance activity frequency of sampling for reactor coolant conductivity.
There were no safety consequences or compromise to the public health and safety as a result of this incident.
When the surveillance activity was completed
hour and 37 minutes after the required time limit, reactor coolant conductivity was verified to be within acceptable limits.
After recovery of the RHR SDC System, Chemistry sampled reactor coolant for conductivity and verified the results to be within acceptable limits.
The inspector determined that the licensee's actions and review of the event were adequate.
However, the failure to comply with Technical Specification 4.4.4.c.
1 requirements is considered a
licensee identified violation per
CFR 2.
(NON 50-387/90-03-03).
The licensee's corrective actions to address the loss of power failure were discussed in NRC Report No. 50-387/90-05.
The inspector realized that extenuating circumstances surrounded the licensee's inability to take a coolant conductivity sample, and has noted such.
LER 50-387/90-009 Failed Reactor Pressure Switch On February 14, 1990, with Unit 1 operating in Condition 1 at 100 percent power, the licensee determined during surveillance testing, that one of the four reactor steam dome high pressure switches was inoperable inoperable because repetitive results could not be obtained during the surveillance test.
The pressure switches provides a trip function for the Reactor Protection System (RPS).
The inoperable channel was placed in the trip condition (half scram)
as required by Technical Specification 3.3. 1 and the applicable Action Statement was entered.
The Action Statement required the unit to be in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
The licensee attributed the cause of the event to failure of a component or components in the pressure switch assembly.
This was determined by evaluation of the surveillance test data which showed that a repeatable as-found setpoint could not be obtaine A replacement pressure switch was obtained and bench tested.
In order to perform the replacement and subsequent surveillance test, the effected RPS channel had to be reset ( taken out of the tripped condition).
With the channel taken out of the tripped condition, the action'tatement was no longer met and Technical Specification 3.0.3 was entered.
Technical Specification 3.0.3 requires that when a
limiting condition for operation can not be met within one hour, the unit shall be placed in at least startup within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and hot shutdown within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
This event was determined to be reportable per
CFR 50.73(a)(2)(i)(B),
in that the Technical Specification 3.3. 1 action 1.,
was not met while an RPS instrument was being replaced and tested.
This event did not create a significant degradation in the ability to protect the health and safety of the public and/or plant personnel since only one of two channels in the Div.
1 trip system was inoperable.
The other channel in the Div. I trip system and both channels of the Div. 2 trip system, as well as all other RPS functions were operable while this condition existed.
During the replacement and testing of the defective pressure switch, Div. 2 of RPS reactor high pressure trip was operable as well as all other RPS functions.
Once the instrument was replaced, the trip had to be reset to facili-tate testing necessary to ensure it would provide the required trip function.
The action statement was not met only during the time period that the defective instrument was being replaced and tested.
This time period was one hour and ten minutes.
The licensee replaced the defective instrument and tested it satisfactorily.
The failure was considered a random failure and was entered into the instrument performance trend program by Instrumentation
& Controls personnel.
In addition, this failure was reported to the Nuclear Plant Reliability Data System (NPRDS).
Concerning entry into Technical Specification 3.0.3, the Technical Specifications do not prohibit or contain provisions for allowing an RPS trip (half scram) signal, imposed due to action requirements, to be reset to allow performance of Technical Specification required survei llances needed to restore an instrument to operable status.
Such provisions are considered necessary and will be pursued as a
change to the Technical Specificatio < ~
The inspector discussed the event with members of the plant staff and reviewed documentation on the event.
The inspector verified that the licensee commenced preparations to place the plant in startup in accordance with the action requirements of Technical Specification 3.0.3, but was able to discontinue those due to returning the instrument to operable status prior to the need to commence power reduction.
As a result, the inspector found the licensee's actions in response to the event acceptable.
Si nificant 0 eratin Occurrence Re orts Significant Operating Occurrence Reports (SOORs)
are provided for problem identification and tracking, short and long term corrective actions, and reportabi lity evaluations.
The licensee uses SOORs to document and bring to closure problems identified that may not warrant an LER.
The inspectors reviewed the following SOORs during the period to ascertain whether:
additional followup inspection effort or other NRC response was warranted; corrective action discussed in the licensee's report appears appropriate; generic issues are assessed; and, prompt notification was made, if required:
1-90-039 1-90-045; 1-90-054; 1-90-060; 1-90-066; 1-90-072; 2-90-027; 2-90-034; 2-90-042; 1-90-040; 1-90-046; 1-90-055; 1-90-061; 1"90-067; 2-90-015; 2-90-029; 2-90-035; 2-90-044
'"90-041; 1-90-042; 1-90-049; 1-90-051; 1-90-056 1-90-057 1-90-062; 1-90-063; 1-90-068; 1-90-069; 2"90-021-2-90-022; 2-90-030; 2-90-031; 2-90-036; 2"90-037; 1"90-043; 1-90-044; 1-90-052; 1-90-053; 1-90-058; 1"90-059; 1-90-064; 1-90-065; 1-90-070; 1-90-071; 2-90-023; 2-90-024; 2-90-032; 2-90-033; 2-90-040; 2-90-041; The following SOORs required inspector followup:
1-90-006 documented the failure to establish a continuous fire watch within one hour following fire detection equipment failure, See Section 2.2. 1 for details.
1-90-022 documented the failure to include two Containment High Range Pressure Instruments in the surveil.lance program.
See Section 4.5.1 for details.
1-90-047 documented a violation of Technical Specifications in order to replace and'test a reactor vessel pressure switch.
See Section 8. 1. 1. 1 for detail ~ ~
l7 t<
) ~
1-90-048 documented the inability to withdraw Control Rod 50-15.
See Section 7.2. 1 for details.
1-90-050 documented "problems with the HPCI turbine stop valve resulting in HPCI being declared inoperable.
See Section 2.2.2 for details.
2-90-028 documented the failure of the quarterly HPCI flow verification surveillance resulting in HPCI being declared inoperable.
See Section 2.2.3 for details.
2-90-043 documented contamination of a licensed operator due to improper CIG tank blowdown.
See Section 3'. 1 for details.
8.2 Sus uehanna Review Committee 40500 The inspector observed the activities of the Susquehanna Review Committee (SRC)
on January 24 and 25.
The purpose of this inspection was to evaluate the depth of the SRC's review of overall plant performance and to ensure that the discussions were directed toward nuclear safety.
The SRC conducted their review activities over two days.
Their review began at 1:00 p.m., January 24 and ended at approximately 4:00 p.m.,
January 25.
Ten members were present full time with two members being absent for a short period of time.
A quorum was maintained throughout the meeting.
An agenda was published and sent with the review material to all members well in advance of the meeting.
Two major topics covered during the meeting were the licensee's self assessment capability and the Nuclear Safety Assessment Groups (NSAG) summary assessment (SA) of both units'perating performance for the past 5 years.
The NSAG SA reviewed transients, challenges to the safe operating envelope, equipment damage and radiological events.
Data was reviewed in each of these areas from 1985 to 1989 and the SRC concluded that the number of challenges and transients were essen-tially unchanged from year to year.
Specifically, the causes (operator error, error non-operator, design, malfunction) occurred in the same relative percentages.
A potentially adverse trend was detected in radio-logical events since their numbers increased.
The licensee committed to review this concern in more detail.
The SRC concluded that the existing management practices and controls resulted in a number of operational events that did not vary from year to year and that the SRC was seeing random variations within their management control system.
They also noted that in order to improve performance further, they would have to make changes to their existing management control system.
The SRC agreed to consider additional control system changes if their safety benefit is commensurate with the resource expenditure necessary to realize performance improvement rg I
~ ~
The inspector noted that there was healthy self criticism of plant activities by the SRC.
Two outside consultants are a part of the SRC and bring a fresh perspective to the meetings.
During the meeting, they frequently challenged existing perceptions of how activities should be and were conducted, as did, the regular licensee members.
SRC meeting minutes were reviewed for 1989.
The inspector noted good documentation of actions taken and thorough review of safety issues.
Management interaction with workers was noted.
No inadequacies were noted.
The following SRC observations and comments were made that agree with NRC perceptions regarding overall licensee performance:
A licensee self assessment program is needed to further improve performance.
This program would be multi-tiered and would emphasize line management's internal self-critical review of past performance.
It would also provide recommended performance improvements.
The excessive time it takes to perform engineering modifications was also mentioned as a continued area of concern.
SRC believed that the on-going Organizational Effectiveness Review (OER) for the Nuclear Department would provide useful recommendations for improving their timeliness.
Further management attention is warranted.
The inspector noted that other NRC and SRC areas of common concern were mentioned which reflected highly on the self-critical attitude of the SRC.
The inspector also noted that SRC tried to set high standards in their expectations from the station.
A questionable Safety Evaluation Report (SER) was sent back to the station for further rewrite when SRC noted a
less than desired safety perspective.
The licensee recognizes that the SRC and the Plant Operation Review Committee must set and maintain high standards to ensure that station performance does not erode with time.
No unacceptable conditions were identified.
9.
Exit Meetin 30703 The inspector discussed the findings of this inspection with station management during and at the conclusion of the inspection period.
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 restrictions.