IR 05000260/1998011

Insp Repts 50-260/98-11 & 50-296/98-11 on 981116-1204. No Violations Noted.Major Areas Inspected:Operations,Maint & Engineering

ML18039A686
Person / Time
Site:	Browns Ferry
Issue date:	01/30/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML18039A685	List: IR 05000259/1998011 IR 05000260/1998011
References
50-260-98-11, 50-296-98-11, NUDOCS 9902190377
Download: ML18039A686 (81)

Text

U. S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket No.

50-260, 296 License No.

DPR-52, DPR-68 Licensee:

Facility:

Browns Ferry Nuclear Plant, Units 2 and 3 Location:

Corner of Shaw and Browns Ferry Roads Athens, AL35611 November 16, 1998-December 4, 1998 Team Leader:

C. Smith, P. E., Senior Reactor Inspector Engineering Branch Division of Reactor safety Inspectors:

W. Bearden, Reactor Inspector F. Baxter, P. E., Electrical Engineering Consultant K. Coyne, P.E., NRC Intern T. Morissey, NRC Intern J. Panchison, P. E., Mechanical Engineering Consultant Approved by:

Kerry D. Landis, Chief Engineering Branch Division of Reactor Safety P OR 90377 990X30

@DOCK aSO00 POR Enclosure

Executive Summa Browns ferry Nuclear Plant NRC Inspection Report 50-260/98-11, 50-296/98-11 The primary objective of this inspection was to assess the effectiveness of Site Engineering through an indepth review of calculations, analyses, and other engineering documents used to support the High Pressure Coolant Injection (HPCI) system performance during normal, and accident or abnormal conditions. A secondary objective was to determine the quality of 10 CFR 50.59 safety evaluations performed by the licensee in support of plant modifications made to the HPCI system.

~Oerations Overall, the Team concluded that the normal, abnormal, and emergency operating procedures were consistent with the HPCI system design and licensing bases. (Section 03)

Maintenance The general material condition of the HPCI equipment was acceptable.

Housekeeping in the equipment areas was good.

However, some minor discrepancies were noted and discussed with the licensee. (Section M2.1)

The post maintenance test acceptance criteria specified in the maintenance procedures were consistent with the design parameters specified in the design and licensing bases.

Preventive maintenance requirements were consistent with the equipment vendor recommendations.

Acceptance criteria in the surveillance tests were consistent with the design and licensing

.

bases.

(Section M2.2)

Maintenance history for the HPCI System indicated that the system de'sign function had been adequately maintained. (Section M2.3)

En ineerin The had implemented design changes which fullysatisfied their regulatory commitments for TS changes relative to the power uprate project and revising the as-found setpoint tolerance band for main steam code safety relief valves. The plant modifications and associated 50.59 safety evaluations were found to be technically adequate.

(Section E1.1)

The inspectors identified a number of minor discrepancies in the design basis calculations, however, the calculations demonstrated no operability concerns associated with adequate HPCI pump NPSH with the suction aligned to the Condensate Storage Tank or the Suppression Pool.

(Section E2.1.1)

The effects of a CST suction pipe break inside the Reactor Building and its effect on HPCI system operability resulted in a CDF of 7.38E-9 which was a minimal CDF increase of 0.08%

and represented a non-risk significant situation.

(Section E2.1.2)

In general, the HPCI design calculations reflected the current design and licensing basis.

Various errors in methodology and/or inputs were detected in the majority of calculations reviewed, however they were usually of a minor nature and no errors resulted in operability concerns. (Section E2.1.3)

The calculation which supported the modification for installing the new ECCS suction strainer demonstrated adequate NPSH for the HPCI pump for specified containment overpressure conditions. The new strainers have an open fiow area approximately twenty-five times larger than the existing strainers in order to accommodate higher debris loading mandated by NRC Bulletin 96-03. (Section E2.1.4)

The detailed walkdown of the accessible portions of the Unit 3 HPCI system suction and discharge piping identified no concerns that would prevent the HPCI system from accomplishing its design safety function. (Section E2.1.5)

Surveillance procedures used to perform HPCI pump flowrate testing met Technical specification requirements.

The inspectors noted that high pressure HPCI pump testing was not representative of HPCI system design criteria for worst case accident conditions.

The procedures used to satisfy ASME XI requirements were acceptable and met code requirements.

(Section E2.1.6)

Although there were capacity limitations on the 250 Vdc system design, manual realignment of alternate power sources from another battery and repositioning of valves allowed the 250 Vdc system to meet the FSAR licensing basis requirements.

The licensee stated that this condition has existed since original plant design, and a PER was written to revise the wording of the applicable FSAR sections so that they more clearly reflect the licensing basis.

(Section E2.2.1)

The inspectors concluded that the electrical equipment in the HPCI room were qualified to meet the environmental changes resulting from the power uprate.

No HPCI room components were required to be changed or modified as a result of the power uprate.. (Section E2.2.2)

The licensee demonstrated by a revised calculation that battery room temperatures would remain above the minimum of 60'F during worst case conditions.

(Section E2.2.3)

The licensee's fuse control configuration management program adequately assured the operability of supplied electrical equipment.

(Section E2.2.4)

The inspectors concluded that the licensees use of the program BATCALCwas an acceptable use of non-QA software.

One instance of improper use of BATCALCwas identified and corrected by the licensee.

The Licensee recognized the limitation of using non-QA software and planned on using an industry recognized verified program in the near future. (Section E2.2.5)

The review of calculation ED-Q0256-880707 showed that the assumptions made were adequate and a sound engineering approach was used.

The review verified that the 48 Vdc power supplies were sized adequately to supply the HPCI turbine speed control unit. (Section E2.2.6)

Discussions with the licensee indicated that BFNP did not have a formal electrical load tracking program.

The licensee had established administrative processes, however, which ensures that

overall effects of load increases and decreases are taken into account to assure no adverse effects on operability.

(Section.E2.2.7)

The licensee has evaluated the effect of power uprate on instrument loop accuracies.

Using

~

revised analytical limits and changed environmental conditions, instrument setpoint calculations were revised as required.

The instrument loops operating under the effects of power uprate conditions were demonstrated to be sufficiently accurate to perform their intended safety function. (Section E2.3.2.)

The self-assessment plan prepared to evaluate the HPCI system was both thorough and complete.

The self-assessment was well executed and included detailed documentation of completed actions.

The self-assessment identified deficiencies concerning quality of

~ calculations and analyses in all major engineering disciplines.

(Section E.7.0)

Re ort Details Introduction The primary objective of this inspection was to assess the effectiveness of the site engineering organization through an indepth review of calculations, analyses and other engineering documents used to support Unit 3 High Pressure Coolant Injection ( HPCI) System performance during normal, abnormal, or accident conditions.

A secondary objective was to determine the quality of 10 CFR 50.59 safety evaluations performed by the licensee in support of engineering modifications made to the HPCI system.

Regulatory commitments and technical specification (TS) changes which impacted operation of the HPCI system were also verified to have been satisfied by the licensee.

The inspection was performed by a team of inspectors which included a team leader, one Region II inspector, one mechanical design contractor, and one electrical design contractor.

The team was accompanied by two Region II NRC interns.

03.

Operations Procedures and Documentation a.

Ins ection Sco e

The Team reviewed the normal, abnormal, and emergency operating procedures to determine ifthe HPCI system operation was consistent with the design and licensing bases.

b.

Observations and Findin s During the review of Safe Shutdown Instructions (SSls) the Team verified that operator response times and manual actions associated with the HPCI System were consistent with TVACalculation ND-Q0999-910033, Safe Shutdown Analysis-Shutdown From Outside Control Room. Specifically the Team verified that the applicable SSls, 2/3-SSI-001,Safe Shutdown Instructions, and 2/3-SSI-16, Control Building Fire El. 593 Through El. 617, reflected required manual actions within seven minutes for termination of HPCI injection following spurious initiation during an Appendix R fire.

c.

Conclusion Overall, the Team concluded that the normal, abnormal, and emergency operating procedures were consistent with the HPCI system design and licensing base II. Maintenance M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Material Condition Walkdowns a.

Ins ection Sco e

The team performed general field walkdowns to assess the material condition of the HPCI system.

b.

Observations and Findin s e

A detailed walkdown was performed of accessable portions of the Unit 3 HPCI piping located outside of the drywell. During this walkdown the field configuration, including seismic supports, was verified against the as-built drawings.

The verified field configuration was also used to verify the accuracy of the system flow model (EZFLOW).

c.

Conclusion The general material condition of the HPCI equipment was acceptable.

Housekeeping in the equipment areas was good.

However, some minor discrepancies were noted and discussed with the licensee.

M2.2 Maintenance and Surveillance Procedures a.

~Scc e

The inspectors reviewed maintenance and surveillance procedures to determine if acceptance criteria were consistent with the design and licensing bases.

b.

Observations and Findin s The inspectors reviewed the procedures listed in the appendix to this report and reviewed a sample of completed surveillance tests.

The team noted that the licensee had recently identified the failure to correctly incorporate revised mechanical process limits into a setpoint and scaling calculation.

While preparing mini-calc ED-Q0073-980039 against base calculation ED-Q2073-890134 to support the Power Uprate (3458 mwt), licensee personnel identified that process limits for time delay relay, 23A-K43, had been revised as part of Revision 2 for Mechanical Calculation, MD-Q0073-870424.

However, the revised process limits of 2.7 to 3.3 seconds supported by this calculation had not been incorporated into the setpoint and scaling calculation, ED-Q2073-890134, Rev 1. The licensee had documented this discrepancy under PER 98007410 and corrective actions had included revision of the electrical calculation and its associated setpoint and scaling document.

The team concurred that the licensee had adequately addressed this proble Ci

c.

Conclusion The post maintenance test acceptance criteria specified in the maintenance procedures-were consistent with the design parameters specified in the design and licensing bases.

~"

Preventive maintenance requirements were consistent with the equipment vendor recommendations.

Acceptance criteria in the surveillance tests were consistent with the design and licensing bases.

M2.3 Maintenance Histo a.

~Sco e

The inspectors reviewed the maintenance history'of HPCI equipment to determine if performance of corrective maintenance was consistent with the design and licensing bases.

b.

Observations and Findin s The team reviewed documentation associated with various completed corrective maintenance activities on HPCI equipment.

No deficiencies were identified during the review of completed work order package and other documentation provided by the licensee.

c.

Conclusion Maintenance history for the HPCI System indicated that the system design function had been adequately maintained.

III. En ineerin E1 Conduct of Engineering F

E1.1 Conformance with Re ulato

/Licensin Commitments a.

Ins ection Sco e

The inspectors verified that regulatory commitments involving design changes which impacted operation of the HPCI system had been completed for the following TS changes:

TS 384, Request for License Amendment Power Uprate Operation Browns Ferry Plant, Units 1 and 3.

TS 386, Revise As-found Setpoint Tolerance Band for Main Steam Code Safety Relief Valves from +/- 1% to +/- 3%.

b.

Observations and Findin s TS 384 Re uest for License Amendment Power U rate 0 eration The license in a letter dated October 1, 1997, submitted a request for an amendment to Operating licenses DPR-52, DPR-68, and Appendices "A",for Browns Ferry Units 2 and 3 respectively.

The proposed changes would allow a power level increase of 5% and permit operation of the Units at an uprated power level of 3458 megawatts thermal (Mwt). Power uprate operation for Units 2 and 3 involved a 5% increase in maximum reactor thermal power and an associated 30 psi increase in the operating reactor vessel pressure.

Proposed license amendment TS 384 consisted of several changes which permitted uprated power operation of Units 2 and 3. Among the changes described were the following:

Pro osed Chan e No.

Chan e Descri tion Revise Main Steam Safety Relief Valve setpoints

'from 1105, 1115, and 1215 to 1135, 1145, and 1155 respectively for increased (30 psi ) reactor operating pressure.

Revise lower and upper bounds of High Pressure Coolant Injection (HPCI) test pressure from 1010 and 920 psig to 1040 and 950 psig respectively, to account for increased (30 psi) reactor operating pressure.

Revise value of upper design pressure for HPCI and Reactor Core Isolation Cooling (RCIC)

operating range 54 psi (from 1120 to 1174 psig) to account for the effects of increased main steam relief valve setpoints.

Pursuant to the license amendment for power uprate the following design changes were implemented for the HPCI system.

S stem Re uirements Maximum reactor pressure for injection, psig Required pump total dynamic head Injection flow rate Start up time,seconds Rated Pump speed, RPM Pre-power

~Urate 1,120 2,800 5,000

4,000 PowerU rate 1,174 2,930 5,000 30',100

Pum Characteristics Pump flow rate(Main) in gpm Pump speed at required TDH, rpm Speed Margin, rpm Total Dynamic Head at rated speed, ft.

TDH Margin, ft.

Brake Horsepower, HP Pump Shutoff Peak Pressure, psig.

Minimum design pressure, psig.

Maximum Pump Discharge Pressure for injection, psig 5,000 3,990

2,820

4,280 1,541 1,284 1,263 5,000 4,070

- 30 2,980

4,520 1,616 1,347 1,320 Turbine Characteristics Steam Flow Rate, Ibm/hr Turbine Discharge Pressure, psia De'sign Rated Speed, RPM Nominal Overspeed Trip Speed,.RPM Overspeed Trip setpoint, % speed 191,470

4,000 5,000 125 204,850

4,100 5,000 122 The inspectors reviewed design criteria number BFN-50-7073, High Pressure Coolant Injection System, Units 2 and 3, Revision 9, and verified that it had been revised to incorporate HPCI system performance changes caused by power uprate.

The inspectors also determined that the licensee had prepared changes to FSAR Chapter 14, Safety Analysis, to reflect reactor power operation at 3458 MWt. The inspectors were informed by TVAthat this "FSAR Markup for Power Uprate" willbe submitted to the NRC in accordance with the requirements of 10 CFR 50.71.e at the next FSAR update submittal.

The inspectors reviewed the" Safety Evaluation by the Office of Nuclear Reactor Regulation. Related to Amendment No. 254 to Facility Operating License No. DPR-52, and Amendment No. 214 to Facility Operating License No. DPR-68, in order to verify compliance with regulatory commitments.

Section 4.5(1), High Pressure Coolant Injection System, (HPCI), was verified to be consistent with changes in the HPCI system performance parameters delineated in design bases documents.

Several design basis calculations were prepared by the licensee in the mechanical, nuclear, electrical, and instrumentation and control disciplines in order to demonstrate the capability of the HPCI system to perform its design function under power uprate conditions. The technical adequacy of the calculations prepared to demonstrate capability of the HPCI system to perform its design function with reactor power operation of 3458MWt are discussed in sections E2.1, Mechanical Design Review, E2.2, Electrical Design Review, and E2.3, Instrumentation and Control (l%C), Design Revie TS 386 Revise As-found Set oint Tolerance Band for Main Steam Code Safet Relief Valves The licensee in a letter dated December 11, 1996, requested amendments to operating licenses for BFNP Units 1, 2, and 3: The requested amendments proposed a change to the technical specification (TS) for the as-found setpoint tolerance for the main steam safety relief valves from +/-1% to+/- 3%.

In a letter dated May 18, 1998, the NRC issued amendments 251 and 210 to facility operating license's DPR 52 and DPR 68 for BFNP Units 2 and 3 respectively.

The amendments revised the Appendix A TS Limiting Safety System Settings (LSSS) 2.2A relating to the main steam.

The setpoint tolerance was changed from+/-1% to+/- 3% and TS Bases 1.2 and 3.6D/4.6D were revised to reflect the changes.

In the safety evaluation report (SER), for TS change 386, the NRC staff concluded that licensing topical report (LTR), NEDC-31753 provided an acceptable basis for GE boiling water reactors (BWRs) to relax safety relief valves (SRVs) setpoint tolerances.

The staff also reviewed certain plant specific analyses addresed in NEDC-31753 and the results of these analyses were acceptable.to the staff. The NRC concluded that the changes were acceptable based on the conditions as given in the staff safety evaluation for NEDC-31753.

Plant modification DCN No. T40664 was developed and implemented to revise the main steam SRVs liftpressure setpoints in order to accommodate the 105% power uprate program.

Design inputs were provided from design bases calculations ND-Q0999-980003 which provided the analytical limit and calculation MD-Q0001-870133 which provided the valve flow capacities.

The inspector reviewed the plant modification package and conducted discussions with TVAengineering personnel concerning a calculation of record which demonstrated the technical adequacy of the main steam SRVs setpoint changes.

In response the licensee presented the following General Electric (GE) reports prepared by the NSSS vendor in support of the 5% power uprate:

~

GE-NE-B13-01866-05, Power Uprate Evaluation Task Report for Browns Ferry Units 1, 2, and 3 Transient Analyses.

~

GE-NE-B13-01866-22-3, Power Uprate Evaluation Report for TVA Browns Ferry Units 1, 2, 1nd 3 Main steam Relief Valves In response to an industry wide phenomena related to main steam SRV mechanical setpoint drift, the licensee also developed and implemented plant modification DCN No.

T4032A to:

Add pressure interlocks to main steam SRVs to open prior to upper relief valve pressure limit using existing analog trip unit channels.

Change the automatic depressurization system (ADS) inhibit hand switch logic to have two separate annunciator windows for "ADS Logic Bus A Inhibited", and similar for B logi This plant modification implemented the recommended corrective action from the BWR owners group to use safety grade pressure sensors ( in a non-safety related function) to actuate the MSRVs during pressure transient events in the relief mode.

Licensing bases changed as a result of this plant modification were made by revising FSAR section 4.4.5.

c.

Conclusion The had implemented design changes which fullysatisfied their regulatory commitments for TS changes relative to the power uprate project and revising the as-found.setpoint tolerance band for main steam code safety relief valves.

The plant modiTications and associated 50.59 safety evaluations were found to be technically adequate.

-E2 Engineering Support of Facilities and Equipment E2.1 Mechanical Desi n Review E2.1.1 HPCI Pump Net Positive Suction Head (NPSH)

a.

Ins ection Sco e

The inspectors reviewed design basis documents to determine ifadequate Net Positive Suction Head was available to the HPCI Pump under expected operating conditions.

b.

Observations and Findin s Available HPCI Pump NPSH from the Condensate Storage Tank (CST)

The inspectors reviewed design calculations MD-Q0073-920184, "Analytical Limits for HPCI Pump Suction - Automatic Transfer to Suppression Pool", and MD-Q0073-870190,

"HPCI Piping Pressure Drop and NPSH", to verify that adequate NPSH was available to the HPCI pump with suction supplied from the CST. The licensee performed the NPSH analysis using the computer program EZFLOW. EZFLOW is a computer software system used to perform flow balance calculations for multi-path water systems.

The licensee verified the results from the EZFLOW program by comparison to hand calculated solutions in accordance with a formal QA Test ResultsNerification Document.

Following power uprate for Units 2 8 3 to a power of 3458 MWt, the maximum reactor pressure considered for HPCI pump injection increased from 1135 psia to 1189 psia.

This increase in required HPCI pump discharge pressure necessitated a corresponding increase in the maximum normal operating RPM for the HPCI turbine. Prior to power uprate, the maximum normal operating speed for the HPCI turbine was 4000 RPM.

In order to support core uprated conditions, the HPCI turbine speed was increased to 4100 RPM. Because of the higher turbine speed, the required NPSH for the HPCI pump increased from 21 feet to 23.2 feet.

Appendix B to calculation MD-Q0073-870190 contains the licensee's HPCI pump NPSH analysis.

The HPCI pump initiallytakes suction from the CST then switches to the suppression pool on low CST inventory or high suppression pool level. Condensate

header low level switches, located on the 24" condensate header, actuate suction source

~ switch-over to the suppression pool and are capable 'of measuring liquid level between the 551'nd 553'levations.

The HPCI booster pump suction centerline elevation is located at the 523.2'levation.

The EZFLOW program is used to calculate the gage pressure at the HPCI booster pump suction centerline.

Available NPSH is obtained by converting the suction line pressure to absolute pressure and subtracting the liquid vapor pressure corresponding to 140

. Positive margin NPSH is obtained by subtracting the required HPCI pump NPSH of 23.2'rom the available NPSH. The EZFLOW analysis model analyzed only the Unit 2 suction piping configuration. The licensee calculated an available NPSH from the CST of 62.9', which corresponds to an excess NPSH for the HPCI pump of 39.7'.

Prior to incorporating the EZFLOW model into calculation MD-Q0073-870190, the licensee performed hand calculations to verify the applicability of Unit 2 results to the Unit 3 HPCI system.

The comparison of NPSH results for Units 2

'nd 3 was subsequently deleted by Revision 7 to MD-Q0073-870190, but indicated that the available NPSH from the CST for the Unit 3 HPCI pump was approximately 0.2 feet greater than Unit 2. Based on these earlier hand calculations and relatively large NPSH ma'rgin, the inspectors identified no operability concerns associated with the application of the Unit 2 CST suction analysis to Unit 3.

The inspectors noted that the analysis methodology in calculation MD-Q0073-0190 non-conservatively models the CST suction source elevation as 577', corresponding to the base of the CST, rather than the lower elevation at which suction switch-over to the suppression pool would occur. Although the analysis methodology does account for system head losses along the piping from the CST to the HPCI pump suction, use of a suction source elevation equivalent to the switch-over point could substantially reduce the excess NPSH margin for the HPCI pump, however adequate NPSH would still exist.

Calculation MD-Q0073-920184 does account for the reduced CST header liquid elevation at which switch-over from the CST to the suppression pool could occur. The purpose of MD-Q0073-920184 is to ensure that adequate NPSH is maintained for the HPCI pump during switch-over from the CST suction source to the suppression pool when initiated by low condensate header liquid level. Prior to this inspection, the licensee identified errors in calculation MD-Q0073-920184 regarding the method used to calculate available NPSH for the HPCI pump in PER 98-012814-000.

The analysis methodology of section 2.1 of the calculation underestimated piping head loss by more than 25 feet of head.

Revision 3 to calculation MD-Q0073-920184 incorporated results from the EZFLOW model that incorporated the correct piping head loss but applied the pre-uprate HPCI pump required NPSH value of 21'ice 23.2'.

Furthermore, Revision 3 did not revise Section 2.1 to reflect the correct methodology for calculation of available NPSH.

The non-conservatisms identified in MD-Q0073-920184 will not impact the operability of the HPCI pump as adequate margin is available to account for these identified discrepancies.

The inspectors also reviewed the CST suction source configuration for the potential of air ingestion to the HPCI pump consistent with the requirements of NUREG 0897, Revision 1, and Regulatory Guide 1.82, Revision 2. The Team's concern was that during the automatic transfer from the CST to the suppression pool, air ingestion to the HPCI pump could occur as the water level lowered in the CST suction piping. The licensee stated that no analysis existed for this scenario, however the licensee pointed out that a transfer

to suppression pool suction would occur due to high suppression pool level prior to low CST level. The inspectors noted that existing analyses and licensing documents did not adequately discuss or document that transfer to the suppression pool on high pool level would occur prior to CST low level which would alleviate air ingestion concerris from the

- CST. The licensee initiated PER 98-014338 to address this concern.

Although the inspectors identified a number of non-conservative assumptions in the HPSI pump NPSH analysis from the CST, due to the available NPSH margin, no operability concerns existed and the licensee initiated PERs to address the concerns.

Available HPCI Pump NPSH from the Suppression Poof

• The inspectors reviewed design calculations ND-Q0999-880127, "ECCS Ring Header Strainer Pressure Drop Calculation" which determined the pressure drop across the original strainer baskets at various debris blockage, and MD-Q0073-870190, "HPCI Piping Pressure Drop and NPSH" which in part determined the available NPSH for the HPCI pump. This was done in order to verify that adequate NPSH was maintained with

'he HPCI pump suction aligned to the suppression pool ring header.

The inspectors reviewed the justification for the suppression pool strainer pressure loss used in the analysis.

The licensee documented in Appendix B of calculation MD-Q0073-870190 a fixed suppression pool suction strainer pressure loss of 2.23 psi to be used for the newly installed strainers which was based on results from calculation ND-Q0999-880127 covering the originally installed strainers.

This pressure loss corresponded to the original strainer design pressure loss with 50% blockage at a flowrate of 20,000 gpm.

The suppression pool ring header suction strainers have been replaced in Units 2 and 3 with stacked-disk strainers having approximately twenty five times the open flow area of the original design.

Calculation MD-Q3999-.970055, Revision 0, "ECCS Ring Header Strainer Replacement" was reviewed to ascertain that the new replacement ECCS suction strainers provided equal or less pressure drop to assure adequate NPSH to the HPCI pump. This calculation was the basis used to document acceptability of the new GE supplied strainer replacement and it compared the flow area and debris loading capabilities of the new strainers.

It c'oncluded that the new strainers provided a significant increase in hydraulic open area and therefore could accommodate a larger debris loading. However this calculation did not quantitatively provide a comparison of the pressure drops through the old and new strainers.

This was required to assure that adequate NPSH would be maintained to the HPCI pump as well as the other ECCS pumps.

The licensee assumed that the 2.23 psi pressure drop associated with the original strainers enveloped the pressure drop through the new strainers.

The inspectors reviewed strainer pressure loss data for the original strainer design and the stacked-disk design to verify that use of a fixed strainer pressure loss of 2.23 psi bounded the new strainer design.

Calculation ND-Q0999-880127 reported a clean strainer pressure loss for the original design of 0.31 psi (.73 feet) at a flowrate of 20,000 gpm. Calculation MD-Q2074-87360 determined that an entrance loss of.1 psi (.23 feet)

was also associated with the old'strainer and should be added for a total pressure drop

of.41 psi (.96 feet). The inspectors were informed by the licensee that the new stacked-disk strainer design currently installed has a clean strainer pressure loss of 1.62 feet at a

flowrate of 14,103 gpm which was derived from GE Report GENE-E12-00148-01 entitled

"ECCS Suction Strainer Hydraulic Sizing".

The clean strainer pressure drop for the stacked-disk design corresponds to a pressure loss of approximately 1.4 psi (3.23 feet) at a flowrate of 20,000 gpm, or approximately..

three times the clean pressure drop for the original design.

The licensee provided the inspectors with calculation MD-Q0999-970046 which determined the pressure loss across the new strainers with greater that the current licensing basis debris loading. This calculation demonstrated that available HPCI pump NPSH is adequate and that design margin is available for the new strainer design.

This calculation was provided to the NRC as part of a licensing amendment request to resolve the NRC Bulletin 96-03 concerns.

The inspectors made additional observations with regard to the HPCI pump NPSH analysis.

The EZFLOW model used was representative of the Unit 2 suction piping configuration. The results of the analysis indicated that the available NPSH for the HPCI pump from the suppression pool ring header was 28.2 feet. This available NPSH corresponded to a positive NPSH margin of 5.0 feet. The inspectors identified two concerns with this analysis that may have resulted in failure to conservatively calculate the available NPSH and bound the Unit 3 system.

The EZFLOW model used a flow rate of 5000 gpm from the suppression pool ring header to the HPCI pump suction.

Since the Residual Heat Removal, Core Spray, and HPCI systems take suction from the common suppression pool ECCS ring header, the use of a 5,000 gpm flowrate underestimated ring header pressure losses ifother ECCS systems take suction from the suppression pool simultaneously during accident conditions.

Furthermore, because the suppression pool suction piping in Unit 2 has fewer bends and a shorter pipe length than Unit 3, the EZFLOW analysis does not bound the Unit 3 conditions. The licensee initiated PER 98-014420-000 to address this latter concern.

The inspectors performed independent NPSH calculations for the Unit 3 HPCI pump suppression pool suction source.

This calculation used a piping model representative of the Unit 3 configuration and applied a suppression pool ring header flowrate of 15,000 gpm to account for other ECCS systems taking suction from the suppression pool. A fixed strainer differential pressure of 2.23 psi was also used.

Using a methodology similar to that used in calculation MD-Q0073-870190, the inspectors conservatively calculated available NPSH for the Unit 3 HPCI pump from the suppression pool of approximately 27.1 feet. This available NPSH corresponds to a positive NPSH margin of 3.9 feet. Although the methodology used in MD-Q0073-870190 does not conservatively calculate available NPSH or bound Unit 3, the inspectors concluded that based on the available NPSH margin, no operability concerns exist.

The team also reviewed GE Report GE-NE-B13-01869-100, "Maximum Vortex Penetration Depth", which evaluated the suppression pool suction source configuration for the potential of air ingestion to the HPCI pump consistent with the requirements of NUREG 0897, Revision 1, and Regulatory Guide 1.82, Revision 2. The Team concluded that the GE analysis model was non conservative in that it used a Froude Number of 1.4 as opposed to the RG 1.82 recommended Froude Number of.8 which yields a deeper

vortex penetration.

Independent calculations performed by the Team however using Fr

=.8 resulted in no operability concerns.

c.

Conclusion The inspectors identified a number of minor discrepancies in the design basis calculations, however, the calculations demonstrated no operability concerns associated with adequate HPCI pump NPSH with the suction aligned to the Condensate Storage Tank or the Suppression Pool.

E2.1.2 Condensate Storage Tank (CST) Suction Pipe Break a.

Ins ection Sco e

The inspectors reviewed documents to determine the effects of a CST suction pipe break inside the Reactor Building and its effect on HPCI system operability.

b.

Observations and Findin s A portion of piping from the CST to the HPCI system pumps inside the Reactor Building was not seismically supported.

The Team reviewed the Brown's Ferry Individual Plant Examination (IPE) Report, Section E.1, Internal Floods Analysis.

The bounding case for internal flooding was due to the complete draining of one condensate storage tank (375,000 gallons) coupled with the rupture of the suppression pool (conservatively assumed as 135,000 cubic feet). The inspectors focus was on the rupture of the non seismically supported condensate piping running from the CST into the Reactor Building. The open pathways direct the water to the basement (elevation 519 feet) of the reactor building. The Reactor Building Elevation 519 feet contains a total floor area of 17,750 square feet.

It contains the RHR pumps, the Core Spray pumps, and the turbine driven HPCI pump and RCIC pump. The CST is located in the yard at Elevation 577 feet with a capacity of 375,000 gallons.

For a rupture of only the condensate piping, the flood level would be approximately 3.25 feet deep in the Reactor Building Elevation 519'. The IPE states in Section E.1.3.7 that failure of the CST such that its contents drain into the Reactor Building will not result in direct failure of the Core Spray, RHR, HPCI, and RCIC pumps.

The inspectors observed that the HPCI turbine lube oil pump and auxiliaries were located close to the floor and would be flooded by the 3.25 feet of water in the HPCI pump room. Contrary to the IPE report, the inspectors concluded that this flooding would fail the oil pump and consequently render the HPCI system inoperable.

The inspectors verified that the RCIC system would be essentially unaffected by this flooding event.'he BFN reactor building was designed to contain the effects of a pipe break to one reactor zone and then mitigate the effects of the maximum internal flood level using equipment on an adjacent unit and/or equipment outside the reactor building. The basement of the reactor building is sealed between units to elevation 565 feet (i.e., ground level) with concrete walls and pressure retaining bulk head door Based on the inspector's finding, the licensee noted that the BFN Unit 3 Probabilistic Safety Assessment (PSA) report with Unit 2 operating and a flood scenario in the Reactor Building had a mean Core Damage Frequency (CDF) of 7.07E-10.

The licensee reevaluated this event considering loss of the HPCI system which resulted in a CDF of 7.38E-9. This was an increase of 6.67E-9 which represents an overall CDF increase of 0.08%. This increase represents a non-risk significant situation. The licensee noted that their response to the inspectors based on the revised analysis was not design verified.

PER 98-014423-000 was initiated to address this issue.

Conclusion I

The effects of a CST suction pipe break inside the Reactor Building and its effect on HPCI system operability resulted in a CDF of 7.38E-9 which was a minimal CDF increase of 0.08% and represented a non-risk significant situation.

E2.1.3 HPCI Design Calculations, Sco e of Review The inspectors reviewed representative design calculations and analyses for the HPCI system to determine functional requirements for the system and active components.

b.

Observations and Findin s Calculation MD-Q0073-870193, Revision 6, "HPCI System Vacuum & Pressure

.

Relief Valve Sizing" This calculation determined the adequacy of the HPCI system vacuum and pressure relief valve's capacity to handle required flows. In the event that one of the three 250 Volt batteries becomes inoperable, HPCI motor operated injection valve FCV-73-44 is manually open to its accident position. This action is necessary because the remaining two batteries did not have sufficient capacity to power all required loads.

Upon realigning the injection valve to full open, flowfrom the feedwater system is isolated from the HPCI pump discharge and suction piping by testable check valve FCV-73-45 which is a containment isolation valve subject to IST requirements.

This calculation in part evaluated the capability of pressure relief valve 73-506 located in the HPCI pump suction piping to relieve pressure created by leakage thr'ough the 73-506 as well as the pressure created by the trapped volume of water being heated in the HPCI piping. The subject calculation used a maximum leakage of 10 cc/hr/in which is the maximum permitted leak rate mandated by standard MSS-SP-61, 1977, the code used for leak rate acceptability on newly manufactured valves.

The IST Administrative Leak Rate Limitfor this valve.

was 24 scfh (air) which equates to 16,000 cc/hr as compared to 140 cc/hr used in the calculation.

The inspectors performed an independent analysis and concluded that even at the higher permitted leak rate through FCV-73-45, pressure relief valve 73-506 had adequate relieving capacity.to assure that the suction piping would not be overpressurized.

The licensee initiated PER 98-014418-000 to address this error in the calculatio Calculation MD-Q0073-880139, Revision 6, "HPCI System, Design Pressure and Temperature, 3458 MWt" This calculation determined the design pressures and temperatures of all the various sections of the HPCI system based on normal operating conditions and variations from-normal operating conditions.

It also was intended to verify the adequacy of the various system components subjected to maximum achievable coincident pressures and temperatures.

The calculation also addressed pressure and temperature excursions that may occur.

Section 5.0, Assumptions, page 9, assumed that the peak pressure, which is the condition of the pump running at shutoff head, occurred at 5% turbine overspeed.

The HPCI turbine overspeed trip setpoint was established at 122% of the turbine normal speed of 4100 rpm. The inspectors were concerned that should there be a failure of the turbine governor control system, the turbine would ramp up to the overspeed trip setpoint very quickly, thereby developing a significant rise'in pump discharge pressure.

At time equals zero, or the time the pump/turbine receives a start signal, three possible discharge flow paths are all closed.

These flow paths are isolated by the normal HPCI injection valve FCV-73-44, the minimum flow valve FCV-73-30, and the test return valve FCV-73-35. The injection valve and the minimum flowvalve begin to.open at pump start.

In response to the inspector's inquiry, the licensee confirmed that the discharge valves had sufficient opening thrust capability to unseat against the line pressure associated with a turbine overspeed trip. The inspectors concluded that the pressure spike would probably exceed the pressure related to 105% turbine speed which the calculation currently assumed.

The inspectors requested that a verification be performed to address the turbine overspeed developed pressure.

Additionally, the inspectors noted that the subject calculation did not address the pressure/temperature ratings and limitations for individual components in the pump discharge piping. Other portions of the HPCI system such as the steam piping and components to the turbine and exhaust line from the turbine were evaluated.

In response to the inspector's inquiry regarding these items, the licensee initiated PER 98-014419-000.

Calculation MD-Q0073-870190, Revision 7, "HPCI Piping Pressure Drop and NPSHA This calculation determined the HPCI pump head requirements, the net positive suction pressure available (NPSH), the pressure drops through the steam piping to the pump turbine and exhaust piping, and also calculated the minimum pipe wall thickness for the HPCI piping.

Specific concerns of the inspectors related to NPSHand air ingestion as related to this calculation have been extensively discussed in Section E.2.1.1 of this report. The inspectors also reviewed the portion of this calculation that determined the pressure drop in the steam line to the HPCI pump turbine.

Part 7 of the calculation addressed the

. impact of the Power Uprate system conditions to the calculation, and Appendix A addressed the applicability of the main calculation to both Browns Ferry Units 2 and 3 based on the similarity between the units. The maximum permitted pressure drop in the steam supply piping was 10 psi. The licensee's methodology was to treat this calculation

as an incompressible fluid analysis provided that the pressure drop determined was less than 10%. The inspectors confirmed that this methodology was valid and that the design inputs were accurate.

The inspectors independently calculated the steam line pressure drop and determined the results to be comparable to the licensees and concluded that

- this portion of the subject calculation was acceptable.

A similar review was performed on the steam exhaust piping pressure drop which was also found to be acceptable.

Calculation HAND-Q0073-920184, Revision 3, "Analytical Limits for HPCI Pump Suction - Automatic Transfer to Suppression Pool" The purpose of this calculation was to document analytical limits for the HPCI System Level Switches LS-73-56A, -56B, -57A, and -57B for automatic HPCI pump suction transfer to the Suppression Pool in case the water level of the. Condensate header falls below a predetermined level or the Suppression Pool water level rises above a predetermined level. The limits were established to ensure that there was sufficient water to supply the HPCI pump while realignment to the suppression pool was accomplished.

The inspectors noted that the subject calculation used an incorrect formula in the assumptions paragraph 2.1 which determined NPSH in the suction piping from the CST.

This error was detected by the licensee in its self initiated internal audit of the HPCI system and was documented in PER 98-012814-000.

The inspectors also observed that although this error was discovered and documented in the PER, a subsequent revision to the subject calculation did not address this error. The inspectors concluded no operability concern was related with this error since significant NPSH margin exists when taking suction from the CST. The licensee wrote PER 98-014338 to initiate corrective action for the inspection finding.

'onclusion In general, the HPCI design calculations reflected the current design and licensing basis.

Various errors in methodology and/or inputs were detected in the majority of calculations

.

reviewed, however they were usually of a minor nature and no errors resulted in operability concerns.

E2.1.4 HPCI Design Modifications The inspectors reviewed one significant design modification made to the original system in order to determine whether the system meets the design basis and licensing basis in the as-modified configuration.

b.

Observations and Findin s The inspectors reviewed design modification DCN T-40211A, "Replacement of ECCS Suction Strainers".

The existing BFN Unit 3 basket style ECCS suction strainers were replaced with larger, higher debris capacity strainers.

The new strainers employ a

.

passive-type design that does not require operator action to ensure an uninterrupted suction flowto the ECCS systems.

The new strainers have an open flow area approximately twenty-five times larger than the existing strainers in order to accommodate higher debris loading mandated by NRC Bulletin 96-03.

Much of the review of this modification has already been documented in this report paragraph E2.1.1, HPCI Pump Net Positive Suction Head (NPSH). As stated previously, the inspectors reviewed design calculations ND-Q0999-880127, "ECCS Ring Header Strainer Pressure Drop Calculation" which determined the pressure drop across the original strainer baskets at various debris blockage, and MD-Q0073-870190, "HPCI Piping Pressure Drop and NPSH" which in part determined the available NPSH for the HPCI pump. This was done in order to verify that adequate NPSH was maintained with the HPCI pump suction aligned to the suppression pool ring header which contained the

~

newly installed strainers.

Upon implementation of NRC Bulletin 96-03 commitments, the new ECCS suction strainers willbe required to handle a much higher debris loading.

In order to accommodate the higher debris loading, it willbe necessary to take credit for containment accident pressure to assist the suction pressure to the ECCS pumps.

The licensee has submitted a licensing change request to permit taking credit for the accident overpressure.

Conclusion The calculation which supported the modification for installing the new ECCS suction strainer demonstrated adequate NPSH for the HPCI pump for specified containment overpressure conditions.

The new strainers have an open flow area approximately twenty-five times larger than the existing strainers in order to accommodate higher debris loading mandated by NRC Bulletin 96-03.

E2.1.5 HPCI System Walkdown Ins ection Sco e

The inspectors performed a detailed walkdown of accessible portions of the Unit 3 HPCI system suction and discharge piping. The field configuration was verified against the HPCI system flow diagram and compared to the design basis calculation hydraulic models.

Observations and Findin s

The inspectors performed a detailed walkdown of accessible portions of the Unit 3 HPCI suction and discharge piping in order to verify that the as-built configuration of the system piping was consistent with the Drawing 3-47E812-1 R047, Flow Diagram High Pressure Coolant Injection System, and design basis calculations.

In general, the inspectors concluded that the as-built Unit 3 configuration was consistent with the system fiow diagram. A number of minor discrepancies were found during the walkdown and were provided to the license i

Based on the walkdown, the inspectors concluded that the design basis calculations performed in MD-Q0073-870190 were not representative of the as-built Unit 3 suction piping configuration. The Unit 3 suction piping from the suppression pool contains five 90 elbows and approximately 100 feet of 16" piping. The EZFLOW model for the Unit 2 HPCI suction from the suppression pool includes only two 90'lbows and 47.3 feet of 16" piping. The use of a non bounding design NPSH calculation for Unit 3 is discussed in Section E2.1.1. The inspectors verified that the EZFLOW model in MD-Q0073-870190 adequately modeled the as-built Unit 2 HPCI pump suppression pool suction.

Conclusion The detailed walkdown of the accessible portions of the Unit 3 HPCI system suction and discharge piping identified no concerns that would prevent the HPCI system from accomplishing its design safety function.

E2.1.6 HPCI Mechanical System Pump Surveillance Test Acceptance Criteria Sco e of Review The inspectors compared the HPCI design process requirements against the Technical Specification Surveillance Requirements and associated surveillance test procedures.

Observations and Findin s Section 3.1.3 of Design Criteria BFN-50-7073, High Pressure Coolant Injection System Units 2 8 3, states that the HPCI system shall be capable of delivering water to the reactor core at a minimum rate of 5000 gpm over a range of reactor pressures from 1189 psia to 165 psia. The basis for this flowrate was to maintain adequate core cooling for LOCA events that do not result in rapid depressurization of the reactor core. Technical Specification Surveillance Requirements SR 3.5.1.7 and SR 3.5.1.8 test the HPCI system, at 92 day and 18 month intervals respectively, to ensure the system is capable of providing rated flow at both the higher and lower pressure ranges of the system.

The inspectors verified that Surveillance Procedures 3-SR-3.5.1.7 and 3-SR-3.5.1.8 met TS requirements for HPCI pump developed flowrate.

Surveillance Procedure 3-SR-3.5.1.7 is performed with reactor pressure within the range of 950 psig to 1040 psig. This test verifies the capability of the HPCI system to develop a flowrate of at least 5000 gpm, against a system head corresponding to reactor pressure.

During this surveillance test, steam for the HPCI turbine is supplied by the reactor and HPCI discharge pressure is controlled by throttling the HPCI Pump Test Valve, FCV-73-35. The test acceptance criteria requires the HPCI pump to'develop a flow of at least 5000 gpm with a minimum discharge pressure of at least 110 psi above reactor pressure.

The factor of 110 psig conservatively accounts for pressure losses associated with the HPCI discharge piping. The maximum discharge piping loss stated in calculation MD-Q0073-870190, HPCI Piping Pressure Drop and NPSH, corresponds to a head loss of 168.2 feet (approximately 73 psi). Although the surveillance procedure conservatively accounts for discharge piping losses, the minimum acceptable HPCI pump discharge pressure does not directly represent the worst case accident conditions

specified in the system design requirements (i.e. a reactor pressure of 1189 psia). The inspectors used pump affinitylaws and extrapolated recent surveillance data and verified that the HPCI pump could achieve a discharge head corresponding to a reactor pressure of 1189 psia without exceeding a maximum expected turbine speed of 4100 RPM.

The inspectors reviewed Section 7.13 of Surveillance Procedure 3-SR-3.5.1.7 which is dedicated to obtaining ASME Section XI data for the HPCI main and booster pu'mps.

For this portion of the procedure, the licensee used a constant turbine speed of 3800 rpm which is maintained within a tolerance of plus or minus 25 rpm. The licensee established appropriate pump head baseline and alert limits, however the inspectors noted that pump head data collected was difficultto use for trending pump degradation because of the variation (within tolerance) of the turbine speed.

The procedure made no provision for analytically correcting the pump head to a constant speed using the affinity laws which would give valid data for pump degradation trending. The inspectors independently made corrections to several data points and confirmed that pump degradation was within the established acceptance band.

Surveillance Procedure 3-SR-3.5.1.8 is performed with maximum reactor pressure of 165 psig to verify that HPCI can deliver rated flow at the lower end of the design pressure range.

The steam supply to the HPCI turbine during this test can either be the reactor or the auxiliary boilers. The minimum acceptable HPCI pump discharge pressure stated in paragraph 6.2.2 of the surveillance procedure is 110 psi above the steam supply pressure.

The inspectors noted an inconsistency in the test acceptance criteria in that the minimum acceptable HPCI pump discharge pressure when using the auxiliary boiler is specified as 265 psig in step 7.20.8.3.

For an auxiliary boiler steam supply pressure of 165 psig, this discharge pressure would be only 100 psig above steam supply pressure and therefore be inconsistent with the test acceptance criteria specified in step 6.2.2. The licensee issued PER 98-014388-000 to document this deficiency

.

C Conclusion Surveillance procedures used to perform HPCI pump flowrate testing met Technical specification requirements.

The inspectors noted that high pressure HPCI pump testing was not representative of HPCI system design criteria for worst case accident conditions.

The procedures used to satisfy ASME XI requirements were acceptable and met code requirements.

Electrical Design Review Ins ection Sco e

The inspectors reviewed FSAR (Final Safety Analysis Report) Section 8.6 "250 Vdc Power Supply and Distribution", and Calculation ED-Q248-870041 "250 Vdc Unit Battery Load Study", Revision 20, to determine ifthe DC system was in conformance with the licensing basis and was capable of performing its design functio i

b.

Observations and Findin s The inspectors reviewed Calculation ED-Q248-870041 and determined that the licensing basis of FSAR Sections 8.6.2.2, 8.6.4.1, and 8.6.5.

Calculation ED-Q248-870041 required that when one 250 V Unit Battery was inoperable, HPCI valve FCV-73-44 be manually repositioned from the closed position to the open position so that it would not have to operate during an accident.

This action was necessary because the remaining two unit batteries did not have sufficient capacity to power all required loads.

By pre-aligning valve FCV-73-44 to its accident position (open) it would no longer constitute a load on the batteries, and with this reduced load, the licensing basis could be met. The capacity limitations on the 250 Vdc system design required the manual realignment of alternate power sources from another battery and repositioning of valves to meet the FSAR licensing basis requirements for the 250 Vdc system.

The inspectors noted that with a simultaneous loss of a battery and an accident, there would be no opportunity to perform any realignment, and under this scenario one safety division would be lost. The inspectors determined that the BFN design required that all electrical equipment of the "Engineered Safeguards System" (ESS) be placed in either Division I or Division II. By this design feature, when one battery is lost, one Division of ESS is also lost. Using Unit 3 as an example, if250 V Battery No. 3 is lost, Unit 3 Division II is also lost and only Unit 3 Division I is available for performing ESS functions.

Based on this inspection finding the licensee issued problem evaluation report PER 98-014034 to revise the FSAR wording to more clearly reflect the licensing basis which included operator actions given the design basis limitations of the 250 Vdc system.

The licensee stated that FSAR section 8.6.2.2, would be revised to clarify the existing licensing basis as follow: "Battery capacity shall be adequate so that any two batteries can supply for 30 minutes, without chargers available, the DC power required to achieve the safe shutdown and cooldown of all three units in the event of the loss of offsite power and a design basis accident in any one unit". The licensee stated that after manual realignment of alternate power sources from another battery, and repositioning of valves, the FSAR statements were met, and that the FSAR was written to include such operator actions.

Conclusion Although there were capacity limitations on the 250 Vdc system design, manual realignment of alternate power sources from another battery and repositioning of valves allowed the 250 Vdc system to meet the FSAR licensing basis requirements.

The licensee stated that this condition has existed since original plant design, and a PER was written to revise the wording of the applicable FSAR sections so that they more clearly reflect the licensing basi a

E2.2.2 Effect of Power U rate on HPCI Electrical E ui ment Ins ection Sco e

The inspectors evaluated the effect of the 5% power uprate on the High Pressure Coolant Injection (HPCI) System electrical equipment.

The evaluation bounded two distinct areas of concern; first the effect of changed environmental conditions on HPCI equipment, and secondly the effect of changed operational conditions on HPCI MOVs.

Observations and Findin s The inspectors compared pre-uprate, and post-uprate revisions of Drawings 3-47E225-103, "Harsh Environmental Data El 519.0", Revision 5 against 6, and 3-47E225-104, "Harsh Environmental Data HELB Profiles - Room No. 1 El 519.0",

Revision 3 against 4.

Dra'wing 3-47E225-103 showed that there was no change of the integrated accident dose as a result of the power uprate.

Drawing 3-47E225-104 showed subtle changes in HPCI room temperature and pressure profiles. There was an increase of peak temperature from 265'F to 270'F, and an increase of peak pressure from 15.5 psia to 16.0 psia.

Both these increases were deemed to be of no safety significance because the pre-uprate qualification profiles for HPCI room components bounded the post-uprate peaks and durations.

This was supported by the 10 CFR 50.59 Evaluation of DCN S40793A which documented the results of the environmental qualification of equipment within the scope of the 10CFR50.49 EQ Program.

The inspectors also reviewed two specific evaluations performed by the licensee for environmental parameter changes resulting from the power uprate.

One was for Fenwal temperature switches, and the other for Limitorque MOVs. The evaluations were identified as Open Item OI-ITS-001-009, dated 9/28/98, and Open Item OI-MOV-003-012, dated 9/28/98.

Evaluation Ol-ITS-001-009 showed that the temperature switches had been demonstrated to survive a temperature of 350'F and a pressure of 26 psig, both values exceeded by far the post-uprate peak temperature and pressure of 270'F and 16.0 psia (1.6 psig) of the HPCI room.

Evaluation Ol-MOV-003-012 showed that the Limitorque MOVs had been demonstrated to survive a temperature of 340'F and a pressure of 120 psig, again both values exceeded by far the post-uprate peak temperature and pressure of 270'F and 16.0 psia (1.6 psig) of the HPCI room.

In order to evaluate the effect of changed operating conditions resulting from the power uprate on MOVs, the inspectors reviewed plant modifications DCN. No. S40979A,

"Non-physical Work Document Changes Required by Power Uprate on Unit 3",

S40688A, "89-10 MOV Mods for 105% Power Uprate" and DCN No. S40689A, "89-10 MOV Gale Revisions for 105% Power Uprate".

DCN S40979A identified plant design documents for which documentation changes only were made as a result of the power uprate. The only changes involving high pressure coolant injection MOVs were made for MOVtesting requirements which were provided on Drawing 3-47B370-2 "Mechanical Motor Operated Valves - Testing Requirements",

Revision 17, and reflected updated thrust requirements.

DCN S40688A identified MOV modifications required by the GL 89-10 program that were needed for the 105% power uprate. High pressure coolant injection MOVs FCV-73-35 and FCV-73-81 required revisions to drawings and documents to show new thrust requirements for the valves.

DCN S40689A identified the MOVcalculations from the GL 89-10 program that were revised for the 105% power uprate.

High pressure coolant injection MOVcalculations for FCV-73-30 and FCV-73-44 were the only HPCI MOVs identified in the DCN and the calculations were revised to incorporate new 105% uprate parameters.

Conclusion The inspectors concluded that the electrical equipment in the HPCI room were qualified to meet the environmental changes resulting from the power uprate.

No HPCI room components were required to be changed or modified as a result of the power uprate.

E2.2.3 250 Vdc Unit Batte Rooms - Minimum Tem erature Ins ection Sco e

The inspectors reviewed the licensee's calculations and procedures which ensured thatb the Unit 1, 2, and 3 battery room temperatures were maintained above 60'F.

Observations and Findin s The inspectors reviewed Calculations ED-Q0248-870041, "250 Vdc Unit Batteries Load Study", Revision 20, and ND-Q0999-910030, "Summary of Mild Environmental Conditions for Browns Ferry Nuclear Plant", Revision 7. The sizing calculation for the 250 Vdc Unit batteries were based on an ambient temperature of 60 degrees Fahrenheit or higher.

Calculation ND-Q0999-910030 determined the normal temperature range of the unit battery rooms as 60'F to 104'F. The minimum value was an input to Calculation ED-Q0248-870041 which was used for sizing the batteries. Calculation ND-Q0999-910030 stated that any abnormal temperatures would be discovered during operator rounds, and based on these rounds, would only exist for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> at a time.

The inspectors questioned the basis for the frequency of determining battery room temperatures, and the absence of any acceptance criteria should the temperature be found less than 60'F.

Technical Specification section 3.8.6, "Battery Cell Parameters",

required the associated battery be declared inoperable ifthe average electrolytic temperature of the

e

representative cell was <60'F; however, Technical Specification surveillance requirement 3.8.6.3 required verification of average electrolytic temperature at 60'F or higher only every 92 days.

The licensee stated that the battery room temperatures were not routinely monitored as long as normal or emergency HVACwas operating.

Temperatures were monitored in accordance with procedure O-OI-31, "Control'Bay and Off-Gas Treatment Building Air Conditioning System", Revision 64, when normal and emergency ventilation was unavailable and temporary ventilation was operating.

A review of 0-Ol-31 indicated that temperatures were monitored during each 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shift and more frequently with rising temperatures.

Procedure 0-Ol-31 contained actions and monitoring requirements for rising temperatures.

The procedure, however, contained no actions for falling temperatures.

The licensee stated that the unit battery rooms and battery pilot cell temperatures were measured and recorded weekly as part of surveillance requirement (SR)-3.8.4.1(1, 2, 3), "Weekly Check for 250 Volt Main Bank Number 1 (2,3)", (Revision 1 all units). These surveillance requirement did not contain acceptance criteria for minimum.temperatures iffound.

At the inspectors request the licensee performed a data base search and determined that the lowest temperature recorded as part of the weekly surveillance was 62'F for battery room temperature and 65'F for pilot cell temperature, both for Unit 3. No instances of battery room or electrolytic cell temperatures less than or equal to 60'F were found.

Based on the inspectors concern that the licensee had no calculation to show that Unit 1, 2 and 3 battery room temperatures would remain above the minimum of 60'F during worst case conditions, the licensee modified Calculation MD-Q0031-930059, "Control Bay Transient Analysis" Revision 1, using worst case minimum outside temperature conditions and determined the temperature of Unit 3 battery room with Unit 3 shutdown and a loss of HVAC. The preliminary analysis revealed that the unit battery room temperature would rise approximately 2'F subsequent to the HVAC loss, and would not fall below its initial temperature.

The licensee wrote PER 98-014331 to document the need for:

1) minimum temperature acceptance criteria in SR-3.8.4.1(1,2,3);

2) instructions in 0-Ol-31 for temperatures approaching 60'F, and 3) to address the monitoring specified in calculation ND-Q0999-910030.

Additionally, based on the inspectors findings the licensee wrote PER 98-014335 to initiate corrective action for calculation ED-Q0248-870041 which contained'data from,an environmental drawing that had been voided.

Conclusion The licensee demonstrated by a revised calculation that battery room temperatures would remain above the minimum of 60'F during worst case condition E2.2.4 Fuse Discre ancies a.

Ins ection Sco e

- The inspectors conducted a walkdown to verify that fuses identified on various HPCI Schematic Diagrams agreed with the data entered in the Fuse Tabulations, and in turn that the Fuse Tabulations were representative of the as-built fuses found in the electrical equipment.

b.

Observations and Findin s The inspectors randomly selected thirteen fuse identification numbers (IDs) from HPCI circuits on:

Drawing 3-45E779-13 "Wiring Diagram 480 V Shutdown Auxiliary Power Schematic Diagram", Revision 13, Drawing 3-45E714-3 "Wiring Diagram 250 V Reactor MOV Bd 3A Schematic Diagram" Revision 8, Drawing 3-45E714-2 'Vfiring Diagram 250 V Reactor MOV Bd 3A Schematic Diagram" Revision 17, and Drawing 3-45E714-4 "Wiring Diagram 250 V Reactor MOV Bd 3B Schematic Diagram" Revision 27.

These IDs were then reviewed against fuse tabulations to verify that the function and fuse size matched that shown in the schematic diagrams.

The Fuse Tabulations listed below provided the fuse type, function, location, manufacturer, and safety class.

It was noted that all fuses selected were Safety Class.

Drawing 3-45B721-12-1 "Electrical Equipment Fuse Tabulations" Revision

Drawing 3%5B721-13-1 "Electrical Equipment Fuse Tabulations", Revision 3 Drawing 345B721-13-3 "Electrical Equipment Fuse Tabulations", Revision

Drawing 3-45B721-26-4 "Electrical Equipment Fuse Tabulations", Revision 3 Drawing 3-45B721-85-2 "Electrical Equipment Fuse Tabulations", Revision

Following this activity, the fuses were walked down to verify compliance with the data obtained from the Fuse Tabulations.

Of the original thirteen fuse IDs selected, four were determined to be in operations-sensitive inaccessible locations and were removed from the scope of the walkdown. Of the remaining nine fuse IDs, seven matched the data in the Fuse Tabulations, and two were found to be inconsistent.

On further review, one of these inconsistency was found to be acceptable since it was an approved fuse substitution.

The remaining fuse ID was determined to be a discrepancy.

This fuse size was correct, but was of a different manufacturer from that specified in the Fuse Tabulation.

An

operability assessment performed by the licensee showed that the fuse was for an indicating light circuit having no immediate safety function or significance.

The licensee issued PER 98-014336 to initiate corrective action for this inspection finding.

Conclusion The licensee's fuse control configuration management program adequately assured the operability of supplied electrical equipment.

E2.2.5 Use of Unverified Com uter Software Ins ection Sco e

b.

The inspectors reviewed'the licensee's use of unverified BATCALCsoftware in 250 V DC Unit Battery sizing calculations.

Observations and findin s The inspectors questioned the use of licensee acknowledged non-QA programs in calculations involving a safety system.

BATCALCis a non-QA program consisting of thousands of formulas, hundreds of macros, and an extensive database contained on a LOTUS spreadsheet.

BATCALCwas created by the licensee to aid in the performance of battery load calculations.

The Inspectors reviewed Calculation No. ED-Q0248-870041, "250 Vdc Unit Batteries Load Study", Revision 20. The calculation allowed the use of BATCALCas long as the results were verified by hand checking a sample of the main features of the calculations.

The inspectors also reviewed Tennessee Valley Authority Nuclear (TVAN)procedures NEDP-2, "Design Calculation Process Control and Standard Programs", Revision 0, and SPP-2.6, "Processes",

Revision 0. The inspectors determined that procedure NEDP-2.

allowed the use of non-QA software for calculations/analysis as long as checking, reviewing, and other requirements of NEDP-2 were met. Procedure SPP-2.6 established requirements for the software quality assurance plan and software verification and validation plan for computer software used to support design.

Additionally, procedure SPP-2.6 specifically listed end user tools (word processors, spread sheets, graphics/presentation tools, data base systems, etc.) as not being controlled by TVAs standard program and processes(

SPP).

The licensee, however, considered BATCALC to be an end user tool allowed by TVANprocedures as long as the requirements in NEDP-2 were met.

As part of the Licensee Unit 3 Self-Assessment on the HPCI System, the licensee identified a case of non-QA software (BATCALC)being used without hand calculation verification. Recent revisions of Calculation ED-Q0248-920089 "250 Vdc Unit Battery Load Study" were issued without performing the required hand calculation verificatio This problem was documented in PER Report 98-012555.

The calculation results were reviewed by the licensee and no technical deficiencies were found.

Discussions with the licensee indicated that they recognized the limits of using non-QA-software such as BATCALCand have procedures in place governing its use.

BATCALC cannot be verified due to the nature of spreadsheets.

The inspectors were informed that TVAwill be using the software,"Electrical Transient Analysis Program" (ETAP) to perform battery load calculations in the future. This software willsatisfy all QA requirements including verification and validation requirements.

Conclusion The inspectors concluded that the licensees use of the program BATCALCwas an acceptable use of non-QA software.

One instance of improper use of BATCALCwas identified and corrected by the licensee.

The Licensee recognized the limitation of using non-QA software and planned on using an industry recognized verified program in the near future.

E2.2.6 Ade uate Volta e for HPCI Turbine Governor Ins ection Sco e

The inspectors reviewed the voltage drop calculations for the 48 Vdc power supplies which provided power to the HPCI turbine speed control unit to determine ifthe governor had adequate voltage.

b.

Observations and Findin s The inspectors reviewed Calculation ED-Q0256-880707 "Loading Calculations for the ECCS ATU Inverters and Logic Power Supplies for Panels 9-81 through 9-88" Revision 7, and Woodward Governor EGM Control Product Specification 37722C.

The calculation assumptions were adequate and used a sound engineering approach.

The Woodward Governor Specification required a minimum dc voltage of 43.2 V and a maximum voltage of 52.8 V. Calculation ED-Q0256-880707 concluded that the available voltage at the governor would range from a minimum of 43.36 Vdc to a maximum of 53 Vdc. The maximum voltage was 0.2 V higher than specified, however, the voltage drop in the connecting cables would reduce the maximum to less than that specified. The minimum calculated voltage was 0.16 V greater than required by the specification and was acceptable.

Conclusion

The review of calculation ED-Q0256-880707 showed that the assumptions made were adequate and a sound engineering approach was used.

The review verified that the 48 Vdc power supplies were sized adequately to supply the HPCI turbine speed control uni E2.2.7 Electrical Load Trackin Pro ram a.,

Ins ection Sco e-The inspectors reviewed BFN procedures in place to track and capture all ac and dc load increases and decreases made by temporary modifications, modifications, etc. to ensure that the capacities and capabilities of electrical equipment and systems that supported the HPCI System were not exceeded.

b.

Observations and Findin s BFN Electrical Instruction No.98-001, "Electrical Instruction for Electrical Calculations",

Revision 0, was reviewed by the inspectors.

This instruction identified the appropriate calculations required to support design modification packages.

The instructions listed approximately 200 base line electrical calculations with the associated mini-calculations.

All base line calculations, with the exception of two, had one one associated mini-calculation. Two base line calculations had two associated mini-calculations that were broken up into 4 kV and 480 V portions.

Each mini-calculation was broken up into addendums that contained a calculation for each design modification. When an addendum was added or changed, the mini-calculation was reviewed to ensure that any accumulative effects of load changes were recognized.

After implementation of a design modification, the associated addendum of the mini-calculation was incorporated into the baseline calculation.

TVAis planning to utilize Electrical Transient Analysis Program (ETAP) to perform many of their electrical calculations in the near future. This software should account for the accumulative effects of dc and ac load increases and decreases due to design modifications.

c.

Conclusion Discussions with the licensee indicated that BFNP did not have a formal electrical load.

tracking program.

The licensee had established administrative processes, however, which ensures that overall effects of load increases and decreases are taken into account to assure no adverse effects on operability.

E2.2.8 Ade uac of250Vdc Volta eat HPCI Control Circuit Cpm onents a.

Ins ection Sco e

The inspectors reviewed Calculation ED-Q3999-920106 "CCVDfor Unit 3 DC Circuits",

Revision 10, to determine if adequate dc voltage existed at all buses required to support the HPCI System and other safety system Observations and Findin s This calculation analyzed the minimum and maximum dc control circuit voltages for circuit breaker trip and closing coils, contactor coils, motor starter coils, and solenoid valves, to assure that the devices had voltages within their rated requirements..

The calculation assumptions and methodology were found to be technically sound, and the results showed that all the control devices analyzed had minimum and maximum voltages within the desired limits.

Some discrepancies were noted by the inspectors which may affect the conclusions of the calculation.

None of the discrepancies appeared to effect equipment operability, however, the licensee issued PER 98-013705 to initiate corrective action for the deficiencies.

c.

Conclusion The inspectors concluded that the calculation was technically sound and supported the adequacy of voltage supplied by the 250 Vdc system at HPCI control circuit components and showed that all the control devices analyzed had minimum and maximum voltages within the desired limits.

Ins ection Sco e

Because of the HPCI Systems dependence on the dc system, the inspectors inspected the battery rooms and identified a small diameter pipe running through the Battery Rooms and the Board Rooms.

They assessed its function and design to determine if it presented a hazard to the equipment contained in the room.

b.

Observations and Findin s A potential hazard existed in the 250 Vdc Battery Rooms and the 250 Vdc Board Rooms from what appeared to be a commercial grade, non-qualified potable water pipe running through the rooms. The licensee provided an analysis of the pipe, indicating that it was a potable water pipe serving eyewash stations, sinks, and water coolers.

The pipe material was Type K copper tubing ranging from 1" to 1/2" diameter, and could withstand 700 psi.

The design pressure of the system was 100 psi. Joints were both soldered and threaded, and the pipe was part of original plant design, and was installed using standard industrial installation practices by qualified craft personnel.

The licensee indicated that the pipe had been evaluated under the seismic category two over one program for seismic and pressure retention concerns, and was found to be acceptable.

Based on the inspectors concerns the licensee issued PER Report 014487 to perform a failure mode and effects analysis to determine ifthere are any safety implications associated with the pipe's failure in the 250 V battery and battery board room c.

Conclusion The inspectors concluded that the function and design of the Battery and Board Rooms were adequate.

E2.3 Instrumentation and Control (l8C) Design Review E2.3.1 Plant Modifications a.

Ins ection Sco e

The inspector reviewed plant modification packages developed and implemented by TVA as a result of the power uprate.

b.

Observations and Findin s Plant modifications DCN No. T40666A and DCN No. T40785A, were prepared in connection with reviews performed for Unit 3 setpoint and scaling calculations for selected instrument loops in the HPCI system.

The reviews were required in response to changes in analytical limits involving reactor power and plant environmental conditions.

Using revised analytical limits and changed environmental conditions, the instrument loops setpoint calculations were revised as required by the power uprate.

Additionaly, nuclear engineering setpoint and scaling calculations were revised to incorporate revised information contained in the setpoint and scaling calculations.

The scope of the plant modification included the following instrument loops which were evaluated and the setpoint and scaling calculations prepared to address the changes in analytical limits and environmental conditions.

Instrument Loo s 3-L-73-56A, B Transfer HPCI pump suction from condensate header to the suppression pool.

3-L-73-57A, B Transfer HPCI pump suction from condensate header to to the suppression pool.

3-P-73-1A, B,C,D.

Isolate HPCI turbine on low supply steam pressure.

3-T-73-2A through S During HPCI steam line break, high temperature initiate HPCI steam line isolation and alarms.

3-P-73-20A through D Isolate and trip the HPCI turbine on high pressure between the turbine exhaust and rupture dis U-73-23A-K43; Provide smooth transition from test mode to injection mode upon receipt of HPCI initiating signal.

3-F-73-33 Decreasing setpoint opens minimum flow bypass valve 3-FCV-73-30 on Iow HPCI pump flowfor purpose of pump protection.

Increasing setpoint closes the minimum flow bypass valve when HPCI flow demand is sufficient. The flow switch also provides annunciation in the main control room.

3-D-73-1A, B.

Monitors HPCI turbine high flow and provide isolation upon supply line break.

The inspector reviewed the 50.59 safety evaluations prepared in connection with the plant modification and determined that no unreviewed safety question (USQ) was identified

.The reviews performed by TVAengineering personnel concluded that no hardware changes were required and the instruments were capable of performing their design functions under power uprate conditions. The inspectors did not identify any deficiencies with the plant modification packages reviewed.

c.

Conclusion The licensee had adequately developed and implemented plant modifications for HPCI system instrument loops and demonstrated their capability to operate under power uprate conditions.

E2.3.2 Instrument Accuracy Calculations a.

Ins ection Sco e

The inspectors reviewed selected setpoint and scaling calculations in order to determine the demonstrated accuracy of the instruments covered by the calculations and verify that the instruments will perform its safety function without exceeding safety or operational limits.

b.

Observation and Findin s

'I The NRC in section 8.4 of SER related to amendment number 254 and 214 for facility operating licenses DPR-52 and DPR-68 determined that TVAhad calculated fission

.

product inventories based on 1400 effective full power days at a rated power of 3458 Mwt. The licensee considered the effects of the power uprate at BFNP Units 2 and 3 on instrument loop accuracies and completed the listed calculations to identify environmental parameter changes which could affect instrument accuracies.

~

Calculation ND-Q0999-980002, Evaluation of Radiological Calculations for Power Uprate and 24 Month Cycle Impact, Revision ~

Calculation ND-Q3999-910036, Summary of Harsh Evnvironmental Conditions for BFNP Unit 3, Revision 11.

~ -

Calculation ND-Q3999-970012, Reactor Building Environmental Analysis for HELBs-Power Uprate, Revision 2.

Design output drawings (CCD) number3-47E225-103, Harsh Environmental Data Elevation 519, Revision 6, and 3-47E225-102, Harsh Environmental Data HE Elevation View, Revision 3 was also prepared by the licensee to accurately reflect the environmental conditions at the instruments location for 6 plant operational conditions.

The inspectors used the above design output drawings and design basis calculations to

~verify the environmental parameter design inputs to setpoint and scaling calculations.

The plant operating conditions for which environmental conditions were verified are.

described in calculation ND-Q3999-910036 as follows:

0 erational Condition 3 LOCA Allparameters listed under this condition are a result of a design basis accident loss of coolant accident (DBA LOCA) inside primary containment.

0 erational Condition 6-HELB Inside Prima Containment HELB-IPC The LOCA temperature, pressure, and relative humidity conditions envelope the HELB-IPC conditions and should be used.

NOTE: The LOCA peak temperature used is actually due to the main steam line break inside primary containment and is conservatively used for LOCA and HELB-IPC.

The licensee has developed and issued for use technical instruction EEB-TI-28, Setpoint Calculations, Revision 2. This instruction define the minimum requirements for assuring that setpoints and associated scaling have been established within and will be maintained within specified limits for nuclear safety related instruments.

It describes the method for determining the acceptability of setpoints for nuclear safety related, Technical Specification (TS) compliance and Appendix R instrumentation channels.

The instruction addressed criteria for ensuring that analytical/safety limits were not exceeded in addition to those criteria that must be considered when evaluating setpoints for normal system operation.

It used the accepted analytic technique of the square root sum of the squares methodology for combining uncertainty terms that are random and independent.

The inspectors performed independent reviews of setpoint and scaling calculations and verified that the calculations were performed in compliance with the guidance of EEB-Tl-28. Environmental parameters used as design inputs were verified by review of the source documents.

Additionally, analytical limits used as design inputs to the calculations were also verified to be correct by review of the analytical calculations.

The following setpoint and scaling calculations were reviewed:

Instrument Loo Calculation No.

3-PS-73-22A, B 3-F IS-73-33 3-T-73-2A thru S, 3-D-73-1A, B 3-LS-73-57A, B 3-LS-73-56A, B ED-Q30739-0036 ED-Q0073-980094 ED-Q0999-980089 ED-Q3073-980017 ED-Q0073-930037 ED-Q0073-930038 3-PS-73-1Athru D ED-Q3073-980018 The setpoint and scaling calculations listed above were mini-calculations prepared against the calculations of record for the subject instrument loops. The calculations of record were referred to when necessary in order to obtain complete and accurate information. Based on this review the inspector concluded that no setpoint changes were required because of the power uprate.

Additionally, Nuclear Engineering setpoint and scaling documents were reviewed and verified to have been revised to incorporate changes delineated in the mini-calculations.

c.

Conclusion The licensee has evaluated the effect of power uprate on instrument loop accuracies.

Using revised analytical limits and changed environmental conditions instrument setpoint calculations were revised as required.

The instrument loops operating under the effects

'f power uprate conditions were demonstrated to be sufficiently accurate to perform their intended safety function.

E7 Quality Assurance in Engineering Activities a.

Ins ection Sco e

The inspectors reviewed the licencees High Pressure Coolant Injection (HPCI) system Self-Assessment, SA-SE-98-001 completed on November 12, 1998.

b.

Obsewations and Findin s The inspectors reviewed the licensees HPCI Safety System Engineering Inspection (SSEI) Self-Assessment Report SA-SE-98-001 and associated SSEI Self-Assessment Support Plan. The objective of the TVASelf-Assessment was to perform an in-depth review of the engineering documentation which supports operation of the HPCI system and its support systems.

The assessment plan included field inspection, review of design

calculations, drawings, design changes, UFSAR, Equipment Qualification (10CFR50.49)

and previous self-assessments.

The self-assessment plan was both thorough and complete.

~ - - The Self-Assessment identified that thirty five of seventy two calculations reviewed contain deficiencies in methodology, justification of assumptions and minor deficiencies such as not updating references.

The licensee determined that none of the issues will result in a change to the conclusion of the calculations.

The licensee previously identified a potential adverse trend in the development/revisions to the engineering calculations

-

during the power uprate program (documented by Browns Ferry Problem Evaluation Report (BFPER) 98-009483).

BFPER 98-009483 is a level B PER and will include a root cause analysis.

Although the corrective action plan was not issued at the time of this inspection, the licensee informed the inspectors that they planned to conduct a detailed root cause evaluation that willaddress identified deficiencies in all major engineering disciplines.

The report identified no major weaknesses in the engineering process or operability concerns for the HPCI system.

c.

Conclusion The self-assessment plan prepared to evaluate the HPCI system was both thorough and complete.

The self-assessment was well executed and included detailed documentation of completed actions.

The'self-assessment identified deficiencies concerning quality ofcalculations and analyses in all major engineering disciplines.

V. Mana ement Meetin s The team leader discussed the progress of the inspection with licensee's representatives on a daily basis and presented the results to m'embers of licensee management and staff at the conclusion of the inspection on December 4, 1998.

No dissenting comments were received from the licensee concerning the inspection findings.

One IFI was identified in connection with six examples where PERs were written to document inspection findings involving design basis calculation deficiencie Partial List of Persons Contacted Licensee

- T. Abney, Licensing and Industry'Affairs Manager R. Greenman, Site Support Manager H. Jones, Senior Engineering Specialist R. Jones, Interim Plant Manager G. Little, Operations Manager D. Motherly, Licensing Manager J. Norris, QA Supervisor, Engineering R. Ryan, Site Engineering Manager J. Shaw, Design Manager J. Schlessel, Maintenance and Modifications Manager K. Singer, Site Vice President J. White, Senior Outage Manager H. Williams, Senior Project Manager NRC F. Baxter, P. E., Consultant W. Bearden, Reactor Inspector t

C. Christensen, Branch Chief, Project Branch No. 6 K. Coyne, P.E., NRC Intern T. Morrissey, NRC Intern J. Panchison, P. E., Consultant C. Smith P. E., Senior Reactor Inspector Inspection Procedures IP 37550 IP 93809 Engineering Safety System Engineering Inspection (SSEI)

Items Opened

~Oened T~e IFI Item No..

50-260,296/98-11-02 Descri tion Reference HPCI System Design Basis Calculations - minor errors and non-conservative assumptions (Six Examples)

Problem Evaluation Report ( PER) No. 98-014338, Calculation MD-Q-0073-92-0184 does not address potential air entrainment. (Section E2.1.1 and E2.1.3)

PER No. 98-014420, Calculation MD-Q-0073-870190 does not bound Unit 3. (Section E2.1.1)

PER No. 98-014418, Calculation MD-Q-0073-870193 incorrectly refers to relief valve setpoint of-50 psi. (Section E2.1.3)

PER No. 98-014419, Calculation MD-Q-0073-880139 does not include documentation for all components within this safety related discharge piping boundary.

(Section E2.1.3)

PER No. 98-014388, SR 3.5.1.8, HPCI flowtest section 7.20 does not meet acceptance criteria.

(Section E2.1.6)

PER No. 98-014331, TS section 3.8.6 verification of battery cell temperature.

(Section E2.2.3)

Acron m List ADS

~

ASME BWR CFR CST DC DCN ECCS ESS FCV FSAR HPCI IEEE IPE IST LSSS LOCA MOV NPSH NRC PER RCIC SER SRV

~

SSI Automatic Depressurization System American Society of Mechanical Engineers Browns Ferry Nuclear Plant Boiling Water Reactor Code of Federal Regulations Condensate Storage Tank Direct Current Design Change Notice Emergency Core Cooling System Engineered Safeguard System Flow Control Valve Final Safety Analysis Report High Pressure Coolant Injection Institute of Electrical and Electronics Engineers Individual Plant Examination Inservice Test Limiting Safety System Setting Loss of Coolant Accident Motor Operator Valve Net Positive Suction Head Nuclear Regulatory Commission Problem Evaluation Report Reactor Core Isolation Cooling Safety Evaluation Report Safety Relief Valve Safe Shutdown Instruction Technical Specification

LIST OF DOCUMENTS REVIEWED OPERATIONS/MAINTENANCEENGINEERING INTERFACE REFERENCE PROCEDURES DRAWINGS AND DESIGN DOCUMENTS REVIEWED Design Criteria No. BFN-50-7073, High Pressure Coolant Injection System Units 2 8 3, Rev. 9 dated May 29, 1987 TVADrawing 3-47E812-1, R047, Flow Diagram High Pressure Coolant Injection System, dated 11/13/98 GENE-B13-01866-12-7, Power Uprate Evaluation Report, dated August 4, 1997 EOI Program Manual EOIPM Section O-X-B, Source References for the EOI Documents, Rev. 4, dated 10/1/98 Operating Instruction, 3-OI-73, HPCI System, Rev. 16; dated 10/4/98 2/3-SSI-1, Safe Shutdown Instructions, Rev. 3, dated 10/1/96 2/3-SSI-16, Safe Shutdown Instruction, Control Building Fire El. 593 Through El. 617, Rev. 4, dated 8/17/98 O-GOI-300-3, General Valve Operations, Rev. 58, dated 10/08/98 3-SR-3.3.5.1.3(D), HPCI Condensate Header Low Level Switch Calibration and Functional Test, Rev. 0, dated 7/27/98 3-SR-3.3.5.1.3(E),

HPCI Suppression Chamber High Level Calibration and Functional Test, Rev.

1, dated 8/11/98 3-SR-3.3.5.1.6(FT); HPCI System Logic Functional Test, Rev. 0, dated 7/27/98 3-SR-3.3.6.1.3(3),

HPCI Steam Line Space High Temperature Calibration, Rev. 0, dated 7/27/98 3-SR-3.3.6.1.5(3A/A), Core and Containment Cooling Systems HPCI Turbine Steam Line High Flow Instrument Channel A Calibration, Rev. 3, dated 9/24/98 3-SR-3.3.6.1.6(3),

HPCI Time Delay Relay Calibration, Rev. 1, dated 9/27/98 MD-Q0073-870423, Suppression Pool High Time Delay Relay 23A-K51 Process Limits, dated 5/26/98 MD-Q0073-870424, HPCI Time Delay Relay 23A-K43 limits, dated 7/5/94 ND-Q3999-970012, Reactor Building Environmental Analysis for HELBs - Power Uprate, dated 10/1 2/98 NESSD 3D-073-0001A-00-01, Nuclear Engineering Setpoint and Scaling Document, Loop 3D-73-1A, High Steam Flow dated 10/3/98 NESSD 3L-073-002A-00-02, Nuclear Engineering Setpoint and Scaling Document, Loop 3-T-73-2A, HPCI Steam Line Space High Temperature dated 9/20/98 NESSD 3L-073-0057A-00-01, Nuclear Engineering Setpoint and Scaling Document, Loop 3L-73-57A, HPCI Pump Suction Transfer dated 9/20/98 NESSD 3U-073-23A-K43-00-01, Nuclear Engineering Setpoint and Scaling Document, Loop 3U-73-23A-K43, HPCI Transition From Test Mode to Injection Mode dated 9/20/98 NESSD 3U-073-23A-K51-00-01, Nuclear Engineering Setpoint and Scaling Document, Loop.3U-73-23A-K51, Suppression Pool High Level Signal to Open Suppression Pool Suction Valves FCV-73-26 and 27, dated 9/20/98 NESSD 3L-073-0057A-00-01, Nuclear Engineering Setpoint and Scaling Document, Loop 3L-73-57A, HPCI Pump Suction Transfer NESSD 3L-073-0057A-00-01, Nuclear Engineering Setpoint and'Scaling Document, Loop 3L-73-57A, HPCI Pump Suction Transfer

NESSD 3L-073-0057A-00-01, Nuclear Engineering Setpoint and Scaling Document, Loop 3L-73-57A, HPCI Pump Suction Transfer ED-Q2073-890134, Setpoint and Scaling Calculation, Time Delay Relays 2-23A-K43 and 2-23A-K51

- ED-Q0073-980039, Setpoint and Scaling Calculation, Time Delay Relays 2-23A-K43 and 2-23A-.

K51(mini calc) dated 11/13/98 MECHANICALDESIGN REVIEW REFRENCES DESIGN AND LICENSING DOCUMENTS UFSAR Technical Specification Design Criteria No. BFN-50-7073, High Pressure Coolant Injection System Units 2 8 3, dated May 29, 1987 PROCEDURES Surveillance Procedure 3-SR-3.5.1.7, HPCI Main and Booster Pump Set Developed Head and Flow Rate Test at Rated Reactor Pressure, revision 4, dated 10/9/98 Surveillance Procedure 3-SR-3.5.1.8, HPCI Main and Booster Pump Set Developed Head and Flow Rate Test at 150 PSIG Reactor Pressure, Revision 2, dated 10/9/98 Surveillance Procedure 3-SR-3.5.1.1, Maintenance of Filled HPCI and RCIC Discharge Piping, Revision 1, August 24, 1998 DRAWINGS 3-47E812-1, R047, Flow Diagram High Pressure Coolant Injection System, dated 11/13/98 3-47W455-8, R005, Mechanical High Pressure Coolant Injection System, Plan 3-47W455-9, R006, Mechanical High Pressure Coolant Injection System, Sections 3-47E611-73-1, R001, Mechanical Logic Diagram, High Pressure Coolant Injection System 3-47E611-73-2, R001, Mechanical Logic Diagram, High Pressure Coolant Injection System.

3-47E611-73-3, R001, Mechanical Logic Diagram, High Pressure Coolant Injection System 3<7E611-73-4, R001, Mechanical Logic Diagram, High Pressure Coolant Injection System 0-105E2694, Revision 1, GE Process Diagram, High Pressure Coolant Injection System f

MECHANICALCALCULATIONS ND-Q0999-880127, ECCS Ring Header Strainer Pressure Drop Calculation, Revision 1, dated September 4, 1992 MD-Q3999-970055, ECCS Ring Header Strainer Replacement-Unit 3, Revision 0, dated August 20, 1997 MD-Q0999-970048, ECCS Ring Header Strainer Replacement - Unit 2, Revision 0, dated July 30, 1997 MD-Q0073-920184, Analytical Limits For HPCI Pump Suction-Automatic Transfer to Suppression Pool For LS-73-56A, 56B, -57A, 8 -57B, Revision 3, dated November 12, 1998 MD-Q0073-870190, HPCI Piping Pressure Drop and NPSH, Revision 7, dated November 4, 1998

ND-Q0073-900022, High Pressure Coolant Injection Transient Analysis, Revision 3, June 7, 1993

~

MD-Q0073-920531, Analytical Limits For HPCI Booster Pump High Suction Line Vacuum, Revision 3, November 12, 1998 MD-Q2074-870360, Pump NPSH - RHR System, dated July 9, 1989 MD-Q0073-880139, High Pressure Coolant Injection - Design Pressures and Temperatures, Revision 6, dated November 2, 1998 MD-Q0073-870193, HPCI System Vacuum and Pressure Relief Valve Sizing, Revision 6, dated November 5, 1998 OTHER DOCUMENTS Browns Ferry Unit 2 Individual Plant Examination (IPE), Revision 0 GENE-B13-01866-12-7, Power Uprate Evaluation Report, dated August 4, 1997 GENE-E12-00148-01, ECCS Suction Strainer Hydraulic Sizing Report, Revision 0, dated July 1997 GENE-E12-00148-04, Net Positive Suction Head. Evaluation, Revision 0, dated June 1997 GENE-B13-01869-100, ECCS Vortex Analysis, Revision 0, dated August 6,1997 GE SIL 323, Suppression Pool Suction Strainer Mesh Size Mismatch With ECCS Pump Seal Orifices, March 1980.

TVAInternal Memo 960722R0265, Suppression Pool Suction Strainer Mesh Size Mismatch With ECCS Pump Seal Orifices, October 28, 1988 ELECTRICAL DESIGN REVIEW REFERENCES BFN-50-7200C, 250 Vdc Power Distribution System - Units 2 8 3, Rev. 4 BFN-50-7073, High Pressure Coolant Injection System, Units 2 and 3, Rev. 9 BFN-50-729, Single Failure Criteria for Fluid and Electrical Safety Related Systems, Rev.1 PER 98-013705, Lack of supporting data in Gale. ED-Q3999-920106 PER 98-014331, Acceptance Criteria for Min. Battery Room Temp.

PER 98-014034, FSAR Rewrite PER 98-014335, Erroneous Reference in Calculation ED-Q0248-870041 PER 98-014336, Fuse Discrepancy PER 98-012555, Use of non-QA Software (Self-Assessment)

PER 98-014487, Water Pipe in Electrical Rooms Open Item OI-ITS-001-009, 9/28/98 Open Item OI-MOV-003-012, 9/28/98 ED-Q2000-870064, Control Circuit Voltage Drop Calculation - DC Circ. for U3, Rev

.5 ED-Q0248-870041, 250 Vdc Unit Battery Load Study, Rev. 20 ED-Q0248-920091, 250 Vdc Voltage Drop Calculations-Battery Boards, Rev. 27 ED-Q3999-920058, 250 V Bus 8 Cable Protection and Breaker/Fuse Coordination, Rev. 8 ED-Q3999-920106, CCVD for Unit 3 Circuits, Rev. 10 ED-Q0256-880707, Loading Calculations for the ECCS ATU Inverters and Logic Power Supplies for Panels 9-81 through 9-88, Rev 10 ND-Q0999-910030, Summary of Mild Environmental Conditions for Browns Ferry Nuclear Plant, Rev.7 MD-Q0031-930059, Control Bay Transient Analysis, Rev.

ED-Q0248-920089, 250 V DC Unit Battery Load Study

ED-Q0256-880707, Loading Calculations for the ECCS ATU Inverters'and Logic Power Supplies for Panels 9-81 through 9-88, Rev. 7 ED-Q3999-920106, CCVD for Unit 3 DC Circuits, Rev. 10 DCN S40793A, Uprate Environmental Drawings

~ DCN S40979A, Non-physical Work Document Changes Required by Power Uprate on Unit 3 DCN S40688A, 89-10 MOV Mods for 105% Power Uprate DCN S40689A, 89-10 MOVGale Revisions for 105% Power Uprate OQ5E710-1, Wiring Diagram Inst. & Controls DC &AC Power System Key Diagram, Rev. 11 0-45E710-2, Wiring Diagram Inst. & Controls DC &AC Power System Key Diagram, Rev. 12 3-45E712-1, Wiring Diagram 250 V Reactor MOV Board 3A Single Line, Rev. 23 3-47E610-73-1, Mechanical Control Diagram HPCI System, Rev. 21 M-4-47A368-73-1, Mechanical Valve Motor Operator Tabulation, Rev. 3 3<5E714-3, Wiring Diagram 250 V Reactor MOV Bd 3A Schematic Diagram, Rev. 8 3-45E714-4, Wiring Diagram 250 V Reactor MOV Bd 3B Schematic Diagram, Rev. 27 3-45E714-3, Wiring Diagram 250 V Reactor MOV Bd 3A Schematic Diagram, Rev. 8 3-45E779-13, Wiring Diagram 480 V Shutdown AuxiliaryPower Schematic Diagram, Rev. 13 3<5E779-43, Wiring Diagram 480 V Shutdown AuxiliaryPower Schematic Diagram, Rev. 6 3-45E749-5, Wiring Diagram 480 V Shutdown Bd 3A Single Line, Rev. 40 3-45E749-6, Wiring Diagram 480 V Shutdown Bd 3B Single Line, Rev. 39 3-45E724-6, Wiring Diagram 4160 V Shutdown Bd 3EA Single Line, Rev.24 3-45E724-7, Wiring Diagram 4160 V Shutdown Bd 3EB Single Line, Rev. 17 3-45E724-8, Wiring Diagram 4160 V Shutdown Bd 3EC Single Line, Rev. 26 3-45E724-9, Wiring Diagram 4160 V Shutdown Bd 3ED Single Line, Rev. 20 3-45E712-1, Wiring Diagram 250 V Reactor Bd 3A Single Line, Rev. 23 3-45E712-2, Wiring Diagram 250 V Reactor Bd 3B Single Line, Rev. 35 3<5E736-6, Wiring Diagram 480 V HVAC Bd B Single Line, Rev. 8 0-45E736-1, Wiring Diagram 480 V Control Bay Vent Bd A Single Line. Rev. 25 0-45E736-2, Wiring Diagram 480 V Control Bay Vent Bd B Single Line, Rev. 22 245E749-3, Wiring Diagram 480 V Shutdown Bd 2A Single Line, Rev. 360-45B721-2-2, Electrical Equipment Fuse Tabulations Index, Rev. 26 0-45B721-3, Electrical Equipment Fuse Tabulations, Rev. 7 3-45B721-12-1, Electrical Equipment Fuse Tabulations, Rev.

3-45B721-13-1, Electrical Equipment Fuse Tabulations, Rev. 3 3<5B721-13-3, Electrical Equipment Fuse Tabulations, Rev.

3-45B721-26-4, Electrical Equipment Fuse Tabulations, Rev. 3 3-45B721-85-2, Electrical Equipment Fuse Tabulations, Rev.

3-47E225-103, Harsh Environmental Data El 519.0, Rev. 5 & 6 3-47E225-104, Harsh Environmental Data HELB Profiles - Room No. 1 El 519.0, Rev. 3 & 4 3%7B370-2, Mechanical Motor Operated Valves - Testing Requirements, Rev. 17 37722C, Woodward Governor EGM Control Product Specification O-OI-31, Control Bay and Off-Gas Treatment Building AirConditioning System, Rev. 64 SR-3.8.4.1, Weekly Check for 250 Volt Main Bank Number 1 (2,3), Rev.

NEDP-2, Design Calculation Process Control and Standard Programs, Rev. 0 SPP-2.6, Processes, Rev. 0 98-001, Electrical Instruction for Electrical Calculations, Rev: 0

INSTRUMENTATIONAND CONTROL DESIGN REVIEW REFERENCES Desi n and Licensin Documents FSAR Section 7.4, Emergency Core Cooling Control and Instrumentation BFN-Unit 3 Technical Specification, Section 3.3, Instrumentation, Amendment No. 213 Design Criteria No. BFN-50-7073, High Pressure Coolant Injection System Units 2 and 3, Revision 9 Procedures TVAStandard Programs and Processes SPP-6.7, Instrument Setpoint, Scaling, and Calibration Program, Revision 0 TVAStandard Department Procedure NEDP-10, Design Output, Revision 0 Branch Technical Instruction EEB-TI-28, Setpoint Calculations, Revision 2

~Drawin s 3-47E812-1, Flow Diagram High Pressure Coolant Injection System, Revision 47 3<7E225-102, Harsh Environmental Data Elevation View, Revision 3 3-47E225-103, Harsh Environmental Data, Elevation 519.0, Revision 6 3-47E610-73-1, Mechanical Control diagram HPCI System, Revision 21 G. E. Drawing No. 0-105E2694, Process Diagram High Pressure Coolant Injection System for 3458 MWT, Revision 0 Calculations ND-Q0999-980002, Evaluation of Radiological Calculations for Power Uprate and 24 Month Cycle Impact, Revision 4 ND-Q3999-910036, Summary of Harsh Environmental Conditions for BFNP Unit 3, Revision 11 ND-Q3999-970012, Reactor Building Environmental Analysis for HELBs-Power Uprate, Revision

ED-Q3073-980036, 3-P-73-22A and -22B, Setpoint and Scaling Calculation, Revision

ED-Q0073-980094, 2, 3-FIS-73-33 Setpoint and Scaling ICalculation, Revision 0 ED-Q0999-980089, HPCI / RCIC Isolation Switches Setpoint and Scaling Calculation, Revision 0 ED-Q3073-980017, 3-D-73-1A and 3-D-73-1B, Setpoint and scaling calculation, Revision 0 ED-Q0073-930037, 2, 3-LS-73-57A; 2, 3-LS-73-57B, Setpoint and Scaling calculation, Revision 0 ED-Q00783-930038, Setpoint and Scaling Calculation for 2, 3-LS-73-56A and 2, 3-LS-56B, Revision 1 ED-Q3073-980018, 3-PS-73-1A, 1B, 1C, and 1D, Setpoint and Scaling Calculation, Revision 0 ED-Q0000-920102, Generic Accuracy Calculation for Rosemount 1151, 1153, and 1154 Transmitters, Revision 0 MD-Q0999-920193, Analytical Limits for HPCI and RCIC System Isolation Temperature Switches, Revision 0

'39 MD-Q0073-980136, Analytical Limits for HPCI Steam Line Flow at 3458 MWTUsing SIL 475, Revision 0 MD-Q0073-920184, Analytical Limits for HPCI Pump Suction Automatic Transfer to Suppression Pool for LS-73-56A, 56B, 57A and 57B, Revision 3 MD-Q3073-920512, Analytical Limits for the HPCI Steam Supply Line Low Steam Pressure.

Switch, Revision 2 Other Documents DCN No. T40666A, Instrument Modification for 105% Power Uprate dated May 26, 1998 DCN No. T40785A, Instrument Modification for 105% Power Uprate dated July 29, 1998 GE-NE-B13-01866-12-7, Power Uprate Evaluation Report for TV8A Browns Ferry Units 2 and 3 High Pressure Coolant Injection System, dated July 199 J