united states nuclear r€gulatory commissionthe updated final safety analysis report (ufsar) stated...

UNITED STATES

NUCLEAR R€GULATORY COMMISSION R E G I O N II

SAMNLiNMATLANTA~~O~WALCEMTER 6.S FORSYTH STREET SW SUITE 23T85

ATLANTA, GEQRGIA 30303-8931

O c t o b e r 9 , 2003

Carolina Power and Light Company ATTN: Mr. J~ S. Keenan

Vice President Brunswick Steam Electric Plant P. 5. Box 10429 Southport, NC 28461

SUBJECT: BRUNSWICK S E A M ELECTRIC PLANT - NRC SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY INSPECTION - REPORT NOS. 05000325/2003008and 05000324/2003008

Dear Mr. Keenan:

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.

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.

In accordance with 10CFR 2.790 of the NRC‘s “Rules of Practice,” a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC’s document system

ATTACHMENT 1

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).

Sincerely,

~

Enaineerina Bran Division of iieactor Safety

Docket NOS.: 50-325,50-324 License Nos.: DPR-71, DPR-62

Enclosure: NRC Inspection Report w/Attachment: Supplemental Information

cc w/encl: C. J. Gannen, Director Site Operations Brunswick Steam Electric Plant Carolina Power & Light Electronic Mail Distribution

W. C. No11 Plant Manager Brunswick Steam Electric Plant Carolina Power & Light Company Electronic Mail Distribution

Terry C. Morton, Manager Performance Evaluation and

Regulatory Affairs CPB 9 Carolina Power & bight Company Electronic Mail Distribution

Edward T. O'Neil, Manager Support Services Carolina Power & Light Company Brunswick Steam Electric Plant Electronic Mail Distribution

Licensing Supervisor Carolina Power and bight Company Electronic Mail Distribution

(cc w/encl cent'd - See page 3)

http://www.nrc.gov/reading

CP&L

(cc w/encl cont'd) William D. Johnson Vice President & Corporate Secretary Carolina Power and bight Company Electronic Mail Distribution

3

John H. Q'Neill, Jr. Shaw, Pittman, Potts & Trowbridge 23067 N. Street, NW Washington, BC 20037-1 128

Beverly Hall, Acting Director Division of Radiation Protection N. C. Department of Environment and Natural Resources

Electronic Mail Distribution

Peggy Force Assistant Attorney General State of North Carolina Electronic Mail Distribution

Chairman of the North Carolina

c/o Sam Watson, Staff Attorney Electronic Mail Distribution

Robert P. Gruber Executive Director Public Staff NCUC 4326 Mail Serw'ce Center Raleigh, NC 27699-4326

Public Service Commission State of South Carolina P. 0. Box I1 649 Columbia, SC 2924 1

Donald E. Warren Brunswick County Board of Commissioners

P. 0. Box 249 Bolivia. NC 28422

Utilities Commission

(cc w/mcl cont'd - See page 4)

CP&L

(cc w/encl cont’d) Dan E. Summers €mergericy Management Coordinator New Hanover County Department of

P. 0. Box 1525 Wilmington, NC 28402

Emergency Management

4

Docket Nos.:

License NO§.:

Report Nos.:

Licensee:

Facility:

Location:

Bates:

Inspectors:

Approved by:

U.S. NUCL€AR REGULATORY COMMISSION

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 B L 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

1. 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


.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


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


2 System Condition and CaDability

2 1 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


2 2 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


.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


10

.3

3 1

a.

b.

3 2

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


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


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


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


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


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.

SUPPLEMENTAL INFORMATION

KEY PQINTS OF CONTACT

Licensee

b. Beller, Supervisor, Licensing E. Browne, Engineer, Probabilistic Safety Assessment 8. Cowan, Engineer 6. Elberfeld, Lead Engineer P. Flados, HPCB System Engineer N. Gannon, Director, Site Operations M. Grantham, Design C. Hester, Operations Support D. Hinds, Manager, Engineering G. Johnson, NAS Supervisor W. Leonard, Engineer T. Mascareno, Operations Support J. Parchman, Shift Technical Advisor, Operatiofls C. Schacker, Engineer 6. Stackhouse, Systems H. Wall, Manager, Maintenance K. Ward, Technical Services

_D NRC (attended exit meeting)

E. DiPaoio, Senior flesident Jnspector 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

2

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. 16 001-01.02, Shift Routines and Operating Practices, Rev. 31 001-50, 125i250 VDC Electrical Load List, Rev. 25 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 27 OPM-BKR002A, IT€ K-line Circuit Breakers, Rev 31 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 1 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. 3 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

3

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 W A C 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

4

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 ~ I 65 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 02/06/01

completed 03/31/03 . . ~

completed 1 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 S t e m 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

5

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 W B 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 1 Q Quarterly MI0 0028265501, SB-1 & 1 B-2 OMST-BATTl I Q Quarterly WO 0038119301, ?A-1 & 1A-2 OMST-BATTIIQ Quarterly WO 0031639601, SA-1 & 18-2 OMST-BATTI I Q Quarterly WO 0031256401,lA-1 & 1A-2 OMST-BATTIlQ Quarterly WO 0028260601, 1A-1 & 18-2 OMST-BATTI 3Q Quarterly W B 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 1 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

6

WO 0014092401, 1 - 1 5 2 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 125 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

125VDC-BAT while batteries remain on line

BUS IAW OAl-I 15 and IOP-51

replacement

Maintenance

Maintenance

Maintenance

Functional Test

Functional Test

Maintenance

7

W B 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 OR 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

8

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 . 1 6

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) ~ ~ p p l y line due to vortex a1 the suction nozzle prior to completion of the H E 1 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 i s appropriate. This instrumentstion is required when the plant is in MODE 1 and a h when in MODES 2 and 3 with reactor s tem dome pressure w a t e r 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 CST. However, if the water level in the CST falls below a psesclecteci level, fimt the 8 U p p S d O n p o l 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 s o w 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 2

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 p e r , 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 H E 1 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 M C 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 r e f e d 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 i t cannot periWm with reasonable assurance of reliability, the system ahould be judged inopefable, even if at this instantaneous p i n t in time the system could provide the specified safety function.

AB stated in NRC h6pction Mwual, Pan 9900: Technical Guidance, STSIOOP.STS, 2.1 C m n t Licensing Bassis:

Cunent licensing basis (CLB) is the set of NRC requirements applicable to a spif ic 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 m n t 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 . 1 7

O C T- 8 9 - 2 0 0 3 03:42 P M B R U N S U I C K RE4 eFF 9184553814 P. 1 B


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 B I ~ 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 ~ f s t t p p ~ 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 P W B R U N S W I C K R E G 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.

OR March 29 1989, CP&E submitted an evaluation to the NRC for revised L E A 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 S t e m 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:

r n M 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 p v i d d t h e 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 p u f o m c e 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 L N A licensing basis prrformance criteria for KPCI at BSEP i s 0 gpm. Given the above, the potential for air enrPainmnt 81 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&.

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F m : Piefed Response to a 1" Line Break Function

Although not Wuired for the BSEB JAXA licensing basis as discwssed in Function 1 above, BSEP d w s 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 ~ a k s .

and

For the HPCI, a criterion was used (in addition to the criterion that it d e p x c ~ s ~ ~ p p r l y in conjunction with the low pmsure systems) which prevents cfaddlng headng far h a k s 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 a b v e 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 W I to meet the above requirements in response t0 response t h e testing concerns. This ESR documented that less than l@lO gpm of makeup flow was required in response to a 1" line break,

B a d on the above this is an explicit function associeted with :he BNP specific HPCI Licensing h i s .

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

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Function 3: Backup to RCIC Function

WPCH also h a a design requirement that it be capable of providing a backup to the non safety related R C E 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 m g e 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 RCIC.

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 c w e LL3 actuation (level olttside the shroud between 33.3' and 35.3' above vessel zero). For thie event, operators would inhibit A D S 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 P S A R 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 p v i d e 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 K K I operatton b n credited. A high HPCI flow rate is appropriate only fer the ATWS function not

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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 o f m l 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: S B 6 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 m o d . 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 W S A R did not explicitly describe the above " C I function, this function waa an essential pan of the SBO evaluation th&t was described at the summary level in the PWSAR. B d 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 i s 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 W I 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 q u i r e a peak flow rate of 500 gpm.

Although the MJSAR did not explicitly describe the above W I 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.

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p c t i o n 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 C w 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 n m w 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 i s 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 a m m e CST depletion.

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The h w 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 " C I sactian transfee occurs based on high suppression pool level and the CST inventory is n e w fully depleted. No air ~ x h e s 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 R C K 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 W C I 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 ~ v e l - H i g h Instrumentation Channels are operable (otherwise, WCI pump suction would be aligned to the suppfession P I ) . 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 1 for CST volumes at variom Icveb.

3 WCI auto transfer on low CST level start5 at the 23' 4 Tech Spec limit. 4 S u p s s i o n p l 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.

7 If NPCf actuates automatically (Le,, due to low reactor water kwl) RCIC will also actutatc if available.

8 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 ~ k e ndding waiet to the GST and no actions are taken to refill the CST. 10 The plant is at noma full power, 2923 MWt.

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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 L W A , 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 i t injects low temperature wster into the vessel. Although it is possible that cmtinued HFCI operation could reduce vessel pressure to below the “ C I 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 2 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 n o w Velocity Fr S-0% L14%

I5 1.23 4 7 0 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

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0 HPCI is providing the Backup to RCIC function 0 h p t 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 W h 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 o f M 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 p l level transfer instrumentation is allowed. Note that if RHR suppression pool cooling is not 5tute5 , " C I 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 o p h n of IipCI tends to depressurize the veasel as it removes s t e m 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 i s not expected for the case being considerect here.

With MSIV closure, all coolant removed from the vessel will be discharged tD the mpp,ssion p l 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 i s assumed. The margin for avoiding air entrainment is therefore increased and the event would be acceptable.

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P. 2 s OCT--89-2BBS 03:46 P M B R U N S W I C K R E G A F F 9164573Ef14


#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”. k v e l may continue to cycle between 105” and 206‘ until such time that operators have had time to assess plant conditions and complctc any other m m 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 w h m 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 p o l level is possible. It wa8 estimated that this would occur at between 0.8 hours and 1.8 h o w 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

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AR 106230-10 Operability Review Page 13 ofu) suction valves were also updated and linked to the transfer function. UncesOainties were e w s s e d .

Dudng an intarnal system review in 1999, it w a 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 c k c t 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 c h g e . 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 E 1 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 s t e m 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 i s started by the operator from the Centhol Room by fernot~ mmud controls. R e szme low level signal also energizes the high prcssun coolant injection system. The RCIC system delivers its design flow approximately 30 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 m l h g followed by containment cmling and then followed by extended c m 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 s t q u i d 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 . 2 9 OCT-09-2003 03:46 P M BRUNSWICK R E G R F F 9 1 0 4 5 7 3 B 1 4


Following 8. loss of feedwater and reactor scram, a low reactor water level signal ( h e 1 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 V e m e l 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 “ C I and RCIC systems fmm the ConrrOl Room befere the b e l 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. # p c I 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 M C IN 97-78, GL 41-18 rev. 1 states:

“it is not appropriate to take cndit for manual action in place of automatic action f a 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 p c r f a r m e d 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 B R U N S W I C K R E G 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 l a g 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 “ C I steam flow induced vessel pressure reduction. Since level increased 30” in 6Q seconds, this is an a m a t e duration fer assumed RCIC backup HPCI full flow injections while opemtom arc maintaining vessel level between 170“ and 200”.

A h 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 3 for details). It would require 62 seconds of HK.1 injection for air to travel the 228’ to the pump, Since only 60 S W Q ~ ~ 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 l i d up M a depktsd CST.

OCT- -D?-2005 03:47 PN BRUHSWICK R E G F1FF 9104573614 8.31


* HgCI is providing the Backup to RCIC function h m p t MSIV ciosupe does nat occur Opemton initiate suppression p o t cooling . Opmtops eventually perform ve5sel level contd in accordance with preceduren

“ C I operation done wit! be considered as RCIC unavailability is part of the ease definition. “ C I will auto start on low reactor warer level (LL2, 105”). HPCI will trip when level reaches the high m o r Ievel trip setpoint at 2W’. bve l 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 p l coaiing is not started, WCI would eventually be o p t i n g with the suctien lined up to the suppss im pod and the suppmsim pool water temperature above the value allowed for “ C I 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 “ C f 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 p m e t e r s aasoeisted with the suctim transfer are the s m e 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 0 3 : 4 8 PPI B R U N S W I C K R E G BFF 9 1 0 4 5 7 3 0 1 4

AK 106230-10 Operability Review Page I7 of 28

mere are no specific limitations. As long as operators comply with p e d u r e requirements as they m gained to do, ?he setpoint is adequate to supp~f l 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 B w 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 S W G E S T R - L W A 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 0 rn-02626

FP-02762 AB102456

* ESR 95-61733 Rev. 0 AI 15 BSR99-00062

P . 3 2

O C l - - B 9 - - 2 0 0 3 0S1 :48 P M B R U N S W I C K REG FlFF 9 1 0 4 5 7 3 8 1 4 P . 3 3


Attachment 1

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 f t 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, 1 0 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 5 7 38 1 4 , OCT--89--2BE3 03:49 PPl B R U N S W I C K REG R F F


Attachment 2

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 r e a c t 4 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) E n d w d 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

l a 1 1 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 8 s

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 I M ) 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 f f l )

? 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