IR 05000400/1998009
| ML18016A765 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 12/07/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18016A761 | List: |
| References | |
| 50-400-98-09, 50-400-98-9, NUDOCS 9812170144 | |
| Download: ML18016A765 (40) | |
Text
U. S. NUCLEAR REGULATORYCOMMISSION
REGION II
Docket No:
License No:
50-400 NPF-63 Report No:
50-400/98-09 Licensee:
Carolina Power & Light (CP&L)
Facility:
Shearon Harris Nuclear Power Plant, Unit 1 Location:
5413 Shearon Harris Road New Hill, NC 27562 Dates:
September 27 - November 7, 1998 Inspectors:
Approved by:
J. Brady, Senior Resident Inspector R. Hagar, Resident Inspector in training J. Coley, Reactor Inspector (Sections M2.2 & M2.3)
J. Lenahan, Reactor Inspector (Section E1.1, E2.2, E2.3 & E81.)
F. Wright, Radiation Specialist (Sections R1.2, R1.3, & R7.1)
B. Bonser, Chief Projects Branch 4 Division of Reactor Projects P812i70i44 98i207 PDR ADOCK 05000400
PDR Enclosure 2
EXECUTIVESUMMARY Shearon Harris Nuclear Power Plant, Unit 1 NRC Inspection Report 50-400/98-09 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support.
The report covers a six-week period of resident inspection; in addition, it includes the results. of announced inspections by a regional radiation specialist and two regional reactor inspectors.
~Oerations During the period, the conduct of operations was in accordance with applicable procedures (Section 01.1).
On October 23, the licensee appropriately initiated a manual reactor trip and turbine trip from a power level of approximately 90 percent, in response to an unexpected opening of the main turbine governor valves, which caused an uncontrolled power increase.
The control room operators responded promptly to the unexpected conditions, and adequately handled the reactor trip in accordance with the emergency operating procedures.
The licensee promptly made the notifications required by 10 CFR 50.72.
The licensee thoroughly reviewed the equipment problems which necessitated the reactor trip and promptly initiated corrective action (Section 01.2).
Daily trending of adverse conditions was evident reflecting improvement in the trending program.
Self-assessment activities were focussed on the identification of safety issues (Section 07.1).
Operator actions for an October 19 loss of component cooling water surge tank level event were appropriate, conservative, and in accordance with applicable procedures.
The licensee's investigation of this event was timely and thorough.
A non-cited violation was issued for the licensee's failure to develop adequate instructions for clearance restoration, which included filland vent for the "C" component cooling water pump piping section (Section 07.2).
Maintenance Maintenance activities were conducted in accordance with applicable work documents and procedures (Section M1.1).
The surveillance performances were conducted in accordance with applicable procedures (Section M2.1).
Refueling Outage 8 (RFO8) inservice examination activities observed on safety injection system piping welds and steam generator tubes were performed in a skillful manner by knowledgeable examiners, using approved procedures (Section M2.2).
RFO8 welding activities observed on a leaking Control Rod Drive Mechanism (CRDM)
canopy seal weld and on the auxiliary feedwater system piping were effectively controlled by approved'procedures/instructions and performed by skillful welders.
In addition, the radiographic processes observed during the filmreview for the AuxiliaryFeedwater (AFW)
system were effectively performed in accordance with the approved procedure (Section M2.3).
~
The steam generator nozzle dam installation training was considered a strength (Section M5.1).
~En ineerin
~
The quality of the modifications reviewed for RFO8 was good.
Two weaknesses in the modification packages reviewed were identified concerning incomplete documentation of the safety evaluation for the AFW steam supply isolation valve modification and failure to include testing of an isolation check valve in the modification to the air supply to the preheater bypasss valves (Section E1.1).
~
A violation was identified for failure to translate design requirements into maintenance procedures which specified service life and replacement frequencies for Agastat E7000 series relays (Section E2.2).
The licensee's operability evaluation of-the settlement of Electrical Manhole 70 was performed in accordance with NRC requirements.
Identification and evaluation ofthis issue was a good example of proactive involvement of engineering support of facilities and equipment (Section E2.3).
The control of contamination and dose for the site was,good and was attributable to good teamwork between the various departments (Section R1.1).
The inspectors concluded that the radiation protection activities were effective and performed in accordance with regulatory requirements (Section R1.2).
The As Low As Reasonably Achievable (ALARA)program was effective in reducing site collective personnel radiation doses (Section R1.3).
A review of Radiation Protection items in the licensee's corrective action program concluded that the threshold for placing issues into,the program was appropriate.
The analysis of problems was generally good with corrective actions to prevent recurrence prescribed.
Quality assurance reviews during the RFO provided evidence the Harris staff was self-identifying problems and taking measures to improve performance and compliance (Section R7.1).
Re ort Details Summa of Plant Status r
Unit 1 began this inspection period at approximately 100 percent power. On October 23, the unit was manually tripped, from approximately 90 percent power, when a turbine governor valve control circuit problem caused the governor valves to unexpectedly go full open. At the time, the unit was shutting down to enter a planned refueling outage.
This ended a 417-day record run, breaking the previous record of 299 days online. The unit ended the period in the refueling outage.
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.
Routine activities were adequately performed.
Operations shift crews were appropriately sensitive to plant equipment conditions and maintained a questioning attitude in relation to unexpected equipment responses.
Control Room staffing was maintained in accordance with technical specification requirements.
The inspectors observed that operators performed operations surveillance tests and fuel handling activities in accordance with applicable procedures.
Transients were responded to in accordance with applicable abnormal operating procedures and emergency operating procedures.
These included a loss of the Sll vital instrument bus (observed by the inspectors), loss of component cooling water surge tank level (Section 07.2), and a reactor trip (Section
.
01.2).
C.
Conclusions During the period, the conduct of operations was in accordance with applicable procedure Manual Reactor Tri Ins ection Sco e 71707 93702 The inspectors observed a planned downpower to enter a refueling outage on October 23 to determine if procedures were followed.
During the downpower a manual reactor trip from approximately 94 percent power was necessary.
The inspectors observed operator response to the trip to determine if applicable emergency operating procedures were followed and afterwards observed the licensee's investigation of the circumstances that made the trip necessary.
Observations and Findin s The inspectors observed the control room operators as they initiated a down-power evolution to begin the planned Refueling Outage (RFO-8). The operators began the evolution with the main turbine's Digital Electro-Hydraulic (DEH) controls in manual mode of operation rather than in automatic, A month earlier the DEH system had transferred to manual mode due to input voltage flunctuations. The licensee elected to leave the DEH control in manual mode until the downpower for entry into the refueling outage.
The operators'lan was to place the DEH system in automatic mode after reactor power was reduced to below 90 percent.
After the power reduction to approximately 83 percent, the operators initiated the DEH system transfer from manual to automatic mode in accordance with approved procedures.
The inspectors noted that the transfer was completed in approximately 20 minutes, and that after the transfer was complete, the operators initiated a relatively large power decrease in automatic mode in accordance with approved procedures.
The operators closely monitored the power decrease to verify proper operation of all plant systems.
Approximately two minutes after initiating the power decrease the operators and the inspectors noted that the control board indicated that all four turbine governor valves had gone fullyopen. Almost immediately thereafter, the reactor's control rods began stepping out rapidly. Within a few seconds, the operators determined that an uncontrolled power increase was occurring. With the concurrence of the Superintendent-Shift Operations (SSO), the Unit Senior Control Operator (USCO) directed the control board operators to initiate a manual reactor trip and turbine trip. The control boards indicated that both the reactor and the main turbine tripped.
Immediately after the reactor and turbine were tripped, the inspectors observed that the operators appropriately and efficiently entered Emergency Operating Procedure (EOP)
"EOP-PATH-1," Rev. 12. They successfully completed the actions required by that procedure, and transitioned quickly into EOP-EPP-4, "Reactor Trip Response,"
Rev. 7.
's they completed the instructions in that procedure, the operators encountered several additional equipment problems, including:
~
all three feedwater regulating valves remained approximately 10 percent open, instead of closing fully;
~
a steam generator power-operated relief valve opened during the transient, and remained open until the operators manually increased its actuation setpoint;
~
the moisture-separator reheater controller did not reset;
~
a condensate booster pump tripped, causing its associated main feedwater pump to trip also; and
~
five extraction steam line non-return valves failed to close.
Despite the problems noted above, the inspectors observed that the operators effectively stabilized the plant, and that plant parameters generally remained within expected ranges.
However, the inspectors noted that the post-trip cooldown resulted in a reactor coolant system temperature of 538'F, which was lower than expected.
The inspectors observed that the control-room operators used clear and concise three-way communications before and during the event, and handled well not only the power decrease preceding the trip, but also the trip and post-trip actions.
The inspectors observed that the licensee appropriately filed a 4-hour non-emergency event notification report in accordance with 10 CFR 50.72(b)(2), and observed that the report failed to note that an "ESF Actuation" had occurred.
(The auxiliary feedwater pumps had started immediately after the reactor trip, in response to the resulting transient in steam generator water levels.) However, the licensee noted that deficiency very soon after filingthe original report, corrected the report, and refiled it within a few minutes.
The licensee initiated Condition Report (CR ) 98-2631 to document this event, assembled an event review team to determine the root causes and contributing factors, and to develop recommendations for corrective actions.
The inspectors observed the team present its results to the Plant Nuclear Safety Committee (PNSC) on November 4.
The team reported that:
~
During the event, the operators performed as they had been trained. Allprocedures were followed correctly and the crew operated as a team.
~
A Condition Report or a maintenance work request had been initiated to resolve each of the equipment problems noted during the event.
~
The "root cause" of the event was that in December 1992, the DEH system engineer failed to adequately resolve an Operations request to implement the DEH vendor's guidance regarding system operation into the operating procedure.
The team concluded that implementing that guidance would have enabled the control-room operators to operate the DEH system in a way that would not have resulted in the abrupt opening of the governor valves.
I The team recommended a set of corrective actions to address the root cause and related contributing factors.
The inspectors noted that the licensee's procedures require completion of a post-trip review in accordance with procedure OMM-004, "Post-Trip/ESF Actuation Analysis",
Rev. 10. The licensee had not yet completed that analysis.
The post-trip review included not only the equipment problems, but also an integrated look at operator an equipment response to the trip. The inspectors will review the post-trip review along, with the licensee event report when they are issued.
c.
Conclusions On October 23, the licensee appropriately initiated a manual reactor trip and turbine trip from a power level of approximately 90 percent, in response to an unexpected opening of the main turbine governor valves, which caused an uncontrolled power increase.
The control room operators responded promptly to the unexpected conditions, and adequately handled the reactor trip in accordance with the emergency operating procedures.
The licensee promptly made the notifications required by 10 CFR 50.72.
The licensee thoroughly reviewed the equipment problems which necessitated the reactor trip and promptly initiated corrective action.
Operational Status of Facilities and Equipment 02.1 General Comments 71707 The inspectors observed that facilities and equipment were maintained and clearances were installed and removed in accordance with applicable procedures.
One problem with a 1997 clearance caused a loss of component cooling water surge tank level, as discussed in Section 07.2.
02.2 En ineered Safe Feature S stem Walkdowns 71707 The inspectors walked down accessible portions of the "B" emergency diesel generator (EDG) system, while maintenance was being performed on the "A" EDG. The inspectors found that equipment operability, material condition, and housekeeping were acceptable.
Quality Assurance in Operations 07.1 General Comments a.
Ins ection Sco e 40500 71707 During the inspection period, the inspectors reviewed multiple licensee quality assurance activities, including:
~
Condition Reports;
~
Nuclear Assessment Section Audits on Vendor/Equipment Services (H-VEQ-98-01),
Environmental and Radiation Control (HNAS98-138), and Maintenance (HNAS98-125),;
~
Plant Nuclear Safety Committee (PNSC) meeting conducted on November 4;
~
Plant Review Meeting conducted on October Observations and Findin s The inspectors observed that the recognition of adverse condition trends was part of the daily meeting to review and classify new condition reports.
During the refueling outage, potential adverse trends were identified on Potential Emerging Trend Warning Sheets to the associated managers.
The inspector found the daily trending observations were of benefit to properly focus licensee attention on repetitive problems.'his item was an improvement in the trending program.
Nuclear Assessment Section activities and management review activities were appropriately focussed on safety.
C.
Conclusions 07.2 a.
Daily trending of adverse conditions was evident reflecting improvement in the trending program.
Self-assessment activities were focussed on the identification of safety issues.
r Partial Loss of CCW Sur e Tank Level Ins ection Sco e 71707 b.
On October 19, control room operators informed the inspectors that while they were placing Component Cooling Water (CCW) pump 1C-SAB in service in accordance with operating procedure OP-145, '-'Component Cooling Water," Rev. 20, CCW surge tank level on the "A"side of the tank dropped to approximately 15 percent, and level on the
"B"side of the tank dropped to below 0 percent before both were recovered to the normal operating level of 50 percent.
The inspectors reviewed the circumstances associated with the event to determine if procedures were followed and to determine whether the licensee had identified adequate corrective action to correct the problem.
Observations and Findin s The inspectors observed that CR 98-02586 had been initiated to document the event, and that an investigation to determine the root causes for the event was ongoing. The inspectors monitored the subsequent investigation of this event, including observation of some interviews, and conducte'd a parallel independent investigation.
The inspectors found that this event was significant in that if CCW surge tank level dropped below 4'ercent, licensee procedures required operators to trip the reactor and stop all reactor coolant pumps.
In the root cause report, the investigator identified the root cause of this event as an
"inadequate fill-and-vent procedure" which had left partially voided a portion of the header associated with the 1C-SAB pump. The valve manipulations required to place the pump in service allowed water to flowfrom the surge tank into the voided header, causing the surge tank levels to drop. The "procedure" identified as the root cause was actually a set of instructions that had been incorporated into Clearance 97-00119.
That clearance had been used to isolate the pump header for routine maintenance work and to restore the header to service in May 1997. The investigator determined that the fill-
.and-vent instructions in that clearance were not adequate to completely fillthe header.
The investigator also determined that the "A"and "B"trains of CCW were cross-
connected, and the two sides of the surge tank were effectively redundant surge tanks for the operating pump.,The investigator concluded that the operators were correct in not tripping the plant when one side of the surge tank fell below the trip setpoint, because the other side remained well above that setpoint. The investigator also identified several contributing factors, arid developed recommended corrective actions to address both the root cause and the contributing factors.
On November 4, the inspectors observed the Plant Nuclear Safety Committee (PNSC),approve the root cause report for CR 98-02586 with only minor changes, and directed implementation of the recommended corrective actions.
The inspectors independently examined the information gathered by the investigator, gathered other information through walkdowns and document reviews, and identified the causes and conditions which were associated with this event. The inspectors'ound durin'g the walkdown that the points chosen to vent the system were drains and were near the low points in the piping. The inspectors found that the licensee's investigation of this event identified the same set of causes and contributing factors as did their own, and that the actions taken by the control-room operators during the event were appropriate, conservative, and in accordance with applicable procedures.
The inspectors considered that the planned corrective actions did not fullyaddress the identified root cause, in that none of the'planned corrective actions involved clearance activities. However, the inspectors noted that a few weeks earlier, the licensee had initiated an adverse-trend Condition Report (CR 98-02439) to address a trend of problems that had been noted. in the clearance process.
The inspectors thus considered that together, the planned corrective actions and CR 98-02439 adequately addressed the causes and contributing factors. The inspectors considered that the planned schedule for implementing the corrective actions was reasonable.
The inspectors found that the inadequate fill-and-vent procedure referred to by the licensee as the "root cause" was inconsistent with Technical Specification (TS) 6.8.1, which requires, in part, that written procedures shall be established, implemented, and maintained for equipment control, including clearances and system filland vent. The inspectors considered the licensee's failure to establish adequate. filland vent instructions for restoring the subject pump to service through Clearance 97-00119 to be a violation of TS 6.8.1. The inspectors concluded that licensee identification credit for this self revealing event was warranted because the root cause of the event was not obvious; and the licensee had no prior opportunity to identify the problem. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy, and was designated as Non-Cited Violation (NCV) 50-400/98-09-01, failure to develop adequate instructions for clearance restoration.
Conclusions Operator actions for an October 19 loss of component cooling water surge tank level event were appropriate, conservative, and in accordance with applicable procedures.
The licensee's investigation of this event was timely and thorough. A non-cited violation was issued for the licensee's failure to develop adequate instructions for clearance restoration, which included filland vent for the "C" CCW pump piping sectio ~
~
08.1 08.2 Miscellaneous Operations issues (92901)
Closed Violation 50-400/98-04-01:
clearance tag not hung. The inspectors reviewed the licensee's response dated July 17, 1998, and the corrective actions described therein. The inspectors reviewed the root cause investigation contained in CR 98-01231-1. The corrective actions included counseling and communication of lessons learned to the other operators.
The inspectors verified that these had been completed and the problem had been corrected.
0 en Violation 50-400/98-01-01:
failure to followprocedure, example 1, properly check main control room chart recorders.
The inspectors reviewed the licensee's responses dated April24, 1998 and May 29, 1998, and the corrective actions described therein. The corrective actions described included counseling, real time training, and lessons learned.
The inspectors verified that these actions had been completed.
The inspectors also reviewed violations 50-400/97-09-02 and 50-400/96-11-01, associated with chart recorder marking problems, and their associated responses, dated November 5, 1997 and March 3, 1997. The inspector noted that the March 3, 1997 response, associated with a December 1996 chart recorder marking problem, had stated that the standard recorder pen and inking system for some recorders would be replaced with felt tip pens on an as needed basis.
The inspectors were aware that the licensee's Robinson Nuclear Plant had success in this approach to correcting the problems with the standard inking systems.
The inspectors observed that over the following years very few of these modifications were made.
The licensee was considering the use of digital chart recorders and considered the felt tip pen conversion to be only an interim measure.
A management decision was made to delay felt tip pen conversion when it appeared that the design change for the digital chart recorder would be approved quickly. Unfortunately, problems with the digital chart recorder design change caused a delay of more than a year. Consequently, operators were left with the old standard inking recorders which were difficultto keep continuously working.
After the 1998 violation was issued, operations management decided to proceed with the felt tip pen modification immediately for all post accident recorders.
The inspectors observed that these modifications have been made and that the new felt tip pens are considerably more reliable than the standard inking system.
The inspectors also noted that the first of the new digital chart recorders were put into operation on a post accident recorder during this report period (approximately 22 months after,the original chart recorder violation). The inspectors have observed that operators are no longer being regularly distracted by chart recorder inking problems.
This example is closed.
08.3 This item remains open pending review of example 2.
Closed Violation 50-400/98-03-01:
failure to properly classify condition reports (2 examples).
The inspectors reviewed the licensee's response dated June 4, 1998, and reviewed the corrective actions described.
The corrective actions included upgrading the condition report classification for the two examples, conducting training, and performing additional reviews of other condition reports.
The inspectors verified that
'I
these actions had been completed.
Four additional condition reports were found by the licensee that were also upgraded.
II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Ins ection Sco e 62707 The inspectors observed all or portions of the following work activities:
~
WR/JO AMCB-002
~
CM-M0176
~
WR/JO 98-AGRE1
~
CM-M0175 CM-M0100
~ ~
PM-E006
~
CM-M0060 PIC 1 power supply replacement Steam Generator Primary Nozzle Dam Installation, Operation, and Removal, Revision 15 Troubleshoot AC input breaker to Sll inverter Removal and Replacement of the Steam Generator Primary Manway Covers/Tensioning, Detensioning, Revision 12 Containment Equipment Hatch Removal and Replacement, Revision 10 6.9KV 3000 Amp AirCircuit Breaker PM, Revision 6 Westinghouse Reactor Coolant Pump, Model W-11010-A1 (93-ACS) Seal Removal and Installation, Revision 11 b.
Observations and Findin s The inspectors found the work performed under these activities to'be professional and thorough.
Allwork observed was performed with the work package or the specific maintenance procedure 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.
c.
Conclusions Maintenance activities were conducted in accordance with applicable work documents and procedure 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 following surveillance tests:
~
OST 1085
~
MST I0247
~
OST 1007
~
OST 1861
~
OST 1823
~
MST E0072
~ 'MST M0019
~
EST-202 1A-SA Diesel Generator Operability Test, Revision 12 Metal Impact Monitoring System Operational Test, Revision 6 CVCS/Sl System Operability Train A, Revision 13 Remote Shutdown Individual Component Tests, Revision 0 1A-SA Emergency Diesel Generator Operability Test, Revision 12 480 VAC Siemens Type RLN(F) Load Center Breaker and Cubicle Test Emergency Diesel Generator Subcover Assembly, Rocker Arm and Cylinder, Revision 8 INSITU Main Steam Safety Valve Test Using Assist Device-Mode 3, Revision 14 b.
Observations and Findin s The inspectors found that the testing was adequately performed.
c.
Conclusions The surveillance performances were conducted in accordance with applicable procedures.
M2.2 Inservice Ins ection a.
Ins ection Sco e 73753 During refueling outage 8 (RFO-8) which was the first period of the second 10-year inservice inspection interval for Unit 1, three methods of nondestructive examination were evaluated by the inspector to determine the effectiveness of the licensee examination procedures, examiners'kill and knowledge in calibrating the test.
equipment, performance of the examinations, and interpretation/evaluation of the test results.
b.
Observations and Findin s Manual ultrasonic equipment calibrations and four weld examinations on the 6-inch safety injection system piping running downstream from the check valve to the loop No.
2 reactor coolant cold-leg were observed by the inspectors.
These welds were examined in accordance with NRC Bulletin 88-08, "Thermal Stresses in Piping Connected to Reactor Coolant System," to determine ifthe welds or the weld heat affected zones had experienced high cycle thermal fatigue cracking.
Multiple angle and
f
wave mode transducers were used to examine these welds. Construction radiographs were also reviewed to verify apparent weld root discontinuities.
As a result of the ultrasonic examinations performed, the examiners concluded that the four safety injection welds examined on loop No. 2 were free of any service defects.
Liquid penetrant examinations on three of the safety injection welds were also observed by the inspectors.
These examinations were satisfactorily performed and evaluated as acceptable by the examiners.
In addition to the above Bulletin 88-08 work, the inspectors observed steam generator tube eddy current data acquisition examinations, 4-hour equipment calibrations, and final resolution analyses of examination data.
Observation of these work activities revealed that the examiners were skillfuland kriowledgeable of the examination process, use of the examination equipment, and evaluation/analyses of the examination data.
C.
Conclusions RFO8 inservice examination activities observed on safety injection system piping welds
'and steam generator tubes were performed in a skillfulmanner by knowledgeable examiners, using approved procedures.
M2.3 W~eldin Ins ection Sco e 55050 The inspectors reviewed repairs to the reactor vessel head penetration ¹18 Control Rod Drive Mechanism (CRDM) housing lower canopy seal weld to verify that they were performed in accordance with the American Society of Mechanical Engineers (ASME)
Code, Sections III and XI, ASME Section XI Code Case N-504-1, and NRC Relief Request 2R1-012. The inspectors also reviewed the radiography records completed for replacement of portions of the 6-inch auxiliary feedwater piping to verify that the radiography was conducted and evaluated in accordance with licensee procedure No.
NDEP 107, Rev. 2.
Observations and Findin s During removal of the reactor vessel mirror insulation from around the vessel head flange, indication of significant amounts of boric acid were found under the insulation around the top of the reactor vessel head.
The source of the boric acid was determined to be the CRDM housing lower canopy seal weld at penetration ¹18. The leak location was repaired by applying a weld overlay repair in accordance with the 1989 edition of the ASME Code, Sections III & XI, and ASME Section XI Code Case N-504-1.
The licensee also replaced portions of the 6-inch auxiliary feedwater piping that had experienced wall thinning resulting from flow-accelerated corrosion. The inspectors observed the quality of welding performed for this replacement activity by reviewing the completed radiographic fil The inspectors verified that the weld package for the CRDM canopy seal weld repair was in compliance withthe ASME Code. This review included Engineering Service Request No.
9800427, Work Request 98-AHAY4, Relief Request No. 2R1-012, Welding Services Inc.
Traveler No. Harris 4, Rev.0, filler material certification, and personnel welding certifications. The inspectors also verified that the parameters of the welding procedure were adhered to and observed the initial welding activities.
Based on review of this documentation and observation of initial work activities, the inspector concluded that personnel and materials were properly certified, and that licensee had appropriate welding controls in place to successfully perform the CRDM canopy seal weld overlay repair.
Radiographs for ten completed ASME Class 2 auxiliary feedwater system welds were also reviewed by the inspectors to determine final weld quality, quality of the radiographic film and whether the film had been evaluated in accordance with the approved radiographic procedure.
Based on the review of those radiographs, the inspector concluded that radiographic processes, including the evaluation of the radiographic film were conducted in a skillfuland effective manner, and the quality of the welds examined were very good.
C.
Conclusions M5 RFO8 welding activities on a leaking CRDM canopy seal weld and on auxiliary feedwater system piping were effectively controlled by approved procedures/instructions and performed by skillfulwelders.
In addition, the radiographic processes observed during the filmreview forthe auxiliaryfeedwater system were effectively performed in accordance with the approved procedure.
Maintenance Staff Training and Qualification I
M5.1 Steam Generator Nozzle Dam Installation Trainin 62707 The inspectors observed both mockup training forsteam generator nozzle dam installation and actual nozzle dam installation.
The inspectors found that team work was practiced between maintenance technicians, health physics technicians, and the steam generator nozzle dam installation crew during both training and installation.
The mockup was equipped with the same equipment used on the actual job. The team was coached and evaluated during the training sessions by personnel that had previously performed the tasks.
The training was considered a strength.
M8 Miscellaneous Maintenance Issues (92902)
. M8.1 Closed LER 50-400/98-003-00 and Violation 50-400/98-01-03:
failure to perform shutdown margin calculation required by technical specification surveillance requirements.
The violation was issued because previous corrective actions had been ineffective. The inspectors reviewed the licensee's response dated April 24, 1998, the LER, and the described corrective actions. This LER was the subject of violation 50-400/98-01-03.
The
corrective actions involved issuance of an operations night order, real-time training for operators, issuance of a plant memorandum on TS compliance and timely resolution of TS
'uestions, and revision of operations procedures APP-ALB-103, "MainControl Board," Rev.
9; AOP-001, "Malfunction of Rod Control and Indicating System," Rev. 13; and OP-104,
"Rod Control System," Rev; 12. The inspectors verified that these actions were complete.
III~ En ineerin E1 Conduct of Engineering E1.1 Review of Modifications Ins ection Sco e 37550 The inspecto'rs performed a review of modifications planned forthe current refueling outage (RF08).
~
b.
Observations and Findin s The inspectors reviewed Engineering Service Request ESR numbers 96-00163, LVC-430 and LCV-435 Removal and MS Traps Upgrade, and ESR 98-00020, SG Preheater Bypass Valves Modification. The inspectors reviewed the 10 CFR 50.59 safety evaluations, design inputs, design evaluations, assumptions and references, installation instructions and drawings, and post modification testing instructions. The inspectors identified the following issues when reviewing the ESR documents:
ESR 96-00163, Revision 3, incorporated a temporary modification into a permanent plant change.
Revision 0 of the ESR was the original temporary modification which'was implemented in 1996. Revisions 1 and 2 of the ESR extended the expiration dates of the temporary modification. The temporary modification repositioned the handwheels on two isolation valves for the drains in the steam supply to the auxiliary feedwater pump turbine to prevent the valves from closing on loss of instrument air. Originally these valves were designed to close on a Main Steam Isolation Signal (MSIS). The MSIS logic was removed from the isolation valves under Plant Change Request (PCR) 3955 to improve reliabilityof the AuxiliaryFeedwater (AFW) pump turbine. However, the evaluation for PCR 3955 failed to recognize the consequences of a loss of instrument air. Review of the safety evaluation for Revision 3 of the ESR disclosed that the answers to the questions for the unreviewed safety question determination were not clear.
This was due to fact that the answers referenced previous safety evaluations for PCR 3955 and Revision 0 of ESR 96-00163, with statements such as "justification for locking valves open is same as that presented in previous safety review."
Some of the statements in the written safety evaluations were incomplete and lacked specificity regarding justification for locking these isolation valves open.
The inspectors discussed this issue with the licensee who indicated the safety evaluation would be rewritten to clarify the conclusions in the safety evaluation.
The inspectors concluded that this issue did not involve an unreviewed safety questio l
ESR 98-00020 provided a modification to the instrument air supply forthe steam generator preheater bypass valves. This modification relocated the sensing points for the pressure switches from the instrument air header to a new common supply header in the steam tunnel near the three preheater bypass valves. The instrument air header supplies air to additional equipment beyond the steam tunnel area. The modification willsense loss of air pressure near the valves, which, if lost through a slow leak (smart leak) would render the valves inoperable.
A smart leak would not be detected from a sensing point on the instrument air header.
The modification installed new safety related instrument tubing to supply air to-the new common header and preheater bypass valves. A check valve was installed to isolate the safety related instrument tubing from the non-safety-related instrument air header. The purpose of the check valve is to prevent toss of air from the new common supply header if the air supply is lost in the non-safety related instrument air
'eader.
During review of the post-modification requirements specified in the ESR, the inspectors noted that the check valves were not being tested ensure they performed their intended function. This issue was discussed with licensee engineers who agreed to add testing of the check valves to the post-modification testing to demonstrate the check valves would function as an isolation valve.
C.
Conclusions The quality of the modifications reviewed for RFO8 was good. Two weaknesses in the modification packages reviewed were identified concerning incomplete documentation of the safety evaluation for the AFW steam supply isolation valve modification and failure to include testing of an isolation check valve in the modification to the air supply to the preheater bypasss valves.
E2 Engineering Support of Facilities and Equipment E2.1 General Comments 37551 The inspectors observed that engineering was actively involved in the refueling outage.
Emergent issues were being appropriately addressed in a timely manner. The inspectors observed that a pre-outage issue on new fuel assembly problems at the fuel vendor was being appropriately addressed.
In addition, the licensee was adeq'uately following construction and testing of new steam generators to ensure that the new generators were being built to specifications.
E2.2 Review of Service Life of A astat Rela s Ins e tion Sco e 37550 The inspectors reviewed the licensee's program for control of the service life of safety-related Agastat relays.
Observations and Findin s The inspectors reviewed the licensee's program for controlling the service life of E7000 series Agastat relays.
The vendor manual recommended replacement of
these relays after 25000 operations, or ten years, whichever occurred first. In 1989,"
'he licensee performed an evaluation of the service life and replacement frequency for the Agastat relays under PCR 3008, Rev. 1 ~ The evaluation in PCR 3008, Rev.
1, was based on testing performed by Acton Testing Corporation, documented in Acton Test Report'15761, dated November 30, 1983. The Acton testing included thermal aging, mechanical aging, radiation aging, and seismic vibration.
Review of the PCR disclosed that two relays had a qualified life of 5 years, four had a qualified life of 10 years, and four had a qualified life of 13.5 years. The remaining Agastat relays had been qualified for a service life of 38.5 to 40 years.
The inspectors questioned licensee engineers regarding the maintenance program controls which ensured replacement of the Agastat relays at the frequencies specified in PCR 3008.
Further discussions with the licensee disclosed that the recommended replacement intervals specified in PCR 3008 had not been translated into the maintenance program procedures which specified the replacem'ent frequency and service life. Initial investigation of this issue showed that six of the relays (those with a 5 or 10 year service life) had exceeded their qualified life as of November 3, 1998.
These six Agastat E7000 series relays were used in safety-related applications in the Emergency Diesel Generator (EDG) Control System and the Reactor Protection System.
The EDG relay tag numbers were TD/1991, TD/2011, TDA/1991, and TDA/2011. Reactor Protection System relay tag numbers were 2-1/455 and 2-2/455. The licensee initiated Condition Report (CR) 98-02832 to document and disposition this issue.
ESR 9800450, "Agastat Relay Evaluation,"
was initiated to evaluate the replacement frequencies for these relays.
ESR 9800450 recalculated the qualified lifeforthese Agastat relays based on the normal expected peak temperatures in areas where these relays were installed, and not the upper limiting temperatures specified in the plant Technical Specifications which were used in calculating the original service life in PCR 3008, Rev. 1. ESR 9800450 concluded that the qualified lifeof the relays currently installed in the plant would not be exceeded prior to the next scheduled refueling outage. The inspectors reviewed the ESR and attached safety evaluation screening checklist and concurred with the conclusions.
The failure to translate the conclusions of PCR 3008, Rev. 1 into maintenance procedures which specified service life and replacement Intervals for the Agastat relays was identified to the licensee as a violation of 10 CFR 50, Appendix B,,Criterion III, "Design Control."
Review of CR 98-02832 disclosed that the licensee identified the cause of this problem to be a human performance issue forfailure to establish replacement schedules forthe relays.
The wrong revision of PCR 3008 was utilized when updating maintenance procedures and did not represent a programmatic problem.
Additional corrective actions planned by the licensee were to perform a review to determine if any additional E7000 series Agastat relays have been installed in the plant since PCR 3008, Rev.
1, was completed;
'performance of operability evaluations forthe relays; evaluation of replacement frequencies for the relays under ESR 98-00497; and establishment of a preventive maintenance program for all relays with a qualified life less than 40 years (life of plant). The licensee's corrective actions, documented in the CR, appeared to be adequate and willbe reviewed by NRC in a future inspectio The failure to translate the conclusions of PCR 3008, Rev. 1 service life design bases, into maintenance procedures is identified as Violation50-400/98-09-02, failure to translate PCR 3008, Rev.
1 Agastat E7000 series relay service life into maintenance procedures.
C.
Conclusions A violation was identified for failure to translate design requirements into maintenance procedures which specified service life and replacement frequencies for Agastat E7000 series relays.
E2.3 0 erabili Evaluation for Electrical Manhole a.
Ins ection Sco e 37550 The inspectors reviewed the licensee's operability evaluation for electrical cables which are routed through an electrical manhole which has experienced excessive settlement.
b.
Observation and Findin s The licensee determined that Electrical Manhole 70 had settled approximately 5 inches. The amount of settlement was a concern because safety related electrical cables are routed through the manhole and the differential settlement could result in overstressing or cutting the cables.
The manhole is actually a large rectangular reinforced concrete structure which is adjacent to the Tank Building, with eight
'aults designated A through H. The Tank Building is supported on rock, and the manhole is supported on approximately 60 feet of compacted fill.The safety-related cables are routed through the walls of the Tank building and manhole in conduits.
The inspectors examined the top of the manhole.
The maximum settlement, estimated at approximately 5 inches, had occurred on the western end of the manhole where vaults G and H are located. Approximately 2 inches of settlement occurred on the eastern end of the manhole, where vault A is located. Vaults E, F, G and H were not in use.
The inspectors reviewed ESR 98-00321, Operability Determination for Electrical Manhole 70, and the attached 10 CFR 50.59 safety evaluation. The ESR evaluation was based on visual inspection of the effect of the settlement on electrical conduits in vaults G and H, where the maximum amount of movement (settlement)
had occurred.
Licensee engineers concluded that the settlement that had occurred to date would not have had a determinable effect on the electrical cables.
The licensee was planning to inspect the conduit and associated cables in Vaults C and D during.the current refueling outage. Additional corrective actions willbe determinedbased on the results of these inspections. The licensee plans to implement a settlement monitoring program to measure any additional settlement of the manhole.
C.
Conclusions The licensee's operability evaluation of the settlement of Electrical Manhole 70 was performed in accordance with NRC requirements.
Identification and evaluation of
this issue was a good example of proactive involvement of erigineering support of facilities and equipment.
E8 Miscellaneous Engineering Issues (92903)
E.8.1 Closed Unresolved Item 50-400/97-13-03: extent of condition review forPNSC action Item 97-044822.
PNSC Action Item 97-044882 involved a concern where engineering service requests (ESRs) were being closed and plant modifications were being placed in service prior to updating documents (drawings, procedures, etc.) affected by the ESRs.
This problem had been previously identified as part of violation item 50-400/97-12-05 and CR 97-04463.
The inspectors reviewed the licensee's program for revision of documents affected by modifications implemented during the current refueling outage.
This review disclosed that document revisions are scheduled as part of the ESR closeout process and that documents affected by various ESRs have been identified. The licensee also has a program in place to eliminate the backlog of documents which require revision due to previously closed ESRs.
The inspectors reviewed the backlog during the inspection documented in NRC Report Number 50-400/98-06.
The inspectors concluded that the licensee has implemented adequate controls to prevent recurrence of this problem.
E8.2 Main and Auxilia Reservoir Dam The inspectors observed the main and auxiliary reservoir dam to determine ifthe corrective actions described in licensee letter dated April9, 1998, had been accomplished.
The letter was in response to a dam safety inspection report provided to the licensee by the NRC in a letter dated October 2, 1997.
The inspectors found that the corrective actions as described in the response letters had been adequately accomplished.
IV. Plant Su ort R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 General Comments a.
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 dos c.
Conclusions The control of contamination and dose for the site was good and was attributable to good teamwork between the various departments.
R1.2 Radiolo ical Work Controls a.
Ins ection Sco e 83750 The inspectors observed Radiation Protection (RP) activities to verify applicable radiation protection program requirements were being implemented during RFO8 conditions.
b.
Observations and Findin s The inspection included reviews of records and procedures, interviews with licensee personnel, and observations of work activities in progress.
The inspectors made observations in the reactor containment, fuel handling, radioactive waste processing and reactor auxiliary buildings.
Engineering controls such as containments and filtered ventilation systems and shielding were effectively utilized.
The inspectors made independent radiation surveys in the licensee's facilities and found the licensee's radiation surveys agreed with those of the inspector's. The radiological postings were adequate for dose rates measured by the inspectors.
Remote monitoring included tele-dosimetry, video monitoring, and two-way communications.
The inspectors observed good RP coverage and good utilization of the technology during the nozzle dam installations in steam generations.
There was good RP coverage at the main Radiological Control Area (RCA) entrance and exit portals and the inspectors observed good interactions and communications between radiation workers and RP personnel
~
Individual radiation doses remained low, withthe highest total effective dose equivalent well below the licensee's 2,000 mrem/yr administrative limit.
C.
Conclusions The inspectors concluded that the radiation protection activities were effective and performed in accordance with regulatory requirements.
R1.3. AsL wAs Reasonabl Achievable ALARA a.
Ins ection Sco e 83750 To determine whether the licensee was meeting commitments to make reasonable efforts to ensure that occupational radiation exposures were maintained ALAR Observations and Findin s The licensee's ALARAreport for RFO7 was a good management and assessment tool and was useful in preparation for'FO8 During RFO7, ALARAgoals were exceeded when the duration of the outage exceeded the goal ~ As a result, the collective dose of 133.9 person-rem was higher than the goal of 121.4 person-rem.
However, the collective dose for RFO 7 was still lower than previous RFOs.
Licensee ALARAgoals for RFO8 included, a collective radiation dose goal less than 101.35 person-rem.
On day 14 of RFO8 the collective radiation doses (54.957)
were approximately 7 percent greater than the projected dose (51.535)
~
Emergent work and scaffolding were adversely effecting the collective dose goals.
Site senior management and the staff appeared very knowledgeable of the collective dose goals and status and continued to emphasize ALARA. The status of collective dose was frequently discussed in planning meetings.
The licensee utilized licensee Chemistry procedure CRC -160, "Plant Start-Up and Shutdown Chemistry Checklist," Rev. 13, to control chemistry conditions of the reactor coolant system and facilitate the reduction of primary system contamination levels and dose rates.
Licensee documentation indicated the procedure had been effective in removing contamination from the primary system.
Some steam generator channel head and bowl doses were slightly higher or lower than previous system cleanups but overall compared well with previous system cleanups.
The site's collective dose goal for non-outage periods was less than 19.480 person-rem which the site had been meeting throughout the year. Through September, the non-outage dose was approximately 10 person-rem.
The radioactive waste tank de-sludging activities appeared to be a good example of management commitment to the ALARAprogram.
The licensee has seen the reduction of radiation levels in several liquid waste collection tanks and anticipated the elimination of several locked high radiation areas.
The de-sludging should also improve effluent quality and help reduce the number of system filterchange outs and collective doses associated with those activities. These activities were also described in NRC Inspection Report 50-400/98-08.
c.
Conclusions The ALARAprogram was effective in reducing site collective personnel radiation doses.
Quality Assurance in RP&C Activities R7.1 Documentation and Corrective Actions Ins ection Sco e 83750 A review of RP items documented in the licensee's corrective action tracking program was made to identify trends and to evaluate the adequacy of licensee corrective action The inspectors noted that the threshold for placing RP issues into the licensee's corrective
- action program appeared to be appropriate, The analysis of the problems was generally good with corrective actions to prevent recurrence prescribed.
Overall the reports appeared to determine causes and implement corrective actions.
However, one condition report concerning the overflow of a floor drain that contaminated an area in the radioactive waste processing building had failed to determine a probable cause of the event. The inspectors reported to licensee management that the event could be a precursor to a more serious 'radiation control event and an opportunity to identify the cause was missed with the limited investigation.
Licensee staff reported the event would be reviewed further to attempt to determine the cause of the event.
The inspectors also reviewed a recently completed observation report by the quality assurance staff for the period of October 23-30.
The report identified several concerns related to outage activities in several program areas, including radiation worker practices.
Such critical reviews provide evidence the Harris staff was self-identifying problems early in the refueling outage and taking measures to improve performance and compliance.
C.
Conclusions-A review of RP items in the licensee's corrective action program concluded that the threshold for placing issues into the program was appropriate.
The analysis of problems was generally good with corrective actions to prevent recurrence prescribed.
Quality assurance reviews during the RFO provided evidence that Harris was self-identifying problems and taking measures to improve performance and compliance.
S1 Conduct of Security and Safeguards Activities S1.1 General Comments 71750 The inspector found the performance of these activities was in accordance with applicable procedures and the security plan. Compensatory measures were posted when necessary and properly conducted.
't F1 Control of Fire Protection Activities F1.1 General Comments 71750 Fire Protection activities were being adequately conducted in accordance with required procedure X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on November 12. 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, l&C Electrical Systems J. Collins, Manager, Maintenance J. Cook, Manager, Outage and Scheduling J. Donahue, Director of Site Operations 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.'anDenburgh, Manager, Regulatory Affairs allace, Senior Analyst, Licensing S. Flanders, Harris Project Manager', NRR.
B. Bonser, Chief, Reactor Projects Branch 4
INSPECTION PROCEDURES USED IP 37550:
IP 37551:
IP 40500:
IP 55050:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 73753:
IP 83750:
IP 92901:
IP 92902:
IP 92903:
IP 93702:
Engineering Onsite Engineering Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Nuclear Welding General Inspection Procedure Surveillance Observations Maintenance Observation Plant Operations Plant Support Activities Inservice Welding Occupational Radiation Exposure Follow-up - Plant Operations Follow-up - Maintenance Follow-up - Engineering Prompt Onsite Response to Events at Operating Power Reactors
"I
~Oened
ITEMS OPENED, CLOSED, AND DISCUSSED 50-400/98-09-01 NCV 50-400/98-09-02 VIO Failure to Develop Adequate Instructions for Clearance Restoration (Section 07.2).
Failure to Translate Design Requirements into Maintenance Procedures for Agastat E7000 Series Relays (Section E2.2).
Closed 50-400/98-09-01 NCV 50-400/98-04-01 VIO
'50-400/98-03-01 VIO 50-400/98-003-00 LER 50-400/98-01-03 VIO 50-400/97-13-03 URI Discussed 50-400/98-01-01
'IO Failure to Develop Adequate Instructions for Clearance Restoration (Section 07.2).
Clearance Tag Not Hung (Section 08.1).
Failure to Properly Classify Condition Reports (2 Examples).
(Section 08.3)
Failure to Perform Shutdown Margin Calculation required by Technical Specification Surveillance Requirements (Section M8.1).
Failure to Perform Shutdown Margin Calculation Required by Technical Specification Surveillance Requirements (Section M8.1).
Extent of Condition Review for PNSC Action Item 97-04482-2, Pending NRC Review of the Extent of Condition Determination for This Problem, and the Identified Root Causes (Section E8.1) ~
Failure to Follow Procedure, Example 1, Properly Check Main Control Room Chart Recorders (Section 08.2).