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{{IR-Nav| site = 05000400 | year = 2004 | report number = 007 | url = https://www.nrc.gov/reactors/operating/oversight/reports/har_2004007.pdf }}
{{Adams
| number = ML041540256
| issue date = 05/25/2004
| title = IR 05000400-04-007, on 03/22/2004 - 03/26/2004 & 04/12/2004 - 04/16/2004, Shearon Harris Nuclear Power Plant Unit 1, New Hill, Nc; Plant Design - Pilot Enclosures 1, 2, & 3
| author name = Ogle C
| author affiliation = NRC/RGN-II/DRS/EB
| addressee name = Scarola J
| addressee affiliation = Carolina Power & Light Co
| docket = 05000400
| license number = NPF-063
| contact person =
| document report number = IR-04-007
| document type = Inspection Report, Letter
| page count = 34
}}
 
{{IR-Nav| site = 05000400 | year = 2004 | report number = 007 }}
 
=Text=
{{#Wiki_filter:May 25, 2004
 
==SUBJECT:==
SHEARON HARRIS NUCLEAR POWER PLANT - NRC PLANT DESIGN -
PILOT INSPECTION REPORT NO. 05000400/2004007
 
==Dear Mr. Scarola:==
On April 16, 2004, the Nuclear Regulatory Commission (NRC) completed a pilot, plant design inspection at your Shearon Harris reactor facility. The enclosed report documents the inspection findings which were discussed on April 16, 2004, with you and other members of your staff.
 
This inspection was an examination of activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations, and with the conditions of your operating license. Within these areas, the inspection involved selected examination of procedures and representative records, observations of activities, and interviews with personnel.
 
Based on the results of the inspection, no findings of significance were identified.
 
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
 
Sincerely,
/RA/
Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Docket No.:
50-400 License No.:
NPF-63
 
===Enclosure:===
(See page 2)
 
CP&L
 
Enclosure:
NRC Inspection Report No. 05000400/2004007 w/Attachment: Supplemental Information
 
REGION II==
Docket No.:
50-400 License No.:
NPF-63 Report No.:
05000400/2004007 Licensee:
Carolina Power & Light Company Facility:
Shearon Harris Nuclear Power Plant, Unit 1 Location:
5413 Shearon Harris Road New Hill, NC 27562 Dates:
March 22-26, 2004 April 12-16, 2004 Inspectors:
J. Moorman, Senior Reactor Inspector (Lead Inspector)
G. Hopper, Senior Operator Licensing Examiner N. Merriweather, Senior Reactor Inspector M. Scott, Senior Reactor Inspector (Week 1 only)
K. VanDoorn, Senior Reactor Inspector (Week 1 only)
R. Cortes, Reactor Inspector S. Rudisail, Reactor Inspector Accompanied by:
C. Ogle, Chief, Engineering Branch 1 N. Staples, Reactor Inspector Intern R. Rodriguez, Reactor Inspector Intern Approved by:
Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety
 
Enclosure
 
=SUMMARY OF FINDINGS=
IR 05000400/2004007; 03/22-26/2004 and 04/12-16/2004; Shearon Harris Nuclear Power
 
Plant, Unit 1; Plant Design - Pilot, Enclosures 1, 2, and 3.
 
This inspection was conducted by a team of regional inspectors. No findings of significance were identified. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
 
===NRC-Identified and Self-Revealing Findings===
No findings of significance were identified.
 
===Licensee-Identified Violations===
None.
 
=REPORT DETAILS=
 
==REACTOR SAFETY==
Cornerstones: Initiating Events, Mitigating Systems and Barrier Integrity 1R.DS Plant Design - Pilot (71111.DS)1R.DS1 Safety System Design and Performance Capability (71111.DS, Enclosure 1)
This team inspection reviewed selected components and operator actions that would be used to prevent or mitigate the consequences of a steam generator tube rupture (SGTR) event. Components in the main steam (MS) system, auxiliary feedwater (AFW)system, steam generator (SG) blowdown system, chemical and volume control system (CVCS), reactor coolant system (RCS), safety injection (SI) system, and radiation monitoring system were included. This inspection also examined supporting equipment, equipment which provides power to these components, and the associated instrumentation and controls. The SGTR event is a risk-significant event as determined by the licensees probabilistic risk assessment.
 
===.1 System Needs===
===.11 Process Medium===
====a. Inspection Scope====
The team reviewed the AFW and high head safety injection (HHSI) net positive suction head and water source calculations, operating/lineup procedures, drawings, licensing and design basis information, surveillance procedures, and vendor manuals. The review included the ability of the steam generator power operated relief valves (PORVs)to support RCS cooldown, and the ability of the HHSI pumps to provide cooling of the RCS. The review also included the refueling water storage tank (RWST) with emphasis on post-accident make-up capability, the condensate storage tank (CST), including minimum-flow flowpaths for AFW and HHSI pumps and vortexing considerations. The team also conducted field walkdowns of the systems in the plant to verify that system design, Technical Specifications (TS), and Updated Final Safety Analysis Report (UFSAR) assumptions were consistent with the actual capability of systems and equipment required to mitigate an SGTR event.
 
====b. Findings====
No findings of significance were identified.
 
===.12 Energy Sources===
====a. Inspection Scope====
The team walked down the energy sources of selected components to verify that selected portions of the systems alignment were consistent with the design basis assumptions, performance requirements, and system operating procedures. The team reviewed valve lineup procedures for the steam supply to the turbine-driven AFW pump and the sources of air for air operated valves (AOVs) such as the pressurizer PORVs.
 
The team also reviewed the testing and maintenance history for these AOVs to assess the reliability and availability of alternate air sources.
 
The team reviewed voltage drop calculations for a sample of safety-related loads such as motors, valve operators, inverters, and radiation monitors to verify that adequate voltage would be available at the end device during worst case minimum grid operating voltage conditions. The team also reviewed surveillance records on breaker alignment checks and bus voltage readings to verify that these checks were being performed in accordance with the requirements specified in the TS. The calculations reviewed are listed in the Attachment. The specific components reviewed are listed below:
* AFW pump motors
* SI pump motors
* Vital Inverters
* 125 volts direct current (VDC) batteries
* Battery chargers
* 6.9 Kilo-Volt (kV) switchgear
 
====b. Findings====
No findings of significance were identified.
 
===.13 Instrumentation and Controls===
====a. Inspection Scope====
The team examined, on a sample basis, instrumentation and indication that are used by operators for detection of primary to secondary leakage and an SGTR event, as well as selected control circuits used for SGTR event mitigation. Instrumentation identified for detection of an SGTR event included the main steam line radiation monitors (on each of 3 main steam lines), liquid radiation monitor assembly (i.e., steam generator blowdown),condensor vacuum pump effluent treatment system radiation monitor, and SG narrow range level instruments. Instruments and indications used by operators for mitigation of the event included condensate storage tank level, refueling water storage tank level, and SG narrow range level. For these instruments, the team reviewed the SGTR accident analysis, instrument loop drawings, scaling calculations, surveillance calibration test procedures, annunciator response procedures, and other design documents establishing the basis for calibration and alarm setpoints, to confirm that the calibration, setpoints, and emergency operating procedures were consistent with the design and licensing basis.
 
For controls used in SGTR mitigation, the team reviewed various electrical drawings of the control circuits for the steam generator PORVs, the pressurizer PORVs, auxiliary feedwater flow control valves, and the automatic initiation and shutdown controls (including low suction pressure trip instrumentation) for the motor driven and turbine driven auxiliary feedwater pumps to confirm that the control circuits implemented the functional logic requirements described by the design basis documents.
 
====b. Findings====
No findings of significance were identified.
 
===.14 Operator Actions===
====a. Inspection Scope====
The team reviewed plant operating procedures (OPs), emergency operating procedures (EOPs), abnormal operating procedures (APs), and annunciator response procedures that would be used in the identification and mitigation of an SGTR event. Specific procedures reviewed are included in the Attachment to this report.
 
The review was done to verify that the procedures were consistent with the UFSAR description of an SGTR event and with the Westinghouse Owners Group Emergency Response Guidelines, including the periodic updates. In addition, the team compared the procedural requirements against the EPRI guidelines requiring early action for plant shutdown after leak detection. The team reviewed step deviation justifications and compared each step against the requirements of Procedure OMM-006, Emergency Operating Procedure Writers Guide to verify that procedures were written clearly and unambiguously. The team conducted discussions with licensed operators and reviewed job performance measures and training documents pertaining to an SGTR event to ensure that training was consistent with the procedures.
 
In addition, the team observed a simulation of an SGTR event on the plant simulator to verify that operator training, procedural guidance, and instrumentation were adequate to identify an SGTR event and implement post-event mitigation strategies. The operator action times for performance of SGTR event mitigation activities were observed and compared against those stated in the UFSAR accident analyses for steam generator overfill.
 
The team also conducted plant walkdown inspections for selected local operator actions to verify that the installed configuration and system alignments were consistent with design basis assumptions and procedural guidance. These actions included local manual isolation of a stuck open atmospheric dump valve, refilling the reactor water storage tank with borated water, local operation of an atmospheric dump valve, and auxiliary feedwater lineup.
 
====b. Findings====
No findings of significance were identified.
 
===.15 Heat Removal===
====a. Inspection Scope====
The team reviewed design calculations, drawings, and surveillance and test procedures for selected equipment to assess the reliability and availability of equipment used to provide cooling for the HHSI pumps and AFW pumps. The team conducted field walkdowns of the equipment to verify that operating conditions were consistent with design assumptions. The equipment reviewed was reviewed to verify that there was adequate cooling for these pumps at both full and minimum flow conditions. The team also verified design calculations, machinery history, and heat transfer removal capability for the HHSI pump room air handling units to ensure adequate room cooling during design basis events.
 
====b. Findings====
No findings of significance were identified.
 
===.2 System Condition and Capability===
===.21 Installed Configuration===
====a. Inspection Scope====
The team performed field walkdowns of selected components in the HHSI, AFW, MS, service water and emergency service water (ESW) systems to assess observable material condition and the installed configuration of components. This review was also conducted to verify that selected valves and components in these systems were in their required position and that the configuration was consistent with design drawings. The team reviewed action requests on foreign material exclusion and on the CST bladder with emphasis on possible bladder material deterioration and other failure mechanisms that could lead to obstruction the AFW pump suction.
 
The team reviewed design drawings and walked down the accessible portions of the main steam line monitors, the liquid radiation monitor assembly (SG blowdown), and the condenser vacuum pump effluent treatment system radiation monitor, to confirm that the instrument configurations were installed consistent with the plant design. The team specifically sought to verify that the radiation detector locations, power supplies, as well as, control room indicators, annunciators, and setpoints, were consistent with design drawings and the UFSAR description of the radiation monitor channels. The team performed field walkdowns and/or reviewed the design drawings to verify that the taps for the RWST and CST level instruments were located so as to preclude adverse velocity effects on the process measurement. In addition, the team visually inspected the routing of the tubing and measured the installed elevations of the CST level and AFW suction pressure transmitters to verify that the instruments were located consistent with design drawings as well as scaling and setpoint calculations.
 
The team also performed field inspections of portions of the Class 1E electrical distribution system; including the 6900 volts alternating current (VAC) switchgear, 480 VAC load centers, 480 VAC motor control centers, and 125 VDC batteries, chargers, and panels. The purpose of the inspections was to assess general material condition, verify that system alignments were consistent with design and licensing basis assumptions, and to identify degraded conditions of SGTR mitigation equipment.
 
====b. Findings====
No findings of significance were identified.
 
===.22 Operation===
====a. Inspection Scope====
The team performed field walkdowns of selected components specified in the SGTR EOP for which local operation or main control room operation was required to verify that operators could adequately determine component status and that the components could be operated under conditions that would exist during an SGTR event. These components included the turbine driven AFW steam supply motor operated valve (MOV), and the SG PORVs. Another aspect that was reviewed was post-accident RWST make-up capability using the CVCS. The team reviewed machinery history and performed field walkdowns of the boric acid transfer pumps, the make-up water pumps and selected valves located between the boric acid tank and reactor makeup water storage tank to the RWST to verify that operators could adequately operate the system during an SGTR event.
 
====b. Findings====
No findings of significance were identified.
 
===.23 Design===
====a. Inspection Scope====
Mechanical Design The team reviewed vendor manuals for the HHSI and AFW pumps, vendor manuals for selected flow control valves, the UFSAR, and the TS to verify that vendor recommendations and licensing basis requirements had been appropriately translated into design calculations and surveillance requirements. The team also reviewed the design of the AFW flow control valves and minimum-flow lines to determine if operating experience items were applicable to this design. In addition, net positive suction head calculations and head curve data for both the AFW and HHSI pumps were reviewed to verify that adequate water levels were available in the CST and RWST. Vortexing considerations were also reviewed.
 
The team reviewed records of preventive maintenance and performed field walkdowns of selected components in the HHSI, CVCS, ESW, MS, and AFW systems to verify that these activities were maintaining the assumptions of the licensing and design bases.
 
During these reviews, the team focused on potential common mode failure vulnerabilities that could be introduced by design or maintenance activities.
 
Instrumentation and Controls Design The team reviewed instrument detail drawings showing installed transmitter and sensing line elevations, process instrumentation control scaling calculations, and level setpoint calculations of the CST, RWST, AFW suction pressure instrument channels to determine if the setpoints for the level alarms and interlocks (e.g., high, low, low-low, and empty RWST tank levels) were correctly established to meet technical specifications and the design performance requirements of the system. In addition, the surveillance and calibration test procedures and test records were reviewed for the above instruments to verify that they specified setpoints consistent with the results of the setpoint calculations or applicable scaling documents. The team also reviewed a sample of replacement part evaluations involving both commercial grade and safety-related parts to determine if appropriate critical attributes were identified and appropriately addressed in the evaluations.
 
Electrical The team reviewed records of completed design changes, corrective maintenance, and preventive maintenance; and walked down selected components of the AFW, SI, 6900 VAC, 125 VDC and 120 VAC systems to verify that these activities were maintaining the assumptions of the licensing and design bases. During these reviews, the team focused on potential common mode failure vulnerabilities that could be introduced by design or maintenance activities.
 
====b. Findings====
No findings of significance were identified.
 
===.24 Testing and Inspection===
====a. Inspection Scope====
The team reviewed records of preventive maintenance, maintenance history, surveillance tests, inspections, and performed field walkdowns of selected components in the RCS, HHSI, CVCS, AFW and MS systems to verify that the tests and inspections were appropriately verifying that the assumptions of the licensing and design bases were being maintained. This review included testing of HHSI and AFW pump discharge pressures and flowrates during full and recirculation flow conditions, MOV torque and limit switch settings, relief valve pressure set point opening, check valve operation; and analysis of pump bearing oil and vibration. A more detailed list of the components reviewed is provided in the Attachment.
 
The team reviewed calibration test records and/or channel operational tests for the following instrument channels:
* main steam line radiation monitor
* SG blowdown radiation monitor
* condenser vacuum pump radiation monitor
* CST level
* RWST level
* AFW slave relays
* AFW suction pressure transmitters
* AFW time delay relays The calibration test records were reviewed to confirm that test acceptance criteria were satisfied or that appropriate corrective actions had been taken.
 
The team reviewed records of completed surveillance tests, performance tests, inspections, and predictive maintenance; and walked down selected components of the SI, AFW, 125 VDC, 6900 VAC systems to verify that the tests and inspections were appropriately verifying that the assumptions of the licensing and design bases were being maintained.
 
The team reviewed the surveillance testing and test records for the 125 VDC batteries to verify that the battery capacity was adequate to supply and maintain in operable status, the required emergency loads for the design basis duty cycle.
 
====b. Findings====
No findings of significance were identified.
 
===.3 Selected Components===
===.31 Component Degradation===
====a. Inspection Scope====
The team reviewed systems with Maintenance Rule functional failures, maintenance records, action requests, and performance trending of selected components in the RCS, HHSI, ESW, AFW, MS, demineralizer water, boric acid transfer and instrument air (IA)systems to verify that components that were relied upon to mitigate an SGTR event were not degrading to unacceptable performance levels. Among the selected components were safety reliefs, AOVs, MOVs, manual valves, check valves, room coolers and pumps. A more detailed list of components reviewed is provided in the
.
The team conducted plant walkdowns and reviewed drawings of the turbine driven AFW steam supply piping to verify the inclusion of steam drains that would prevent water accumulation in the piping. The team also performed walkdowns to assess the observable material condition of the components shown in the Attachment.
 
The team visually inspected the as-built configuration of the condenser vacuum pump effluent radiation monitor, SG blowdown radiation monitor, CST level, and AFW suction pressure transmitters to confirm that the visible material condition of the impulse lines, instruments, supports, and connections was adequate with no components degraded (e.g., rusting, missing parts, or leaking fluids). The team also confirmed that the instruments were physically separated from redundant channels.
 
The team reviewed the maintenance history for the electrical components listed below to determine their current performance capability to mitigate an SGTR event.
* AFW pump motor breakers
* 125 VDC batteries
* 125 VDC battery chargers
* vital inverters Specifically the team reviewed:
* each components maintenance history by reviewing selected corrective-maintenance and preventive-maintenance work order summaries and trends of component performance data, to verify that unexpected degradation had not been found, and that performance problems had not reappeared; and
* each components preventive-maintenance schedule, to verify that the schedule was based either on vendor recommendations or appropriate industry experience.
 
====b. Findings====
No findings of significance were identified.
 
===.32 Equipment/Environmental Qualification===
====a. Inspection Scope====
The team reviewed environmental qualification requirements in the vendor manuals for major components in the AFW, MS, and HHSI systems. The team then performed field walkdowns of the components to assess suitability of the environment in terms of temperature and humidity anticipated under accident conditions, including high energy line breaks.
 
The team reviewed preventive maintenance records for selected Class 1E electrical equipment to verify that environmental qualification requirements were being implemented during mentioned activities. Specifically, while reviewing calibration procedures for steam generator level transmitters included in the licensees environmental qualification program, the team confirmed that appropriate requirements were included for replacement of O-ring seals as required to maintain qualification.
 
In addition, the team reviewed preventive maintenance records for the main steam radiation monitors ( i.e., Work Orders 0018037001, 0018036901, and 0018235201 ) in order to verify that the batteries were being or had been replaced within the 4.5 year replacement frequency required by the PM program and vendor recommendations.
 
====b. Findings====
No findings of significance were identified.
 
===.33 Equipment Protection===
====a. Inspection Scope====
The team performed field walkdowns of selected components in the HHSI, MS, AFW, CVCS and service water systems to verify that the components were adequately protected from potential effects of missiles, flooding, high winds and high or low outdoor temperatures.
 
The team visually inspected the main steam radiation monitors, condenser vacuum pump radiation monitor, and steam generator blowdown radiation monitor to confirm that the instruments and connections were not vulnerable to the effects of design basis events for which they were credited to be functional, including the effects of extreme ambient temperatures and background dose rates.
 
In addition to the above, the team reviewed the equipment specifications for the SG PORVs, pressurizer PORVs, RWST level, CST level, SG narrow range level, and AFW suction pressure transmitters to verify the design was adequate for anticipated ambient conditions and system application.
 
====b. Findings====
No findings of significance were identified.
 
===.34 Loose Parts Monitoring===
====a. Inspection Scope====
The team reviewed historical records on the operational performance of the digital metal impact monitoring system (DMIMS) to assess whether the system was operational and was being used by the licensee to monitor for loose parts in the reactor coolant system and steam generators consistent with the licensing and design basis for the plant.
 
Specifically, the team reviewed documentation demonstrating that the system had been tested and calibrated in accordance with the surveillance test program. The team also reviewed an Alarm Event Summary of the DMIMS, an Action Request, and an Action Plan (Rev.0) as well as the results from SG C secondary side tubesheet inspection to determine if alarms previously received on SG C DMIMS Channels 758 and 759 were properly evaluated by the licensee to determine the significance on plant operation.
 
====b. Findings====
No findings of significance were identified.
 
===.35 Operating Experience===
====a. Inspection Scope====
The team reviewed the licensees applicability evaluations and corrective actions for industry experience issues related to radiation monitors and SG level uncertainties. The specific documents reviewed are listed in the Attachment to this report.
 
====b. Findings====
No findings of significance were identified.
 
===.4 Identification and Resolution of Problems===
====a. Inspection Scope====
The team reviewed a sample of Action Requests as well as corrective maintenance work order records initiated over the past three years, to confirm that the licensee was adequately identifying, evaluating, and dispositioning adverse conditions. The specific documents reviewed are listed in the Attachment.
 
====b. Findings====
No findings of significance were identified.
1R.DS2 Permanent Plant Modifications (71111.DS, Enclosure 2)
 
====a. Inspection Scope====
The team evaluated design change packages for eight modifications, in all three cornerstone areas, to verify that the modifications did not degrade system availability, reliability, or functional capability. The team reviewed attributes such as: energy requirements can be supplied by supporting systems; materials and replacement components were compatible with physical interfaces; replacement components were seismically qualified for application; Code and safety classification of replacement system, structures, and components were consistent with design bases; modification design assumptions were appropriate; post-modification testing established operability; failure modes introduced by the modification were bounded by existing analyses; and appropriate procedures or procedure changes had been initiated. For selected modification packages, the team reviewed the as-built configuration to verify that it was consistent with the design documentation.
 
Documents reviewed included procedures, engineering calculations, modification packages, work orders, site drawings, corrective action documents, applicable sections of the UFSAR, supporting analyses, TS, and design basis documentation. The samples reviewed are listed below:
* ESR 00-00322, Component Cooling Water System Design Pressure Increase
* ESR 00-00197, AFW Substitution and Relocation Evaluation
* ESR 01-00014, Ground Detector Relay Replacement for TDAFW
* EC 52543, MSIV Damaged Threads
* EC 48993, ECCS High Point Vent Installations
* ESR 00-00336, Motor Replacement for MOVs 1AF-55, 74, and 93
* ESR 01-00061, PORV Block Valve Fuse Coordination
* ESR 01-0013, Temporary Modification Affecting Switchover to ACP The team also reviewed selected Action Requests (ARs) to confirm that problems were identified at the appropriate threshold, were entered into the corrective action program, and appropriate corrective actions had been initiated. These documents are listed in the
.
 
====b. Findings====
No findings of significance were identified.
1R.DS3 10 CFR 50.59 Safety Evaluations (71111.DS, Enclosure 3)
 
====a. Inspection Scope====
The team reviewed selected samples of evaluations to verify that the licensee had appropriately considered the conditions under which changes to the facility or procedures may be made, and tests conducted, without prior NRC approval. The team reviewed evaluations for six changes. The team verified, through review of additional information, such as calculations, supporting analyses and drawings that the licensee had appropriately concluded that the changes could be accomplished without obtaining a license amendment. The six evaluations reviewed are listed below:
* ESR 00-00322, Component Cooling Water System Design Pressure Increase
* ESR 01-00014, Ground Dectector Relay Replacement for TDAFW
* ESR 00-00294, PORV Cycling During SGTR
* ESR 01-00087, Chemical and Volume Control System Recirculation Flow Path Change
* ESR 01-00005, RCP Standpipe Alarms
* Evaluation No. 01-0013, Temporary Modification affecting Switchover to ACP The team also reviewed samples of design and engineering packages and procedure changes for which the licensee had determined that evaluations were not required. This review was performed to verify that the licensees conclusions to screen out these changes were correct and consistent with 10 CFR 50.59. The ten screened out changes reviewed are listed below:
* ESR 01-00197, AFW Substitution and Relocation Evaluation
* Emergency Operating Procedure PATH-1, Rev. 14
* Emergency Operating Procedure PATH-2, Rev. 13
* ESR 00-00336; Motor Replacement for MOVs 1AF-55, 74, and 93
* ESR 01-00061, PORV Block Valve Fuse Coordination
* EC 51918, Service Water Booster Pump B Annunciator Relay Causes Blowdown Relays to Cycle
* EC 52295, Update of Calculation for Degraded Voltage Relay Tolerance
* Abnormal Operating Procedure 004, Remote Shutdown, Rev. 28
* EC 52543, MSIV Damaged Threads
* EC 48993, ECCS High Point Vent Installations The team also reviewed the results of a recent self-assessment report (57664; Processing of Changes, Tests, and Experiments) of engineering activities and ARs related to the 10 CFR 50.59 process, to confirm that problems were identified at the appropriate threshold, were entered in the corrective action process, and appropriate corrective actions had been initiated. The ARs are listed in the Attachment.
 
====b. Findings====
No findings of significance were identified.
 
===4. OTHER ACTIVITIES===
{{a|4OA6}}
 
==4OA6 Meetings, Including Exit==
The lead inspector presented the inspection results to Mr. J. Scarola, and other members of the licensee staff, at an exit meeting on April 16, 2004. The licensee acknowledged the findings presented. Proprietary information is not included in this inspection report.
 
=SUPPLEMENTAL INFORMATION=
 
==KEY POINTS OF CONTACT==
Licensee
: [[contact::D. Baska]], Supervisor, Equipment Performance
: [[contact::J. Caves]], Supervisor, Licensing
: [[contact::F. Dean]], Senior Engineer
: [[contact::F. Diya]], Engineering Manager
: [[contact::J. Dufner]], Supervisor, Reactor Support
: [[contact::W. Gurganious]], Manager, Nuclear Assessment
: [[contact::C. Hemming]], Senior Engineer
: [[contact::I. LaCross]], Senior Engineer
: [[contact::E. McCartney]], Training Manager
: [[contact::M. Moss]], Supervisor, Radiation Protection
: [[contact::R. Mullis]], PES Assessor
: [[contact::S. OConnor]], Superintendent, Design Engineering
: [[contact::W. Ponder]], Lead Engineer
: [[contact::M. Robinson]], Superintendent, Chemistry
: [[contact::J. Scarola]], Site Vice-President
: [[contact::M. Wallace]], Senior Specialist, Licensing
: [[contact::M. Weber]], Superintendent, Operations Support
: [[contact::J. Yadusky]], Lead Licensing Engineer
NRC (attended exit meeting)
: [[contact::C. Ogle]], Chief, Engineering Branch 1, Division of Reactor Safety
: [[contact::R. Musser]], Senior Resident Inspector
: [[contact::P. OBryan]], Resident Inspector
 
==LIST OF ITEMS==
===OPENED, CLOSED AND DISCUSSED===
None.
 
==LIST OF DOCUMENTS REVIEWED==
 
}}

Latest revision as of 02:47, 16 January 2025

IR 05000400-04-007, on 03/22/2004 - 03/26/2004 & 04/12/2004 - 04/16/2004, Shearon Harris Nuclear Power Plant Unit 1, New Hill, Nc; Plant Design - Pilot Enclosures 1, 2, & 3
ML041540256
Person / Time
Site: Harris Duke Energy icon.png
Issue date: 05/25/2004
From: Ogle C
NRC/RGN-II/DRS/EB
To: Scarola J
Carolina Power & Light Co
References
IR-04-007
Download: ML041540256 (34)


Text

May 25, 2004

SUBJECT:

SHEARON HARRIS NUCLEAR POWER PLANT - NRC PLANT DESIGN -

PILOT INSPECTION REPORT NO. 05000400/2004007

Dear Mr. Scarola:

On April 16, 2004, the Nuclear Regulatory Commission (NRC) completed a pilot, plant design inspection at your Shearon Harris reactor facility. The enclosed report documents the inspection findings which were discussed on April 16, 2004, with you and other members of your staff.

This inspection was an examination of activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations, and with the conditions of your operating license. Within these areas, the inspection involved selected examination of procedures and representative records, observations of activities, and interviews with personnel.

Based on the results of the inspection, no findings of significance were identified.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Docket No.:

50-400 License No.:

NPF-63

Enclosure:

(See page 2)

CP&L

Enclosure:

NRC Inspection Report No. 05000400/2004007 w/Attachment: Supplemental Information

REGION II==

Docket No.:

50-400 License No.:

NPF-63 Report No.:

05000400/2004007 Licensee:

Carolina Power & Light Company Facility:

Shearon Harris Nuclear Power Plant, Unit 1 Location:

5413 Shearon Harris Road New Hill, NC 27562 Dates:

March 22-26, 2004 April 12-16, 2004 Inspectors:

J. Moorman, Senior Reactor Inspector (Lead Inspector)

G. Hopper, Senior Operator Licensing Examiner N. Merriweather, Senior Reactor Inspector M. Scott, Senior Reactor Inspector (Week 1 only)

K. VanDoorn, Senior Reactor Inspector (Week 1 only)

R. Cortes, Reactor Inspector S. Rudisail, Reactor Inspector Accompanied by:

C. Ogle, Chief, Engineering Branch 1 N. Staples, Reactor Inspector Intern R. Rodriguez, Reactor Inspector Intern Approved by:

Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety

Enclosure

SUMMARY OF FINDINGS

IR 05000400/2004007; 03/22-26/2004 and 04/12-16/2004; Shearon Harris Nuclear Power

Plant, Unit 1; Plant Design - Pilot, Enclosures 1, 2, and 3.

This inspection was conducted by a team of regional inspectors. No findings of significance were identified. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

NRC-Identified and Self-Revealing Findings

No findings of significance were identified.

Licensee-Identified Violations

None.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems and Barrier Integrity 1R.DS Plant Design - Pilot (71111.DS)1R.DS1 Safety System Design and Performance Capability (71111.DS, Enclosure 1)

This team inspection reviewed selected components and operator actions that would be used to prevent or mitigate the consequences of a steam generator tube rupture (SGTR) event. Components in the main steam (MS) system, auxiliary feedwater (AFW)system, steam generator (SG) blowdown system, chemical and volume control system (CVCS), reactor coolant system (RCS), safety injection (SI) system, and radiation monitoring system were included. This inspection also examined supporting equipment, equipment which provides power to these components, and the associated instrumentation and controls. The SGTR event is a risk-significant event as determined by the licensees probabilistic risk assessment.

.1 System Needs

.11 Process Medium

a. Inspection Scope

The team reviewed the AFW and high head safety injection (HHSI) net positive suction head and water source calculations, operating/lineup procedures, drawings, licensing and design basis information, surveillance procedures, and vendor manuals. The review included the ability of the steam generator power operated relief valves (PORVs)to support RCS cooldown, and the ability of the HHSI pumps to provide cooling of the RCS. The review also included the refueling water storage tank (RWST) with emphasis on post-accident make-up capability, the condensate storage tank (CST), including minimum-flow flowpaths for AFW and HHSI pumps and vortexing considerations. The team also conducted field walkdowns of the systems in the plant to verify that system design, Technical Specifications (TS), and Updated Final Safety Analysis Report (UFSAR) assumptions were consistent with the actual capability of systems and equipment required to mitigate an SGTR event.

b. Findings

No findings of significance were identified.

.12 Energy Sources

a. Inspection Scope

The team walked down the energy sources of selected components to verify that selected portions of the systems alignment were consistent with the design basis assumptions, performance requirements, and system operating procedures. The team reviewed valve lineup procedures for the steam supply to the turbine-driven AFW pump and the sources of air for air operated valves (AOVs) such as the pressurizer PORVs.

The team also reviewed the testing and maintenance history for these AOVs to assess the reliability and availability of alternate air sources.

The team reviewed voltage drop calculations for a sample of safety-related loads such as motors, valve operators, inverters, and radiation monitors to verify that adequate voltage would be available at the end device during worst case minimum grid operating voltage conditions. The team also reviewed surveillance records on breaker alignment checks and bus voltage readings to verify that these checks were being performed in accordance with the requirements specified in the TS. The calculations reviewed are listed in the Attachment. The specific components reviewed are listed below:

  • AFW pump motors
  • SI pump motors
  • Vital Inverters
  • 125 volts direct current (VDC) batteries
  • Battery chargers
  • 6.9 Kilo-Volt (kV) switchgear

b. Findings

No findings of significance were identified.

.13 Instrumentation and Controls

a. Inspection Scope

The team examined, on a sample basis, instrumentation and indication that are used by operators for detection of primary to secondary leakage and an SGTR event, as well as selected control circuits used for SGTR event mitigation. Instrumentation identified for detection of an SGTR event included the main steam line radiation monitors (on each of 3 main steam lines), liquid radiation monitor assembly (i.e., steam generator blowdown),condensor vacuum pump effluent treatment system radiation monitor, and SG narrow range level instruments. Instruments and indications used by operators for mitigation of the event included condensate storage tank level, refueling water storage tank level, and SG narrow range level. For these instruments, the team reviewed the SGTR accident analysis, instrument loop drawings, scaling calculations, surveillance calibration test procedures, annunciator response procedures, and other design documents establishing the basis for calibration and alarm setpoints, to confirm that the calibration, setpoints, and emergency operating procedures were consistent with the design and licensing basis.

For controls used in SGTR mitigation, the team reviewed various electrical drawings of the control circuits for the steam generator PORVs, the pressurizer PORVs, auxiliary feedwater flow control valves, and the automatic initiation and shutdown controls (including low suction pressure trip instrumentation) for the motor driven and turbine driven auxiliary feedwater pumps to confirm that the control circuits implemented the functional logic requirements described by the design basis documents.

b. Findings

No findings of significance were identified.

.14 Operator Actions

a. Inspection Scope

The team reviewed plant operating procedures (OPs), emergency operating procedures (EOPs), abnormal operating procedures (APs), and annunciator response procedures that would be used in the identification and mitigation of an SGTR event. Specific procedures reviewed are included in the Attachment to this report.

The review was done to verify that the procedures were consistent with the UFSAR description of an SGTR event and with the Westinghouse Owners Group Emergency Response Guidelines, including the periodic updates. In addition, the team compared the procedural requirements against the EPRI guidelines requiring early action for plant shutdown after leak detection. The team reviewed step deviation justifications and compared each step against the requirements of Procedure OMM-006, Emergency Operating Procedure Writers Guide to verify that procedures were written clearly and unambiguously. The team conducted discussions with licensed operators and reviewed job performance measures and training documents pertaining to an SGTR event to ensure that training was consistent with the procedures.

In addition, the team observed a simulation of an SGTR event on the plant simulator to verify that operator training, procedural guidance, and instrumentation were adequate to identify an SGTR event and implement post-event mitigation strategies. The operator action times for performance of SGTR event mitigation activities were observed and compared against those stated in the UFSAR accident analyses for steam generator overfill.

The team also conducted plant walkdown inspections for selected local operator actions to verify that the installed configuration and system alignments were consistent with design basis assumptions and procedural guidance. These actions included local manual isolation of a stuck open atmospheric dump valve, refilling the reactor water storage tank with borated water, local operation of an atmospheric dump valve, and auxiliary feedwater lineup.

b. Findings

No findings of significance were identified.

.15 Heat Removal

a. Inspection Scope

The team reviewed design calculations, drawings, and surveillance and test procedures for selected equipment to assess the reliability and availability of equipment used to provide cooling for the HHSI pumps and AFW pumps. The team conducted field walkdowns of the equipment to verify that operating conditions were consistent with design assumptions. The equipment reviewed was reviewed to verify that there was adequate cooling for these pumps at both full and minimum flow conditions. The team also verified design calculations, machinery history, and heat transfer removal capability for the HHSI pump room air handling units to ensure adequate room cooling during design basis events.

b. Findings

No findings of significance were identified.

.2 System Condition and Capability

.21 Installed Configuration

a. Inspection Scope

The team performed field walkdowns of selected components in the HHSI, AFW, MS, service water and emergency service water (ESW) systems to assess observable material condition and the installed configuration of components. This review was also conducted to verify that selected valves and components in these systems were in their required position and that the configuration was consistent with design drawings. The team reviewed action requests on foreign material exclusion and on the CST bladder with emphasis on possible bladder material deterioration and other failure mechanisms that could lead to obstruction the AFW pump suction.

The team reviewed design drawings and walked down the accessible portions of the main steam line monitors, the liquid radiation monitor assembly (SG blowdown), and the condenser vacuum pump effluent treatment system radiation monitor, to confirm that the instrument configurations were installed consistent with the plant design. The team specifically sought to verify that the radiation detector locations, power supplies, as well as, control room indicators, annunciators, and setpoints, were consistent with design drawings and the UFSAR description of the radiation monitor channels. The team performed field walkdowns and/or reviewed the design drawings to verify that the taps for the RWST and CST level instruments were located so as to preclude adverse velocity effects on the process measurement. In addition, the team visually inspected the routing of the tubing and measured the installed elevations of the CST level and AFW suction pressure transmitters to verify that the instruments were located consistent with design drawings as well as scaling and setpoint calculations.

The team also performed field inspections of portions of the Class 1E electrical distribution system; including the 6900 volts alternating current (VAC) switchgear, 480 VAC load centers, 480 VAC motor control centers, and 125 VDC batteries, chargers, and panels. The purpose of the inspections was to assess general material condition, verify that system alignments were consistent with design and licensing basis assumptions, and to identify degraded conditions of SGTR mitigation equipment.

b. Findings

No findings of significance were identified.

.22 Operation

a. Inspection Scope

The team performed field walkdowns of selected components specified in the SGTR EOP for which local operation or main control room operation was required to verify that operators could adequately determine component status and that the components could be operated under conditions that would exist during an SGTR event. These components included the turbine driven AFW steam supply motor operated valve (MOV), and the SG PORVs. Another aspect that was reviewed was post-accident RWST make-up capability using the CVCS. The team reviewed machinery history and performed field walkdowns of the boric acid transfer pumps, the make-up water pumps and selected valves located between the boric acid tank and reactor makeup water storage tank to the RWST to verify that operators could adequately operate the system during an SGTR event.

b. Findings

No findings of significance were identified.

.23 Design

a. Inspection Scope

Mechanical Design The team reviewed vendor manuals for the HHSI and AFW pumps, vendor manuals for selected flow control valves, the UFSAR, and the TS to verify that vendor recommendations and licensing basis requirements had been appropriately translated into design calculations and surveillance requirements. The team also reviewed the design of the AFW flow control valves and minimum-flow lines to determine if operating experience items were applicable to this design. In addition, net positive suction head calculations and head curve data for both the AFW and HHSI pumps were reviewed to verify that adequate water levels were available in the CST and RWST. Vortexing considerations were also reviewed.

The team reviewed records of preventive maintenance and performed field walkdowns of selected components in the HHSI, CVCS, ESW, MS, and AFW systems to verify that these activities were maintaining the assumptions of the licensing and design bases.

During these reviews, the team focused on potential common mode failure vulnerabilities that could be introduced by design or maintenance activities.

Instrumentation and Controls Design The team reviewed instrument detail drawings showing installed transmitter and sensing line elevations, process instrumentation control scaling calculations, and level setpoint calculations of the CST, RWST, AFW suction pressure instrument channels to determine if the setpoints for the level alarms and interlocks (e.g., high, low, low-low, and empty RWST tank levels) were correctly established to meet technical specifications and the design performance requirements of the system. In addition, the surveillance and calibration test procedures and test records were reviewed for the above instruments to verify that they specified setpoints consistent with the results of the setpoint calculations or applicable scaling documents. The team also reviewed a sample of replacement part evaluations involving both commercial grade and safety-related parts to determine if appropriate critical attributes were identified and appropriately addressed in the evaluations.

Electrical The team reviewed records of completed design changes, corrective maintenance, and preventive maintenance; and walked down selected components of the AFW, SI, 6900 VAC, 125 VDC and 120 VAC systems to verify that these activities were maintaining the assumptions of the licensing and design bases. During these reviews, the team focused on potential common mode failure vulnerabilities that could be introduced by design or maintenance activities.

b. Findings

No findings of significance were identified.

.24 Testing and Inspection

a. Inspection Scope

The team reviewed records of preventive maintenance, maintenance history, surveillance tests, inspections, and performed field walkdowns of selected components in the RCS, HHSI, CVCS, AFW and MS systems to verify that the tests and inspections were appropriately verifying that the assumptions of the licensing and design bases were being maintained. This review included testing of HHSI and AFW pump discharge pressures and flowrates during full and recirculation flow conditions, MOV torque and limit switch settings, relief valve pressure set point opening, check valve operation; and analysis of pump bearing oil and vibration. A more detailed list of the components reviewed is provided in the Attachment.

The team reviewed calibration test records and/or channel operational tests for the following instrument channels:

  • SG blowdown radiation monitor
  • condenser vacuum pump radiation monitor
  • AFW slave relays
  • AFW suction pressure transmitters
  • AFW time delay relays The calibration test records were reviewed to confirm that test acceptance criteria were satisfied or that appropriate corrective actions had been taken.

The team reviewed records of completed surveillance tests, performance tests, inspections, and predictive maintenance; and walked down selected components of the SI, AFW, 125 VDC, 6900 VAC systems to verify that the tests and inspections were appropriately verifying that the assumptions of the licensing and design bases were being maintained.

The team reviewed the surveillance testing and test records for the 125 VDC batteries to verify that the battery capacity was adequate to supply and maintain in operable status, the required emergency loads for the design basis duty cycle.

b. Findings

No findings of significance were identified.

.3 Selected Components

.31 Component Degradation

a. Inspection Scope

The team reviewed systems with Maintenance Rule functional failures, maintenance records, action requests, and performance trending of selected components in the RCS, HHSI, ESW, AFW, MS, demineralizer water, boric acid transfer and instrument air (IA)systems to verify that components that were relied upon to mitigate an SGTR event were not degrading to unacceptable performance levels. Among the selected components were safety reliefs, AOVs, MOVs, manual valves, check valves, room coolers and pumps. A more detailed list of components reviewed is provided in the

.

The team conducted plant walkdowns and reviewed drawings of the turbine driven AFW steam supply piping to verify the inclusion of steam drains that would prevent water accumulation in the piping. The team also performed walkdowns to assess the observable material condition of the components shown in the Attachment.

The team visually inspected the as-built configuration of the condenser vacuum pump effluent radiation monitor, SG blowdown radiation monitor, CST level, and AFW suction pressure transmitters to confirm that the visible material condition of the impulse lines, instruments, supports, and connections was adequate with no components degraded (e.g., rusting, missing parts, or leaking fluids). The team also confirmed that the instruments were physically separated from redundant channels.

The team reviewed the maintenance history for the electrical components listed below to determine their current performance capability to mitigate an SGTR event.

  • AFW pump motor breakers
  • 125 VDC batteries
  • 125 VDC battery chargers
  • vital inverters Specifically the team reviewed:
  • each components maintenance history by reviewing selected corrective-maintenance and preventive-maintenance work order summaries and trends of component performance data, to verify that unexpected degradation had not been found, and that performance problems had not reappeared; and
  • each components preventive-maintenance schedule, to verify that the schedule was based either on vendor recommendations or appropriate industry experience.

b. Findings

No findings of significance were identified.

.32 Equipment/Environmental Qualification

a. Inspection Scope

The team reviewed environmental qualification requirements in the vendor manuals for major components in the AFW, MS, and HHSI systems. The team then performed field walkdowns of the components to assess suitability of the environment in terms of temperature and humidity anticipated under accident conditions, including high energy line breaks.

The team reviewed preventive maintenance records for selected Class 1E electrical equipment to verify that environmental qualification requirements were being implemented during mentioned activities. Specifically, while reviewing calibration procedures for steam generator level transmitters included in the licensees environmental qualification program, the team confirmed that appropriate requirements were included for replacement of O-ring seals as required to maintain qualification.

In addition, the team reviewed preventive maintenance records for the main steam radiation monitors ( i.e., Work Orders 0018037001, 0018036901, and 0018235201 ) in order to verify that the batteries were being or had been replaced within the 4.5 year replacement frequency required by the PM program and vendor recommendations.

b. Findings

No findings of significance were identified.

.33 Equipment Protection

a. Inspection Scope

The team performed field walkdowns of selected components in the HHSI, MS, AFW, CVCS and service water systems to verify that the components were adequately protected from potential effects of missiles, flooding, high winds and high or low outdoor temperatures.

The team visually inspected the main steam radiation monitors, condenser vacuum pump radiation monitor, and steam generator blowdown radiation monitor to confirm that the instruments and connections were not vulnerable to the effects of design basis events for which they were credited to be functional, including the effects of extreme ambient temperatures and background dose rates.

In addition to the above, the team reviewed the equipment specifications for the SG PORVs, pressurizer PORVs, RWST level, CST level, SG narrow range level, and AFW suction pressure transmitters to verify the design was adequate for anticipated ambient conditions and system application.

b. Findings

No findings of significance were identified.

.34 Loose Parts Monitoring

a. Inspection Scope

The team reviewed historical records on the operational performance of the digital metal impact monitoring system (DMIMS) to assess whether the system was operational and was being used by the licensee to monitor for loose parts in the reactor coolant system and steam generators consistent with the licensing and design basis for the plant.

Specifically, the team reviewed documentation demonstrating that the system had been tested and calibrated in accordance with the surveillance test program. The team also reviewed an Alarm Event Summary of the DMIMS, an Action Request, and an Action Plan (Rev.0) as well as the results from SG C secondary side tubesheet inspection to determine if alarms previously received on SG C DMIMS Channels 758 and 759 were properly evaluated by the licensee to determine the significance on plant operation.

b. Findings

No findings of significance were identified.

.35 Operating Experience

a. Inspection Scope

The team reviewed the licensees applicability evaluations and corrective actions for industry experience issues related to radiation monitors and SG level uncertainties. The specific documents reviewed are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

.4 Identification and Resolution of Problems

a. Inspection Scope

The team reviewed a sample of Action Requests as well as corrective maintenance work order records initiated over the past three years, to confirm that the licensee was adequately identifying, evaluating, and dispositioning adverse conditions. The specific documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R.DS2 Permanent Plant Modifications (71111.DS, Enclosure 2)

a. Inspection Scope

The team evaluated design change packages for eight modifications, in all three cornerstone areas, to verify that the modifications did not degrade system availability, reliability, or functional capability. The team reviewed attributes such as: energy requirements can be supplied by supporting systems; materials and replacement components were compatible with physical interfaces; replacement components were seismically qualified for application; Code and safety classification of replacement system, structures, and components were consistent with design bases; modification design assumptions were appropriate; post-modification testing established operability; failure modes introduced by the modification were bounded by existing analyses; and appropriate procedures or procedure changes had been initiated. For selected modification packages, the team reviewed the as-built configuration to verify that it was consistent with the design documentation.

Documents reviewed included procedures, engineering calculations, modification packages, work orders, site drawings, corrective action documents, applicable sections of the UFSAR, supporting analyses, TS, and design basis documentation. The samples reviewed are listed below:

  • ESR 00-00322, Component Cooling Water System Design Pressure Increase
  • ESR 00-00197, AFW Substitution and Relocation Evaluation
  • ESR 01-00014, Ground Detector Relay Replacement for TDAFW
  • ESR 01-00061, PORV Block Valve Fuse Coordination
  • ESR 01-0013, Temporary Modification Affecting Switchover to ACP The team also reviewed selected Action Requests (ARs) to confirm that problems were identified at the appropriate threshold, were entered into the corrective action program, and appropriate corrective actions had been initiated. These documents are listed in the

.

b. Findings

No findings of significance were identified.

1R.DS3 10 CFR 50.59 Safety Evaluations (71111.DS, Enclosure 3)

a. Inspection Scope

The team reviewed selected samples of evaluations to verify that the licensee had appropriately considered the conditions under which changes to the facility or procedures may be made, and tests conducted, without prior NRC approval. The team reviewed evaluations for six changes. The team verified, through review of additional information, such as calculations, supporting analyses and drawings that the licensee had appropriately concluded that the changes could be accomplished without obtaining a license amendment. The six evaluations reviewed are listed below:

  • ESR 00-00322, Component Cooling Water System Design Pressure Increase
  • ESR 01-00014, Ground Dectector Relay Replacement for TDAFW
  • ESR 01-00087, Chemical and Volume Control System Recirculation Flow Path Change
  • ESR 01-00005, RCP Standpipe Alarms
  • Evaluation No. 01-0013, Temporary Modification affecting Switchover to ACP The team also reviewed samples of design and engineering packages and procedure changes for which the licensee had determined that evaluations were not required. This review was performed to verify that the licensees conclusions to screen out these changes were correct and consistent with 10 CFR 50.59. The ten screened out changes reviewed are listed below:
  • ESR 01-00197, AFW Substitution and Relocation Evaluation
  • Emergency Operating Procedure PATH-1, Rev. 14
  • Emergency Operating Procedure PATH-2, Rev. 13
  • ESR 01-00061, PORV Block Valve Fuse Coordination
  • EC 52295, Update of Calculation for Degraded Voltage Relay Tolerance
  • EC 48993, ECCS High Point Vent Installations The team also reviewed the results of a recent self-assessment report (57664; Processing of Changes, Tests, and Experiments) of engineering activities and ARs related to the 10 CFR 50.59 process, to confirm that problems were identified at the appropriate threshold, were entered in the corrective action process, and appropriate corrective actions had been initiated. The ARs are listed in the Attachment.

b. Findings

No findings of significance were identified.

4. OTHER ACTIVITIES

4OA6 Meetings, Including Exit

The lead inspector presented the inspection results to Mr. J. Scarola, and other members of the licensee staff, at an exit meeting on April 16, 2004. The licensee acknowledged the findings presented. Proprietary information is not included in this inspection report.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

D. Baska, Supervisor, Equipment Performance
J. Caves, Supervisor, Licensing
F. Dean, Senior Engineer
F. Diya, Engineering Manager
J. Dufner, Supervisor, Reactor Support
W. Gurganious, Manager, Nuclear Assessment
C. Hemming, Senior Engineer
I. LaCross, Senior Engineer
E. McCartney, Training Manager
M. Moss, Supervisor, Radiation Protection
R. Mullis, PES Assessor
S. OConnor, Superintendent, Design Engineering
W. Ponder, Lead Engineer
M. Robinson, Superintendent, Chemistry
J. Scarola, Site Vice-President
M. Wallace, Senior Specialist, Licensing
M. Weber, Superintendent, Operations Support
J. Yadusky, Lead Licensing Engineer

NRC (attended exit meeting)

C. Ogle, Chief, Engineering Branch 1, Division of Reactor Safety
R. Musser, Senior Resident Inspector
P. OBryan, Resident Inspector

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

None.

LIST OF DOCUMENTS REVIEWED