ML20086A403

Annual Rept Per 10CFR50.59 for 1990. Rept Contains Tests or Experiments Conducted in 1990 But Not Described in FSAR

ML20086A403
Person / Time
Site:	Brunswick
Issue date:	12/31/1990
From:	Spencer J CAROLINA POWER & LIGHT CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
NUDOCS 9111190099
Download: ML20086A403 (95)

Text

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Cp&L Caro *2na Power & Light Company

.:k Brunswick Nuclest Project P. O.-Box-10429 Southport N.C.

28461 0429 gy 12 W31

' VILE:

-. B09 -13510C 10CFR50.59 4

. U.S; Nucleer Regulatory Commission

\\JL ATTN:. Doc 2 ment Control Desk Washington, L.-C. 20555 BRUNSWICK STEAM ELECTRIC PLANT UNITS 1 & 2 DOCKET NuS. 50-325/50 324 LICENSE NOS. DRP 71/DPR-62

ANNUAL REPORT IN ACCORDANCE WITH }0CFR50. 59 Centlemea:

In accordance with 10 CFR 50.59, the following annual report is submitted for

~1990.

This_ report ;ontains brief-functional summaries of procedures and plant modifications which are changes to the facility as (.escribed in the FSAR, The

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report also.contLip3 thosc tests or experiments conducted' in-1990 which are not described ~-in ths;19Ah, Very truly your

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. Spencer, neral Manager swick Nuclear Project s

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Enclosure cc:

Mr. S. D. Ebneter Mr.?N. B, Le -

."SEP NRC Resident Office w

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9111190099 901231

PDR ADOCK 05000324 R

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Table of Contents item Eac12Lu 1990 Chantes to the Facility as Described in the FSAR EER 89-0268, Evaluation of Dryvell Ambient Temperature Excursion 1

During Recent Unit 1 Power Operation EER 90-0070, 2-G31--F035 Temporary Replacement 2

EF 90-0118, 2-VA-FV-916B D<;s Not Meet Fall Safe Criteria 3-4 EER 90-0170, CAD Subsystem Design Evaluation 5-9 EER 90-0174, Justification for Continued Operation for 2-CAC-749 10-11 with DC Grounds EER 90-0181. Reactor Bulloing Steam Heaters and Evaporative 12 14 Coolers Out of Service EER 90 0246, 2-COR-V7 Temporary Repair 15 EER 90-0253, Use of Fire Protection Water for Battery Discharge 16-17 Tests EER 90-0259, Unit 2 Rod Sequence Control System Disabling 18 PM 81-227B, Rev. 9, Installation of Fish Diversion Structure 19-20 PM B2-198, Storm Drain Monitoring - Pump Basin 21-72 PM 82-220B, Unit 2 Replacement of Service Water Vital Header 23 Loop "B" PM 83-150, AOG System Punchlist Modification, Field Rev. 5 2o PM 84-062, Field Rev, 36, Alternate Safe Shutdown Feed for Valve 25 2 Ell-F009 PM 86-095, 2-B21 PI R612 and 2-B21-PDT-NO35 Core D/P Loop 26 Removal; Remove Above Instruments and Associated Wiring Spared PM 86-096, Relocation of Service Water Chlorine Solution Piping 27 and Diffusers i"86-101, Unit 1, Automatic Dispatch System (ADS) Removal PMs 28-31 87-039 and 87-040, Unit 1 and Unit 2, Removal of Control Switches, Indicators, Controllers and Pushbuttons PM 87-007, Unit ' Replacement of Feedwater Recorder and 32 Relocation of Reactor Level Indicator PM 87-029 and 87-030, Unit 1 and Unit 2 Containment Atmospheric 33 Control (CAC) System Recorder Replacement PMs87-037 and 87-038, Unit 1 and Unit 2 Residual Heat Removal 34 ^5 (RHR) System Control Room Upgrade PM 87-169, Unit 1 Pna'4atic Nitrogen System (PNS) 36-37 PMs87-240 and 89-026, Unit 1 and Unit 2 service Water Piping 38 Inspection and Repair PMs87-241 and 87-099, Unit 1 and Unit 2, Camma TI P Re t.ro f i t 39 PMs88-051 and 88-052, Unit 1 and Unit 2 High Pressure Coolant 40-41 Injection Reliability Improvements

Table of Contents Item Pace (s)

PM 89 011, Unit 2 DC Motor Operated Valve Motor Replacement

/d 46 PM 89 107. Replace Elec. Components in Ur.st 1 DC MCCs and Motors PM 89 024, 2 E51-F007 Alternato DC Power Supply 47-49 PMs89-035 and 89-036, Unit 1 and Unit 2 ARTS RBM 50-54 Instrumentation Modification PMs 89 038 and 89-095, Unit 1 and Unit 2 Replacement of Reactor 55-56 Coolant Recirculation System Inlet Safe-Ends and Riser Piping PM 89-059, Unit 2 Weld Overlay 57 PM 89-094, Unit 1 Weld Overlay and RIIR Valve Machining PM 89 071, RCIC 1 E51-F007, F008, and F013 Valve Replacement 58-60 PM'89-092, Replacement of Core Spray System Safe Ends - Unit 1 61-62 PM 89-103, Unit 1 SBCT/ Secondary Containment Auto Initiation 63-64 Logic Change PMs90-014 and 90-015, Unit 1 and Unit 2 Reactor Water Cleanup 65-67 (RWCU) High Energy Line Break (HELB) Isolation PM 90-047, Unit 1 Residual Heat Removal (RHR) Head Spray Removal 68-69 DR 89-037, 90 005, Replacement of Flow Orifices 2-SW-FO-1190, 70 1191, 1192 and 1193 EDP 89-017, Decommissioning of Unit 2 Brunswick Cumberland 71 Transfer Trip 1990 Changes to the Procedures as Described in the FSAR EER 89-180, Justification To Remove 15% Reduction of Safe 72 Working Load For Rigging EER 90-187, kHR Minimum Flow Design Data Evaluation 73-74 ENP-19, Special Nuclear Material Inventory 75-76 SP-88-035, Fuel Assembly Inspection and Repair BSEP Commitment to Visual Weld Acceptance Criteria for 77 Structural Welding at Nuclear Power Plants (VWAC), Rev. 2 Control of 4KV Emergency Bus Cross Tie Breakers 78 Current Operational Practices fcr Ensuring Reactor Protection 79 System (RPS) Operability Status FSAR Update Deleting Pipe Classification Tables and Describing 80 NDE Requirements Probable Maximum Precipitation Design Loading for Class 1 81 Structures Radiation Work Permit Time and Exposure Data Recording 32 Revision to Circulating Water Chlorination Frequency 83 l

i

Tal'le of Contents Lt.9]n Paoe(si Site Organization Changes 84 Test or Experirrent Not-Described in the FSAR 1-SP-90-026, Stroke Testing of Core Spray Injection Valves E21-85 F004 A/B and E21-F005 A/B Under dP and Flow to Meet Requirements of Generic Letter 89-10 1-SP-90-029, Stroke Testing of Residual Heat Removal (RHR) 86-88 System Valves 011-F007 A/B, E11 F011 A/B, E11-F027 A/B, Ell-F028 A/B, Ell-F047 A/B and Ell-F048 A/B Under Differential Pressure and Flow Conditions to Meet the Requirements Described in NRC Ceneric Letter 89 10-2-SP-90-004, Service Water System Hydraulic Performance Test 89-91 l

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Change to the Facility as Described in the FSAR TITLE:

EER 89-0268, Evaluation of Drywell Ambient Temperature Excursion During Recent Unit 1 Power Operation UE&C Report No. 7992.403-S S 051 FUNCTIONAL

SUMMARY

Temperature excursion experienced within the Unit 1 primary containment (drywell) as a result of the failure of the lu and 1A2 drywell cooler fan motors prompted operability assessment of aMected equipment and structures.

Based on the conclusion of these assessments the impact to structural integrity and the qualified life of EQ components was determined to be the limiting factors.

EER 89-0268 and UE6C report No. 7992.403 S-S 501 determined that the impact to the qualified life of EQ components and to drywell structural integrity did not exceed any known operability threshold.

Based on the results of these assessments, an increase of allowable peak temperatures from 150 degrees F (as originally defined by the FSAR) to 200 degrees F during normal operation (100% power) has been determined acceptable.

SAFETY

SUMMARY

The safety analysis developed in support of the conclusions developed by EER 89-0268 was used to support the increase in the acceptable maximum localired dryvell temperature of 200 degaes F.

Based upon these conclusions, the subject equipment is expected to perform its required design safety function during normal and post accident operating evolutiens, given the anticipated return to normally observed drywell temperatures. Since the equipment's operability has nel been challenged by the expected normal and postulated post-accident environmental conditions evaluated within EER 89-0268 (and confirmed, where

required, by corrective actions / inspections performed during the unscheduled 9/22/89 outage), the following observations have been made:

The probability of occurrence of any accident (and its consequences) previously evaluated in FSAR Chapter 15 will ngt be increased, given that the qualified lives of subject equipment will be maintained (consistent with that documented in this EER).

The probability of occurrence of malfunction of equipment important to safety (and its consequences) previously evaluated in FSAR Chapter 15 will nqt be increased, given that the qualified lives of subject equipment will be maintained (consistent with that documentec in this EER).

The probability of an eccident or possibility for rn1 function of equipment important to safety of a different type than already evaluated in FSAR.

have n91 been created.

The margin of safety as defined in the bases to any Technical Specifications has not been reduced, given that the contribution of elevated normal / post-LOCA ambient temperatures (with respect to bulk average primary contairaent temperatures) has been previously evaluated in EER No. 85-0231 (and current practices utilized in performance of daily Suppression Pool Tamperature Monitoring System monitoring).

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Change to the Facility as Described in the FSAR TITLE:

EER 90-0070, 2 031-F035 Temporary Replacement FUNCTIONAL

SUMMARY

Valve 2-C31-F035 is the RWCU ~ reject to radwaste -isolation valve located.in the Reactor Building on 50' elevation in-the RWCU Room.

This valve-was found to be leaking past the seat while the system was running and pressurized.

Problem vas found during a leak hunt which involved mechanical maintenance snugging this valve down followed by shutting the upstream isolation valve (2-G31-F032). Af ter the isolation valve was shut, the quantified inleakage to Radwaste dropped to near zero GPM.

During inspection, the valve internals were found to be damaged beyond immediate repair. An investiration into available spare parts reverled no available like-in-kind replacemento.

A 4" carbon steel 600 lb. manual gate valve, Stockham figure 600W U, was selected as a temporary replacement for 2-G31-F035. This valve is stocked under CP&L part number 732-553-74.

In evaluating this valve as an acceptabic temporary replacemenc the following were considered: design specifications, existing and replacement valve specifications, physical characteristics of both valves, impact on operation of the valve, and electrical considerations.

The replacement valve meets or exceeds the design requirements of the existing specification.

The end prep and height are similar to the extent that no significant differences exist.

The weight of the new valve is unknown, but it is assumed the weight of the new valve is lers than the combined weight of the existing valve and motor operator, therefore no concerns are created by the end prep, height, or weight of the new valve.

The existing valve is equipped with a motor operator to allow for remote valve operation. This valve is not used for normal operation. The preferred system lineup ensures reject to the condenser. However, during the unusual circumstance when it is desirable to direct RWCU water (Reactor vessel water) to a location other than the vessel or rundenser, rej ect to Radwasce could be adequately accomplished with the manual operation of 2-G31-F035.

The removal of the remote operating capabilities requires Operations personnel to locally operate the valve.

Although this is not a preferred method of operation due to A1 ARA concerns it does retain the ability to reject Reactor vessel water directly to Radwaste.

For the above reasons, the temporary replacement of the existing remote operated valve with a locally operated valve is acceptable.

SAFETY

SUMMARY

This replacement is the temporary replacement of a motor operated valve with a manual operated valve. This replacement temporarily does not allow Operations the ability to remotely operate the RWCU reject to radwaste isolation valve (2-G31-F035).

However, local operation capabilities are maintained by the temporary installation of the new valve. In addition to local operation, valve 2 G31-F034 is in parallel to 2-031-F035 and is the RWCU reject

-to-the Condenser valve, and therefore serves as an alternate reject flowpath.

- Because an alternate flow path for RWCU re is maintained and-Operations personnel can locally operate the 2-G31 F035, jectthe probability or consequences of occurrence of any accident previously evaluated in the FSAR will not - be increased. Nor will the probability or consequences of occurrence of malfunctian of equipment important to safety evaluated in the FSAR be -increased.

The probability or possibility of an accident not previously evaluated in the FSAR important to safety will not be created. The basis of any margin of safety as defined in the basis to any' tech spec will not be reduced.

2 u

Change to the Facility as Described in the FSAR TITLE:

EER 90 0118, 2 VA-FV-916B (2L-D-CB Actuator) Does not Meet Fail Safe Criteria StNCTIONAL

SUMMARY

1 Design basis review identified that the 2-VA-FV-916B solenoid valve does not fail to the open position to allow the control air to close the 2-VA 2L-D-CB.

This eva)uadon provides justification for securing damper 2-VA-2L-D-CB (normal fresh air makeup to Control Room) in the closed position due to the determination that it does not fail to the closed position on loss of power.

ihis is not consiste nt with previous statements to the NRC which stated that the damper is fait safe and was used as the basis for justifying the adequacy of the control logic (NUS-3697, rev. 2).

Inoperability of the 2-VA-2L-D-CB placed the plant in a dual unit 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> LCO due to inability to isolate the control room as required by Technical Specification 4.7.2.d.4.

The recommended interim action secured tLe damper in t.he closed position until appropriate control changas could be made. This is consistent with the actions given in Technical Specification 3.3.5.5 action statement b. for a high c' >, ine alarm.

Closure of the normal makeup air supply to the control room leaves only the emergency trains as a flow path for outside air intake which supplies fJ1tered air on smoke and high rad annunciation and isolates on chlorine annunciation.

Closure of the damper would prerent makeup to the control room and only recirculation would be occurring.

Thus, the possibility exists for loss of adequate oxygen and maintenance of positive pressure.

E&RC established controls to ensure the atmosphere inside the cor. trol room was monitored thus ensuring appropriate breathing atmosphere to the operators.

Humidity has been considered and determined not to be a concern because there are no significant sources of moisture within the control room.

Temperature was considered and determined not to be a concern because, as stated in Q-list evaluation 87-34, the control room temperature would stabilize at 97 degrees Fahrenheit (F) with a loss of the cooling coils, which is still suitable for the equipment.

This evaluation assumed the normal air supply to be an additional heat load, which would be eliminated thereby reducing the stabilization temperature which is already acceptable.

Should oxygen levels drop below acceptable levels of 19.5%,

the emergency filtration system shall be started per OP-37 until adequate levels are again established.

Positive pressure is only required during operation of the emergency filtration as shown in Technical Specification 4. 7. 2.d.4.

Thus, positive pressure will be established upon receipt of a high radiation or smoke annunciation.

Additional corrective actions recently implemented included plant modification resolving the fail close position concern.

Therefore the temporary condition addressed by this evaluation has been restored to a design basis configuration as described in the FSAR.

SAFETY

SUMMARY

Disconnecting the actuator linkage and securing the damper c h ed isolates the normal makeup to the control room, thus, protecting the intake path during a high radiation, smoke, or chlorine incident, which envelopes the applicable accident scenarios affecting control room habitability.

E&RC established controls to ensure the atmosphere inside the control room is monitored thus ensuring appropriate breathing atmosphere to the operators.

Control room positive pressure would be established by the emergency filtration 3

Change to the Facility as Described in the FSAR l

system during a high radiation or smoke incident, Securing the dartper ensures isolation of the affected duct is accomplished. Therefore, the probability of occurrence or the conwquence of any accident previously evaluated or otherwise in the FSAR will not be increased.

The equipment affected by the isolation would be that located inside the control room proper.

11umidity has been considered and determined not to be a concern because there are no significant sources of moisture within the control room.

Temperature was considered and determined not to be a concern because, as stated in Q-list evaluation 87 34, the control room temperature would stabilize at 97' F with a loss of the cooling coils, which is still suitable to be an additional heat load, which would be eliminated, thereby reducing the stabilization temperature which is already acceptable.

Therefore the probability of occurrence or consequences and malfunction of equipment irepor tant to safety previously evaluated or otherwise will not be increased.

Control room positive pressure would be estaalished by the emergency filtration system during a high radiation or smoke incident.

Securing the damper ensures isolation of the af fected duct is accomplished. The margin of safety as defined in the basis to any technical specification is not reduced by this change.

k 4

Change to the Facility as Described in the FSAR U11JJ EER 90-0170, CAD Subsystem Design Evaluation FUNCTIONAL

SUMMARY

This evaluation suppcrts the temporary acceptability of the Containment Atmospheric Dilution (CAD) Subsystem which currently does not meet FSAR reqairements for redundancy of power sources for the nitrogen vaporizer trains.

The power supplies for the CAD Subsystem are designed such that if (1) Unit Substation E5 is lost, a nitrogen injection path through Loop A exists without any power transfers or manual valve operations, (2) if Unit substation E7 is lost, a nitrogen injection path through Loop B exists without any power transfers or manual valve operations (in addition, injection through Loop A can also be accomplished if distribution panel 32AB is transferred from its normal source to its alternate source, to allow elec.trical operation of valves NP-CV 2713 and NP FCV-2717) and (3) if Unit Substation E6 is lost, *he cbility to electricall conttol the Loop A vaporizer and Loop B valves NP-CV-2714 and NP-FCV-2720 wil be lost. This will render the CAD Subsystem inoperable electrically. However, manual operation of Loop B vaporizer inlet and outlet valves permits operation of Loop B on a loss of power from Unit Substation E6.

All other valves in the CAD Subsystem flow path f or Units 1 and 2 are redundant and diversified valves.

FSAR Paragraph 6.2. 51.e states:

"The CAD System was designed to engineered safety features (ESP) standards.

Therefore, all equipment required for CAD service was designed with suitable redundancy and interconnections such that no single failure of an active a rrp o c.c..t will render the system inoperable."

General Design Criteria (CDC) 41. Containment Atmosphere Cleanup, requires that each system have suitable redundancy in components and features to ensure that its safety function can be accomplished assuming a single active failure.

The CAD Subsystem is designed to comply with the single active failure criteria on a conmonent leve). (i.e,, valve, vaporizer, etc. ). With respect to redundancy of power supplies, the CAD Subsystem is not completely protected against a single active failure.

The CAD Subsystem is designed to be manually initiated using remote manual valves and controls.

There are no automatic initiation features associated wl;h the system. In the event of a loss of power f rom Unit Substation E6, CAD Subsystem Loop B can be placed in service by manually operating valves NP-CV-2714 and NP-FCV-2720 (the Loop B vaporizer would be available since it is power from Unit Substation E5 which are both provided with adequate hardware (ie., handwheel and air actuator piston pressure equalizing valves) to facilitate manual operation.

These valves are located in.eide the AOG Building on the upper elevation.

The post-LOCA environment in this area of the building is suitable for human occupancy.

The radiation dose that an operator would receive while in transit between the Control Room and the A0G Building is also acceptable. Based on UFSAR paragraph 15.6.4.5.5.2 assumptions, the operator would receive on the order of 0.4 Rem whole body. This exposure is well below that allowed a radiation worker by 10 CFR20.

The configuration of the CAD Subsystem has been evaluated and determined

• o provide sufficient redundancy to ensure manual operation capability in the eveut of any single active power f a ilure.

Prior to canceling the LCO which was initiated af ter recognizing the CAD subsystem design discrcpancy, manual control will be procedura11 zed, and manual system operation demonstrated. The procedure will then be incorporated into the BNP Plant Operating Manual.

Satisfactory implementation of this procedure will demonstrate that, while the CAD Subsystem power supplies are not in compliance with the single active failure critt-ria of the FSAR and GDC 41, reasonable operator action will ensure that the intended protection is provided.

The cabling and raceways in the CAD Subsystem were designed with suitable 5

Change to the Pacilitj es Described in the FSAR and interconnections such that no = single fallute - of an active redundancy 'ill render the system inoperable. However, the existence of opposite component w division equipment in the redundant trains creates the potential for violations of physical separation criteria. A design review of the_ system will be performed to verify the wiring is installed in accordance with design requirements. This will be completed in parallel with procedure development.

HISTORICAL DESIGN BASIS REVIEW

~

A review of system design basis information was conducted to determine the original-basis, and is presented below.

Although the system is not protected against single active failure with respect to power supplies, a review of the applicable documents tends to support the view that the system is installed as originally intended. Per -SDBD-24, System Design Basis Document for Containment Atmosphere Control System, Paragraph 1.2.2, Redundancy Criteria, the CAD Subsystem was uesigned with redundant valves and vaporizers to ensure operation at the subsystem level in the event of a single failure of any active component.

SDBD-24 Paragraph 1.2.2 further states that electrical power for critical components is taken from one of the two emergency buses or from t'. i DC Power System. In contrast, the Oxygen Hydrogen Analyzer Subsystem is defined per SDBD-24 Paragraph 1.2.2, as consisting of two 100% redundant loops, such that no single failure of piping, valves, electrical power supply or controls could cause a loss of monitoring capability. The design basis of the two systems clearly-differs with respect to power supply redundancy.

The design basis for the Oxygen-Hydrogen Analyzer Subsystem requires redundant power supplies. The design 4;

basis for the CAD-Subsystem requires a reliable source of power (ie., DC or emergency AC) to critical components, combined with redundancy on the component level only (ie., redundant valves and vaporizers). Further indication that the CAD Subsystem was not intended'to be designed against failure of the emergency AC power source is provided in SDBD-24 paragraphs 1.7.5, Power Supplies, and l'7.6, Separation.

The power supply criterion states that power be provided from the nearest available source.

With respect to separation criteria, paragraph 1.7.6 states that all CAD Subsystem electrical equipment has been designed with suitable redundancy so that 1o single failure of the vaporizer heaters nor solenoid valves render the ajstem inoparable.

Neither criteria requires redundant emergency power supplies.

In a memo from H.G. Kreider, UE&C Project Manager, to W.

B. Kincaid, CP&L BNp Manager, dated October 15, 1971, UE&C Design Specification 9527-01-260-1, Hydrogen Control Systems, was discussed. UE&C indicated that the original draf t

- of the specification did not address redundancy of active components in the CAD In order to satisfy the Desi n Guide 7 redundancy requirements, UE&C Subsystem.

5 indicated that if required to meet licensing concerns, credit could potentially be taken for containment venting through the Standby Gas Treatment System as a system back-up, in the event of CAD Subsystem failure. In this light, redundancy of the Hydrogen Control System could have been achievedm UE&C agreed however to revise Specification 9527-01-260-1 to require redundancy of active components and critical control functions of. the CAD Subsystem as an added measure of protection.

With respect to the Standby Gas Treatment System (SGTS), the PSAR GDC 41 compliance paragraph states that the SGTS is a dual-train system powered from emergency busses to assure uninterrupted power.

This compliance statement

-indicates redundant power supplies. In contrast,- the CDC 41 compliance paragraph for the CAD Subsyrtem states only that nitrogen will be added to the containment stmosphere for dilution as required to maintain a nonflammable atmosphere. This compliance statement does not indicate redundanev of power supplies.

Based on these contrasting GDC 41 compliance statements, it appears that the CAD Subsystem was not intended to be designed a6ainst failure of an emergency bus.

Based on the precedin6 considerations, it is our opinion that the original design system with redundant intent of the CAD Subsystem-Dilution was to provide a 6

Change to the Facility as Described in the FSAR inechanical flow paths and reliable, but not necessarily redundant power supplies.

The CAD Subsystem was designed based on the very conservative radiolytical oxygen generation rates assumed in the Safety Guide 7.

The following discussion demonstrates that the safety significance of the CAD Subsyatem has been diminished based on more realistic oxygen generation rates. On December 2,1981, the NRC amended 10 CFR 50.44 by. the addition of the provisions of 50.44(e) (3).

One of these provisions required licensees of BWRs that rely upon purge /repressurization systems as the primary means of hydrogen control to provide a recombiner capability by the end of the first scheduled outage after July 5,1982. In response to this amendment, the BWR Owners Group prepared NEDO.

i 22155, Generation and Mitigation of Combustible Cat, Mixtures in Inerted BWR Mark l

I Containments, demonstrating that Mark I plants do not need to rely on the use of a purge /repressurization system as the primary means of hydrogen control.

Generic Letter 84-09 was issued on May 8,1984, endorsing the NEDO-22155 finding.

The Commission determined that a Mark I BWR plant would be found to not rely upon purge /repressurization systems as the primary means of hydrogen control, if certain conditions were satisfied. Non reliance on these systems would climinate the need for recombiner - installation required by 10 CFR 50.44(c) (3).

BNP satisfied these criteria based on the existing technical specification requiring an inerted containment atmosphere, and by installing the Nitrogen Pneumatic and Nitrogen Backup Systems to eliminate potential sources of oxygen not considered in the NEDO-22155 models. The NRC then concurred that BNP did not rely on the purge /repressurization system as the primary means of hydrogen control, ar;d that the NED0-22155 combustible gas generation models were applicable to BNP 11ovever, Generic Letter 84-09 required that any plant with an existing "satety I,rade" purge /repressurization system continue to maintain the system even though n

t may be determined with respect to 50.44(c) (3) that the plant does not rely on that system as the primary means of hydrogen control.

NED0-22155 concluded that for BWR plants with inerted Mark I containments, peak post IDCA oxygen concentrations are maintained below the combustible limit ac all times without requiring containment venting or hydrogen recombiners.

In addition, for the design base analysis, oxygen concentrations were maintained below the combustible limit without containment atmosphere dilution (ie, with CnD Subsystem-Dilution operation).

CAD Subsystem Dilution operation was necessary only in certain of the " sensitivity" studies performed assuming significantl;r more conservative oxygen generation rates. Based on these findings, the safety.

related function of the CAD Subsystem is less significant than that for which it was originally oesigned. In fact, based on the NED0-22155 " base case", its use would not be required to maintain oxygen concentrations below the Regulatory.

Guide 1.7 limit of 5%,

The BSEP FSAR assumptions concerning containment oxygen generation rates post LOCA do not take credit for the reduced rates justified in NED0-22155. Based on overly conservative generation rates, and an initial containment oxygen concentration equal to the Technical Specification-3.6.6.3 limit of 4 percent, FSAR paragraph 6.2.5.3.2.1 states that ruppression chamber oxygen reaches a five percent concentration level approxin N1y 0.45 days af ter a LOCA.

In order to limit oxygen concentration below 5 pes :ent, it can be conservatively assumed that initiation of the CAD Subsystem-Dilution would not be required until at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after a LOCA.

Therefore in the unlikely event of a Unit Substation E6 failure, a reasonable amount of time is available for compensatory actions required to manually initiate containment dilution. The length of timo available between accident initiation and required operator action is well within the minimum operator action time delay guidelines established by ANSI /ANS 56.6, Time

. Response Desian Criteria for Nuclear Safety Related Operator Actions.

The few t

steps require $ to locally initiate the CAD Subsystem are straightforward. The additional time required to perform these steps is insignificant compared to the time elapsed between the accident and the need for containment atmosphere dilution.

(During normal operation, containment oxygen concentration is maintained well below the Technical Specification limit of 4 percent. Therefore 7

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Change to the Facility as Described in me FSAR the minimum expected duration between accident initiation and a c ont aitunent oxygen concentration of 5 percent, would be significantly 1-

.,er than the 0.45 days assumed above.)

The existing configuration of the CAD Subsystem does not comply with the FSAR and GDC 41 single active failure criteria wlth respect to power supplies to the vaporizers and valves NP-CV-2714 and NP-FCV-2720.

It is our opinion however, that the dilution system complies with the original design intent, in that the system is provided with redundant flow paths, and critical components are powered from reliable emergency sources. This opinion does not however materially af fect the conclusion reached in this evaluation; manual operation of the vaporizer valves provides adequate and reasonable compensatory action to ensure that the system remains capable of performing its safety-related function, even in the unlikely event of a loss of power from Unit Substation E6.

Also, BNP no longer relies upon containment purge /repressurization as the primary means of hydrogen control due to improvements in containment atmosphere control (ie., installatlon of the nitrogen pneumatic and nitrogen backup systems).

Elimination of this reliance diminished the safety significance of the CAD Subsystem. In fact, based on the NEDO-22155 ba.o case assumptions, peak containment oxygen concentrations will be maintained below combustible limits even without dilution by the CAD Subsystem.

However, in keeping with the requirements of Generic Lettnr 84-09, the CAD Subsystem will continue to be maintained as a " safety grade" system.

Procedures for manual operation of the Subsystem will be prepared and performed (on a test basis) to demonstrate acceptability of manual system operation.

These procedures, combined with the existing level of redundancy in the CAD Subsystem, provide adequate assurance that the system will be avail able and capable of performing its safety-related function.

This capability will be assured even in the improbable event that containment atmosphere dilution would be required after a LOCA, while assuming a Loss of Off-Site Power (LOOP) and a loss of power from Unit substation E6.

The final long term resolution to the CAD Subsystem redundant power sup,.y concern has been identified and includes implementation of a modification to achieve redundant CAD Vaporizer trains, with the A Train Division I, and the B Train Division 11, as assumed in the FSAR. An action item has been established to track completion of this corrective action. Modification implementation will be completed as early as practicable.

In the interim period, the CAD Subsystem will be available and capable of performing its safety-related function as demonstrated by this evaluation. Acceptability of manual system operation has been demonstrated by Special Procedure. Necessary Plant Operating Manual (POM) revisions have been completed. Identified discrepancies that could potentially affect system operability have been corrected.

SAFETY

SUMMARY

The CAD Subsystem provides for post-accident control of combustible gases.

The system is not associated with the initiation of any accident.

Rather, it provides an accident mitigating function.

Since the fundamental function and objective of the system is not affected by the subject evaluation, the probability of any accident will not be increased.

The subject evaluation has demonstrated that the CAD Subsystem will be capable of performing its accident mitigating function when required to do so.

Therefore accident consequences will not be increased.

It has been shown that the CAD Subsystem does not meet the single active failure criteria with respect to vaporizer power supplies, required by the UFSAR and General Design Criteria 41.

However, the evaluation has demonstrated that adequate and reasonable compensatory actions can be taken to ensure that a loss of power f rom Unit Substation E6 can be tolerated without af fecting the ability of the system to perform its safety-related function of containment atmosphere dilution, when required.

The evaluation requires that procedures for manual operation of the system be developed, tested, and incorporated into the POM prior 8

_._m._..

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Change to the Facility as Described in the.oAA to; canceling the LCO.

This methodology, combine. with the diminished safety significance of the CAD Subsystem, provides assurance that the protection

' intended by CDC 41 is adequately achieved.

BWR Owners Group report NEDO-22155 has demonstrated the diminished safety significance of the CAD Subsystem, from that originally considered in the FSAR.

BNP no longer relies on containment purge /repressurization as the primary means of combustible gas control in containment.

In the unlikely event of a failure of the emergency - power -supply, there is adequate time to implement the compensatory actions required to ensure that the CAD Subsystem will be available to perform its safety-related function when, and if, called upon to do so.

Based on these considerations, the consequences of the CAD Subsystem malfunction are not Arcreased.

The subject evaluation has reasonably demonstrated that the CAD Subsystem is installed as originally intended and "that it remains capable of performing its safety related design function of combustible gas control, with reasonable compensatory action required in the event of a Unit Substation E6 related failure. Furthermore, the CAD Subsystem is associr ted with accident mitigation, not initiation. Even in the event of a complete loss of its mitigating function, the CAD Subsystem is not capable of initiating an accident.

Therefore the-existing configuration of the CAD Subsystem does not create any new accident

types, i

The subject evaluation has reasonably demonstrated that the CAD Subsystem is installed as originally intended-and that it remains capable of performing its safety related design function of combustible gas control, with reasonable compensaton action required in the event of a Unit Substation E6 related failure.

Therefore although the FSAR apparently did not assume that a single

- active failure could render both loops on the CAD Subsystem electrically inoperable, the existing level of system redundancy combined with the degree of manual operation required, provides the protection intended by the single active failure criteria.

The basis for Technical Specification 3.6.6.2 is to prevent a flammaole mixture of gases from occurring in containment post-accident.

This basis is satisfied by-maintaining the containment oxygen concentration below the Regulatcry Guide 1.7 value-of 5 volume percent, through use of the CAD Subsystem.

The subject evaluation has demonstrated that even in the event of a loss of emergency power, reasonable compensatory actions (ie., manual control) onsure that the system will

-be'available to limit containment oxygen concentration below the basis limit.

Therefore-the Technical Specification safety margin is not reduced.

t 9

I

Change to the Facility as Described in the PSAR TITLE.

EER 90-0174, Justification for Continued Operation (JCO) for 2-CAC.

V49 with DC Grounds FUNCTIONAL

SUMMARY

1 The CAC system Vent / Purge subsystem is used to control 1

containment over-pressurization af ter an accident. The CAC system CAD Vent / Purge subsystem utilizes the SBGT system or the stack as an exhaust path.

There are three paths from containment to the SBGT system or to the stack. The three paths are: (1) Suppression Pool venting through valves, (2) Drywell venting through valves, and (3) Drywell head venting through valves 2-CAC-V49 and 2-CAC-V50. The suppression pool and the drywell venting valves are all powered by Division II AC Power sources, with the exception of valve 2-CAC V172 which is powered by a Division 1 AC Power source. The head venting valves are powered from 125 VDC power sources. If Unit Substation E8 is lost, the ability to open the Division II AC Valves is lost. This condition leaves the only electrically operable path for venting / purging contaitunent as the path through valves 2-CAC-V49 and 2-CAC-V50.

In March 1990 a ground was detected on the 125/250 VDC Switchboard 2A.

The ground hunting effort determined that there is a 16,000 to 20,000 ohm ground on the circuit for valve 2-CAC-V49.

Af ter it was determined that a ground evisted for valve 2 CAC-V49, the valve was closed and placed under clearance on March 23, 1990 (reference corrective maintenance work order 90-ACFC1).

The cleatance on valve 2-CAC-V49 made the DC powered path for containment venting unable to be operated electrically from the control room.

This evaluation is required to allow valve 2-CAC-V49 to remain under clearance and to provide guidance to BNP operational staff on the operation of the valve in the event of an accident where contaitutent purging / venting is required. The compensatory operating guidance for the valve will allow two redundant, diverse, and independent paths to be established for containment venting, one powered by AC valves and one powered by DC valves. The actions taken will ensure that the containment venting path through the DC valves remains in an operable condition.

S AFETY SUMMB.11 The CAD Vent / Purge Subsystem provides for post-accident control of combustible gases and for pressure control. The system provides an accident n.itigating function.

Since the operability of the 2-CAC V49 valve and the operation of the CAD Vent / Purge subsystem are not af f ected, as evaluated by this EER/JCO, the probability of any accident previously evaluated in the UFSAR will not be increased.

This EER/JC0 evaluation has demonstrated that valve 2-CAC-V49 is operable and is capable of performing its containment isolation and accident mitigation function when required. Therefore, the ccusequences of any accident previously evaluated in the UFSAR will not be increased.

The DC ground on valve 2-CAC-V49 is a high resistance ground. Per IEN 88-86 and previous plant surveys, most other nuclear plants have a ground alarm set-point of 5000 Ohms. The worst ground on the 2 CAC-V49 is 11,000 Ohms. The 11,000 Ohm ground should not result in valve 2-CAC-V49 failing to operate.

Additionally, 4 nsures that the compensatory actions (i.e.,

ground re,istance me asu reme nt r.)

circuit cannot degrade.

The feeder breaker for valve 2-CAC-V49 will be maintained in the OFF position until the valve is required or tested. This will ensure that the ground on the valve control circuit will not mask other grounds which may occur on switchboard 2A. This EER/JC0 evaluation has demonstrated that valve 2-CAC-V49 is operable and is capable of performing its containment isolation and accident mitigation function when required.

Additionally, the increased surveillance, testing, and compensatory actions taken will ensure that the occurrence of malfunction of equipment important to safety previously evaluated in the UFSAR is not increased.

Three paths exists for the CAD purge / vent subsystem to vent primary containment.

10

Change to the Facility as Described in the FSAR Two paths are established usinr, AC powered valves and ot.e path is established using DC powered valves. This ELR/JC0 evaluation has demonstrated that 2 CAC-V49 is operable and is capable of performing its containment isolation and accident mitigation function when required. Additionally, the other redundant AC paths provide further assurance that containment isolation and accident mitigation functions, when required, will be accomplished.

This independence and diversification will ensure that the ecnsequences of malfunction of equipment important to safety previously evaluated in the FSAR will not be increased.

This EER/JC0 evaluation has demonstrated that valve 2-CAC-V49 is operable and is capable of performing its containmint isolation and accident mitigation function when required.

Increased surveillance, testing, and compensatory actions will ensure that the valve will perform it s safety functions of ec.ntairunent isolution and venting. This EER/JC0 evaluation ensures that the probability of an accident or possibility of a malfunction of equipment important to safety of a different type than already evaluated in the FSAR will not be created.

This EER/JC0 evaluation ensures that the containment i s ol a t ',oi.

and accident mitigation function of 2-CAC-V49 ts operable thus not changing ary technical specification basis.

Increased surveillance, testing and compensatory actions will ensure that the valve will perform its safety functions of contairunent isolation and venting. Basad upon the cvaluation presented in this EER/JC0 the aiargin of safety as defined in the basis of Technieni Specifications will not be reduced.

11

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. Change to the Facility as Described in the FSAR TITLR EER 90 0181, Reactor Building Steam Heaters ani Evaporative Coolers Out of Service.

FUNCTIONAL SUMMAKh This evaluation justifies cliuate control in the plant reactor buildings without the use of the steam heating and evaporative cooler systems. Tha-steam heating and evaporative coolerc are no longer in use. This evaluation concludes that the steam benting ond evaporative cooling systems are not required-to maintain the reactor Wilding tcmperature within the established design limits.

A low temperature design limit of 40 degrees Fahrenheit (f) has been estatlished to prnvide protection from freezing of liquid processes by original deuign basis.

Based on temperature monitoring data. lwer temperature values historically approach the 50 to 60 degree F range without the use of the steam heaters.

No known freezing problems have' occurred in the reactor buildings since disabling the steam heater system, An upper temperature design limit of 104 degrees F has been established to safety equipment qualification requiremants. Based on the design outside temperature of 93 degrees, this allows an 11 degree heatup.

l The reactor buildings are designed ~for a clinimum of two air changes per hour.

Thus, warm air from equipment heat loads are constantly exchanged with outside air such that the temperature remains within the 11 degree ban.

Temperature measurements - in July,1990 indicat.e that the reactor building is within the 11 degree ban.

The measured outside temperature was in the low 90's with the reactor building not exceeding _100 degrees general area temperature except for the 7/23 outside reading _of 81 degrees which is either inaccurate or following a rain in which the reactor buildin6 had not yet responded.

Temperature monitoring was performed in the HpCI and PHR rooms during the period September 1987 to September 1988. Graphs and a summary table of the highs, lows, and' averages ate recorded on cat tridge 4393, frames 980 and 992 through 1009 of-the Brunswick records system.

The data was gathered once each shift (twice a l

day) and the weekly readings from each shift were averaged. Thus, the plotted j

readings include night and daytime readings thereby including the most severe l_

conditions. During this period, the absolute high temperature recorded was 115 degrees with the highest weekly average of 109.1 degrees. These highs occurred in the Unit 2 HPCI room which is susceptible to heat rise f rom steum Icaks. The i

range in the RHR rooms was.100 107 peak with a weekly average high of 93.6-97.1 p

de. ' re e s.

Also, the room cooler setpoint for this area is 120 degrees, so thev l

did not affect the measured temperatures.

L

- Thus, if the 1987 peak HPCI room temperature was 115 degrees and the peak wakly j.

average was ~109, then the peak ' building temperature would not be expected to j

- exceed 122 degrees F peak with a weekly average maximum peak of 116 degrees F, The EQ Qualification Data Package (QDP) aging calculations for the reactor

-building are based on the equipment being at a temperature up to 104 degrees F for the life of the equipment. Although the highest recorded temperatures are hi her in - some areas - than the 104 degree analysis temperature, the yearly 6

averages are wel1~below 104 degrees F.

Thus, the lack of-evaporctive coolers l

does not affect - the EQ analysis.

As previously stated, the purpose of l

maintaining the air space temperature to 104 degree F is to satisfy equipment

-qualification requirements.

Concerning short term peak temperatures. E0P SCCP, Emergency Operating Procedure for Secondary containment Control, has maximum -normal operating values (degrees F) which -specify peak normal temperatures for various rocu. Temperatures in excess of these values require

-evaluation. -The 20 ft. and 50 ft. elevation ambient temperatures have recently been added to the Unit 2 per PM 87-108. Temperature recorder 2 B21-TR-5769A and l

5770B located in the Unit 2 back panels give indication for four ambient temperature points on the 20 ft and 50 ft elevations of the reactor building.

12

.. ~

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Change to the Facility as Described in the FSAR Similar recorders will be installed in Unit 1 this upcoming refueling outage per Plant Modification 87 107. These elevations exhibit temperatures at or near the peak temperatures for the building.

Four areas of specific equipment have been analyzed for eff ects of high arkient temperature.

They are representative exattples which encompass the areas of concern for high temperatures. They are:

wire resistar.:e, AC coils, DC coils, and Rosemount pressure transmitters.

Based on the results of the analysis, it has been determined the increase in temperature to < 122 degrees F has ininimal effect on the resistance of wire and thus insignificant change to the amount of electrical current present at initial energization and through current stabilization af AC and DC coils.

The rcactor building designed environment is 40 to 104 degrees with the steam heaters and evaporative coolers in service. 'Ihe method for calibrating process transmitters is to calibrate them in place in the reactor building at ambient conditions.

The vendor states that transmitter error induced is linear with respect to temperature to the positive or negative side of the calibrated condition.

Transmitters could operate with the error induced by an ambient temperaturn swing of 64 degrees (calibrated at 104, building temperature at 40) within the building ambient temperature design lin'.ts.

Since error is linear for either an increase or decrease in temperature, it follows that an addition of 64 degrees ambient temperature to the 104 degree deaigned upper limit to the reactor build!ng would induce the s atte error as a drop to 40 d'grees.

Since this evaluation predicts a peak temperature for short periods of only 122 degrees, instrument inaccuracy due to ambient temperature rise would be within the bounds presently operated under.

In conclusion, the averare upper temperatures are below 104 degreec F which is within the EQ analysis. Yor short term temperature peaks which may occur during summer months, electrical equipment resistance and/or current changes are small, thus, having a minimal 'effect on equipment operability. Controls are installed to nonitor and to evaluate short term temperature peaks, if required.

Thus, safety related concerns in relation to high temperature are addrest,ed without use ci the reactor buildins evaporative coolers, j

SAFETY SURMABX; In summary, the steam heaters are not required to meet the 40 degree lower limit based on:

the system was not designed for safety related use.

temperature data confirms freezing is not a problem.

there are numerous heat sources within the reactor building which maintain temperature.

the limit is to prevent freer.ing and numerous years experience verify that freezing of components in the reactor building is not occurring.

01-43 reduces circulation of outside air, if required, to maintain building heat.

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p Change to the Facility as Described in the PSAR The reactor building 04 degree reactor building limit based on; temperature'is acceptable without.

coolers-to meet the 1 the ventilation system exchanges the building air volume twice per hour.

temperature peaks above 104 degrees are for short periods.

EQ equipment

- is rated for continuous service at 104-de rees.

- = changes - in electrical equipment and/or-draulic fluids are small and would not significantly effect system per ormance.

controls are in. place with. specific temperature limits for each area of the building to ensure equipment remains operable, Since the lower temperature does not fell below the building design of 40 degrees and is within t'ne EQ analysis for the high temperatures, the probability of occurrence - of an accident or malfunction of equipment malfunction would not chango.

Since thf 8 evaluation is temperature related only and does not affect operational

-changes, equipment changer,, testing, etc., the consequences of an accident or malfunction of equipment would not change.

4 This issue is not addressed in the technical specifications and does not affect the margin-of safety contained therein.

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Change to the Facility as Described in the FSAR TITLE:

EER 90 0246, 2-COR-V7 Temporary Repair FUNCTIONAL SUM 5R CRD pump suction check valve 2-COR-V7 failed due to disc and seat wear. This evaluation was prepared to provide justification for a temporary repair consisting of the following:

1.

Valve reassembly without the disc or spring, 2,

The system restoration to normal lineup and verification of proper operation.

3.

Action item assignment requiring determinatien of a permanent resolution for this problern (this may be converting this temporary repair into a permanent configuration per the appropriate process).

SAFETY SUM'4ARY: The check valve prevents water from the CST tank from trying to flow into the condensate line just downstreatn of the deminercliters, the only tirne that prest.ure in this line sould be low enough for water to flow this

(-

direction would be either due to shut down of all three condensate punips or in the event of a valve lineup problem.

If this were to occur as the result of a transient, this would not cause any problems. When the condtnsate system is shut down for a planned outage, this line is isolated by closure of the 2-COR V6 and 2 COR-Vll per OP-32.

Since this line is administrative 1y isolated when the condensate system is shut down, then there is no reason that the check valve need to function.

b 4

15

I Change to the Facility as Described in the FSAR TITLE; EER 90 0253, Use of Fire Protection Water for Battery Discharge Tests FUNCTIONAL St% MARY 1 Plant battery / chargers lA-1, lA-2, IB-1, and IB 2 are tested per 1MST BATTilR,13R, ISR and 17R using the Hi-Rate Discharge (HRD) tester. The HRD tester requires cooling water during performance of these tests.

The only readily available source of cooling water near the battery rooms is the fire protection (FP) system supply. This evaluation determines the acceptability of temporarily using the FP system to supply the HRD tester cooling water.

The HRD tester is used to perform the battery / charger " Service Capacity Test".

This is performed to determine the operability of the 125VDC plant batteries and their associated chargers.

The HRD tester, under worst case conditions, will require 40 GPM for adequate cooling.

Each battery discharge test takes approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The approximate HRD tester usage from the fire protection storage tank'is 19,200 gallons pet battery discharge test.

The two fire protection system jockey pumps are each rated for 130 GPM at 125 PSIG, The electric fire pump automatically starts when the system pressure drops to approximately 105 PSIG. With both jockey pumps running, a total outflow of 360 GPM would be required to drop the system pressure to 105 PSIC. There is an existing demand of 55 GPM on the jockey pumps which includes a 20 GPM flow for each gump bypass. The total system flow during the HRD battery test is 95 GPM which is well below the design flow of 360 GPM needed to drop the system pressure to 105 PSIC.

The maximum total output of water from the suction tank during battery testing is 55 GPM (95 GPM minus 40 GPM for both jockey ptunp bypasses. ) The normal level of the fire protection tank is 300,000 gallons.

At an output flow rate of 55 GPM, it would take 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> to draw the tank below the committed minimum volume of 225,200 gallons.

Each bettery discharge test requit es the use of the HRD tester for approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. At 55 GPM, the total outil w fenm the fire protection storage tank is approximately 26,400 gallons. To insure that Technical Specification / committed minimum tank volume is not exceeded, the tank volume prior to each battery discharge test should be at least 267,000 gallons.

The fire protection system can easily supply the HRD tester cooling water requirements without jeopardizing the integrity of the fire protection system.

The cooling water for the HRD tester will be obtained from the test connection down stream of Unit I valve 1-FP-V133.

No fire suppression Limiting Condition of Operation will be required because hose station 1-CB-1 will remain available for immediate use, thus meeting Technical Specification criteria.

The temporary hose connection will be disconnected immediately following completion of the battery discharge tests.

Additional controls established during performance of the test include:

1.

No other demands are allowed on the FP system during the HRD battery tests.

2.

The HRD tester water flow rate is limited to a maximum of 40 GPM by the use of control valves.

3.

The HRD discharge water is not contaminated and can be discharged to the clean floor drain system.

4.

Both FP system jockey pumps mtat be operable prior to the HRD battery tests.

16

Change to the Facility as Described in the FSAR SAFETY

SUMMARY

1 The use of the temporary fire protection connection does not adversely effect previous FSAR evaluations, nor does it result in adverse operating conditions for the fire protection system since Technical Specification water levels are maintained and the hose station remains operable.

The use of FP water at the hose station does not prevent use of the station for fire fighting efforts, nor is the Technical Specification margin of safety reduced.

17

~I-Change to'the Facility as' Described in'the FSAR TITLE:

EER 90-0259, Unit 2 Rod Sequence Control System (RSCS) Disabling EDP 90-013,-Unit 1 RSCS Decommissioning acceptable by the ges support the elimination of the RSCS functions Those chan FUNCTIONAL

SUMMARY

NRR SER developed in response to an amendment as. defined request to the Brunswick Operating License Nos. DPR-71 and DPR-62. In accordance with engineering evaluation procedures, the Unit 2 RSCS function was disabled by defeating / removing some of associated control logic relays and annunciators. An EER 90-0259..

action item requires complete RSCS system hardware removal / decommissioning by the B210R1 refuel outage scheduled for 9/7/91. Unit 1 RSCS -decommiasioning was performed in - accordance with plant procedures by removing portions of the input / output logic circuits and supporting elements including-electrical conduit, turbine first stage pressure instrumentation sensing lines and isolation valves, control panel cover plates and electrical power circuits.

Because of the disabling of RSCS, Operations will no longer rely on RSCS to restrict control rod movement. Those segments of the RSCS logic responsible for control rod movement restriction are disabled.

Control rod pattern error is prevented by the Rod Worth Minimizer (RkH) solely. The impact of such a change to the applicable Technical Specifications is addressed within Technical Specification Amendment No. 144 issued 9/11/90.

SAFETY

SUMMARY

The RSCS restricts rod movement through the use of red select, insert, and withdrawal blocks to minimize the individual worth of control rods to lessen the consequences of a postulated Rod Drop (Accident (RDA) with control rod movement restricted. The RSCS is a hardwired as opposed to the RbH which is computer controlled),_ redundant backup.to the Rod Worth Minimizer.

It is independent of the RkH in terms of inputs and outputs but the two systems are compatible. The RSCS is designed to monitor and block necessary operator control rod selection,--withdrawal and insertion actions, and thus assist in preventing significant control rod pattcrn errors which could lead to a control rod with a large reactivity worth (if dropped).

A significant pattern error is ons of several abnormal events all of which must occur t - have a RDA which might exceeC the fuel enthalpy limit criteria set for the event. -The RSCS was designed only for possible mitigation of the RDA and is active only during low power operation

- (currently less than 20% of rated thermal) when a RDA might be significant. It provides rod blocks on detection of a pattern error. It does not prevent a RDA.

A similar pattern control function is performed by the RkH, a computer controlled system.

As discussed above, the RSCS is a redundant backup to the RkH.

Also, the RkH verifies compliance.with Banked Positions Withdrawal Sequence (BPWS) which prevents the RDA from exceeding the 280 cal /gm fuel enthalpy criterion. When the RkH is operable, the RSCS is not needed since the RkW prevents control rod pattern-error, In the event the RWM is out of service, af ter the withdrawal of the first 12 control rods, Technical Specifications require that control rod movement and compliance with the prescribed control rod pattern (i.e., Banked Position Withdrawal Sequence per Technical Specification 4.l.4.1.2) be verified by a second licensed operator or technically qualified member of the technical staff.

The verification process is contro11ed procedurally to ensure =a high i

quality, independent-review-of control rod movement.

In-addition, to further

. minimize control rod movement at low power with the RWM out of service, the.

proposed Technical Specifications will permit only one plant startup per calendar

..- year with the RWM out of service prior to or during the withdrawal of the first twelve control rods. These measures, taken together, demonstrate consistency and appitcability to those conclusions reached in the referenced SER and prevent significant control rod pattern error which could' lead to a control rod with a.

'large reactivity worth (if dropped).

18

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Change to the Facility as Described in the FSAR TITLE:

FM 81-227B, Revision 9, Installation of Fish Diversion Structure (FDS)

FUNCTIONAL

SUMMARY

This inodification allows for installation of the supporting structure required to support screens designed to minimize the entry of fish into the Intake Canal and thus minimize impingement or. the traveling screens for Circulating Water and Service Water Systems.

Revision 9 to this modification recognizes that the diversion structure affects the cooling water intake canal level which affects the suction pressure for the Service Water Pumps (SWPs),

Circulatory Water Pumps (CVPs) and the Screen Wash Pumps.

Revision 9 also provides the safety analyses justifying this change does not represent an unreviewed safety question.

A supplemental safety analyses and raview was performed to address the impact of

'he FDS on the ability to transport diesel fuel oil by barge up the Intake Canal to the Fuel Oil Storage Facility.

SAFETY

SUMMARY

Calculation G0050A-20

" Hydraulic Analysis of Cooling Water Intake Canal and Pump Intake Structure," provides the relationship between water elevation in the Cape Fear River and the water elevation in the Intake Canal outside of tne intake structure lor various cooling water flow rates, The maximum flow rate considered, 1,350,000 gpm, is slightly larger than the maximum possible total flow rate for the plar.t. 1,312,000 gpm (8 CVPs at 156,000 gpm each and 8 SWPs at 8,000 gpm each).

The calculation also provides head loss relationships for flow through the bar racks and traveling screens.

Revision 2 of Calculations C0050A-10 and C0050A-12 have analyzed the operation of the SWPs for the Sarvice Water Pump Intake Bay water level of -8.63' Mean Sea Level (MSL). EER 90-0084, Rev. O, issued 8/15/90, has evaluated the Intake Canal minimum water level at -7.75' MSL with a reasonaole maximum pressure drop across the traveling screens of 0.88' to maintain the Intake Bay water level of -8.63' MSL.

Action item 6 of the EER requires revision of AOP 13 to reducs or secure the operation of the Circulating Water Pumps flow as required to maintain a minimum required Intake Canal water lavel of -7.75' MSL.

For the extreme low tide of -7.5' MSL and a flow of 224,000 gpm, Calc. C0050A-20 indicates the water c1cvation at the pump intake structure to be -7.o7. MSL. Since the flow required for the Se rvice Water pumps is approximately 50,000 gpm (a conservative assumption of three SWPs in operatior for each unit), by reducing or securing Circulating Water flow during extreme low tides, the required minintm water level can be maintained for operation of the Service Water system. This is consistent with FSAR Section 2.4.11 which asserts that an assumed nlevation of -7.5 MSL is within the capabilities of plant safety related equipment.

This approach is conservative and provides the necessary minimum Intake Canal water level for Service Water System operation. For vary low flows the pressure drop for the Intake Canal (including the Fish Diversion Structure) is negligible, The 50,000 gpm demand for full operation of the Service Water Systems in both units can be considered a very low flow compared to the design flow for the canal. The pressure drop for 224,000 gpm flow at extreme low tide of -7.5' MSL is 0.17 ft.

The pressure drop for 50,000 gpm would be less than ane fourth of that value or less than 0.04 ft.

Even 11 the Fish Diversion Structure was assumed to experience massive plugging durinF extreme low water condit. ions, the pressure drop for 50,000 gym would be negliglble.

Based on the conclusions determined by calculation C0050A-20, Rev.

O, under extreme low water conditions (-7.5 MSL) and severe plugging of the Fish Diversion Structure, the canal level at the structure would remain within the opera ional restrictions required by EER 90-0084.

Transportin5 fuel oil by barge up the Intake Canal for off loading into the Fuel Oil Storage System was only one of the three suggested nethods for replenishing the fuel oil supply to the Emergency Diesel C<.nerators following an accident 19

Change to the Facility as Described in the FSAR involvirg the loss of Malu Fuel 011 Storage Tank.

The other two methods of transportation are by rail care and by tank truck from the several fuel oil supply depots or from company owned facilities. A barge could still be unloaded local dock and transported by truck tc the plant site.

Considering the at a variety of sources of fuel oil supplies and the dif ferent transportation L. thods available, limiting the last resort transportatien method to of f-site unloading does not create an unreviewed safety question.

20

- -. -. -.. ~ - -. -

Change to the' Facility as Described in the FSAR TITLE:

PM 82-198, Storm Drain Monitoring - Pump Basin FUNCTIONAL SLMMARY:

Plant Modification (PM)82-198 provides monitoring and control instrumentation at the " Storm Drain System" pump basin which will be used to measure flow-rate, cumulative total volume of effluent pumped t-o the

- stabilization pond pH level and radfation level of the effluent.

Controls are provided which " lock out" the existing basin pumps on high pH, law pH, and/or high radiation. This lock-out feature can be overridden manually liy a r.ey-locked switch or automatically by a-basin high-water level to prevent the backup of contaminated water into. the plant.

Annunciation is provided.

The above equipment is housed in a 12' by-12' insulated metal building complete with lighting-and environmental conditior.ing.

The monitoring system is comprised of:

A pH monitoring system of the in-line type and capable of measuring a pH range of 5.0 to 10.0.

It is capable of providing contact closures for high, high-high, low, and low-low pH, each independently adjustable.

It is also capable of providing a malfunction signal.

-A flow monitoring system capable of measuring flow rates of 0 to 3,000 GPM at-the pump's basin and 0 to 1,000 GPM at the stabilization pond It is

. complete with a totalizer and a flow rate recorder and has the capability of providing a momentary contact closure for each preset unit volume (to turn on a composite sampler) and a 4 to 20 ma. signal proportional to flow rate for controlling a rad e.onitor, A radiation monitoring system of in-line type and capable of providing contact closures for 1) high rad, 2) high-high rad, and 3) malfunction.

Items 1 and 2 are -independently adjustable.

The monitor is capable of 2 to 107 cpm.

The capability measuring radiation levels at a range of 10 for controlling the monitor by a 4 te 20 ma. signal based on flow rate must be provided.

A-composite sampler capable of providing a pre determined sample volume af ter being actuated by a momentary contact closure, provided by the flow peristaltic type pump and complete with 5-gallon totalizer.

It is a sample jug and level switch cut-of f capability to prevent accidental overfilling of the sample jug.

An annunciator having a minimum of twelve windows, It is the mannal reset type and has an auxiliary output contact that closes when any of the twelve windows alarm. The auxiliary output contact must reset (open) when the acknowledge button is pushed and then reclose on a second, third, etc., alarm SAFErY SlMMARY L This plant modification provides the necessary instrumentatioa and controls to effectively monitor and control the release of radiation to the environment via the existing storm drain system pump basin.

The monitoring system is co sprised of 1) a radiation monitor, 2) a pH monitor, 3) a flow monitor and - 4) - a composite sampler.

This monitoring system will " lock-out" normal t:

operation of the existing basin pumps on high radiation, high pH or low pH, thus preventing the automatic release of substandard quality water from the pump basin. This " lock-out" feature can be overridden manually (on high pH, low pH and/or high rad isolation) via key locked switch or automatically (on high pH or low pH isolation) via a basin high-high water signal (to prevent contaminated water from backing up into the plant). This is acceptable because water from the pump basin is retained in the " stabilization pond" until it is manually released to the intake' canal.

Annunciation is provided for high pH, low pH, high radiation, high water level, manual override, auto override, pump seal water failure, radiation monitor l-i 21 u

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Change to the Facility as Described in the FSAR l

failure, pH monitor failure and loss of power.

will be used in con with the installedunderPM8gunction The pump basin monitoring equipment

& 197.

There will stabilization pond monitoring equipment be no direct ties between the two systems, thus, they can be installed and operated independently.

The storm drain catch basin is provided with an overflow discharge litie.

This line maintains double isolation to mitigate the chances of a release of contaminated water to the discharge canal, which is where the overflow line empties.

Based on the above, no reduction in tl.e margin of safety as defined by Technical Specification nor an unreviewed safety question is introduced by these changes.

22

- _ _ _ ~

Change to the Facility as Described in the FSAR TITLE:

.P.M.82-220B, Unit 2 Replacement of Service Water Vital Her'a Loop 3

FUNCTIONAL SlMMARY: This change replaces the existing cement-lined carbon steel

' piping of~the Service Water-B Loop Vital Header supply and return with 70 30 copper-nickel piping. The replacement piping configuration does not include the well water flush connection.

Future well water chargin',of the Service Water Vital Header may be' accomplished:through the existing we water connection on i

the A-Loop side of the vital header while the A Loop ao B Loop are cross-connected.

Deletion of the Well Water flush connection sill not impair the capability to clean the coolers that the SW Vital Header Loop "B" services.

These coolers would normally be cleaned by " rodding out" the tubes from the cooler end manifolds, not by flushing, The existing well water line will be blind-flanged off.

The new piping will be re-routed to allow for as much pre-outage installation as possible. This modification will replace existing Butterf1[-V117 will be reused.

Valves 2-SW-V117 and 2-SW-V127. The existing Limitorque actuator on valve 2-S1

. New - Monel ball valves will be installed to replace existing vent and drain valves. Repairs. to existing piping, where the new replacement piping ties in, will be performed under this. modification on an as-needed basis.

Also, this modification will include relocation or temporary removal and reinstallation of i

- interferences where required. The existing cement-lined carbon steel piping will be ripped out under this modification. During piping replacement, ev.isting flow element 2-SW FE-5115 will be reinstalled with its annubar piping tap rotated 90*

to a horizontal orientation (current installation is with the tap coming off the bottom of the pipe). This reorientation will reduce silting / plugging problems with the annubar,.and will make its orientation consistent with the other new vital header piping configurations.

SAFETY SlHMARY:

The upgrade of Vital Header piping and valves will increase system reliability while maintaining system functional design. Deletion of the well water flush connection will have no impact since the Loop "A" connection is left in place, allowing for future system wet lay-up.

The well water flush connection being removed by this-PM ia not for use in flushing / cleaning the RHR

& Core Spray Pump Room Coolers - they are cleened by " rodding out" the tubes from

. the end manifolds. Thus, removal of the flush connection will not impair: cooler cleaning capability. Consequently, the probability of occurrence of any accident previously evaluated in the FSAR will not be increased.

The piping and valve replacement and well water flush deletion do not affect system functional design and do not compromise the system's ability to mitigate the effects of any accident previously evaluated. This modification increases system reliability and simplicity; therefore the probability of accident occurrence is not increased. The replacement / material upgrade portion of the modification merely serves to decrease system corroston-erosion susceptibility; removal of the well water flush connection also has no impact, as other flush connections are left in place. Consequently, the consequences of malfunction of equipment important to safety previously evaluated in the FSAR are not increased. This modification does not introduce any new or not previously evaluated components or system functions;- therefore it does - not create the probability of an accident or possibility for malfunction of equipment diffccent than already evaluated. This modification increases system reliability by dareasing system susceptibility to corrosion-erosion. This modification does not affect any technical specification margin of safety.

i 23 l-i 3

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. -.. _ _ - -. ~. _ -.

Change to the Facility as Described in the FSAR TITLE:

PM 83-150, A00 System Punchlist Modification, Field Rev. 5 FUNCTIONAL

SUMMARY

Due to the' maintenance requirements of salt water systems,-

an engineering evaluation was performed to determine the feasibility of permanently bypassing the A0G Charcoal Adsorber System Precoolers. Based on the conclusions within that evaluation permanent bypassing of the A0G system precoolers was determined acceptable.'

The work required to permanently bypass the A0G System precoolers and disable' the associated Service Water Radiation Monitors in this modification package involves i

the following tasks:

1.

The precooler and precooler service water radiation monitors will be abandoned in place.

2.

The associated piping will essentially remain intact while various isolation valves are removed and replaced with blind flanges and caps.

3.

The associated wiring will be disconnected and spared at each component and related interface.

4 All associated drawings, and impacted documents will be updated accordingly.

5.

Temperature element TE-003 will be removed and spared, and associated conduit will be removed. The anrunciator alarm switch from this loop will be wired into the "002"' loop in order to provide a comparable surveillance function.

SAFETY

SUMMARY

t The main pu pose for bypassing the A0G precoolers is to reduce the high maintenance and problems associated with the Service Water cooled precoolers which will enhance overall system performance and availability. Based on the below information, bypassing the A0G precoolers and disabling equipment associated with ths precoolers-will not adversely affect system operation or cause a reduction in system performance.

The design parameters used to originally determine the cooling requirements for the AGG system exceed the actual and anticipated operating conditions for the system. The precoolers were designed to reduce the inlet off-pas temperature to 110 degrees Fahrenheit (F) at 150 scfm and to reduce the cooling demands on the refrigeration units for the cooler condenser. The original desita parameters did not factor in the cooling that takes place in the underground off-gas 30 minute holdup line and the - 8 inch line - to the A0G building -which reduces off-gas temperature considerably below the design inlet temperature for the cooler condenser.

Thereby, reducing the cooling load on the refrigeration units and l

eliminating the need for the precoolers within the operating range of the AOC system.

i In addition since normal inlet temperature to the A0G system is not significantly higher than the service water temperature, the need for the precoolers would:be limited to unusual operating conditions such as high flow (approaching 150 scfm) and/or high inlet temperature (greater than 110 degrees F).

If one of these-j.

unusual conditions were encountered the cooler condenser is equipped with two refrigeration units that could be run in parallel to meet the increased cooling demand until ' correction of the unusual condition.

Note that under normal operation only one refrigeration unit is required to cycle periodically to meet the cooling demand.

24 i

l

Change to the Fa:ility as Described in the FSAR TITLE:

PM 84 062, Field Rev. 36, Alternate Safe Shutdown Feed for Valve 2-l E11.r009 I

FUNCTIONAL

SUMMARY

Plant inodification (PM) 84 062 was initially established to provi.ie an alternate safe shutdown power supply for vsdve 2 E11 F009. Relocation f

of the Unit 2 High Pressure Coolant Injection (ilPCI) t,02 system control panel was t

required to support iruplementation of this roodification.

As a cost effectiva me s.ture, the scope of this modification was expanded to include wiring changes necessary to provide local alarms upon !!PCI CO2 system actuation by a signal from the reserve pull boxes.

Field Rev. 36 to IM 84 062 allowed for roodification of Local slarm initiation for all methods of the HPCI CO, Sy(stem control circuit.

CO2 actuation

a. automatic via thermal detectors located in the llPCI room, b.

taanually via pull box operation, c.

m nually as the C02 cylinder locatiot) throu h the use of a spare contact from the uair, and reserve CO2 supply pressute i

switcies has been added.

SAFFTY

SUMMARY

This mcdification revieten does not affect safe shutdown equipment or procedures. The modification revision does not affect pasriu fire protection features in that penetration of fire barriers is requi ' -l.

The opening and resealing of the-- f!re seals will be done ocr the requi nts of BSEP Specification llo. 110. G3, " Selection and Installation of Fi barrier Penetrations,"

and Brunswick Construction Work Precedure WP-20

" Fire Seals / Stops".

The roodification adds combustibles (in the form of ciertrical cable insulation), llowever, the added cables do not. impose an additional fire severity burden on affected fire areas an the esbles are routed in conduit.

The. modification adds a local alarm initiation to the lipCI CO2 system.

The function of the fire suppression system is not altered. Also, emergency lighting is not affected by this PM revision.

Bas,e d on the above and the conclusions of the orictnet safety evaluation developed for PM 84 062, Rev. 0 (reported in the 1988 $D.59 vnnual report) thir, taodification does not reduce the. margin of safety es def t wa by Technical Specifications or constit s e an unreviewed safety question.

4 25 1

Change to the Pacility as Described in the FSAR TITLE.

pH 86 095, 2 821 pl R612 and 2.B21 pDT.NO35 Core D/p loop Removal; Remove Above Instruments and Associrted Wiring Spared FUNCTIONAL

SUMMARY

This modification permanently removed the following instruments from the plant:

2 B21 PDT NO35 and 2-B21 pl R612 These instruments comprised a loop that monitored jet pump developed head. This parameter is essentially duplicated by the core plate D/p on recorder B21 pDR.

R613, The purpose for removal is two fold:

1.

This transmitter was believed to have been the cause of a scram in 1986 and has been isolated on both units since then. According to the site GE Operations Engineer, this problem has been encountered at other BWRs.

2.

The indicator was rarely, if ever, used.

It is not required by any periodic test.s or any other procedures and was recommended for remeval by the Human Factors Engineering group.

4 The change removed these instruments.

The three valve manifold a.

the transmitter was removed along with associated low and high pressure test valvee.

The associated indicator lines were plugged are a blank plate mounted in its place. The power supply was part of a multi unit,,ower supply B21 X604. This unit of the K604 power supply was spared.

Other-interconnecting conductors / cables were spared as appropriate.

The instruments removed are located on Safe Shutdown support panels, however, removal of these instrurnents has no impact on the post-fire functions of the support panels.

This modification does not affect Safe Shutdown procedures, nor does it affect.

fire detection or suppression systems. The modification does not add combustible materials to cable trays and penetration of fire barriers is not reputred.

Based on the above, this modification has no eftect on Appendix R compliance.

SAFETY

SUMMARY

The instrument loop has no function in any of the accident sequences in chapter 15 of t.ht FSAR; therefore, its removal has no inpact en the previous evaluations.

This equiprnent did provide indication that was essentially redundant to a core differential tressure indication. Removal of the equipment does not comprornise system reliability or reduce redundancy assumed in the FS t,R.

Single active failura criteria and commen mode failure are not affected, These items are ut,affected because the transmitter is safety related for pressure boundary only and the balance of the loop is non safety related.

The subject equipment and associated perameters are not used in the basis for any technfr.a1 specification; therefore no margin of safety is reduced by slimination of the equipment.

l 26 L

Change to the Facility as Described in the ISAR T111.C pH 86 096, Relocation of Service Vat er Chlorine Solut ion Piping and Diffusers ll3.CIl0NAL SlHMARL plant Modifiertion 86-096 remosed the existing chlorine solut ion piping and dif f users in the Service Vat er lutake bays. New piping and diffusers were installed in the Service Water bays.

The new piping in SV bays "2A" and "1B" were rerouted to the inboard (Service Water Pump) side of the traveling screens.

This reroute required two core bores of the Service Water Intake structure walls. Additionally four sections of piping and four rotometers located in the Chlorination Building vore removed and replaced.

The relocation of chlorine piping and dif fusers to the inboard side of the screen wash systern lessens the likelihood of chlorine intrusion to the ecosystem.

SAFETY SlHMARY: The changes made do not alter chlorination system funct ions nor do the changes increase the probability of occurrence of any accident previously evaluated in the FSAR.

This modification doesn't. reduce the capability of any system associated with accidents evaluated in the FSAR, theref ore it does not increase any consequences.

This modification does not affect any equipment itrTortant to safety evaluated in the FSAR, therefore there is no increase in probability of malfunction.

This modification does not affect any equipment important to saf ety evaluated in the FSAR, therefore there is no increase in consequences of malfunction.

This modification does not affect plant equipment of systems associated with safety, therefore there is no probability of an accident or possibility for malfunction of equipment important to safety of a different typa.

This modification does not affect any Technical Specification.

27

Change to the racility as Described in the PSAR TITLE:

PM 86 101, Unit 1, Automatic Dispatch System (ADS) Removal PM 87 039, Unit

1. Removal of Control

Switches, Indicators, Controllers and Pushbuttons pH 87 040, Unit 1,

Removal of Control

Switches, Indicators Controllers and Pushbuttons FUNCTIONAL SUMMARL' The purpose of this plant modification is to risolve applicable sections of Iluman I.ngineering Discrepancies (llEDs) 3008, 3565, and 5088 as identified in llED Resolution Packare 009.

The work scope involves removing unnecessary controls and associated displays irom the main control room panels that are not used by the operators or which have already been spared and still remain on the contro1 boards.

Retaoval of this unused eg' utpment, control

~

switches, and displays from the Reactor Turbine Generator (RTG) boards will enhanc e the control operators' ability to quickly locate and use required controls and displays, it will provide space for future relocation of existing control switches so as to place them in a more orderly and logical position for functional grouping of systens.

At Panel ill2-P601, the f o'.

. wing devices were removed and blank cover plates installed in vacated holes:

1, Core Spray " Loop A" a A Loop B" tentabic check valve control switches and ten associated i t.dic a t.ng lights.

These two control switches and ten indicating lights were previounty spared oy plant modification (PM) 79 032 and 79-033.

2.

RilR llent Exchanger IA,1B, 2A and 2B shcIl vent valves position indicating gauges which were never used.

3.

RilR Crosstle Valve E11 F010 control switch and indicating lights.

These valves had been electrically disabled and maintained lu the closed position, monitored by Technical Specification 4.5.3.2.a.3.

The following devices were removed f rom Panel XU-1 and a blank cover plate installed over the vacated holes:

1.

ADS Turbine Generator Unit Controller located on the benchboard section.

2.

ADS "lN" sh button and ADS "OUT" push hutton located on the turbine Electro ll draulle Control (EllC) Control Panel, EllC CS 437.

3.

Turbine Generator Line Speedmatcher controls located on the Turbine Control Panel. EllC CS-437.

The following devices were removed irom Panels XU 2 and blank cover plates installed over vacated holes:

1.

Control module f or previously disabled Control Switch MS CS 1068, located on the console section. The control switches were spared under pM 86-013 and PM 86 037, 2.

Control Switch EX CS-337, Feedwater lleater 3A Extraction isolation Valve, MOV EX V15, located on the console.

The associated valve will remain in place, electrically disabled.

The valve may be operated by the manual handwhnel on the operator.

3.

Control Switch EX CS-338, Feedwater lleater 3B Extraction isolation Valve, MOV-EX V16 located on the console.

The associated valve will remain in place, electrically disabled.

The valve may be operated by the manual handwheel on the operator.

28

I I

Change to the Facility as Described in the FSAR 4.

Control Switch OG CS 350, Moisture Separator Reheater Blanket Steam Vent, located on the console.

This switch controls valves OG 1BSVV1, 1BSVV2, 2BSVV1, and 2BSVV2 on the Moisture Separator Reheaters (MSR).

These valves were part of the MSR Blanketing Steam System and are no longer required since the Blanketing Steam System piping and feed valves were removed under PM 06 013 and PM 86 037.

5.

Control Uwitch OG CS 346, Moisture Separator Reheater Tube Shell Vent located on the console, These switches control valves OG INCCV1 INCCV2, i

2NCGV1, and 2NCGV2 on the Moisture Separator Reheaters. Thevaiveshave 1.e en removed and the system piping blanked off.

The valves were apparently never used.

The following devices will be removed from Panel XU 3 and blank plates installed i

in the vacated holes:

j 1.

VA ZL 3376, Reactor Recirculation Pump Motor Generator (MG)

Set Ventilation Dampers, and Ventilation Louver position indicating lights.

The ventilation damper and louver have been disabled by isolating their air supply source and manually blocked open.

The position indicating lights are no longer required 2.

The Turbire Vibration Phase Angle Meter (TSI XI 639) and Vibration Phase Angle Selector Switch (TSI XIS 639). This equipment is no longer used by the plant.

Additional changes to Unit I controls include the following:

1.

RHR Check Valves 1 E11 F050A and B actuator and disk position indicating lights. The actuator position lights were previously spared under PM 81-213. The disk position lights are no longer required and will be removed by this plant modification. The actuator and disk position lights for the Unit 2 valves were removed by PM 85 090.

2.

2 VA TI 1648 2, cable spread room temperature indicator. This device has been previously spared and will be removed under this plant modification.

3.

Diesel Generator Cell #1, 2, 3, 4 Ventilation Exhaust Fan RUNNING /0FF legend lights:

a.

2 VA ZL 1606 b.

-2 VA-ZL 1607 c.

2 VA ZL 1608 t

d.

2 VA-ZL 1609 These lights are redundant Unit 2 indicating lights located on the Unit I control board and are not required.

4 Spsre air temperature indicators for the Unit 1 Drywell Reactar Recirculation PurT Motors:

r i

a.

1-FP TI 3917 b.

1 FP-TI-3922 c.

1-FP T1 3927 d.

1 FP T1 3932 e.

1 FP TI 3937 l

f.

1 FP TI-3942 i

g.

1 fP T1-3947 h.

1 FP TI-3952 5.

Spare air temperature indicators for the Unit 2 Drywell Reactor Recirculation Pump Motors:

29 l

m

)

N v a the Facility as Described in the FSAR J

i-FP TI 3917 h

" FP TI 3922 L

bFP-TI 3927 d.

2 PP TI 3932

- e.

2 FP TI 3937 f.

2 FP TI-3942 g.

2-FP T1 3947 h.

2 FP T1 3952 6.

Spare control switch modules' a.

1 FP-CS 3957 b.

2 FP CS 3957 SAFETY

SUMMARY

The p rpose of this plant modification is to remove unnecessary and unusco control equ puent from the control room RTG boards based on a detailed Human Engineering Des gn Review in accordance with NUREG 0737.

This scope includes previously spared components, nonoperational circuits, and operational circuits no longer used by the plant. Removal of this unused equipment. control switches an,i displays will enhance the control operators' ability to quickly locate and use the other required controls and displays.

It will also provide space for future relocation of existing controls so as to place them in a more orderly and logical position for functional grouping of systems.

The following scope of this plant modification has potencial-safety significance;-

14 The LPCI Crosstie Isolation Valve E11 F010 has been electrically disabled by determinating motor 1 cads at the associated MCC. The MCC buckets were r

removed froin the MCC cubicles by' earlier modifications.

The valves are alocked closed" and monitored by Technical Specification 4.5.3.2.a.3 to assure physical independence of each train of the LPCI subsystem of the Residual Heat Removal Systern.

This modification removes the remaining components of the control circuit (control switch, cables, indicating lights, and annunciator). The valve will remain in the system and will be i

adininistratively controlled by the Technical Specification and associated plant procedures.

Removal of the remaining control equipment for this valve offers additional assurance-that the-valvo cannot be inadvertently operated.

2.

The extraction steam isolation valves to. Feedwater lleaters 3A and 3B (Valves EX V15/V16) are adininistratively controlled by the Shift Supervisor due to spurious closures resulting from historically high water i

levels in Feedwater lleaters 3A and 3B, This modification removes the control switches and associated power sources for these valves, thereby electrically disabling the valves.

The isolation signal from the level switches on Feedwater Heaters 3A and 3B will also be disabled. The valves will remain in the system piping and may be operated using the manual handwheel on the operators.

The purpose of the isolation valves is to prevent water induction to the turbine and to isolate extraction steam when the equipment is removed from service.

Since Feedwater lleaters 3A and 3B are fed extraction steam from the lleater Drains Deaerator No. 1 (No. 2 for Unit 2), any water backflow would result in high levels in the deaerator. Existing level control equipment on the licater Drains Dearator No. 1 (No. 2) would result in closure of upstreato extraction steam I

isolation valves and open moisture removal valves, thus preventing water injection into the turbine. The UFSAR Section 15.1.1 analyzes an accident where one of the causes is loss scenario for " Loss of Feedwater Heating" heater.

of extraction steam to the feedwater To preclude loss of Feedwater Heater 3A and 3B heating capacity, the Shift Supervisor placed the extraction steam isolation velves under administrative control.

Removal of the controls and isola ion signal associated - with the 30 7

Change to the Facility as Described in the FSAR extraction steam valves will provide added assurance that inadvertent operation of the valves will not occur and vill serve to clean up the RTC board for litusian Partors conc "s.

3.

The Diesel Genet Cell 2,

3, and 4 vent 11ation exhaust fan

" running /off' leg light niocoles (2 VA :".h 1606, 1607, 1608, and 1609) are redundant Unit 2 indicating lights located on the Unit 1 Cont rol Board 1 XU 3.

These indicating light modules provide redundant indication of nt Fens E EF DG, F EF DC, G EF DG, and the status of the Diesel te116 '-

li EF DC on the Unit I contro iard.

The control switch modules and associated primary status indiu.ing lights for the diesel cells exhaust fans are located on the Unit 2 control board, 2 XU 3.

The stat J indicating lights are 111tuninated via contacts on the exhaust ian control switches. Since the modules provide redundant information and perf orm no control function, they are not required for operation.

Removal of these modules will in no vt-affect plant operation or any system required for safe shutdown.

Thue modifications remove unnecessary and unused controls f rom the Units 1/2 RTG control boards.

These controls include previcusly spared components, nonoperational controls, and operational controls no longer used by the plant.

These controls are nonsafety related, non-Q, and are not required ist the detection of an accident, the actuation of any 5,afety system, or the altir,ation of any accident previously evaluated in the UPSAR.

Removal of ;hese csntrols will not increase the consequences or p;obability of any accident or malfunction to equipment previously evaluated or of a different type than already evaluated.

31

Change to the racility as Described in the PSAR TITLE:

PM 87-007, Unit 2 Replacement of Feedwater Recorder and Relocation of Reactor level Indicator FUNCTIONAL SW A RY1 The purpose of this plant modification is to make channes to the Unit 2 control boards as identified by lluman Engineering Discrepaneles (HED) packages 1401, 1402, 2415, & 2458 an requiring revisions to meet the intent of NUREG 0760. Work scope involves; Relocating reactor watet level indicators B21 L1 R604A and B21 L1 R604B from RTCB panel ill2 P603 to RTGB Panel H12 P601.

Removing the existing General Electric (GE) recorder C32 PR R609, and installing a new seismically qualified "Esterline Angus" Tigraph 200A recorder in the space vacated by relocation of B21 L1 R604 A&B to Panel ill 2 - P601.

Channel B of the new recorder shall be connected to the pressure transmitter C32-PT-N008.

The other signal to the existing recorder, pressure transmitter C32 PT-N007 will be deleted from the recorder input and monitored by ERFIS only. Reactor water level B21 LT-NO26B loop input will be addad to channel A of the new recorder.

this modification installs four new indicators for reactor feed Additionally, ion flow COD-FI-44 3 and COD F1-45-3 and discharge pressure IN-PI-pump A&B suct 50 3 and IV Pl 51 3.

These indicators will be located in the space vacated by the recorder relocation.

This modification has bron implement ed to meet CP&L's commitment to the Control Room Design Review final summary report per NRC Committal letters Serial: NLS 86-449 (R/D) and NLS 87-123 (R/1)

SMETY SUM'4ARY:

Relocation of indicators and recorders will place the instruments in a moro desired visual envelope. No aut omatic protective systems or plant environmental conditions are affected. The requirements of Regulatory Guide 1.97 Category I will be maintained for reactor water level indicators 604A and 604B. The improved visual envelope will enhance operator ability to respond to the necessary displayed parameters, therefore more effectively mitigating potential accidents and transients. Technical Specification requitements will be complied with for this modification.

f 32

Change to the Facility as Described in the FSAR TITLE:

PM 87-029, Unit 1 Cont a itument Atmospheric Control (CAC) System Recorder Replacement PM 87 030, Unit 2 CAC System Recorder Replacement FUNCTIONAL

SUMMARY

This change to the facility replaced the existing TRACOR Vestronics M$E drywell suppression chamber temperature monitoring recorders with Esterline Angus Tigraph 200A 6 recorders.

Functionally, the new installation is the same as the existing installation. The difference between the two installations is that for each of two divisions, one 12 channel recorder is being replaced by two 6 channel recorders.

The new recorders meet the human engineering criteria for BSEP and provide a digital readout as well as a point trace for each channel.

The Tigraph recordcrs also meet the physical size and channel capacity criteria for this replacement. This installation will maintain compliance to the requirements of Regulatory Guide 1.97 and seismic qualification / design.

SAFETY

SUMMARY

The thermal print-head recorders being installed by this plant modification serve to monitor the same drywell/ suppression chamber temperature parameters as the pen / ink recorders being replaced.

There are no control functions associated with these recorders.

The new installation maintains the redundancy, functional independence, physical separation, and seismic qualification and support requirements of the existing installation as well as maintaining compliance to the post accident monitoring and 10CFR50, Appendix R criteria. The addition of digital displays to monitor each channel and ensuring that the digital and point trace displays meet the BSEP human f actors engineering criteria, including readability, reduces the possibility of operatar reading errors.

As discussed above, the new recorders are installed to the same design criteria as the recorders being replaced, and the applicable concerns that resulted from the control room design review have been resolved.

Therefore, the probability of occurrence or consequences of any accident or equipment malf unction previously evaluated in the FSAR or of a diff erent type than already evaluated in the FSAR is not increased.

The margin of safety is not decreased but is possibly increased by improving the human engineering design of this recorder installation.

33

1 Change to the Facility as Described in the FSAR I

TITLE:

PM 87 037, Unit 1 Residual Heat Removal (RllR) Syst em Control Rootn Upgrade PM 87-038, Unit 2 RilR System Control Roorn Upgrade miCTIONAL

SUMMARY

This change has been implemented to resolve lluman Engineering Discrepancy #1409 as identified in Carolina Power 6 Light Conpany Control Roorn Design Review (CRDR) Revision 0, subtaitted to the NRC December 31, 1986. HED #1409 problem definition statement indicated that Controls (located in Panel P601) are located out of functional reach of sotte operators".

CRDR design review concluded that the applicable indicating controllers related to llED

1. 1409 were unnecessary and required removal.

The indiccting controllers the steam condensing mode will be replaced by indicators only with no ci rol function.

The RilR lleat Exchanger Level Indicating Controllers A&B ano Condensate Outlet Preas Indicating Controller will be replaced by manual loading stationu located on the Reactor Turbine Cen( rator Board (RTCB) section within the functional reach criteria of the 5th percentile female.

Other control functions associated with the above indicating controllers will also be rettoved from other panels located in the Electronic Equipment Room and RTCB.

After removal of the above controllers, the integrity of the cntrol circuits will be established as necessary to niaintain operability.

Specifically, these plant modifications implement the following changes:

Remove Rl'.R lleat Exchangers Condensate Outlet Pressure Indicating Controller Ell PIC R609 and lleat Exchanger Level Indicating Controllers Ell-LIC R604A cnd B.

These instrument are no lonr.er used in the EllR system.

New Non-Q manual Loading Stations E11-ilC-6D4A and B are ta he installed to replace these units in an accessible area of the RTGB to allow the operators to mat.unlly control valves E11-F05 3A and B which are Q list for pressure boundary purposes only.

Remove RilR System Pressure Indicating Controllers Ell-PIC R606A and B.

These controllers are non-Q and are nc longer required to contrcl the Steam Condensing Valves E11-F051A and B.

These valves are locked closed and the steam condensing lines have been cut and capped. !nstall new non-Q indicators Ell PI-606A and B to retain the indication portion of this loop.

Remove Mode Solector Switch Ell-S42 which is used to select betweer. RCIC Flow Controller E51-FIC-R600 or RilR lleat Exchanger Level Controllers Ell-LIC R604A(B) which control RCIC turbine speed. The mode selector is to be a factor in RCIC removed since RilR heat exchanger levet is no longer turbine speed.

Remove Q-list lli Lo Signal Selectors E11-SS R605A (Panel H12-P613) and Ell-SS-R605B (Panel lil2 P612), which are no longer required to select the lower signal of RllR lleat Exchanger Level Controllers E11-LIC 604A(B) or the heat exchanger conlensate outlet Pressure Controller E11 PIC-R609.

Jumpers will be installed to retain tho integrity of these loops to maintain control of valves E11-F053A and

• f. manually through new manual Control Stations Ell-UC 604 A and B that are to be located in control room Panel H12 P601.

Jumpers are to be instalhd at points where cables are disconnected that allowed RHR heat exchanger level controllers E11-LIC-604A or B to control the RCIC turbine speed through mode Selector E11 S42.

Installing these jumpers will maintain control of RCIC turbine speed by Flow Controller E51-FIC R600 34

Change to the Facility as Described in the FSAR E/P Converters E11 PY.K003A and B associated with valves E11.F051A and B are to be disconnected and removed.

Level Transmitters E11-LT.N008A and N008B and associated seal pots, capillary tubing and supports will be removed downstream of Root Valves E11-V22, V23. V24, and V25. The root valves will be capped at their pipe nipple and will be maintained closed, Pressure Transmitter E11 PT N028 RilR heat exchanger condensate outlet pressure, is to be disconnected and removed from Instrument Rack H21 P018.

Control Valves E11-LV F053A and B no lont.er control IcVel in the RHR Heat Exchangers 1A and 1B but only serve to flush the upstream and downstream piping back to the Torus during the Shutdown Cooling Mode.

The tagging for the valves will be revised to:

E11 CV F053A and B.

Associated E/P converters will be retagged from E11 LY 001A and B to E11 CY 001A and B.

- SAFETY SUMMARJ1 Modifications under the DBD are implemented to comply with the requirements sut forth in ICREG 0660, "NRC Action Plan Developed as a Result of TMI 2 Accident, "NUREG 0801 " Evaluation Criteria for the Detailed Control Room Design Review " and NUREG 0800, " Guidelines for Control Room Design Reviews."

Revisions to the existing control room switch legends, annunciator windows, indicator scales, indicators, recorder scales, recorders, and re arrangement of control switches and instruments will provide the system status information, control capabilities, feedback, and analytic aides necessary for control room operators to accomplish their functions effectively.

Individual plant modifications will be developed incorporating changes to the-control room panel boards as delineated in Human Engineering Dlscrepancy (HED) reports as developed per the requirements of NUREG-0801, " Evaluation Criteria for the Detailed Control Room Design Review."

The enhancements to visual displays and controls of the equipment altered by these modifications improve operator interface with plant parameters and do not serve to create the possibility for malfunction of equipment important to safety eh. her as described in the Final Safety Analysis Report (FSAR) or of a dif ferent type than that described within tha FSAR.

The removal of controls und indications no longer required to support components / equipment no longer in use aids in eliminating factors contributing to operator confusion and/or inaccurate control of the plant and does not increase the probability of occurrence or the consequences of any accident or malfunction to equipment previously evaluated in

- the FSAR. These changes do not reduce the margin of safety as defined within the basis of any Technical Specifications.

a 35 l

l' u

_ _ _ _, _. _ _ - - -,... _. ~ _ _

Change to the Pacility as Described in the PSAR TITLE:

PM 87 169. Unit 1 Pneumatic Nitrogen System (PNS)

TUNCTIONAL

SUMMARY

The Non Interruptible Instrument Air System is a subsystem of the Instrument and Service Air System. It pros ' des instrument quality air to vital instrumentation-and pneumatic controls s.:hin the Reactor Cont aitunent

vessel, The purpose of this modification is to upgrade the existing Non Interruptible Instrument Air (RNA) Systems as a result. of concerns regarding potential sources of oxygen in the inerted drywell atmospheres.

The pneumatic nitrogen system is designed to eliminate the use of compressed air from the non interruptible instrument air loads in the drywell.

Nitrogen is supplied from the nitrog,en storage facility located at the southeast corner of the Unit 2 reactor building. A complete independent storage unit is provided for each unit.

The storage systems are cross tied for improved reliability.

The nitrogen supply piping from the storage facility splits into Division 1 and Division 2 lines prior to entering the reactor building. Each division line ties into its respective header upstream of the primary containment isolation valve and is separated from the other division by a restricting orifice (one in each division).

The utilization of nitrogen for the pneumatic loads in the drywell valve operation, ygen concentration build up due to instriunent air release from eliminates the ox Various system changes that will be incorporated in these modifications are as follows:

The existing Non Interruptible Instrument Air piping (RNA System) will remain in place, but will be valved out by luolation valves upstream of the respective Division I and Division 11 tee connections to the Pneumatic Nitrogen System. During a system outage, these valves will be opened and the Pnetuna tic Nitregon System isolated to pernit use of the Non.

Interruptible Instrument Air while plant personnel are working and entering the drywell, l

As used during power operation, the Nitrogen Pnetuna tic System will eliminate the introduction of oxygen into the drywell due to operation of pnetunatic controls, l

An alarm will be added in the control room to sir,nal low cryogenic tank pressure.

Local and cont.rol room indication will be provided from tank level and pressure.

Control room and local indication of vaporizer outlet temperature will bc l

provided. Vaporizer outlet temperature is alarmed for a low setpoint.

l The vaporizer will be automatically isolated on low vaporizer outlet temperature.

Two temperature shutoff devices mounted in series will provide additional. reliability.

Pressure regulating valves operating downstream of the ambient vaporizers are self regulating based on downstream pressure, A unit crosstie line will be provided between the Unit I and Unit 2 tanks immediately downstream of the pressure reducing valves. This will provide a nitrogen source backup for the two systems.

A unit crosstic valve, provided in this line, is operator controlled by a switch on each RTCB, Either the Unit 1 or Unit 2 operator can open the crosstie valve.

Both manual switches must be in the closed position in order for the crosstic valve to be closed.

Existing indicators and annunciator alarm windows located on the control 36 l

Change to the Facility as Described in the FSAR room Reactor Turbine Genertor Board (RTCB) will be relocated to other panels in order to achieve functional grouping of the new PNS devices.

This is being accomplished in compliance with human factors engineering criteria.

SAFETY

SUMMARY

No new anticipated operational occurrences or postulated accidents will be introduced as a result of the work contained in this modification.

The PNS added to the Non Interruptible Air System, requires no external source of power except for instrumentation and control devices.

The Pneumatic Nitrogen System adds no new function to the existing system, nor does it reduce the present function of that system.

Since the PNS adds no 'new function to the Non Interruptible Instrument Air System, no additional consequences of an accident other than those previously evaluated in the FSAR could be introduced.

The PNS will reduce the oxygen concentration in the drywell post accident and therefore reduce the chance for a combustible atmosphere.

The PNS, while providing the pneumatic requirements of the instruments and controls within the containment, will be isolated in the event of a core spray thCA, low pneumatic nitrogen header pressure, or loss of power.

In such an event, the Backup Nitrogen System (bottle rack) aligns with the ADS headers and the CAC butterfly valves for the reactor building to torus vacuum breaker valves.

Since both the non interruptible instrument air and pneumatic nitrogen systems are: isolated by the same valve, the probability of occurrence of a malfunction of the Backup Nitrogen System wil) not be increased.

Because of the isolation of the PNS during events requiring alignment of the Backup Nitrogen System (bottle rack) with the ADS headers and the CAC butterfly valves, the consequences of a malfunction in the Backup Nitrogen System will not be increased because of the new system.

Replacing that portion of the IM System which provides the pneumatic requirements for instruments and controls within the containment, with a pneumatic nitrogen system tied in upstream of the containment isolation valve will create no new conditions which can lead to an accident or a malfunction of equipment important to safety of a different type than already evaluated in the FSAR.

Because the basic system design and operational l capabilities remain unchanged, the margin-of-safety as defined in the basis to the Technical Specifications is

-not reduced. The Backup Nitrogen System (bottle rack) is designed with enough capacity to serve the loads for twenty four hours which is established by Calculation No. 84 196-233 in Plant Modification 84 196 and verifies that adequate margins exist.

37

l Change to the Facility as Described in the FSAR IIILE1 PM 87 240 Unit 1 Service Water (SW) Piping Inspection and Repair PM 89 026, Unit 2 SW piping Inspection and Repair PUNCTIONAL SlHMARY: These modifications provided the procedural guidance necoed to support the inspection, evaluation and repair of the Units 1 and 2 SW piping and associated components. The purpose of these modifications is to ensure the continued integrity of the SW systems and prevent salt water in leakage to the plant. The scope of changes affected by these mods resulted from the inspections performed as directed - by the modifications.

With the exception of the installation of new test connections in the lube water supply lines, no other changes are identified as being changes to the facility as described within the Final Safety Analysis Report.

The new test connections are installed in the lubewater supply lines off both the conventional and nuclear headers upstream of the lubewater pump. The connections are installed between the isolation and check valves on lines 71 4 157B and 72 4-1$7B for Unit 1 and 213 4-157B and 214 4 157B for Unit 2 in accordance with the applicable codes and standards, The test connections enable the plant to comply with ASME Section XI requirements for the testing of check valves.

SAFETY

SUMMARY

The Service Water cystem design basis, control logic and functions were not revised by this modification. The inspection provided by this change served to identify deficiencies in the Service Water System incurred as a result of normal / expected wear / corrosion.

Identified deficiencies were corrected while ensuring compliance to the applicable codes and standards and the operability of safety-related equipment interfaced by this mod, consequently, neither the probability of occurrence or the consequences of an accident previously or otherwise analyzed has incressed as a result of these changes.

This change ensures the SW system will continue to perform its FSAR evaluated design basis function.

No reduction in the safety margins -as defined by the Technical Specification has resulted from implementing this change.

I l

i 38

Change to the Facility as Described in the PSAR TITLE:

PMs 87 241 and 87 099, Unit I and Unit 2 Camma T1P Retrofit i

FUNCTIONAL

SUMMARY

The neutron flux sensitive TIPS were replaced with gamma flux sensitive TIPS per this change. This involved not only TIP replacement but also replacernent of the detector cables and flux probe monitor. The gamma TIPS and flux probe monitor are direct replac.'ments for the neutron TIPS and associated monitor. The ramma TIPS should ptovide a better measure of the core flux profile, This should reduce the probability that the unit will he derated due to thermal limits.

The gamma sensitive traversing incore probe (gamma TIP) is a direct replacernent for the neutron sensitive TIP. These TIPS are interchangeable mechanically and are compatible with the existing drive machines, indexers, and guido paths The neutron TIP sensor element has an outside diameter of 0.207 inch and a lendth of 2.348 inches. The ramma TIP sensor element has an outside diameter of 0.213 inch and a length of 2.365 inches. The gamma TIP has a longer conical cap protecting the sealed off exhaust tube, which accounts for its longer length.

These slight dimensional changes are readily accommodated by the existing guide paths and do not affect operation in these guide paths.

Both TIP types use the same drive cable material.

TIPS, both gamma sensitive and neutron sensitive, beco'ne activated by in core radiation when they are used. The two primars contributom to post + irradiation gamma radiation rate are Mn 56 and Co 60, which are produced from constituents in the materials from which the TIPS are constructed.

Mn 56 is the primary contributor to gamma radiation rate -for the - first one to two days after irradiation.

Co-60 is the primary contributor after that time for TIPS which t

have been in service for long cimes.

The-initial gamma TIP design contained a component (cable seal) made from a special high-cobalt alloy.

This TIP assembly (sensor and cable) contained, effectively, 3.3 times the cobalt content of the neutron TIP. Subsequently, this component was changed to a low cobalt alloy,-which reduced the total gamma TIP cobalt content to 1.6 times that of the neutron TIP.

Recently a further improvement has been made in which the total cobalt content. of the gamma TIP has been reduced so that it now is less than one-third that of the neutron TIP. This results in the gamma radiation rate of gamma TIP detectors for long-service, long j

post-irradiation time being less than that for corresponding neutron TIPS.

The manganese content of the gamma TIP remains 10% greater than that of the neutron TIP because of the increased stainless steel content in the gamma TIP triaxial cable. For post irradiation times up to two days, the gamma radiation i

rate (due to the manganese material)-for the gamma TIP will be 10% higher than that for the neutron TIP.

SAFETY

SUMMARY

The TIP system is not involved with the accident sequence evaluated in Chapter 15 of the FSAR, therefore, the probability of occurrence and consequences of any accident previously evaluated la the FSAR vill not be increased. The installation of this modification does not affect the operation of the TIP guide tube valve referenced in Technical Specification 3/4.6.3 and the margin of safety as defined in the basis of that specification or any other is not reduced. Because a gamma TIP has less cobalt content than the neutron TIP, a gamma TIP will have a lower long term radiation rate. This will lower accumulated radiation exposure during TIP maintenance. Additionally, the gamma TIP extended operating life should serve to reduce frequency of replacement and therefore lower radiation exposure to personnel.

5 39

. ~. -

a...-..-

. _ -..-~.~. _. _.- - _._ _

o Change to the Facility as Described in the PSAR 1

TITLE:

PM F8 051, Unia 1 liigh Pressure Coolant Injection (llPCI) Reitability Improvements PH 88 052, Unit 2 IIPCI Reliability improvements w yhMRYi The purpose of this modification is to improve HPCI FUNCTIONAL S

reliability tsy making the following chan6es to the Governor Ilydraulic Control Sys tern:

Additisn of an oil bypass line around the Woodward EC R Actuator.

Rernuting tubin5 between the Woodward EC u Actuator to the Woodward Remote Servo Deletion of the opening rato control valve and bypass tubing on Stop Valve V8 i

Implementation of these changes will improve the overall performance of the llPCI turbine by reducing the initial speed peak, reducing the turbine exhaust line pressure transient, and eliminating the critical adjustment of the !!PCI Turbine Stop Valve Balance Chamber.

Time from itPCI initiation to required rated flow will not be affected.

The portion of the HPCI System tubing to be affected in part of the Governor Hydraulic Control System.

The tubing is located on the Terry Turbine Skid i

between the oil pumps and the Woodward Remote Servo.

The hydraulic bypass modification is a technical improvement which will significantly improve the llPCI turbine initiation response.

The bypass modification will allow hydraulic oil pressure developed from the auxiliary oil pump to move the Control Valve (Valve V9) prior to turbine startup, thus:

l Reducing the initial speed peak of the HPCI turbine Reducing the turbine exhaust line pressure transient I

Eliminating the critical adjustment of the IIPCI Turbine Stop Valve Balance Chamber In addition to the changes above, a time delay relay will be added to the Low Suction Pressure Pump frip to delay the. trip ten seconds.

This delay la to prevent the pump from tripping due to pressure spikes experienced during pump startup.

.The Low Suction Pressure Trip has traditionally been a standard " pump" protection measure. The purpose of this trip is to protect the pump from damage caused by severe cavitation or chronic exposure to mild cavitation due to insufficier,t suction head.

Pump manufacturers continue to recommend low suction pressure protection as a conservative measure in their standard pump specifications.

7 During previous investigations -into the need for the Low Suction Pressure (LSP) i Trip (reference Engineering Work Request 05812A), it was noted that the llPCI pump vendor (Pacific Pumps) had been contacted.

Pacific Pumps stated that they had deliberately induced. severe, prolonged cavitation on similar pumps in their testing, and that no significant damage to the pumps.had been observed.

Basc<1 on the above, it is-not imperative that the pump turbine be tripped immediately

-on low suction pressure to prevent pump damaPe. However, to provide protection from :a condition of prolonged operation with decreased suction head, the low suction pressure trip will not be deleted.

40 o

1 L

-,.--_...a.-.-

i i

Chrnge to the Facility as Described in the FSAR RAIT E

SUMMARY

HPCI is not an initiator of any accident anal with the except16n of an inadvertent HPCI purtp start (FSAR Section 15.1.3).ysis, Modifications to the llPCI Govtraor llydraulic Control Sys, tem do not increase the probability of a pump start. The addltion of a low suction pressure pump trip does not increase the probability of a purnp start.

The 11PCI Governor Hydraulic Control System is being modified to improve the overo11 performance of the llPCI turbine by reducing the initial Speed peak, reducing the turbine exhaust line pressure transient, and eliminating the critical adjustaent of the llPCI turbine stop valve balance chamber.

The los suction pressure trip will protect the HPCI pump from extended (>13 sec.) low suction pressure. These changes increase the reliability of HPCI and t.hus do not increase the consequences of any accident previously evaluated in the FSAR (Chapter 15).

The consequences of malfunction of the HPCI systern previously evaluated in the FSAR remain unchanged.

The probability of an accident or possibility for malfunction of equipment important. to safety of a different type than already i

evaluated in the FSAR is not created.

The Technical Specification Basis consists of operability and availability of the HPCI system. By improving the operation of the Governor Ilydraulic Control System the mar & n of safety is not and by adding a lov su.: tion pressure pump trip, i

reduced.

L 4

P 41

Change to the Facility as Described in the FSAR UTLE:

PM 89-011. Unit 2 DC Mot or Ope.ated Valve (MOV) Motor Replacement PM 89-107, Repince Electrical Components In Unit 1 DC MCCs and Motors ITNCTIONAL

SUMMARY

L These changes were implemented to address existing DC motors instal 1+d in motor operated valves which have, since initial construction, been operated outside the vendor recommended cperating parameters. This was a result of poor communications in the conceptual design phase between design organizations. Discussions with the valve operator vendor (Limitorque) and the motor vendor ("eerless) reveal that the impact in terms of life expectancy is indeterminate.

Testing and/or additional qualification techniques which could be employed to establish a 1cvel of degradation were discussed with the vendors without success. The specific concerns expressco by both vendors are as follows:

1.

The effect of continuous elevated temperature is indeterminate 2.

The effect of continuous energization of the shunt field on a motor whose duty cycle is 5 min /hr is considered to be hieterious; again, the effect on motor life cannot be quantifled.

3.

Due to the shunt fields on DC mot,rs remaining energized continuously, a situation was created whereby a high-induced voltage due to the collapsing magnetic field was experienced each time the motor's breaker was opened.

This voltage, measured in the 6000-volt range, has t'eva determined to be the cause of motoc failure in one in-tar.ce and is suspected as the cause of several other motor failures.

Plant Modifications88-014 and 88 015, ada ess the concerns associated with the shunt field problems.

pMs89-011 and Pb 107 address various concerns with DC motor operator valves including the ef W t nf continous elevated temperatures.

All of the motors listed below have been evaluated in the individual valve electrical and mechanical analysis and calculation data packages by the BSEP-MOVTG. The replacement motors for the majority of the valves evaluated are to be the same size. llowever, three valves per unit w'.1 have a smaller size motor installed, and one valve will have a larger size motor installed.

Vhen considering the design margin of the three valves 1/2 E41-F059,1/2-E51 F019, uad 1/2-E51 F046 at stall torque and :brust, it was determined tha: the 5 f t lb motor has the potential to cause a condition which will allow the design thrust rating of the operator to be exceeded.

To reduce the design thrust rating to an acceptable Icvel, a 2 ft-lb motor will be installed.

Due to the stotor change, the torque switch settings will have to be adjusted accordingly. Because of the torque switch setting changes, four valves (1/2-E51-F059 and 1/2-E51-F019) will require spring-pack changes to accomplish the necessarv torque switch settings.

Also, the motors for valves 1/2 E41-F004 do not dcvelop sufficient torque; therefore, these motors will be replaced with a larger size (10 f t-lb) to supply the required torque to operate the valves.

The folle

,g is a list of valve motors being replaced by this plant modificata

@l/2-E41-F004/10 ft.-lb.

1/2 E41.F042/10 ft. lb.

1/2 E41 F041/10 ft lb.

1/2 E51 V8/2 ft.-lb.

1/2 E51 F010/5 ft.-lb.

1/2-E51-F012/10 ft.-lb.

1/2 E51-F022/10 ft.-lb.

1/2 E51 F045/15 ft.-lb.

1/2-E51-F031/5 ft.-lb.

1/2-E51 F029/5 ft.-lb.

42

l Change to the Facility as Described in the FSAR f

1/2 E11 F040/5 ft -1b.

• 1/2 E41 F059/2 ft. lb.

• 1/2 F51.F046/2 ft. lb.

• 1 2 E51 F019/2 ft.-1b..

1 2 E11 F008/100 ft.+1b.

2 E41+F012/25 ft, lb.

1 E41 F007/80 ft, lb.

• Hotor being replaced with a smaller size, and @ motor being replaced with a larger size; the remaining motors are the saine size as the anotor being replaced.

Additionally, FM 89107 implemented the following changes:

1.

Replaces the "74" relay and re wires the contacts to de energize the control circuit while maintaining position indication on an overload condition.

Also, the circuit will be re wired so that the relay is de-energized when the breaker is closed, instead of continuously energized with the breaker closed, a.: presently designed. This change will result in energizing the "74" relay during a inotor overload, which will alarm in the control room (existing design) and stop valve travel (new cesign). In addition, tha new design elirninates magnetic trip and. loss of control power as causes for an alarm in the applicable annunciator procedures.

Also, this makes the DC HOV logic consistent with the AC MOVs.

2.

Rep 1nce overload relay, "49" device, with ambient temperature compensated type and re size / replace the overload heaters.

3.

Remove the. anti pumping feature from the control circuit of 1.E51.F022.

9 4.

Remove the dynamic braking fec;'are from the control circuit of 1 E41.F001 and 1 E41 F006.

5.

An additional design review of the DC HOVs indicates that the shunt field feeder cables of certain HOVs were not properly coordinated with the feeder breaker.

To obtain proper coordination, breaker size can be reduced or cable size can be increased or, in some cases a cornbination of both. The following is a list of the specific changes:

a.

1-E11.F008 shunt field cuble increased to s9 AUG b.

1 E41-F001 feedst breaker reduced to 20 amps c.

1.E41. F006 shunt field cable increased to #10 AWG and feeder breaker reduced.to 3b amps d.

1-E41 F007 ' shunt fic]d cable, increased to #10 AVG e.

1-E41 F008 feeder breaker reduced to 20 amps f.

1.E41-F011 feeder breaker reduced to 15 amps SAFETY

SUMMARY

The rootors are required to operate during ant. after a Design i

Basis Event, therefore, seismic and envirotunental qualifications (unless indicated otherwise) are required. All of the motors listed in this modification have been evaluated in the individual valve electrical and mechanical analysis and calculation packages. The replacement motors for the majority of the valves listed above were evaluated to be the correct riize and have adequate margin the margin of safety as defined in the basis to any technical specification will not

+

be - reduced and, therefc e, this plant modification does not constitute an unreviewed safety question.

014. DC Motor Surge Suppression, it was Duri.ng installation and testing ofdiscovered that the overload relay (FM 88-49 device) was not of the a con'pensated type. Also, many of the relays showed signs of aging and/or damage.

It is recommended the relay be replaced with a similar type with no change to lts function. In addition, overload her.ters will be replaced to be compatible with i

43

.. -... -... -. _ - - _. +.. - _., _ _ _ _ _ _, _ - -, _ _ _...

- a,

-. - - - - - - - ~ -

Change to the Facility as Described in the FSAR the overload relay. The overload heaters are sized in accordance with NED design guide DC V.55, whleh is based on teethods described in ANSI /IEEE Standard 741-1986 Draft D 5 (6 9 89). The basic criteria is as follows:

1.

When carrying locked rotor current, the overload relay should actuate within the motor's limiting tirne for carrying locked rotor current.

2.

When carrying twice norinal torque current, the. overload relay should actuate within the motor's limiting time for carrying twice normal torque current.

3.

When carrying twice normal torque currer,t, the overload relay should not

)

actuate within the stroke tirne of the valve.

4.

When carrying norninal current, the overload relay should not actuate within the duty cycle tirne of the valve (stroke time X number of strokes to complete intended service).

Voltage variations per calculations and stroke times per applicable periodic tests have been considered when sizing the overload heaters.

Assumptlons and sizing criteria are docurnented in BNP-E.6,032 and BNP E 6.033, DC Valve Overload Relay Heater Sizing (Unit 1). The heaters selected have been sized per DG V.55 and IEEE 741 1986 with the following order of priorities:

1.

Ensure the heater will not interfere with valve operation under the conditions evaluated in the calculation.

2.

Select a heater size which will snaximize motor protection while ineeting Priority l'.

ANSI /IEEE Standard 741 requires that certain vendor information be used in selecting the overload heater for optimum motor operation and protection. Vendor information for motor stall time at locked rotor vas not available at the tiinc the calculations were performed, therefore, an assumption based on industry standards had to be inade for acceptable locked rotor tirne for these motors. The calculation was perforrned to assure operability and with no nuisance tripping of the overload by examination of the de inotor performance curve at twice rated torque.

.This will assure operability of the valve to perform its safety function.

Even if the assumed time the motor can withstand locked rotor-is correct, inotor darnage could occur if actuator failure causes the inotor to stall

. for longer than its stall time rating and the overload heater does not initiate.

However, overload heater sizing to preclude nuisance tripping during normal and i

accident conditions provides the highest assurance the inotor will operate under all-design conditions.

This design ensures the motor will complete its safety function.

Also, prior to operability, the calculation will be reviewed and finalized when motor performance data is received with motor delivery. Because t

the relays are being replaceu and the heaters are sized to 1) ensure valve operability and 2) provide inaximum motor protection, as practicable, accident and equipment malfunction probabilities and/or consequences will not be increased, and no new accident scenarios will be created.

In addition, based on this determination the margin of safety as defined in. the basis of any technical specification will not change. Therefore, this does not constitute an unreviewed 3

safety question.

ALARM RELAY REPIACEMENT AND RE-VIRING DC MOVs currently have no mechanism to de energize the control circuit during a motor overload condition (alarm only).

This Mondition could damage the-motor, valve and/or actuator.

It is recommended that the logic be changed to de-energize the control circuit and still maintain valve indication during overload conditions. In addition to re wiring the spare contact of the "74" relay to de-energize the control circuit (stop valve travel), the relay will be replaced and its normal state in the circuit will be changed. Originally designed the "74" 44 zu a.

Change to the Facility as Described in the PSAR relay was energized when the control circuit was energized (breaker closed). The new design will have the relay normally de-onergized when the cont rol circuit. is energized. This results in energiring the relay during an overload condition, producing an alarm in the Control Room and stopping valve travel. This design elianinates inagnetic trip and loss of control power as causes for an alarm as stated in the annunciator procedures.

In addition, the DC HOV cont rol circuit will be consistent with the AC HOVs. Installation of the "74" relay contact. in the control circuit will create a failure mode scenario different from the present design, llowever, the relay contact which energizes the "74" relay will normally be open (closing on overload only) in what would be termed a f all safethereby reducing any chanc random mode failure. This relay is irstalled mode (failure not preventing safety initiation) and, therefore, is considered not to increase the chat"tes of a failure previously analyzed in the FSAR. Based on this, consequences a accidents previously evaluated in the PSAR, consequences of malfunction of equipment f reportant to safety as well as margins of safety defined in technical specification rescain the same. Therefore, this chaH6e does not constitute an unreviewed safety question.

REMOVAL OF ANTI-PUMPING FROM 1-E51 P022 Presently,1 E51.F022 has an anti pumping feature incorporated in to the closing circuit to prevent a " hammering" ef fect experienced at. several other utilities.

This " hammering" ef fect is a condition in which the valve is closed and continues to receive a closing signal (auto or manual), causing the motor to cycle on and off. When the valve is torqued closed, the torque switch " breaks" the closing circuit causing the motor to stop.

Because certain valve actuators are not equtpped with self-locking gearsets, the torque switch could reclose as a result of the valve relaxing, causing the motor to restart due to the continuous closing signal which is present. This ' hammering" eff ect could cont inue unt il damage to tl.e motor actuator and/or valve occurs. The " hammering" ef fect is only a concern in valve actuators that do not have scif locking gearsets and have a low gear ratio (high speed). Since 1 E51 F022 is equipped with scif locking gear sets and a high gear ratio (slow speed), it is not susceptibic to the " hammering" ef fect and does not require the anti purnping feature. This modification will removo the anti pumping feature from the closing circuit.

Because the operation of this valve has not been changed, accidents evaluated in the PSAR consequences of malfunction of equipment important to safety, as well as margins of safety defined in Technical Specifications, remain the same.

Based on this determination, this change does not constitute an unreviewed safety question.

REMOVE DYNAMIC BRAKING FROM 1 E41-F001 6 1-E41-F006 De energiring the shunt field and armature, when the tuotor stops, simultaneously

- defeats the dynamic braking scheme presently installed on 1 E41 F001 and 1 E41-1 F006. Limitorque has stated that only those valves that travel laster than 24

- in/inin for gate valves and 8 in/ min for globe valves require the dynamic braking.

in addition, valves with SB type actuators provide braking by use of spring packs and do not require dynamic braking.

This feature is currently installed on 1-E41 F001 and 1-E41 F006, plant Modification 89 069 will replace the valve and actuator for these valves with SB type actuators. This modification will remove the dynamic braking feature and associated wiring / components from the circuit.

Since the basic function and operation of the valves has not changed, the probability of occurrence and consequences of an accident previously evaluated-in the FSAR will not increase.

Based on this, the margin of safety as defined in the basis to any technical specification-will not be reduced.

BREAKER / CABLE COORDINATION An additional design review of the DC MOVs indicate that-the shunt field feeder cables of certain HOVs were not properly coordinated with the feeder breaker.

2

. To obtain proper coordination, breaker size can be reduced or cable size can be increased or, in some cases c combination of both. The following is a list of the specific changes:

45 l

-,,-,.,-_,_,-n._,

,-,n.,n4.-..,.n,,...

_...-.,v_.--.~

._,6,-,.-4,..

,,._,.,,n._

.,, -, - ~

Change to the Facility as Described in the FSAR a.

1.E11.F008 shunt field cable increased to w9 AWG b.

1.E41.F001 feeder breaker reduced to 20 amps c.

1.E41 F006 shunt field cable increased to #10 AVO and feeder breaker reduced to 35 amps d.

1.E41.F007 shunt field cable increar.ed to *10 AVG e.

1.E41.F008 feeder breaker reduced to 20 amps

'f.

1.E41.F011 feeder breaker reduced to 15 amps Increating the shunt fleid cable size and/or reducing the feeder breaker size has no effect on the control circuit, but will provide proper breaker / cable coordination. The breaker chan6es listed above will require a change to Figure

8. 3. 2 6 o f the FS AR. Because, the basic function of the valven has not-changed, j

the probability of occurrence and consequences of an accident previously evaluated in the FSAR will not increase. Based on this the snargin of safety as defined in the basis to any technical specification will not be reduced.

I l

.i t

1 1

46

-.. a

--,2_,.

j i

4 l

Change to the Facility as Described in the PSAR

\\

TITLE 1 pH 89 024,_2 E51 F007 Alternate DC Power Supply FUNCTIONAL

SUMMARY

of NRC Ceneric Letter 81 12 recommends that 4'

either HPCI or RCIC be used to provide reactor coolant makeup so as to achieve hot shutdown in a BVR nuclear plant. For a Control Room fire, HpCI powered from 4

Division 1 buses.is assumed to be-lost per the ASCA Seport, Book 1.

Only RCIC powered by Division 11 buses would be available te eaintain the proper reactor o

1 coolant level in the vessel, while the plant is pron eding to either hot or cold shutdown per ASCA Report, Book 1, page 6-11.

The RCIC pumps are driven by steam turbines.

MOV 2-E51 F007 is an isolation valve in the stearn line to the RCIC ra bines and must be open for them to operate.

For a Control Room fire, this valve must be available to prevent uncovering the reactor core since RCIC i

provides the only reactor coolant makeup function.

The problem of the unacceptable spurious closure of MOV 2 E51 F007 due to a control room fire can not be readily corrected by modifications in its existing control circuits thus it was determined that an AC independent power source should supply the Alternate Safe Shutdown (ASSD) feed to the valve.

t This modification provides an AC independent feed to MOV 2 E51-F007. MCC 2XDB,

-Compartment B49 will supply DC power to an inverter from which AC paw w will b2 obtained for the valve. MCC 2XDB is powered by Unit 2 station 2Bl. The inverter

~

converts its 125VDC input to a 480V, 3 phase output so as to supply MOV 2 E$1-F007. The output of the inverter will ro through a now motor starter (C0J) and a new termination box (W6Z) an,1 then be directed to the valve via transfer switch (L61).

3 To make MCC 2XDB, Compartment B49 suitable as a DC power source, it must be modified.

The existing dravout unit complete with the DC starter in that compartment and the door to the compartment must be removed. A new 6" drawout unit will then be installed in the compartment along with a new 40A breaker to be installed in it per this modification. Two blank doors 12" and 18" will then be installed on the front of the remainder of that compartment.

presently the normal feed and ASSD feed from MOV 2 E51.F007 are directed first to a transfer switch (L61) and then to their respective MCC.

To permit reusing the existing cables for the ASSD feed from automatic transfer switch (L61) to MCC 2XD, Compartment DY1, they will be rerouted to a termination box (W6Z) located near MCC 2XD in Unit 2, Rx Bldg at the 20' elevation. As the result of this, MCC 2XD, Compartment DY1 vill be bypassed and thus spared.

New cable and conduit will be installed between the following components:

o Termination box (W6Z) and Motor Starter (C0J) o Motor Starter (C0J) and Inverter (H1K)

Inverter (H1K) and MCC 2XDB, Compartment B49 o

l Existing cable trays will be used for a portion of the run from the inverter to MCC 2XDb, Compartment B49 has to be used as a DC source of supply for.this modification, the existing feed to MOV 2 E11 F023, which is part of Unit 2 RHR head spray, will be permanently disabled electrically. This valve has been under t

clearance for a period of 3 years per EER 86 0275 which required that both Unit 1 and Unit 2 head-spray RHR be disabled.

In addition, Unit 2 RHR head spray is disconnected from its vessel thus this modification just further disables a system which was already disabled by a previous modification.

SAFETY Sl!MMARY: The operation of RPV hes.d spray is not addressed in Chapter 15 of the FSAR.

No credit is taken for it in either preventing or mitigating an accident. Unit. 2 RPV head spray was deactivated by EER 86 0275 by placing valves 2 E11 F022 and 2-E11-F023 in the closed position and placing their motor starters under clearance. In addition, Unit 2 RpV Head Spray Line was disconnected from l

47

g Change to the Facility as Described in the PSAR the vessel head and capped per a recent plant is,dification. Thus, electrically disabling Unit 2 RPV head spray will not increase either the possibility or consequences of an accident.

The ASSD feed to valve 2 E51 F007 is required only to operate during an Appendix R fire and no credit is taken for it in either preventing or mitigating the consequences of a Chapter 15 accident.

The normal feed to valve 2 E51-F007 is isolated from the alternate feed at the qualified automatic transfer switch (Node L61). Thus, the normal feed will not he affected by the new ASSD feed.

}

Neither the probability of occurrence or consequences of an equipment malfunction is increased by further electrically disabling Unit 2 RPV head sprag since EER-l 86 0275 stated it was not required for the safe operation of Unit..

RPV head spray has no safety function and no credit is taken for it in initigating the effects of a Chapter 13 accident. Its only function was to perinit more rapid cooldown of the reactor vessel so as to reduce outage time.

Since it is a low flow system, RPV head spray cannot be rolled upon for emergency makeup water to the reactor vessel.

The system was designed to supply 625 GPM to the vessel

+

steam dome through the head spray nozzle at <129 PSIG reactor pressure. It was y

designed to maintain saturated conditions in the vessel by condensing steam generated in it. This permits the water level in the vessel to rise enabling the RPV head to cooldown in parallel with the rest of the rnetal below the water line.

- During actual plant operation, head cooldown has not been on the critical path.

Consequently there has been very little incentive for the use of the RPV head spray system.

The contribution of RPV head spray to the - low pressure makeup water system that provides cooling for the vessel is insignificant in comparison with that of either LPCI or core spray. LPC1 alone can deliver up to 34000 CPM to the vensel whereas RPV head spray can deliver only 600 to 700 CPM. RPV head spray diverts water frorn the LPCI system which is more effective in cooling the core because its flow is directed to the lower vessel plenum.

In any severe accident, RPV iiead spray injection valves automatically -close elitninating any flow from that system to the vessel.

In addition, it has been determined that

- RPV head spray may increase thermal duty on vessel head by promoting too rapid of a cooldown.

Therefore, disabling of the RPV head spray will not increase either the probability or consequences of damage to either the RPV ves:;e1 or fuel assemblies.

The-ASSD -feed to valve 2-E51 F007 performs-a non safety related function.

One Q interface boundary for the new ASSD feed will be at the feeder breaker in MCC 2XDB, Compartment B49. Since the breaker is qualified for operation in class 1E circuits, any faults in the non-Q circuit will not affect the MCC or any Q listed circuits because the breaker will trip and isolate downstrearn faults. The other Q interface boundary for the ASSD feed is at the transfer switch (Node L61) but has not been physically altered in this modification.

Since Unit 2 RPV head spray was not required for the safe operation of Unit 2 per EER 86 0275, further disabling it will not create a new type of accident.

Since RPV head spray is a very low flow systern, the emergency makeup water function provided by this system can also be provided by increasing the flow rate of the LPCI system. The cooling provided by this system during the shutdown of the reactor is not a safety function but is used only to reduce the duration of an outage. Presently at BSEP the system is~ not in use. Further disabling this system will not create a different type of accident than previously analyzed.

- The installation of the new DC breaker into MCC 2XDB will not affect the safe operation of the MCC.

In addition NED calculation BNP-E 6.003, Rev.

O, demonstrates that buses upstream will not be affected because of the coordination-between protective devices.

48

Change to the Facility as Described in the FSAR Disabling of the RPV head spray will not reduce the margin of safety as defined in the basis of the Technical Specification since it is not required'for the safe operation of Unit 1 per EER 86 0275.

In EER 86-0275, Mr. Gary Jozzi, G.E.

Manager-Applications Engineering, was quoted as saying that RPV head spray is not.

a safety system.

NRC Report No. 50 325/88 40 further confirms that RPV head spray is not a safety system.

Since RPV head spray does not perform a safety related function directly, the only way it could reduce the margin of safety as defined in the technical specifications is by interfering with the operation of another safety system. As stated previously, disabling of RPV head spray does not reduce the reliability of either the LPCI system or core spray syst ern in performing their intended safety functions.

Either LCPI or core spray can prc. vide shutdown cooling for the vessel without any assistance from kPV head spray. Thus, disabling RPV head spray does not reduce the margin of safety as defined in the basis of the technical specification.

Resupplying the ASSD feed from a batter:r backed source improves its reliability but does not change its function. The ASSD feed is a non-Q circuit only required to operate for an Appendix R fire and does not affect any safety related systern except the Unit 2 Battery 2B-1 and the specific DC buses.

Any fault in the alternate feed will be Isolated from MCC 2XDB by the new DC breaker.

The Appendix R BSEP DC load study was reviewed with the end result being that adequate margin exists in the Linit 2 battery 2B 1 for operation of the alternate feed.

l i

l l

l I

l 49

i i

Change to the Pacility as Described in the PSAR TITLE:

PM 89 035. Unit 1 ARTS RBM Instrutnentation Modification PM 89 036, Unis 2 ARTS RBM Instrumentation Modification FUNCTIONAL SlHMARY: Tne APRM RBM Technical Specification (ARTS) modifications are an integral part of the Maximum Extended Operating Dornain (MEODj prograin.

The MEOD is an extended power / flow envelope that permits Brunswick operation at

- rated power over a wide range of core flow (75 to 105 percent of rated). ARTS consists of the Technical Specification and hardware changes necessary to permit operation within parts of the extended load line limit which might otherwise be The ARTS program helps to Brunswick the

{

capability to maneuver within a larger power / flow region, providethereby significantly blocked by the RBM system.

I improving plant operating economics.

The ARTS modification requires changes to the APRM and RBM systems. Modification of the APRM system consists of setpoint changes which will be accomplished by a recalibration of the APRM channels. An APRM card replacement adds an adjustable clamp circuit to the APRM flow bias rod block trip reference level over the 30%

to 125% power level ranre Modification of the RBM system requires replacement of four printed circuit bo.ards and the addition of two new circuit boards in each RBM channel.

The RBM channels will be removed from the H12-P608 panel to facilitate completion of approximately l'io internal wiring changes per channel.

Additionally, eight conductors will be installed between the A and B channel bays of Panel H12 P608.

Improvements to the APRM System include APRM trip setdown climination.

An alternative to setting down APRM trips is to monitor thermal margins (CPR) to ensure that any increased transient ef fects are offset by larger initial margins.

Ptoliminary transient evaluations have shown that the APRM trip setdown Technical Specification can be eliminated.

The. required power and flow dependent MCPR and fuel heat flux requirements are well within tne expected performance capability of the plant, and no increased core' operational effort is anticipated The APRM trip setdown elimination requires reevaluation of the Maximwn Average Planar Linear Heat Generation Rate (MAPillCR) multi This is because previous analyses of MAPlJICR multipliers at less than pliers.

rated flow conditions were based on the assumption that the setdown APRM rod block trip limits core peak Linear Heat Generation Rate (1JICR) to flow dependent values.

An improved and simpler RBM system is created by this change.

Low margins at high power imply low REM setpoints are required, while large margins at low power imply high RBM setpoints would be acceptable. Based on this observation, a more direct trip logic is designed to remove the current limitations of the RBM syatem. Drive flow dependence of the trip level is replaced by a power dependent trip level expressed relative to an arbitrary signal source icyc1 to which the RBM channels are calibrated. APRM provides the input power signal from which the trip level is automatically selected.

RBM trip level-will vary as step functions of core power.

This will allow longer withdrawals at high power.

These trip levels will be based on a power dependent MCPR specification and a statistically based rod withdrawal error analysis.

Advances in electronics have made it possible to efficiently specify system performance requirements which were not possibic in the mid-1960's ARTS takes advantage of these advances to make changes in the RBM hardware which controls the trip logic and LPRM averaging to enhance the signal to thermal :nnrgin correlation.

Further improvements in the capability of the RBM to perform its intended function of assisting the operator in safe operation of the plant are obtained by improving the methodology used to determine the required trip setpoints 50

~,.,, _ - - - -,,

... ~ - - - _. -. - _.

-_. - -..- - - ~ _ - _ _- - - -... -.

i Change to the Facility as Described in the FSAR The changes which ARTS will make to t!w RBM system are expected to:

imposed on core wer by the current Eliminate the restrictions flow biasea RBM trips..(This function wikrossi be fulfilled by the APRM flow.

biased rod block);

Enhance operator confidence in the system by reducing the frequency of nonessential - rod blocks and by making occurrence of rod blocks more predictable and therefore avoidable; and 1

Upgrade the performance-of the system such that the Rod Withdrawal Error will never be the limiting transient.

Other changes to the LPRM/RBM system include; 1)

Optimum LPRM assignment Studies have also indicated that reassignment of the B, C, and D level in.

. core LPRM detectors to each RBH channel gives an enhanced RBM response with no significant impact on RBM system availability.

Thirteen alternatives to-the current LPRM assignment were studied.

No single alternative was found to be best in all areas but the new assignment scheme is the best compromise to achieve the following objectives; Similarity of' channel response o

liigh response to rod motion (allows higher setpoints which reduces the o

effect of random signal noise, calibration inaccuracies, and instrument drift)

Low MCPR limits with high setpoints o

liigh availability (tolerance of LPRM failures) o Ease of implementation o

All changes above can be accomplished by minor changes to existing electronics.

2)

RBM Signal Filter An adjustable parameter filter is also added to reduce unnecessary RBM rod blocks caused by neutron noise, The filter tira constant can be adtusted such that it can effectively be deleted or optimized for plant's characteristic noise properties. RBM setpoints will be provided for the full range of signal filter adjustments.

3)

Relaxed Bypass Requiretaants Further advantage can be made of the statistically based analysis to define an MCPR value above which no single Rod Withdrawal Error (RWE) could violate fuel safety limits. Operation could then be allowed without RBM restrictions when operating margins exceed this value. This would be particularly useful during rod sequence exchange maneuvers when many control' rods are moved and margins are high.

Speeding up sequence exchanges can increase unit capacity _ factor.

RBM surveillance L

requirements could also be reduced.

E In summary, the new RBM system is more easily understood, possesses predictable behavior, and will limit the thermal margin reduction during rod withdrawals, but will not restrict rod withdrawals on the basis of gross core power level. Limitations on gross power levels are now imposed 51 m

c..er

--M,..

4

m. w..'E.r.-

..,y,m.

,. <. y h y

_.en,--w-,.,_.r-m

,,.,n y,mn.<-,-e.y-,.y-,--ye-e-.

, ~. ~.,

f-

t f

Change to the Facility as Described in the FSAR by the safety grade-APRM flow biased rod block; this system will remain unchanged.

These RBM modifications, along with the chs7ge in APRM flow biasing slope to 0.58, allow attaining the ideal start up path.

In summary, RBM rod blocks can virtually be eliminated.

New cycle-independent RBM setpoints allow an operating MCPR as low as 1.20 for rod withdrawal error.

APRM setdown can be elianinated.

Thermal margin Technical Spucificatiot.s will be refined to increase operating margins by allowing operations significantly above the design total peaking factor without the APRM trip setdown.

SAFETY

SUMMARY

Power-and flow dependent adjustments to the Average Planar Linear Heat Generation Rate (APUICP) and Minimum Critical Power Ratio (MCPR) operating limit values will maintain existing margins between the operating limit and the safety limit.

The change identifies that adjustments to the MCPR and APulGR limits as specified in the Core Operating Limits Report will be made as functions of core flow and power.

These adjustments as specified in the Core Operating Litnits Report are determined using NRC approved methods as required by Technical Specification 6.9.3.2.

The adjustments impose restrictive conditions on plant operation such that the consequences of anticipated operation occurrences are no more severe than the most limiting condition with the current Technical Specification with flow biased APRM scrata anc rod block setpoint setdown provisions.

The RBM system is not involved in the initiation of-any accident and does not increase the probability of the occurrence of any accident. The RBM system only serves to mitigate the consequences of one event; the Rod Withdrawal Error (RWE) anticipated operational occurrence.

Analysis of the RWE were performed using NRC approved methods for the modified setpoints.

The results demonstrate that the consequences of the RWE event are no more severe with the modified RBM system than with the current configuration.

The change expands the power and flow operating domain by relaxing the restrictions imposed by t.he formulation of the flow-biased APRM rod block and scram trip setpoints.

The. probability of any accident is not significantly increased by operating at a higher power at. a lower core flow because the formulation of the flow biased APkM rod block trip equation has been modified to provide the protection similar to that which currently exists. The consequences of anticipated operational occurrences have been evaluated using NRC approved methods and the proposed setpoint formulations have been selected so as not to involve a significant increase in the consequences of-any-accident.

The probability of occurrence of malfunction of equipment to safety previously evaluated in the FSAR will not be increased. The bases are as follows:

Operation at higher-than-rated core flows can increase the pressure differences imposed on the reactor internals. A reactor internal pressure difference analysis was performed to determine-the increase associated with the Increased Core Flow (ICF) operation.

The pressure differences cross the reactor internals were generated with the ICF conditions at and faulted conditions.

Based on the normal, upset, emergency, d that s conclude the stresses produced in the reactor evaluations, it i internal components and fuel assemblies and channels are acceptable for operation along the ICF boundary.

An increased core flow vibration analysis was perfornad by analyzing the startup test vibration data for Brunswick and its valid prototype plant (FitzPatrick).

Based on the results of the analysis and a review of the test data.-the reactor internals response to flow-induced vibration is expected to be-within acceptable limits for plant operation in the ICP region.

52

=

i e

e=-+

e+#-+,-

,m-4s-g w

iyw

-y---g--4 w

w-

-**+ep p-r 1

t'-

'*T-'

~. _.

~.. _ _

i Chonge to the Facility as Described in the FSAR

- This modification does reduce the degree of redundancy and separation between RBM channels; however, the RBM system is non safety haring of the related. The impact on the availability of the new RBM r ' stem due to the s "C" level detectors -has been shown to be small and the benefits of the improved signa 1' response are significant.

Changes in the operating limit values will maintain existing margins between the operatins limit and safety limit.

Operstion within the operating limit will en mre that the consequences of any accident which could occur would bc within acceptable lim! ts.

The adjustments n.ade by the modification impose restrictivo conditions on plant operatfor, such that the consequences of anticipated cperational occurrences are no more severe than the most limiting condition within the current Technical Specifications vitl flow biased APRM scram and rod block setpoint setdown conditions.

Expansioa of the power / flow map can lead to an increase in the acoustic and flow-induced loads (associated with propagation of a decompression wave caused by a recirculation line break) on the vessel internal components. The impact on the components was evaluated throughout the Maximum Extended Load Line Limit (MELLL) region. The analysis uncluded that ths Brunswick components have enough design margin to handle the increased loading.

The changes are designed primarily for plant startup, and. lo not affect the safe shurdown of the plant.

The replacement equipment is of a quality equal to or t

better than the equipment currently in place.

The replaceaent equipment and changas will not increase the consequences of malfunction o'. equipment.

This modification does reduce the degree of redundancy and separation between RBM channels; however, the RBM system is - non safety-related.

The impact on the availability of the new RBM system due to the sharing of the "C" level detectors has shown to be small and the benefits of the improved signal response are significant.

The change eliminates the requirements for setdown of the flow-biased APRM scram and rod block trip setpoints under specified conditions and operating limits.

The MCPR and AP1JICR operating limits are defined such that no postulated transient svent, if= initiated from other than rated power and flow conditions, could result in violation of either the safety limit MCPR or fuel thermal-mechanical design bases.

Modification of the flow bias, sPRM scram and rod block equations to accommodate an expanded operating domain not change their respective functions.

The APRM rod block trip setpoint.

continue to block control rod withdrawal when core power significantly exc a desi n bases and approaches scr m level.

The 6

APRM scram trip setpoint w!!

continue to initiate a rod block wetpoint.

"he change does not alter the funct'on of any component or system other than the RBM system.

The changes to the RBM system are designed to enhance the impacting the de of reliability and accuracy of-the RBM system without isolation of the RBM system from other plant systems.

The function of.greethe RBM system does not ( hange.

The margin of safety as defined in the basis of any technical specification will not be reduced. The bases are as follows:

l The flow and power adjustment factors were determined using NRC-approved i

methods and satisfy the same NRC approved criteria met by analyses assuming setdown of the flow-biased APRM scram and rod block setpoints.

The flow-biased:APRM rod block and scram trip setpoints will continue to perform their respective functions.

l 53 l

L h

- ~_.-

3 4.

Change to the Facility as Described in the FSAR

- 'rha = change revises the setpoints for the RBM - system which is sole".y dusignad to mitigate the consequences-of-the RWE anticipated operational setpoints.

Analyses of the RWE-event are ured to derive the setpoints such that the safety limit for the Minimum Critical Power Ratio (MCPR) will.not be challenged assuming the initial MCPR was no less than the operating limit MCPR.

These setpoints are therefore dependent upon the operating limit MCPR.

For this reason,-the change also identifies that these setpoints are specified in the Core Operating Limits Report.

The Core Operating Limits Report is prepared based on the results of NRC approved methods as required by Technical Specification. 6.9.3.2.

The setpoints reported in the Core Operating Limits Report are derived such that the RWE event -- is not the most limiting event in determining the operating limit MCPR.

The operating limit MCPR maintale the 'nargin of safety for this thermal limit.

Thus, the change does.to t involve a significant reduction in the margin of safety.

54

Change to the Facility as Described in the FSAR TITLE:

PM 89 038, Unit 2 Replacement of Reactor Coolant Recirculation System Inlet Safe Ends and Riser Piping PM 89 095, Unit 1 Replacement of Reactor Coolant Recirculation System Inlet Safe-Ends and Riser Piping FUNCTIONAL SUM'iARY: Plant Modification 89-038 was implemented to remove flawed material and to mitigate future intergranular stress corrosion cracking (ICSCC) in portiona of the Reactor Coolant Recirculation (RCR) system by replacine existing cracked discharge risers, inlet safe ends and N2 nozzles cladding witU materials more suited for a BWR reactor coolant environment.

Secondary design changes include electropolishing and preoxidation of the inside surf aces of the replacement components to deter reactivation of the components in service.

The RCR system piping configuration essentially remains unchanged as a result of this change. However a few minor details changed and are discussed below.

I The total number of weld joints has been reduced.

This vill be accomplished by using induction bent discharge risers in lieu of welded elbows.

A decrease in total number of welds is a design improvement since welded joints (including heat af fected zones) are more susceptible to ICSCC than other areas in non-sensitized austenitic stainless steel and Inconel piping systems.

Therefore this change improves long term reliability of the RCR system.

Additionally, the replacement risers are seamless, eliminating the longitudinal weld seams on the existing risers.

The replacement safe-ends were redesigned to include an integrally attached thermal sleeve extension and to smoothly blend the " tuning fork" area to imp. ave the stress profile in that region.

The new design eliminates the sharp crevice in the " tuning fork" annular region. Tightly creviced regions have been demonstrated to increase the potential for stress corrosion cracking, The new safe end configuration decreases the chances of IGSCC initiation and improves component and system reliability. The design function of the safe-end has not changed.

The existing RCR system discharge risers have differential pressure ins t rtunent taps which were cut, capped and abandoned in place by a previous plant modification.

The replacement risers do not include instrument taps, however this dces not degrade RCR systen design or function since the existing taps are abandoned and are not described in the FSAR.

Additionally, removal of the taps will eliminate the possibility of a small bore line Icak caused by failure of the abandoned pipe stubs or caps This change also affected the materials used in the Recirculation piping system.

Material changes from type 304 stainless steel and Inconel 600 to type 'll6 NG stainless steel for the risers, safe ends and extensions, and INCONEL 82,182 to type 308L stainless steel for the nozzle cladding and weld metal on a design upgrade based on exhaustive industry study and development.

Use of the new materials ensure the structural integrity of the RCE system schile improving corrosion resistance.

SAFETY

SUMMARY

This change does not change the RCR system function or operaticc characteristics and the replacement piping / components meets or exceeds originaY design criteria.

In addition, replacement materials are more suited for a BWR reactor coolant environment and represent a significant deterrent to the 55

Change to the Facility as Described in the PSAR 1.

ation and growth of ICSCC. Therefore, long term structural inter,rity and re!.

ility of the RCR system will be improved.

Based on the above considerations the probability of occurrence or consequences of any accident or malfunction of equipment important to safety previously evaluated in the FSAR is not increased. Additionally, these changes do not affect the margin of safety as defined in the bases to any technical specification.

l 56

~-. - - - -..-. ~

Change to the Facility as Described in the FSAR t

TITLE:

PM 89 059. Unit 2 Weld Overlay PM 89 094, Unit 1 Weld Overlay and RilR Valve Machining-FUNCTIONAL SUFMARY:

The modification to the RHR valves X E11-F060A and X-Ell-F060B was performed to fulfill a CP&L commitment to the NRC to address the inspectability of weld joints X-B32 RDXB2 84-WB33 and X B32 RDXA2-87 WA33.

This alteration was evaluated by Structural Integrity and Associates. in accordance with rules of ' ASME Ill, Subsection NB, 1986 Edition and it was i

verified that all design criteria has been satisfied following the completion of the machining. Long term strue' ural integrity and reliability of the RCR and RilR systems has not been degraded,. Reliability of the systems la increased due to the ability to inspect the joints.

SAFETY

SUMMARY

This plant modification addressed reworking, by machining, the RHR valves X E11-F060A and F060B to facilitate UT inspection of weld joints XB32-RDXB2 84 WB33 and XB32 RDXA2-87-WA33 (this is the recire tee to valve weld).

This involved machining the valve body to a configuration that allows the joint to be inspected 360 degrees.from the valve side of the weld joint. The complete circumference of the joint could not be previously inspected. This change does not affect any system operation derign parameters-and consequent 1v the probability of occurrence or consequences of any accident previously evaluated or of any other type not evaluated in the FSAR is not increased.

[..

57

~ _ - -

Change-to the Facility as Described in the FSAR TITLE:

PM 89 071 RCIC 1 E51-F007, F008, and F013 Valve Replacement FUNCTIONAL

SUMMARY

Plant Modification 89 071 replaces RCIC Turbine Steam Supply i

Valves 1-E51 F007 and 1-E51-F008 and the RCIC Pump Discharge Valve 1-E51 F013 with new parallel disc gate valves.

The existing valves are flex wedge gate valvese Flex wedge - gate valves are susceptible to thermal binding when

- attempting to open the valves in the cold condition af ter having closed them in the hot condition. The thermal binding effect can be greet enough to prevent any opening of the valve by the valve operator until the valve temperature is sufficiently raised again. The parallel disc gate valves chosen as replacement valves are not subject to thermal binding due to the design of the double-disc / stem interface.

Therefore, the valves are capable of operation when required under various temperature conditions.

Both the flex wedge and parallel disc gate valves can be subject to " pressure locking". This occurs when fluid trapped between the valve seats and the bonnet cavity of the closed valve heats up, causing the pressure to increase, and thereby increasing the seating force on the valve dise(s).

The valve actuator then might not.be able to overcome the increased seating force without a bonnet pressure equalization desi6n.

For valves 1-E51 F007 and 1-E51 F008, this equalization will consist of a small diameter pipe routed from the between-seats area of each valve towards the Reactor Vessel side of the valve. Valve 1-E51-F013 will have a hole drilled in its downstream disc. Any potential for pressure buildup between the seats is therefore eliminated, thus preventing the " pressure lock" phenomenon. The pressure squalization piping will also include a double-valved ISI test connection to permit local leak rate testing (LLRT) of valves 1-E51-F007 and 1-E51 F008. Valve 1-E51-F013 will not be equipped with external Is1 test connections.

The new valves also will utilize a live load packing design. -The live-load packing will reduce the number of packing problems and adjustments required for packing leakage.

This modification also replaces the DC motor on valves 1-E51-F008 and 1-E51-F013.

' The motor circuit configuration for the DC motor has shunt winding continuously energized.

This creates a higher motor internal temperature than originally designed and significantly shortens the motor life.

The level of motor i

degradation cannot be determined; therefore, a new replacement motor (same f t.-

lb. size motor as the existing motor) will be installed to ensure motor reliability.

A design change to eliminate the continuous shunt energization problem is being addressed by Plant Modification 89-107.

l An emergency trudification (89-053) installed a new valve two feet upstream of 1-I E51-F013 to function as 1-E51-F013 with the old valve retagged 1-E51-V100 and locked open.

This modification will restore the original configuration and remove 1-E51-V100 from the system.

The replacement motor for 1-E51-F013 has been ordered and furnished with a six duty cycle per hour rating instead of a standard three duty cycle, SAFETY

SUMMARY

The substitution of new valves for existing Valves 1-E51-F007, l

1-E51-F008, and 1-E51-F013 requires a review of the ways in which the new valves might adversely impact the safety. function of the valves.

-The " essential" function of these valves is to stay (open (1-E51-F007 AND 1-E51-F008) to keep the steam supply lines warm or to open 1-E51-F013) to provide inflow to the reactor vessel to cool and cover the core.

related" function of these valves.

The "safetyhe valves must close when required l-

' s to provide primary containment is,1ation.

i T

and must remain closed.

Any charp which makes closure of the valves more-difficult or which decreases the sealing capability of the valves is potentially unacceptable.

I If the parallel disc gate valves were to require more torque to close than the 58

Change to the Facility as Described in the FSAR existing flex wedge gate valves, the possibility of unacceptable actuator operation could result (i.e., the actuator may not be sufficient to close the valse). However, based on a review of the vendor reports on the existing and new valves, the replacement parallel disc gate valves actually require less torque Company Valve Report Numbero R88.138, R88.097, R88.108, R89.054 and R8Y. Valve to seat / unseat the disc than the flex wedge gate valves (Anchor Darline 052).

Thus, existing valve actuators are sufficient to operate the valves.

Response time will be verified after valve installation by the performance of Periodic Test (PT) 10.1.1, which verifies valve stroke time in both the closing and opening directions for Valve 1.E51 F013 and in the closing direction only for Valves 1 E31-F007 and -F008.

Valve leak tightness is also important.

The flex wedge gate valves were originally specified partially because of their good sealing characteristics, particularly under adverse conditions of valve body / seat distortion.

The parallel disc gate valves must seat equally as well or risk failure to meet containment isolation leakage criteria.

The ded gn of the parallel disc gate valves ensures this capability. The use of a " rocker" type interface between the two discs provides sealing capability under normal and adverse conditions equivalent to the flex wedge design. As with valve operating times, seat leakage will be verified to be within acceptable limits by performance of a periodic test.

The specific tests in this case will be PT 20.3, Tests Numbers 156 and 165.

The new valves will be installed with live load packing. Unacceptable packing installation or overtightening of the packing gland will cause excessive packing friction which can cause binding of the valve stem, potentially resulting in excessive valve closure time or incomplete valve closure.

Live load packing eliminates these concerns by applying a uniform packing loading controlled by a Belleville washer. The proper packing load is automatically maintained by the Belleville washer during both expansion or compression of the packing. Also, the packing load is uniformly applied around the stem, eliminating the possibility of uneven tightening of the packing gland nuts. Therefore, closing of the valve will not be impacted adversely by the installation of live load packing.

The major benefit to be derived from the new valves relates to valve performance in the opening direction, not the closing direction.

The parallel disc gate valves provide more assurance of the valve being able to open as a result of the reduced opening torque required (due to the rocker-type interface between the discs) and the lack of susceptibility to thermal binding.

Valve 1-E51-F013 c1carly will benefit from this modification, since it is normally closed and it must open automatically to provide its essential function of maintaining sufficient coolant in the reactor vessel to prevent overheating of the reactor fuel in the event of reactor isolation accompanied by loss of feedwater flow.

The specific features of the parallel disc gate valves which provide more reliable valve opening are reduced opening torque necessary due to the rocker type interface between the discs and lack of susceptibility to thermal binding.

In addition, the bonnet pressure equalization piping eliminates the potential for bonnet overpressurization, which could prevent the valve from opening.

Replacement of the DC motors for 1-E51-F008 and 1-E51-F013 does not create an unreviewed safety question.

The motors' electrical and mechanical characteristics will not change, nor will they impact the plant's electrical distribution system.

Proper motor installation and valve operation will be verified by acceptance testing specified in this modification package.

Safety considerations associated with the shunt energization changes will be addressed by Plant Modification 88-014. The UFSAR section describing the RCIC system does not address the specific construction of the valves (flex wedge versus parallel disc) nor does it describe the particular procedure for Local Leak Rate Testing (LLRT). Re-rating of 1-E51-F013 motor to six duty cycles per hour by the vendor 59

i Change to the Facility as De.cribed in the FSAR does not constitute a physical / hardware change.

This modification installs a 3/4" bypass line around the upstrea n disc for valves 1-E51-F007 and -F008.

This bypass line has a normally open, manually operated valve (pressure equalization valve) and a 3/4" tee with a 3/4" LLRT test line.

The ISI test line has double isolation valves. The pressure equalization valve can be closed and the double isolation valves opened to allow for a "between the seats" LLRT on these valves.

The 3/4" lines and valves are ASME Section Ill, Class 1 components.

The test Valves 1 E51-V104 and V105 are not expected to fail, but even if they did fail on 1-E51-F008, the redundant inboard containment isolation valves would prevent any leakage into the Reactor Building environment. The redundant valve is 1-E51-F0D7 and 1-E51-F008. ISI test valve failure on Valve 1-E51-F006 would result in a small amount of steam

c. idensate discharge into the rimary containment atmosphere which occurrence would be bounded by other ana$ysis such as LOCA, MSLB, and HELB. Therefore, these lines would not introduce a new mode of failure not previously analyzed in the FSAR.

The inboard valves on the new 3/4" lines are manually operated and normally closed. Only one valve, the inboard ISI test valve 1-E51-V104 (valve -F008) can be considered as a contaitunent isolation valve. Being an ISI test valve, 1-E51-to 10CFR50 A pendix J. Type "C",

tests, but it is required V104 is not subject i

to be checked periodically to meet the surveillance requirement of Technical Specification 4.6.1.1.a.

This concurs with the Standard Review Plant Section 6.2.6 on Contaitment Leakage Testing, which states, ".. the test, vent and drain connections that are used to facilitate local leak testing and the performance of the contaitunent integrated leak rate test should be under administrative control, and should be subject to periodic surveillance to assure their integrity and verify the effectiveness of administrative control."

60

Change to the Facility as Described in the FSAR TITLE:

PM 89-092, Replacement of Core Spray System Safe-Ends - Unit 1 FUNCTIONAL

SUMMARY

This change has been implemented to remove existing flawed material and to mitigate future intergranular stress corrosion cracking (ICSCC) in portions of the Core Spray system by replacing existing cracked safe ends and N5 nozzle cladding with materials more suited for a BWR reactor coolant environment. Secondary design changes include electropolishing and preoxidation of the inside surfaces of the replacement safe ends to deter reactivation of the components in service.

The Core Spray system piping configuration remains essentially unchanged as a result of this change, except for minor changes in the connection between the safe-end and thermal sleeve.

The existing Core Spray safe-ends are connected to their respective thermal sleeve by a tight friction fit. This design could have had up to 100 gpm bypass leakage during Core Spray system actuation.

The replacement safe-ends connect to the existing thermal sleeves by full penetration butt welds, thereby eliminating bypass leakage.

The cyisting Core Spray safe-ends were Type 316L stainless steel and have been replaced with Type 316NC stainless steel safe-ends. Type 316MG SS has been shown to be more resistant to intergranular stress corrosion cracking (IGSCC) than Type 316L SS in BWR reactor c,olant environments.

Type 316NG (Nuclear Grade) stainless steel was developed specifically in response to ICSCC problems in the nuclear industry.

The primary deterrent to ICSCC is an extremely low carbon content (0.02% maximum) and tight control of impurities.

The minimum required tensile strength, yield strength and ASME Code allowables are identical for 316NC and 316L stainless steels. The Inconel cladding on the Core Spray nozzles has been shown to be susceptible to ICSCC and have been replaced with Type 309L stainless steel weld metal with a controlled delta ferrita content. The 309L weld metal is more resistant than Inconel to ICSCC in BWR reactor coolant environments.

The coefficient of thermal expansion is higher for 308L and 309L stainless steel weld metals than for Inconel 82 and 182 weld metals and will lead to slightly higher pipe displacements, and therefore stresses, at service temperatures.

However these changes are negligible because of the very small weld metal volume.

A carbon steel " transition piece" forging replaces a portion of the existing carbon steel piping on each Core Spray loop.

The mechanical properties of the transition piece are similar to those of the existing piping and have been considered in the piping stress analysis reconciliation.

In summary, the material changes implemented by PM 89-092 are a design improvement. The structural integrity of the Core St ray system is not degraded and the improved corrosion resistance of the new materials improves long term system reliability.

Three special processes utilized during the implementation of this change 1).

Electropolishing of piping 2).

Preoxidation of piping 3).

Mechanical Stress Improvement Process (MSIP) implementation on stainless steel welds The MSIP process have been previously analyzed and determined to not represent an unreviewed safety question.

61

Change to the Facility as Described in the FSAR The electropolishing process uses an electrochemical reaction to remove typically 2-3 mils of material from piping inner surfaces, taking advantage of field gradient enhancement at surface roughnesses to preferentially attack high spots en the surface.

This rocess reduces the true, as opposed to the projected, surface atea of the p pe and reduces the rate of reactivation of the pipe surfaces. The loss of

-3 mils wall thickness will be verified not to encroach on minimum code-required wall thickness, thus structural integrity of the piping / components will not be compromised. In addition, post process rinses and inspections assure that no activa corrosion agents remain on the pipe surfaces.

This process is performed under shop conditions, prior to field installation.

Preoxidation is another shop process, performed af ter electropolishing, where hot (approximately 550' F),

moist, filtered air is circulated through the piping / components for approximately 160 hours0.00185 days <br />0.0444 hours <br />2.645503e-4 weeks <br />6.088e-5 months <br />. The effect of preoxidation is to condition the piping / component inner surface with a passive oxide film which retards future buildup of contamination (relative to a similar untreated surface). The oxide layer is completely passive and does not increase assumed corrosion rates nor impact mechanical properties of the plping/ component substrate.

Electropolishing and preoxidation are consistent with the BSEP commitment to NRC Regulatory Guide 8.8 and ALARA.

SAFETY

SUMMARY

This change does not change the Core Spray system function or operating characteristics and the replacement components meet or exceed original design criteria.

In addition, replacement materials are more suited f or a WR reactor coolant environment and represent a significant deterrent to the initiation and growth of ICSCC. Therefore, long term structural integrity and reliability of the Core Spray system are improved.

Additionally, the electropolishing and preoxidation processes will not detrimentally impset the structural integrity of the piping / components and will deter buildup of activated films, thus providing an ALARA benefit.

Based on the above considerations the probability of occurrence or consequences of any accident or malfunction of equipment important t.a safety previously evaluated or of a dif ferent type than previously evaluated in the FSAR is not increased. Additionally, these changes do not affect the margin of safety as defined in the bases to any technical specification.

62

a j

Change to the Facility as Described in the FSAR

-TITLE:

PM 89-103, Unit 1 S8GT/ Secondary Containment Auto Initiation Logic Change

~ FUNCTIONAL

SUMMARY

Brunswick Technical Specification state that Reactor Low Water Level No. 2 or High Drywell Pressure will provide a signal for Secondary Containment-Isolation.

These signals previously did not initiate a Secondary Containment Isolation directly but instead auto started Standby Cas Train (SBGT) and used the same SBGT circuits to initiate Secondary Containment. - This created a potential Single Point of Failure for Secondary Containment Isolation.

This change provided a path for these signals independently for both SBCT initiation and Secondary Containment isolation. The modification removed the "B" relay from both divisions of the SBGT starter circuitry. The K66 (Div I) and K67 (Div II) relays (each relay provides both the Reactor Low Level No. 2 and Drywell High Pressure signals) controlled the "B"

relays. The K66 and K67 relays were terminated in series with the K82 relays (Reactor Building Exhaust High Radiation signals).

A Reactor Vessel Low Level Drywell High Pressure, and Reactor-Building High Radir. tion signal will control the "A"

relay of the associated division.

The "A"

relay for each division of the SBGT starter circuitry will now provide its normal function of Secondary Containment Isolation

and SBGT Auto-Start by trip signals from not only the K82 but also the K66 or K67 relays. This change ensures that upon a trip signal from the K66 or K67 relays i

the - respective division of the Reactor Building Supply and Exhaust Dampers isolate independent..of the SBGT Starter Circuit Power Supply.

SAFETY

SUMMARY

The probability of occurrence of any accident previously evaluated in the FSAR will not be increased. The accidents evaluated in the FSAR which related to the SBGT or Secondary Containment are the Refueling accident and the LOCA.

The analysis to determine the consequences of a worst postulated Refueling accident (dropping a fuel assembly) and mitigation of the effects of a LOCA are based on Secondary Containment Isolation / SBGT functioning 1.roperly and being initiated as designed. Relying on the "A" relay for a trip signal-to either division of the SBGT Starter Circuitry will not increase the vulnerability for failure of the SBCT or Secondary Containment Isolation function or initiation as designed.

Therefore, the probability of these accidents occurring can not be increased by 1

this modification.

The consequences of any cecident previously evaluated in the FSAR will not be increased.

The analysis to determine the consequences of a worst postulated Refueling accident (dropping a fuel assembly) and mitigation of the effects of a LOCA are based on Secondary Containment Isolation /SBGT functioning properly and being initiated as designed.

Relying on the "A"-Relay for a trip signal to either division of the SBGT Starter Circuitry will not increase the effects of failure-of the SBGT or Secondary Containment Isolation function or initiation as designed. Therefore, the consequences of 3 Refueling accident or LOCA are not

-. increased by this modification.

The probability of occurrence or consequences of malfunction of equipment important to safety previously evaluated in the FSAR will not be increased. The equipment of concern are the components of SBGT, Secondary containment, and their associated initiation signals.

These systems will not be degraded by this modification.

The probability of an accident or possibility for malfunction of equipment impetant'to safety of a different type than already evaluated in the FSAR will not be created.

Relying on the "A"

relay for a trip signal to either division of the SBGT Starter Circuitry will not increase the vulnerability for failure of the SBGT or Secondary Containment Isolation functions or initiation (including a11' system components and initiating signal systems) as designed.

Therefore, changes of. any accident or equipment malfunction is not increased by this modification.

63

Change _to the Facility as Described in the FSAR The margin of safety as defined in the basis to any Technical Specification will not be reduced.

The Technical Specifications require the SBGT and Secondary

- Containment system to initiate / isolate on specific - trip - signals and to be initiated / isolated within a specific time.

The "A" relay in cach division of the SBGT - will continue to reliably provide these functions per Technical Specification requirements.

All other Technical Specification requirements

-related to the SBGT or Secondary Containment are not affected by the starter

- logic of the SBGT and thus not affected by this modification.

Therefore, this

. modification does not reduce the margin of safety as defined in the basis to any technical specification.

4 I

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64

Change to the Facility as Described in the PSAR TITLE:

PM 90 014, Unit 1 Reactor Water Cleanup (RWCU) High Energy Line Break (HELB) Isolation PM 90-015, Unit 2 RWCU HELB Isolation FUNCTIONAL

SUMMARY

This change provides instrumentation capable of detecting and initiating the mitigation of all design basis breaks in RWCU piping outside of the RWCU equipment rooms that have the potential to create environmental consequences that could exceed reactor building equipment qualification (EQ) limits. To accomplish this two thermocouple senscrs have been installed in th<

vicinity of the high temperature RWCU piping that is external to the equipm rooms.

Location of these sensors near openings in the 50' elevation c s (stairways and pipe chases) will provide adequate detection capability for a Design Basis Break in RWCU piping in either the 20' and 50' elevation general areas. Each thermocouple will be cabled to a temperature switch located in the control room Leak Detection System cabinet.

Increase in the Reactor Building ambient temperature beyond the switch setpoints of 120 +/-5 degrees F will initiate Group 3 Isolation closure of the G31-F001 and G31-F004 valves.

Instrumentation and controls added by this change perform a safety related function.

The installation of Q-list, Seismic Category I components has been Qualified components have been specified for use specified.

Environmentally (reactor building).

inside harsh environments The two instrument loops are divisionally separated and redundant in order to assure that single failures cannot prevent the opposite division from accomplishing its safety function.

The logic contacts of the new temperature switches are wired in series with the existing temperature and differential flow switches that comprise the RWCU leak detection input to the Group 3 logic. High ambient reactor building temperature open and will cause the will cause the temperature switch logic contacts to Nuclear Steam Supply Shutoff System logic to initiate the Group 3 isolation.

SAFETY

SUMMARY

The instrumentation provided by this modification is intended to detect, and initiate mitigation, of a full design basis HELB break in the RWCU high temperature piping located outside of the RWCU equipment rooms, outside of the differential flow leak detection instrumentation boundaries and to the point at which it enters the main steam pipe tunnel above the 20' elevation via the RCIC piping connecting to the Feedwater System. Detection of breaks within the RWCU equipment rooms is already adequately previded for by the original leak detection instruments installed within those rooms.

will have adequate detection

(

High temperature RWCU piping in the reactor buildinkification assures mitigation capability for Design Basis Break HELBs. This mo of RWCU HELBs capable of causing reactor building temperatures in excess of the qualification limits that could cause the malfunction of safety related CE MCCs.

This modification does not extend the capability to detect small leaks since it dces not provide the high density spatial coverage and sensitivity features typical of the Falance of the temperature based leak detection syste'ms.

Less-than-Design Basis Breaks in RWCU are not a safety related concern. A small hot leak or s.ny size cold Icak does not require the same prompt detection and isolation that is critical in the case of project Design Basis Breaks. The less-than-Design Basis Breaks do not cause the rapid general area environment degradation that could challenge the qualification limits of reactor building safety related equipment.

RWCU itself is not a safety related system and therefore any functional impact on RWCU that might be caused by ' low level leakage, either hot or cold, is not a safety related concern.

Leakage from RWCU does, however, represent a loss of coolant from the reactor coolant pressure boundary. Small leaks would be made up for by CRD in-flow and by feedwater aakeup.

Such smaller leaks will be detected by a variety of indirect methods such as sump pump timers, area radiation monitors and direct observation by personnel present in the reactor building.

In the event of a 65 I

Change to the Facility as Described in the FSAR large undetected cold leak f rom RWCU, core safety is still ultimetely assured by the safety related Reactor Water Low Low Level instrumentatior, which will automatically isolate the Group 3 valves.

SAFETY SlMMARY: The scope of potential influence on plant systems required to prevent occurrence of accidents is extremely limited.

The new instrumentation and control circuitry do not connect to, or interf ace with, any plant components other than the PCIS logic directly associated with the two Group 3 isolation valves, G31-F001 and G31-F004, and the 120 VAC emergency power. Application of safety related design, installation and testing practices, along with the use of Q-list materials where required, will assure that there is no reduction in reliability of thos-rtIS or power supply circuits.

The redundancy and separation criteria applied to this design provides continued assurance that no random single failure could block the RWCU automatic isolation feature as is required to maintain the probr.bility of occurrence of accidents within that evaluated in the UFSAR.

The result of this modification mitigates the potential consequences of a liigh Energy Line Break (HELB) of RWCU piping outside of the RWCU equipment rooms. The added instrumentation is designed to increase assurance that RWCU llELB events

=

would be promptly detected and that the Group 3 RWCU isolation would automatically occur.

This isolation will serve to maintain reactor coolant consequences and help maintain the reactor radiolog[ical inventory, reduce to w thin the design basis limits used for equipment building environment qualification.

Expansion of the RWCU system leak detection coverage will help limit, not increase, the consequences of accidents previously evaluated in the FSAR.

This installation has little potential for impact on any equipment other than the PCIS logic directly associated with the two Group 3 isolation valves, C31-F001 and G31-F004, and the two supply breakers from the emergency AC power system.

Within one instrument division, the application of safety related design, installation and testing practices, along with use of Q-list materials where required, should assure that there is no reduction in reliability of that division's circuits.

The new temperature switches are powered from divisionalized emergency 120 VAC breakers common to other switches in the G31 and other system leak detection switches within that division.

Impact on those parallel systems is minimized in that each system's switches are ganged to separate fuses and the component loads are small, Worst case single failure on the instrumentation installed by this modification could only affect the other leak detection circuits within the same division.

This proj ec t does not introduce any credible single failure potentials that could affect both divisions.

This modification assures that a RWCU line llELB outside of the RWCU equipment rooms is detected and isolated in a time frame that assures maintenance of the reactor building accident environment within the limits utilized f rom equipment qualification.

This modification is intended to reduce the possibility that unanalyzed equipment failures could result from an unmanaged RWCU HELB.

Expansion of the RWCU system leak detection coverage, therefore, will not increase the probability of occurrence of malfunction of equipment important to safety as previously evaluated in the FSAR.

The instrumentation added by this modification has limited direct interface with other equipment.

It serves to detect and mitigate potential llELBs but has no credible potential for increasing the consequences of occurrence of malfunction of equipment important to safety as previously evaluated in the FSAR.

66

~...

... - ~.

Change to the Facility as Described in the FSAR This modification is specifically designed to reduce the possibility that an hi her than-qualified reactor building

-unmanaged_ RWCU HELB could-cause 6

' environmental conditions and establish the potential for unanalyzed equipment malfunctions or resultant unanalyzed accidents.

Expansion of the RWCU system leak detection coverage, therefore, will help assure that accidents or malfunctions of equipment important to safety of a dif ferent

~

type than already evaluated in the FSAR do not occur.

Ex an of the RWCU system leak detection coverage will not reduce the margin c 'patsatecy as defined in the basis to any technical specification.

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67

Change to the Facility as Described in the FSAR TITLE:

PM 90 047,_ Unit 1 Residual Heat Removal-(RHR) Head Spray Removal FUNCTIONAL SUMMARL' This change provides for the design, engineering, and construction ef f ort to permanently remove RHR Head Spray System components which are located between the RPV nozzle N-6A and the flanged connection directly downstream of the check valve E11 F019.

In addition, valves E11-F022 and Ell-F023 will be de-energized.

Instruments E11-FI-R607-and E11-FI-3339 will be de-energized. Instruments E11-FI-R607 and Ell-F13339 will be de energized and Ell.

FT N013 and Ell FT 3339 will be removed.

The RHR Spray System at Brunswick was intended for use to speed Reactor Pressure vessel (RPV) head cooldown. By maintaining saturated conditions in the RPV head volume and decreasing thermal stratification in the RPV coolant, the RHR Head Spray allowed RPV head cooldown in parallel with cooldown of the remainder of the vessel below the water line. It was anticipated during plant design that vessel cooldown and head removal would be critical path activities and that rapid head cooldown would reduce outage time.

In actuality, head cooldown is not the critical path activity (even in an outage where refueling is critical path) and the RHR Head Spray System has never been utilized during plant shutdown. Nor do plant personnel ever intend to use the system. However, since it is installed, numerous periodic surveillance, and ISI tests are required to be performed during each refueling outage also the pipe must be-disassembled for head removal and reassembled after refuelirrg.

These activities require time and effort during an outage and place personnel in a high radiation environment.

If the RHR Head Spray System could be permanently remcved, refueling outage time allocated for ISI testing and piping disassembly and reassembly could be reduced, unused equipment could be removed from the Q-list, man-rem exposure could be reduced, and associated tasks would be eliminated thus freeing manpower for other activities.

Major Equipment - The RHR Head Spray System will be deactivated.

No major equipment is involved but piping, snubbers, pipe hangers, and two instruments will be removed.

Two motor operated valves and two -instruments will be de-energized and abandoned in place.

Control Features - Flow Transmitters Ell-FT-N013 and E11-FT-3339 will be removed.

The RHR Head Spray system is being disabled end so the flow tranamitters will not be used. The corresponding flow indicators E11 FI-R607 and Ell-FI-3339 will he de energized and abandoned in place. No other control changes are.being made at this time. The switches and annunciators associated with RHR Head Spray will be abandoned as is.

System Operations - There will be no changes to the RHR system operation since the RHR Head Spray is not utilized. However, removal of the RHR Head Spray and its associated appurtenances will result in the elimination or scope reduction of ten periodic, surveillance and ISI tests.

The implementation of this modification will enhance unit performance due to the following benefits:

a.

Elimination / scope reduction of ten periodic tests.

b.

Reduced radiation exposure of personnel in a high radiation area MLARA).

c.

Better availability of Maintenance /ISI/ Operations-personnel to perform other tashs during an outage.

d.

Reduced general maintenance.

1 e.

Increase-of available spare parts from removed components (snubbers).

68

. Change to the Facility as Described in the FSAR SAFETY SUti4RY: This modification will have no effect on the reliability of the RHR System as the head spray system is abandoned and not used. The head spray mode of RHR is.not necessary for the satisfactory operation of the other modes of RHR.

The removal of the head spray piping and installation of the blind flanges has no effect on the remainder of the equipment in the RRR system or

. equipment located in the general area, The blind flanges to be installed have no more probability of failure than the exirting piping and if failure occurred, the consequences would be identical to that of a pFja break. Pipe break inside the drywell is an analyzed accident in Chapter 15 o f the MAR. In fact, it could be argued that removal of the RHR piping may decrease the probability of a pipe break inside the drywell. The decrease would be slight considering that a very small percentage of drywell piping is being removed.

Removal of the head spray system and irsta11ation of blind flanges does not affect the safety function of the RHR rystem.

The head spray system has no safety function and is not required to operate in the case of an accident. Head Spray could be used in an accident scenario but would not be the RHR path of choice.

1.PCI has a much greater flow c spacity and is much more effective for core cooling; opening the head spray line diverts flow from LPCI, 6

"he removal of the head spray piping and installation of blind flanges does not reduce the margin of safety as defined in the basis of any Technical Specification. ' Brunswick takes no credit for the operation of head spray and head spray has no safety significance.

J

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l 69

_ _ _..... _ - - _.. ~.,, _ _. _ _ _ _ _. _. _. _., _

Change to the Facility as Described in the FSAR I

TITLE.

DR 89 037,90-005, Replacement of Flov Orifices 2 SW-FO-1190, 1191, 1192 and 1193 FUNCTIONAL

SUMMARY

This change replaces the Unit 2 RilR pumps seal cooling heat exchangers flow orifices with a larger bore flow orifice plate than originally designed. New plates with larger bores are required because new heat exchangers with higher flow requirenents were installed under direct replacement packages DR 89 0363 and 89 0364. Following installation of the new heat exchangers, flow measurements were taken and the required bore diameter determined via calculation. The new flow orifices are fabricated to the same standards as the original plates and consequently are essentially identical to the original plates except for bore diameter. Orifice plate thickness was determ'aed by calculation.

The subject change is reflected in the 1990 revision to the Updated Final Safety Analysis Report Amendment No. 9.

MIX SUtd$,Y1 The direct replacement process evaluated the equivalency of the larger bore orifice plates while considering design criteria, seismic criteria, safety classification, material specification and assessment of functional characteristics. The results of these evaluations determined the acceptability of equivalency.

Additionally, system flow requirements were determined aceseptable by calculation.

Therefore, a suitable basis is provided for detemining that the change does not increase the probability or consequences of occurrence of any accident or malfunction of equipment important to safety previously evaluated or of a different type than already evaluated in the FSAR.

Similarly, this change does not reduce the margin of safety as defined in the basis to any technical specification.

70

Change to the Facility as Described in the FSAR TITLE:

EDP 89-017, Decommissioning of Unit 2 Brunswick Cumberland Transfer Trip FUNCTIONAL

SUMMARY

This change decommissions the transfer trip relay equipment associated with the transfer trip between the Brunswick Plant and the Whiteville 230 kV substation. This equipment is non safety related and no longer required.

This modification provides for the removal of non-safety related equipment from the 230 kV switchyard building that will no longer be required. This equipment is used to initiate tripping of Cumberland 230 kV Line PCB's No. 31A and 31B at BSEP for a 230/115 kV bank lockout at our Whitev111e 230 kV Substation. (Similar equipment is also being removed at the Cumberland end of this line).

Tripping of PCB's No. 31A and 31B (as well as the 230 kV breakers at Cumberland) is necessary so that the Cumberland 230 kV line could be deenergized following a

- bank lockout at Whiteville to allow the 230 kV eirbreak switch at Whiteville to open and the troubled station cleared.

Upon installation of two 230 kV circuit breakers at Whiteville 230kV Substation, this form of relaying will no longer be required, With this new arrangement, a 230/115 kV bank lockout at Whiteville would on1 initiate tripping the 230 kV circuit breakers at Whiteville and not 230 kV PCB s No. 31A and 31B at Brunswick.

Based on modification implementation relay operations of PCB's No. 31A and 31B would be limited to breaker trouble and line faults and not station trouble at Whiteville, thereby reducing the number of breaker operations at Brunswick.

SAFETY

SUMMARY

Removal of the transfer trip equipment will have no impact on-the existing relay protection for 230 kV PCB's No. 31A and 31B or the 230 kV transmission line switched by -these breakers; therefore, the probability of occurrence and consequences of any accident previously evaluated in the FSAR will not increase.

Since this modification involves removal of equipment the

' probability of occurrence and consequences of malfunction of equipment important to safety previously evaluated in the FSAR will not change ' nor will - the probability of an-accident or possibility for malfunction of equipment in the FSAR be created. The removal.of the transfer trip equipment does not reduce the margin of safety as defined in the basis to - any technical specification;

._ therefore, this plant modification does not constitute an unreviewed safety question.

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. -~

Change to Procedures as Described in the FSAR TITLE:

EER 89180, Justification To Remove 15% keduction of Safe Working Load For Rigging

? FUNCTIONAL

SUMMARY

This evaluation justifies the amendment of the 15% load reduction commitment regarding NUREG-0612, TER response to Section 2.1.6, item C, Part 1, to say: In addition to the static load condition, dynamic loads shall be considered when they are in excess of what constitutes normal usage. Normal usage shall be as defined in ANSI B30.9, Section 9.1.9, Operating Practices, and ANSI B30.2, Section 2.3.2, Operations.

The evaluation demonstrated that the addition of dynamic loads-to the static load to obtain a working load is only necessary when the dynamic load is in excess of what would be encountered during normal conditions. Precautions are identified in plant procedures to preclude shock loading and related conditions such as rapid acceleration of a load.

SAFETY

SUMMARY

ANSI-B30,9,1984 Edition, Interpretation 9-2 states, in context, that all slings have a design factor that will accommodate normal usage. When hypothetical conditions were analyzed with respect to on-site cranes, the results were well within the design factors. Since these potentially induced loads due to normal usage are within the design factors, and since normal usage is defined in accordance with ANSI standards, the probability or consequences of an accident previously evaluated in the FSAR will not be increased.

Sling tpe and design, and methods of rigging will not be altered. The deletion of the 15% -reduction requirement will a110w use of the manufacturer's prescribed safe working loads.

Since induced loads due to normal usage are within the design factors and are not a basis for consideration when selecting a sling, the probability of occurrence or consequences of a malfunction of equipment important

-to safety will not be increased due to this change.

-Methods for the rigging and sling selection have not been altered.

The evaluation addresses the 15% reduction due to dynamic loading.

Section of the sling will not be based on the static load (as currently practiced) but on the manufacturer's safe prescribed working load. This change will-thus not increase

- the probability of a sling failure, and therefore will not create the possibility for a malfunction or -accident of a different type.

As the method for rigging and sling selection has not changed, and sling sizing will be in accordance with the manufacturer's prescribed safe working load, and therefore the margin of safety as defined in the basis to - the technical specifications will not be reduced, i

72

_ _ ~, _ _. - _ _ _. _ -. _. _ _ _ - - _ _ _ _ _.

-m Change to Procedures as Described in the FSAR TITLE:

EER 90-187, RHR Minimum Flow Design Data Evaluation FUNCTIONAL

SUMMARY

This change increased the RHR minimum flow requirement from 311 GPM to 330 GPM.

The change in minimum flow requirement was based on pump manufacturer recommendation.

SAFETY

SUMMARY

1 Short-term operation of the RHR pumps in the minimum flow mode is expected to have little or no impact on the pump service life.

Loss of minimum flow does not impact accident probability.

Pump vear attributable to minimum flow operation is not a significant contributor to the total system unavailability.

Other factors (such as loss of emergency power, loss of cooling, etc.) are more significant, BWR operating history indicates no occurrences of system unavailability due-to pump _ excessive. wear attributable to low flow operation (Ref. EER No. 88-0295).

In addition, operation in the minimum flow rede is not expected to have an adverse affect on redundant or back up safety systems. Therefore, the probability of occurrence, or the consequences of any accident previously evaluated in the FSAR will not be increased.

'All Class 1, 2, 6 3 centrifugal and displacement-type pumps installed in a BWR facility required to perform a specific function in shutting down-the reactor or in mitigating the consequences of an accident that are provided with an emergency power source must undergo routine in-service inspection per ASME Boiler and Pressure Vessel Code Section XI Article IVP 1500 (" Detection of Change")

which states:

"The * 'raulic and mechanical condition of a pump relative to a previous conc... can be determined by attempting to duplicate by test a set of basic reference parameters.

Deviations detected are symptoms of changes and, depending upon the degree of deviation, indicate need for further tests or corrective action."

The inservice tests typically measure speed (if variable), inlet pressure, discharge pressure, flow rate, and vibration amplitude.

Alert ranges and required action ranges are strictly defined (in each test procedure), and require either increased frequency _ of testing or declaring the pump as inoperative,

-respectively. Performance outside of the required action range would. place the affected system in a Limiting Condition for Operation.

Although _ these inservice tests do not detect. inadequate minimum flow, any

-deleterious effects of operating within adequate flow-would be detected in advance of significant. pump performance-degradation. Therefore, any changes in pump performance would be detected and corrected per routine testing in advance of _ pump degradation due to cumulative low flow effects from pump surveillance testing and normal system starts. Therefore, the probability of occurrence or the consequences of malfunction of equipment important to safety previously evaluated in the FSAR will not be increased.

For the LPCI pumps, certain small break LOCAs actually require ECCS. injection from LPCI after runninc in the minimum flow mode. Once initiated, the maximum duration that LPCI pumps may operate in the minimum flow mode for the spectrum of hypothetical LOCAs is less than 30 minutes. This~.is derived from postulated small break LOCAs, where reactor depressurization to below the shut-off head of -

these pumps is delaved. For large break IDCAs, where the full complement of ECC systems is more fully utilized, the reactor inherently depressurJ zes through the break.

l The present minimum flow bypass line is expected to provide adequate protection l

73 i'

l

._.-______-__.m Change to Procedures as Described in the FSAR for-these pumps for compliance with ECCS. requirements for the short durations postulated during both the small and large break thCAs.

The intent of the Technical Specification surveillance requirements. is to

- demonstrate compliance with the plant safety analysis, This evaluation does not effect the minimum limits or change the intent of the BSEP Technical Specification surveillance requirements. -Therefore, the margin of safety as defined-in the basis to any technical specifications will not be reduced, s

4 74

l Change to Procedures es Described in the FSAR TITLE:

ENP-19, Special Nuclear Material Inventory SP-88 035, Fuel Assembly inspection and Repair FUNCTIONAL SUMM6E1* This change allows for storage of an individual spent fuel

- rod in a spent fuel rod holder residing in a BVR spent fuel storage location.

The spent fuel rod holder is provided by the General Electric (GE) Company.

Seismic and criticality concerns related to safety were assessed by GE and used as the basis for-the safety analysis bounding this change. The ability to remove defective individual fuel rods from a fuel bundle is needed to support repair of active fuel bundles.

SAFETY

SUMMARY

The probability of occ'arrence and the consequences of any accident previously evaluated in the FCAR will not be increased.

The Brunswick FSAR Section 9.1.2.1, describes 3 design bases for the storage of spent fuel. The following will discuss each of the 3 design bases with respect to the addition of.a spent fuel rod holder in the Brunswick fuel pool storage racks.

The FSAR states the storage racks "are designed and arranged so that fuel assemblies can be efficiently handled during refueling operations".

GE has provided a spent fuel rod holder (CE drawing No. 118D9642, Revision 3) to be placed in the Brunswick spent fuel racks which hold up to 8 individual rods from a disassembled fuel bundle. The usage of the spent fuel rod holder is controlled by SP-88-035, Fuel Assembly inspection and Repair. The spent fuel rod holder has an eye bolt used for efficient h ndling with a "J" hook.

The FSAR states "all possible arrangemenes of. fuel in the spent fuel storage racks and HDFSS modules tre maintained in a suberitical configuration having a k-eff equal to or less than 0.95". GE Letter IJiQ: 90-071, from L.M. Quintana (GE) to B. A. Morgan (CPL) addresses any criticality concerns using a spent rod holder

-in the Brunswick Spent Fuel Pool Storage Racks. GE has concluded that the eight rod spent fuel rod holder can be conservatively treated as a design basis fuel

- bundle.

The FSAR states -Each spent fuel storage rack and HDFSS module loaded with fuel and the pool structure has been designed to withstand seismic loading to minimize the distortion of the spent fuel storage arrangement and to prevent the loss of spent fuel pool water".

GE Letter 11tQ: 90-096, from L. M. Quintana (GE) to B. A.

Morgan (CPL) addresses seismic considerations using a spent rod holder in the-Brunswick spent fuel pool storage racks..Coolability is the primary seismic consideration for spent fuel rods. There are two aspects to c - W r:

1) The effect of the spent rod holder on the storage rack itself.

-GE has determined that the forces-on the storage-rack from the spent rod holder in a seismic event are judged to be bounded by that of fuel bundles or assemblies.

2) The effect of loads which are transmitted to any fuel rods in the. spent rod holder. GE has determined that the seismic effects on individual fuel rods are j.

bounded ~ by the forces of such rods in fuel bundles.

The corresponding distributed loads on the spent rod holder tubing are judged to be small and

- within the capability of the structure.

I Thus the ability to cool the fuel is provided by the design of the spent rod holder and vill be maintained in a seismic event.

The. probability of an accident or possibility for malfunction of equipment important to safety of a dif ferent type than already evaluated in the FSAR will not be created. -GE has determined that the use of the spent fuel rod holder to store spent ' fuel rods in the Brunswick spent fuel = racks is acceptable with respect to criticality and seismic considerations.

75

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Change to Procedures as Described in the FSAR The margin of safety as defined in the basis to any technical specifications will not be reduced. GE has determined that the use of the spent fuel rod holder to store spent fuel rods in the Brunswick spent fuel racks is acceptable with respect to criticalit SP 99-035, Fuel Assembly Inspect on and Repair,y and seismic considerations. controls usage of the spent fuel rod hoiders, i

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Change t. Irocedures as Described in the FSAR TITLE:

BSEP Commitment To Visual Veld Acceptance Criteria For Structural Welding at Nuclear Power Plants (WAC), Rev.

2 FUNCTIONAL

SUMMARY

The changes made allow for BSEP commitment to WAC, Rev. 2, BSEP will-implement WAC through appropriate specifications-which take no significant exceptions to WAC, Rev. 2.

Changes to WAC were only made for clarification and applicability to BSEP.

SAFETY

SUMMARY

The changes made received NRC acceptance as identified within the NRC letter dated June 4,1986 from E. D. Sylvester to E. E. Utley and the NRC SER " Application of Visual Weld Acceptance Criteria for Structural Welding at Carolina Power and Light".

As identified within the aforementioned ~ documents, the use of WAC was found acceptable and-specific BSEP exceptions were noted as insignificant and conservative in nature. The quality of nuclear safety is not jeopardized as a result of this change in that the criteria denoted in WAC'are appropriate.and provide adequate integrity of affected structures at BSEP,

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Change to Procedures as Described in the FSAR TIT 14; Control of 4KV Emergency Bus Cross Tie Breakers-DJNCTIONAL

SUMMARY

The method of controlling the use of the emergency bus cross tie breakers for El, E2, E3 and E4 buses has been-altered.

Previous control.

methods utilized equipment clearance tags.

This change allows for the administrative control of these breakers by plant procedure. Normal cross tie

- breaker configuration has not changed.

The breakers are racked out to the disconnect position when not in use and are not used without shift supervisor permission.

SAFETY

SUMMARY

The use of the equipment clearance process has been deemed inappropriate for the following reasons:

Clearances do not require 10CFR50.59 reviews prior to removal of tags.

Clearances do not require two independent reviews to allow removal of the tags.

Brunswick commitments to 10CFR50 Appendix R utilizes Emer6ency bus cross.

tie breakers for control room fires and the possibility exists for a-clearance t,g for maintenance to be masked by clearance tags for administrative control. This could lead to damage to operable equipment from using a cross-tie bus that was grounded for maintenance purposes but appeared to only be tagged for administrative reasons, U

Changes to plant procedures do require two party technical reviews, 10CFR50.59 reviews, and do not mask maintenance in progress, For the cross-tie breakers to be operated inadvertently three errors in three separate locations would have to be made, The surveillance requirements of Technical Specifications 4.8.2.1 require these breakers to be verified in the correct position every 7 days. This 7 day surveillance requirement makes it highly unlikely that all three errors would.be made prior to-detection, unless these breakers were operated deliberately (in the cross-tie from which case tag)ging of the breakers would not prevent being operated.

Based on the above, the following is concluded:

. The probability _of, or consequences of any accident will-not be increased.

The probability of, or consequences of malfunction of ' equipment important to safety will not be. increased.

Technical Specifications does not require the cross-tie breakers to be racked-out so the margin of safety 'as described in Technical Specification is not reduced.

l 78 l

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. s Change to Procedures as Described in the'FSAR TITLE:

Current Operational Practices for Ensuring Reactor Protection System

.(RPS) Operability Status

-FUNCTIONAL'

SUMMARY

The practice of periodic review of an outstanding plant equipment clearance log to assure continuing Operation's personnel surveillance of equipment status has been superseded,

. Inoperable Technical Specification equipment is administrative 1y tracked. This tracking system is reviewed at shif t turnover by Operations personnel.

Operations personnel also utilize shift

. turnover procedures which are reviewed at shift turnover.

These procedures include an equipment status log which is updated at least once per shift to reflect the status of major ECCS and BOP equipment.

SAFETY

SUMMARY

This change does aot alter the intent of the or!;inal commitment to track RPS - Partial Inoperabilit Furthermore, this change provides more stringent controls while simplify ng the process of trackiny, out-of-service Technical Specification and ESF re ated equipment. No reducticn in the margin of safety will be made by use of these enhanced administrative controls.

l.

79

Change to Procedures as Described in the FSAR

~ TITLE:

FSAR-Update Deleting Pipe Classification Tables and Describing NDE-Requirements-FUNCTMONAL

SUMMARY

This FSAR change updates the FSAR to current BSEP

- installation and material-procurement specification requirements.

A-reconciliation was performed as required by ASFE Code,Section IX, IWA requirements -to address the use of later editions of codes (United Engineers 6-Constructore Inc. Report No.-7992.017-M 045).

The NDE tables in the FSAR are being deleted, rather than being. revised, since it would be redundant to repeat the code requirements.

Applicable BSEP specifications provide the site.

requirements for installation and material procurement. The applicable updated codes are shown on the revised FSAR Table 5.2.1-1.

The deletion of root NDE examinations, which are currently in the table, does not reduce the quality of the installation. The requirements for root NDE vere not in the original code, but were specified in original installation specifications written by UE6C for Brunswick. Mandatory root NDE examination are not required by code and root LP examinations are not typically used in the industry due to AW concerns, schedule constraints, and welding concerns about welding over an area where dye penetrant removal is questionable.

Informational root-radiographic examinations are made where ever possible, but this is a matter of good practice and is not a code requirement. 1The impact tests requirements are being revised to current ASME Code requirements, which requires impact test for material greater-than 5/8" thickness, (previously it was required for 1/2" or greater).

SAFETY

SUMMARY

Safety margins, long term reliability and structural integrity of components was not reduced because all applicable requirements of ASME CODE and ANSI B31.1 are being satisfied.-

Detailed design requirements regardingl system class designation cross references,- welding, NDE, material tests, etc. are contained in controlled plant documents such as drawings, specifications and procedures.

Consequently, the probability of occurrence or consequences of any accident or

- malfunction to equipment previously evaluated in the FSAR is not increased as a result of this change.

L 1

80

Change to Proceduras as Described in the FSAR

]

TITLE!

Probable Maximum Precloitation Design leading for Class 1 Structures FUNCTIONAL

SUMMARY

This change.

cs the ori inal commitment as defined in the 4

I BSEP FSAR relating to the probable a...imum prec itation design loading for Class I structures. Existing Class 1 structures were esigned using Ilydrometerological Report. No. 33 of the U.S. hather Bureau dated April 1956, which was incorporated in the approved FSAR.

In October 1989, Generic Letter 89 22. was issued maximu:n precipitation calculations.poration of moreBSEP commits to using the data in NOAA/tNS requesting re evsluation.and incor recent data for probable i

i Hydrometerological Reports 49, 51, 52. 33 and 55 in the design if new Class 1 structuren af ter October 1989 Backfitting of er.isting Class 1 structures is not 4

required, nor t. beneficial improvement.

$AffJY

SUMMARY

The use of recent hydrometerological dr.ta pro,ide.. a more realistic and conservative basis for the calculations used to design new Class 1 attuctures and therefore does not degrade the margin of safety as defined by Technical Specifications nor introduce an unreviewed safety question.

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1111JJ, Radiation Vork Permit Time and Expc.sure Data Recording TNCTIONAL

SUMMARY

The recording of worker radiation exrosure and exposure time as accomplished through input of data to the Radiation Infortnation Ma.gement System (RIMS).

The changes acade to the recarding of data into RIMS anow for

' live time' data entry. I'rior to 'lise time' data entry, recording of exposure I

and exposure time was accomplished by first recordin6 the data rannually on dose l

cards and then after the fact into RIMS. Live time data entry provides a more efficient exposure control / data acquisition process.

SAFETY SUMR AY1 The channes to the teethod of recording worker radiation exposure and time were inade to enhance dose tracking and worker radiation control.

The changes do not represent an unreviewed safety question in that the coatrol of radiation exposure is not downgraded.

The changes allow the plant. to operate more efficiently by streamlining the radiation control process.

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Cht.ngo t o Procedures as Described in the PSAR ILT1L.

Revirion to circulating Water Chlorination frequency WNCUf&u 1MM11 This change allows circulating water chlor ination rates and f reque icir s t o 1,e determined cirpirically during plant operation so as t o minimire condenser biofouling and maximize condenser heat transfer capability.

These changes are consistent with the National Pollutant Discharge Elimination System (NPDES) permit.

The previous FSAR reference t o circulnt ing water chlorinat ion rates and f requencies was rest rictive and didn't allow for continual chlorination application.

This change support s continued chlorinat ion if dm med acceptable and if within NPDES limits.

Eb!IIL R T.APL The increased chlorinat ton that would be allowed by this change would f urther minintre biofoullnr and aid in minitatzing flow loss of circulating water to the condenser. Also, chlorination of the circulating water system is not an initiator of any accident evaluated in the PSAR.

The change in chlorination would have no effect on the consequences of sny acciden:.

Chlorinatis of the circulating water system has no effect on radioactive materials re. eased during any accident.

The potential for increased chlorination has not been proven to effec' the cocrosion rates of the condenser tubes. Tbc increase in chlorination will result in less biofouling of the condenser tubes and should aid in decreasing the f requency of any safety system actuation that could possibly result f rom a losr.

of circulating water flow to the. condensors.

The chance in chlorine concentration and frequency of chlorinat ion have no of f ect on consequences of malfunction of equipment important to safety.

This change will have no effect on the amount of chlorine being stored on the plant site at r.ny one time and therefore cont rol room habit ability should not be effected. As per the PSAR Section 10.4.5.2

" Complete outage of the condenser circulating water system will not result in loss of any service essential to reactor safety."

A margin of safety for chlorination of circulating water is not defined in the basis to any Technical Specification.

The plants National Pollutant Discharge Elimination System (NPDES) Permit is reviewed, updated, and approved by the North Carolina Department of Environment al Management on a routine basis. This ensures compliance with applicable state and federal laws dealing with environmental

issues, 83

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Change to Procedures as Described in the PSAR i

IITilt.

Site Organisation Changes

}11{CIl0NAL St% MARY:

Several site organization changes were made during 1990.

Changes included operations Shif t Foreman title change to shif t Supervisor, the Operatibus Shif t Operating Supervisor to Unit Manager, Control and Administration consolidation and position title changes, and transfer of fire brigade training to the Brunswick Training Unit.

SAFETY St% MARY:

These changes were made to functionally enhance the operation of the hN!' frat]ity. The changes do not represent an unreviewed safety question downgraded, Aor have they'y for tasks related in that approva", authorit to nuclear safety have not been resulted in a reduction in couanttment.

Consolidat:nn o-work function and the transfer of f tre brigade training serve not to dele. work functions but to iroprove the ef ficiency of BNP processes.

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84

Test or Experiment Not Described in the FSAR TITLE:

1 SP 90 026, Stroke Testing of Core Spray injection Valves E21-F004A/B and E21 P005A/B Under dP and Flow to Meet Requirements of CL 89 10 FWCTIONAL SUhMARY:

This special proceduto (1 SP 90 026) tests the response characteristics of the Core Spray Outboard Injection Valves 1.E21 F004A(B) and Inboard Injection Valves 1 E21 F005A/B under maximuta flow and thett reaximum differential pressure conditions.

Although this test io not specifically described.in the FSAR, it was designed to he performed within the design limitations of the Core Spray System. The Unit 1 Reactor Vessel is defueled, and the Fuel Pool Cates installed during the test. The Reactor Well is first flooded 2 feet above the Vessel Flange.

The cavit/ will hold approximately 400,00u

allons above that level.

The Inboard Injection Valve 1 E21 F005A(B) logic is jumpered to allow stt ding the Outboard Injection Valve 1 E21 F004A(B) open while the Inhoard Injection Valve 1 E21 F005A(B) is open, The Core Spray System is then brought up to the maximum flow rate as defined in this special procedure as the rate at which 1).

the pump begins to cavitate (if continued, pump damage could occur), 2) the flow reaches 7000 CPM (the upperlimit of the flow instrument), or 3) the valve reaches full open. At that point, the Minimum Flow Bypass Valve 1 E21 F031A(B) has been made non functional by closing the manual valve 1-E21 F010A(B). This condition has been determined by the Byron Jackson Pump Co. as being acceptable for up to 3 1/2 minutes while this procedure limits that condition to no more than 30 seconds. The consequences of exceeding 31/2 minutes could be overheating of the water in the pump with seal damage and cavitation to follow.

Following testing of the Outboard Injection Valve 1 E21 F004A/B, the jumper is removed from the Inboard Injection Valve 1 E21 F005A(B), and it is then identically stroke tested.

SAFETY StMMARY:

Since 1 SP-90 026 is performed with the Reactor Coro defueled and drained, and with the fuel Pool Cate installed, the main concern is that of flooding.

This procedure will not initiate an accident, and the neationed i

individual on Elevation 117 ', - in communicaton with the -Test Engineer and Operations, will prevent inadvertent flooding by notifying them of high water l

1evel prior to flooding. This. procedure will not effect the mitigation of an r

accident,- since the stationed individual on Elevation 117', in communication with the Test Engineer and Operations, will prevent inadvertent flooding by notifying them of high water level prior to flooding. The flooding could possibly damage Fuel Pool Cooling power supplies if allowed to occur.

This procedure will not initiate equipment damage, since 1) the valves are stroked within design parameters (except for the jumpering of the Inboard Inlection Valve 1 E21 F005A(B), to allow stroking the Outboard Injection Valve IU21 F004A(B) with the Inboard Injection Valve 1421-F005A(B) remaining open), 2) the pump is monitored for cavitation and the-maximum flow of 7000 CPM, = and 3) flooding of the 117' elevation is prevented by stationing on individual on Elevation 117',

in communication with the Test Engineering and Operations, to prevent inadvertent 4

flooding by notifying them of high water level prior to floodirg. This procedure will not effect the mitigation of equipment damage, since 1) the valves are stroked within design paraineters of pressure and flow, 2) the pump is monitored for cavitation and the maximum flow of 7000 GpM, and 3) flooding of the 117' elevation, with the consequential equipment damage, is monitored.

With the reactor core defueled and drained and the Fuel Pool Cate installed, Technical.

Specification requirements are not applicable and the margin of safety defined within Technical Specification is not reduced.

I 85

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_ _ _,,_ _ _ _ ~-,_, _.

I Test or Experiment Not Described in the FSAR TITLE:

1 SP 90 029, Stroke Testing of Residual lleat Removal (RllR) System Valves E11 0007 A/B, E11 F011 A/B, E11 F027 A/B, E11 FO?8 A/B, Ell-F047 A/B and E11.F048 A/B Under Differential Pressure and Flow Conditions to Meet the Requirements Described in NRC Ceneric Letter 89 10 Ft*NCTIONAL

SUMMARY

Special proceduro, 1-SP-90 029 was written to test the f

opening and closing functions of a number of valves in the Residual lient Removal (RHR) system. Specifically the valves tested are: Minirnum Flow Bypass Valve 1-E11 F007A(B), RilR llent Exchanger (llX) 1A(B) Drain to Suppression Pool Valve 1-E11 F011A(B)Yalve 1-E11 F047A(B), and RHR HX 1A(B) Bypass Valve 1 E11 F048A(B). Suppres 1A(B) Inlet These valves are to be tested at the closest conditions to desir,n application for both maximum pressure and inaximum flow in accordance with hRC Generic Letter Number 89-10.

This procedure was written to be performed by taking suction frorn the Suppression Pool and returning it to the Suppression Pool. Where possible, normal Operating Procedures for PJIR were used for these valve tests. For some modes of operation, changes were required.

These changen are The valve was stroked open and Minimum Flow Bypass Valve E11-F007A(B) closed against inaximum pump discharge pressure.

It was therefore necessary to disable the automatic opening command of the valve for low flow conditions and operate the purnp deadheaded.

While deliberate operation of a pump in t.be deadheaded configuration is not desirable. this is the only method possible to verify the Minimurn Flow Bypass Valve is apabic of operatinr, in that regime.

A March 4, 1985 letter froin Bor6 Warner (Byron Jackson Pump Division) to CP6L indicates that an RilR pump inay be operated in a closed discharge condition for up to three and one half minutes before flow must be established.

Procedure 1-SP 90 029 requires dual verification when the function is disebled and independent verification when the function is restored.

The procedure contains cautionary notes to remind the Operator that the automatic mode of minimum flow protection has been disabled and to restrict the deliberate deadheaded operation of the pump to less than 30 seconds.

Testing of the minimum flow valve also required operation for moderate periods of time with only the minimum flow valve open. In CP6L's responses to IEB 88 04 (EER 88-0295 and EER 90 0187) the question of low flow protection and operation at moderate flow rates is addressed. One of the references used is a Nov 22, 1989 letter from General Electric to CP6L. That reference defines or supplies a recommended limit for short term operation for the RilR pump between flow rates of 330 to 2900 GPM. The letter recommends not operating for more then 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> per year in this region. To allow a reasonable time for the verification of data collection at the test sites, but not to allow unlimited time to operate in the low flow regime,1-SP 90 029 contains several " Cautions" not to allow more than 10 minutes with low to moderate flow rates.

RIIR HX 1A(B) Drain to Suppression Pool Valve 1 E11 F011A(B)

This valve was lleat tested by establishing a flow path from the Suppression Pool to the pump,f the Exchanger and back to the Suppression Pool.

The flow path is upstream o flow orifice used to monitor system flowrate therefore it is impossible to measure flowrate and accordingly the Mintimun Flos Bypass Valve, 1 E11 F007A(B) remained open for the duration of the test. System flow during this test was in the low to medium area. " Cautions" were established to restrict operation, while waiting for test results to be verified, to a reasonably short period of tirne (approxirnately 10 minutes).

Suppression Pool Spray Isolation Valve - 1 E11-F027A(B) - This valve was. tested by establishing a flow path frorn the Suppression Pool thru the pump and return back to the Suppression Pool thru the spray header. Since the expected flowrate 86 l

l l

Test or Experiment Not Described in the PSAR is sinell, the miniinum flow valve was lef t functional.

System flow daring this test was in the low to medium area. " Cautions" were established to restrict operation, while waiting for test resvits to be verified, to a reasonably short period of tirne (approximately 10 ininutes).

As the condl* ions for simultaneous opening of both the 1.E11 F027A(B) and the 1-E11-P028A(B) do not exist, this interlock was defeated by installing a jumper in th6 control logie of the Sprav Isolation Valve. The installation and independently verified on removal. jumper vas dual verified on This section of the procedure initiated flow thru the spray header inside the Suppression Pool.

To prevent loose materials frota being washed into the Suppression Pool, a cleanliness inspection was required before beginning this section of the test. For reasons of personnal safety, access to the Suppression Pool was likewise secured before beginning the test.

Suppression Pool Isolation Valve - 1.E11-F028A(B)

This valve was tested by using the full flow test path, Suppression Pool pump,l via 1 E114028A(B) and Ileat Exchanr.er and llent then returned to the Suppression Poo Exchanger By(pass, Maximum flowrate was established using t.wo pump operation, then 1.E11-r024A B).

the isolation valve was closed and opened twice. This alignment is $dentical to

-the normal Suppression Pool Cooling alignment, thus no interlocks were required to be defeated.

RitR llX 1A(B) Inlet Valve - 1 E11.F047A(B)

The valve was tested using the full flow test path Suppression Pool, pump, thru the llent Exchanger, and return to the Suppression Pool via 1 E11 F028A(B) and 1.E11.F024A(B). In essence, sito11ar flow path vaed for testing of the 1-E11.F028A(B) valve except the heat exchanger bypass valve was closed. Flowrate was restricted to 11,500 CPM, the design shell side flowrate for the heat exchanger, Since this alignment was also used for Suppression Pool Cooling no interlocks were required to be defeated.

RHR RX 1A(B) Bypass Visve 1-E11 F048A(B)

• The valve was tested using the full flow test path, Suppression Pool, pump, Heat Exchanger Bypass, and return to the Suppression Pool via 1 E11.F028A(B) and 1-E11-F024A(B). The same flow path used for testing of the 1 E11 F028A(B) valve except the llent Exchanger was isolated.

Maximum flowrate was established using two pump operation, and then the itX 1A(B)

Bypass valve was closed and opened twice.

This alignment was also used for Suppression Pool cooling, thus no interlocks were required to be defeated.

1 SP 90 029 is written to test the operation of system valves in conditions of maximum pressure and flow. The RHR pump was operated deadheaded for very short intervals of time and at low to intermediate flow rates for short time intervals.

l The maximum flow conditions were within the system design.

SAFETY

SUMMARY

! The testing activities did not innpact the ability of RHR safety systems to keep the core covered and cooled, No conditions existed during the performance of this test that increased the likelihood of initiating a previously evaluated accident scenario.

t No situations existed during the test that decreased the ability of plant safety systems from mitigating the consequences of a previously evaluated accident. Use of the system is limited to the design criteria of the RHR system.

The RitR design pressure, temperature, and flow parameters were exceeded.

Temporary alterations to valve control logic were made under controlled conditions.

But, appropriate restraints such as time limitations and flow limits, were established to ensure that system design parameters were not exceeded.

Additionally, appropriate procedural steps, including independent verification practices, were in place to ensure that the system was returned to i

its "as found' condition upon completion of the test. Therefore, the probability i

j of occurrence of a malfunction of equipment important to safety was not l

l 87

\\

s Test or Experiment Not Described in the l'SAR increased.

Because the PilR operating parameters were not exceeded, and all temporary jun'pers and log 8c actuation alterations were returned to their *as found" condition, there va no increased chance that an equipment malfunction would decrease the system's ability to nitir, ate the consequences of a previously evaluated accident.

Loss of at. RHR loop is a previously analyzed event.

Technical Specification requirements were followed.

No new operational situatione vere created during performance of the procedure.

'Ihe r e f o re, no accident situations, that were not pre,viously defined in the FSA't were created.

No new operational situations, which could result in the increase in probability of equipment malfunction, were created during the procedure.

Controls established within the procedure protected the RHR heat exchanger and piping from water hammer. Although the RllR pump min'mu6. flow valve was temporarily disabled during the procedure, appropriate time restraints and precautionary steps were included to avoid exceeding Ritt. pump design parameters.

This activity did not move any regulatory limits in the non c mservative direction or reduce the ability of the plant to meet current regulatory limits.

88

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Test or Experiment Not Described in the FSAR i

TITLE:

2 Sp 90 004, Service Water Systern liydraulic Perforuanco Test PUNCTIONAL

SUMMARY

The Service Vater System llydraulic Analysis Report issued in December 1989 evaluated the design basis capability of the Servico Water

^

syt,t e m. The hydraulic report concluded the Service Water system is capable of satisfying its design function for all design basis events, including all credible combinations of events, llowever, this conclusion is based on two assumptions. The first assumption concerns cross header leakage from the Nuclear to the Conventioaal Service Water header. The second assumption which requirco verification relates to Conventional Service Water header and Conventional 4

Service Water pump flow capability.

This procedure provides the data for verification of the above assumptions.

Nuclear Service Water (NSW) header performance, includin6 cross header leakage, and Conyc7tional Service Water (CSW) header and Conventional Service Water pump flow capability.

Specifically, the overall perfortnance test is structured in three parta:

a Nuclear Service Water header performance test; a Nuclear Service Water llender 1eakage test; and a Conventional Service Water header performance test. The NSW header performance test establishes a specific NSW header lineup similar to the lineup after a design basis accident and records system parameters. CSW header pressure is inaintained as close to NSW header pressure as practical to minimize the effect of cross header ler.kage. The data collected will be compared against the results of a computer simulation for that system lineup to confirm the validity of the computer model. After completion of this test, the CSW header will be depressurized to provide data on NSW header leakage under a severe header

{

DP situation.

Data coliccted will provide verification of the flow value used for worst case leukage in the computer model.

Finally,he nonsafety TBCCW flow tie CSW header will be placed-in service supplying RHRSW and vital header.

T will be isolated and system parameters will be recorded.

Then, the total CSW header flow rate will be increased in 1000 gpm increments, up to the approximate flow rate the header would be required to supply during certain accidents. Data recorded af ter each increase will be used to establish a CSW header leakage value. This-part of the special procedure provides both a direct indication of CSW header performance under conditions similar to those followint certain accidents.

Data recorded after each increase will be used to establish a CSW header leakago value. This part of the special procedure provides both a direct indication of CSV header performance under conditions similar to those following certain accidents, and a measure of actual system leakage which can be used to evaluate CSW header performance for worst case accident conditions.

i MFETY

SUMMARY

Performance of this special procedure will not placo the Service Water system in an unsafe condition or result in an unreviewed safety question.

. The function of the Service Water system is to provide required cooling water to safety basis event.related components to allow a safe shutdown of the plant following a design The analyses conducted in support of the liydraulic Analysis Report demonstrate the Service Water system is fully capable of meeting its design function assuming implementation of operating restrictions defined in t.he hydraulic report and verification of assumptions concerning cross header leakage and CSW header performance.

The required operating restrictions have been imposed by various docurnents including En6 neering Evaluation Report's and 1

Standing Instructions, and are observed in this procedure. The assumptions in the report about Unit 2 cross header leakage and CSW header performance will be verified by this procedure.

-Since cross-header leakage and CSW header performance are not quantified until completion of testing, the possibility exists of placing the Service Water system in an operating condition which is outside the liraits analyzed in the hydraulic analysis report. To ensure this will not occur, several precautions are taken.

First, the actual operation of the Service Water system will he under conditions i

t 89 L

= -, - -. -.- -.-. -

e e

i i

i Test. or Experiment Not Described in the FSAR much less severe than the design scenarios analyzed in the hydraulic report.

System flows and pressures will be maintained well within those assumed as the most limiting initial conditions in the analyses.

System performance under design conditions then will be extrapolated from data collected at the less i

severe operating scenarios.

This testing methodology reduceo the risk of challenges to the Se vice Water system during the test, Second, all operating restrictilons provicusly defined f or the Service Water system are observed.

j flows, and pressures defined in operating procedures, Specific component lineups, have been incorporated into the special precedure to Standing Instruction, etc.

i ensure safe operation of the Service Water systein.

i.ast, caution statuents are i

1 provided in the body of the procedure-to alert operators of any.ctions which have the potential to cause unacceptable systern or equipment condit ions.

The Service Water system design function is to provide required component cooling to safety related equipment. Ade uate compenent cooling is ensured during this l

test by observing lineups for equ pment cooled by service water are maintained as tuch as possible to ensure t ie equipment _ wlli be capabic of full design performanco in the event of a design basis accident. When a normal lineup is not maintained e.g., supplying tho bital header from the CSW header operating restrictions are implemented as required by previously approved documents to r

guarantee cooling water flow to that equipment under all accident scenarios, Service Water pump operability is guaranteed by maintaining pump flow rates l

within acceptable values.

If actions dictated in the procedure have the potential to drive service water pump flows above or below the acceptable flow limit 9, paution _ statements are provided to direct plant personnel to take approptlate actions to bring service water pump flows within the acceptable range.

A specific example can be seen in the NSW header cross-leakage test.

+

Vhen the OSW header is depressurized for the NSW header leakage test, cross.

header is depressurized for the NSW header leakage test, cross header leakage i

greater than assurned would place the Service Water system in a configuration f

outside the limits analyzed in the hydraulic report and create the possibility of Service Vater pump failure as a result of excessive flow. Accordingly, the caution utotement orovides direction to the control operators to iminediately restatt 6 CSV pure lf NSW header falls below the minituum acceptable pressure (40 s

psig),

My conducting the Service Water system testing as discussed above, Service Water system design capability is ensured. Service Water pump operability and required component cooling flows can be maintained in the event of a design basis accident or transient.

Therefore, performance of this special procedure does not compromise Service Water systern operation or place the plant in an unsafe 4

condition.

This special procedure aligns the Unit 2 Service Water system as required to i

verify system performance and cross header leakage. The specific system lineups are not in the UPSAR, but are in cornpliance with existing operating restrictions and procedures.

The probability of occurrence of any accident or transient previously analyzed in the FSAR will not be increased, The capability of the Service Water Systern to perform its design function is ensured by the testing methodology and precautions utilized in the development of this procedure.

7 The consequences of any accident or transient previously analyzed in the FSAR wul not be increased since precautions are taken in the development and itnplementation of this procedure to ensure the Service Water system will be able

- -to supply-required cooling Icads - in particular, the diesel generators and the ECCS components under any credible accident scenario.

The probability of occurrence of malfunction of equipment important to safety previously evaluated in the FSAR will not be increased.

Service Water syatem reliability is maintained by operating within all currently specified operating 90

o e

Test or Experiment Not Described in the FSAR i

i 11: nit s. Single failure protection is maintained to ensure Service Water system availability during a DBA. Therefore, ali equipinent which relies on the Service Water system can be credited as being operable.

The consegrences of occurrence of malfunction of equipment isoportant. to saf ety previously evaluated in the FSAR will t.ot be increased.

Service Water system i

reliability is maintained by operating within all currently specified operating 11eits. Single failure protection is staintained to ensure Service Water system availability during a DBA. Therefore, all equipment. which relics on the Service Water system can be credited as being operabic.

The consequences of occurrence of malfunction of equipinent important to safety previously evaluated in the FSAR will not be increased since all single failure requirements are ansured by compliance with existing operating restrictions. The procedure introduces no systern lineups which can cotopromise single failure protection for the Service Water systern or create common mode failure scenarios.

This procedure does not place the Service Water system in any unanalyzed system configurations or compromise Service Water system design capability. Protection against single and common mode failure is maintained throughout the test duration by the testing methodology and specific precautions in the nrocedure. Therefore, the probability of any accident or possibility for malfunction of equipment itoportant to safety of a dif ferent type than aircady evaluated in the FSAR will not be created.

This special procedure will not cause a reduction in the snargin of safety of any Technical Specification.

Equipment operability requirernents of the current Technical Specifications and Technical Specification Interpretations are trot.

Operating restrictions necessary to maintain design capability of the Service Water systern are observed.

Therefore, the margins of safety contained in the Technical Specification are not reduced.

J L

i 91

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