IR 05000400/1998010
| ML18016A784 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 01/15/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18016A783 | List: |
| References | |
| 50-400-98-10, NUDOCS 9901260246 | |
| Download: ML18016A784 (39) | |
Text
U. S. NUCLEAR REGULATORYCOMMISSION
REGION II
Docket No:
License No:
50-400 NPF-63 Report No:
50-400/98-10 Licensee:
Carolina Power & Light (CP8L)
Facility:
Shearon Harris Nuclear Power Plant, Unit 1 Location:
5413 Shearon Harris Road New Hill, NC 27562 Dates:
November 8 - December 19, 1998 Inspectors:.
Approved by:
J. Brady, Senior Resident Inspector R. Hagar, Resident Inspector J. Blake, Senior Project Manager (Section M1.2, E1.2)
B. Bonser, Chief Reactor Projects Branch 4 Division of Reactor Projects 990i2b024b 990ii5 PDR ADOCK 05000400
PDR Enclosure
EXECUTIVE SUMMARY Shearon Harris Nuclear Power Plant, Unit 1 NRC Inspection Report 50-400/98-10 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support.
The report covers a 6-week period of resident inspection; in addition, it includes the results of an announced inspection by a regional senior project manager.
~Qerationa
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During the period, the conduct of operations was professional and safety-conscious (Section 01.1).
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Reactor startup and power ascension was accomplished in accordance with applicable procedures.
The synchronization to the grid was the best performed at the site in the past three years, and could be termed a smooth synchronization.
This was a significant improvement from past synchronizations, all of which had resulted in plant transients (Section 01.2).
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The licensee briefly disabled all indications of reactor vessel level during an unsuccessful attempt to vacuum-fill the reactor coolant system.
Management oversight and control of the corrective action program was not adequate to ensure that the event was properly characterized and dispositioned (Section 01.3).
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Licensee management appropriately focused on resolving a previously identified adverse trend related to clearances that continued during this period. A Nuclear Assessment
.Section special assessment on clearances was effective in focusing management attention on the clearance problems, and in helping to define which aspects of the clearance process were causing problems.
The event investigation related to an unexpected reactor vessel water level increase while in mid-loop with no fuel in the reactor vessel was not well-handled (Section 02.1) ~
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The equipment in the reactor coolant system was found to be aligned and operating in accordance with procedures and as described in the Final Safety Analysis Report (FSAR)
(Section 02.2).
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The licensee's plans for and activities associated with reduced-inventory operations were consistent with their commitments arising from Generic Letter 88-17 "Loss of Decay Heat Removal" (Section 03.1)
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Operator performance during the period was mixed. Several examples of operator inattention resulted in unexpected equipment responses (Section 04.1).
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Effective simulator training helped operators achieve a well-coordinated reactor staitup and a smooth synchronization while synchronizing to the grid (Section 05.1).
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In general, self-assessment activities were being performed as required, and the appropriate management focus was being placed on self-assessment findings. A Post-trip/
Safeguards Actuation Report review by the Plant Nuclear Safety Committee (PNSC) lacked sufficient questioning to address the post-trip cooldown.
Prior to the PNSC meeting, the Nuclear Assessment Section review of the report did not provide substantive comments.
Management involvement in the corrective action program for several events was insufficient to properly classify the events.
The result was that adequate resources for investigation and root cause determination were not appropriately assigned (Section 07.1).
Maintenance
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Maintenance activities were conducted in accordance with applicable procedures (Section M1.1).
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The licensee's steam generator inspections were conducted in a conservative manner (Section M1.2).
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The surveillance performances were generally conducted in accordance with applicable procedures.
One example, related to containment closeout, indicated a lack of attention to detail (Section M2.1).
~En ineerin
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Engineering was appropriately involved in the emergency service water piping inspection results and pump performance issues.
Resolution activities were being conducted in accordance with required procedures (Section E1.1) ~
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Steam generator replacement project activities appeared to be progressing in a well-controlled manner.
Current staff for the project appeared to provide a significant experience data base (Section E1.2).
The control of contamination and dose for the site was good and was attributable to good teamwork between the various departments.
Some temporary shielding was being used as permanent shielding, indicating a lack of management focus on the administrative aspects of the temporary shielding program.
However, the shielding was providing an appropriate ALARAfunction. This issue was identified as a minor violation. (Section R1.1).
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The performance of security and safeguards activities was in accordance with applicable procedures and the Security Plan.
For the refueling outage, access and search activities were handled well (Section S1.1).
The fire brigade adequately responded to a fire that occurred November 25 on the 261-foot elevation of the auxiliary building in the motor for air handling unit AH-21, a non-safety related air handler.
A minor violation was identified for failure to initiate a condition report for the fire (Section F4.1).
Re ort Details Summa of Plant Status Unit 1 began this inspection period in refueling outage number eight.
Fuel reload was completed by November 15, and the unit began heatup on November 24. The reactor startup was accomplished on November 27, and the unit was synchronized to the grid on November 28. The power ascension test program was completed and the unit achieved 100 percent power on December 3.
I. 0 erations
Conduct of Operations 01.1 General Comments a.
Ins ection Sco e 71707 The inspectors conducted frequent reviews of ongoing plant operations including control room tours, shift turnovers, and observation of operations surveillance activities.
b.
Observations and Findin s In general, the conduct of operations was professional and safety-conscious.
Operators maintained a questioning attitude in relation to unexpected equipment responses, and did not hesitate to stop the startup to address equipment problems.
Refueling activities were performed in accordance with fuel handling procedure FHP-20, "Refueling Operations," Revision 18. Mode changes were made in compliance with the minimum equipment required by the Technical Specifications (TS), and were accomplished in accordance with the general procedures listed below:
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GP-001, "Reactor Coolant System FilI and Vent (Mode 5)," Revision 14;
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GP-002, "Normal Plant Heatup from Cold Solid to Hot Subcritical," Revision 16;
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GP-004, "Reactor Startup (Mode 3 to 2)," Revision 19; and
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GP-005, "Power Operation (Mode 2-1)," Revision 22 Several examples of operator inattentiveness are described in section 04.1. The inspectors observed that control room staffing met TS requirements.
c.
Conclusions During the period, the conduct of operations was professional and safety-consciou.2 Plant Startu From Refuelin Outa e 8 a.
Ins ection Sco e 71707 The inspectors observed the licensee's startup from the refueling outage to determine whether procedures were followed and TS requirements were met.
b.
Observations and Findin s The inspectors observed that the licensee brought the reactor to criticality using section 7.1.2, "Rod Pull to Criticality,"of procedure EST-923, "Initial.Criticality and Low Power Physics Testing," Revision 5. Although this section was being used for the first time (previous startups had involved approaching criticalityvia dilution of the reactor coolant),
the inspectors observed that this evolution was completed in accordance with the subject procedure and applicable policies, and identified no related concerns or deficiencies.
Synchronization to the grid was accomplished by a new smooth synchronization method that had been developed in response to inspectors comments in NRC Inspection Reports (IR) 50-400/97-09 and 50-400/98-08.
On the simulator. the procedure had not been completely successful in achieving a smooth transfer of steam demand from the steam dumps to the main turbine during synchronization to the grid. The inspectors observed that the procedure was successful during the plant synchronization at 11:45 p.m. on November 28. During the evolution, reactor coolant system (RCS) average temperature remained almost constant and steam dump demand reduced from 15 percent to 1 percent after the synchronization, with the steam dumps closing as temperature reduced only slightly. Steam generator levels were relatively stable.
However, the inspectors observed that the 'B'eed regulating bypass valve was cycling steam generator level more than the 'A'nd 'C'team generator levels were cycling.
This indicated a need to evaluate the tuning of the 'B'alve controller. The inspectors observed that the licensee did not accomplish any tuning. The synchronization was the best performed at the plant in the previous three years and did not induce a plant transient.
Power ascension testing was performed in accordance with procedure PLP-626, "Power Ascension Testing Program after a Refueling Outage," Revision 13. (Specific tests observed by the inspectors are listed in section M2.1.)
Conclusions Reactor startup and power ascension was accomplished in accordance with applicable procedures.
The synchronization to the grid was the best performed at the site in the past three years, and could be termed a smooth synchronization.
This was a significant improvement from past synchronizations, all of which had resulted in plant transient Loss of Valid Reactor Vessel Level Indication Durin Reduced-Invento 0 erations Ins ection Sco e 71707 92901 The inspectors observed control-room operations that were being conducted in accordance with procedure GP-001, "Reactor Coolant System Fill and Vent - Mode 5,"
Revision 14, in an attempt to vacuum-fill the RCS. After that attempt was unsuccessful, the inspectors inspected the licensee's response to that evolution.
Observations and Findin s The inspectors noted that operators were attempting to fillthe RCS using Section 5.3,
"Vacuum Fill and Vent" of GP-001.
The operators informed the inspectors that section 5.3 was being used for the first time, following reconfiguring the RCS to include a vacuum skid that had been designed and installed, as described in Engineering Service Request (ESR) 94-00099, "RCS Vacuum Fill," Revision 10. As the operators proceeded, the inspectors observed that the plant did not respond as described in the procedure:
when the operators opened valves which admitted service air into a venturi in an attempt to draw a vacuum in a portion of the RCS, the inspectors and the operators observed that all indications of reactor vessel level immediately increased from their previous steady-state value of approximately -80 inches (that is, 80 inches below the reactor vessel flange) to approximately -40 inches.
When the service air valves were closed a few seconds later, the inspectors and the operators observed that the level indications returned to their previous values.
Meanwhile, no change in RCS
= pressure was discerned.
The inspectors observed that the control-room staff made a second attempt to complete section 5.3. This attempt was similarly unsuccessful.
Staff members began developing informal plans for implementing an alternate method for achieving the vacuum fill. When the inspectors questioned their activities, the inspectors observed that the senior manager present directed the operators to discontinue their efforts to complete section 5.3, restore the conditions that existed prior to those efforts, and then initiate normal fill-and-vent activities in accordance with section 5.2 of GP-001.
Subsequently, operations personnel successfully completed RCS fill-and-vent in accordance with that'section.
The inspectors noted that flow rates and temperatures in the residual heat removal system remained stable throughout this evolution, and therefore concluded that during this evolution, actual reactor vessel level did not change appreciably,'nd decay-heat-removal capability was not impaired.
The inspectors observed that engineering personnel initiated Condition Report (CR) 98-03025 to document the event. They classified the event as an "Adverse Condition," and completed an "Adverse Condition Evaluation" on December 3. The inspectors reviewed this Adverse Condition Evaluation, and identified to the licensee several related concerns.
Among those concerns were the following:
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CR 98-03025 characterized the adverse condition only as unsuccessful performance of the fill-and-vent instructions in GP-001; neither that characterization nor the associated Adverse Condition Evaluation mentioned the loss of valid level indication.
The inspectors noted that while the RCS was in the reduced-inventory configuration,
the time to begin boiling in the reactor core following a loss of decay-heat-removal capability had been calculated to be approximately 28 minutes, and therefore considered any loss of valid reactor vessel level indication with the RCS in this configuration to be risk-significant. The inspectors thus considered CR 98-03025 to be either inappropriately or incompletely characterized.
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ESR 94-00099, through Revision 10, did not describe any testing to verify the adequacy of the design of the reactor coolant system with the vacuum skid attached.
This appeared to be contrary to the requirements of procedure EGR-NGGC-005,
"Engineering Service Requests," Revision 5.
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According to licensee personnel and CR 98-03025, Revision 14 of GP-001 does not include instructions for venting the reactor vessel head during vessel level drain down that had been included in earlier revisions. The inspectors found that at least two licensee personnel were aware of this apparent deficiency before the fill-and-vent evolution began.
Both participated in an unsuccessful attempt to correct the procedure before the evolution began, but neither initiated a condition report, and neither informed his management.
In those circumstances, failure to initiate a condition report appeared to be contrary to the requirements of procedure CAP-NGGC-001, "Corrective Action Management," Revision 1.
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The only corrective action described in CR 98-03025 was to revise GP-001 to ensure that the reactor vessel head was vented while draining down the vessel level, but the CR did not adequately explain why that corrective action was both necessary and sufficient to fullyaddress the cause(s) of the subject event.
The inspectors observed that a week after CR 98-03025 had been dispositioned and closed, licensee management was not aware of that fact. The inspectors considered that the manner in which this event was entered into and dispositioned within the corrective action program indicates that management oversight and control of that program was not adequate to ensure that:
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the event was properly characterized and classified,
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the subsequent investigation was properly focused and effectively completed, and
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the resulting corrective actions were both necessary and sufficient to address the cause(s) and contributing factor(s) for this event.
In response to the inspectors concerns the licensee initiated a Significant Adverse Condition Evaluation of this CR in accordance with procedure AP-605, "Condition Report Investigations," Revision 17.
Pending the licensee's completion of the Significant Adverse Condition Evaluation, the inspectors'eview of the evaluation, and the subsequent completion'f the inspectors'ssessment of the safety and risk significance of this event, this issue has been designated as Unresolved Item (URI) 50-400/98-10-01, loss of valid reactor vessel level
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indication during reduced-inventory operation C.
Conclusions The licensee briefly disabled all indications of reactor vessel level during an unsuccessful attempt to vacuum-fill the RCS. Management oversight and control of the corrective action program was not adequate to ensure that the event was properly characterized and dispositioned.
Operational Status of Facilities and Equipment 02.1 General Comments a.
Ins ection Sco e 71707 The inspectors conducted frequent tours of the facilityto verify equipment condition, housekeeping, and proper use of clearances.
Observations and Findin s The licensee had identified an adverse trend in clearances (CR 98-02439), as discussed in section 07.2 of NRC IR 50-400/98-09.
The inspectors noted that during the outage, the licensee identified several other clearance problems.
Condition Report 98-02850 identified an inadvertent fillof the reactor vessel while in a mid-loop configuration with no fuel in the reactor vessel on November 9 (approximately 40" increase).
The inspectors learned from the licensee that a clearance restoration problem contributed to the event.
The inspectors also learned that control room operators had not identified clearing of the vessel low level alarm until 45 minutes after the level increase began.
In reviewing the licensee's investigation of this issue, the inspectors found that some aspects of the investigation process were not well-handled.
For example, seven days after the vessel level increase event the licensee's investigation team still did not have all the written statements from the operators involved.
The inspectors found that none of the clearance problems resulted in TS violations or inoperable equipment.
However, they did indicate a lack of control of plant configuration by the plant operations staff, which the inspectors observed was of considerable concern to licensee management.
The inspectors observed a management meeting on November 10 and a Plant Nuclear Safety Committee Meeting on November 20, to discuss the additional clearance problems during the outage.
The inspectors found that licensee management was appropriately focused on resolving the clearance issue(s).
However, the adverse trend previously documented by operations management in the corrective action program in October had not resulted in actions that.had stopped the trend. The inspectors'observed that the Nuclear Assessment Section (NAS) had performed a special assessment on clearances to help management assess what aspects of the clearance program were causing the problem. The inspectors found that the NAS assessment was effective in performing that functio c.
Conclusions Licensee management appropriately focused on resolving a previously identified adverse trend related to clearances that continued during this period. A NAS special assessment on clearances was effective in focusing management attention on the clearance problems, and in helping to define which aspects of the clearance process were causing problems.
The event investigation related to an unexpected reactor vessel water level increase while in mid-loop with no fuel in the reactor vessel was not well-handled.
02.2 En ineered Safe Feature S stem Walkdowns The inspectors walked down accessible portions of the RCS.
Equipment operability, material condition, and housekeeping were acceptable in all cases.
Several minor discrepancies were brought to the licensee's attention and were corrected.
The equipment in the RCS was found to be aligned and operating in accordance with procedures and as described in the FSAR.
Operations Procedures and Documentation 03.1 Licensee Readiness for Reduced-Invento 0 erations a.
Ins ection Sco e 71707 The inspectors examined the licensee's readiness to conduct activities with the RCS in a reduced-inventory condition, by inspecting the status of the licensee's commitments arising from Generic Letter 88-17, "Loss of Decay-Heat Removal," as described in
. licensee letter HNP-97-109.
b.
Observations and Findin s The inspectors found that most of the licensee's commitments arising from the subject Generic Letter had been incorporated into the following procedures:
AOP-020, GP-001, GP-008, MST-I0322, 0MP-001, OMP-003, OMP-004, OST-1091, OST-1034,
"Loss of RCS Inventory or Residual Heat Removal While Shutdown,"
Revision 17
"Reactor Coolant System Fill and Vent Mode 5," Revision 14.
"Draining the Reactor Coolant System," Revision 16
"Reactor Vessel Level Monitoring System Transmitter Calibration," Revision
"Outage Scheduling," Revision 2
"Outage Shutdown Risk Management," Revision 9
"Control of Plant Activities During Reduced Inventory Conditions," Revision
"Containment Closure Test, Weekly Interval During Core Alterations and Movement of Irradiated Fuel Inside Containment," Revision 8
"Containment Penetrations Test, Weekly Interval During Core Alterations and Movement of Irradiated Fuel Inside Containment," Revision 8
The inspectors found,that all of the licensee's commitments had been either incorporated satisfactorily into one of the above procedures, had already been completed prior to reducing RCS inventory, or incorporated into the schedule of activities associated with reduced-inventory operations, as appropriate.
C.
Conclusions The licensee's plans for and activities associated with reduced-inventory operations were consistent with their commitments arising from Generic Letter 88-17, "Loss of Decay Heat Removal."
Operator Knowledge and Performance 04.1 General Comments Ins ection Sco e 71707 The inspectors observed and reviewed the performance of licensed and non-licensed operators.
b.
Observations and Findin s The inspectors observed during a tour of the steam tunnel on November 30 that the B steam generator power operated relief valve (PORV) was leaking with the plant at about 50 percent power. The inspectors communicated this observation to the Shift Superintendent - Operations.
Operators had not identified this problem and on December 3, the inspectors noted that a deficiency tag had not been placed on the main control board although the valve was still leaking. After discussing this with licensee management, the inspectors observed on December 8 that the PORV problem had.
been corrected and the valve was shut. The problem was attributed to an incorrect controller card setting (reset under WR/JO 98-AIJZ1). The inspectors found that operators were not fullyaware of this plant condition and did not take prompt action to resolve this problem until off-shift operations management got involved.
During the inspection period, the inspectors noted several other examples of operator inattention.. One example was the failure to identify that the RCS standpipe low-level alarm had cleared during the restoration of a clearance, as discussed in section 02.1.
Another example was the many clearance problems identified by the licensee. during the outage.
These pertained to the preparation, releas'e, and restoration of clearances by operators, as discussed in Section 02.1. A third example involved, an evolution for reducing level in the C cold-leg accumulator, where the wrong accumulator was drained.
Yet another example was in relation to performance of the containment closeout surveillance discussed in Section M2.1.
Collectively these examples represent a negative spike in operator performance.
In the NRC letter to the licensee, dated February 24, 1998, transmitting the Systematic Assessment of Licensee Performance report 50-400/98-99, the NRC noted the cyclic nature of operator performance over the previous four years.
The inspectors were
nature of operator performance over the previous four years.
The inspectors were concerned that the above four items represented the start of a negative performance trend similar to those noted during the previous two SALP assessment periods. The inspectors observed that the operations manager discussed this performance as a trend at a turnover meeting with operators and concluded that operations management was appropriately sensitive to performance trends.
However, the inspectors also noted that an adverse trend on clearances was documented by operations management in the corrective action program in October, but operations management had yet to be successful in turning the trend.
(For a related discussion, see Section 02.1).
c.
Conclusions Operator performance during the period was mixed. Several examples of operator inattention resulted in unexpected equipment responses.
Operator Training and Qualification 05.1 General Comments a.
Ins ection Sco e 71707 The inspectors observed simulator training for licensed operators.
b.
Observations and Findin s The inspectors observed that the startup training helped to develop good teamwork between reactor engineering and the operators on the new pull-to-criticalityprocedure.
This training produced positive results during the actual plant startup after the refueling outage.
In addition, the training allowed the operators to practice the synchronizing-to-the-grid procedure, which had been recently revised.
The synchronization training indicated that the limits in the procedure were borderline to achieving a smooth synchronization transfer on the simulator. The training allowed the operators to practice their skills and generate a teamwork approach to the synchronization.
As discussed in section 01.2, the training produced positive results in that a'smooth synchronization to the grid was achieved during the startup after the refueling outage.
C.
Conclusions Effective simulator training helped operators achieve a well-coordinated reactor startup and a smooth synchronization while synchronizing to the gri Quality Assurance ln Operations 07.1 General Comments ao Ihs ection Sco e 40500 71707 During the inspection period, the inspectors reviewed multiple licensee quality assurance activities, including:
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Condition Reports;
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Plant Nuclear Safety Committee (PNSC) meetings on November 16, 19, 20, and 25;
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Management review of the adverse trend involving clearances b.
Observations and Findin s The inspectors, observed that PNSC quorum requirements were met and for most issues the PNSC was thorough and asked probing questions.
The PNSC was appropriately sensitive to the clearance issues discussed in section 02.1, and to mid-loop operation of the RCS.
In relation to the Post-trip/Safeguards Actuation Report for the October 23 reactor trip, the inspectors found that the PNSC did not question the post-trip cooldown, which the inspectors concluded was not adequately explained.
The report presented to the PNSC on November 20 explained that the post-trip cooldown had resulted in a letdown isolation, and was caused by the steam dumps closing relatively late (at 544'F) due to reactor coolant cold leg temperature (Tcold) starting out relatively low. The inspectors
. determined that the steam dumps should not have closed late, because the steam dump controller should not have been affected by Tcold. (The steam-dump signal is set to close at 553 F). The inspectors found that the conclusions in the safeguards actuation report suggested a potential problem with the steam dump operation.
However, the report did not identify a problem with the steam dumps, and no corrective action was planned.
The inspectors observed that the PNSC did not question this conclusion until after the inspectors asked questions about the cooldown, and suggested that it indicated a problem with the steam dumps. The conclusion was later changed by the operations staff to say that the steam dumps did not close late, and that they were not a contributor to the cooldown.
The inspectors observed that the Nuclear Assessment Section (NAS) organization had not provided any substantive comments during the PNSC meeting.
The inspectors discussed this observation with the NAS manager, and determined that although NAS personnel reviewed the report, the level of review did not provide any substantive comments at the PNSC meeting in relation to the data analysis for the post-trip review.
The inspectors found that NAS was adequately staffed for that function, in that the NAS staff included two operations assessors with current or prior senior reactor operator license The inspectors concluded that, for the RCS vacuum-fill issue discussed in Section 01.3
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and the AirHandler (AH) 21 fire discussed in section F4.1, upper level management was not adequately engaged in the corrective action process.
The basis for this finding was that the problems discussed in Section 01.3 were not categorized in the corrective action process as significant, even though the evolution was risk-significant, as described in Section 01.3.
In addition, when the inspectors discussed their findings with upper-level licensee managers, those managers were unaware that the condition report written on this issue had been closed.
In the case of AH-21, management was unaware that a condition report had not been written.
C.
Conclusions In general, self-assessment activities were being performed as required, and the appropriate management focus was being placed on self-assessment findings. A Post-trip/Safeguards Actuation Report review by the PNSC lacked sufficient questioning to address the post-trip cooldown.
Prior to the PNSC meeting, the NAS review of the report did not provide substantive comments.
Management involvement in the
"
corrective action program for several events was insufficient to properly classify the events.
The result was that adequate resources for investigation and root cause determination were not appropriately assigned.
08 Miscellaneous Operations Issues (92700, 92901)
OPEN LER 50-400/98-007-00:
Turbine control anomaly causes a manual reactor trip.
On October 23 while the licensee was conducting a controlled shutdown of the unit, all four of the main turbine governor valves unexpectedly went full open. At the time, the unit was operating at approximately 85 percent power. The resulting transient caused a rapid reduction in the RCS temperature and a corresponding increase in reactor power.
The transient was terminated when the licensee manually tripped both the reactor and the main turbine. (The circumstances surrounding this reactor trip were discussed in Section 01;2 of NRC IR 50-400/98-09.)
During this inspection period, the licensee completed a detailed review of the circumstances associated with the trip, in accordance with procedure OMM-004, "Post-trip/Safeguards Actuation Review," Revision 10. The inspectors noted that OMM-004 requires preparation of a "Post-trip/Safeguards Actuation Report" (PTSAR), and observed that on November 20, the Plant Nuclear Safety Committee (PNSC) reviewed and approved the "DATACOLLECTION"and "INVESTIGATION"sections of that report (Sections 1 and 2, respectively).
Following PNSC approval of Sections 1 and 2 of the PTSAR, and in response to
'uestions raised by the inspectors (as discussed in Section 07.1 of this report), the licensee conducted further investigations into the transient which followed the reactor trip. The results of those investigations were presented to and approved by the PNSC on November 25, and as directed by the PNSC, were attached to the PTSAR as an addendum.
The inspectors observed that those results indicated that "the response of the RCS during the October 23, 1998 trip was normal and neither operator response nor equipment malfunction subsequent to the trip contributed significantly to the decrease in
e
RCS temperature [that occurred following the trip]." Pending the licensee's completion and inspectors'eview of the "Followup Report" required by procedure OMM-004, this LER will remain open.
II. Maintenance M1 Conduct of Maintenance M1.1 General Comments 62707 The inspectors observed all or portions of the following work activities:
CM-M0300
"Spent Fuel Cask Handling," Revision 28 CM-M0239
"Reactor Coolant Pump Motor Uncoupling (Backseating) and Coupling,"
Revision 0 CM-M0059
"Feedwater Isolation Valve Operator Disassembly and Maintenance, Pilot Check Valve Shim Replacement and Fill/Bleed," Revision 18 The inspectors found the work performed under these activities to be professional and thorough.
Allwork observed was performed with the work package present and in active use.
Technicians were experienced and knowledgeable of their assigned tasks.
The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality control personnel were present whenever required by procedure.
Peer-checking and self checking techniques were being used.
When applicable, appropriate radiation control measures were in place.
Maintenance activities were conducted in accordance with applicable procedures.
M1.2 Steam Generator SG Ins ections a.
Ins ection Sco e
IP 50002 The inspectors reviewed, the results of the refueling-outage SG inspections.
b.
Observations and Findin s The inspectors reviewed the licensee's SG program inspection procedures, and reviewed the results of the eddy current examinations conducted during refueling outage 8 (RFO-8).
The inspectors also reviewed the video tapes of visual inspections of the SG secondary side internals.
The internal damage noted during these visual inspections included indications of flow-assisted corrosion in the downcomer sections of the steam dryers.
The inspectors reviewed the final documentation for the licensee's engineering service request, ESR 98-00499, which included the safety evaluation and operability analyses for continued operation of the SGs until replacement in RFO-10. The inspectors agreed with the safety and operability assessments provide c.
Conclusions The licensee's steam generator inspections were conducted in a conservative manner.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Surveillance Observation a.
Ins ection Sco e 61726 The inspectors observed all or portions of the surveillance tests accomplished in accordance with the following procedures:
OST-1011 OST-1506 OST-1507 OST-1081 OST 1046 OST 1808 OST-1824 OST-1835 EST-724 EPT-813 EST-923
"AuxiliaryFeedwater Pump 1A-SA Operability Test Monthly Interval,"
Revision 8
"Reactor Coolant System Isolation Valve Leak Test 18 Month Interval,"
Revision 7
"RHR Loop Isolation Valve Leak Test 18 Month Interval Modes 4,5,"
Revision 7
"Containment Visual Inspection When Containment Integrity Is Required,"
Revision 7
"Main Steam Isolation Valve Operability Test Quarterly Interval," Revision
"Main Steam Isolation: ESF Response Time 18 Month Interval Modes 3-5," Revision 7
"1 B-SB Emergency Diesel Generator Operability Test 18 Month Interval,"
Revision 15
"MSIVRemote Shutdown with MSIVand Bypass Isolation Remove Position Indication Test 18 Month Interval Mode 3 to 5," Revision 5
"Shutdown and Control Rod Drop Test Using Computer," Revision 7
"Control Rod Drive Mechanism Timing Test Using Computer,". Revision 4
"InitialCriticalityand Low Power, Physics Testing," Revision 5 b.
Observations and Findin s The inspectors observed that the operators and technicians had copies of the-procedures in the field and were practicing appropriate place-keeping techniques to ensure that steps were not missed and were performed in the proper order. The inspectors found that the testing was adequately performed and that the TS surveillance requirements were satisfied.
The inspectors performed an independent containment walkdown on November 25 to verify the adequacy of the licensee's performance of procedure OST-1081, which had
'een accomplished on November 24. The inspectors found many items that the licensee had missed, including a sanding wheel, a spirit level, a four-foot length of 3/4" pipe, an 18-inch pry bar, a heat gun, a 50-foot drop cord, a safety belt, and a number of other small items including small pieces of tape, some old rubber gloves, small mechanical devices such as grease fittings, nuts, wire, bolts, washers, etc.'he
inspectors estimated that if laid out, the items found would cover approximately three square feet. The heat gun, drop cord, and safety belt were found together behind a vertical cable tray on the 261-foot containment elevation. The licensee determined that safety'belts of the type found had not been used at the site since 1995, indicating that these items had been there since that time. The licensee initiated CR 98-03140 to document these findings, and determined that an operability and reportability concern did not exist. The inspectors found that this determination was valid, and that surveillance requirement 4.5.2.c.1 was satisfied. The inspectors found the general condition of containment was acceptable, and that emergency core cooling system sump operability would not have been challenged from loose items in containment.
c.
Conclusions The surveillance performances were generally conducted in accordance with applicable procedures.
One example, related to containment closeout, indicated a lack of attention to detail.
MS Miscellaneous Maintenance Issues (92902)
M8.1 OPEN VIO 50-400/98-01-01:
Example 2; inadequate work instructions for rod control system.
In Section M1.2 of NRC IR 50-400/98-01, the report indicated that the cause of this example was "inadequate initial troubleshooting,"
Recent experience prompted the licensee to supplement these corrective actions, as described below:
~
In Section E.4 of NRC IR 50-400/98-08, the inspectors discussed the role of MMM-027 in the troubleshooting efforts associated with the trip of a heater drain pump, and concluded that Revision 10 of MMM-027"did not include adequate guidance for planning and conducting troubleshooting activities to ensure a systematic and analytical approach to troubleshooting was used."
~
In the Adverse Condition Evaluation associated with CR 98-02318 (associated with the heater drain pump trip), the licensee stated that "MMM-027[was] not suitable for complex problem solving evaluation."
The inspectors noted that in response to these findings, the licensee took the corrective actions described below':
~
The licensee developed and on October 23 issued a procedure (AP-925, "Event Evaluation," Revision 0) that addressed logistics and expectations for performing a formal event evaluation.
~
On October 14, the licensee completed a training course on situation appraisal and problem analysi ~
The licensee initiated action to integrate AP-925 into the procedure hierarchy, by revising procedures MMM-027and OMM-004, "Post-trip/Safeguards Actuation Review," Revision 10, to refer personnel from those procedures to AP-925 as appropriate.
The inspectors found that the third action was being tracked in the corrective-action program as tasks 2 and 3 of action item 98-03267, and noted that the due date for completing these tasks is February 28, 1999.
After discussions with the licensee's Regulatory Affairs personnel, the inspectors understood that the corrective actions described above represent a response to the subject violation that is more complete than the response described in letter HNP-98-055. The inspectors considered the corrective actions described above as a supplement to the licensee's original response to the subject violation.
The inspectors examined procedure AP-925, and found that it provides a structure for organizing, managing, and documenting the results of event-evaluation activities. The inspectors also examined materials used in the 3-day training course, and found that those materials describe techniques that appear to be both directly and readily applicable to plant-related problems.
Pending the integration of AP-925 into the procedure hierarchy, this item will remain open.
III. En lneerln E1 Conduct of Engineering E1.1 En ineerin Service Re uests a.
Ins ection Sco e 37551
The inspectors reviewed portions of Engineering Service Request (ESR) 9800448,
"Evaluation of Large-Bore "B"Train ESW Interior Pipe Coating," Revision 0, to determine whether procedure EGR-NGGC-005, "Engineering Service Requests,"
Revision 5, was being followed, and to determine whether engineering was properly resolving problems.
b.
Observations and Findin s The inspectors observed that engineering personnel evaluated the information provided from the performance of preventive maintenance activity PM ANTF001 for inspection of the B train Emergency Service Water (ESW) piping header during refueling RFO8. The information was compared to the previous inspection data and evaluations documented in ESR 95 00823," B Train ESW Piping, Lining Inspection Concerns," Revision 0, which had addressed ten areas of concern from RFO6. The current ESR evaluated the ten
previous areas based on the additional data.
In addition ESR 9800448 specified two new areas where the internal pipe coatings had degraded.
The problems found in the ESW header inspection were being properly addressed by engineering and the ESR procedure was being followed.
The inspectors reviewed the performance data from EPT-442, "1B-SB Pump Curve Determination," Revision 0, which the system engineer had plotted for the new B ESW pump installed during RFO8, under ESR 9600025, Revision 5. The new larger capacity pump was installed to provide additional margin. The inspectors discussed the EPT-442 results with licensee engineers and were told that performance was slightly below the predicted performance for the pump. Engineering was performing an evaluation to determine the overall affect of the installed pump performance on future ESW needs.
The inspectors found that engineering was appropriately involved in the resolution of the pump upgrade issue.
Conclusions Engineering was appropriately involved in the ESW piping inspection results and pump performance issues.
Resolution activities were being conducted in accordance with required procedures.
Steam Generator Re lacement Pro'ect SGRP Pre arations Ins ection Sco e 50001 The inspectors reviewed licensee SGRP programs and activities.
Observations and Findin s During this inspection, the licensee received the first replacement SG and transferred it from rail cars to a transport vehicle. The remaining two'replacement SGs were in transit by barge and rail. The inspectors reviewed replacement SG procurement documentation, including procurement specifications, source inspection procedures, shipping plans and specifications, and receipt inspection procedures.
The inspectors also conducted an inspection of the condition of the first SG.
The inspectors found that the licensee had assembled an engineering team with a significant amount of SGRP experience to oversee the Harris SGRP.
The project gave every indication of being well-managed, with most required engineering, construction, and test work items identified, developed, and being tracked.
RFO-8 activities appeared to have been successful, and project management was already into planning and scheduling for RFO-9 activities. The inspectors attended a monthly meeting between the licensee and the primary engineering contractors for the SGRP, and noted that the level of detail of current planning and scheduling activities was extremely well develope Conclusions
Steam generator replacement project activities appeared to be progressing in a well-controlled manner.
Current staff for the project appeared to provide a significant experience data base.
ES Miscellaneous Engineering Issues (92903)
E8.1 Closed Violation 50-400/98-06-03:
Containment sump FME bracket design deficiency. 'NRC IR 50-400/98-06 discussed the licensee's resolution for containment sump foreign-material-exclusion (FME) brackets installed in the sump grouting without being part of the plant design.
The only item left to be resolved was removal of the brackets, which was scheduled for the refueling outage.
The inspectors observed that the FME brackets had been removed.
Removal had been accomplished under WR/JOs 97-AJIR1 and 97-AJIS1, which implemented ESR 97-00429.
E8.2 Closed Violation 50-400/97-13-02:
Inadequate corrective actions for preheater bypass valve air system design deficiency. This item was addressed in NRC IRs 50-400/98-07, section E8.2 and 50-400/98-09 section E1.1. The inspectors reviewed the corrective actions and the previous reports.
The inspectors determined that the post-modification testing had adequately determined that the problem was corrected.
IV. Plant Su ort R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 General Comments ao Ins ection Sco e 71750 The inspectors observed radiological controls during the conduct of tours and observation of maintenance activities.
b.
Observations and Findin s The inspectors found radiological controls to be acceptable.
The general approach to the control of contamination and dose for the site was good. Teamwork between the various departments continued to be a major contributor to the good control of dose.
The inspectors found during tours of the plant that some temporary shielding was not identified with an expiration date on the temporary shielding tag.
In reviewing procedure HPP-015, "Use of Temporary Shielding," Revision 12, the inspectors found that section 10.5 indicated that "an ESR should be submitted in accordance with EGR-NGGC-005 if permanent shielding is needed."
The inspectors looked at the temporary shielding log which showed that some shielding had been in place since 1991 and observed that the expiration date column had the word "none" for about five items. The lack of an expiration date on the temporary shielding tag and the word "none" for the expiration date in the log indicated that the shielding was not temporary.
The inspectors
determined that the shielding was there for valid As Low As Reasonably Achievable
"
(ALARA)purposes and should therefore not be immediately removed.
The inspectors discussed this observation with plant management, who subsequently initiated a-condition report (CR 98-03286) to address this issue.
The issue of using temporary programs in lieu of the ESR process for temporary shielding is similar to a violation for incorrect use of caution tags in NRC IR 50-400/96-11.
The failure to comply with administrative requirements on temporary shielding was contrary to requirements of procedure HPP-015, "Use of Temporary Shielding," Revision 12. This failure constitutes a violation of minor significance and is not subject to formal enforcement action.
C.
Conclusions The control of contamination and dose for the site was good, and was attributable to good teamwork between various departments.
Some temporary shielding was being used as permanent shielding, indicating a lack of focus on the administrative aspects of the temporary shielding program.
However, the shielding was providing an appropriate ALARAfunction. This issue was identified as a minor violation S1 Conduct of Security and Safeguards Activities
'1.1 General Comments a.
Ins ection Sco e 71750 The inspectors observed security and safeguards activities during the conduct of tours and observation of maintenance activities.
b.
Observations and Findin s The inspectors found the performance of these activities was good. Compensatory measures weie posted when necessary and were properly conducted.
The handling of additional personnel for the refueling outage was managed well.
C.
Conclusions The performance of security and safeguards activities were in accordance with applicable procedures and the Security Plan.
For the refueling outage, access and search activities were handled well.
F1 Control of Fire Protection Activities F1.1 General Comments 71750 The inspectors observed fire protection equipment and activities during the conduct of tours and observation of maintenance activities.
Fire protection activities were being
., adequately conducte Fire Protection Staff Knowledge and Performance F4.1 Fire in Air Handler 21 Ins ection Sco e 71750 On November 25, the inspectors observed the fire brigade respond to a fire on the 261-foot elevation of the reactor auxiliary building to determine whether the brigade was adequately trained and took the appropriate actions.
b.
Observations and Findin s The inspectors observed the fire brigade staged in the hallway outside the room where AH-21 was housed.
The breaker for the air handler had already tripped and there was a burnt smell in the air. The inspectors observed that the fire brigade staged the fire hose and had a fire extinguisher available. The inspectors observed that the 1A motor/motor bearings for the air handler had apparently seized, causing the breaker to trip. The fire brigade ensured that the fire was out and adequately assessed the cause.
The inspectors found that the fire brigade response was prompt and that the actions taken in response to the fire were appropriate.
The inspectors found that the fire brigade team
'eader kept the control room informed of the fire brigade activities and findings.
The brigade pointed out to the inspectors that there was an open deficiency (38337) on the air handler motor bearings due to high vibration. A maintenance request (WR/JO 98-001890) had been initiated on October 8, 1998. The air handler apparently had continued to be'used.
This was a nonsafety air handler located in the same room with one of the safety-related reactor auxiliary building emergency exhaust system filtration units (E-6A). On November 30, the inspectors found that no condition report had been initiated to address the fire event to which the fire brigade had been dispatched.
The inspectors discussed this issue with the plant general manager, who ensured that a condition report was written. The inspectors later verified that CR 98-03178 was initiated for this event and discussed the investigation with the operations manager and the system engineer.
The'inspectors found that the failure to initiate a CR for this adverse condition was contrary to requirements described in CAP-NGGC-001, Corrective Action, Revision 2. This failure constitutes a violation of minor significance and is not subject to formal enforcement action.
C.
Conclusions The fire brigade adequately responded to a fire that occurred November 25 on the 261 foot elevation of the auxiliary building in the motor for air handling unit AH-21, a non-safety related air handler.
A minor violation was identified for failure to initiate a condition report for the fir V. Mana ement Meetin s X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on December 18, 1998. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary.
No proprietary information was identifie PARTIALLIST OF PERSONS CONTACTED Licensee J. Bates, Superintendent, Environmental and Chemistry D. Batton, Superintendent, On-Line Scheduling D. Braund, Superintendent, Security B. Clark, General Manager, Harris Plant A. Cockerill, Superintendent, I&C Electrical Systems J. Collins, Manager, Maintenance J. Cook, Manager, Outage and Scheduling J. Eads, Supervisor, Licensing and Regulatory Programs R. Field, Manager, Nuclear Assessment M. Keef, Manager, Training G. Kline, Manager, Harris Engineering Support Services R. Moore, Manager, Operations K. Neuschaefer, Superintendent, Radiation Protection J. Scarola, Vice President, Harris Plant S. Sewell, Superintendent, Mechanical Systems D. Shockley, Superintendent, Design Control C. VanDenburgh, Manager, Regulatory Affairs S. Flanders, Harris Project Manager, NRR B. Bonser, Chief, Reactor Projects Branch 4
INSPECTION PROCEDURES USED IP 37551:
IP 40500:
IP 50001:
IP 50002:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 92700:
IP 92901:
IP 92902:
IP 92903:
Onsite Engineering Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Steam Generator Replacement Inspection Steam Generators Surveillance Observations Maintenance Observation Plant Operations Plant Support Activities Onsite Followup of Events Followup - Plant Operations Followup - Maintenance Followup - Engineering
~Oened ITEMS OPENED, CLOSED, AND DISCUSSED 50-400/98-10-01 URI Loss of valid reactor vessel level indication during reduced-inventory operations (Section 01.3)
Closed 50-400/98-06-03 VIO Containment sump FME bracket design deficiency (Section E8.1).
50-400/97-13-02 Discussed VIO Inadequate corrective actions for preheater bypass valve air system design deficiency (Section E8.2).
50-400/98-007-00 50-400/98-01-01 LER Turbine control anomaly causes a manual reactor trip (Section 08.1).
VIO Example 2; Inadequate work instructions for rod control system (Section M8.1).