IR 05000387/1995024
| ML17158B084 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 01/23/1996 |
| From: | Pasciak W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17158B083 | List: |
| References | |
| 50-387-95-24, 50-388-95-24, NUDOCS 9601290361 | |
| Download: ML17158B084 (28) | |
Text
Inspection Report Nos.
License Nos.
Licensee:
Facility Name:
Inspection At:
Inspection Conducted:
Inspectors:
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
50-387/95-24; 50-388/95-24 NPF-14; NPF-22 Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Susquehanna Steam Electric Station Salem Township, Pennsylvania November 2, 1995 December 18, 1995 M. Banerjee, Senior Resident Inspector, SSES B. HcDermott, Resident Inspector, SSES Approved By:
ascia
,
ie Reactor Projects Branch No.
/
~2'60129036i 960i23 PDR ADOCK 05000387 G
EXECUTIVE SUMMARY Opet ations Susquehanna Inspection Reports 50-387/95-24; 50-388/95-24 November 2, 1995 - December 18, 1995 Continuing problems with the automatic level control for the reactor core isolation cooling (RCIC) system drain pot since the last refueling outage have made operators less sensitive to the alarm associated with it.
Control room operators did not take any action or question the drain pot high level alarm that occurred with the drain pot bypass valve open to provide a flow path for drainage.
The issue was discussed with Operations management and subsequently the inspector found control room operators to be sensitive to this alarm indication.
A temporary change to the alarm response procedure has been made pending correction of the level setpoint problem.
Nuclear Systems Engineering (NSE) is currently investigating potential modifications to correct the drain pot problem before the next refueling outage.
(Section 2. 1)
A residual heat removal (RHR) system alarm response (AR) procedure could have allowed opening of the RHR injection valve under a high differential pressure (dp) in excess of its design.
Licensee's procedure review process did not detect this error.
Although a similar configuration was present in core spray (CS) system, the licensee did not verify the alarm response procedure or CS valve's design margin until the inspector questioned it.
6ecause of the operational practice of using additional test procedures to control such an evolution, the error did not have any safety consequences.
Additionally, the CS injection valves had adequate design margin to be operated safely under the expected dp.
The inspector concluded that the licensee's corrective action in response to the RHR AR procedure error was less than adequate because the CS AR procedure was not reviewed until after further NRC questions.
(Section 2.2)
A procedure error resulted in unplanned ESF actuations when the RHR head spray valve closed twice during performance of the Unit 2 reactor pressure vessel ASHE Class 1 boundary system leakage pressure test.
(Section 2.4)
Maintenance/Surveillance The emergency diesel generator maintenance work was detailed enough to require a work plan.
Hence, per licensee's procedure use of a regular Work Authorization (WA), and not an investigative WA, was more appropriate.
However, the inspector noted good communication and oversight provided by the Shift Supervisor and the electrical test engineer, and did not have any safety concerns, The licensee's plan to replace the affected but repaired Agastat relays at an available opportunity is appropriate.
The inspector concluded, overall, the maintenance work was completed in an acceptable manner.
(Section 3.1.1)
Several questions were raised based on the inspector finding chart recorders connected to two operable emergency diesel generators after completion of a routine surveillance test.
The temporary test devices were not removed as
required by the surveillance procedure and one had been installed for ten days prior to its discovery by the NRC.
Although the recorders were installed under approved administrative controls, there are no written safety evaluations documenting that they do not impact operability of the diesel generators.
The installation itself resulted in open control cabinet doors which may not be consistent with the equipment's seismic qualification.
Control of temporary test equipment is considered to be weak based on the lack of formal safety evaluations and the exceptions allowed by the administrative procedure.
This item is unresolved pending the licensee's evaluation of temporary non-safety related test equipment used on safety related systems.
(Section 3.2.1)
Engineering/Technical Support The licensee's review for Generic Letter 95-07 identified that the HPCI and RCIC injection valves, that are located approximately 4 feet from the feedwater injection lines to the reactor vessel, were susceptible to thermally induced pressure locking due to their direct communication with hot feed water (387'
at 100X power).
On November 30, 1995, with Unit 1 in cold shutdown, the licensee reported that for some period of time between April 1992 (the last valve overhaul date)
and November 11, 1995, the Unit 1 HPCI injection valve's bonnet sufficiently pressurized to make the valve, and therefore the HPCI system, inoperable.
The Generic Letter recommended modification was made on the Unit 1 valves, and the licensee plans to modify the Unit 2 HPCI and RCIC injection valves during the next outage of sufficient duration.
The licensee's interim corrective action, to ensure operability by stroking the Unit 2 injection valves during power ascension was prudent.
NRC review is continuing and will be reported in the next inspection report, Plant Support Inadequate attention to radiological posting and step-off-pads resulted in a personnel contamination when a plant operator passed through contaminated HPCI/RCIC rooms without protective clothing.
A personnel contamination report (PCR)
was written and the individual was counseled.
The inspector noted that information from PCR or area contamination reports are not factored into the licensee's human performance enhancement task team data base.
The licensee is considering incorporation of this information into the system.
Safety Assessment/guality Verification The HPCI/RCIC room flooding event indicated an important lesson learned on one of the potential impacts of a shorter refueling outage.
The impact of substantial core decay heat on the hydrostatic test evolution was not anticipated and hence no action was developed to address it.
Although this procedure was effective during previous outages, it was not adequate with the additional decay heat present and appropriate heat sink not available.
The inspector noted another inadequacy in the same procedure resulted in unplanned ESF actuations (Section 2.4).
The licensee's planned and implemented corrective actions were adequate.
(Section 6. 1)
TABLE OF CONTENTS EXECUTIVE SUMMARY.
SUMMARY OF FACILITY ACTIVITIES 2.
PLANT 2.1 2.2 2.3 2.4 OPERATIONS Plant Operations Review
.
.
.
.
Alarm Response Procedural Errors NRC Notifications
.
Licensee Event Reports
1
3
3.
MAINTENANCE AND SURVEILLANCE 3. 1 Maintenance Observations 3. 1. 1 '8'mergency Diesel Generator Maintenance 3. 1.2 Maintenance Open Item Followup 3.2 Surveillance Observations
.
3.2. 1 Temporary Monitoring Equipment
5
7
10 5.
6.
7.
ENGINEERING 4.1 Pressure Locking Of HPCI and RCIC Injection Val PLANT SUPPORT
.
5. 1 Radiological and Chemistry Controls 5.2 Security 5.3 Emergency Preparedness SAFETY ASSESSMENT/EQUALITY VERIFICATION 6. 1 Followup On HPCI/RCIC Room Flooding MANAGEMENT AND EXIT MEETINGS 7. 1 Resident Exit and Periodic Meetings 7.2 Other NRC Activities ves
11
13
14
14
15
DETAILS 1.
SUHNARY OF FACILITY ACTIVITIES Susquehai.,>;
Unit 1 Summary At the start of the inspection period Unit 1 was at 100X power.
On November 10th, operators began a down power due to indications of an increasing leak of main generator hydrogen into the stator water cooling system.
The reactor was shutdown in accordance with routine procedures and cold shutdown (Condition 4)
was reached on November 11th.
After repairing the main generator and completing the forced outage maintenance work, the reactor was made critical on December 5th and the generator was synchronized to the grid on December 6th.
On December 11th PP8L concluded that errors discovered in the heat balance computer program resulted in the indicated core thermal power being 1.5 HW, less than actual.
As immediate compensatory measures, the indicated core thermal power was reduced by 2 HW,.
With the exception of minor power reductions for routine surveillance, the Unit remained at 100X power for the remainder of the report period.
Susquehanna Unit 2 Summary The Unit 2 reactor was at 100X power at the start of this report period.
On November 18th power was reduced to 80X for repair of the position indication on control rod 46-19.
During this down power, routine turbine valve testing was also completed.
The Unit 1 heat balance computer program error, reported on December 11th, also applied to Unit 2 and consequently its indicated core thermal power was reduced by 2 HW,.
On December 15th a down power to 75X was made for main turbine valve testing, condenser water box inspections, and a
control rod pattern adjustment.
The Unit was returned to 100X power on December 17th.
2.
PLANT OPERATIONS (71707, 92901, 93702)'.
Plant Operations Review The inspectors routinely observed the conduct of plant operations to independently verify that the licensee operated the plant safely, and according to station procedures and regulatory requirements.
The inspectors conducted regular tours of the various plant areas and periodically reviewed logs and records to ensure compliance with station procedures, to determine if entries were correctly made, and to verify correct communication of equipment status.
These records included various operating logs, turnover sheets, blocking permits, and bypass logs.
The inspectors observed plant housekeeping controls including control and storage of flammable material and other potential safety hazards.
Posting and control of radiation, high radiation, and contamination areas were appropriate.
The inspection procedure from NRC Hanual Chapter 2515 that the inspector used as guidance is parenthetically listed for each report sectio During the December Unit 1 startup the inspector noted that the RCIC steam line drain pot alarm high level alarm was lit despite the fact that the drain pot bypass valve was open.
The drain pot bypass valve
~054 'was manually opened at the beginning of the operating cycle after the licensee discovered that the automatic control of the drain pot level was not functioning properly and could not be adjusted.
Pending permanent corrective action, a Status Control tag was used to keep the bypass valve open so that water could not accumulate in the RCIC steam line.
When questioned by the inspector, operators did not know why the 'high level alarm had come in with the bypass valve open.
Subsequently, a nuclear plant operator (NPO)
was dispatched to the RCIC room.
Based on the NPO reporting that steam flow through the bypass line could be heard, the licensee concluded that the alarm switch had become stuck during drain pot level perturbations resulting from the startup.
The high level alarm cleared by itself later that day.
This issue will be resolved with the modification plan to correct the drain pot automatic control during the next refueling outage.
The inspector concluded that continuing problems with the automatic level control for the RCIC drain pot since the last refueling outage has made operators less sensitive to the alarms associated with it.
The inspector considered the operator's response to the alarm inadequate and discussed this issue with operations management.
Operations management stated that the operators response to the alarm (i.e, do nothing)
was not up to their expectations.
Subsequently the inspector found control room operators to be sensitive to this indication.
A temporary change to the alarm response procedure has been made pending correction of the level setpoint problem.
Nuclear Systems Engineering (NSE) is currently investigating potential modifications to correct the drain pot problem before the next refueling outage.
2.2 Alarm Response Procedural Errors On December 5,
1995, the inspector observed that indicated pressure in one residual heat removal (RHR) injection line had exceeded the 381 psig alarm setpoint and triggered an overhead annunciator.
Pressurization of the injection line by small leakage past the motor operated injection valve (F015)
and the testable check valve (F050)
was previously discussed in NRC Inspection Report 50-387/91-13.
Upon review of alarm response (AR) procedure AR-109-001,
"RHR And Core Spray Div I, IC601," the inspector noted that the procedure would allow operators to cycle the RHR throttle valve (F017)
and the F015 valve to improve seating of the normally closed F015, The inspector identified that the AR procedure would allow opening the F015 valve with a differential pressure greater than its design basis value.
This action could result in failure of the motor operated valve actuator and the disabling of one RHR low pressure coolant injection train.
Although the AR procedure allowed operators to take this action, the inspector believes that operators would not have attempted to stroke open the F015 valve, a low pressure system's injection valve, without additional support from Nuclear System Engineering (NSE).
Reasonable assurance of this is based on the inspector's observation of excellent oversight of the RHR system performance by NSE and good communication between the system engineer and
control room operators.
Further, when the F015 was stroked to improve seating during a past operating cycle, it was done under a
PORC approved test procedure and with NSE oversight.
AR-109-001 has been revised (PCAFt 1-95-1174)
and now requires contacting NSE regarding RHR line pressurization to determine if stroking the valve under a Test Procedure is appropriate.
After the licensee had corrected the RHR procedure the inspector checked the similar AR procedure for the core spray (CS) system.
Its procedure contained a
similar step, allowing operators to cycle the CS injection valve.
In response to the inspectors questions, NSE reviewed the CS injection valves and concluded the CS valves have sufficient margin to open against the expected differential pressure.
There was no safety impact due to the error in the RHR alarm response procedure since the injection valve had not been stroked using it.
However, the inspector considered the licensee's corrective action in response to the RHR procedure error less than adequate because a similar potential existed with the CS system AR and it was not checked.
The inspector concluded that the RHR AR procedural inadequacy should have been detected in the review process but this inadequacy did not have any real safety impact due to the operating practices and licensee performance relative to monitoring RHR injection line pressurization.
2.3 NRC Notifications On November 11, 1995, PP&L made a courtesy notification due to a planned shutdown to repair a stator water cooling leak in the main generator.
On November 30, 1995, the licensee reported (EN 29659) that the HPCI and RCIC injection valves were susceptible to thermally induced pressure locking.
The licensee determined that damage found in the Unit
HPCI injection valve was most likely caused by a buildup of pressure in valve bonnet that would render the valve inoperable.
Section 4. 1 of this report pertains.
On December ll, 1995, with both Units at 100X power, the licensee reported (EN 29699)
an error in the core thermal power calculation that resulted in the indicated power being
HW, less than actual power.
The error was caused by mass flow into the reactor from reactor recirculation pump seal flow and cleanup system pump purge flow, which had not been accounted for in the heat balance.
As a corrective action, the indicated thermal power was reduced to account for the error in each unit.
Similar event notifications were made by other BWRs during this period.
2.4 Licensee Event Reports (92712)
The inspectors performed an in-office review of the following Licensee Event Reports (LERs)
and found them acceptable for close out.
The conclusion to close them out was based on the report being adequate to assess the subject event, the cause appearing to have been accurately identified, the corrective actions appearing appropriate to correct both the deficient condition and the cause, and the generic applicability having been considere Unit LER No.
Title
95-014
95-012 Manual Shutdown Per Technical Specific~tion (TS)
Due To Failed Local Leak Rate Testing Manual Shutdown Per TS Due to Failed Relief Valve Acoustic Monitor Unplanned ESF Due To Momentary Loss Of RPS 'B'us Voltage During Refueling Outage After in-office review of LERs the inspectors performed on-site followup of selected reports to determine whether PP&L had taken corrective action(s)
as stated in the LERs and if responses to the events were adequate.
Unit 2 95-013-00 Unplanned ESF Due To Procedural Error On October 14, 1995, with Unit 2 in cold shutdown (Condition 4), the licensee discovered that the residual heat removal head spray valve had automatically closed during performance of the reactor pressure vessel ASHE Class 1 boundary system leakage pressure test.
The ESF actuation occurred during initial pressurization for the test on October 13th and again during repressurization for performance of the test on October 14th.
The ESF actuation was caused by a procedure writer error that mixed sections of the test for hydrostatic testing (once every 10 years) with sections for system leakage pressure testing.
The licensee reported that the Unit 1 head spray valve is thought to have closed during the Unit 1 system leakage test on April 29, 1995, due to a
similar Unit 1 test proces
. e inadequacy.
However, the valve's unexpected closure was not recognized at that time.
The Unit 1 and Unit 2 boundary system leakage test procedures have been re-reviewed and corrected.
The licensee's review of other test procedures revised to the 1989 edition of ASME Code Section XI found no similar errors.
The licensee has also committed to review the event, and its causes related to procedure preparation and review, with applicable personnel.
The inspector found the licensee's corrective actions appropriate for the procedure error, and determined that the ESF actuation had no real safety consequences.
95-001-01 Inoperable 'B'xcore Neutron Monitor On January 30, 1995, with Unit 2 at 100X power, the excore neutron flux channel 'B'onitor was declared inoperable.
NRC inspection report 50-387, 388/95-02 discussed the licensee's request and issuance of a Notice of Enforcement Discretion by the NRC.
Subsequently, an exigent TS Amendment was granted on March 1, 1995,.to allow continued operation with only one operable channel, until the first shutdown of sufficient duration or until the Unit's seventh refueling outage.
In a Safety Evaluation dated January 13, 1993 the NRC approved the BWR Owners'roup (BWROG)
NEDO Report No. 31558,
"BWR Owners'roup Licensing Topical Report Position on NRC Regulatory Guide 1.97, Revision 3, Requirements for Post-Accident Neutron Monitoring Systems",
and concluded that Category
excore neutron flux monitoring instrumentation was not needed for existing BWRs to cope with a Loss-Of-Coolant Accident, ATWS, or other accidents that do not "esult in severe core damage conditions.
The staff further indicated in its letter dated November 28, 1994, that the neutron flux monitoring system installed at SSES Units 1 and 2 exceeds the criteria of NEDO 31558 and that PP&L may take advantage of any relaxation that the new criteria might allow.
PP&L is currently revising the TS Bases and Final Safety Analysis Report for both Susquehanna Units to eliminate reference to the excore neutron monitoring system because the post accident neutron monitoring function is accomplished by the source range monitors, intermediate range monitors, the local power range monitors, and the average power range monitors.
Further, the SSES emergency operating procedures do not rely upon the excore monitoring system.
After reviewing the safety evaluation for the exigent TS amendment, the inspector concluded that the licensee's actions to remove the excore neutron monitoring system were acceptable.
3.
HAINTENANCE AND SURVEILLANCE (62703, 61726, 92902)
3.1 Haintenance Observations The inspector observed and/or reviewed selected maintenance activities to evaluate whether 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.
Haintenance observations and/or reviews included:
WA V56746 WA C53467 Replacement of Three Valve Hanifold for FIS-B21-2NOOBC, Hain Steam Flow Indication, observed on November 15, 1995 Installation of Suppression Pool Letdown Hanual Valve 157310, observed on November 15, 1995 WA P51212 WA S31572 WA P52082 Division II 24 VDC Bus Over/Under Voltage Calibration, observed on November 16, 1995 PM and Adjustment of Breaker 1B210-33, observed on November 16, 1995 Two Year Appendix 'R'mergency Light Check, observed on December 4,
1995
Based on observation of selected portions of the above maintenance, the inspector concluded that the work was conducted and completed appropriately, with due concern for plant safety and procedures.
3.1.1 'B'mergency Diesel Generator Naintenance During a monthly test run of the
EDG on November 27, 1995, the control room operators were unable to regulate the output voltage from the control room, and subsequently the diesel tripped on loss of field.
The diesel generator was declared inoperable, and control room initiated a work authorization WA S51575 to troubleshoot and correct the problem.
The work performed under the investigative WA removed the power driven potentiometer (PDP),
and reinstalled it after inspection and adjustment.
Contact points on two Agastat control relays in the PDP circuit were found to have high resistance, and were subsequently adjusted and burnished.
The licensee determined that the real cause of the loss of voltage control was the high resistance on "b" contacts of these two relays that did not allow adequate voltage at the PDP motor for voltage adjustment.
With the diesel running parallel to the grid (in a test mode) this resulted in a diesel trip.
The licensee concluded that the emergency mode of the diesel operation was not affected as the "a" contacts that are in the emergency circuit had acceptable contact resistance.
After the repair, during a subsequent diesel run a generator field ground alarm was annunciated at the local panel.
The diesel was shut down, and control room initiated WA S51576.
The ground was found on several terminals of the PDP.
The licensee concluded that the ground was introduced by the maintenance evolution and was detected during the post maintenance run.
The PDP was changed out, and subsequent diesel run indicated satisfactory performance of the diesel.
The two affected Agastat relays were changed out in June 1994 with new units.
The inspector questioned if a similar high resistance on the "a" contacts, that are in the emergency actuation circuit, could render the diesels inoperable, and what preventive maintenance program was implemented for these relays.
The licensee indicated that the emergency mode of diesel operation would not be affected with high resistance in the "a" contacts, because by the diesel operating procedure, in its standby mode the PDP is always set at 4250 VAC, the emergency mode setpoint.
Also the licensee concluded that during testing, the magnitude of the voltage was adequate to support its emergency and shutdown loads.
The licensee indicated that the current preventive maintenance program for these Agastat relays calls for periodic replacement, every five years for normally energized, and every ten years for normally deenergized ones.
However, the licensee intended to replace these two relays at the next available opportunity because of the above unsatisfactory performance.
The inspector observed part of the maintenance work and briefing of the control room operators, and reviewed the WA package, The inspector noted good communication between the maintenance organization and the control room, with the Shift Supervisor clearly articulating his expectations to the work group, The inspector noted 'that post maintenance testing requirements were not
clearly specified in the WA.
The WA required the control room operators to raise and lower the PDP settings, but did not specify any numerical values.
This value was later specified in the revised work plan.
The inspector concluded that as the work was detailed enough to require a work plan, use of a regular WA, and not an investigative WA, was more appropriate.
A regular WA requires review by Planning and Engineering.
Licensee's procedure NDAP-gA-0502, Work Authorization System, implies that correction of obvious problems are allowed under an investigative WA, but they are not intended to be performed when work instructions are necessary to control the activities.
However, the inspector noted good communication and oversight provided by the Shift Supervisor and the electrical test engineer, and did not have any safety concerns.
The inspector concluded, overall, the maintenance work was completed in an acceptable manner.
3. 1.2 Maintenance Open Item Followup (92902)
(Closed)
URI 50-387/92-20-01, Primary Containment Leakage Due To Maintenance During a 1992 maintenance activity on the Unit 1 Containment Radiation Monitor (CRM), several solenoid valves were removed from the 'B'RM panel.
The sample lines connected to the valves were left open, creating a flow path for gases in the containment to escape into the reactor building.
After approximately one week the open pathway was discovered during investigation of a high indicated oxygen level in the suppression chamber.
The open pathway allowed reactor building air to enter the H,O, analyzer sample line and resulted in the false high oxygen indication.
This open item was updated in Inspection Report 50-387/94-06.
The licensee's corrective actions were reviewed and considered adequate with one exception, The item was kept open pending the licensee's consideration or evaluation of the effects of. small continuous containment gas releases into the reactor building over an extended time period (i.e., not during post accident).
The licensee's subsequent review has concluded that for a small continuous leak of containment gases into the Reactor Building, the local area radiation monitors would alarm if an abnormal condition existed.
Health Physics. personnel were involved with the initial system breech, and dose was monitored subsequent to the breech by dosimetry.
In addition, the normal Reactor Building ventilation system directs the air to the plant exhaust and does not recirculate.
The Reactor Building post accident monitors (SPING) would therefore monitor any radioactive release.
The inspector considered the licensee's response to the remaining issue left open in Inspection Report 50-387/94-06 acceptable.
Based on this review, and the corrective actions reviewed in the open item update, this item is closed.
(Closed)
VIO 50-387;388/94-06-01, Maintenance-Failure to Follow Procedures This violation addressed four circumstances where maintenance was not performed in accordance with licensee procedures.
In response to the Notice of Violation, the licensee stated that the violation was caus d by not effectively communicating maintenance management expectations to the first
line supervisors.
This included expectations regarding presence of first line supervision in the field, the importance of effective field observations, adherence to procedure and work plan, and importance of identifying problems and correcting them.
As a result, the licensee concluded that the importance of procedure adherence was not consistently being reinforced.
As a corrective action, a briefing package was developed detailing management's expectations on work practices, and procedure adherence.
The package was reviewed by the maintenance supervisors, who in turn briefed their crew.
The expectation package was included in pre-outage briefing.
The maintenance department reviewed their self assessment process to measure the effectiveness of the first line supervision on worker performance.
This review indicated that the self assessment process was adequate.
The assessment process included numerical goals for permit and tag violations, work control errors, reworks, and ESF actuations.
These goals were followed for each production area as a focus on accountability for performance improvement.
Based on this review the licensee concluded that changes made to the permit and tag program, the status control program, and the work control process prior to the Unit 1 8th refueling outage resulted in an improved performance.
The inspector reviewed the Maintenance Performance indicator Report, a list of condition reports related to maintenance failure to follow procedures, refueling outage information booklet issued in March 1995, and a surveillance of plant maintenance performed by the Independent Safety Evaluation Services (ISES).
The inspector noted that the procedure adherence issue and management expectations for the first line supervisors were discussed in detail in the refuel outage information booklet.
Approximately a dozen 1995 condition reports were identified by the inspector that involved maintenance not following procedure or work plan.
Some of these failures resulted from human error and lack of attention to details.
The ISES surveillance of plant maintenance indicated a decline in work crew's actual use of the procedure in 1995 from the previous year.
However, there was no meaningful trend in other related attributes, e.g., following of procedure adherence level, and performing all steps.
A recently completed human performance task team report showed an improvement in work practices in that as of July, 45X of 1995 condition reports were related to human perFormance verses 25X as of December.
Work practice issues include use and following of procedures and work documents among other indicators.
The licensee attributed this success to the increased use of briefing, training and supervisory involvement to improve the workers'wareness to human performance errors.
Additional recommendations are being developed by this team to further improve human performance.
The inspector concluded the procedure compliance is an issue not yet fully resolved, however, adequate management attention is focused on the issue.
This issue is being monitored and trended by the licensee, and the corrective actions to improve human performance appear appropriat (Closed)
VIO 50-387;388/94-06-02, Failure to Write NCR to Address Generic Implication of MSIY Cable Embrittlement Due to Overheating On March 29, 1994, the licensee discovered signs of overheating on a number of electrical cables for the Unit 2 inboard main steam isolation valves (MSIVs).
Close proximity or contact of some conduits to uninsulated pipe supports resulted in overheating damage to the cables.
The inspector discovered that during the fall 1993 (7th) Unit 1 refueling outage, the licensee identified overheating damage on certain MSIV cables that were replaced.
however, no nonconformance report (NCR) was written to address the possible generic implication and potential for such damaged cables at the other unit.
Following identification of the damaged Unit 2 cables, the licensee generated an NCR to assess the subject on both units.
Separation criteria were developed based on heat transfer and steam packing leakage for heat source considerations.
Walkdown of the Unit 2 primary containment identified additional conduit/cables subject to degradation due to proximity to exposed
=
main steam line supports.
These conduit/cables were either relocated or replaced.
The walkdown also identified cable damage due to steam leak in a reactor water cleanup (RWCU) system valve.
Certain safety related inside containment valves were identified to be potentially susceptible to heat damage due to their history of steam leak.
The licensee concluded that installation of live load packing that had been highly successful in preventing packing leaks, or the large size of some these valves significantly reduce the risk of cable damage from steam leaks.
In some cases conduit/cable rework resolved the problem.
As stated in licensee's response to the NOV, training on this event with emphasis on generating nonconformance report for adequate evaluation was included in the site continuing engineering training curriculum, and was provided to the site engineers including the modification installation group.-
During the spring 1995 (8th) refueling outage the licensee conducted an inspection of the Unit 1 cables inside the drywell that could be similarly subjected to heat damage.
Cables and conduits were reworked and/or replaced as necessary.
The licensee continues to look for such cable damage during the outages, and is considering inspection of cables in the pipe tunnel area outside the containment because of higher ambient temperature in this area.
The newly implemented condition report process is being used to resolve identified issues.
The inspector concluded the licensee's response to the violation was adequate, and the new condition report process provides adequate assurance that such conditions will be reported and evaluated.
3.2 Surveillance Observations The inspector observed and/or reviewed the following surveillance tests to determine whether the following criteria, if applicable to the specific test, were met:
the test conformed to TS 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 were accurate and complete;. removal and restoration of the a;fected components we> e properly accomplished; test
) esults were appropriately communicated with regard to TS and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequency.
Surveillance observations and/or reviews included:
SO-024-001
'C'DG Monthly Operability Test, observed on November 20, 1995 GO-100-002 Attachment G,
RHR and CS Testable Check Valve Verification, observed on December 5,
1995 Based on observation of selected portions of the above surveillances, the inspector concluded that they were completed with appropriate consideration for safe plant operation and administrative control.
3.2. 1 Temporary Monitoring Equipment During a walkdown of the 'C'DG room, on November 20, 1995, the inspector noted that a chart recorder connected to the generator control cabinet for the monthly EDG surveillance had not been removed.
The door of the control cabinet had been left open to allow connection of the chart recorder leads to the EDG control circuitry.
After finding a similar chart recorder installed on the 'A'DG the same day, the inspector notified the control room.
Subsequently, the Unit Supervisor contacted Electrical Maintenance to remove the chart recorders.
Surveillance procedure S0-024-001, Monthly Emergency Diesel Testing, step 6.1.3 requires a signoff to confirm installation of a strip chart recorder (if an alternate method for timing the EDG is desired).
After completion of the EDG run, step 6. 1.26 requires a signoff to confirm removal of the strip chart recorder.
On November 20th, operators stated that the procedure step 6. 1.26 was initialed based on their notification of Electrical Maintenance to remove the recorder, not based on confirming it had been removed.
After researching the chart recorder found on the 'A'DG, the licensee discovered that it had not been removed following a surveillance on November 10, 1995.
According to the licensee, the surveillance procedure step for the 'A'DG had been signed off by operators as
"NA" after notifying Electrical Haintenance to remove the chart recorder.
Condition Report (CR)95-676 was written based on the chart recorder being installed on November 10th and not removed in accordance with the procedure.
The inspector noted that the licensee took immediate actions to remove the chart recorders and that NSE provided additional guidance to Electrical Maintenance on installation of the chart recorder leads without opening cabinet doors.
The human performance issue associated with how different operators treated the procedure signoff for removal of the chart recorder is being addressed by CR 95-676.
However, the presence of temporary monitoring equipment on the operable EDGs led the inspector to question several other aspects of the temporary monitoring equipment and its installatio Specifically, the inspector questioned what affect an open cabinet door has on the seismic qualification of an EDG and the licensee's basis for determining the temporary equipment aid not affect operability of che EDGs.
Recent industry experience with certain types of temporary data acquisition systems has identified that non-safety related test equipment can affect the signals being monitored.
Information Notice (IN) 95-13, Potential For Data Collection Equipment To Affect Protection System Performance, discusses the potential impact of these devices based on their failure modes.
The problems associated with these temporary devices were identified after their installation had affected safety related systems.
Neither the licensees'0.59 evaluation nor the vendor documentation had identified the potential problem.
PP&L is evaluating this information as part of their Industry Event Review Process.
Currently, the evaluation of temporary monitoring equipment is performed by technicians on a case by case basis and is not always required to be documented as a temporary modification.
As an exception in the Bypass Program (NDAP-gA-0484), the licensee allows "test instruments which do not affect plant equipment" to be installed for up to seven days (under a work authorization or other procedure)
without a 50.59 safety evaluation.
The
'nspector considered this a significant exclusion because the Bypass Program exception may be used for temporary monitoring equipment installed on safety related systems that are considered operable.
The inspector noted that, to date, PP&L's approach to temporary monitoring equipment has not resulted in many problems.
However, the inspector considered it inappropriate for a non-safety related test equipment to be connected to safety related systems for up to seven days with no 50.59 safety evaluation.
The administrative controls also fail to address connecting test equipment to multiple trains of safety systems at the same time.
Other requirements, beyond electrical separation, also need consideration when determining the installation of a temporary monitoring device is acceptable.
Examples where these other requirements were a factor are the seismic qualification of the EDG control cabinet with its door open, and the past event where an open relay cabinet door defeated its Halon fire protection system (Refer to Inspection Report 50-387/95-12, Section 6. 1).
Pending the licensee's safety evaluation for the temporary monitoring equipment currently used on operable systems, including the EDG chart recorders, the inspector considered this issue unresolved.
(URI 50-387,388/95-24-01)
4.
ENGINEERING (71707, 37551, 92903)
4.1 Pressure Locking Of HPCI and RCIC Injection Valves On November 10, 1995, the licensee's review for Generic Letter 95-07 identified that the HPCI and RCIC injection valves were susceptible to thermally induced pressure locking.
The subject valves are located approximately 4 feet from the feedwater injection lines to the reactor vessel and the downstream side of each valve is in direct communication with hot feedwater (387'
at IOOX power).
The licensee determined that because of the injection valves'irect contact with the feedwater, the valves could become
pressure locked by thermal expansion of water trapped in their bonnets.
Condition Reports95-646, 95-647,95-648, and 95-649, discuss that during plant startup, the increase in feedwater temperature could cause heatup and expansion of water trapped in the valves'onnets during cold shutdown stroking.
On November 30, 1995, with Unit 1 in cold shutdown the licensee reported (EN 29659) that for some period of time between April 1992 and November 11, 1995, the Unit 1 HPCI injection valve's bonnet sufficiently pressurized to make it inoperable, and therefore the HPCI system inoperable.
The licensee's conclusion was based an initial engineering assessment of damage to a pressure seal retaining ring found during disas'sembly of the valve in prepar ation for a modification to preclude pressure locking.
The last close examination of the valve was during its refurbishment in April 1992, and no damage was identified at that time.
Prior to the Unit 1 restart, the licensee completed modifications to the HPCI and RCIC injection valves that would preclude pressurization of the valves'onnets.
As an immediate corrective action to address operability of the Unit 2 injection valves, the licensee stroked both injection valves on November 30th.
Motor current traces taken during the valve strokes were within expected ranges and well below the licensee's calculated current value associated with each valves'eak link.
This test demonstrated that the valves were not pressure locked at that time and with feedwater temperature essentially constant during 100X power operation the condition would not be expected to change.
Although the licensee's C:-."ition Report identified the susceptibility of the valves to thermally induced pressure locking during plant startup, the inspector questioned the effects of other feedwater temperature transients.
For example, feedwater temperature decreases as power is reduced for routine
'aintenance.
As power is subsequently returned to 100X, the feedwater temperature will increase and potentially induce pressure locking of the valves.
Upon further evaluation, PP&L determined that the feedwater temperature increase associated with returning from power reductions to below 95X power (for any reason),
after greater than two hours, could potentially cause pressure locking of the injection valves.
Base upon this new information, the licensee amended the administrative procedure for power ascension to require NSE concurrence.
Prior to the Unit 2 down power on December 15, 1995, the engineering department developed guidance for stroking the HPCI and RCIC injection valves to prevent pressure locking.
This guidance requires stroking the HPCI valve once every 75 minutes during a power ascension (and for six hours after reaching 100X),
and requires stroking the RCIC valve once every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> during a power decension (and for two strokes after reaching 100X).
The guidance memorandum (TSM¹95-095) also emphasizes the need to maintain a nominal power ramp of 1X per hour after 80X power is achieve The inspector reviewed the guidance for stroking the HPCI and RCIC valves during 'the power ascension and operator records of valve stroking.
No problems were encountered stroking the valves during the December 16, 1995 Unit 2 power ascension from 70X while using this newly developed guidance.
The inspector concluded that the licensee's actions to ensure operability were appropriate given the recent damage discovered in Unit I HPCI F006 valve.
The licensee plans to modify the Unit 2 HPCI and RCIC injection valves during the next outage of sufficient duration.
Until that time, the guidance for stroking the injection valves will be used to ensure operability.
Additional NRC review of the licensee's evaluation of the thermally induced pressure locking will be included in the next Inspection Report.
5.
PLANT SUPPORT (71750, 71707, 92904)
5. 1 Radiological and Chemistry Controls During routine tours of both units, the inspectors observed the implementation of selected portions of PPSL's radiological controls program to ensure:
the utilization and compliance with radiological work permits (RWPs); detailed descriptions of radiological conditions; and personnel adherence to RWP requirements.
The inspectors observed adequate controls of access to various radiologically controlled areas and use of personnel monitors and frisking methods upon exit from these areas.
Posting and control of radiation areas, contaminated areas and hot spots, and labelling and control of containers holding radioactive materials were verified to be in accordance with PP8L procedures.
Health Physics (HP) technician control and monitoring of these activities was satisfactory.
Overall, the inspector observed an acceptable level of performance and implementation of the radiological controls program.
The inspector reviewed the incident involving HPCI/RCIC room flooding, and the area and personnel contamination resulting from the event.
Personnel contamination resulted when a plant operator, during his rounds in the reactor building, ignored step-off-pads (SOP)
and postings at the HPCI/RCIC rooms (elevation 645 ft) and did not contact HP personnel after crossing an SOP, designating a contaminated area, without any protective clothing.
The individual then continued on to the 818 ft elevation.
Contamination on his shoes was detected when he went through the whole body frisker at the exit of the refuel floor (elevation 818 ft).
A personnel contamination report (PCR)
was written.
The individual was counseled by HP regarding the appropriate procedure he should have followed when he found himself inside contaminated area without protective clothing.
Because of the contamination level, the licensee's procedure required review of the PCR by the individual's Section Head, which has not yet been completed after approximately three months.
The licensee is investigating the reason for the delay in processing the PCR.
The inspector considered this event an example of human performance error, and noted that information from the contamination reports are not routinely factored into the licensee's human performance enhancement program.
The licensee indicated that they were looking into this area for program enhancement.
The inspector considered the licensee's actions adequat ~
~
5.2 Security
PP&'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.
These inspection activities were conducted in accordance with NRC inspection procedure 71707.'he inspector reviewed access and egress controls throughout the period.
No significant observations were made.
5.3 Emergency Preparedness On November 28, 1995, the inspector observed training conducted for the licensee's emergency operations facility (EOF) responders.
The training session was held at PP&L's East Mountain Business center near Wilkes Barre, Pennsylvania.
Position specific and group interaction issues were addressed.
Through use of an emergency scenario that unfolded over the day, the emergency preparedness staff illustrated their lessons and brought out areas for improvement.
The inspector considered the training for EOF responders to be well conducted and appropriately focused on timely determination of protective action recommendations.
6.
SAFETY ASSESSMENT/OUALITY VERIFICATION (90700, 90712)
6.1 Followup On HPCI/RCIC Room Flooding The Unit 2 HPCI and RCIC rooms were found to have approximately one inch of water on October 14, 1995.
At the time of the occurrence, drain down of the reactor vessel after a hydrostatic leak test was in progress, and the reactor was in a cold shutdown condition.
'Under such condition, the plant technical specification allowed the reactor temperature to be increased to 212 degrees F
while conducting the hydrostatic testing provided secondary containment integrity, isolation actuation instrumentation, automatic isolation dampers, and the standby gas system are operable.
The root cause analysis team determined that depressurization resulted in a flowrate that pressurized the main steam line drains and forced wate" to backflow down the HPCI and RCIC steam line drains into the rooms.
With the HPCI/RCIC room floor drain lines to the liquid radwaste isolated, this resulted in room flooding.
The team noted that the operators were within the procedure allowed flow rates, and the valving configuration was also as allowed by the procedure.
The same procedure used during the previous hydrostatic tests did not cause the same problem.
As corrective action, the hydrostatic test procedure was to be revised to close certain valves in the HPCI and RCIC systems to prevent steam line drain to bypass through the HPCI and RCIC drain lines.
The other pressure test procedures were to be reviewed for similar considerations while draining, filling or venting systems.
The inspector reviewed the root cause analysis and had discussions with engineers involved with the root cause analysis.
A causal factors chart indicated that higher flowrate was required during depressurizati'on due to concerns that the coolant temperature could exceed the TS limit because of substantial decay heat at the end of the shorter refueling outage and
unavailability of the RBCCW to the RWCU system to act as a heat sink.
The inspector noted that this aspect was not further addressed in the analysis, and no corrective actions were developed for it.
Upon inspector's question the licensee indicated that their outage critique process is currently looking at the need to start such hydrostatic test at a lower temperature and assess availability of adequate heat sink prior to starting the test.
The licensee planned to implement the necessary corrective actions prior to the next refueling outage when such testing is performed.
The inspector concluded that the event indicated an important lessons learned on one of the potential impacts of a shorter outage.
The impact of substantial core decay heat to the hydrostatic test evolution was not anticipated and hence no action was developed to address it.
This resulted in a procedure that was not adequate for the situation.
The licensee's planned and implemented corrective actions are adequate.
7.
MANAGEMENT AND EXIT MEETINGS (71707)
7. 1 Resident Exit and Periodic Meetings The inspector discussed the findings of this inspection with PPSL station management throughout the inspection period to ensure timely communication of emerging concerns.
At the conclusion of the reporting period, the resident inspection staff conducted an exit meeting summarizing the preliminary findings of this inspection.
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.
7.2 Other NRC Activities An Engineering Core Inspection (35771)
was conducted Oecember 11-15, 1995 and will be covered in the next Inspection Repor,