IR 05000387/1991018
| ML17157A993 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 12/23/1991 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17157A992 | List: |
| References | |
| 50-387-91-18, 50-388-91-18, NUDOCS 9201070044 | |
| Download: ML17157A993 (34) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION Inspection Report Nos.
REGION I
50-387/91-18; 50-388/91-18 License Nos.
Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Facility Name:
Inspection At:
Susquehanna Steam Electric Station Salem Township, Pennsylvania Inspection Conducted:
September 24, 1991 - November 11, 1991 Inspectors:
G. S. Barber, Senior Resident Inspector, SSES J: R. Stair, Resident Inspector, SSES B. C. Westreich, Reactor Engineer, DRP C. C. Harbuck, Senior Engineer, NRR J. J. Raleigh, Licensing Project Manager, NRR Approved By
~J. R.
hite, Chief Reactor Projects Section No. 2A Date In ecti n Summa I
p i
d Hi h fI ig:
p i, slv controls, maintenance/surveillance testing, emergency preparedness, security, engineering/technical support, safety assessment/quality verification, and Licensee Event Reports; Significant Operating Occurrence Reports, and open item followup.
~Result:
During this inspection period, the inspectors found that the iicensee's activities were
'directed toward nuclear and radiation safety.
Two non-cited violations and two unresolved items were identified.
An Executive Summary is included and provides an overview of specific inspection findings.
920i070044 9i1223 PDR ADOCK 05000387 G
EXECUTIVE SUMMARY Susquehanna Inspection Reports 50-387/91-18; 50-388/91-18 September 24, 1991
- November 11, 1991 Q)er~ti ns (30702, 71707, 71710)
A Unit 2 Division 1 half scram occurred on October 14 due to loose connections and degraded relays in an RPS cabinet.
The loose connections and degraded relays were attributable to weaknesses in the preventative maintenance activities for these components.
Planned improvements in preventative maintenance activities appear adequate.
~di I
i
<<(71707)
Individual workers and Health Physics personnel implemented radiological protection program requirements.
Periodic inspector observation noted no inadequacies in the licensee's implementation of the radiological protection program.
t Maintenance/Surveillance (61726, 62703)
The failure to include eighteen containm ent boundary isolation valves within the required surveillance check list was a non-cited violation while all of the subject valves were verified to be closed in conformance with valve positioning procedures.
The valves were not included in the surveillance listing due to administrative oversight.
Improper oil level caused two Control Structure chiller trips.
Oil level varies with chiller performance and extremely high or extremely low levels can cause chiller trips.
The licensee is investigating methods to control oil level.
This item is unresolved.
During a test surveillance on the reactor building closed cooling water system, a relief valve failed to liftat its required setpoint.
The failure was attributed to rust and a dust cap found inside the valve.
The licensee failure to discover this dust cap during initial installation remains to be resolved.
Further information is needed to evaluate this problem.
This item is unresolved.
On October 30, the licensee discovered that a secondary containment isolation damper would not close during its routine surveillance.
The failure of this damper to close-was attributed to problems with solenoid valve operation.
An air leak from the solenoid valve was initially identified on August 25.
Although an evaluation of the potential impact on operability was apparently performed at that time, documentation supporting the evaluation was not generate Emer e'nc Pre aredness (82301)
No emergency preparedness issues occurred during the'period.
~Securit (71707)
Routine observation of protected area access and egress control indicated good control by the licensee.
En in rin /Technic l (37700, 71707, 92720, 93702)
The inspectors reviewed the licensee's 10 CFR 50.59 safety evaluation program.
Overall, the licensee's program was found to be acceptable.
However, pre-1990 evaluations lacked concise documentation..
The screening process for Engineering Change Orders did not require a documented basis for decisions reached.
The licensee agreed to review their practices for these program deficiencies.
The licensee determined that, during accident conditions, an additional four second delay could exist when opening the LPCI and Core Spray Injection Valves due to pressure locking in the bonnet area.
This delay, although undesirable, is within the bounds of the accident.
analysis.
Some weaknesses existed in the licensee's initial evaluation that was used to justify continued operation.
Supplementary information was needed to verify the acceptability of the licensee's methodology.
Safet A sessment/Assurance of ualit (40500, 90712, 92700, 92701)
'
Licensee Event Report was generated for unsealed openings in fire barriers.
This resulted'n a non-cited Violation.
The inspectors reviewed 40 Significant Operating Occurrence Reports, four of which were followed up in this report.
Two open items were closed.
The first item concerned licensee actions for a January 1989 cooldown event and the second pertained to EOP actions necessary to minimize vessel stratification.
The Susquehanna Review Committee (SRC) met on October 1 and 2.
The SRC probed licensee activities in detail.
Some weaknesses in root cause identification were noted by the inspector for component level failures that led to the July 31 Reactor Scram with Main Steam Isolation Valve Closur SUMMARYOF OPERATIONS 1.1 Inspection Activities The purpose of this inspection was.to assess licensee activities at Susquehanna Steam Electric Station (SSES) as they related to reactor safety and worker radiation protection.
Within each inspection area, the inspectors documented the specific purpose of the area under review, any identified findings, and appropriate conclusions.
This assessment is based on actual obser-vation of licensee activities, interviews with licensee personnel, measurement of radiation levels, independent calculations, and selective review of applicable documents.
Abbreviations are used throughout the text.
Certain uncommon abbreviations are identified on initial use.
The more common abbreviations are identified in Attachment 1.
1.2 'usquehanna Unit 1 Summary Unit 1 operated at or near full power throughout the inspection period.
Scheduled power reductions were conducted during the period for control rod pattern adjustments; surveillance testing, and maintenance.
No ESF actuations occurred in Unit 1 during the inspection period.
1.3 Susquehanna Unit 2 Summary Unit 2 operated at or near full power until November 4 when power was reduced to 60 percent to repair a main condenser tube leak in the "C" waterbox.
The tube was plugged and the unit was restored to full power on November 6. Full power was maintained for the remainder of the inspection period.
One ESF actuation occurred on October 14 when the "A" RPS motor generator output breaker tripped.
As a result, several Division I systems isolated and both the Standby Gas Treatment System and Control Room Emergency Outside Air Supply System initiated.
For details on the actuation see Section 2.2.1.
2.
OPERATIONS 2.1 Inspection Activities The inspectors verified that the facility was operated safely and in conformance with regulatory requirements.
Pennsylvania Power and Light (PP&L) 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 71707.
The inspectors performed 16.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of deep backshift inspection during this perio.2 Inspection Findings and Review of Events On October 14, the output breaker from the "A" RPS Motor Generator (MG) Set tripped open causing both Electrical Protection Assembly (EPA) breakers to trip. As a result, a Division I half scram occurred, the Reactor Water Cleanup (RWCU) inboard isolation valve
'losed, the Reactor Recirculation Pump cooling water isolation valves closed, the Reactor Building HVAC Zones II and IIIisolated, and the Standby Gas Treatment System (SGTS)
and Control Room Emergency Outside Air Supply System (CREOASS) initiated.
These isolations and initiations were expected, as per design.
Power to the RPS was restored through its alternate power supply and all systems were restored to their normal lineups.
The licensee made. the required Emergency Notification System call within the allowed time period per 10 CFR 50.72.
Licensee investigation discovered three loose connections in the RPS MG control cabinet.
In addition, three mechanical relays for the generator electrical protection system were found to be in a degraded condition and functioning improperly due to poor maintenance.
The loose
'onnections were tightened and the relays disassembled, cleaned, and contacts burnished.
The regulator and protective device settings were functionally tested and the "A" RPS returned to its primary power supply on October 16.
Planned corrective actions include inspection of the remaining MG Set regulators for relay abnormalities and loose connections in both units during the next available planned equipment outages.
Additionally, periodic maintenance activities for RPS MG Sets willbe reviewed to incorporate maintenance of relays and security of connections.
The results of this review will be evaluated by a task team previously established to enhance the reliability of the RPS systems.
t The failure to maintain the relays in good condition indicates a weakness in the preventive maintenance program.
Accordingly, the inspector reviewed documentation related to the event and discussed details of the matter with the licensee.
It is uncertain that the RPS reliability task team would have identified the need for preventive maintenance of these components-if this event had not occurred.
However, appropriate disciplines have been included on the task team to review such issues.
Planned system modifications are expected to improve in the preventive maintenance of the RPS MG sets and breakers.
Based on the planned and implemented corrective actions, the inspector had no further questions at this time.
3.
RADIOLOGICALCONTROLS 3.1 Inspection Activities PP&L's compliance with the radiological protection program was verified on'
periodic basis.
These inspection activities were conducted in accordance with NRC inspection procedure 7170.2 Inspection Findings Observations of radiological controls during maintenance activities and plant tours indicated
'hat workers generally obeyed postings and Radiation Work Permit requirements.
No inadequacies were noted.
4.
MAINTENANCE/SURVEILLANCE 4.1 Inspection Activities 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,sections.
4.2 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 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; quality control hold points were established where required; functional testing was performed prior to declaring the involved component 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:
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Reactor Building Chilled Water Compressor 1K206B Bearing Resistance Temperature Device and Impeller Displacement Switch Wiring Modification, per WA U10070, on October 18; Control Room Emergency Outside Air Supply System Fan OV101A Annual Preventive Maintenance, per WA P12094, on October 23; Replacement of "E" Emergency Diesel Generator Jacket Water Pump Seal, per WA S13261, on October 31; Replacement of "D" Emergency Diesel Generator Air Compressor OK507D1 Relief Valve, per WA S15056, on November 1; and Replacement of Control Structure Fan OV103A Bearings, per WA S14156 on, November.3 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to verify that the following criteria:
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 component was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
These observations and/or reviews included:
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TP-016-007, Residual Heat Removal Service Water System Dye Injection Testing, performed on September 27; and SO-252-001; High Pressure Coolant Injection Quarterly Flow Verification, performed on October 21.
4.4 Inspection Findings The inspector reviewed the listed maintenance and surveillance activities.
The review 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 the system/component was declared operable.
The inspector questioned. the two maintenance mechanics working on the OK507D1 air compressor with regard to a torquing specification procedure contained in the work package.
The inspector noted that the individuals did not appear to be able to identify different materials in order to determine which torquing specification was appropriate.
One of the two individuals questioned was uncertain on which torque specification to use'or a given application.
The other said he would contact his foreman.
The inspector reviewed this matter with the responsible maintenance foreman and supervisor.
The individuals stated that the training program provides instruction on how to identify certain materials used for fastener applications.
By knowing the material, fastener size, and application, the proper torque value can be read from the torque table in the torquing specification procedure.
The individuals indicated that torquing training is adequate and that the inability of these particular mechanics to identify the proper torque value was an isolated case.
However, in view of this particular matter, the licensee committed to provide refresher training to all mechanics prior to January 31, 1992.
Based on the above, the inspector considers this item close.5 Containment Boundary Valves Not Included In Monthly Surveillances On October 7; the licensee determined that 18 containment boundary valves in each unit,were not identified. (listed) in the monthly containment integrity surveillance inspection procedures.
Containment boundary valves are those system, valves between the containment wall and outboard containment isolation valve that act to form an extension of the containment boundary.
The outboard containment isolation valve is also a containment boundary valve.
Containment isolation valves are those valves that assure primary containment integrity by isolating process lines that penetrate the primary containment boundary.
This is usually accomplished by either manual valves secured in the closed position or by those valves listed on TS Table 3.6.3-1 which automatically close during accident conditions.
The identifed 18 containment boundary valves were normally locked closed test 'connection valves on vent and drain lines in the Residual Heat R'emoval (RHR) and Containment Atmosphere Control (CAC) systems.
The fact that these valves were not included in the surveillance procedure was discovered during the biennial review of Surveillance Procedures
SO-159-003 and SO-259-003, "Monthly Outside Containment Verification of Primary Containment Integrity" for both units.
A comparison of the valves listed in the procedures against the actual containment boundary valves revealed that 12 valves in the RHR system and 6 valves in the CAC system were not listed in the procedures.
All suspect valves were immediately verified locked closed in accordance with valve lineup checklists.
For additional confirmation, a plant walkdown was conducted to assure that primary containment integrity was maintained.
Procedure changes were subsequently initiated to add the missing valves to the surveillance procedures.
An Event Review Team was established to identify the root cause(s)
and provide corrective actions.
Some of the apparent root causes contributing to the event were:
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Certain outside containment boundary valves were improperly designated as containment isolation valves.
During the biennial procedure review, the licensee found that the procedure writer incorrectly assumed that automatic valves located on the penetration side of the RHR test valves were containment isolation valves, and therefore, failed to identify the actual boundary valves.
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Plant modifications to the Containment Radiation Monitoring (CRM) systems in both units during the last refueling outages installed additional test lines and valves which became part of the primary containment boundaries.
The modification program failed to involve the containment system engineer in the review process and to identify these valves for inclusion in the appropriate surveillance procedures.
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The CRM system engineer was unaware of the containment penetration surveillance requirement per TS.
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The operations modification engineer failed to identify the need to change the containment penetration surveillances to the operations surveillance procedure write Planned corrective actions to prevent recurrence include:
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Improving the method used for the handling and processing of modifications within the operations department to ensure adequate reviews of affected procedures.
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Improving the agenda of the Installation Kickoff"Meeting instructions relative to attendance by appropriate systems engineers and ensuring a comprehensive procedure review of affected procedures.
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Requiring Systems Engineering review of containment boundaries to ensure that all valves are properly addressed within procedures; and that necessary procedure changes are completed.
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Training system engineers relative to expected procedure and 'surveillance changes associated with system modifications.
The inspectors discussed the event with knowledgeable plant personnel and reviewed plant drawings and other pertinent documentation.
This event resulted in a failure to comply with TS 4.6.1.1.b in that the actual containment boundary valves were not verified at least once per 31 days, as required.
However, the significance of this failure is considered minor since the valves were found to be properly positioned and were verified previously when the
'ystem checklists were performed prior to restart following the last refueling outage.
In addition, the position of these valves is administratively controlled by the system checklists.
Since the licensee met the requirements of 10 CFR 2, Appendix C, Section V.G. related to self-identification of deficiencies and immediate corrective action, the failure to verify these particular containment boundary valves per TS 4.6.1.1.b is considered a non-cited Violation.
4.6 Improper Oil Level Causes "A" Control Structure Chiller Trips The licensee identified two trips of the "A" Control Structure (CS) chiller due to improper oil level.
The first trip occurred at 11:45 p.m., October 9; the second occurred at 5:11 p.m., October 10.
Licensee maintenance personnel investigated the first trip and found that oil level was excessively high.
Subsequently, four gallons of oil was drained from the chiller. The chiller was started and continued to run satisfactorily until the second trip occurred.
Investigation of the second trip showed high oil level again.
The licensee reviewed the CS chiller trips and determined that the events were not reportable.
The CS chillers are an integral part of the CS habitability systems.
Their proper functioning is needed to ensure that appropriate pressure is maintained in the CS and that the required heating and cooling functions are maintained for safe shutdown equipment to satisfy the specifications of 10 CFR 50, Appendix R.
Technical Specification Interpretation (TSI) 1-90-001 s'pecifies the functionality requirements of various CS Heating, Ventilating, and Air Conditioning (HVAC) systems.
It also requires a prompt shutdown ifboth CS chillers become unavailable, or a 30 day repair time ifone chiller becomes unavailabl The inspector reviewed the event and noted that high bearing temperatures preceded both trips.
In addition, the inspector questioned the licensee to determine if: (1) the causes of the chiller trips were adequately identified, (2) the planned or implemented corrective actions were adequate to prevent recurrence, and (3) maintenance activities did not lead to the trips.
The licensee determined that the chiller trips were due to two major factors, low chiller loads and short chiller run times.
The following pertains:
Freon and oil mix together well at high freon velocities, but poorly at low velocities.
Thus, at low velocities (low chiller loads), oil in the freon becomes immiscible and comes out of solution.
This typically occurs in the evaporator, the lowest pressure part of the system.
The oil willremix with the freon as velocity increases at higher loads.
This results in the returning of oil'to the sump compressor/gearbox.
As oil level increases, immersion of the rotating gears in the gearbox occurs, which significantly increases the heat input to the lubricating oil. Heat input exceeding the capacity of the oil cooler usually results in high bearing temperatures and subsequent chiller trip.
Short chiller run times result in oil hideout.
Short run times do not allow adequate time for the. circulating freon to pick up oil from system low spots.
Oil tends to concentrate at lower elevations in low pressure parts of the system and the freon flow velocity is inadequate to cause effective mixing. Thus, ifthe system is shut down shortly after starting, the oil will separate from the freon and sump level willdrop.
Consequently, additional oil may be added to ensure adequate oil volume for initial bearing lubrication on chiller startup, When the chiller is started, the freon will re-entrain the oil in the system low spots and cause the high sump oil level that can lead to chiller trips.
To prevent these types of chiller trips, the licensee initiated action to closely monitor oil level in the sumps.
Level increases have been detected in the past and action has been taken to drain oil level with the chiller running.
Oil has been added during chiller starts and stops, when required.
These actions have successfully prevented chiller trips in the past.
In addition, a temporary chiller was installed during the last refueling outage to minimize similar problems with the reactor building chillers.
Prompt and effective communication between operations and maintenance on all planned evolutions that affect chiller performance is expected to ensure that adequate oil level is maintained.
The inspector concurred with the root cause identified by the licensee and noted that monitoring by maintenance was effective at preventing CS chiller trips.
However, the close coordination between operations and maintenance was not evident for the October 9 and 10 chiller trips.
No documentation exists that describes the extent of the communications and coordination necessary for activities that affect chiller performance.
Improved coordination appears necessary, for the interim, until long term corrective actions are proposed and implemented.
The licensee stated that resolution of SOOR 1-91-255 will be used to track long-term corrective actions for the identified causes.
In addition, the inspector noted that the licensee was aware that oil level problems have been recognized as
8.
causes for previous chiller trips.
The licensee's review of these types of recurring problems has not been sufficient to effect resolution.
This item will remain unresolved pending NRC review of the licensee's long term corrective action.
(UNR 50-387/91-18-01)
4.7 Relief Valve Fails Tests - Test Failure, Unit 2 On October 14, the Reactor Building Closed Cooling Water (RBCCW) Heat Exchanger "A" Service Water Safety Relief Valve (PSV 21022A) failed its liftpressure setpoint and seat leakage tests.
PSV 21022A failed to liftin response to an applied test pressure of 202 psig (setpoint:
150 psig + or - 3%).
The valve was found to be clogged with rust and a plastic dust cap, which had apparently been left inside the valve since initial installation during plant construction.
The valve was cleaned, reworked, reassembled, retested satisfactorily, and reinstalled.
The inspector questioned the licensee concerning:
(1) the potential causes which allowed the plastic dust cap to be left in place, (2) the potential safety impact to the plant, (3) whether this problem could be generic, and (4) whether appropriate corrective actions had been taken.
This item remains unresolved pending the licensee evaluation of this matter (UNR 50-387/91-18-02(Common)).
4.8 Secondary Containment Damper Failure -, Unit 1 On October 30, the Zone I HVAC Equipment Compartment Filtered Exhaust System Suction Damper (HD-17524B) would not close during its quarterly stroke time surveillance.
The apparent cause was failure of the associated solenoid valve, SV-17524B, to reposition to vent air from the damper's actuator diaphraghm.
A dual unit L.C.O. was entered, and the solenoid valve was replaced; however, prior to restoration of the system, the new solenoid valve failed and had to be replaced with another valve from the warehouse.
The damper failed closed shortly after the new solenoid was installed and this failure was due an internal short in the operating coil ~ A second solenoid was installed and the damper was stroke tested satisfactorily.
The system was restored to an operable status and the L.C.O. was cleared within the allowable time period.
The failed solenoid valves were manufactured by
"Circle Seal Corporation" of Anaheim, California.
The inspector questioned the licensee to determine ifthere was any prior notice of the failure.
The licensee stated that a deficiency tag (02566) was hung on SV-17524B on August 25, due to an identified air leak.
The inspector reviewed Work Authorization S11098, initiated August 25, which was to investigate the cause of the air leak.
The licensee investigated per the WA and tightened a set screw, which was unsuccessful at stopping the air leak.
Maintenance personnel wanted to stroke test the solenoid valve; however, operations personnel wanted the stroke testing to be planned and scheduled through Unit Coordination (the licensee's scheduling group) since it involved TS related equipment.
On September 5, Planning and Quality Control completed review of the new WA written for solenoid valve replacement.
However, no work was performed until the solenoid valve failed during its next scheduled surveillance on October 3 Based on the above, it appeared that the licensee failed to perform a prompt operability evaluation of the impact of the air leak on damper operation and the necessary stroke time test to.confirm their conclusion.
Further discussions with licensee personnel have shown that
'an evaluation was performed by maintenance personn'el; however, this evaluation was not documented, The evaluation determined that the air leak did not pose a condition which would prevent the damper from functioning.
Maintenance personnel were aware that ifthe air leak worsened the damper would fail closed to its safety related position.
The licensee stated that the request to stroke the valve was only for the purpose of attempting to stop the air leak.
The inspectors were concerned that the valve had been in a degraded condition, which could have impacted its ability to function, and no operability evaluation or stroke test were performed to prove otherwise.
The licensee stated that the solenoid failure on October 30, was unrelated to the existing air leak.
Without any documentation supporting that an evaluation was performed, the inspectors were concerned that the air leak and solenoid valve failure were related.
It appeared that a potentially degraded condition existed on safety related equipment, which was not being properly addressed.
The inspectors initially believed that the work performed on August 28 was a maintenance activity which should have required cycling and timing of HD-17524B, in accordance with TS 4.6.5.2.a.
The licensee disagreed with this position and stated that the activity (set screw adjustment) performed would not have affected the operation of SV-17524B and therefore was not an activity which required imposition of TS 4,6.5.2.a.
Vpon further evaluation, the inspectors concurred with the licensee conclusion for these specific circumstances.
The inspectors are concerned that a weakness exists in the licensee's documentation process, related to troubleshooting, since a written evaluation for known deficiencies is not required.
Although it appears that an evaluation was performed in this case, the lack of supporting documentation did not provide for review of its adequacy.
In addition, the inspectors noted that the adequacy of these evaluations is strongly dependent upon the training and experience of the individuals involved.
In this case, those individuals were apparently knowledgeable of the valve internals and realized that neither the set screw adjustment nor the existing air leakage would impact valve operability.
Current procedural guidance does not require
.written operability evaluations for deficient or degraded conditions.
In addition, troubleshooting activities that may impact operability do not have to be documented.
The inspectors questioned with the adequacy of the licensee's root cause investigation for the first failure.
When the valve was bench tested, it stroked freely.
So, no further action was taken.
Since the cause was undetermined at this point, valve disassembly should have been required.
None was performed.
There have been previous solenoid valve failures (SOORs 1-87-221, 1-90'-099, 1-91-022, 1-91-024) where no conclusive cause could be identified.
These failures were listed as random.
The inspectors are concerned with the licensee's failure to perform a detailed investigation when the potential for generic failure mechanisms exists.
The lack of:
(1) a thorough root cause investigation for potentially similar solenoid valve failure mechanisms, and (2) detailed procedural guidance requiring written operability evaluations for safety related equipment degradations that potentially impact operability will remain unresolved pending action by the licensee and review by the NRC.
(UNR 50-387/90-18-03(Common))
F
5.
EMERGENCY PREPAREDNESS 5.1 Inspection Activity The inspector reviewed licensee event notifications and reporting requirements for events that could have required entry into the emergency plan.
5.2 Inspection Findings No events were identified that required emergency plan entry.
No inadequacies were identified.
6.
SECURITY 6.1 Inspection Activity PP&L's implementation of the physical security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundaries.
Additionally, the inspector reviewed access and egress controls throughout the period.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.
6.2 Inspection Findings
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No unacceptable conditions were noted.
7.
ENGINEERING/TECHNICALSUPPORT 7.1 Inspection Activity The inspector 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 identified 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 term problem correction.
The inspector verified that problem resolutions were thorough and directed toward preventing recurrences.
In addition, the inspector reviewed short term actions to ensure that the licensee's corrective measures provided reasonable assurance that safe operation could be maintained.
7.2 Inspection Findings 7.2.1 Pressure Locking Effects on RHR and Core Spray Injection Valves On October 18, the licensee informed the inspector of a potential safety issue concerning pressure locking of Residual Heat Removal (RHR) and Core Spray (CS) injection valves.
The issue concerned the possibility of back leakage into the bonnets of normally closed
11.
injection valves.
In this situation, leakage could slowly pressurize within the bonnet area and impede the opening of the valve when required.
The licensee's calculations evaluated seven distinct cases.
These calculations showed that the opening times for the injection valves were increased by either one or four seconds, depending on the case involved.
The inspector was provided with safety evaluations (SEs)
. that documented the licensee's positions for these cases.
The inspector reviewed these SEs in detail, and noted the following:
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The SEs did not provide enough information to evaluate the acceptability of the licensee's assumptions and methodologies.
Plant staff had to supplement the written SEs with verbal information to define the scope, assumptions, calculations, and methodologies used for each case.
The need for, or the existence of, compensatory actions was not defined.
Additionally, licensee assumptions included the effects of degraded voltages without discussing whether credit was being taken for the existing TS provided degraded grid protection schemes.
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The basis for.continuing to consider these valves operable was not clearly articulated in the SEs.
The potential for these valves to fail to open was discussed in the SEs, but the conclusion was hidden in the details of the SE.
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The lack of a concise document that clearly articulated the scope, assumptions and basis for the operability determination significantly hampered the ability of plant, staff to perfor'm a timely evaluation of the pressure locking concern.
The licensee indicated that these items would be considered relative to improving the management of enginering discrepancies.
The inspector noted that the supplementary information provided by the licensee indicated that maximum injection delay time increased from 24 seconds to 28 seconds-;
A maximum injection time of 40 seconds is assumed in the Final Safety Analysis Report.
Though slighltly delayed, the injection times were well within the bounds of the safety analysis.
The inspector had no further questions at this time.
7.2.2 10 CFR 50.59 Safety Evaluation Program The licensee's Safety Evaluation program was reviewed to verify that it implemented the requirements of 10 CFR 50.59.
The inspectors reviewed relevant procedures and controls, training materials, and qualification requirements for persons that prepare and approve
CFR 50.59 safety evaluations.
The inspectors also evaluated implementation by reviewing selected 10 CFR 50.59 safety evaluations, Design Change Packages (DCPs), Engineering Change Orders (ECOs), Technical Safe'ty Assessments (TSAs), Setpoint Change Packages (SCPs), and other related documentation.
Appropriate licensee personnel were interviewed.
Table 1 contains a list of the documents reviewe Pr ram Descri tion The licensee's 10 CFR 50.59 process is entered whenever a request to change plant design is made.
The licensee refers to these changes in plant design as minor modification candidates (MMCs). A 10 CFR 50.59 evaluation is performed on each MMC to determine whether it becomes a Design Change Package (DCP), Setpoint Change Package (SCP), or an Engineering Change Order (ECO).
DCPs and SCPs require a 10 CFR 50.59 safety evaluation; ECO's do not.
An ECO may subsequently become a DCP, depending on the circumstances affecting the proposed modification.
The licensee also incorporates the use of TSAs for analyzing the technical bases of changes and may reference them in the 10 CFR 50.59 safety evaluation documentation.
The primary procedures used in the licensee's 10 CFR 50.59 program are Nuclear Department Instruction (NDI)-Quality Assurance (QA)-9.1.1 and Engineering Procedures Manual (EPM)-QA-121.
These documents establish the formal procedural guidelines'that are used to evaluate each change, test or experiment (CTE).
The procedures include the assignment of responsibilities to assure that all CTEs are evaluated for 10 CFR 50.59 applicability. The licensee's 10 CFR 50.59 applicability determination (screening) process includes controls for coordination of resources for CTEs that span multiple disciplines, controls to assure adequate access to up-to-date licensing basis arid design basis documents, specifications for independent review and approval, and instructions to assure proper reporting to the NRC and update of the SAR.
The inspectors found that the licensee's formal procedures appeared to be consistent with 10 CFR 50.59 and the industry's guidance document, NSAC-125 "Guidelines. for 10 CFR 50.59 Safety Evaluations."
However, the inspectors noted a weakness in the licensee's screening process; in that, the written determinations are usually brief checklists.
The checklist does not require the documentation of the technical basis for the determination that written safety evaluation is not required.
Notwithstanding this exception, the inspectors found that the determinations 'reviewed were correct.
The inspectors also noted that there was little procedural guidance for addressing
"defacto" changes.
Nuclear Department Instruction (NDI) QA-9.1.1 makes minor reference to defacto changes, however, no specific guidance is provided on how they are to be addressed.
Defacto design changes are deviations from the plant design, as described in the FSAR, that ifallowed to remain uncorrected, either permanently or temporarily, have the potential to affect plant operation.
Although these types of changes may be captured in the Non-Conformance Report (NCR) program and dispositioned "use as is," these changes should be reviewed to determine ifan unreviewed safety question (USQ) exists.
Trainin and uglification The licensee's training program specifically addresses the 10 CFR 50.59 safety evaluation process.
The training manual appeared to be comprehensive and consistent with the licensee's procedures, 10 CFR 50.59, and NSAC-12 Only licensee personnel that approve 10 CFR 50.59 safety evaluations and applicability determinations are required to complete the training program.
Although there is no requirement, many of the individuals that write the safety evaluations also attend the training.
Although most personnel take this training, the failure to make it a requirement for personnel that prepare 10 CFR 50.59 safety, evaluations is considered a weakness.
Im lementation A number of DCPs, ECOs, SCPs, TSAs, and Bypasses (temporary modifications) were reviewed to determine whether the licensee is adequately implementing its 10 CFR 50.59 program.
The inspectors found that the licensee processes each MMC as a DCP, a SCP, an ECO, or a Bypass in accordance with the appropriate procedures and controls as described above.
The inspectors observed a PORC meeting and noted that it appeared to adequately address the safety aspects of the topics discussed.
Discussions observed included 10'CFR 50.59 safety evaluations, procedural changes, Technical Specification interpretations, a DCP, and a SCP.
The inspectors noted that the quality of 10 CFR 50.59 safety evaluations performed in the latter part of 1990 was much improved compared to safety evaluations prepared prior to that time.
This appears to be the'result of enhanced training efforts.
(~oncl i~in In general, it appeared that the licensee's safety evaluation program was implemented in a manner consistent with 10 CFR 50.59 and industry guidance.
The program appears to incorporate adequate procedures and controls, and a thorough training program.
Recently prepared safety evaluations appeared to be of high quality and contained sufficient scope and depth to address potential safety issues.
During the course of the inspection, no violations or major deficiencies were found; however, the inspectors noted some apparent weaknesses, which are summarized below:
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The review of procedures and selected changes identified an area of concern in the screening process for making the 10 CFR 50.59 determinations.
A checklist is used to document the decision regarding which items do not receive a 10 CFR 50.59 safety evaluation.
This checklist does not require a written basis to support the screening decision.
The inclusion of a written basis would facilitate the independent review and approval process.
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The inspectors found that some 10 CFR 50.59 safety evaluations, performed prior to the mid-1990 time frame, failed to include information. It was found that the licensee maintained this information in background files.
Inclusion of this information in the body of the safety evaluations would facilitate both internal and independent review ~ 'n the review of selected ECO's, the inspectors found a case where it appears that the 10 CFR 50.59 applicability criteria were met and a safety evaluation should have been performed.
This item, ECO 89-6113a-d, involved the removal of internal parts from the emergency diesel generators as recommended by the diesel vendor.
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The inspectors found little procedural guidance for addressing
"defacto" changes.
As mentioned above, the 10 CFR 50.59 Safety Evaluation procedure NDI-QA-9.1~ 1 and the NCR procedure AD-QA-120 give little mention to defacto design changes.
The licensee acknowledged the above weaknesses and agreed to evaluate them for potential program improvements.
8.
SAFETY ASSESSMENT/QUALITY VERIFICATION 8.1 Licensee Event Reports (LERs)
The inspector reviewed the submitted LERs to verify that details of the event were clearly reported, including the accuracy of the description of the cause and the adequacy of'orrective action.
The following LER was reviewed was reviewed for this period:
iinit i LER 91-011-00 Unsealed Openings in Fire Bamers.
On August 19, with both units 1 and 2 operating at fullpower, the licensee discovered openings in fire rated barriers in the control structure.
These barriers are required to meet Technical Specification (TS) 3.7.7.
The licensee immediately confirmed operability of the fire detection equipment on one side of the barrier and established an hourly fire watch.
Eleven openings were identified in the Power Generation Control Complex flooring, below several doorways, between the subfloor structural steel framework and the underside of the raised flooring. These openings measured about 1" by 2" by 36" and were not identified on any design drawings.
The openings were apparently never sealed during plant construction.
All similar locations were inspected for the same condition, but no others were found.
The licensee plans to seal these openings as soon as practical to restore the integrity of the fire barriers, revise the appropriate plant drawings, and identify the openings in the fire protection surveillance program.
The licensee determined that the event was reportable in accordance with 10 CFR 50.73(a)(2)(i)(B), relative to failure to meet the requirements of TS 3.7.7; in that, compensatory measures were not in place to meet the TS action statement.
The licensee met the requirements of 10 CFR 2, Appendix C, related to self-identification of deficiencies and immediate correction of problems; therefore, this violation is not being cited since the criteria specified in Section V.G of the Enforcement Policy were satisfie V
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8.2
. 'ignificant Operating Occurrence Reports (SOORs)
SOORs are provided for problem identification and tracking, short and long term corrective
'actions, and reportability evaluations.
The licensee uses SOORs to document and bring to closure identified problems that may not warrant an LER.
The inspectors reviewed the following SOORs to ascertain whether:
additional NRC inspection was warranted, corrective action discussed in the licensee's report appeared appropriate, generic issues were assessed, and prompt notification was made, ifrequired.
Unit
28 SOORs, inclusive of 1-91-241 through 1-91-274.
gni~2 12 SOORs, inclusive-of 2-91-215 through 2-91-226.
The following SOORs required inspector followup:
1-91-253 Documented the failure to include 18 containment isolation valves in their required TS surveillances.
See Section 4.5 for details.'-91-255 Documented the trip of the "A" Control Structure Chiller due to improper oil level.
See Section 4.6 for details.
1-91'-266
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Documented the potential for a delay in the opening of the I.PCI and Core Spray Injection Valves.
See Section 7.2.1 for details.
2-91-218 Documented an ESF actuation which occurred when the "A" RPS Motor Generator output breaker tripped.
See Section 2.2 for details.
No unacceptable conditions were identified with the SOORs reviewed.
8.3 Open Items (Closed) UNR 50-387/89-01-02 Excessive Cooldown =-Following Unit 1 Reactor Scram On January 12, 1989, a turbine trip and reactor scram occurred on Unit 1.
While increasing
'ower during the subsequent reactor plant startup on January 16, 1989, the unit supervisor discovered that the cooldown rate during the first hour following the scram on January
had exceeded the allowable 100'F per hour rate at the bottom head drain line.
The actual cooldown rate was 101'F per hour.
The shift.supervisor determined that a Technical Specification (TS) 3.4.6.1 limit had been exceeded, and that the plant was in an action statement.
The action statement stated that ifa cooldown of greater than 100 'F in any one hour is exceeded, restore temperature to within the limits with 30 minutes, and perform an engineering evaluation to determine the effect of the out-of-specification condition on the
structural integrity of the reactor coolant system.
It also required verifying that the reactor coolant system remained acceptable for continued operation.
In this instance, the licensee failed to perform the engineering evaluation as required by the TS.
The NRC recognized that the cooldown rate following the reactor trip only slightly exceeded the Technical Specification limitand, therefore, the safety significance of the violation was limited.
Nonetheless, the NRC was concerned that the excessive cooldown rate 'was not recognized and evaluated prior to reactor restart.
This failure was one of the examples which was set forth in a Notice of Violation letter dated May 12, 1989.
The licensee's corrective actions to this event included performance of an engineering evaluation which concluded that the reactor coolant system was still within its design limits and that the unit remained acceptable for continued operation.
In addition, all operations personnel received training on the proper actions for this event.
Operating procedures were changed to add a supervisory review of reactor vessel temperature and pressure data once per shift.
The post transient evaluation procedure was also revised to include an additional review of reactor coolant temperatures by the Shift Technical Advisor, The licensee has re-evaluated the design basis for the reactor pressure vessel fatigue and brittle fracture analysis to determine the proper way to determine the cooldown rate.
The licensee concluded that the 100'F per hour cooldown rate was not intended to be applied to the bottom head drain line, which was being monitored by plant procedures during the cooldown.
Accordingly, the NRC considered this matter to require further regulatory analysis and evaluation.
A meeting was held between the licensee and the NRC on October 19, 1991, to review the li'censee's bases for the appropriate set of temperatures used to calculate the reactor vessel cooldown rate.
The licensee's analysis indicated that the Technical Specification requirements on heatup/cooldown are based on brittle fracture mitigation; and that the Technical Specification limiton heatup and cooldown of 100'F per hour applies to the beltline region only.
Subsequently, the licensee concluded that the most appropriate indicator, for Technical Specification compliance, is the saturation temperature based on steam dome pressure; and that when coolant temperature is less than 212'F, recirculation suction line temperatures should be used.
The licensee further concluded that bottom head drain temperatures should be used to ensure compliance with the applicable Technical Specification pressure and temperature curves.
The NRC staff reviewed these conclusions separately.
Based on the above meeting and the review of licensee documentation, the NRC staff concurred with the corrective actions taken to assure, tracking and timely review of cooldown rates, and the prompt completion of the required engineering evaluations.
In addition, the staff determined that use of the saturation temperature (TSAT) was acceptable for complying with the TS limit on heatup and cooldown rates since TSAT is a more realistic indication of temperatures affecting the reactor vessel.
Based on these actions, the licensee's proposed method for determining. compliance with the TS is acceptable, and this item is close (Closed) UNR 387/89-36-02 Implementation of Scram Procedure, EO-100-101, Revision to Assure CRD Flow is Minimized Following a Scram.
On January 12, 1989, following a reactor scram on Unit 1, an excessive cooldown event occurred.
The event was not discovered until January 16, 1989, during the reactor startup.
The NRC subsequently issued a Notice of Violation concerning the excessive cooldown on June 2, 1989, which included a violation involving failure to reduce control rod drive flow following the plant trip to minimize thermal stratification.
(Item A.2 of the Notice of Violation) In a subsequent response, the licensee contested the violation. The licensee stated that Operations personnel properly implemented the procedure which required CRD flow to be reduced after it was determined that a recirculation pump could not be started.
This condition did not exist following the scram.
Operators believed the pumps could be restarted with the normal time delays needed to establish initial conditions.
When the pump restart step was ultimately reached the recirculation pump was restarted on the first attempt.
'I Further NRC review of the event confirmed that the operators followed the emergency operating procedure (EOP) during the scram.
The piocedure directed them to bypass the CRD flow reduction step in the conditions which existed at the time the step was reached.
As a result, the NRC withdrew item A.2 from the Notice of Violation. The licensee recognized however, that procedure improvements were necessary to assure CRD flow was promptly controlled to minimize thermal stratification.
The inspector reviewed the revisions made to the scram procedure EO-100-101 and determined that the changes were adequate to ensure CRD flow was reduced in a timely manner.
This revision was incorporated into the procedure as Revision 2, dated March 18, 1990. This item is closed.
8.4 Susquehanna Review Committee The Susquehanna Review Committee (SRC) met on October 1 and 2,.the inspector observed the proceedings of the first day.
Major topics reviewed included root causes and corrective actions for the July 31 scram with MSIV closure, waterhammer and diesel generator reliability issues, and other scheduled open item and safety'reviews.
The inspector observed the staff presentation of the root causes and corrective action for the July 31 scram.
The licensee initiated various Event Review Teams (ERTs) to evaluate the scram and identified ancillary open items related to the scram (See Inspection Report 50-387/91-10).
The scram ERT focused primarily on the timeline, operator performance, and procedural concerns.
A second ERT reviewed the failure of the RCIC pump to trip on high level.
The inspector found the staff's root. cause investigation generally good at the system level with some weaknesses noted at the component level.
During the presentation from the scram ERT, the root cause for the loss of an off-site transmission line was attributed to impr'oper operation of a breaker relay due to foreign matter impeding relay movement.
The inspector noted that this conclusion was not strongly supported by physical evidence since subsequent relay testing showed free travel.
Nothing
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was found in the work area that could have specifically come from the breaker, and previous maintenance activities on the breaker were reviewed with no conclusive findings.
Based on the ERT's presentation to the SRC, the inspector also noted some weaknesses with the root cause identification of the initiating event at the component level.
Specifically:
Age and/or temperature related degradations had previously been identified as likely failure mechanisms for relay malfunctions.
This was not evaluated as a potential or likely cause during the ERTs discussion with SRC.
The ERT did not include a representative from the PP&L system, even though the system was responsible for the breaker failure relay in the Montour switchyard.
Much of the information provided to the ERT was from the maintenance group that was responsible for the breakers, with little or no independent review by plant staff.
The quality'of maintenance standards applied to the PP&L system components was not evaluated as a potential causal factor.
Offsite power distribution reliability problems contributed to the causes of five of the last ten Susquehanna scrams.
The Main Steam Line radiation monitor failure was attributable to a power supply failure.
Specifically, a capacitor failure internal to the power supply deenergized the rad monitor and caused the initial half scram.
The ERT identified the capacitor failure. as random, without consideration of the ambient temperature affect on capacitor lifetime.
The inspector discussed these concerns with the licensee and they agreed to address them further.
Subsequently, a management meeting was conducted on November 14 to review the licensee's analysis of the scram and other pertinent concerns that were identified in.
Inspection Report 50-387/91-10.
The results of that meeting willbe documented in a future resident inspection report; Notwithstanding the above, the inspector noted that the SRC probed many areas during the discussions with the staff.
Their questions were focused on ensuring safe operations.
Plant staff was challenged by the SRC in many areas.
Additional areas requiring followup were identified.
The Senior Vice President questioned the adequacy of the original design and the need to consider betterment modifications to improve the basic design.
The inspector found the SRC to be a probing, self-critical organization with a healthy attitude toward nuclear safety.
9.
MANAGEMENTAND EXITMEETINGS 9.1 Routine Resident Exit and Periodic Meetings The inspector periodically discussed the issues of this inspection with station management and summarized the findings 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 10 CFR 2.790 restrictions.
9.2 ate 09/27/91 MOVs 91-80 10/07/91 EDSFI F/U 91-17 10/17/91 Emergency Drill 91-19 10/31/91 Rad waste/Transportation 91-20 Inspections Conducted by Region Based Inspectors Inspection 5ggect
~Re inert N i Reporting
~ins e~ct r L. Prividy R. Mathew C. Conklin J. Noggle
TABLE 1 REVIEWED D MENT Pr~Ãurre.
AD-QA-410, Rev 13 EPM-QA-121, Rev 0 EPM-QA-209, Rev 8 NDI-QA-'3.2.1, Rev 4 NDI-QA-9.1.1, Rev 4 SRMS TP4.1 SRMS TP4.2, Rev 3 Plant Modification Program Technical Safety Assessments, Interim Procedure Change Notice Technical Specification Change Safety Evaluations Processing and Logging of Non-Modification Package Related Design Change Mechanisms Processing and Logging of Modification Packages and Associated Documents Desi n Chan e Packa es:
DCP 87-9089 DCP 87-9198 DCP 90-3009A DCP 90-3083B DCP 90-3088 DCP 90-3092 DCP 90-9001 DCP 90-9007M Safet Evaluati n:
NL-89-026 NL-89-035 NL-89-036 NL-90-017 NL-90-023 NL'-90-029 NL-90-033 NL-90-026 En ineerin han e rder
'CO 89-6113A ECO 89-6114A ECO 89-6118A ECO 90-6044 ECO 90-6069 ECO 90-6106 alculations:
F9007816 F9105174 F9105185 F9106133 Set oint Chan e Packa es:
SCP J89-1025 SCP J90-1012 SCP J90-1025 SCP 91-1046 Technical afet As e sments PLI-67638
. PLI-56043
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ABBREVIATI N LIST ATTACHMENT 1 AD ADS ANSI CAC CFR CIG CRDM CREOASS DG DX
'CCS EDR EP EPA ERT ESF ESW EWR FO FSAR HVAC ILRT ISAAC JIO LCO LER LLRT LOCA LOOP, MG MSIV NCR NDI NPE NPO NQA NRC OI PC PCIS PMR PORC QA
- Administrative Procedure
- Automatic Depressurization System
- American National Standards Institute
- Containment Atmosphere Control
- Code of Federal Regulations
- Containment Instrument Gas
- Control Rod Drive Mechanism
- Control Room Emergency Outside Air
- Diesel Generator
- Direct Expansion
- Emergency Core Cooling System
- Engineering Discrepancy Report
- Electrical Protection Assembly
-.Event Review Team
- Engineered Safety Feature
- Emergency Service Water
- Engineering Work Request
- Fuel Oil
- Final Safety Analysis Report Supply System
- Heating, Ventilation, and Air Conditioning
- Instrumentation and Control
- Justification for Interim Operation
- Limiting Condition for Operation
- Licensee Event Report
--Local Leak Rate Test
- Loss of Coolant Accident
- Motor Generator
- Non Conformance Report
- Nuclear Department In'struction
- Nuclear Plant Engineer
- Nuclear Plant Operator
- Nuclear Quality Assurance
- Nuclear Regulatory Commission
- Open Item
- Protective Clothing
- Primary Containment Isolation System
- Plant Modification Request
- Plant Operations Review Committee
- Quality Assurance
ATTACHMENT 1 (CONT.)
RCIC RG RHR RHRSW RPS RWCU SGTS SI SO SOOR SPING TS TSC WA
- Reactor Building
- Reactor Core Isolation Cooling
- Regulatory Guide
- Residual Heat Removal Service Water
- Standby Gas Treatment System
- Surveillance Procedure, Instrumment and Control
- Surveillance Procedure, Operations
- Significant Operating Occurence Report
- Sample Particulate, Iodine, and Noble Gas
- Technical Specifications
- Work Authorization