IR 05000324/2003008: Difference between revisions

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{{Adams
{{Adams
| number = ML033240610
| number = ML042160062
| issue date = 10/09/2003
| issue date = 08/02/2004
| title = IR 05000325-03-008, IR 05000324-03-008, on 08/11-15/2003 and 08/25-29/2003, Brunswick Steam Electric Plant, Units 1 and 2; Safety System Design and Performance Capability
| title = IR 05000324-03-008, Notification of Brunswick, Unit 2, Supplemental Inspection During Week of 08/23/2004
| author name = Ogle C
| author name = Fredrickson P
| author affiliation = NRC/RGN-II/DRS/EB
| author affiliation = NRC/RGN-II/DRP/RPB4
| addressee name = Keenan J
| addressee name = Gannon C
| addressee affiliation = Carolina Power & Light Co
| addressee affiliation = Carolina Power & Light Co
| docket = 05000324, 05000325
| docket = 05000324
| license number = DPR-062, DPR-071, NPF-037, NPF-066
| license number = DPR-062
| contact person =  
| contact person =  
| case reference number = -RFPFR
| document report number = IR-03-008
| document report number = IR-03-008
| document type = Inspection Report, Letter
| document type = Inspection Report, Letter
| page count = 45
| page count = 5
}}
}}


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=Text=
=Text=
{{#Wiki_filter:ber 9, 2003
{{#Wiki_filter:ust 2, 2004


==SUBJECT:==
==SUBJECT:==
BRUNSWICK SEAM ELECTRIC PLANT - NRC SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY INSPECTION - REPORT NOS. 05000325/2003008and 05000324/2003008
NOTIFICATION OF BRUNSWICK STEAM ELECTRIC PLANT UNIT 2 SUPPLEMENTAL INSPECTION - NRC INSPECTION REPORT 50-325/2003-08 AND 50-324/2003-08


==Dear Mr. Keenan:==
==Dear Mr. Gannon:==
This refers to the safety system design and performance capability team inspection conducted on August 11 -1 5 and August 2549,2003, at the Brunswick facility. The enclosed inspection report documents the inspection findings, which were discussed on August 29, 2003, with Mr. C. J. Gannon and other members of your staff. The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license. The team reviewed selected procedures and records, observed activities, and interviewed personnel.
In a Final Significance Determination letter, dated June 2, 2004, from Mr. Loren Plisco, the Region II Deputy Regional Administrator, you were informed that the NRC had concluded that the final significance determination of a Brunswick Steam Electric Plant Unit 2 finding associated with an emergency diesel generator jacket water cooling system leak, had been characterized as White (i.e., an issue of low to moderate safety significance, which may require additional NRC inspection). Also in this letter you were informed that, because Brunswick Unit 2 plant performance for this issue had been determined to be in the increased regulatory response band, we would use the NRC Action Matrix to determine the most appropriate NRC response for the finding, and notify you by separate correspondence of our determination.


Based on the results of this inspection, one finding of very low safety significance (Green) was identified. This issue was determined to involve a violation of NRC requirements. This finding has very low safety significance and has been entered into your corrective action program. However, the NflC is withholding the treatment of this issue as a non-cited violation as provided by Section VI.A.4 of the NRC's Enforcement Policy, pending our review of your corrective actions related to restoration of compliance. lf you contest this finding, you should provide a response with the basis for your concern, within 40 days of the date of this inspection report to the Nuclear flegulatory Commission, ATTN: Document Control Desk, Washington, BC 20555- *1001 ~ with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001 ; and the NRC Resident Inspector at the Brunswick faciiity.
The purpose of this letter is to notify you that we plan to conduct a Supplemental Inspection of Brunswick Unit 2 during the week of August 23, 2004. The inspection will be conducted by Mr.


In accordance with 10CFR 2.790 of the NRC's "Rules of Practice,"
Bob Hagar, the Senior Resident Inspector at the H. B. Robinson Nuclear Plant. In accordance with NRC Inspection Manual Chapter 0305, Operating Reactor Assessment Program, the inspection will be conducted using NRC Inspection Procedure 95001, Inspection For One Or Two White Inputs In A Strategic Performance Area.
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 ATTACHMENT


CP&L 2 (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Discussions between Mr. Eugene DiPaolo of my staff and Mr. Steve Tabor of your staff have taken place to allow for scheduling conflicts and personnel availability to be resolved in advance of this inspection. Thank you for your cooperation in this matter. If you have any questions regarding the inspection, please contact Mr. Hagar at (843) 383-4571 or me at (404)
562-4530.
 
CP&L   2 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter will be available electronically for public inspection in the NRC Public Document Room (PDR) or from the NRCs 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,
Sincerely,
~ Enaineerina Bran Division of iieactor Safety Docket N O S.: 50-325,50-324 License Nos.: DPR-71, DPR-62
/RA/
 
Paul E. Fredrickson, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket No.: 50-324 License No: DPR-62 cc: (See page 3)
===Enclosure:===
NRC Inspection Report w/Attachment:
Supplemental Information
 
REGION 11 50-325,50-324 DPW-71, BPW-62 05000325/2003008 and 05000324/2003008 Carolina Power and Light Brunswick Steam Electric Plant, Units I and 2 8470 River Road SE Southport, NC 28461 August 11-15, 2003 August 25-29,2003 J. Moorrnan, Senior Reactor Inspector (Lead Inspector)
N. Merriweather, Senior Reactor Inspector R. Schin, Senior Reactor Inspector (Week 1 only) M. Thomas, Senior Reactor Inspector M. Mayrni, Reactor Inspector (Week 2 only) N. Staples, Reactor Inspector Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Enclosure
 
=SUMMARY OF FINDINGS=
bR 05000325/2003-008, 05000324/2003-008; 08/11-15/2003 and 08/25-29/2003;
Brunswick Steam Electric Plant, Units 1 and 2; safety system design and performance capability.
 
This inspection was conducted by a team of inspectors from the Region II office. The team identified 1 Green unresolved item. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609, "Significance Determination Process" (SBP). Findings for which the SBP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated Juiy 2000.
 
===A. NRC-Identified===
 
and Self-Revealina Findinas
 
===Cornerstone: Mitigating===
 
Systems m. The team identified a violation of 10 CFR 50, Appendix B, Criterion Ill, Qesign Control requirements.
 
The Technical Specification (TS) allowable value for the Condensate Storage Tank (CST) Level - Low function, for automatic high pressure coolant injection (HPCI) pump suction transfer to the suppression pool, was not adequately supported by design calculations.
 
The calcuIations did not adequately address the potential for air entrainment in the HPCI process flow due to vortexing.
 
This finding is in the licensee's corrective action program as Action Request 102456. This finding is unresolved pending further NRC review of the requirements for the CST Level - Low function and of the corrective actions related to restoration of compliance with 10 CFR 50, Appendix B, Criterion 111, Design Control requirements.
 
The finding is greater than minor because it affects the design control attribute of the mitigating systems cornerstone objective.
 
It is of very low safety significance (Green) because the finding is a design deficiency that will not result in loss of the HPCl function per BL 91- 18 (Rev. I) and the likelihood of having a low level in the CST that would challenge the CST level - low automatic HPCI suction transfer function is very low. In addition, alternate core cooling methods would normally be available, including reactor core isolation cooling (RCIC) as well as automatic depressurization system and low pressure coolant injection. (Section 1821.1 1. b)
 
===B. Licensee-Identified Violations===
 
None
 
=REPORT DETAILS=
 
==REACTOR SAFETY==
Cornerstones:
Initiating Events and Mitigating Systems 1821 Safety Svstem Desian and Performance Casabilitv (71 11 1.21) This team inspection reviewed selected components and operator actions that would be used to prevent or mitigate the consequences of a loss of direct current power event. Components in the high pressure coolant injection (HPCI), reactor core isolation cooling (RCIC), and 125E5.0 volt
: (v) direct current
: (dc) electrical systems were included.
 
This inspection also covered supporting equipment, equipment which provides power to these components, and the associated instrumentation and controls.
 
The loss of dc power event is a risk-significant event as determined by the licensee's probabilistic risk assessment. .I .I 1 a. b. Svstem Needs Process Medium Inspection Scowe The team reviewed the licensee's installed configuration and calculations for water volume in the condensate storage tank (CST) and for net positive suction head for the HPCI pump. This included reviews of system drawings and walkdown inspection of installed equipment to compare arrangements and dimensions to those used in the calculations.
 
The team also reviewed the licensee's calculations supporting the Technical Specification (TS) setpoint for the CST level instrumentation which initiates an automatic transfer of the HPCB pump suction from the CST to the suppression pool. This included checking the adequacy of the calculations and comparing calculated values to values in the TS and in the instrument calibration procedures.
 
Findines introduction:
An unresolved item of very low safety significance (Green) was identified for inadequate design control of the HPCI suction source from the CST. The calculations which determined the CST low level setpoint for automatic HPCl system suction transfer from the CST to the suppression pool did not adequately account for air entrainment in the process flow due to vortexing.
 
This finding involved a violation of NRC requirements.
 
However, it is unresolved pending further NRC review of the requirements for the CST bevel - bow function and corrective actions related to restoration of compliance.
 
=====Description:=====
Vortexing in pump suction sources is a well known phenomenon.
 
It is discussed in typical textbooks on centrifugal pumps. NRC Regulatory Guide I.8z5 "Sumps for Emergency Core Cooling and Containment Spray Systems,"
dated June 1974, discussed the need to preventing vortexing.
 
Regulatory Guide 1.82, Rev. 1, dated November 1985, and Rev. 2, dated May 1996, included specific guidance on how to prevent air ingestion due to vortexing in containment heat removal systems. That 2 guidance included limiting the Froude number (Fr) to less than 0.8 for BWW suppression pool suctions
[where Fr is equal to the inlet pipe velocity (U) in feet per second divided by the square root of (the suction pipe centerline submergence below the water level (S) in feet times gravity
: (9) in feet per second squared}].
NRC NUREG / CR-2772, "Hydraulic Performance of Pump Suction Inlet for Emergency Core Cooling Systems in Boiling Water Reactors?" dated June 1982, included experiments on suctions from tanks and showed almost no air entrainment with a Fr of 0.8. The experiments also showed that air entrainment increased dramatically when Fr reached 1.0. The BWR Owners' Group Emergency Procedure Guidelines included guidance on preventing vortexing in emergency core cooling system pump suctions from the suppression pool. This guidance included a vortex limit curve based on maintaining Fr less than 0.8. All of the above references addressed suction pipes that extended into a LanWsump.
 
A more recent research paper published in 2001 by ASME titled "Air Entrainment in a Partially Filled Horizontal Pump Suction Line" described tests on air entrainment.
 
The tests were conducted at various flowrates, in a horizontal suction pipe that did not extend into the a tank; a configuration similar to the HPCl suction from the CST at Brunswick. The paper's conclusions about vortexing and air entrainment at high flow rates were similar to those of the previous references where a suction pipe extended into a tank. Brunswick Units 1 and 2 TS Table 3.3.5.1-1 stated that the allowable value for the HPCl system automatic suction transfer from the CST to the suppression pool was a low CST level of 2 23 feet 4 inches above mean sea level. (NQTE:
That value represented 3 feet 4 inches above the bottom of the CST.) Once initiated, the HPCI suction transfer involved first opening the suppression pool suction valves (E41-FO41 and F042) and then closing the CST suction valve (E41-FOO4). The Updated Final Safety Analysis Report (UFSAR) stated that for each unit's CST: "...the HPCl and RCIC pumps take suction through a 16-inch line connected to the tank with a nozzle centerline 2 feet above the tank bottom. Level instruments will initiate an automatic transfer of the pumps' suction path to the suppression pool suction if level approaches this connection. For HPCl the setpoint is above the 3.3-foot TS limit and below the 3.5-foot calibration maximum allowed value.
 
To allow time for the suction transfer to take place, this setpoint provides a margin of approximately 10,000 gallons in the tank after the setpoint is reached and before air will be entrained in the process flow." The calculation of record that supported the TS allowable value was Calculation OE41- 1001, "High Pressure Coolant Injection System Condensate Storage Tank Level Low Uncertainty and Scaling Calculation
[E41 -LSL-N002(3)
Loops]," Rev. 1, dated March 29, 1999. The team noted that Calculation OE41-1001 stated that its objective was to determine the allowable value and setpoint for the CST low water level trip function for the HPCl system. However, the calculation did not include a hydraulic analysis to determine the allowable value.
 
Instead, it relied on a design basis input from Engineering Service Request (ESR) 97-00026, Action Item 2, for the allowable value.
 
3 ESR 97-00026, Action Item 2, stated its objective:
"... the analytical limit for the HPCI and RClC CST low level transfer function is 23 feet 4 inches. Provide a basis for this analytical limit. The basis should address air voids ..." It also stated: "This ESR action item will show that using the TS limit as the analytical limit is acceptable."
 
The ESW included Condition Report (CR) 97-02379 Task 2 (approved August, 27,1997) as an attachment.
 
The team noted that the ESW relied entirely on CR 97-02379 Task 2 for concluding that using the TS limit as the analytical limit was acceptable.
 
However, the ESR also stated: "This CR review was not conducted as a design basis input with formal testing and design verification."
 
CR 97-02379 Task 2 stated that its objective was to determine if a vortexing problem existed in the CST when running the HPCO pump. Task 2 further stated that it was responding to an operating experience event where a nuclear plant had identified that they had failed to account for unusable volume In their CST due to vortexing concerns.
 
It described a scale model test that had been performed by another nuclear plant to conclude that no vortexing would occur in their CST. However, the CR noted reasons why this test could not be relied upon as a design input. The CR also contained results from an informal test performed by the licensee.
 
The CR concluded that, based on the results of the informal testing and engineering judgement, air ingestion may briefly occur during the transfer process; however, the air ingestion would be of such limited duration and such a small percentage that there was no concern for damage to the HPCI pumps. The team noted that the informal test used a small scale model without determination that the results would be applicable to the installed CST and HPCl suction, the test was performed without calibrated instruments, and the test was not independently verified.
 
The team considered that the informal test was not suitable for use as an input to a design basis calculation.
 
Subsequently, action request (AR) 00005402 documented an engineering audit concern with relying on ESR 97-80026 as a design basis input to a calculation.
 
ESW 01-00322 was then written to respond to AR 00005402.
 
ESR 01-08322 stated that its purpose was to document the technical resolution of the CST intake vortex formation issue and to insert appropriate references into design documents.
 
ESR 01 -00322 included an extensive review of reference documents on vortexing.
 
It included references to LERs and INPO Event Reports on vortexing issues at other nuclear plants; NUREWCR-2772; and several research papers on vortexing.
 
The team noted that ESR 01-00322 did not reference NRC Regulatory Guide 1.82. ESR 81-00322 agreed with the conclusions of CR 97-02379 and ESR 97-00026 that the TS allowable value of 23 feet 4 inches was adequate.
 
It concluded that the potential for a significant air ingestion event was of sufficiently low probability to be considered non- credible.
 
The team noted that this conclusion was based primarily on the CR 97-02379 informal test and on a research paper by A. Daemi of the Water Research Center in Tehran, Iran, that had been presented to the American Society of Civil Engineers in 1998. The research paper tested the effect of an intake pipe protruding various distances into a reservoir and found that a pipe that did not protrude into the reservoir showed some vortexing but no air entrainment while a pipe that did protrude into the reservoir would have significant vortexing and air entrainment into the pipe. ESR 01- 00322 considered that, since the NUREG/CR-2272 tests used a configuration where the 4 suction pipe protruded into the tank and the licensee's HPCl suction pipe did not protrude into the CST, the NUREG/CR-2272 conclusions were not applicable to the Brunswick design. The NRC team noted that the research paper by A. Baemi was significantly flawed for applicability to Brunswick in that it did not state what flowrates were used in its tests and apparently used gravity flow. Regulatory Guide 1.82 and NUREG/CR-2272 indicate that flow velocity is one of the most important factors in vortex formation.
 
A suction pipe that would have little or no vortexing at low flow velocities (e.g., gravity flow) could have significant vortexing at higher flow velocities (e.g., a HPCI pump at 4300 gprn). The team considered that both sources of information on which the conclusions of E§R 01-00322 were based were not suitable for use as inputs to safety-related design calculation OE41-1001.
 
The HPCl pump was designed to automatically start and establish a flowrate of 4300 gpm. Licensee procedures did not contain guidance to reduce that flowrate when the CST level approached the low level switchover setpoint.
 
Using the NUREG/CR-2272 methodology, the team calculated that, at a HPCI pump flowrate of 4300 gpm, an Fr of 0.8 would be reached at a CST level of 5.0 feet and an Fr of 1 .O would be reached at a CST level of 3.9 feet. Considering the automatic suction transfer actuation setpoint and the valve stroke times, the HPCB pump suction pipe could be exposed to a suction Fr in excess of 0.8 (some air entrainment)for about 8.9 minutes and over 1 .O (over 2% air entrainment)for about 5.0 minutes. Calculations that used the 2001 ASME research paper equations provided different results: air entrainment in the process flow would start at a tank level of 3.2 feet and would exceed 2% at tank levels below 3.0 feet. This would represent a HPCI pump suction pipe exposure to some air entrainment in the process flow for about 1.8 minutes and to over 2% air entrainment for about 1.1 minutes. The team concluded that the plant design was not consistent with the UFSAR in that the TS allowable value for the HPCl automatic suction transfer would not prevent air from becoming entrained in the HPCl process flow. During this inspection, team and licensee measurements of the installed CST configuration revealed non
-conservative errors of about 1.5 inches in the actual heights of the Units 1 and 2 CST level switches above the HPCl suction pipes. These would result in additional non-conservative errors in the HPCI automatic suction transfer setpoints.
 
The licensee entered this issue into their corrective action program as AR 102456. This AR included an operability determination and planned corrective actions that were reviewed by the team. The operability determination concluded that the CST Level - Low instrument was operable with the existing TS allowable value and related setpoint and no compensatory measures were needed. This conclusion was based on the following:
1) HPCl operation during design or licensing basis events would not challenge the CST Level bow instrument; and 2) Operator actions consistent with plant procedures would not result in 4300 gpm HPCl flow for the full duration of the suction transfer.
 
The operability determination did not include an analysis which assured that the instrument's allowable value was adequate to prevent significant air entrainment during the full duration of a CST bevel - Low setpoint initiated suction transfer while the HPCl pump was operating at its maximum flowrats of 4300 gpm.
 
However, the team's interpretation of licensing basis documents indicated that the CST 5 Level - Low function was required to be able to protect the HPCl pump from damage from any suction hazard that could occur. This inciuded air entrainment in the process flow due to vortexing that would result if the CST level became low while the HPCI pump was operating at about 4300 gpm, even if this could only occur outside of a design basis event. The licensee's corrective actions for this issue were in AR 102456. This AB included only two planned corrective actions.
 
The first corrective action was: "Issue a UFSAR change package to correct the description of HPCB air entrainment potential during suction swap." Phis was described in more detail in the AB under Section 3, Inappropriate Acts, item 4: "Error 4 was a simple text error by BNP engineering where the concept was understood (no significant air at the pump) but was not translated into specific detailed words." The second corrective action was: "Issue an evaluation to update the HPCI CST level switch design basis information to reflect the evaluation provided in the operability review portion of this AW." The operability determination portion of the AR concluded that the CST Level - Low automatic HPCl suction transfer function would not be challenged during design basis events and consequently the TS allowable value was adequate. The documented corrective actions in AR 102456 did not appear to be sufficiently comprehensive to restore compliance with 10 CFR 50, Appendix B, Criterion 111, Design Control. The licensee's planned corrective actions did not Specifically include revising the design calculation, OE41-1001.
 
In addition, they did not include assuring that the CST Level Low suction transfer function will protect the flPCl pump if it is operating at its maximum flowrate during the transfer.
 
The planned corrective actions identified in the AR did not include obtaining a certification from the pump vendor that the pump can withstand a certain amount of air in the process flow for a certain amount of time without pump damage. [This was subsequently done by the licensee.]
The planned corrective actions identified in the AR also did not include submitting a license amendment request to the NKC to revise the TS allowable value, remove the CST Level - Low function from TS, or add an operator action to throttle HPCl pump flow at low CST levels so that the existing setpoint will be able to protect the pump. This issue will remain unresolved pending further NRC review of the design basis and operability requirements for the CST Level - Low suction transfer function.
 
Specifically, the NRC will review whether the CST Level - Low function is required to be able to protect the HPCI pump from damage only during design basis events; or if it is required to be able to protect the HPCI pump from damage due to air entrainment if the level is the CSB becomes low with the HPCI pump operating at a flowrate of about 4300 gpm, even if this could only occur outside of a design basis event. Analvsis:
Design Calculation OE41-1001, for the CST Level - Low setpoint and TS aliowable value was inadequate.
 
The finding is greater than minor because it affects the design control attribute of the mitigating systems cornerstone objective.
 
It is of very low safety significance (Green) because the finding is a design deficiency that will not result in loss of the HPCl function per GL 91-18 (Rev. 1) and the likelihood of having a low level in the CST that would challenge the CST bevel - Low automatic HPCI suction transfer function is very low. In addition, alternate core cooling methods would normally 6 be available, including RCIC as well as automatic depressurization system and low pressure cooiant injection.
 
=====Enforcement:=====
10 CFR 50, Appendix B, Criterion Ill( Design Control, requires in part, that design control measures shall include provisions to assure that appropriate quality standards are specified and included in design documents.
 
Contrary to the above requirements, the NRC identified during this inspection that, from 1999 to August 2003, licensee Calculation OE41-1001 and associated design documents did not adequately consider air entrainment in the HPCl pump process flow due to vortexing in the CST for the current TS value for the CST Level bow setpoint for automatic transfer of the HPCl pump suction from the CST to the suppression pool. This finding was entered into the licensee's corrective action program as Action Request 102456 and is unresolved pending further NRC review of the requirements for the CST Level - Low function and of the licensee's corrective actions related to restoration of compliance with Criterion Ill of 18 CFW 50, Appendix E. This finding is identified as UBI 05000325, 324/2003008-01, Failure to Adequately Consider Vortexing in the Calculation for CST Level for Automatic Transfer of the HPCI Pump Suction. .I2 Enerav Sources a. lnsoection Scow The team reviewed appropriate test and design documents to verify that the 12.9250 vdc power source fur HPCl system valves and controls would be available and adequate in accordance with design basis documents.
 
Specifically, the team reviewed the 125'250 vdc battery lead study, 125 vdc battery charger sizing calculation, and 125/250 vdc system voltage drop study, and battery surveillance test results, to verify that the dc batteries and chargers had adequate capacity for the loading conditions which would be encountered during various operating scenarios.
 
The team reviewed a sample of HPCl motor operated valves (MOVs) to verify the adequacy of available motor output torque, stroke times, thermal overload heater sizing, and valve performance at reduced voltages.
 
The team also reviewed portions of a voltage study to verify adequacy of voltage for HPCl solenoid valves l-E41-F025 and -F026 under worst case voltage conditions.
 
A list of related documents reviewed are included in the attachment.
 
The team reviewed design basis descriptions and drawings and walked down the HPCl and RClC systems to verify that a steam supply would be available for pump operation during a loss of station dc power event. This included review of the steam supply drain systems and review of a recent modification to the HPCI steam supply drain system. The team reviewed the HPCl steam supply drain pot flow orifice inspections; the drain pot level switch logic and calibration records, and the drain pot drain line isolation valves modification to verify that the HPCl steam supply would be available if needed. The team reviewed functional valve testing fur the HBCl and RClC turbine exhaust vacuum breaker check valves to verify adequacy of acceptance criteria and to verify that vacuum breaker functionality was being maintained.
 
7 b. Findinas No findings of significance were identified. .I 3 Instrumentation and Controls
 
====a. Inspection Scope====
The team reviewed electrical elementary and logic diagrams depicting the WPCI pump start and stop logic, permissives, and interlocks to ensure that they were consistent with the system operational requirements described in the UFSAR. The team reviewed the HPCI auto-actuation and isolation functional surveillance procedures and completed test rscords to verify that the control system would be functional and provide desired control during accident and event conditions in accordance with design. The team reviewed the calibration test records for the CST low water level instrument channels to verify that the instruments were calibrated in accordance with setpoint documents. The team also reviewed the records demonstrating the calibration and functional testing of the HPCI suppression pool high level instrument channels to determine the operability of the high level interlock functions of HPCI. b. Findinas No findings of significance were identified. .I4 Operator Actions a. Inspection Scone The team assessed the plant and the operators' response to a Unit 1 initiating event involving a loss of station battery 18-2. The team focused on the installed equipment and operator actions that could initiate the event or would be used to mitigate the event. The team reviewed portions of emergency operating procedures (EOPs), abnormal operating procedures (AOPs), annunciator panel procedures (APPs), and operating procedures (OPs) to verify that the operators could perform the necessary actions to respond to a loss of dc power event. The team also observed simulation of a loss of dc power event on the plant simulator and walked down portions of Procedure OAOP-39, "Loss of DC Power." The simulator observations and procedure reviews focused on plant response and on verifying that operators had adequate instrumentation and procedures to respond to the event. The team reviewed operator training records (lesson plans, completed job performance measures, etc.) to verify that operators had received training related to a loss of dc power event.
 
b. Findinas No findings of significance were identified.
 
8 .I5 Heat Removal
 
====a. Inspection Scope====
The team reviewed historical temperature data for the Unit 2 battery rooms to verify that the minimum and maximum room temperatures were within the allowable temperature limits specified for the batteries. The team reviewed heat load and heat removal calculations for the HPCl and RClC rooms. The team also reviewed the calculated peak temperature and pressure responses during high energy line break and loss of coolant accidents for these rooms. The team reviewed service water temperature and flow requirement calculations for the HPCl and RClC rooms and fan coolers. These reviews were conducted to verify the adequacy of design for the room coolers, and to verify that heat will be adequately removed during a loss of dc power event. The team also reviewed HPCI and RClC room cooler thermostat calibrations, inspection and cleaning records, and corrective maintenance history to verify room coolers were properly maintained and would be available if called upon. b. Findinas No findings of significance were identified.
 
2 System Condition and CaDability 21 Installed Confiauration
 
====a. Inspection Scope====
The team visually inspected the 125/250 vdc batteries and battery chargers, dc distribution panels, dc switchgear, and dc ground detection systems in both units to verify that the dc system was in good material condition with no alarms or abnormal conditions present and to verify that alignments were consistent with the actions needed to mitigate a loss of dc power event. The batteries were inspected for signs of degradation such as corrosion, cell discoloration, plate buckling, grid cracks, and excessive plate growth.
 
The team waiked down the HPCI and RCIC systems and the CST to verify that the installed configuration was consistent with design basis information and would support system function during a loss of dc power event. The team walked down portions of the HPCI system to verify that it was aligned so that it would be available for operators to mitigate a loss of dc power event. During this walkdown, the team compared valve positions with those specified in the HPCI system operating procedure lineup, and observed the material condition of the plant to verify that it would be adequate to support operator actions to mitigate a loss of dc power 9 event. This also included reviewing completed surveillance tests which verified selected breaker positions and alignments. b. Findines No findings of significance were identified.
 
22 Desian Calculations a. Inspection ScoDe The team reviewed the thermal overload sizing calculations for a sample of Unit 1 HPCI MOVs to verify adequacy of the installed overload relay heaters. The team also reviewed calculations that assessed the stroke times and motor torque produced at reduced voltage to verify that they would exceed or meet minimum specified requirements. The valves and calculations reviewed are listed in the attachment.
 
The team reviewed design basis documents, probabilistic risk assessment system notebooks, UFSAR, selected piping and instrumentation diagrams, selected TSs, system reviews, ARs, and the corrective maintenance history for HPCl and RClC systems to assess the implementation and maintenance of the HPCI and RCIC design basis. b. Findinas No findings of significance were identified.
 
===.23 Testing and InsDection===
 
a. The team reviewed the 125/250 vdc battery surveillance test records, including performance and service test results, to verify that the batteries were capable of meeting design basis load requirements. The team reviewed functional and valve operability testing (stroke times), and corrective maintenance records for HPCl and RClC selected valves, including the minimum flow bypass valves, and steam admission valve. This review was conducted to verify the availability of the selected valves, adequacy of surveillance testing acceptance criteria, and monitoring of selected valves for degradation. The team reviewed HPCI and RCIC system operability tests to verify the adequacy of acceptance criteria, pump performance under accident conditions, and monitoring of system components for degradation.
 
b. Findinas No findings of significance were identified.
 
===.3 31===
a. b. 32 a. b.
 
===.33 a. Selected Components===
 
Component Dearadation InsDection Scope The team reviewed in-service trending data for selected components, including the HPC! and RClC pumps, to verify that the components were continuing to perform within the limits specified by the test. The team reviewed the maintenance history of the 125/250 vdc batteries, 125 vdc battery chargers, and selected 41 60 v alternating current
: (ac) and 480 vac breakers to assess the licensee's actions to verify and maintain the safety function, reliability, and availability of the components in the system. The team also reviewed the preventive maintenance performed on selected 41 60 vac and 480 vac breakers to verify that preventive maintenance was being performed in accordance with maintenance procedures and vendor recommendations.
 
The specific work orders and other related documents reviewed are listed in the attachment.
 
Findinas No findings of significance were identified.
 
Eauipment/Environmental Qualification Inspection Scope The team conducted in-plant walkdowns to verify that the observable portion of selected mechanical components and electrical connections to those components were suitable for the environment expected under all conditions, including high energy line breaks. Findinos No findings of significance were identified.
 
Eauipment Protection inspection Scope The team conducted in-plant walkdowns to verify that there was no observable damage to installations designed to protect selected components from potential effects of high winds, flooding, and high or low outdoor temperatures.
 
The team walked down the HPCI and RClC systems and the CST to verify that they were adequately protected against external events and a high energy line break.
 
11 Findinas No findings of significance were identified.
 
Oueratinq Experience lnsuection Scope The team reviewed the licensee's dispositions of operating experience reports applicable to the loss of de power event to verify that applicable insights from those reports had been applied to the appropriate components.
 
Findinos No findings of significance were identified.
 
Identification and Resolution of Problems lnsuection Scose The team reviewed corrective maintenance work orders on batteries, battery chargers, and ac breakers to evaluate failure trends. The team also reviewed Action Requests involving battery problems, battery charger problems, and charger output breaker problems to verify that appropriate corrective action had been taken to resolve the problem. The specific Action Requests reviewed are listed in the attachment.
 
The team reviewed selected system health reports, maintenance records, surveillance test records, calibration test records, and action requests to verify that design problems were identified and entered into the corrective action program. Findinus No findings of significance were identified.
 
Other Activities b.
 
===.34 a.===
b.
 
===.4 a.===
b. 4. 40A6 Meetinos.


lncludina Exit The lead inspector presented the inspection results to Mr. C. J. Gannon, and other members of the licensee staff, at an exit meeting on August 29, 2003. The inspectors confirmed that proprietary information was not provided or examined during this inspection.
CP&L  3 cc:
W. G. Noll, Director Site Operations Margaret A. Force Brunswick Steam Electric Plant Assistant Attorney General Carolina Power & Light Company State of North Carolina Electronic Mail Distribution Electronic Mail Distribution David H. Hinds, Plant Manager Jo. A. Sanford, Chair Brunswick Steam Electric Plant North Carolina Utilities Commission Carolina Power & Light Company c/o Sam Watson, Staff Attorney Electronic Mail Distribution Electronic Mail Distribution James W. Holt, Manager  Robert P. Gruber Performance Evaluation and Executive Director Regulatory Affairs PEB 7 Public Staff NCUC Carolina Power & Light Company 4326 Mail Service Center Electronic Mail Distribution Raleigh, NC 27699-4326 Edward T. O'Neil, Manager Public Service Commission Site Support Services  State of South Carolina Brunswick Steam Electric Plant P. O. Box 11649 Carolina Power & Light Company Columbia, SC 29211 Electronic Mail Distribution David R. Sandifer, Chairperson Leonard R. Beller, Supervisor Brunswick County Board of Commissioners Licensing/Regulatory Programs P. O. Box 249 Brunswick Steam Electric Plant Bolivia, NC 28422 Carolina Power & Light Company Electronic Mail Distribution Warren Lee, Director New Hanover County Department of William D. Johnson  Emergency Management Vice President & Corporate Secretary P. O. Box 1525 Carolina Power & Light Company Wilmington, NC 28402-1525 Electronic Mail Distribution Distribution w/encl: (See page 4)
John H. O'Neill, Jr.


=SUPPLEMENTAL INFORMATION=
Shaw, Pittman, Potts & Trowbridge 2300 N Street NW Washington, DC 20037-1128 Beverly O. Hall, Section Chief Division of Radiation Protection N. C. Department of Environment and Natural Resources Electronic Mail Distribution


KEY PQINTS OF CONTACT Licensee b. Beller, Supervisor, Licensing
Distribution w/encl:
: [[contact::E. Browne]], Engineer, Probabilistic
B. Mozafari, NRR L. Slack, RII EICS RIDSRIDSNRRDIPMLIPB R. Hagar, RII PUBLIC OFFICE DRP/RII SIGNATURE PEF NAME PFredrickson:as DATE  08/02/2004 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO PUBLIC YES NO OFFICIAL RECORD COPY DOCUMENT NAME: E:\Filenet\ML042160062.wpd
Safety Assessment
8. Cowan, Engineer 6. Elberfeld, Lead Engineer
: [[contact::P. Flados]], HPCB System Engineer
: [[contact::N. Gannon]], Director, Site Operations
: [[contact::M. Grantham]], Design
: [[contact::C. Hester]], Operations
Support
: [[contact::D. Hinds]], Manager, Engineering
: [[contact::G. Johnson]], NAS Supervisor
: [[contact::W. Leonard]], Engineer
: [[contact::T. Mascareno]], Operations
Support
: [[contact::J. Parchman]], Shift Technical
Advisor, Operatiofls
: [[contact::C. Schacker]], Engineer 6. Stackhouse, Systems
: [[contact::H. Wall]], Manager, Maintenance
: [[contact::K. Ward]], Technical
Services _D NRC (attended
exit meeting)
: [[contact::E. DiPaoio]], Senior flesident
Jnspector
: [[contact::J. Austin]], Resident Inspector
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened 0500032~,324/2003008-~~
UBI Failure to Adequately
Consider Vortexing
in the Calculation
for CST Level for Automatic
Transfer of the HPCI Pump Suction (Section 7 R21.17. b) Attachment
LISP OF DOCUMENTS
REVIEWED Procedures
OAI-115, 125/250 VPC System Ground Correction
Guidelines, Rev. 6 OAOP-36.1, boss of Any 41 60V Buses or 48OV E-Buses, Rev. 25 OAOP-39.0, Loss of DC Power, Rev.
001-01.02, Shift Routines and Operating Practices, Rev. 31 001-50, 125i250 VDC Electrical
Load List, Rev.
OOP-50.1, Diesel Generator
Emergency
Power System Operating Procedure, Rev. 55 OPM-ACU500, Inspection and
Cleaning of the RHWCore Spray Room Aerofin Cooler Air Filters
1APP-,445, Annunciator Procedure for Panel A
-05, Rev. 46 IAPP-UA-23, Annunciator Procedure for
Panel UA-23, Rev. 45 1 EOP-01 -RSP, Reactor Scram Procedure, Rev. 8 f OP-19, High Pressure
Coolant Injection
System Operating
Procedure, Rev. 58 16P-50, Plant Electrical System Operating Procedure, Rev. 64 1OP-51, DC Electrical System Operating Procedure, Rev. $0 2APP-A-01, Annunciator Procedure for Panel
A-81, Rev. 44 OPIC-TMRQ02, Calibration
of Agastat 7020 Series Time Delay Off Relays, Rev. 18 OPM-BKR001 , ITE 4KV-line Breaker and compartment checkout, Rev
OPM-BKR002A, IT* K-line Circuit Breakers, Rev
OPM-TRB518, HPCI & WClC Steam Inlet
Brain Pot Flow Orifices Inspection, Rev. 3 Drawinqs 1-FP-60085, High Pressure Coolant Injection System Unit
1, Rev. J Contract No. 71-2162, Dwg. No. 1, General Plan for Condensate Storage Tanks by Brown
& D-02523, High Pressure Coolant Injection
System Unit 2, Sh. 1 & 2, Rev. 52 & 45 8-02529, Reactor Core Isolation Cooling System
Unit 2, Sh. 1 & 2, Rev. 52 & 36 8-25023, Sheet 2, Unit 1 High Pressure Coolant Injection System Piping Diagram, Rev. 45 D-25023, Sheet
I Unit 1 High Pressure Coolant Injection System Piping Diagram, Rev. 54 F-03044, Units 1 & 2 480 Volt System Key Qne Line Diagram, Rev. 38 LL-7044, Instrument Installation
Details Units 1 & 2, Sh. 15, Rev. 10 Calculations
OE41-1001;
High Pressure Coolant Injection System - Condensate Storage Tank Level - Low 9527-8-E41-06-F;
NPSH Requirements - HPCI and RCIC; dated March 26, 1987
BNP-E-6.033, AC/DC MOV Thermal Overload Sizing Calculations, Rev. 3 BNP-E-6.062, 125i250 Volt DC System Voltage
Drop Study, Rev.
BNP-E-6.074, 125i.250 Volt DC Battery Load Study, Rev. 2
BNP-E-6.079, 125 Volt DC Battery Charger Sizing Calculation, Revision
BNP-E-6.109, Unit 1 Stroke and Motor Torque Calculations for
250VDC Safety-Related MOVs, BNP-E-8.013, Motor Torque Analysis for
AC MQVs, Rev. 4 and Coolers, Rev. 7' Root, lnc; Rev. C Uncertainty and Scaling Calculation (E41 -bSL-N002(3)
Loops), Rev. I, dated March
29, 1999 Rev. 5
BMP-EQ-4.001, Temperature
Response in RHR and HPCl Rooms Following
LBCA with BNP-MECH-E4I -F002, Mechanical
Analysis Report to Verify Minimum Torque Availability, BNP-MECH-RBER-001, Reactor Building Environmental
Report, Rev. OA WAC Flow Rates, Rev. 0 M-89-0021; HPCllRCIC
NPSH with Suction from the CST; Rev. 0, dated November 27, 1989 PCN-G0050A, RHR Room Cooler Allowable
Service Water Inlet Temperature, Rev. 2 Desian Basis Bocuments
DBD-19, High Pressure Coolant Injection
System, Rev. f 1 DBD-51, DC Electrical
System, Rev. 5 Enaineerina
Service Requests ESR 97-0026; Provide a Basis for the Analytical
Limit for the HPCl and RCIC CST bow bevel ESR 98-00067;
HPCI/RCIC
Reserve Capacity in CST; Rev. 1, dated February 17, 1998 *SI? 99-00404; #PCI/WCIC
Drain Pot Piping Boundary Changes; dated February 25,2000 ESR 01-00322;
Document the Technical
Resolution
of the CST Intake Vortex Formation
Issue; ESR 99-00405, HPCl Design Conversion
To Fail Open for E-41-F028/29, Rev. 0 Updated Final Safetv Analvsis Reuort UFSAR Section 54.6, Reactor Core Isolation
Cooling System UFSAR Section 6.3, Identification
of Safety Related Systems - Emergency
Core Cooling UFSAR Section 7.1.1.2, Emergency
Core Cooling Systems UFSAR Section 8.3.2, BC Power Systems UFSAR Section 9.2.6, Condensate
Storage Facilities
Improved Technical
Soecifications
Section 3.5.1, ECCS - Operating
Section 3.5.3, RCIC System Section 3.8.4, DC Sources - Operating
Section 3.8.6, Battery Cell Parameters
Section 3.8.7, Electrical
Distribution
Systems s Operating
TS Bases Section 3.5; Emergency
Core Cooling Systems and Reactor Core Isolation
Cooling Reduced Rev. 3 Transfer Function;
dated November 24, 1997 dated September
25,2001 Systems System List of Valves lnsoected
1-E41-F0011
HPCl Steam Supply Valve l-E41-F006, HPCI Main Pump Discharge Valve
1-E41-F007, HPCl Main Pump Discharge
Valve ?-E41+008, HPCI Test Bypass to CST Valve
1-*41-F011, WPCl Redundant
Shutoff to CST Valve 1-E41-F012, HPCl Test Line Miniflow Valve 1-E41-F04lI
HPCI Suppression
Pool Suction Valve 1-E41-F042, HPCE Pump Suction Valve Completed
Maintenance
and Tests OPT-09.2, HPCI System Operability
Test, completed
06/29/03, 04/03/03, 01/10/03, 08/20/03, OPT-20.10, Testing of Valves E4l-FO96, E44 -FO99, *51 -F063, E51 -F064, completed
04/24/02, OPT-10.1 1, RClC System Operability
Test, completed
06/06/03, 03/14/03, 12/20/82, 07/31/03, OPT-09.3, HPCl System ~ I65 Psig Flow Test, completed
04/20/03, 03/26/01, 03/29/02, OPT-09.7, HPCl System Valve Operability
Test, completed
09/25/03, 05/02/03, 02/07/03, 05/01/03, 04/01/03 OPT-10.1 .El, RClC System Valve Operability
Test, completed
09/04/03, 0411 0103, 07/03/03, 04/09/030PT-10.1.3, RClC System Operability
Test - Flow Rates at 150 Psig, completed
0311 8/QO, 03/29/02, 03/23/01, 04/02/03 05/29/03,04/04/03
03/08/02, 0311 0/03,04/22/02
05/08/03, 04/03/03 03/23/00 Completed
Work Orders (WOs) and Work Requests (WRs) WO 49443-01, HPCl Turbine Restricting
Orifices Inspection, completed
0311 3/01 WO 49442-01, RClC Turbine Restricting
Orifices Inspection, completed
03/15/01 WQ 45998-01, HPCl Turbine Supply Steam Drain Pot Hi Level Switch Calibration (Unit 2), WQ 192543-01, HPCl Steam Supply Valve 2-E41-F001
Repairs due to Leakage Past the Seat, WO 4581941. HPCl Turbine Sugnlv Steam Drain Pot Hi bevel Switch Calibration (Unit I), completed
2/06/01 completed
03/31/03 .. ~ completed
i/25/Oi WO 46107-01, Calibration
of RHR Room Cooler Thermostats, completed
11/09/80 WO 53172-01;
Inspection
& Cleaning of iqe RHR Roorrl Cooler, cotnpleted
03/05/02 WO 50171-01, Inspectioil
R Cleartiny
of the HI-iR Room Cooler, completed
03/05/02 WR AFQO 001, HPCI Turbine Supply Stem Drain Pct Hi Level Switch Calibration (Uqit 2), WR AlTl 001, HPCI Turui!ie Supply Steam Drain Po! Hi Level Switch Caliwation (Unit 1). WR ABPD 063, Calibration
of PCIR Room Cooler Thetmostars, completed
09/13/00 WR ABPD 002. Caiibratiori
of HHH Room Cooler Thermosta!s, completed
08/25/97 WR AGEB 002, Calibratiop
of HHH Room Cooler Thsrmosats, comple;ed
08/21/97 WR AlWK 004, Inspectian
& Cleaning of the HI-IH Rocm Cooler, completed
C3/09/02 WWJO ANRROOl, 1A-1 Ba:teries, 125 VDC, Perfcrmacice
Capaci!y Test WW:O ANTKGOI, 1A-2 Bat:er:es, 'I25 VUC, Performarice
Capacity Test WWLO ANSN001, 1 B-1 Batteries, 125 VDC, Performarm?
Capacity Test WR/;O ANSTOOl, 10-2 Batteries, 125 VDC, Performance
Capacity Test WO 0004C;46SOI, 28-1 Batteries, 125 VDC, Performance
Capacity Test WO 0004546C3:, 28-2 Batteiies, 125 VDC, Pertormance
Capacity Test completed
06/07/96 cmpieted 08/03/95
WO 0004546301,2A-I
Batteries, 125 VDC, Performance
Capacity Test WO 0004546601,2A-2
Batteries, 125 VBC, Performance
Capacity Test WO 0004635001, 18-2 Batteries, 125 VDC, Service Capacity Test WO 0004635101, 1A-1 Batteries, 125 VDC, Service Capacity Test WO 0004634901, 1 B-1 Batteries, 125 VDC, Service Capacity Test WO 0004634801, 1 B-2 Batteries, 125 VDC, Service Capacity Test WO 0017812801, 2B-2 Batteries, 125 VDC, 28-2 Service Capacity Test WO 0017569601, 28-1 Batteries, 125 VDC, 2B-1 Service Capacity Test WB 8019450581,2A-l
Batteries, 625 VDC, 2A-1 Service Capacity Test WO 0017414101,2A-2
Batteries, 625 VDC, 28-2 Service Capacity Test WO 0040923401,OMST-BAW11
W, 525 VDC, Weekly Test WO 5040495901, OMST-BATTI 1 W, 125 VDC, Weekly Test WO 0040496001,OMST-BAW11
W, I25 VDC, Weekly Test WO 0040734401, OMST-BATTI 1 W, 125 VDC, Weekly Test WO 003991 4901, 15-1 & 18-2 OMST-BATTI 1 Q Quarterly
MI0 0031256501, 18-1 & 1 B-2 OMST-BATTI 1 Q Quarterly
WB 80309501 01,15-1 & 1 B-2 QMST-BATTI
Q Quarterly
MI0 0028265501, SB-1 & 1 B-2 OMST-BATTl
IQ Quarterly
WO 0038119301, ?A-1 & 1A-2 OMST-BATTIIQ
Quarterly
WO 0031639601, SA-1 & 18-2 OMST-BATTI IQ Quarterly
WO 0031256401,lA-1
& 1A-2 OMST-BATTIlQ
Quarterly
WO 0028260601, 1A-1 & 18-2 OMST-BATTI 3Q Quarterly
WB 0030391 401.2A-1 & 2A-2 OMST-BATTI 1 Q Quarterly
WO 0530391 501,2B-1 & 28-2 OMST-BATTI 1 Q Quarterly
WO 0031256201,2A-l
& 2A-2 OMST-BATTI 1Q Quarterly
WO 0531256301,2A-I
& 28-2 OMST-BATTI 16 Quarterly
WO 0031256601,2!3-1
& 28-2 OMST-BATTI t Q Quarterly
WO 0031256701,2B-I
& 28-2 OMST-BAW1
Q Quarterly
WO 0004680801, HPCl Auto-Actuation
and Isolation
Logic System Functional
Test WO 0067956801, HPCl Auto-Actuation
and Isolation
Logic System Functional
Test WB 003971 1701, 1 MST-HPCi27Q
and RCIC CST Low Water bevel Instrument
Catibration
WB 0031316101, 1 MST-HPC1270
and RClC CST Low Water Level Instrument
Calibration
WO 0539317801,2MST-HPC127Q
and RClC CST Low Water Level Instrument
Calibration
WO 0031323101,2MST-HPC127Q
and RClC CST Low Water bevel Instrument
Calibration
WO 0038679201, HPCI Suppression
Pool High Level Instrument
Channel Calibration
WO 0031264601, HPCl Suppression
Pool High Level Instrument
Channel Calibration
WO 0038677301
I HPCl Suppression
Pool High Level Instrument
Channel Calibration
WO 0004589001, Calibrate
14541 -FSHL-NO06
in accordance
with OPIC-DP-SO01
WO 0007165106, Replace HPCl pump discharge
line flow switch WO 00431 63606, Perform single cell charging on 1-1 A-2 Cell #43 IAW BSPP-BAT010 WO 0043161306, Perform single cell charging on 1-18-1 Cell #13 IAW BSPP-BAT010
WO 0042888401, 1-1 B-1 125 VBC Battery Cell # 13 has a low voltage reading WO 0044659406, Perform single cell charging on 1A-2 Battery Cell # 1 WO 0037821401, 18-2 Battery Cell ?# 53 has a cell voltage of 2.124, minimum voltage is 2.1 3 WO 0033286001, 1-1 8-2 Battery corrosion
found on positive terminal of battery cell # 52 WO 0033285401
~ I-1A-1 Battery corrosion
found WO 0033285301, l-IAP-125VDC-BAT.
Replace Cell # 4 on Battery 1A-2 WO 001 6351401, Equalize 1-1 8-2-1 25VBC-BAT
IAW OPM-BAT004
WO 0014092401, 1-152 Cell # I needs to be replaced due to low specific gravity reading WO 0006930901, Using ESR 00-00345 and WO Task knstructions, Replace Cell # 54 in I-1B- WO WRiJO 99-ADIK1, Troubleshoot
and assist operations
in ground hunting for 18 Battery WO 0043131301, 1-1A-2-125VDC-CHRGW
investigate
breaker tripkharger
voltage card WO WWJO 99-AFEC1, Replace floatlequalize
toggle switch on I-$A-1-125VBC-CHWGR
WO WWJO 99-AFED1, Replace floaffequalize toggie switch
on 1 -lA-2-125VQC-CHRGR WO WWJO 99-AFEEI Replace floatlequalize
toggle switch on 1-1 B-1-125VDC-CHRGR
WO WWJO 99-AFEE2, Place 1-1 B-I-125VDC-BAT on equalize WO WWJO 99-AGKAI, Investigate
problem with 1-18-2-125VDC-CHRGR WO WWJO 99-AGKA2, Troubleshoot
ground on 1-1B-2 Battery Charger during Unit 1 outage WO WWJO 99-AFEF1, Replace floatlequalize
toggle switch on 1-1 8-2-125VDC-CHRGR
WO WWJO 98-ACNW 1, Troubleshoot
and Repair 1-1 B-2-125VDC-CHRGR
WO 0033286301, Perform OMST-BAWI
SQ to remove corrosion
from battery terminals
WO 0033286201, Perform OMST-BATTI 1Q to remove corrosion
WO 0027849301, 2-2A-1-125VDC-BAT, Petform DLRO measurements
WO 0027849201,2-28-1
-125VDC-BAT, Perform DLRO measurements
WQ 0016331601, 2-2B-I-125VDC-CHRGR
has no output voltage please investigate
and repair WO 001 3345101, The corrected
specific gravity was less than the required 1.205 tolerance
WO WWJO 99-ADMLI, Place 125 VDC Battery Banks 2A-1,2A-2,2B-II
2B-2 on equalize WO WWJO 00-ADJS1, Replace Cell # 27 in 2-2A-2-125VDC-BAT
WO WWJO 00-ADEEf , Clean off electrolyte
on cell #27 of 2-28-2 Battery WQ WWJO 99-AAGJI, 2-28-2-125VDC-BAT
individual
ceil voltage out of tolerance
WO WWJQ 00-AARJ1, Troubleshoot
2-28 battery bus ground WO WWJO 99-ACRSI , Replace floatlequalize toggle switch
on 2-2A-2-125VDC-CHRGR WO WR/JO 99-ACSWI, Replace floatlequalize toggle switch
on 2-2A-1-125VDC-CHRGR WO 001 11 66201, Replace floaffequalize
toggle switch on 2-28-1-125VBC-CHRGR
WO 0017170101, Specific gravity on Cell #56 of battery 1B-2 out of tolerance
WO WWJO 99-AAGEd.
I-lB-2-125VDC-BAT
Cell #37 voltage low WWJQ ASLEOOI ,I -E6-AV4-52, 5175 480 VAC Distribution
System, Substation
Breaker PM WWJO ADUEQOl ,l-Es-AU9-52, 5175 480 VAC Distribution
System, Substation
Breaker PM WWJO ADKC007 ,1 -EB-AXI-52,5175
480 VAC Distribution
System, Substation
Breaker PM WWJO 99-ACPTI ,2-2CB-C56, 5175 480 VAC Distribution
System, Substation
Breaker WR/JO 00-ABHD2,1-1CA-C05, 5175 480 VAC Distribution
System, Substation
Breaker WWJO 00-ABDH1 ,1 -1 CAC05, 5175 480 VAC Distribution
System, Substation
Breaker WWJO ACDUOO-i, 2-2A-GKO-72, 5240 125 VDC Battery Charger System, Circuit Breaker WWJO ACDXOOI, 2-2A-GK3-72,5240
25 VDC Battery Charger System, Circuit Breaker WR/J0 AAKOOOI, 2-2CB-656-52, 5240 125 VDC Battery Charger System, Circuit Breaker WO 0005034401, PM on 1 -E2-A#1 WO 0017871402, In-situ Test of Mag Latch for 1-E6-AV4-52
25VDC-BAT
while batteries
remain on line BUS IAW OAl-I 15 and IOP-51 replacement
Maintenance
Maintenance
Maintenance
Functional
Test Functional
Test Maintenance
WB 0030223001, Overload Relay Setting Change WO 0019871802, In-situ Test on 143-AV4-52
WO 0029973501, Circuit Breaker Tie Between Unit Substation
E5&E6 WO 0017868201, in-situ Test of Mag Latch of E5E6 Tie Breaker WO 0005033201, PM on I-E2-AH1 WO 0012789501, Breaker Operator Replacement
WO 0005030701
PM on Breaker 1 -dB-GMI -72 WO 5005009301, PM on Breaker 1-1B-GM4-72
WO 0029610701
I PM O R Breaker 2-25-GM1-72
WO 0029609301, PM on Breaker 2-25-GM4-72 WO 0013432712, Test/Replace
Breaker 2B-l-125VDC-Charger
AC CKT Comcdeted
Surveillance
Procedures.
Preventive
Maintenance (PM). and Test Records OPT-12.6, Breaker Alignment
Surveillance, Rev. 42, Completed
8/2/03, 8/9/03, 8/16/03, 8/23/03 Action Reauests (ARs. 087358, Deficiencies
related with valve 2-E41-F001
CR 97-02379;
Determine
if Vortexing
Problem Exists in the CST When Running the HPCl AB 00005402;
Vortexing
in CST Needs More Formal Analysis than CR 97-02379;
dated AR 00098654,125
VDC 1A-2 Battery Charger Main Supply Breaker Trip AR 00047078, 1 B-2 Cell # 56 Failed Specific Gravity AR 00091O76, Positive Plate Discoloration
and Expansion
AR 00071079, 16-2 Battery cells have positive piate discoloration
and expansion
AR 00058078, Battery $A-2 has low voltage cells AR 00053109, Visual signs of degradation
on 213-1 battery AR 00083997,2A-I
Battery Cell #31 cracked cell top AR 00085750, 1B-2 Battery Cell #53 has a low voltage AB 00044684, 15-2 Batteries
are A(1) under new Maintenance
Rule criteria AI? 00052618, BC MOV Thermal Overload Heater Sizing AI? 00076440, BESS Caiculatiofls
Self Assessment
50952 Action Reauests Written Due to this lnsnection
101924, Update periodic maintenance
program to add periodic replacement
of diaphram in Pump; dated August 27, 1997. December 30,1998. valve E41-PCV-152, dated 08/14/03 102321, Valve E41-FC42, reduced voltage strike time calculation
basis, dated 08/14/03 102456, CST Vortexing
Documentation
Discrepancies;
dated 08/20/03 103005, Note in OPT-09.2 Referring
to Auto Closure of HPCl Steam Line Brains (F029 and F028) should have been removed by ESR 99-00405, dated 08/26/04
103106, Correct procedure
inconsistencies
in preventative
maintenance
Procedure
OQM-EfKR001, ITE 4KV Breaker and Compartment
Checkout, dated 08/27/03 103252, Procedure
Enhancement
to OPT-09.3, Rev. 50, HPCl System - 165 Psig Flow Test. Add Procedural
Guidance to Ensure that HPCl Minimum Flow isolation
Valve E41-FO12 Goes Closed After Proper Flow Setpoint is Reached, dated 08/28/03 103256, Procedure
Enhancement
to OPT-09.2, Rev. 1 11, HPCl System Operability
Test. Add Procedural
Guidance to Ensure that HPCl Minimum Flow Isolation
Valve E41-FO12 Goes Closed After Proper Flow Setpoint is Reached, dated 08/28/03 103299, Provide procedural
guidance as io when a Shift Technical
Advisor should activate their post, dated 08/28/03 Lesson Plans/Job
Performance
Measures (JPM) Lesson Plan CLS-LP-51, BC Distribution, Rev. 0 Lesson Plan CkS-LP-402-G, Electrical
Failure Related AOPs (AQP-32.0, AOP-22.0, AOP-36.1, AOT-OJP-JP-O51-AOI, DC Ground Isolation
for P, N, and P/N, Rev. 1 AOT-OJT-JP-302-GO1, Loss of BC Power - Transfer of DC Control Power, Rev. 2 Miscellaneous
Documents:
Brunswick
Nuclear Plant Probabilistic
Safety Assessment
RSC 98-24, Reactor Core Isolation
Cooling System Notebook, Rev. 0 RSC 98-23, HPCl System Notebook, Rev. O HPCI System Periodic Review, dated 02/20/03 RClC System Periodic Review, dated 02/20/03 Maintenance
Rule §coping and Performance
Criteria, System 1001, ECCS Suction Strainer Vendor Manual FP-3808, Battery Charger, Rev. G Specification
137-002, 125 Volt Battery Chargers, Rev. 9 Engineering
Evaluation
BNP-DC-03, Overload Heater Resizing for Valves 1-E41-F00II
FOQ6, and AQP-39.0).
Rev. 0 FOOT, and FOO8, Rev. 0
BCT-09-2083
W3:41 PPl BRUNSWICK
REG BFF 9104573014
P. 16 AII 106230-10
Operability
Review Page 1 of 20 AR 102,456 was written to address documentation
discrqsancies
with respect to pottntkl air entrainment
in the con,ndensate
storage tank (CST) ~~pply line due to vortex a1 the suction nozzle prior to completion
of the HE1 pump suction auto transfer on low CST level. An initia? operability
evduation
concluded
that the low CST WCI level insbmmentathn
ia still operable.
Due to additional
questions
and concerns, a more detailed operability
evaluation
was desired. 'This evaluation
provides additional
detail. When more detail was added tQ the review, some unneeded conservatism
were no longer applied and the end results actudly improved, The issue in question, foe both Units 1 and 2, is whether the setpoint for the Technical
Specification (TS) Table 3.3.5.1-1 Function 3.d. HPCI Condensate
Srmge Tank Level -Low insmentation
is appropriate.
This instrumentstion
is required when the plant is in MODE 1 and ah when in MODES 2 and 3 with reactor stem dome pressure water than 150 pig. TS Bases B 33.5.1 discusem the PIPGI Condensate
Storage Tank Level-Low function:
LOOW level in the CST indicates
the unavairability
of an tldequste
supply of makeup water from this normal source. Normally 6he suction valves between HpeI and the CST are open and, upon receiving
a HPCI initiation
signal, water for KPCI injection
wouldbt taken from the CS
: [[contact::T. However]], if the water level in the CST falls below a psesclecteci
level, fimt the 8UppSdOn pol suction valves automatically
open, and then the CST suction valve automatically
cio&es. This ensures that an adequate supply of makeup water is available
to the MlpcI pump. To prevent losing suction to the pump, the suction valves are interlwked
sion pool suction valves m~~t bc open before the CST suction valve automatically
chses. The Function is implicitly
assumed in the accident and transient
analyses (which take credit for HPCI) since the analyses assume that the HPCI suction sow is the suppression
pool. The Condensate
Storage Tank Level-Low signal is initiated
from two level switches.
The lo& ie arranged slack that either level switch cxn cause the suppression
pool suction valves to open and the CST suction valve to close. The Condensate
Storage Tank Level--Low
FURC~~DII
Allowable
Value is high enough to ensure adequate pump suction head while water is being takrn faom the CST. Two channels of the Condensate
Storage Tank Level-Low Function are nquired to be OPERABLE only When HPCI is required to be OPERABLE to en8uTe that no single insmmenr failure can preclude HPCi swap to suppression
pool source. H41-ULNW and Mi-LSL-NOQS
are TS required instrumentation
and are designated
8s Q Clslla A (safety related).
Elquipmcnt
datnbase (H>B) describes
the active function as ''P~wv&% a signal to the WPCI logic when the condensate
storage tank level is low. This opens valves E41- FM1 and E41-FQ42 to dlow WPCl pump suction from the suppnssion
p~o!." This review was performed
in accordance
with EGR-NGGC-0019, Engineering
Operability
Assessment, and makes dime reference
to NRC Inspection
Manual, Part 9900: Technical
Guidance STS1Oo.TG
and STS IOOPSTS. It supports the determination
that the deficiencies
are. dacumentation
problems only and that no oprability
coneem exists. ATTACHMENT
AR 106230-10 Operability
Review Page 2 of 20 The definition
ofOPERABLBO?ERAB~LITY
is contained
in Chapter 1 of the plant's Technical
Specifications
which states: A system, subsystem, division, component, or device shall be O?ERABLB OT have OPmAI4ILITY
when it is capable of perfoming
its specified
safety funCtion(s)
and when dl necessary attendant instrumentation, controls, normal or emergency
elect13cd
per, cooling and seal water, lubrication, and other auxiliary
equipment
that are required for the system, ~ubsystern, division, component, or device to perfom its specified
safety function(@
ate also capable of pefloming
their related support function(s).
For the HE1 CST Level-Low
instmmenratioa
to be OPERABLE, the chawlaels
must be in calibration
and the CST Level-Low
Function Allowable
Value must bc high enough Io ensm an sdquate 8upply of water is available
for all MPCI system specified
functions.
The preaence of vwtexing in the CST wm not initially
factored into the setpoint development.
This evalunlticm
demonstrates
that the current TS Allowable
Value for the instmentation
setpaint ie appropriate
for all HPC1 system specified
fUnCtiQn9
with the effects of the CST suction vortexing
phenomenon
considered.
As stared in MC Inspection
Manual, Part 9900: Technicai
Guidance, STSlOOP.Sri'S, 3.3 Specified
Function(s):
%e definition
of operability
refers to capability
to perfom the " specified
functione," The SpeciEied
bclim(s) of the system. subsystem, train, component, or device (hereafter
refed to a!? system) is that specified
safety function(8)
in the cumnt licensing
basis for the facility.
In addition to providing
the specified
safety function, a system is expected to perform a designed, test&, and maintained.
When system capabiiity
is de to a point where it cannot periWm with reasonable
assurance
of reliability, the system ahould be judged inopefable, even if at this instantaneous
pint in time the system could provide the specified
safety function.
A B stated in NRC h6pction Mwual, Pan 9900: Technical
Guidance, STSIOOP.STS, 2.1 Cmnt Licensing
Bassis: Cunent licensing
basis (CLB) is the set of NRC requirements
applicable
to a spific plant, and a licensee's
written commitments
for =wring compliance
with and operation
within applicable
NRC requirements
and the plant-specific design basis (including
all modifications
and additions
to such commitments
over the life of the license) that an? docketed and in effect. The CLB includes the NRC ngulations
contained
in IO Cm Parts 2,19.2D, 21,30,40,50, SI, 55,?2,73,100
and appendices
thereto; orden: license conditions;
exemptions, and Technical
Specifications (TS). It also includes the plant- specific design basis infomation
defined in 10 CFR 50.2 a5 documented
in the rnmt mnt Find Safety Analysis Repon (FSAR) as required by 10 CFR S0.71 mad the licmsm's comiome~ts
remaining
in effect that were made in hketed licensing
c~mspondence
such 88 licensee respanscs
to NRC bullctins, generic Ictcers, and enforcement
Bctions. BS well as licensee eomrnitnaents
documented
in NRC safety evaluations
or licensee event repone. P. 17
OCT-89-2003 03:42 PM BRUNSUICK
RE4 eFF 9184553814
P. 1B AR 106230-10 Operability
Review Page 3 of 20 A5 stated in NRC Inspection Manual, Part 9908: Technical
Guidance, STS100.'Ki, ScctiOn 1.0, C.S. Principal
Criteria, the following are the principal criteria
for technical
speGification
operability
rquirem~ts:
a, The system oprability
requirements
should ke consistent
with the safety ana)ySiS Of b. The system operability
quirernemts, including related
regulato~
requirements, my be c. Design-basis events are plant specific
and regulatory
requirements
may have plant- d. The system opesability
quiremen&
that are based on safety analysjs of spcific desip- specific desipbases
events and regulatory requirements.
waived BI~ a consequence
of swified action statements.
spedflc considerations
related to technical specification
operability.
bmis events fer one mode or condition
of operation
may not be the same for ail modes 0% conditions
of operation.
e. The system qxrability
requirements
extend to necess~sy
support systems regardless
of the existence
or absence ~fsttpp~n
system quiroments.
f. lphe operability
of necessary
support systems includes regulatory
requimnentli.
It doca not include consideration
of the Dccumnce of multiple (simultaneous)
&sign buls events. Also applicable
to this discussion
is NRC Inspection Manual, Part 990: Technic& Guidme, STSlO(9.TG.
Section 1.0, D. Conclusion:
Many systems and components
perform dual-function roles with ?egard to midart mitigation
and Foe events for which safe plant shutdown
is required.
The cotrcct application
of operability
quirenuents
for them systems and components
requins additiond
reliance on a knowlededge
of design bssis events. Thus, it is essential
for the proper application
of technical
specification
operability
requirements, to know the applicable
design-basis events for the facility. 
. OCT--BS-2883
83:42 PW BRUNSWICK
REG FIFF 9104573014
P. 19 AR 196230-10
Ojknrbility
Review Page 4 of 20 The specified
functions
for the IfpcI spstem for the purposes of this operability
evduatim are as follows: F-B: HPCI LoeA Licensing Basis Function
The Oriri$inal
mI design and limnsing basis requirements
were established
such th$K HecI was a part of the integrated
ECCS group of systems that provide a LOCA response capability
consistent
with the requirements
of 1QCFw50.46.
O R March 29 1989, CP&E submitted
an evaluation
to the NRC for revised LEA licensing
basis rand to update the demonstration
of conformance
to the ceiteria provided in iOCPR50.46, a6 modified by SECY-83-472, Emergency Core Coolant System Analysis
Methods. This evduati~n, Brunswick
Stem Electric Plant, Units 1 & 2, SAFEWGESTR-LOCA
bnas-of- Coolant Accident Anfdysie, NEDC31624P, assumed less performance
from ECCS systems to allow for relaxation
of some selected requirements, On May 17,19&9,6P&L
submitted
a written response to 0 verbal NRC request for additional
information.
I"XC Question 2 was given
as: Relative to relaxations
of input values (Table AI), what ate all of the nlaxatims
between the new analysis and the analysis of record (Le., the current analysis).
The respnse to Quwtim 2 grovided a tiable which included the following:
rnM ANALYSIS OFRECORD NEW ANALYSIS HPCI hump Minimum Flew 4250 gpm 0 gPm On June I, 1989, the NRC iaswd a Safety Evaluation
for the CP&L submittal.
This SER included "tsstly the staff notes that significant system
or component
assumptions
included no offsite pawet, RO high pressu~ coolant injection
system, two SRVIADS valves out
of servkc and a SRV setpint tolerance
of 3% The assumptions
are acceptable." It also pviddthe fdowing " On this basis. the analysis contsined
in the GE report can be Used to @rdde B nvkd LOCA licmnsing
basis for both Brunswlck
units, and can be referenced
in futuro submittals." The HK.1 pufomce requirements
were discussed
more recently in NEDG-33039P, The Safety Andysis Report for Brunswick
Units 1 and 2 Extanded Power Uprate (pUsAI6), that WBB part of the 08M/01 120% power uprate submittal.
The report included the fdowing "Ori@inally, the HITI system was primarily
for the mitigation
of small break ILEA8 where the depressurization
function [Automatic
Depressurization
System (ADS) I SRVa] WW assumed TO fail. Fw BSEPP, the depressurization
function is Fully redundant, and no accidenr mitigation
credit is taken for the HPCI system." On the bmis of the 1989 NRC SER, the cutrent safety related
LNA licensing
basis prrformance
criteria for KPCI at BSEP is 0 gpm. Given the above, the potential
for air enrPainmnt
the CST suction nozzle during
HpcI operation
is not a concern with respect to the ECCS rcquircments
of 1OCFR50.46
and no further discus5bn
of this function will be prOVi&.
OCT-E9-20E3
03:42 PM BRUNSWICK
REG FlFF 91R4373014
._ AR 106238-10
Operability
Review Page 5 of 20 Fm: Piefed Response to a 1" Line Break Function Although not Wuired for the BSEB JAXA licensing
basis as discwssed
in Function 1 above, BSEP dws consider HPCI operation
to be the preferred
method of responding
to very srnd line breaks. VFSAR 6.3.1.2 and 6.3.3.5 have the following
statements
which go along with this fundon: One high pressure cooling system is provided, which is capable of maintaining (he water level above the top
of the core and preventing
ABS actuation
for small b~aks. and For the HPCI, a criterion
was used (in addition to the criterion that it
depxc~s~~
pprly in conjunction with
the low pmsure systems) which prevents cfaddlng headng far haks less than a 1-in. pipe when functioning
alone, This wm done to ensum maincen@rmce
of level at rated vessei pressure for the more probable leaks
thst might occur QVCT plant life. Since I-in. lines predominate, this provided a good basis for such a criterion.
This flow io also orders of magnitude
in excess of leakage that would occur for cracb approaching
critical size in large pipes. The abve IJFS.4.R 8tatetnCntS
provided the basis for the following
portion of the PWSAR described
WPCI funnctim: "me primary remaining
purpose of the FECI system is to maintain reactor level above the top of the active fuel (TAR and prevent ADS actuatim for line breake up tQ I" in dim*." ESR 99-0062 evaluated
the ability of WI to meet the above
requirements
in response t0 response the testing concerns.
This ESR documented
that less than l@lO gpm of makeup flow was required in response to a 1" line break, Bad on the above this is an explicit function associeted
with :he BNP specific HPCI Licensing
his. Function 2 88 described above
does not inherently exclude the
possibility
of HPCl suction transfer m !OW CST level. Evaluation
of the potential
for air entrainment
at the CST suction noule duhg HPCI Qperaaion
for this function will be evaluated
a8 Case 1 
. OCT--89--2803
243 Bbl BRUNSWICK
REG eFF - - -~ 9104573814
P.21 AR 104230-10
Operability
Review Page 6 of 20 Function 3: Backup to RCIC Function WPCH also ha a design requirement
that it be capable of providing
a backup to the non safety related RCE fuwtiOR for loss of feedwater
and vessel isolation
events. Technical
Specifications
require that RGIC be able to inject water to the vessei at 400 gpm over the same mge of vessel pressme as is specified
for WCI. The RCIC functional
nquiwnents
specified
in UPSAR 5.4.6 include: The RCIC system operates automatically
to maintain sufficient
coolant in the reactor veswl to prevent overhesting
of the reactor fuel, in the event of reactor isolation
accompanied
by loss of feedwater
flow. The system functions
in a timeiy manner so that integrity
of the rgxtioactive
material bamer is not compromised.
This is a transient
response function and is not a Safety Related function.
Technical
Specification
aquirements
have been maintained
because of the contribution
to the reduction
of overall plant risk provided by RCI
: [[contact::C. After the 105% Power Uprate]], analysis showed that the original RCIC performslace
quhmenbs (4W gpm starting 30 seconds after initiation)
would result iIl a lowest level Inside rtme shmud of no less than 5.4 ft above the top of active fuel. Even with relared perfomnce
requirements
of 360 gpm starting 66) seconds after initiation, the lowest level Insick the shroud would be no less than 4.7 ft above the top of active fuel. Either nspon8e ia aeccptable.
RCIC operetion
can prevent the need for ABS biowdown and low preressupe
ECCS injection
following
a loss of feedwater.
Transient
rcsponse graphs in NEF1Bc-30106-P (the GE basis for changing the MSIV isolation
setpoint from LL2 to LId that provrded LTSAR Figure 15.2.6-3)
and GE-NE-187-26-1292 (Power Upate Transient
Analysis for Bmnswick Steam Electric Plant) indicate water level may drop far enough to cwe LL3 actuation (level olttside the shroud between 33.3' and 35.3' above vessel zero). For thie event, operators
would inhibit ADS a5 directed in EBPs due to the large margin between the LJ3 setpoint and top of active fuel, the lack of LQCA indications
and the slow fate of level decrease.
A slow downward trend would follow as the mass of steam flew for decay heat removal via SRV actuations
initially
exceeds the RCXC makeup flow. At 15 to 20 minutes into the event, the level trend would stabilize
and then later start to increase a8 the RCIC makeup matches and then exceeds the steam flew for decay heat removal. The above UFSAR statements
are consistent
with the following
portion of the PSAR dessnbed HPCI function:
"'Kc HPCI system also serve6 as a backup to the Reactor Core Isolation
Cooling (RCIC) system to provide makeup water in the event of a loss of feedwater
flow transient.
For the loss of feedwater
flow transient, which assumes closure of the Mslin steam halation ValVeP (MSrVs), the currentty
specified
WCI system minimum injection
rate of 3825 gpm would pvide sufficient
makeup water to maintain the level inside the shroud well above TAP. DMwg tfiis transient
event, the SRVs would open, then cycle, and the WCI system would quickly retwm the reactor water level to P~WIIIR~, or to the reactor high water level trip (i.e., kvel 8 shutoffh" Note that the 3825 gpm vaiue used above is 90% of the original design Row and is the value that BE would have specified
for HPCI in the SAIFEWGESTR-LQCA
evaluation
had KKI operatton
bn credited.
A high HPCI flow rate is appropriate
only fer the ATWS function not 
. OCT--Y9-2003
53:43 PPI BRUNSWICK
RE6 QFF 9104573814
P.22 AR 106230-10
Operability
Review Page 7 of ZQ the backup to RCIC function.
A flow rate of 400 gpm is the ticensing
basis flow rat0 requirement
for the HPCI Backup to RCIC Function.
Based on the above,this
HETI function is an expiicit fUIICtiOR
associated
with ?-he BNP specific IIPCURCIC
Licensing
basis. Function 3 as described
above does not inherently
exciude the possibility
ofml SWtia transfer on low C§T level. Evaluation
of the potential
for air entrainment
at the CST suction nozzle during NPCI operation
for this function will be evaluated
as Case 2. Case 3 and Case 4. Function 4: SB6 Function Although not pan of the original HPCI design basis, the HPCI system has been credited fW providing
makeup water during B postulated
Station Blackout (SBO) event. The most recent SBO evdu~tion
required HPCI to deliver approximately
86,080 gallons of CST water to the Reactor in a 4 hour time mod. This is an average flow wte of only 3.58 gpm. The peak flow requirement
for this event can be estimated
as the decay heat removal plow rate nonndy provided by RCIC at 4QO gppm combined with an assumed 61 gpm win: pump seal leak or 461 kpm. Although the WSAR did not explicitly
describe the above "CI function, this function waa an essential
pan of the SBO evaluation
th&t was described
at the summary level in the PWSAR. Bd on the above this WCI function is an implied function associated
with the BNP specific SBQ Licensing
basis. Since RHB operation
is not assumed for the initial SBO response, significant
Suppression
Pwl heating is anticipated.
Due to HPCI system process fluid temperacue
limitations, the event explicitly
excludes allowing CST depletion.
This requirement
establishes
a limit on the highest allowed actuation
of the low CST level HLPCL instruments.
Function 5: Appendix R Function Although not pant of the original FPCX design basis, the I;IpcI sysfem has been credited for providing
makeup water during a postulated
Appendix R event. Appendix R evaluations
squired WI to deliver CST water to the Reactor for decay heat removal when manually started after a number of other manual operator actions are completed.
RCIC has a similar Appendix R function.
The use of RCIC for the similar Appendix R event was found to quire a peak flow rate of 500 gpm. Although the MJSAR did not explicitly
describe the above WI function, this funCtiOn i5 essential
for Appendix R compliance.
Appendix R compliance
a uprated conditions
is descrjbctl
at the summary level in the PUSAR. Based on &e above this HKX function is an implied function apsociatd
with the BNP specific Appendix R Licendng basis. SirrPiliv
to the SBO event, the Appendix R event is evaluated
over a specific time penOd. The mal required makeup inventory
for this event will not exceed the required makeup for thc SBO event. Suppression
pool temperature
is expected to exceed the allowed temperaturn
for #pcI operation, CST depletion
is not a required assumption
for this evenr. 
" OCT-B9-288%
83:44 PPI BRUNSWIGK
REG BFF ~- 9104573614
P. 2s AR 106230-10
Operabillry
Review Page 8 of 20 pction 6: HPCB Rod Drop Function I-PCI may be used for vessel inventory
makeup following
a rod drop accident.
Although a 03/IY02 Extended Power Uprate RAI response documented
that neither HBCI nw RCIC operation
is required for a rod drop event, HPCl usage would be expected if RCIC is not available.
The nquired makeup during this event is based on decay heat alone where either HPCI or RCIC operation
would be sufficient.
This function is essentially
the game as the Backup to RCIC function that is addressed
in the Cw 2, Case 3 and Case 4 cvdulaiione.
Function 7: HPCI ATWS Function When the 120% power uprate site specific ATWS evaluation
was performed, KPCI operation
WBS assumed. The operation
of HPCI during iin ATWS is based entirely on manual operator actions including
inhibiting
the auto start at Low Level 2, manually allowing WCX to start just prior to reaching the desired level, and then promptly adjusting
the flow controller
secpolnt a8 ne%clled to control level in B nmw band. Although the FUSAR did not explicitly
describe the above HPCI function, this hn~tim was an essential
pdin afthe ATWS evaluation
&hat was described
at the susnmtppy
level in the PUSAR. Baaed on the above this MPGI function is an implied function associatd
with the BNP specific ATWS Licensing
basis. This event is also an event where Suppmssion
Pod temperatun%
are expected to exceed the limit for w?cI operation.
ASSKIW~ WCI operation
for an ATWS response will be for a relatively
short duration and the event does not amme CST depletion.
OCT-WS-~~W~
m:44 PM BRUNSWICK
R E G AFF - 9184573814
P. 24 AR 106230-10 Operability
Review Page 9 Qf 20 The hw CST level setpoint
does not need to provide any pmtection
for LOCA even&. It do= provide yrotectios
when either an operator action in accordance with
existing procedures, suppflsiiwr
pool level reduction
is credited, or when early MSIV Closure is Rat assumed. For all LOCA response wen&, operator actions
to drain the suppression
pa01 or to jumper the high suppsion pool level FPCf instntments
would not be allowed by proceduns.
The "CI sactian transfee occurs based on high suppression
pool level and the CST inventory
is new fully depleted.
No air ~xhes the HPCI pump and all HPCI performance
is consistent
with UFSAR descriptions.
The Tech Spec hstrumen!
function is however required for HPCI when it is pmviding the
backup to RCIC function.
This funstton can requin extended NPCI operation, either at a reduced flow
rate or intermittently.
The potentid fw an acceptabte
operator action in reccordence
with existing procedmo (educing suppression
pa01 level) could result in pump damage if the stpoint is not adequate.
Additionally, if early MSIV closure does
not occur, a loss of feedwater
event may result in CST depletionc
For this backup to RCK function, opcrarer actians for mnudIycmtrolling
vesseS level late in the event are appropriate.
Etthtr the WCI flow rata would be reduced acceptably
or HFC6 would be operated at full flow for only 60 seeonds. For dhe full faow caw, no air would Each the pump during the last injection
with CST suction and the WCI suction swap would then
be completed
prior to the next HPCI injection.
This proVides the Protechicpn
that is nm&d to prevent continued "Cl operation
with the suction lined
up to a depleted CST. 1 TS Table 3.3.5.1-1.
Function 3.e. #pcI Suppression
Chamber ~vel-High
Instrumentation
Channels are operable (otherwise, WCI pump suction would
be aligned to the suppfession
PI). NP@I auto transfer on high suppression
pool kvel starts at the - 24 inch Tech Spec limit. 2 Cofhmak Stomp Tank level is being maintained
at a minimum of 10' in accordance
wiKh UPSAR 9.262 requirements.
See Attachment
for CST volumes at variom Icveb. 3 WCI auto transfer on low CST level start5 at the 23' 4 Tech Spec limit. 4 Supssion pl Ievel is assumed to start at the -31 inch Tech Spec low level limiL 5 w"cI suction valves operate with maximum stroke times allowed during sUndat9Ce
testing. 6 The HPCI system will respond to automatic
signals at Tech Spec specified
serpoints, and OpMatora will operate the plant in accordance
with existfng design basis, training
and prOCC&*S.
If NPCf actuates automatically (Le,, due to low reactor water
kwl) RCIC will also actutatc if available.
CRlp is nDt taking suction from the CST as the bottom of the suction nozzle
supplying
CRD is more than 9' above the bottom of the tank. 9 Ne sources ~ke ndding waiet to the GST and no actions are taken to refill the CS
: [[contact::T. 10 The plant is at noma full power]], 2923 MWt.
I OCT-09-2083
83:45 PM BRUNSUICK
REG AFF 9104Ei73014
AR 106230-10
Operability
Review Page $0 of20 e IIpeI is providing
the Pafemd Response to 1" Line Break function 0 Operators
may or may not manually control vessel level
Requind manual operation
of RHK is assumed in accordance
with proccdurcs
FOF Case 1, HPCI and RClC will inject QR low wactor water !eve1 (LL2, 105"). If not manually secured due to the standad post trip 170" to 200" level control band
procedure
requiremenl, WBCI and RCIC will trip when level reaches the high feactor level trip setpoint
at 206". Level will then continue to cycle between 105" and 286" if RO operator actctrons
are assumed 01: 190" and 200" if operatom RE performing
normal event response actions. Level control assumptions
do nor affect the outcome of this case. Since this
event involves a small break LWA, significant
drywell heating and pssurizatim
would mur. Operatom would place at least one loop of WI-IR in suppres8ion
pool cooling at 18 minutes consisknslt
witlh existing BSEP Licensing basis assumptions (ref. UFSAR 6.2.2.3).
RWR would also be used for containment
spray if drywell pressure approaches
or exceeds 11 pBig, but containment
spray operation would be terminated prior
to resetting
the Group 2 isolation
instrumentation
that actutltes
at 2 psig. With drywell pres5ure above 2 psig, no flow path is available
for reducing suppression
pool ievel due to the isolation
of Ell-FW md Ell-FW9. With RHR in auppmsioil
pool cooling and the reactor not depressurized via
SRVs, suppnssion
peol ternpeRlture8
would not increw to a value where overriding
the HPCI high suppreselon
pol level transfer inemmentation
is allowed. Continued
operation
of KPCI and/or RCJC rends to depressurize
the vessel 8s it nmoves steam from the reactor and 8s it injects low temperature
wster into the vessel. Although it
is possible that cmtinued HFCI operation
could reduce vessel
pressure to below the "CI isolation
8etpdnt prim to my automatic
auction transfer for larger small breaks, this is not expected for the 1" line break king considend
here. The HPCI suction transfer will stm after 94,330 gallons of water Is injected based on high suppression
pwl level, not low CST level (see Attachment
for supporting
&tds). The CST lswl would k at least 8.0 inches above the top of &e CST suction nozzle after the transfer k complete.
A recent industry paper, JBOC200UPWR-190010, presents the best published
information
applicable
to this appIication
that BNP has been able to find. Although the plant review indicates
that the nominal equation provides
a conservative
estimate for our CST, the "bounding"
eqUQtiOn for 0% air from JPGC2001/PWR-1$010, Equation 10, was used in this case for conservatism:
Sa% I 1.363*FrA0.261
where Fr = V1(32.2*(d/12)"0.5
and S = (d+Lll/d d Pipam now Velocity Fr S-0% L14% I5 1.23 470 8.53 1.345 1.473 7.09 (in) (frA22) (gem) Wet) (in) This shows that no airentrainment
at the CST nozzle will occur far CrrSR I. P.25
OCT--89-2003
245 PPl BRUNSUICK
REG QFF 9184573814
P. 26 AR 106230-10
Operability
Review Page1lofaO
HPCI is providing
the Backup to RCIC function 0 hpt MSIV closure occurs e No cperstor actions assumed other than the required
initiation
of suppression
pool cooling For Cwe 2, WBCI operation
alone will bc considered
as RCiC unavailability
is part of the CBBC definition.
Wl will auto start on low reactor water level (LU, l05"). "(3 will Wip Wh level reaches the high reactor level trip setpoint at 206". Level will then continue to cycle between 105" and 286". This event
does not involve a
small break LOCA, but it may involve a loss of drywell cooling. Drywell heating and pressurization
to above 2 peig may or may not occur. Operatma would place & feast one loop ofM in suppression.
pool cooling a1 10 minutes. With RHR in suppression
pool cooiing and the reactor nut depressurized
vie SRVs, suppssion
pool temperatures
would not increase fo a value whea overriding the
HPCI high suppression
pl level transfer instrumentation
is allowed. Note that if RHR suppression
pool cooling is not 5tute5, "CI would eventually
be operating
with the suction lined up to the suppression
and the supppessim
pool water remperanurc
above the value allowed for Hp@I operation.
Conhued ophn of IipCI tends to depressurize
the veasel as it removes stem fmm the reactor and 8s it iaajecte low ternpalure
water into the vessel. Although it is possible that Continued
mI operation
could reduce vessel pressure to below the HPCI isolation
setpoint prior tn any automatic
suction transfer for small breaks, this is not expected for the case being considerect
here. With MSIV closure, all coolant removed from the vessel will be discharged
tD the mpp,ssion
pl via SRVs and the HPCK turbine exhaust. For this case, the suction transfer Will start after only 43,160 gallons of water is injected to the vessel based on high suppression
pi level. The volume would be less than for Case 1 as the lower
elevation
of the drywell does not collect my water. Also the qqulnd submergence
would be less than for Case 1 since only HPCI operation
is assumed. The margin for avoiding air
entrainment
is therefore increased and
the event would be acceptable.
___ ~- - P. 2s OCT--89-2BBS
03:46 PM BRUNSWICK
REG AFF 9164573Ef14
AR 106230-10 Operability
Review Page 12 of 20 #pcI is providing the
Baekekup to RCIC function m Prompt MSIV closure occuls Qpmtors initiate suppression
pool cooling e Operators
perform suppression
pooi level contml in accordanhe
with proceduns
e Operators eventually perform vessel level
control in accordance
with procedures
WCI operation alone
will be considered
as RCIC unavailability is
part uf the case definition.
=I will auto start on low reactor water
level (LL2, lO5"). HPCI will trip when level
%aches the high reactor Ievd trip setpoint at 206". kvel may continue to cycle between 105" and 206' until such time that operators
have had time to assess plant conditions
and complctc any other mm important actions. Additional discussion
of manual actions to control level in the spified 170" to 2oh)" ievef contpol band will be pmvided below. This event does not involve R smaH bfeak LOCA, but it may involve a loss of drywell cooling. Drywell heating and pmsurization
to above 2 psig may or may not occur. opmttors would place at least one Imp of RHB in suppression
pool cooling consistent
with existing BSEP licensing
basis assumptions.
With RHA in suppression
pool cooling and the reactor not depnssutized
via SRVs, suppression
pool tempecnrtures
would no? increase to a value whm oveniding
the Hpcy hi& suppression
pool level transfer instrumentation
is allowed. The coolant removed from the vessel will be discharged
to the suppression
pool via SRVs and the HPCI turbine exhaust and the lower elevation
of the drywell will not fill with water. For chis case it will be assumed that prim to reaching the high suppression
pod Hg61 level instrument
Setpoint, dfpel1 pressure has been controlled
or restored such the manually
reducing suplprcssion
pol level is possible.
It wa8 estimated
that this would occur at between 0.8 hours and 1.8 how into the event depending
on starting suppression
pod IeveI. For this case CST depletion
at some time after 4 hours of intermittent
HPCI operation needs
to be considered.
Prior to considering
the plant level response, it is appropriate
to take a close look at the cumnt BSEP design basis for the instrument
in question.
The original licensing
bssis for the switch did
not provide an explicit descripien
of the plant IeVd condtions
as&wiated
with actustion.
It simply indicated that the
switch would actuate on 10W CST level to onsure that an adequate supply of makeup water is available
to the HPCI pump. The original licensing basis
for the switch went with an original design basis that specified
the nominal trip setpoint be at a value that "corresponds
to 10,000 gallons capacity".
The documekd design basis did not specify a flow rate and it did not specify the
refmnce point foF the capacity.
The documented design
basis also did not link this setpoint to any stroke time limits on the WPCI suction valves. There
is no indication
that a margin for unccrtsdnties
such 86 temperature effects, suction vortexing, seismic concerns, e&. had to be Considercd.
Aftcr evaluating
OE item PS 5 109, BSEP changed the design basis
for the switches in 1997. The combination
of ESR 97-WO26 and ceiculation
0E41-1001
documented that setpoint
was acceptable
when continuous
HPCI plus RCIC oQeraticn
at 4700 gpm considered
This determination
WBS made based on engineering judgment.
The stroke time limits for the HPCi
9164973W14
OCT-%9-4003
83:46 PM BRUHSWICK
REG AFF P. 2% AR 106230-10 Operability
Review Page 13 ofu) suction valves were also updated and linked to the transfer function.
UncesOainties
were ewssed. Dudng an intarnal system review in
1999, it wa determined that
a more defendable
basis for the vottex aspect of setpint WEIS needed and AR 5402 was generated.
ESR 01-00322 was issued in 2001 88 a ckct mult of this AR. ESR 01-QO322 updated the switch
design as allowed by 1QCFR5Q.59
and was issued in accordance
with CB&L procedures
foe a design chge. The EX noted that the Hpcl system level functional
requirements
did not include actuation
of the switch at the flow rates pnviousty
consi&d. It documented that the highest
applicable
event respnsc flow rate requirement
far WCI was approximately
Io00 gpm. It noted that the HPCI operating procedure
instructs
operators
to adjust HPCI flow after stanup to mainfain stable rcactw vessel levd within the normal range. It established
that fer the HPCl system to be operating at
a high flow rate where significant
air entrainment
would occur due to the lack of adequate reactor level control
mmua! actions is conriderad
non credible.
AK greater than 4 hours into an event where E1 is pmviding the backup to RCIC function, it is apppriate
to Consider operam actions with respect to vessel level control. The following
guidance in the UBSAR is applicable
to this discussion:
UFSAR 5.4.6 inclwdes:
Following
any reactor shutdown, steam generation
continues
due to decay heat. hitidy, the rate of stem $enemtion
can be as much as six percent of rated flow. Thc stem normally flow8 to the main condenser
through the turbine
bypass a, if the emdenser is isolated, through the relief valves to the suppression
pool. The fluid removed from the reactor vmsel either can be furnished
entirely by the feedwater
pumps or can be partially
funti6ked
by the control rod drive (CRD) system, which is supplied by the CRD feed pumps. Lf makeup water is required to supplement
these sources of water, the RCIC turbine-pump unit either start?, automatically
upon receipt of a reactor vewi low water level signal (Bigurn 7.3.3-2) or is started by the operator from the Centhol Room by fernot~ mmud controls.
Re szme low level signal also energizes the
high prcssun coolant injection
system. The RCIC system delivers its design flow approximately
8&c after actuation.
WFSAR 6.3.2.8 System Operation
includes the following:
The ECCS have been designed to atart automatically
in the event of an accident that
threatens the adequacy
of core cooling. Manual operations
are required to Wntain long term cooling. The description
that follows details the
opedon of the systems needed to achieve initial
con mlhg followed by containment
cmling and then followed by extended cm cooiing for a long term plant shutdown
for the case of a non-opcrable
main feedwater
system. The manual operations
deseribcd
we generally
similar to those stquid in the event of a LOCA. The discussion
below also includes the
operation
ob the non-ECCS, non-safety relate$ RClC system. This system is designed to operate dueng loss Of feedwater
events, but is not relied upon to mitigate any accidents.
P.29 OCT-09-2003
03:46 PM BRUNSWICK
REG RFF 9104573B14
AR 186230-10
Operability
Review Page 14 of 20 Following
8. loss of feedwater
and reactor scram, a low reactor water
level signal (he1 2) will automatically initiate
a signei which places the HPCl and RCIC Systems into the reactor coolant makeup
injecrion
mode, These systems will inject water
into the Vemel until a high water level
signal automatically
trips the system. Following
a high reactor water level trip, the HPCI and RCIC Systems will automatically
ninitiate
when =tor water level agdn &creases to low water Level 2, Later in WSAR 6.3.2.8, the discussion
includes:
The aperator can manually initiate the "CI and RCIC systems fmm the ConrrOl Room befere the bel 2 automatic initiation
level is reached.
ahe OperW3' has the Option of manual control
or automatic
initiation
and can maintain
xactor water level
by throttling
system flow rates.
The applicable
operator actions asissodated
with reacror vessel level mtrol level for the non safety dated Backup to RCIC function iire the manual starting of HPCI, the adjusting
of the HBcl flow rate and the stopping of HPCI. The staning and stopping of WCI arc manual actions that also kave associated automatic actions.
#pcI does not have pin automatic feature
to adjust the flow rate to control vessel level
within the procedurally
specified
170" to 200" range. NRC gddrmce wm reviewed with respect to Operator actions. As described
in MC IN 97-78, GL 41-18 rev. 1 states: "it is not appropriate
to take cndit for manual action in place of automatic
action fa protection
of safety limits to consider equipment operable.
This does not preclude opcpator action to put the plant in P safe condition, but operator action canna be a substitute
for automatic
safety limit protec~im."
It is notable that the OL text was specifically
far "automatic
safety limit protection"
and not "any automatic
WtkiR s@ecifid in tkc FSAR or Technical
Spccificatiorms".
Ttie text of IN 99-78 then goes on to quote the following
from ANSI-58.8: "Nuclear safety-related operator actaons or sequences
of actions may
be pcrfarmed
by an operator only whepe a single operator crror of one manipulation
does not Tesult in exceeding
the &sign requirements
for design basis events." Again the text rsfers to "safety-relaled operator actions" and not UFSAR described
actions for a non safety related function.
The text of Cy 97-76 then goes on to discuss that it is pctentid%ly
acceptable
to rely on operator actions, but that the requirements
of 1WFR50.59
eppiy, and @or NRC approval is applicable
when an Unreviewed Safety Question (WSQ) is involved.
A IoCpR50.59
review of the changes of the changes did not constitute
a WSQ. If it is desind to conservatively neglect the
manual actions associated
with starting and stowing HPCI due 10 the associated automatic features, then the ESR 01-00322 design basis for the switches yuire.8 that tRe manual action for adjusting
the HPCI flow controller
(&er flow in automatic
mc& or speed in manual mode) is assumed ro reduce flow such that significant
air entrainment
doe$ not occur. 01-00322 was performed
and it was identified
that
OCf--03--ZBB%
03:47 BM BRUNSWICK
REG FIFF 9104573014
P.30 AR 106230-10
Operability
Review Page IS of 20 Using JPGCXt01/PWR-19010
Equation 8, it was determined
that 2% air entminment
at cbe CST nozzle would be expected at 3000 gpm when LI reaches 2.6". With m assumed average HPCI flow of 3ooO gpm, the 2% entrainment
would start at 1 I7 seconds afta level switch actuation.
With a 45 second transpoet
time, "significant air
entrainment"
would not reach the HPCI pump bedm the lf4 seconds suction tmnsfer is complete.
With a flow rate requirement
that will be no mose than 400 gpm, it would be reasonable
to assume that the injection
flow rate would bc 3000 gpm or less for the last injection
from the CST. This assumption
is not contrary to any regulatory
guidance fer this non safety related function, is consistent
with WSAR descriptions
for sptem operetion
and is applicable given the switch
desigo basis. Regwdlcss
of whether 01 not the manual actions of starting and stopping HFCI am credit4 these actions very likely and need io be considered
for completeness.
Ef an operator decides that he d~ not want to adjust the HPCI flow rate, he can maintain the specified
vessel level by npeatedy starting I%pCI at 2 170" and then securing MPCI at 5 ZOO" whiIe leaving the flow controller
Bet for 4300 gprn. Operating
history was reviewed &J undemnd the plant
response to a full flow "cI[ injection.
Only one HWI injection was
found that was at full flow
for lag enough to determine the expected
plani response, As documented
in AR 102456-10
Atta&ment
5, JJ Unit 2 HPCI scram response injection
on 8/16/90 increased level
from 123" to 153" in just less than 60 seconds. This short response takes less time than would be first expected BB the increase in indicated
8evd is caused by both the inventory
mskeup md "level swell"
cwRlsed by the "CI steam flow induced
vessel pressure reduction.
Since level increased
30" in 6Q seconds, this is an amate duration fer assumed RCIC backup HPCI full flow injections
while opemtom arc maintaining vessel level between
170" and 200". Ah 4 horn, if 8.4300 gpm injection
were tu Stan witk CST level at just above slevatkm 23' 4", air entrainment
could stafl at L1= 5.3.7 inch based on JP(jc2QQ1/PWR-19010
Equation 6, (31 seconds into the injection, see Attachment
for details).
It would require 62 seconds of HK.1 injection
for air to travel the 228' to the pump, Since only 60 SWQ~~S of injection
is expscted, no air will reach the pump.
Any postulated
#pCI full flow rate injection
for this case with CST level starting at just above elevation
23'4" will result in no air reaching the
pump during that speeific injection.
The Wpcl suction swap would then be completed
prior to the next HPCI injection.
This provides the protection
that is nw$ed to prevent continued
HPCI operation with
the suction lid up Ma depktsd CST.
OCT--D?-2005
03:47 PN BRUHSWICK
REG F1FF 9104573614
8.31 AR 106230-10
Operability
Review Page 16 of 20 * HgCI is providing the Backup
to RCIC function hmpt MSIV ciosupe does nat occur Opemton initiate suppression
pot cooling . Opmtops eventually
perform ve5sel level contd in accordance
with preceduren
"CI operation
done wit! be considered
as RCIC unavailability
is part of the ease definition.
"CI will auto start on low reactor warer level (LL2, 105"). HPCI will trip when level reaches the high mor Ievel trip setpoint at
2W'. bvel may continue to cycle between 105'' an8 206" until such time that opereton have had time to assess plant
conditions
and complete any ether more important
actions. Manual actions to controi level in specified
170" to 2QO" kvel control band would probably take place
early in the event. However, it is not needed to sssurne them actions until after 4 hours into the event.
This event dws not involve a small break LOCA, but it may involve a loss of CrOyweH cdlng. Drywell heating and pressurization
to above 2 psig may or may not occur. Operators
would place a! lewt one loop of RHR in suppmsion
pool cooling at
f 0 minutes. With RHR in suppreasion
pool cooling snd the reactor
not depressurized via
SRV6, suppression
pool tempemtiares would not
inmase to a value where overriding
the WCI high suppression
poot level transfer Insmmmtation
is allowed. Note that if RHR suppression
pl coaiing is not started, WCI would eventually
be opting with the suctien lined up to the suppssim pod and the suppmsim pool water temperature
above the value allowed for "CI operation, Continued
operation
of HPCI tends to depressurize
the vessel BS it removes steam from the reactor and 88 it inject8 low temperature
water into the vesscl. Although it ia possible that continued
HPGI operation could
reduce vessel pressufe to below the "Cf isolation
setpoint prior to any automatic
suction transfer for small breaks, this is not expected for the case being considered
here. Much of the coolant leaving the
vessel will be discharged
to the main condenser
in this cwe. One potential
initiator
for this event would be a loss of condensate
system pnssurc boundary inte@ty ar loss of condensate
sysrern flow path. For this case it is appropriate
to assume that the high suppmsim pool KPCI level instrument
setpoint is not reached prior to the CST depletion
that would be expected after 4 hours into
the event. AH pmeters aasoeisted
with the suctim transfer are the sme as for Case 3. Either the IPCI flow rare would be reduced acceptably
or HPCI wouid be operated at full flow for Only 60 seconds. For the full flow cwe, no air would reach
the pump during the last injection
with 6ST suction and
the HPCK suction swap would then be completed
prior to the next Hp(31 injetion.
This provides the protection
that is ncedd to prevent continued
HpeI opratim with the sUCtiim lined up to a depleted em. 
-~ ' KICT-09-2B83
03:48 PPI BRUNSWICK
REG BFF 9104573014
AK 106230-10
Operability
Review Page I7 of 28 mere are no specific limitations.
As long as operators
comply with pedure requirements
as they m gained to do, ?he setpoint is adequate to supp~fl the PfPCI licensing
basis functions
and can be consided operable with no compensatory
actions. Technical
Specification
3.5.1, Table 3.3.5.1 Technicd Specification
Bw B 3.3.5.1 WSAR 5.4.6,6.2.2.3,6.3.1.2.1.6.3.2.8,6.3.3.5.5,9.2.6.2
EGR-NGGe-0019, Engineering
Operability
Assessment
N]RC Inspection
Manual, Part 9900: Technical
Guidance §TSlOO.II%
and sm 100P.STS h%C Infomath Notice 97-76 dated 10/23/97:
Crediting
of Operator Actions in Place of Automatic
Actions and Modifications
of Operator Actions, Including
Response Times GL91-18 rev. 1 * SAE.WGE§TR-LOQcA
Analysis Submittal, dated March 29 1989 h?ZW31624P.
Brunswick
Steam Electric Plant, Units II & 2. SAFBWOESTR-LOCA
hsa-sf~Qulanr
Accident Analysis SWGESTR-LWA
Analysis Response to Request For Additional
Infomation, datal May 17,1989 NRC approval ledter and SER for SAFEWGESTR-LOGA
ANALYSIS, BRUMSWICK
STEAIW ELECTRIC PLANT, UNITS 1 AND 2, dated lune 1.1989 m Bmnswick Unite 1 and 2 Extended Power Wprate submittal
dated O8/09101 * NEDC-33039P, 'Ke Safety Analysis Report for Brunswick
Units 1 and 2 Extended Power Wprate * Ex& Pwcr Uprate Kcspensc to Request For Additionel
Infomation, dated 03/12@2 c m2001/BwR-19010
rn-02626 FP-02762 AB102456 * ESR 95-61733 Rev. 0 AI 15 BSR99-00062
P.32
OCl--B9--2003
0S1:48 PM BRUNSWICK
REG FlFF 9104573814
P.33 AR 106230-10
Operability
Review Page 18 of 20 Attachment
General inputs of CST volume determinations
are as foollows:
input Tank OD from Tank shell thickness, 1st ring Tank shell heigth, 1st ring Tank shell thickness, ring 2, 3 & 4 t-tPCVRC!C
nozzle (N-1) centerline
HkCt/RCi6
nozzle (N-1 j thickness
HPCVRCIC nOZle (N-1) SIZ& HPGllRClC
noule (N-1) ID Volumes to specific levels
Normal Low bevel per OP 31 2 Level needed for routine OPT-09.2 01-03.6 & UFSAR 9.2.6.2 req'd level Nominal drain down via CRD MZ (CR[a/cond)
i% N9 [CS) Nozzel bottom Top of first ring HPCI lnstr Max Setpoint adjusted for AR 102466 HPCI lnstr Nom Setpoint adjusted for AB 102456 HBCl lnetr Min Setpoint adjuijlasted
for AW 102456 HPCl lnlstr T/S adjusted for AR 102456 RCIC lnstr Max Setpoint adjusted for AR 102456 RCIC lnatr Nom Setpoint adjusted for Af? 102456 RCIC lnstr Min Setpoint adjusted for AR 102456 8616 lnstr TIS adjusted far AR 102458 HPCilRClC
Sucd Top HPCllRC1C
Suct Centerline
APP UA-04 5-7 Source FP 2626 FP 2626 FB 2626 FP 2626 FP 2626 FP 2628 FP 2626 FP 2626 Height (in) 40.0 39.5 39.0 38.5 36.0 35.5 35.0 34'5 31.5 24.0 Height (ft) 23.50 20.00 12.00 10.00 9.50 9.38 7.75 3.333 3.292 3.250 3.208 3.000 2.958 2.81 7 2.875 2.625 2.000 Value 52 ft 0.279 in 7.75 ft 0.25 in 2ft 16 in 0.5 in 15 In Volume Volume (e%) (gallons)
49,824 372712 42,403 317198 25,441 190310 21,208 158588 20,140 1 50667 16,428 12295O 7,066 52860 6,978 52205 6,890 52539 6,801 50878 6,360 47574 6,271 46914 6,183 46253 6,095 45592 6,566 41628 4,240 31716 19,875 i 481375 Note distances
above are referenced
to the tank bottom at plant eievarlon
20' 1.5' bl from fop of nozzle ID to HPCl Tech Spec 7.0 Volume, 10' to HPCl max setpoint 14,134 155727 Volume, 10 to HPCI Tech Spec 14,389 107710 Volume, 23.s' to HPCl Tech Spec 43,023 321834 Volume, 20 to HPCl Tech Spec 35,602 266320 Volume, 16' to HPCI Tech Spec 27,221 202876 
.-*.I - 9 1 84 57 38 1 4 , OCT--89--2BE3
03:49 PPl BRUNSWICK
REG RFF AR 106230-10 Operability
Review Page 19 of 20 Attachment
EBB 6541733 Rev. 0 AI 15 was used to document the HPCI Suppression
Pool HI Level Instment bwis. The values and methods of this document were used to determine
the Containment
Inventory
increase assuming small break, HPCI plus RClC operation
at 4700 gpm until the HPCl Suppression
Pool Hi auto transfer Tech Spec level of -24" Is react4 assuming no operator actions. With Torus level starting at The Torus inventory
wouM be With Torus level ending at The Torus inventory
would be Torus inventory
increase ~iyweil spill over volume (rnax. no misc structures)
Endwd volume Plui sump volume Minus pedestal volume Total Injection
volume Or HPCi injection
flow rate Minimum standby total inventwy in CST (1 0') Tank volume at Hi Torus Transfer start Tank afeR near bottom Tank Level at HI Torus Transfer Or Top of HPCi nozzle ID (FP-02826)
Nozzle subinergence (U ) Ushg llmithg wive stroke rimes and no credit for flow r$duction
prim to end cf valve travel the level duction for the transfer will be 85 fOllOWS: E41-F041/!%42
stroke tlme TOM transfer time HPCl flow durlng transter C~T wlurne at end d valve motion Tank Level Nozzle submergence (U) E41 -F004 EilrOk8 flille *31 in 87140 eu ft -24 in 9a90 cuft 43160 gallons 5770 cun 7306 GU R loo CUB 585 cuft m1 cuft la11 CUR 94330 gal 4700 QPm 158588 gallcns 84257 gallons 8599 ft* 2120 w2 48.83 in 31.50 in 17.13 In 4.05 ft 70 8Bc 76 8s 154 see 12063 galllons 52194 gallon8 6978 w 39.50 in 8.00 In P. 34
AR iOg230-10
Operability
Review 0 1 2 3 Q $0 11 12 19 16 16 16 $7 18 .~ 18 20 21 22 l.1 7.00 8.95 8.88 8.84 8.78 8.73 6.87 6.67 6.81 6.48 8.34 6,'ZLl 8.24 8.18 8.13 &OB 6.M 5.87 5.91 8.86 6.81 6.75 5.64 6.88 6.53 5.48 8.43 5.37 5.52 5.26 6.21 5.16 6.W 5.05 4.w 4.84 4.88 4.e3 4.77 4.72 4.67 6.81 4.63 4.69 1.43 b.38 424 4.29 4.23 4.18 4.12 4.07 6.01 3.98 3.91 3.86 3.W IM) 3.a 8.82 e.@ 8.m 3.80 Pa¶ 1 1 1 1 1 I 1 1 1 1 1 1 1 1 9 1 1 1 1 1 1 1 1 1 I 11 1 ? 1 1 1 1 1 1 1 1 1 1 t 1 FWA vel 7.g 722 7.22 7.22 7.22 7.22 7.22 7.22 7.22 7.22 7.22 7.22 ?.?.E 7.22 7.22 7.22 7.22 7.22 7.11 7.22 7.22 7.22 7.P 7.22 7.21 7.22 7.22 7.22 7.92 7.22 7.22 7.22 7.22 7.22 7.21 9.22 7.72 7.22 722 ?.a 7.22 7.22 722 7.22 7.22 7.7.2 7.22 7.22 7.22 7.22 7.22 7.8 7.a 722 7.22 7.22 7,zz 7.22 7.22 7.E 7.22 72.2 7.22 FO42 POS 0.m 0.013 Q.028 0.038 0.061 0.064 0.0V 0.080 0.103 0.115 0.128 0.141 0.154 0.187 0.179 0.1% 0305 0.218 0.Pl 0.244 0.288 0.m 0.2W 0.308 0.321 0.333 0.346 0.358 0.372 0.386 0.M 0.410 0.423 0.436 Q.448 0.462 0.474 0.447 0.903 0.513 0.528 0.538 0.681 0.664 0.477 0.580 0.m 0.816 0,m 0.641 0.654 0.W 0.879 0.692 a.ms 8.718 0.73t 0744 0.75e 0.789 0.782 8.7115 0.258 Air DlSt ffl) ? 14 22 28 38 4a 51 50 55 72 78 87 Bl 1Qd 1 08 1t6 123 130 13? $44 152 18% 186 173 160 186 9% 202 208 217 224 291 91045930114
Page 20 of 20 P. 35
}}
}}

Latest revision as of 00:47, 17 March 2020

IR 05000324-03-008, Notification of Brunswick, Unit 2, Supplemental Inspection During Week of 08/23/2004
ML042160062
Person / Time
Site: Brunswick Duke Energy icon.png
Issue date: 08/02/2004
From: Fredrickson P
NRC/RGN-II/DRP/RPB4
To: Gannon C
Carolina Power & Light Co
References
IR-03-008
Download: ML042160062 (5)
v • d • e


Text

ust 2, 2004

SUBJECT:

NOTIFICATION OF BRUNSWICK STEAM ELECTRIC PLANT UNIT 2 SUPPLEMENTAL INSPECTION - NRC INSPECTION REPORT 50-325/2003-08 AND 50-324/2003-08

Dear Mr. Gannon:

In a Final Significance Determination letter, dated June 2, 2004, from Mr. Loren Plisco, the Region II Deputy Regional Administrator, you were informed that the NRC had concluded that the final significance determination of a Brunswick Steam Electric Plant Unit 2 finding associated with an emergency diesel generator jacket water cooling system leak, had been characterized as White (i.e., an issue of low to moderate safety significance, which may require additional NRC inspection). Also in this letter you were informed that, because Brunswick Unit 2 plant performance for this issue had been determined to be in the increased regulatory response band, we would use the NRC Action Matrix to determine the most appropriate NRC response for the finding, and notify you by separate correspondence of our determination.

The purpose of this letter is to notify you that we plan to conduct a Supplemental Inspection of Brunswick Unit 2 during the week of August 23, 2004. The inspection will be conducted by Mr.

Bob Hagar, the Senior Resident Inspector at the H. B. Robinson Nuclear Plant. In accordance with NRC Inspection Manual Chapter 0305, Operating Reactor Assessment Program, the inspection will be conducted using NRC Inspection Procedure 95001, Inspection For One Or Two White Inputs In A Strategic Performance Area.

Discussions between Mr. Eugene DiPaolo of my staff and Mr. Steve Tabor of your staff have taken place to allow for scheduling conflicts and personnel availability to be resolved in advance of this inspection. Thank you for your cooperation in this matter. If you have any questions regarding the inspection, please contact Mr. Hagar at (843) 383-4571 or me at (404)

562-4530.

CP&L 2 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter will be available electronically for public inspection in the NRC Public Document Room (PDR) or from the NRCs 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/

Paul E. Fredrickson, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket No.: 50-324 License No: DPR-62 cc: (See page 3)

CP&L 3 cc:

W. G. Noll, Director Site Operations Margaret A. Force Brunswick Steam Electric Plant Assistant Attorney General Carolina Power & Light Company State of North Carolina Electronic Mail Distribution Electronic Mail Distribution David H. Hinds, Plant Manager Jo. A. Sanford, Chair Brunswick Steam Electric Plant North Carolina Utilities Commission Carolina Power & Light Company c/o Sam Watson, Staff Attorney Electronic Mail Distribution Electronic Mail Distribution James W. Holt, Manager Robert P. Gruber Performance Evaluation and Executive Director Regulatory Affairs PEB 7 Public Staff NCUC Carolina Power & Light Company 4326 Mail Service Center Electronic Mail Distribution Raleigh, NC 27699-4326 Edward T. O'Neil, Manager Public Service Commission Site Support Services State of South Carolina Brunswick Steam Electric Plant P. O. Box 11649 Carolina Power & Light Company Columbia, SC 29211 Electronic Mail Distribution David R. Sandifer, Chairperson Leonard R. Beller, Supervisor Brunswick County Board of Commissioners Licensing/Regulatory Programs P. O. Box 249 Brunswick Steam Electric Plant Bolivia, NC 28422 Carolina Power & Light Company Electronic Mail Distribution Warren Lee, Director New Hanover County Department of William D. Johnson Emergency Management Vice President & Corporate Secretary P. O. Box 1525 Carolina Power & Light Company Wilmington, NC 28402-1525 Electronic Mail Distribution Distribution w/encl: (See page 4)

John H. O'Neill, Jr.

Shaw, Pittman, Potts & Trowbridge 2300 N Street NW Washington, DC 20037-1128 Beverly O. Hall, Section Chief Division of Radiation Protection N. C. Department of Environment and Natural Resources Electronic Mail Distribution

Distribution w/encl:

B. Mozafari, NRR L. Slack, RII EICS RIDSRIDSNRRDIPMLIPB R. Hagar, RII PUBLIC OFFICE DRP/RII SIGNATURE PEF NAME PFredrickson:as DATE 08/02/2004 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO PUBLIC YES NO OFFICIAL RECORD COPY DOCUMENT NAME: E:\Filenet\ML042160062.wpd

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