ML020800771

Summary of Facility Changes, Tests & Experiments Implemented During 2001

ML020800771
Person / Time
Site:	North Anna
Issue date:	03/13/2002
From:	Heacock D Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
02-148
Download: ML020800771 (166)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 March 13, 2002 United States Nuclear Regulatory Commission Serial No.02-148 Attention: Document Control Desk NAPS/JHL Washington, D. C. 20555 Docket Nos. 50-338 50-339 License Nos. NPF-4 NPF-7 Gentlemen:

VIRGINIA ELECTRIC AND POWER COMPANY NORTH ANNA POWER STATION UNIT NOS. 1 AND 2

SUMMARY

OF FACILITY CHANGES. TESTS AND EXPERIMENTS Pursuant to 10 CFR 50.59 (d)(2), enclosed is a summary description of facility changes, tests and experiments, including a summary of the regulatory/safety evaluations, that were implemented at North Anna Power Station during 2001.

If you have any questions, please contact us.

Very truly yours, D. A. Heacoc/

Site Vice President Enclosures cc: U. S. Nuclear Regulatory Commission Region II Atlanta Federal Center 61 Forsyth St., SW, Suite 23T85 Atlanta, Georgia 30303 Mr. M. J. Morgan NRC Senior Resident Inspector North Anna Power Station

SAFETY EVALUATION LOG SPECIAL TESTS 2001 SNSOC Unit Document System Description Date 01-SE-ST-01 1,2 O-ST-79 Auxiliary Building Filter Bank Acceptance Tests" 3-09-01 I

O1-SE-ST-01 Description Tests" Revision 0 to 0-ST-79, "Auxiliary Building Filter Bank Acceptance (1-HV-FL-3A & 1-HV-FL-3B) will filter banks This Special Test ensures that the Auxiliary Building in by performing the filter acceptance testing specified provide adequate filtration at design conditions, performed: a) airflow the following tests will be sections 8 & 9 of ANSI N510-1975. Specifically, test, and c) pressure drop test.

distribution test, b) air-aerosol mixing uniformity Summary BACKGROUND tests of the Auxiliary Building filter banks (1-HV Plant Issue N-2000-0695 states that detailed acceptance is no 8, 9, 10 & 12 of ANSI N510-1975, but there FL-3A & 1-HV-FL-3B) were required by sections was performed at the design flow rates.

confirmation that acceptance testing of these filters function during and following accidents. Without The Primary Ventilation System provides a filtration not was performed, the primary ventilation system may confirmation that acceptance testing of these filters C-98-01 identifies resolution of Revision 1 of JCO be able to provide the required degree of filtration. closing out the JCO. The required action before plant issue N-2000-0695 as a required corrective associated with this JCO is to maintain ECCS leakage within an administrative limit compensatory action both This is controlled by 1&2-GOP-8.2. With this limit, of 600 cc/hour for total ECCS leakage per unit.

even if all ventilation is unfiltered. Therefore, onsite and offsite dose will be within licensing basis limits, required for any post-accident filtration function.

with this JCO in place, the filter banks are not PROPOSED ACTIVITY & 1 the Auxiliary Building filter banks (1-HV-FL-3A 0-ST-79 is a Special Test designed to verify that performing the filter acceptance testing conditions, by HV-FL-3B) will provide adequate filtration at design 8 & 9 of ANSI N510-1975. Section 8 specifies an airflow capacity verification, an specified in sections test.

section 9 specifies an air-aerosol mixing uniformity airflow distribution test and a pressure drop test; banks which is specify in-place leak testing of the filter Note that sections 10 & 12 of ANSI N510-1975 & 14B for

& 77.3 currently, and future 0-PT-77.14A performed by periodic test procedures (l-PT-77.2 be rate). The special test is required to allow JCO C-98-01 to testing at the required post-accident flow at a time:

for one filter bank closed. The special test performs the following activities is performed of the filter banks, similar to that done by existing surveillance

"* First, a visual inspection approximately 39,200-cfm is aligned through one tests. Then the filter design maximum flow rate of filter bank.

within the housing across the inlet to the

" The first test verifies that there is adequate flow distribution blades installed for this purpose where the HEPA/pre-filters. There are adjustable flow distribution is measured at both the design maximum filter suction duct enters the filter housing. Air distribution flow rate.

flow rate and at the minimum expected post-accident ports and sample ports are located so as to provide adequate mixing

"* The next test verifies that injection of the aerosol in the air approaching the HEPA/pre-filters. conditions at the maximum filter

"* The third test verifies that the fans can operate under actual field pressure drop of 5" wg, based on TSCR #377A.

test is secured and the system is re

"* These tests are then repeated for the other filter bank. Finally, the aligned to its normal configuration.

the filter housing is addressed by requiring confined Personnel safety while taking measurements inside The filter bank being tested will be considered space entry precautions in accordance with VPAP-1904.

will be entered.

inoperable but available, and the action of TS 3.7.8.1 FAILURE MODES or with inadequate sample port locations, the filter With inadequate airflow distribution within the filter, These conditions are acceptable since the filter may not be providing its design filtration efficiencies. the function with JCO C-98-01 in place. Also, during banks are not required for any post-accident filtration of 39,200 cfm. The potentially the design maximum special test the flow rate may be up to 10% above In affect filter residence time and will not physically damage the filter banks.

high flow rate will only

will be aborted, and existing EOPs ensure that addition, in the event of a Unit trip or ESF actuation, the test flow through the Auxiliary Building Filters.

the post-LOCA ventilation configuration will be aligned with drop testing, steps within the procedure To ensure ventilation equipment is not damaged during pressure it is increased gradually, and require independent require the filter pressure drop to be monitored while testing.

verification that all plastic has been removed following UNREVIEWED SAFETY QUESTION DETERMINATION Special Test creates no unique precursors or Operation of the ventilation system as proposed by this Special Test does not change the intended precursor events for Chapter 15 accidents. The proposed for accident mitigation. This Special Test may operation of the charcoal filter bank or equipment required operating conditions (for example, be aborted at any time as directed by the Shift Supervisor based on Unit or Tech Specs. Appendix to the Operating License Unit Trip or ESF actuation). No changes will be made these reasons, an unreviewed this Special Test. For R and the environment will also not be impacted by safety question does not exist.

SAFETY EVALUATION LOG TEMPORARY MODIFICATIONS 2001 SNSOC Unit Document System Description Date 01-SE-TM-01 2 N2-1137 DA Allows testing of the incore sump high level switch 2-DA-LS- 1-12-01 206 because annunciator 2J-C8 is locked in.

01-SE-TM-02 2 N2-1138 DA Defeats the hi-hi alarm for 2-DA-LS-206 (which is locked in), 1-12-01 restoring annunciator 2J-C8 to a condition to alert the operator to a high level in the incore room sump.

01-SE-TM-03 1 N1-1694 SW A ground was discovered on the positive lead (black) of the 2-08-01 PI circuit, causing indication failure of 1-SW-PI-110, 1-SW P-4 discharge header pressure transmitter. This TM swaps leads to allow the ground to be transferred to the negative (white) side of the circuit to restore the circuit to a functional condition.

01-SE-TM-04 2 N2-1140 Temporarily removes coil wires #73 from both bridge 4A 4-04-01 relays for polar crane 2-MH-CRN-1 because 1 wire is sticking & the operator has no bridge speed control.

01-SE-TM-05 1,2 N1-1695 FW Temporarily replaces the 1st orifice (1-FW-RO-102A & 2- 4-12-01 N2-1139 FW-RO-202A) in the full flow recirc line for each turbine driven AFW pump with a replacement orifice sized to limit 1-PT-71.1Q (OTO) pump discharge to about 345 gpm. Data will be collected 2-PT-71.1Q (OTO) for design input to a DCP (REA R1996-503) that will ET N-00-134 permanently replace the existing 1 st orifices.

WO 447260-01, 02 WO 447261-01, 02 01-SE-TM-06 2 N2-1141 Lift leads from 2-GM-LS-210-2 to clear a locked-in 5-10-01 defoaming tank level alarm (2T-C2) on the turbine 2-AR-T-C2 supervisory panel in the MCT (2-EI-CB-1 0) with no high oil VPAP-1403 level condition present.

01-SE-TM-07 2 N2-1142 The leads for seal leakoff temperature element (2-CH-TE- 5-10-01 2126) & pump radial bearing temperature element (2-CH TE-2125) for U2 "C" RCP need to be swapped at Junction Box JB-781-2 for these parameters to indicate correctly on the P-250.

01-SE-TM-08 1 TM Ni-1697 Main turbine speed pickup #4 has failed & cannot be 5-17-01 repaired until the next outage. The failed speed sensor provides a start permissive to bearing lift pump 1-GM-P-10.

Use of a spare speed input will allow the lift pump control to be returned to AUTO & restore turbine speed indication to the turbine supervisory panel.

01-SE-TM-09 2 TM N2-1143 Installs a video camera & associated equipment to observe 6-08-01 oil level in the lower oil reservoir for the 2-RC-P-1 A motor.

01-SE-TM-10 1 TM N1-1696 GM Lifts leads at 1-GM-TS-102B to disable the input to 6-12-01 annunciator K-B7, which has been alarming prior to the setpoint of 175 0 F & periodically causes annunciator K-B7 to lock in on hot days.

01-SE-TM-11 1,2 TM Ni-1698 BC Installs a temporary chemical addition system to the BC 6-14-01 system in order to add Calgon biocide H-900 in tablet form I

SAFETY EVALUATION LOG TEMPORARY MODIFICATIONS 2001 SNSOC Description Date Unit Document System 2

O1-SE-TM-O1 Description Temporary Modification (TM) N2-1137 (2-DA-LS-206).

Allow testing of the incore sump high level switch Summary sump of a Hi and then a Hi-Hi alarm corresponding to The The Incore Sump Level alarm (2J-CS) is comprised level electrodes.

two alarms are actuated by two different levels of 18" and 20" respectively. These at 18" will open for the incore instrumentation sump and 18" high electrode provides the level control the Hi level alarm and will close 2-DA-LS-206 to actuate contact (B) (12050-TLD-DA-09) in level switch pump, 2-DA-P-5. The 20" electrode instrument room sump contact (A) in the switch to start the incore in the level switch at 20" to reflash the close contact (C) provides the Hi-Hi level alarm only and will of a third probe the alarm clears when level reaches the setpoint Hi/Hi-Hi level alarm. The pump stops and (6" Unit 1 electrode, 8" Unit 2 electrode).

locked in.

Hi/Hi-Hi Level alarm) was received and remained Annunciator 2J-C8 (Incore Inst. Room Sump portion of the field circuit was determined that the Hi-Hi The hathaway system was tested and it was condition exists since there is no level that an actual high level causing the alarm. However, it is not clear and not actual To ensure the Hi-Hi level alarm is due to an erroneous signal indication for the incore sump. to COO (TM) will install a jumper from contact COI incore sump level, this Temporary Modification to be manually high sump level interlock, allowing the pump (12050-ESK-6GD) to defeat the 2-DA-P-5 a valid Hi level jumper will ensure the pump will operate on started with a sump level less than 18". This 18" electrode.

signal and will verify the operability of the for only 30 start permissive. The pump will be run manually This jumper will also bypass the high level and the Hi Level start permissive will with this TM installed. The TM will be removed thereafter could seconds the pump to be run with less than 8" in the sump and be restored. This TM will also allow the pump run, no damage to the pump is expected to of this pump be run in a dry condition. For the short duration level alarm and will enough to test the validity of the Hi/Hi-Hi occur. This TM will be installed only long opened to ensure the the breaker for 2-DA-P-5 will be then be removed. Prior to installing the jumper, is installed, the breaker than necessary. Once the jumper pump does not prematurely start and run longer and run until one of the following occurs:

will then be closed and the pump started (the incore sump pump discharges to the containment (a) The containment sump level stops increasing sump),

clears, or (b) The incore sump Hi/Hi-Hi level alarm (2J-C8) containment sump level (c) 30 seconds passes with no change in the for the following reasons:

This Temporary Modification should be allowed are listed in is minimal. Reactor Coolant leakage limitations

1) The safety significance of this Hi-Hi alarm leakage detection required are listed in 3.4.6.1. The Tech Spec 3.4.6.2. and leakage detection systems sump level and radiation monitors and the containment systems are Containment gaseous and particulate of the Safety Analysis sump level indication is not a part discharge flow measurement system. The Incore RCS leakage.

system required to monitor for increased Detection'.

sump level indication in Section 5.2.4.1, 'Leakage

2) The UFSAR also takes no credit for the leakage: Containment gaseous rad UFSAR credits the following systems for monitoring for RCS The Containment Structure leakage monitoring system, monitor, Containment particulate rad monitor, RCS makeup load, Containment Sump monitoring and the Containment recirculation system cooler heat in the group of essential leakage indications.

rate. Again, the Incore sump is not included ensure that the Hi indicator to have available and this TM will

3) The Incore Sump level alarm is a good properly.

level portion of the alarm which is still operating leakage) is based on early detection of leakage and (containment

4) The margin of safety of the Tech Specs as possible based on industry Threshhold values are as low is consistent with Reg Guide 1.45, May 1973.

is not operation. The restoration of this system which experience yet not too low to unnecessarily restrict with regard to RCS to improve the margin of safety even taken credit for in the Safety Analysis only serves leakage. the will not increase the probablity of occurence,

5) Testing the validity of the Hi/Hi-Hi alarm no credit is taken for this function in the of accident since consequences or the possibility of a different type TM.

risk of a small break LOCA as a result of this Tech. Specs. or UFSAR. There is no increased in that one by implementing the TM. This TM is beneficial No Technical Specifications require change no unreviewed safety by the operator. For these reasons portion of the alarm will be restored for use Level and the TM should be alarm on Incore Sump question is created by this TM for the Hi/Hi-Hi installed.

01-SE-TM-02 Description Temporary Modification # N2-1138 The high alarm The HI-Hi alarm for the Incore Room Sump Level is alarming spuriously (2-DA-LS-206).

does the operation of the sump pump.

for the Incore Room Sump level remains operable as Summary alarm corresponding to sump The Incore Sump Level alarm (2J-C8) is comprised of a Hi and then a Hi-Hi different electrodes. The 18" high levels of 18" and 20" respectively. These two alarms are actuated by two and at 18" will open contact 'B' electrode provides the level control for the incore instrunmentation sump alarm and will close contact 'A' in (12050-TLD-DA-09) in level switch 2-DA-LS-206 to actuate the Hi level The 20" electrode provides the Hi-Hi the switch to start the Incore Instrument Room Sump Pump, 2-DA-P-5.

at 20" to reflash the Hi/Hi-Hi level alarm. The level alarm only and will close contact 'C' in the level switch reaches the setpoint of a third probe (6" Unit 1 electrode, 8" sump pump stops and the alarm clears when level signal to indicate a sump level of Unit 2 electrode). The 2-DA-LS-206 level switch is sending an erroneous and restore the Control Room 20". This Temporary Modification will disable this erroneous signal inches is reached in the sump. This annunciator to a non-alarming condition until an actual Hi level of 18 Temporary Modification should be allowed for the following reasons:

leakage limitations are listed in

1) The safety significance of this Hi-Hi alarm is minimal. Reactor Coolant are listed in 3.4.6.1. The leakage detection systems Tech Spec 3.4.6.2. and leakage detection systems required monitors and the containment sump level and discharge are Containment gaseous and particulate radiation sump level indication is not a part of the Safety Analysis system flow measurement system. The Incore required to monitor for increased RCS leakage.

5.2.4.1, 'Leakage Detection'.

2) The UFSAR also takes no credit for the sump level indication in Section leakage: Containment gaseous rad The UFSAR credits the following systems for monitoring for RCS leakage monitoring system, monitor, Containment particulate rad monitor, Containment Structure Containment Sump monitoring and the RCS makeup rate.

Containment recirculation system cooler heat load, Again, the Incore sump is not included in the group of essential leakage indications.

this TM will restore that portion of

3) The Incore Sump level alarm is a good indicator to have available and the Hi-Hi alarm, the original the alarm which is still operating properly, the Hi level alarm. By disabling with the audible and visual alarm intent of the alarm is restored by alerting the OATC to an unusual condition the Hi-Hi alarm to remain in (flashing) from Annunciator 2J-C8 when sump level reaches 18". Allowing degree of complacency on the part of the operator with the audible alarm acknowledged establishes a regarding an alarm which is constantly present and this should be avoided.

reasons:

The TM does not introduce an Unreviewed Safety Question for the following any analyzed acidents. The 20" The incore sump Hi-Hi level alarm does not contribute to the initiation of and provides no other function. Removing the level electrode provides input to the Hi-Hi level alarm only probability of occurrrence, the consequences or the possibility input from the Hi-Hi alarm doesn't increase the credit is taken for this function in the Tech. Specs. or UFSAR. By of a different type of accident since no this TM improves the ability to restoring the ability of the operator to receive alarms for the incore sump, respond to a small break LOCA.

early detection of leakage and is The margin of safety of the Tech. Specs. (containment leakage) is based on are as low as possible based on industry consistent with Reg. Guide 1.45, May 1973. Threshold values The restoration of this system which is not even experience yet not too low to unnecessarily restrict operation.

serves to improve the margin of safety with regard to RCS taken credit for in the Safety Analysis only leakage.

The TM is limited to the Incore Sump Hi-Hi level alarm, and will not adversely affect the operation of any component used to mitigate the consequences of any accident. Operation of this alarm is not required for he mitigation of any analyzed accident, nor is it required to operate to maintain the plant in a safe condition.

The change does not impact any Tech. Spec., TRM or License Conditions. Compliance with the specifications will be maintained.

This TM is an electrical modification to the Control Room annunciator circuit and does not affect the environment in any way.

01-SE-TM-03 Description Temporary Modification (TM) Ni- 1694 Roll leads at 1-EI-CB-23D TB 7 and 8 and at local junction box JB-2115 TB 1 and 2 for 1-SW-PI-110, 1 SW-P-4 Discharge Header Pressure.

Summary A ground was discovered on the positive lead (black) of the PI circuit causing indication failure of 1-SW-PI 110, 1-SW-P-4 Discharge Header Pressure Transmitter. The Temporary Modification (TM) involves rolling leads at 1-EI-CB-23D TB 7 and 8 and at local junction box JB-2115 TB 1 and 2 for 1-SW-PI-1 10. Swapping the leads will allow the ground to be transferred to the negative (white) side of the circuit, which is normally grounded. This action will restore the circuit to a functional condition, and allow it to be functionally tested and returned to operable status. The transmitter should perform as expected with no spurious signals.

The TM will be installed and remain in place until the associated cable can be permanently repaired. Use of the temporary arrangement is considered acceptable in the short term to restore the channel to operable status.

The long term corrective action will eliminate any degraded condition associated with the existing cable.

These short term and long term corrective actions are compliant with Generic Letter 91-18 (Information on resolution of degraded and nonconforming conditions) guidance regarding the treatment of component operability and restoration of qualification. As previously mentioned, the short term action will allow the channel to be returned to a functional condition and returned to operable status.

UFSAR Section 9.2.1 describes the Service Water System. The TM will not change the purpose or function of the pressure indication loop. A functional test after the configuration change will ensure accuracy and operability of the indication. The reconfiguration will not cause adverse effects in the parameter indication.

The TM is limited to one pressure instrument loop. There will be no affect on any other instruments. Channel separation will not be compromised.

The TM does not involve or create an Unreviewed Safety Question. The indication loop itself is used to monitor the status and performance of the Auxiliary Service Water Pump. The indication is not associated with the initiation of any accident/malfunction or any accident/malfunction precursor. Therefore, the TM will not increase the probability of an accident or malfunction. Since the TM will restore the indication loop to operable status, the instrument will be available to monitor Auxiliary Service Water Pump pressure. As such, the TM will not increase the consequences of any accident or malfunction. No new equipment, instrument components, or new failure modes are introduced, so no new accidents or malfunctions are created. The function of the instrument will remain the same, so no new Technical Specification surveillance requirements are required, nor are any License Condition changes necessitated. Therefore, the margin of safety as described in the Technical Specification Bases for the Service Water System and other related systems is unchanged.

01-SE-TM-04 Description Temporary Modification N2-1140 1.

Temporarily remove coil wires # 73 from both bridge 4A relays, for Polar Crane 2-MH-CRN-Summary and the Electric Overhead The polar crane is designed and constructed to comply with ANSI B30.2.0-1967 for Electric Overhead Traveling Cranes". The rotational speed of the Crane Institute, Inc., "Specification to increase or decrease bridge is controlled by 5 relays that consist of resistor banks. These relays actuate of the two bridge 4A relays is the rotational speed of the four bridge motors in a controlled manner. One This is causing the bridge to jerk to a currently sticking, which is bypassing the first three resistor banks.

high speed from rest when the motors are energized. It is desired to lift coil wires #73 (Vendor Drawing, panel located on the Polar Crane bridge, to bypass Harnischfeger P & H, # 101A5263) in the bridge control This will limit the top speed of the bridge motors, but will the 4A resistor bank to the bridge motors.

provide for speed control.

vendor technical manual, 59 A review of the design specification for the Polar Crane in accordance with A review of the Electric Overhead H800-00001, indicates there are no speed requirements for the bridge.

Cranes" indicates that the trolley and Crane Institute, Inc., "Specification for Electric Overhead Traveling or bridge within a distance in feet equal to 10 percent bridge brakes have been designed to stop the trolley travelling at full speed with full load. Limiting the speed of the of full load speed in feet per minute when Operation of the crane with a bridge motors is within the design of the brakes and is more conservative.

the ANSI Safety Code for load is not affected in any way by this activity. There is no requirement in does not affect the function or limiting the speed of the bridge. Limiting the speed of the bridge motors operation of the crane in any way.

crane bridge speed is not The TM does not involve or create an Unreviewed Safety Question. The polar or any accident/malfunction precursor.

associated with the initiation of any accident/malfunction of an accident or malfunction. Since the TM will Therefore, the TM will not increase the probability the TM will provide for safer operation of the polar crane. As such, restore speed control to the bridge, this new equipment, instrument will not increase the consequences of any accident or malfunction. No failure modes are introduced, so no new accidents or malfunctions are created. The components, or new Specification requirements function of the polar crane will remain the same. There are no Technical changes required. As such, the margin associated with the polar crane, and there are no License Condition of safety as described in the Technical Specification Bases remains unchanged.

01-SE-TM-05 Description 2)

Temporary Modification: No. 1695 (Unit 1) and 1139 (Unit 00447261-Oland 00447261-02 WO # 00447260-01, 00447260-02, ET N-00-134 that will permit performing response time testing with 1-PT-7 1.1 Q and 2-PT-7 1.1 Q - With an OTO change steps to record the maximum flow achieved during the recirculation valve full open. It will also add testing.

in the full flow recirculation line for each turbine The first orifice (1-FW-RO-102A and 2-FW-RO-202A) 345 orifices sized to limit the pump discharge to about driven AFW pump will be removed and replaced by gpm.

Summary lines are fitted with two flow restricting orifices (1-FW Each of the TDAFW pump full flow recirculation the recirculation flow to 809 gpm. Currently, RO-102A/103A and 2-FW-RO-202A/203A) designed to limit gpm. To achieve the targeted test flow range 340 to 345 the TDAFW pumps are tested at flows in the valve position indicator is aligned with the 340-345 range, the recirculation valve is opened until the characteristic of the recirculation valve is such that position marked on the valve yoke. However, the flow inch) in the indicated valve position yield a significant relatively small changes (between 3/32 and 1/8 by impossible to achieve repeatable initial flow rates change (about 270 gpm) in flow. Thus, it is almost marked on the valve yoke.

aligning the position indicator with the 340-345 position line concluded that the first orifice in each recirculation An evaluation conducted per ET N 00-134, Rev. 0, recirculation valve full flow to about 345 gpm with the can be resized and replaced to limit the recirculation during the initial portion for throttling the recirculation open. Replacing this orifice will eliminate the need the uncertainty associated with setting the recirculation valve to the of surveillance tests, and will eliminate precise point to achieve flow in the desired range.

the first orifice in each recirculation line on a Loss This Safety Evaluation assesses the impact of replacing Pipe Rupture.

of Normal Feedwater and a Major Secondary System to begin initially with the recirculation valve full The intent of this modification is to enable pump testing constitute a special test since the recirculation system open. Operating the pump in this manner does not full open or throttled.

was designed for operation with the recirculation valve Work Orders 00447261-01 (Unit 1) and 00447260-01 In summary, the modification will be installed by may be performed with the recirculation valve (Unit 2). Replacement of the orifice at I-FW-RO-102A requires that the pump be tagged before the tagged closed. Replacement of the orifice at 2-FW-RO-202A the pump will then be readied for testing per 1/2-PT orifice is replaced. After each orifice is replaced, change will permit performing response time testing 71.1 Q that will contain an OTO change. The OTO flow change will also add steps to record the maximum with the recirculation valve full open. The OTO achieved during testing.

or affect the likelihood of a loss of normal feedwater The modification and testing described above will not the Main Steam or the to be performed will not affect a major secondary system line rupture as the work consequences of these accidents are not changed. There are no Main Feedwater Systems. Thus, the or This modification will not affect either the main reactivity effects associated with this modification. of the creation of a different valves. The possibility control power associated with the AFW pumps and previously analyzed does not exist. In addition, the proposed modification will have type of accident than as such it cannot cause a failure of the TDAFW pump no effect on the auto start circuitry of the AFW pumps; to start on receipt of an auto start signal.

the recirculation line, which is isolated, when the pump The modification affects only the discharge through the to limit the discharge to about 345 gpm, whereas is in standby. The replacement orifice has been sized new orifice is less than the Since the bore of the original orifice was sized to limit flow to 809 gpm.

currently installed orifice, it is unlikely that the pump will runout during testing. A failure of the orifice during testing, while very unlikely, could result in excessive flow that can lead to pump damage.

Therefore, the OTO par will instruct the operator stationed in the MCR to stop the pump should flow exceed 600 gallons. Thus adequate measures to mitigate significant leaks and orifice failures will be available during this activity. Moreover, the margin of safety for AFW pump operation is not affected. For these reasons, an unreviewed safety question does not exist, and this activity should be allowed.

01-SE-TM-06 Description Temporary Modification - N2-1141 2-AR-T-C2 VPAP-1403 Level Switch - Turbine End) to Lift leads from 2-GM-LS-210-2 (Unit 2 Main Generator Defoaming Tank TANK LEVEL - HIGH) on the clear a locked-in defoaming tank level alarm (2T-C2, DEFOAMING level condition present.

Turbine Supervisory Panel in the MCR (2-El-CB-10) with no high oil Summary DEFOAMING TANK LEVEL The Unit 2 Defoaming Tank High Level Alarm annunciator (2T-C2, MCR. The annunciator is fed by both 2-GM HIGH) is locked-in on the Turbine Supervisory Panel in the Switch - Exciter End) and 2-GM-LS-210-2 (Unit LS-210-1 (Unit 2 Main Generator Defoaming Tank Level

- Turbine End). Both level switches were checked during 2 Main Generator Defoaming Tank Level Switch end) was replaced. The current the March, 2001 Unit 2 refueling outage and 2-GM-LS-210-1 (Exciter an actuation of 2-GM-LS-210-2 alarm condition has been verified by Electrical Maintenance to be from Exciter End Defoaming Tank level (Turbine end). A visual examination of both the Turbine End and oil levels are well below the High indications shows that no high level condition exists in either tank. Both above the oil in the tanks. Based on Level alarm setpoint. A significant layer of foam was found to exist existed for a brief time (possibly during the past experience, it is suspected that a high oil level actually startup of the turbine-generator) and that now the oil level is normal. The layer of foam above the oil, type level switch up in the Turbine end tank and preventing the however, is believed to be holding the float and repair the alarm alarm condition from clearing. A Work Request has been submitted to investigate the potential for disrupting the seal switch. However, due to the difficulty in accessing the level switch and generator on line as long as other oil system, it is prudent to not try to repair the level switch with the options exist.

of 2-GM-LS-210-1 (Exciter end)

The annunciator does not have reflash capability. Therefore, an actuation is desired to clear the locked in alarm from 2-GM-LS-210 will not cause an alarm in the Control Room. It switch. This will provide a warning of any subsequent 2 to allow alarm capability for the remaining from the Exciter end. As the two defoaming tanks are connected defoaming tank high level conditions a high oil level to help indicate through a common line, the level switch in the Exciter end tank can be used (TM), the existing alarm in the Turbine end tank. Without performing this temporary modification 2-GM-LS TM will lift leads from annunciator is useless as a warning tool for changing conditions. The Box 003-2 to

- Turbine End) in Junction 210-2 (Unit 2 Main Generator Defoaming Tank Level Switch place until the modification will remain in clear the locked-in defoaming tank level alarm. The temporary completion of maintenance to repair/replace the switch.

UFSAR (Section 10.2). The The Generator Hydrogen Seal Oil system is only vaguely described in the alarms. The only reference to any description of the system does not include the defoaming tank or its has an alarm system to provide warning of alarms is a brief statement that the Hydrogen Control system will restore the usefulness of the remaining defoaming improper system operation. Performance of the TM operational capability to provide warning of any subsequent tank level switch, and thus will restore alarm of the alarm the TM will improve the current condition problem involving the defoaming tank. Therefore, Oil System.

system and enhance the ability to detect a malfunction in the Generator Seal There are no T.S. LCOs associated with the Generator Seal Oil System.

rotor interface with the Main The Generator Seal Oil System provides an oil seal at the Turbine/Generator from the Main Generator. Hydrogen is used as a Generator housing to prevent the escape of Hydrogen of the system could result in the loss of one or more of cooling medium for the Generator. A malfunction and potentially cause flammable or the Hydrogen oil seals which could cause a loss of Generator cooling be detected by various alarms explosive conditions around the seals. Such a failure of the system would Generator is designed to contain and result in a shutdown of the Main Generator and Turbine. The Main Fire Protection at the machine any explosion without damage to life or property external to the machine.

failure of the Main provides suppression capability to prevent the spread of any fire. Catastrophic needed to safely shutdown the Generator will not adversely affect Safety Related systems or components a Seal Oil system malfunction so that unit. The TM will enhance the ability of the alarm system to detect actions may be taken to correct the condition prior to failure of the system.

any new accident or event As the level switch only provides an alarm function, this TM will not introduce precursors. There are no control or protective functions that are associated with the level switch, therefore, of occurrence of an accident nor will it increase the consequences this TM will not increase the probability per this TM.

equipment is added of any accident. No new accident or malfunction is introduced as no new does not and this TM The level switch is not part of any system required by the Technical Specifications affect any TM does not adversely reduce the margin of safety as described in the bases section. This maintain safe the station to achieve and releases to the environment and does not affect the ability of shutdown in the event of a fire.

performance of the TM.

For these reasons, an Unreviewed Safety Question is not created by the

01-SE-TM-07 Description Temporary Modification #N2-1142 Coolant Pump (RCP), 2-RC-P-1C, seal leakoff The leads are swapped for the Unit 2 "C" Reactor bearing temperature element (2-CH-TE-2125), and temperature element (2-CH-TE-2126) and pump radial (RCP Thermocouple Transfer Junction Box) for it is desired to swap the wires at Junction Box JB-781-2 the temperatures to read correctly on the P-250.

Summary provide indication of the Unit 2 "C" RCP radial Temperature elements 2-CH-TE-2125 and 2-CH-TE-2126 on the P-250, respectively. During the last bearing temperature and shaft seal water outlet temperature in accordance with drawing 12050-FE-7BX per Refueling Outage the wiring was verified to be correct when monitoring the "C" RCP parameters, the shaft Work Order # 428041-01. During the plant startup, appeared suspect. When compared to the "A" seal water return and the pump radial bearing temperatures lower than expected, and the radial bearing temperature and "B" RCPs, the seal water temperature appeared leads for the temperature elements may have been appeared higher than expected. It is believed the swapped during the wiring verification.

Lane (NAPS Operations) dated 4/19/01, indicated An e-mail from B. Harper (NAPS System Eng.) to Larry notion that to those prior to the outage to support the that the current temperature readings were compared 0 before the bearing) indicated approximately 138 F the leads are swapped. 2-CH-TE-2125 (pump radial 0 and 2-CH-TE-2126 (seal water outlet) indicated outage and approximately 167 F after the outage, 123 0F after the outage. It specifically states:

approximately 173 F before the outage and approximately 0

from before and after the refueling "Temperature data across the Unit 2 RCP #1 seals for the "A" and "B" pumps are outage has been evaluated. Radial bearing temperatures outage. This is expected 15 and 23 degrees lower respectively following the refueling temperature). However, the "C" with lower seal injection temperatures (due to lower CC higher than pre-outage data.

RCP radial bearing temperature is currently 29 degrees the seals, it is noted that the "C" When reviewing the differential temperatures across bearing temperature. As there RCP seal water outlet temperature is lower than the radial the "C" RCP radial bearing is no cooling mechanism between those two points, suspect and should be used for temperature indication (2-CH-TE-2125) is considered for this instrument was verified during the trending purposes only. Note that the wiring RCP seal differential temperatures refueling outage under WO 428041-01. Post outage degrees and "C" negative 44 degrees."

are: "A" 43 degrees, "B" 30 Pumps in detail. The journal-type radial pump bearing UFSAR Section 5.5.1 describes the Reactor Coolant elements 2-CH-TE-2125 and 2126 are used to is water-lubricated from seal injection flow. Temperature adverse conditions such as a low or loss of seal evaluate the pump during normal operation and during pump performance, it is desired to swap the leads at injection~leakoff flow. In order to properly evaluate can be properly trended and pump and seal Junction Box JB-781-2 to ensure the "C" RCP parameters Modification (TM) will swap the leads for both performance can be properly evaluated. This Temporary Junction Box, JB-781-2. Referring to Test Loop temperature elements at the RCP Thermocouple Transfer from terminals TA-4, TA-5, TA-6, and TA-10 will Diagram 12050-CH-032 for 2-CH-TE-2125, the leads 12050-CH-033 for 2-CH-TE-2126, the leads from be lifted at JB-781-2. Referring to Test Loop Diagram lifted at JB-781-2. The leads for 2-CH-TE-2125 will terminals TA-14, TA-15, TA-16, and TA-20 will be TA-20, while the leads for 2-CH-TE-2126 will be then be relanded at terminals TA-14, TA-15, TA-16, and relanded at terminals TA-4, TA-5, TA-6, and TA-10.

Question. The temperature indications are used to The TM does not involve or create an Unreviewed Safety Coolant Pump. The indication is not associated with monitor the status and performance of the "C" Reactor precursor. Therefore the TM will not the initiation of any accident/malfunction or any accident/malfunction Since the TM will correctly restore the temperature increase the probability of an accident or malfunction. will be available to properly evaluate the instruments indication for both 2-CH-TE-2125 and 2-CH-TE-2126,

or TM will not increase the consequences of any accident Reactor Coolant Pump performance. As such, the are introduced, so no new or new failure modes malfunction. No new equipment, instrument components,temperature elements will remain the same, that is, created. The function of the accidents or malfunctions are 1 seal leakoff at the pump radial bearing and number to provide indication of seal water temperature are any License surveillance requirements are required, nor temperature. No new Technical Specification Technical Specification the margin of safety as described in the Condition changes necessitated. Therefore, and other related systems is unchanged.

system, Bases for the Reactor Coolant system, Charging

01-SE-TM-08 Description Temporary Modification TM-N I-1697 be repaired until the next outage. This speed pickup Main Turbine speed pickup #4 has failed and can not indication, Bearing Lift Pump (1-GM-P-10), and provides input to the Turbine Supervisory panel's speed input will be used as a one-for-one replacement until the Turning Gear Motor Circuit. A spare speed sensor repairs may be performed at the next refueling outage.

Summary be repaired until the next outage. This speed pickup Main Turbine speed pickup #4 has failed and can not indication and a start permissive to Bearing Lift Pump provides input to Turbine Supervisory panel's speed A spare speed sensor input will be used as a one-for (1-GM-P-10) and the Turning Gear Motor Circuit.

next refueling outage.

one replacement until repairs may be performed at the to Bearing Lift Pump 1-GM-P-10 when turbine speed The failed speed sensor provides a start permissive failed, the lift pump must be left in OFF instead decreases to less than 600 RPM. With the speed indication lift pump control to be returned to AUTO and restore of AUTO. Use of a spare speed input will allow the turbine speed indication to the Turbine Supervisory Panel.

way.

probability of occurrence for any accidents in any This Temporary Modification will not increase the control systems Failure modes of the turbine and its The spare speed sensor is identical to the failed sensor.

speed sensor will result in a start permissive to the Bearing Lift are not affected in any way. Failure of the turbine in any way.

Pump, 1-GM-P-10, which does not adversely affect the consequences of any accidents in any way. The This Temporary Modification will not increase the are identical to those associated with the normal consequences of failure of the Temporary Modification calibration, and operation with the sensor that speed indication. The installed spare is identical in location, has failed.

for an accident of a different type than was This Temporary Modification will not create the possibility installed spare is identical in location, previously evaluated in the Safety Analysis Report since the calibration, and operation with the failed sensor.

01-SE-TM-09 Description Temporary Modification #1143 observe oil level in the lower oil reservoir for Installation of a video camera and associated equipment to stanchion several feet away from the 2-RC-P-IA motor. The camera will be mounted on a free-standing Main Control Room for remote routed to the the oil reservoir sight glass. The output of the device will be monitoring of the level.

Summary associated equipment to observe oil level in The activity evaluated is the installation of a video camera and will be mounted on a free-standing stanchion the lower oil reservoir for the 1-RC-P-lA motor. The camera Two drop lights will be fastened to a handrail in the several feet away from the oil reservoir sight glass.

the camera. The output of the device will be vicinity of the sight glass to provide sufficient lighting for of the level. The camera and its associated routed to the Main Control Room for remote monitoring (TM).

equipment will be installed as a Temporary Modification means to remotely monitor the oil level in the The purpose of the camera installation is to provide a Annunciator for the 2-RC-P-lA oil reservoir reservoir to ensure adequate level. The Main Control Room indicated low level condition. An attempt to drain oil level has been coming in and out of alarm due to an relatively no oil in the tank. Oil was added to the from the RCP oil collection tank revealed that there was to be generated from the low level switch in the reservoir to clear the alarm. The alarm has been verified sight glass. This will allow the level to lower reservoir. It is desired to remotely monitor the oil reservoir glass will be remotely viewed, the TM will be conveniently checked as often as desired. Since the sight than the existing level alarm. In addition, it provide higher quality oil level information to the Operator repeated Containment entries (long term dose will provide a means to trend the indicated level without chances of bearing failure, and thus, savings). Early detection of an adverse level trend will reduce the be noted that a failure of a motor Trip. [It should reduce the chances of an RCP motor trip and Reactor Section 15.4.4) or a Complete Loss of Forced bearing will not cause a Locked RCP Rotor event (UFSAR in the UFSAR. The UFSAR evaluation Reactor Coolant Flow event (UFSAR Section 15.3.4) as described bearing seizure results; this is due to the of an RCP motor bearing failure assumes that no sudden material. It is assumed that the motor will consideration of the melting characteristics of the babbitt demand requires the motor to be shutdown. An continue to run following the failure until high current the loss of one RCP; the remaining two RCPs individual motor bearing failure will ultimately result in continue to run providing forced coolant flow].

such that during a seismic event, it will not The camera and associated equipment will be restrained is not required to function during or damage any safety related equipment significantly (the camera be fastened on a handrail in the vicinity of the following a seismic event). The two portable drop lights will halogen bulb. Two lights will be installed for oil reservoir sight glass. Each light will contain a 100 watt will not be in contact with any equipment, and the reliability in case one of the bulbs bums out. The bulbs surroundings. The lights will be powered from a heat associated with these bulbs will be dissipated by the not be a concern, since it is not expected to be local convenience receptacle. The camera flexible cable will be powered by a 120 volt local receptacle in accelerated during a seismic event. The camera will therefore, failure of the camera will not affect Containment which is not powered from an Emergency Bus; any an Emergency Bus. The breaker supplying the receptacle will provide adequate protection to prevent "shorts" from feeding back and damaging the electrical penetration; therefore Containment Integrity will be Room will be seismically restrained and will be maintained. The monitor located in the Main Control powered 2 Mind printer). The monitor will be located away from the main control panels (next to the Unit is supplied by the 2J Emergency Bus. The addition of from a local 120 volt convenience outlet which receptacles is minimal, and the additional electrical load from the camera and monitor via the convenience Room has been previously evaluated and loading from the convenience outlets in the Main Control distribution system. The camera and associated accounted for in the design of the emergency electrical and stainless steel. In the event of a LOCA equipment are constructed mostly of metals such as aluminum equipment fall to the Containment Sump, the or MSLB, should any pieces of the camera or associated intrusion into the RS and SI pump suction. The screening around the sump would be adequate to prevent

design of the sump and debris screens is such that any related debris that can pass through the series of coarse and fine mesh screening will not adversely affect system components. The area of the screening covered by the debris would be negligible. The sump screen area is approximately 168 square feet; it is judged that any camera and associated equipment related debris would not cover more than 2 square feet.

Engineering has reviewed the estimated amount of aluminum added to the Containment due to the installation of the camera and associated equipment and has determined that it is within allowable specification; therefore, the added post-accident hydrogen generation potential introduced by the installation of the TM is not a concern.

Installation and use of the camera and associated equipment will not change the performance characteristics or the RCP or its support systems. The camera performs no control or protective functions. The camera is essentially a passive device used for monitoring purposes only. No safety related systems or components will be adversely affected by the installation of the camera during normal or accident conditions.

For these reasons, installation of the TM will not create an Unreviewed Safety Question.

01-SE-TM-10 Description Temporary Modification (TM) N I-1696 WO# 434982 01 K-B7 (Generator Leads Cooling Lift the leads at l-GM-TS-102B to disable the input to annunciator Trouble).

Summary air temperature, is alarming prior to the setpoint Temperature switch 1-GM-TS-102B, "B" phase bus duct annunciator K-B7 to lock in on hot days. Since the of 175 degrees Fahrenheit and periodically causes and the annunciator has no reflash capability, temperature switch can not be repaired or calibrated on line, the input to the annunciator until the Winter months.

it is desired to lift the leads from the switch to disable other inputs will have no effect on the alarm Since there is no reflash associated with this annunciator, remove the degraded input to this annunciator.

when it is locked in, and therefore it is beneficial to from the "B" phase bus duct temperature, the Although there will be no input to annunciator K-B7 Leads Cooling Trouble alarm:

following inputs will still be available to cause a Generator duct air temperature; 1-GM-TS-102A & C, high "A" and "C" phase bus main transformer low side bus temperature, 1-GM-TS-103A through -103F, high "A", "B", and "C" return air temperature; 1-GM-TS- 104, high generator bus duct cooling 1-GM-FS-100, low generator bus duct supply air flow cooler 1-GM-FS-101, loss of water flow to generator leads of the cooling air supply 1-GM-MS-100, high relative humidity function than providing an input to K-B7. There are Temperature switch 1-GM-TS-102B provides no other operator to a problem with the generator leads bus numerous inputs to the annunciator that would alert the system which is used to cool the air. In addition to duct air cooling system or the Bearing Cooling Water installed in bus ducting, and therefore, the above mentioned inputs, there are temperature indicators temperatures of each phase can be obtained locally.

an Unreviewed Safety Question for the following This Temporary Modification does not constitute reasons:

K-B7 does not affect any automatic safety

1. Removing the input from I-GM-TS-102B to annunciator functions.

the no Tech Spec requirements and is not described in

2. The temperature switch is not Safety Related, has are not affected.

UFSAR. The probability or consequences of an accident the or malfunction occurring previously evaluated in

3. The probability or consequences of an accident as a result a new accident or malfunction increased SAR is not increased, nor is the possibility of creating of this temporary modification.

an Unreviewed Safety Question and no changes Therefore, this Temporary Modification does not involve are required to the Operating License.

01-SE-TM-11 Description Temporary Modification 01-1698 Approval to install a temporary chemical addition system to the BC system. This temporary chemical addition system will be used to add Calgon Biocide, H-900 in the tablet form, to the BC system. H-900 is approved for use and was normally added to the Bearing Cooling (BC) system per VPAP-2201 and 2202 via the Brominator (1-BC-TK-4) prior to replacement with the activated bromine system. The Brominator had to be removed from service due to an oil-intrusion incident on the BC system (reference PI N-99 2478). The activated bromine system is currently not available due to the failure of pump 1-BC-P-7A (Ref. PI N-2001-1708). Hence, it is being proposed to apply H-900 tablets at the top of the Bearing Cooling (BC) tower in the hot water distribution basin. The tablets will be placed in one or more plastic containers to facilitate solubility and to prohibit direct contact with the wood structure of the tower.

Summary H-900, which was applied via the Brominator (1-BC-TK-4), is an approved biocide for the Bearing Cooling (BC) system per VPAP-2201 and 2202. The Brominator was removed from service due to an oil-intrusion incident on the BC system (reference PI N-99-2478). The brominator was replaced with the activated bromine system that is currently unavailable due to failure of pump 1-BC-P-7A (Ref. PI N-2001-1708).

Hence, approval for the use of a temporary chemical addition system, which will be used to add Calgon Biocide (H-900) in the tablet form to the BC system, is being sought. It is being proposed to apply the H 900 tablets at the top of the Bearing Cooling (BC) tower in the hot water distribution basin. The tablets will be placed in one or more plastic containers to facilitate solubility and to prohibit direct contact with the wood structure of the tower. The oxidizing agents in H-900 promote wood decay when used in high concentrations over extended periods of time. This interim application will not produce any long-term effects.

To address the plant safety significance of the TM, the following accidents per the SAR were considered:

UFSAR Chapter 15.2.8 - Loss of Normal Feedwater: The loss of Bearing Cooling could result in a Main Feedwater pump trip or failure because the BC system provides pump seal-oil cooling.

It is unlikely that this interim use of H-900 in the tablet form in the Bearing Cooling tower would result in the loss of Bearing Cooling. This TM does not increase the probability of occurrence or increase the consequences of the Loss of Normal Feedwater accident. The plastic container used to deliver the H-900 is larger than the flow holes through which the BC water cascades down in the wood structure. Additionally, this modification does not impact any safety systems used to mitigate this accident, mainly Auxiliary Feedwater and its associated components.

UFSAR Chapter 6.4 Habitability Systems, for the Control Room to ensure that continuous occupancy of the area is possible for the events described in chapter 3 as well as all the postulated accidents discussed in chapter 15.

The use of H-900 in tablet form will not impact the Control Room habitability analysis. The H-900 biocide will be used on site in small quantities (40-50 lb.). Bulk storage (>100 lb.) will remain in warehouse #7, which is greater than the required .3 miles. H-900 in crystal form, is an approved chemical for use in the BC system. This chemical will be handled and administered by trained chemistry technicians in accordance with Chemistry Special Order 01-005 and procedure CH-99.301.

Thus, no unreviewed safety question exists.

Note: This safety evaluation can be used as the basis for approval of a procedurally controlled temporary modification if a future need should arise.

01-SE-TM-12 Description Temporary Modification #1144 box RCPV 16B to disable the Unit Install an electrical jumper between terminals 2-15 and 2-16 of junction LEVEL."

2 Control Room annunciator 2C-F 1, "RCP 1A OIL RES HI-LO Summary box jumper between terminals 2-15 and 2-16 of junction This temporary modification installs an electrical IA OIL RES HI-LO LEVEL."

2C-F1, "RCP RCPV 16B to disable the Unit 2 Control Room annunciator the level in the lower motor bearing oil reservoir on the "A" RCP is This activity is being done because frequency of the low level alarm is causing a distraction oscillating at the lower alarm limit. The increased ability to this jumper will enhance the Board Operator's to the Control Room Board Operators. Also, The most likely cause of the condition has been respond to level alarms from the upper oil reservoirs. remote through a vent pipe between the reservoir and its tentatively identified as a restriction in the air flow level indication.

conjunction alarm. It states that this alarm shall be used in The UFSAR specifically addresses this oil level Pump shutdown is required in the operation of the pump.

with bearing temperature indication to monitor will not be altered by this Temporary characteristics event of high bearing temperatures. Performance of the bearing temperature indication and P-250 alarms, will provide adequate Modification. Monitoring from setpoint for P-250 point T0415A will be lowered assurance that the pump is not degrading. The alarm necessary for changing ambient conditions.

1850 F to 1400 F. The setpoint can be adjusted as defeats potential for any evaluated accidents. The TM only Jumpering out the annunciator can not affect the of occurrence of the alarm will decrease the frequency the RCP motor lower oil reservoir level alarm. This jumper will in no way affect Board Operators. The which is currently causing a distraction to the Control bearing failure, it will not cause a there is a single motor the operating characteristics of the RCP. Also, if flow' event. UFSAR Section 5.5.1.3.4 reactor coolant

'locked RCP rotor' or a 'complete loss of forced bearings, based on this discussion bearing failure will not affect the consequences of discusses failure of the will not affect the Board Operator's ability to monitor any UFSAR analyzed accidents. Disabling the alarm a the ability to mitigate and recover from effects of bearing temperatures, so there is no way to affect chapter 15 accident.

locked RCP rotor, a loss of all RCP's or any other analyzed the plant to essentially lose indications Because the UFSAR section 5.5.1.3.4 has already mode associated with the bearings, defeating the pertaining to monitoring RCP bearings and the failure of a different type. Disabling the annunciator annunciator does not create any accidents or malfunctions of the RCP will continue via bearing fail. Monitoring does not increase the probability that the bearing will any control or protective functions for the RCP.

temperatures. The TM will not provide or remove the of the bearings-this is not altered by disabling The UFSAR has a discussion of the failure mode or manual reactor trip, dependent on at is an automatic annunciator. The consequences of an RCP failure a result of disabling the RCP motor lower not change as power plant conditions-this failure mode is also annunciator. No adverse operational effects are introduced by using this jumper.

oil reservoir level The RCP motor lower oil reservoir level annunciator.

Margin of safety is not reduced by defeating the equipment. This they do not affect accident mitigation annunciator, nor the bearings are TS equipment, and to TS's or the Operating License.

jumper does not require any changes Question exists.

Based on the above discussion, no Unreviewed Safety

01-SE-TM-13 Description Temporary Modification - N2-1145 (2-CD-MR-1) compressor high thrust This Temporary Modification will defeat the Mechanical Chiller normal bearing oil temperature.

bearing oil temperature trip due to the Chiller tripping with Summary to a faulty bearing module in the Chiller The Mechanical Chiller has been unnecessarily tripping due is to sense the Chiller compressor thrust Control Panel (2-EP-CB-59). The purpose of the bearing module the compressor via temperature switch, 2-CD bearing oil temperature via RTD, 2-CD-TE-702, and to trip actual module consists of the temperature TS-702, when oil temperature reaches its setpoint of 201'F. The switch.

The jumper will consist of landing a lead across the thrust temperature switch, 2-CD-TS-702, terminal points "CC" to "CC". By doing this, the Chiller compressor bearing high oil temperature automatic trip is protection to the Chiller components defeated. All other automatic Chiller trips will continue to provide this jumper. An Operations or HVAC group individual will and will not be affected by the installation of is in place. The function of this individual be locally stationed at the Mechanical Chiller while this jumper temperature via the local temperature will be to continuously monitor the compressor thrust bearing increases to above 1900F.

indicator and to manually trip the Chiller in the event oil temperature an additional factor of safety with the The temperature trip requirement of 190'F was chosen to provide trip defeated. It will give the individual Chiller compressor thrust bearing high oil temperature automatic to manually trip the Chiller and ensure the monitoring the Chiller parameters adequate time to take action does not warrant a setpoint change since automatic temperature limit of 2011F is not exceeded. This the Chiller at a temperature below 201'F is defeating the auto trip is temporary and manually tripping added protection against damage to the compressor thrust bearing.

bearing oil temperature does not manually trip In the event the individual monitoring the compressor thrust most likely trip on compressor motor the Chiller, the thrust bearing may fail, and the Chiller would bearing failure and subsequent Chiller trip overload or high motor temperature. The consequences of the partial air pressure decreasing and would be an increase in chilled water temperature, containment Fans (CARF's) would have to be containment temperature increasing. The Containment Air Recirculating containment partial internal air pressure to be swapped to service water. Tech. Spec. 3.6.1.4 requires the 3.6.1.5 requires that containment average maintained greater than or equal to 9.0 psia and Tech. Spec.

F and less than or equal to 120 degrees F.

temperature be maintained greater than of equal to 86 degrees the gas stripper vent chillers, The primary loads on the Mechanical Chiller are the CARF cooling coils, Loss of chilled water to the gas recombiner after cooler, as necessary.

sampling coolers and the waste CARF's is addressed by abnormal procedure AP-35.

following:

This does not pose an unreviewed safety question because of the The UFSAR clearly states that the chiller

1) The Mechanical Chiller is not a safety related component.

to maintain the plant in a safe condition".

"does not supply water to equipment that is required to operate with the Chilled Water System.

2) No Technical Specification deals either directly or indirectly some measure of protection and input to the

3) The individual stationed locally at the Chiller will provide trip feature which protects the chiller.

compressor thrust bearing high oil temperature automatic and all other chiller trips and protective The likelihood of a chiller fault is not considered to be very great cooling to the CARF's removes the functions remain in affect. The use of the chiller to provide and readiness of that system to provide requirement for the SW system to do so and improves the reliability heat sink.

essential core cooling and meet the requirements of an ultimate

SAFETY EVALUATION LOG PROCEDURES 2001 SNSOC Date Unit Document System Description 1-04-01 1 NA-M-DSE-800 Makes a OTO change to a switchyard procedure to adjust 01-SE-PROC-01 the position of the inlet isolation valve on the #1 cooling (OTO1) bank of the U1 "A" main transformer, 1-EP-MT-1A, in an attempt to stop the internal rattling 3-02-01 1,2 ICP-RP-1-RPI-1, Att. 2 Procedure-controlled temporary mod to jumper in regulated 01-SE-PROC-02 temporary power to the RPI system in the event the normal ICP-RP-2-RPI-1, Att. 2 power supply fails 3-07-01 Provides for opening the "B" RCS loop bypass valve, 2-RC 01-SE-PROC-03 2 2-OP-3.2 (Rev. 41) MOV-2586, in Mode 3 while shutting down for refueling 3-12-01 Installs a temporary hose between an SI accumulator vent 01-SE-PROC-05 2-OP-5.7 (Rev. 9) & a drain off of the RHR relief valve discharge line 3-12-01 New procedure provides guidance for transferring water 01-SE-PROC-06 0-OP-16.11 (Rev. 0) between the BRT and the Unit 2 RWST as a means of recovering the borated water.

3-23-01 Uses a procedurally controlled TM to allow recovery of loop 01-SE-PROC-07 2 2-OP-6.2 (R.15-P1) stop valve leakage from the PDTT pump discharge to the RP system.

3-27-01 Provides an alternative method to fill the SI accumulators 01-SE-PROC-08 2-MOP-7.31 (Rev. 1) from the refueling purification system while the RP system is lined up in one of the following configurations: (1) recirc to the U2 RWST; (2) U2 cavity to cavity; (3) pump down of the U2 RCS to the U2 RWST.

3-30-01 Allows opening of the loop stop valves to support backfill of 01-SE-PROC-09I 2 2-MOP-5.98 (Rev. 0) drained loops one at a time from the water in the reactor cavity 4-17-01 Implements a change of reactor coolant chemistry pH 01-SE-PROC-1 I 1,2 VPAP-2201 (R. 7) control from the current "coordinated" program to a modified CH-97.100 (R. 6) program which allows the pH(t) to increase as the fuel cycle progresses from an initial pH(t) of 6.9 to a final pH(t) of 7.4.

VPAP-0306, Att. 3 5-17-01 0-OP-4.13 (R. 0) "Inspection of Fuel Assembly Thimble Sleeves" 01-SE-PROC-11 1,2 5-24-01 1-MOP-31.35A New procedures to allow removal from service & return to 01-SE-PROC-12 1,2 1-MOP-31.35B service of selected drain coolers & FW heaters. Also permit 2-MOP-31.35A maintenance on these HX during plant operation.

2-MOP-31.35B 6-12-01 0-OP-52.1 (R. 3) Installation & removal of an electrical jumper that will defeat 01-SE-PROC-13 1,2 a domestic water (DM) booster pump's alternating circuit input in order to facilitate maintenance on a DW booster pump.

8-21-01 Nozzleless Fuel Assembly Handling Tool - this tool may be 0-OP-4.11 (R. 0) used to move F/As that have exhibited the potential for top 01 1,2 ET NAF 2001-0071 nozzle separation.

I

SAFETY EVALUATION LOG PROCEDURES 2001 SNSOC Unit Document System Description Date 01-SE-PROC-15 1,2 0-OP-4.13 (R. 1) Provides instructions for visual inspection of irradiated fuel 12-04-01 assemblies (F/A), which may possibly have degraded thimble sleeves. Fuel handling performed under this procedure consists of lifting the F/A a maximum of 4 ft, while the assembly remains inside the spent fuel pool rack cell in order to perform the visual inspections. Lifting will be performed with the station's spent fuel handling tool (not the nozzleless handling tool).

.1. 1 .4. 4

___________ +/- I - I ______

+ 4 -t 4 r

.4- 4 4 r I .4- 4 r

4. 4 + *

4. 4 4. 4 .4-J I J. & 4 2

01-SE-PROC-01 Description NA-M-DSE-800, "Substation Electrical North Anna Switchyard Substation Maintenance Procedure, Equipment Minor Maintenance/Troubleshooting".

bank of the Unit 1 'A' Main Transformer, Adjust the position of the inlet isolation valve on the # 1 cooling 1-EP-MT-1 A, in an attempt to stop the internal rattling.

Summary a forced-air and forced-oil cooled system to The Unit 1 'A' Phase Main Transformer, I-EP-MT-1A, uses sets of fans located on 4 sets, or banks, of oil air remove the heat from the transformer windings. There are 16 is currently tagged out due to internal coolers. The # 1 cooling bank of the Unit 1 'A' Main Transformer With this cooling bank unavailable, the cooling noise/rattling coming from the cooler inlet isolation valve.

decreased, and it is desired to have all cooling banks capacity for the Unit 1 'A' Main Transformer is available, especially during warmer weather.

Procedure, NA-M-DSE-800, "Substation In accordance with North Anna Switchyard Substation Maintenance the # 1 cooling bank cooler inlet isolation valve Electrical Equipment Minor Maintenance/Troubleshooting",

rattling. More specifically, the valve will be position will be adjusted in an attempt to stop the internal flow will not be allowed to drop below 850 partially closed in an attempt to stop the internal noise, however, modified and placed in the "over-toggle" position. The gpm +/- 10%. If this is unsuccessful, the valve will be lever and fastening on a new lever so modification will consist of cutting a portion of the existing operating fails to stop the valve noise, all further attempts that it could be moved past its open stop. If the modification will be terminated.

relied upon for the safe operation of the plant.

The Main Transformers have no safety functions and are not function to isolate the cooling unit from the The oil air cooler isolation valves are butterfly valves and 1 cooling bank and is physically located at the top of transformer. The valve that is rattling is the inlet to the #

4 are in service with bank 3 in manual and the the 'A' Main Transformer. Currently, cooling banks 2 and to stop the internal rattling should bank I oil pump tagged out. Failure of the valve adjustment/modification ambient temperatures are cooler.

of year since have no impact on the transformer performance at this time to operate on warmer days, and the unit may be required to be ramped However, all banks may be required not be maintained below approximately 90 down or offline if transformer winding and oil temperatures can degrees Celcius.

will be performed by Substation personnel The valve adjustment and/or modification to the operating lever personnel safety with any work on or near an energized familiar with the equipment. There is risk to exists anytime oil flow through the transformer. A potential for static electrification in the transformer include high oil flow rates and low oil transformer is changed. Factors contributing to this condition throttled in the closed direction, temperature. For this activity, if the internal rattling stops when the valve is requires modification to the If the valve the oil flow rate through the bank I cooling unit will be decreased. oil temperature, and the winding temperature, over-toggled position, the flow rates may be higher. However, basis, and action would be taken to prevent oil flow rate in the Main Transformers are monitored on a regular these risks and are qualified to perform the this condition from occurring. Substation personnel are aware of work.

Specifications Bases is not altered since the The margin of safety for the station as described in the Technical Based on the above major issues Main Transformers are not described in the Technical Specifications.

of the unit to shutdown and remain shutdown considered, there is no unreviewed safety question. The ability in the event of a transformer failure or fire is not affected.

UNREVIEWED SAFETY QUESTION ASSESSMENT:

troubleshooting will not adversely affect the

1) Accident probability has not changed because the planned back into the switchyard to cause a station main transformer. No faults could be developed that would feed

blackout event. Loss of transformer cooling would require a unit power reduction but would not produce a sudden loss of turbine load.

2) Accident consequences are not increased. No safety equipment is affected by the proposed troubleshooting.

If a loss of offsite power were to occur, the EDGs would operate to supply emergency power. The ability to remove the excess steam load on a loss of turbine load accident is not affected. The Main Steam safety valves, Main Steam PORVs, and steam dumps would all function as designed.

3) No unique accident probabilities/possibilities are created. The proposed troubleshooting will be performed by Substation personnel who are familiar with the power transformers. The work will be performed in accordance with a preplanned procedure. The only affect of the troubleshooting will be to the Unit 1 'A' Main Transformer cooling unit. All accident analysis remains bounded.

01-SE- PROC-02 Description ICP-RP- 1-RPI-I Attachment 2 ICP-RP-2-RPI- 1 Attachment 2 Procedurally controlled temporary modification (PCTM) to jumper in regulated temporary power to the RPI system in the event the normal power supply fails.

A temporary power supply to the RPI system will be used to provide power in the event the normal power supply (H-Bus Sola Transformer 01-EE-VREG-2, 02-EE-VREG-2-2) fails or to repair/replace a malfunctioning unit. The temporary power will be provided from the installed J-Bus transformer (01-EE TRAN-92 / 02-EE-TRAN-92-2) through a portable power conditioner. The power conditioner will receive an unregulated input from the J-Bus Transformer and provide regulated power to the RPI cabinets that meets the system input power requirements.

Summary A temporary power supply to the RPI system will be used to provide power in the event the normal power supply (H-Bus Sola Transformer 1-EE-VREG-2/2-EE-VREG-2-2) fails. The temporary power will be provided from the J-Bus (transformer 01-EE-TRAN-92 / 02-EE-TRAN-92-2) through a portable power conditioner. The power conditioner will receive an unregulated input from terminals located in the back of the "B" RPI cabinet and provide regulated power to the RPI cabinets that meets the system input power and regulation requirements.

The RPI system will function as designed with the temporary power supply installed and will maintain its function in the event of a loss of offsite power. Installation will occur only in the event of the loss of the normal power supply due to failure or the need to repair/replace a malfunctioning unit. During the power swap-over individual rod position indication will be lost briefly but the step counters will be unaffected ensuring the operators of continued but limited rod group position surveillance capability. Since the RPI system is isolated and separate from the Rod Control system, the power swap-over will not affect the operator's ability to move control rods.

The temporary power supply will be installed in a fashion that meets the seismic requirements of VPAP 0312 and will utilize an emergency bus (J-Bus). The temporary power supply will be as reliable as the normal power supply and meet the input power and regulation requirements of the RPI system. Per Corporate I&C Engineering, EMI/RFI concerns will be precluded by including steps in ICP-RP-I-RPI-1 and ICP-RP-2-RPI-1 Attachment 2 that ensure the portable power conditioner is positioned such that it will not affect the protection or control circuitry. The power supply swap-over will be made in a "break-before-make" fashion thus ensuring that the emergency busses are not cross-tied. Per Corporate Power Engineering, the Unit 1 & 2 J EDG loading calculations assume 100% loading of transformers 01 EE-TRAN-92 & 02-EE-TRAN-92-2; therefore, this PCTM will not create any additional loading on the J Bus that has not already been considered.

This PCTM meets the input power and regulation requirements of the RPI system and will not affect the operation of the system once installed. The temporary power supply is isolated from the J-Bus by a transformer and breaker; therefore, will not adversely affect the emergency busses or any other plant systems. The RPI system is separate and isolated from the Rod Control system; therefore, this activity cannot affect the movement of control rods or the Rod Control system. Installation of this PCTM will not increase the probability of occurrence or consequences of a loss of offsite power or a control rod accident, nor will it create the possibility of an accident not previously evaluated in the SAR. Installation of this PCTM will not increase the probability of occurrence or consequences of malfunctions of equipment important to safety, nor will it create the possibility of equipment malfunctions not previously evaluated in the SAR. The deliberate loss of the RPI system for a brief period of time to swap to a temporary power supply is preferable to a permanent loss or unreliable operation of the system and is in keeping with the desire to maintain the margin of safety as described in the basis section of tech specs. T.S. 3.0.3 will be entered during the period of time that the individual rod position indications are lost.

any unreviewed safety questions and will maintain This PCTM should be allowed since it does not present power supply to the RPI system.

adequate safety margin while providing a reliable temporary

01-SE- PROC-03 Description 2-OP-3.2 - Unit Shutdown From Mode 3 to Mode 4, Revision 41 Open the "B" RCS Loop Bypass valve, 2-RC-MOV-2586, in Mode 3 while shutting down for refueling.

Summary The activity is to energize and open the "B" RCS Loop Bypass valve (2-RC-MOV-2586) in Mode 3 to flush the 8" bypass line. It is expected that this activity will reduce the dose rates for maintenance activities planned for the "B" Loop during the refueling outage.

Tech Spec Considerations With the bypass valve open the B RCS loop will be conservatively considered INOPERABLE as a heat removal method due to slightly reduced flow through the core (TS 3.4.1.2.a Action: Restore prior to Mode 2)

RCS Loop Flow Reactor Trip TS 3.3.1.1 Item 12 will be INOPERABLE since it will not be sensing flow through the core (due to bypass flow through 2-RC-MOV-2586) Action: Secure bypass flow prior to Mode 1.

TS 3.8.2.7, (TRM Table 9.2-1) requires the supply breaker to 2-RC-MOV-2586 (2-EE-BKR-2H1-2S-F3) to be open. Action: Deenergize in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Note: TS 3.8.2.5 (TRM Table 5.1-2) requires the breaker to be OPERABLE.

TS 3.8.1.1, The EDG loading does not take into account the subject MOVs. However, MOVs are momentarily energized devices and are only considered in EDG loading during the first few minutes of EDG loading for accident/loop initiated actuations. Also, the valve is manually operated, and the brief energization of this valve in Mode 3 will not impact the EDG loading. It will be placed back into its normally de-energized condition once this evolution is over. 2H EDG will be considered OPERABLE while 2-RC-MOV-2586 is energized.

Non LOCA Analysis Considerations Currently, Unit 2 is operating with about 308,000 gpm total vessel flow, as opposed to a safety analysis thermal design minimum flow of 278,400 gpm for Mode 3 accidents. [Note that the 295,000 gpm required minimum flow in Technical Specification Table 3.2-1 is only applicable in Mode 1]. Therefore there is more than adequate flow margin to accommodate the expected effect of the bypass line being open. Since the available flow margin (29,600 gpm) is well in excess of the estimated flow penalty for opening the bypass line (<17,000 gpm), and the RCS remains intact, all of the HZP non-LOCA accident analyses presented in UFSAR Chapter 15 remain bounding.

LOCA Analysis Considerations With 2-RC-P-1B in service and 2-RC-MOV-2586 open, there is a potential path between the 'B' loop cold and hot legs through which ECCS flow can bypass the core, making it less effective for core cooling. It is expected that ECCS flow injected into 'B' loop will still aid in maintaining overall RCS coolant inventory.

With the "B" RCP shut down, the "B" cold leg cooling capability is unchanged with the bypass valve open.

The evaluation of this situation for postulated LOCA events is presented below. With the bypass valve open in Mode 3, the ECCS operability requirements of TS 3.5.2 are satisfied, ensuring that two independent ECCS subsystems are operable and capable of automatically injecting upon receipt of a safety injection signal. This would provide, at a minimum, the flow from one LHSI pump and one charging pump.

LBLOCA - The ECCS flow bypass is only a concern if 'B' loop is one of the intact loops, since design basis LBLOCA analyses assume all injected flow is lost from the broken loop. The minimum flow requirements for mitigating a LBLOCA can be determined from Attachment 2 of Emergency Operating Procedure 2-

ECA- 1.1, entitled Minimum SI Flow Rate Versus Time After Trip. This figure is based upon time after trip, assuming initial hot full power conditions, and defines the flow required to remove core decay heat. At one minute after trip, a minimum flow of approximately 640 gpm is indicated. The cooling requirements under the present situation are significantly less than this, since the initial condition is Mode 3. Even if it is assumed that all of the flow injecting into 'B' loop bypasses the core, and all ECCS flow through either 'A' loop or 'C' loop is lost through the break, flow would still be injected from one LHSI and one charging pump branch line. The sum of these flowrates exceeds the 640 gpm necessary for decay heat removal. This cooling capability would provide abundant flow to maintain any core heatup within the acceptance criteria of 10CFR50.46.

SBLOCA - WCAP-12476, "Evaluation of LOCA During Mode 3 and Mode 4 Operation for Westinghouse NSSS," documents an evaluation of Westinghouse plant response to postulated LOCA events in Mode 3 and 4. It was concluded that for three loop plants, response would be within the acceptance criteria of 10CFR5 0.46 if flow from one charging pump was initiated at 10 minutes. Accumulators were assumed to be unavailable for the Mode 3 evaluation in WCAP-12476 since it was assumed that RCS pressure was below the point at which accumulator MOVs are isolated (1000 psig for NAPS).

Summary A review of the UFSAR Chapter 15 accidents indicates that the current accident analyses remain bounding for the proposed condition. This is based on the following:

"* For the non LOCA accidents, the RCS remains intact and therefore the FSAR analysis remains bounding by virtue of the flow margin discussion above.

"* For the LOCA events, the effect of the bypass line on SI flow delivered to the core is acceptable. If we assume that the effect of the bypass line would result in SI flow being delivered to only one loop (broken loop spills and loop B injection bypasses the vessel and core) the delivered flow to the intact line would still be adequate to remove decay heat at shutdown, as discussed above.

For these reasons, the consequences of accidents considered are not increased. The RCS pressure boundary is not affected; therefore, the probability of occurrence of a Loss of Coolant Accident is not increased.

Affected equipment is being operated as designed; therefore, the activity does not create the possibility of accidents not previously considered. Based on the above, an unreviewed safety question does not exist.

Since the activity will reduce the dose rates for planned maintenance in the "B" loop room without jeopardizing safe station operation in Mode 3, the activity should be allowed.

01-SE- PROC-05 Description 2-OP-5.7, Operation of the Pressurizer Relief Tank (PRT)

Install a temporary hose between an SI accumulator vent and a drain off of the RHR relief valve discharge line.

Summary Due to flow restrictions that exist in the installed nitrogen supply line, it is desired to provide an additional controlled source of nitrogen to the PRT to provide a slight overpressure to the RCS as part of the normal RCS draindown from 28% to 74 inches. The proposed procedure change will use a hose rated for at least 100 psig to supply nitrogen from the "A" SI accumulator vent to the RHR relief valves discharge line and then to the PRT. This configuration will allow the control room operator to control RCS overpressure by opening the pressurizer PORV and controlling the makeup flow of nitrogen to the SI accumulator with its supply HCV.

Personnel safety will be ensured by maintaining the nitrogen supply pressure from the accumulator at approximately 50 psig and by physically restraining the hose at the connections in accordance with standard Operations practice. This will prevent the the hose from whipping. In addition, a check valve will be provided on the jumper discharge side which will limit the amount of radioactive gas that could be released from the PRT if the jumper hose were to be cut or damaged.

Equipment safety is provided by at least one pressurizer PORV and its associated block valve maintained open and the PRT rupture disc. The nitrogen pressure to the RCS will be limited to less than or equal to 50 psig. This pressure will provide a back pressure to the RHR relief valves which will tend to increase the pressure at which those valves will lift. However, the main RCS overpressure protection will still be the PRT rupture disk which will be unaffected by the additional nitrogen makeup source.

An unreviewed safety question is not created because:

(1) The probability of an accident or malfunction previously evaluated in the SAR occurring is not increased.

The change does not introduce any accident initiators. The unit is shutdown and will be in Mode 5 while this change is active.

(2) The consequences of any accident or malfunction previously evaluated in the SAR are not increased. No fission product barriers are compromised by this change. The unit is shutdown and will be in Mode 5 while this change is active.

(3) The possibility of creating a new accident or malfunction has not increased. The change will be installed by qualified personnel and using appropriate safety guidelines. The control room operator will have control of the nitrogen supply via the SI accumulator makeup HCV. A jumper hose rupture does not breach the RCS boundary because of the installed check valve.

Because the change is not an undue risk to personnel safety or reactor safety, this procedure change should be allowed.

01-SE- PROC-06 Description O-OP-16.11, Makeup to Unit 2 RWST From The Boron Recovery Tanks O-OP-16.11 is a new procedure to support the recovery of borated water that is otherwise lost during a refueling outage. A Boron Recovery Tank will be used as a source of makeup water to the Unit 2 RWST.

Summary O-OP-16.11 is a new procedure designed for transferring water between a Boron Recovery Tank and the Unit 2 RWST. During refueling outages, a significant quantity of borated water will collected in the in-service Boron Recovery Tank. Recovery of this borated water back to the RWST will result in cost savings and reduce the amount of water that must be discharged back to the environment. The procedural actions are the similar to other RP alignments such as transferring refueling cavity water back to the RWST and maintenance related activities previously evaluated in 96-SE-PROC-05 and -32.

The overall operation of all involved systems will not be altered. Boron concentration of the RWST is maintained within allowable limits by calculations prior to the initiation of the transfer and by sampling afterwards. A significant portion of the RP piping is non-seismic and it will be aligned to the RWST when the RWST is required to be operable. This condition has been previously evaluated in 96-SE-PROC-25 for Engineering Transmittal CE-96-014 which addressed the non-seismic characteristics of the RP system.

These contingency actions will be put in place to protect the plant from a loss of the RP system due to a seismic event. These contingency actions are described in the Engineering Transmittal and are included in the procedure. RWST boron concentration and level are maintained within their Technical Specification allowable limits by administrative requirements that are included in the procedure. These actions will ensure enough borated water remains in the RWST to perform necessary functions. Design features prevent the loss of the entire spent fuel pit or reactor cavity during a seismic event where the RP system is lost.

Accident precursors are not affected by contingency actions designed to isolate the RP system from safety related systems necessary to respond during the postulated accident. Since these actions cannot affect the accident precursors, the probability of any postulated accident or loss of equipment is not altered. Therefore, the probability of occurrence of accidents or malfunctions of equipment previously evaluated in the SAR is not increased.

The contingency actions are designed to isolate the non-seismic piping of the RP system from any system needed during the postulated accident. The administrative requirements to calculate and sample the RWST ensure that it remains fully operable. Since these contingency actions and administrative requirements ensure the continued availability and operability of all necessary systems, the consequences of any postulated accident have not been altered. RP system contingency actions will not adversely affect equipment required to mitigate malfunctions of equipment previously analyzed. Therefore, the consequences of accidents or malfunctions of equipment previously analyzed are not increased.

The overall operation of the RP system and the RWST is not altered. The non-seismic portions of the RP system will be isolated in the event of a seismic event and RWST boron concentration and level are maintained within required limits. Therefore, existing analysis is still valid and no other accidents are postulated. The overall operation of the RP system and the RWST is not altered. Therefore, the probability of occurrence or consequences of accidents or malfunctions of equipment not previously analyzed are not increased.

RP is not a Technical Specification system. Contingency actions and administrative requirements will ensure that Technical Specification systems remain fully operable during any postulated seismic event. Therefore, the margin of safety as reflected in the bases of the Technical Specifications is not reduced.

Given the above conclusions, no unreviewed safety question exists.

01-SE- PROC-07 Description 2-OP-16.2 Revision 15-P 1 This TM change is being developed to allow recovery of loop stop valve leakage from the PDTT pump discharge to the RP system. This procedure will allow the installation of a hose and a check valve between the discharge of the PDTT pump and a vent valve on the RP system back to the Refueling Cavity.

Summary A temporary modification is to be added to procedure 2-OP-16.2 as a method for loop stop valve leakage recovery. This procedure will allow the installation of a hose and a check valve between the discharge of the PDTT pump and a vent valve on the RP system to the Refueling Cavity. This change will allow recovery of the leakage when the RHR system is unavailable.

The difference in elevation between the connection at the PDTT pump discharge and the Refueling Cavity water level is 76 feet. The PDTT pumps are rated for 120 feet of discharge head at a flow rate of 60 gpm.

The rated discharge pressure of the PDTT pumps is 53 psig. The procedure allows the use of both PDTT pumps if required. Operating both of the PDTT pumps in parallel will result in a minimal increase in the discharge head of the pumps; therefore, using a hose that is rated for 250 psig is acceptable.

The temporary modification will be leak checked when placed in service. Failure of the hose would result in water from the PDTT being pumped on to the containment floor until the leak is terminated. The Loop Stop Valves will be closed during the period that this temporary modification is installed which will limit any leakage to the PDTT. Refueling Cavity level will be preserved by the check valve that is to be installed near where this Temporary Modification ties into the RP system. This procedure will only be used during a de fueled condition, so the safety significance is negligible.

Failure of the temporary check valve could cause a reduction in Refueling Cavity and Spent Fuel Pit level; however, this Temporary Modification will normally be used with the transfer canal gate valve closed.

Maintaining the transfer canal gate valve closed is not a procedural requirement and its configuration does not affect this evaluation. This TM will only be installed when the unit is de-fueled and it will be removed prior to core on-load. The transfer canal gate valve is normally closed in this condition.

An Unreviewed Safety Question does not exist based on the following:

Implementation of this TM will not increase the probability of occurrence of an accident or malfunction of equipment previously analyzed. Failure of the TM will not affect equipment and systems used to respond to the considered accidents. The ability to provide makeup to the RCS and cavity are not reduced by implementing this TM. Implementation of this TM has no effect on systems or equipment required to provide backup cooling to the reactor vessel or spent fuel pit. The design function of the RP system will not be adversely affected by this TM. Therefore, implementation of this TM will not increase the consequences of an accident or malfunction of equipment previously analyzed.

The TM will be installed with no fuel in the Reactor Vessel, when the core cooling function of RHR is not required. Catastrophic failure of the TM could result in a loss of Cavity inventory; however, even if the transfer canal gate valve were open to the Spent Fuel Pool, the leakage would be detected locally or remotely from MCR indications and would be isolated locally prior to the development of any adverse inventory condition. The TM will not interface with other systems that are required for any safety function. Therefore, implementation of this TM will not create the possibility of an accident or malfunction of equipment not previously analyzed.

Implementation of this jumper has no effect on the basis section of the Tech Specs. Therefore, the margin of safety as defined in the bases to the Tech Specs is not reduced.

01-SE- PROC-08 Description 2-MOP-7.31 This procedure change provides an alternative method to fill the Safety Injection (SI) Accumulators from the Refueling Purification (RP) system while the RP system is lined up in one of the following configurations:

1) Recirc to the Unit 2 RWST

2) Unit 2 Cavity to Cavity

3) Pump down of the Unit 2 RCS to the Unit 2 RWST Summary The normal method of filling an SI Accumulator is from RWST via the Hydrostatic Test Pump. Filling three accumulators using the normal method is slow and designed for normal makeup at power. It is desired to fill the SI Accumulators in a more timely manner. The proposed changes will allow the SI Accumulators to be filled by installing a temporary modification and fill from the RP system which is lined up to take a suction from either the Reactor Cavity or Unit 2 RWST.

The first method (2-MOP-7.31, Section 5.13) involves filling the SI Accumulators from the RP System with the RP System suction source from the Unit 2 Cavity. A temporary hose is installed between the RP pump discharge, downstream of the RP Filters and Ion Exchanger, and the SI Accumulator fill line downstream of the Hydro Test pump. The normal Accumulator fill line trip valves control which Accumulator is being filled.

The water will be supplied from the cavity, and the fill rate will be controlled by throttling at the RP pump discharge connection. The RP system parameters (RP Filter and Ion Exchanger DiP) will be monitored and maintained within their normal operating ranges during the evolution. The Accumulator fill rate can also be adjusted by throttling the RP discharge flow to either the Unit 2 RWST or the Unit 2 Cavity, depending on the RP system configuration.

The second method (2-MOP-7.31, Section 5.14) involves filling the SI Accumulators from the RP system with the RP system suction source from the Unit 2 RWST. Temporary hoses are installed between the RP pump discharge, downstream of the RP Filters and Ion Exchanger, and the Accumulator drain lines through the Type A test air line and trip valves. With the temporary hoses installed and the RP system on recirculation to the Unit 2 RWST, the Accumulator fill rate will be controlled by throttling at the RP pump discharge connection. The RP system parameters (RP Filter and Ion Exchanger D/P) will be monitored and maintained within their normal operating ranges during the evolution.

This procedure is only valid when Unit 2 is in Mode 5, 6, or defueled. The RP system will be initially configured in one of the following line ups:

- Unit 2 Cavity to Cavity

- Pump down of the Unit 2 RCS to the Unit 2 RWST

- Recirc to the Unit 2 RWST The RP system as described in the Safety Analysis Report allows for the above mentioned configurations.

The boron concentration of the RP suction source must be between 2200 and 2400 ppm boron and the water must meet all other Chemistry requirements for SI Accumulator water. If the RP System is aligned to the RWST, then the limitations of 2-OP-16.2 must be met. If a seismic event occurs, an operator must be available to be immediately dispatched to close the isolation valves. Step 5.14.3 verifies that RP is aligned on recirc to the RWST.

The probability of occurrence of accidents is not increased. This activity may be performed when the RWST is required to be operable. The contingency actions designed to isolate the RP system from safety related systems and the demonstrated ability to maintain the RWST fully operable at all times do not affect the event precursors. Since these actions cannot affect the event precursors, the probability of any postulated accident is not altered.

will remain fully operable as The consequences of any postulated accidents is not increase. The RWST defined in the Technical Specifications. The contingency actions ensure the continued availability of all accident have not been altered. This activity necessary systems; therefore, consequences of any postulated required to be operable. There is no postulated accident will be performed when the SI Accumulators are not during this evolution that requires operability of the accumulators.

overall operation of the RP This activity does not create the possibility of a different type of accident. The portions of the RP system, the RWST, and the SI Accumulators is not altered in any way. The non-seismic sampling ensure that the SI system will be isolated in the event of a seismic event. Calculations and analysis Therefore, all existing Accumulators will be operable when required by the Technical Specifications.

is still valid and no other accidents are postulated.

01-SE- PROC-09 Description 2-MOP-5.98 Rev. 0, Returning One or More Reactor Coolant Loops to Service Following Maintenance Using Backfill Method with the Reactor Head Removed This new procedure allows isolated and drained reactor coolant loops to be returned to service using by backfilling through the loop stops from the active portion of the RCS while the reactor head is removed.

Installation of temporary modifications to bypass the loop stop valve interlocks is included in this procedure.

Summary 2-MOP-5.98 Rev. 0 will be the procedure controlling this evolution. This new procedure was created to return one or more drained reactor coolant loops to service following maintenance using the backfill method with the reactor head removed. This will take advantage of the large volume of water in the cavity as a source of makeup. This will reduce the amount of water needing to be pumped back to the RWST. The procedures provide the necessary controls for temperature and boron concentration of the isolated loop to ensure the required shutdown margin is maintained if fuel is in the vessel.

Specifically, the procedure ensures the following conditions are maintained: a) Seal injection will be supplied to the RCP if the loop has been verified drained (using PDTT inleakage rate), and the boron contration of the seal injection water is above the TS 3.9.1. b) After defeating the loop stop valve interlocks via jumper installation, the applicable cold leg loop stop valve may be opened provided that the loop is drained, the pressurizer contains at least 450 cubic feet of water (32% cold cal level), and a source range neutron flux monitor is operable. c) Backfilling of the loop may proceed if the pressurizer level is maintained above 32 %

cold cal level, the source range neutron flux count rate is no more than a factor of 2 above the initial count rate, and seal injection is maintained above the required boron concentration. d) When the isolated loop is full, the loop stop valves can be fully opened when the boron concentration of the loop is in spec, and no more than two hours have passed since the loop was backfilled. This backfill technique was previously evaluated under 99-SE-OT-32, and these required conditions are properly controlled by the proposed procedure, 2 MOP-5.98 Rev. 0. This evaluation concentrates on the temporary modifications that will be required to defeat the loop stop valve interlocks. Safety Evaluation 00-SE-PROC-21, written for 1/2-MOP-5.97 (RETURNING ONE OR MORE REACTOR COOLANT LOOPS TO SERVICE FOLLOWING MAINTENANCE USING BACKFILL METHOD) previously evaluated temporary modifications being used in this procedure.

If fuel will be in the vessel, core onload will be complete, but other core alterations will be allowed. This makes evolutions such as gap testing and core map video activities possible while filling the loops. Technical Specifications will be complied with by maintaining adequate boron concentration and shutdown margin, and 23 feet will be maintained above the reactor pressure vessel flange at all times.

RCS Loop Stop Valve interlocks are designed to ensure that an accidental startup of an undrained, unborated and/or cold, isolated reactor coolant loop results only in a relatively slow reactivity insertion rate. The interlocks perform a protective function using two independent limit switches to verify that the hot leg loop stop valve is open, two independent limit switches to verify that the cold leg loop stop valve is full closed, and two independent flow switches to verify that bypass flow around the cold leg loop stop valve is greater than 125 gpm for 90 minutes. (The flow verifies that the pump is running, the bypass line is not blocked, and the valves in the bypass line are open). Additionally, the hot leg loop stop valve is prevented from opening unless the cold leg valve in the same loop is fully closed.

It is desired to partially open the loop stop valves on one loop at a time to support backfilling a drained loop.

After an initially drained loop is filled from the RCS in this manner, the loop is no longer considered to be isolated. Thus, the requirements for returning an isolated and filled loop to service are not applicable, and the loop stop valves may be fully opened without restriction but within two hours of completing the loop backfill evolution. This Safety Evaluation considers a Temporary Modification that would allow bypassing the protective circuitry as needed to allow opening of the hot and cold leg loop stop valves. To support this evolution, the restrictions imposed by Technical Specification 3.4.1.6 will ensure that: 1) no potential is created for the introduction of unsampled water from the loop to the core after the evolution; 2) adequate RCS

inventory for core cooling is maintained throughout the evolution; 3) no potential for an undetected boron dilution as a result of mismatch between the boron concentration of the makeup stream and the RCS is created. 2-MOP-5.98 maintains the breakers for the subject valves with jumpered interlocks locked open until the TS restrictions are satisfied. Therefore, installing the proposed Temporary Modifications does not alter the bases of diminishing the potential for uncontrolled positive reactivity addition or loss of decay heat removal.

Additionally, the UFSAR analyzed condition for startup of an inactive loop with the cold leg loop stop valve initially closed states: "Even with the assumption that administrative procedures are violated to the extent that an attempt is made to open the loop stop valves with 0 ppm in the inactive loop while the remaining portion of the system is at 1200 ppm, the dilution of the boron in the core is slow. ... For these conditions, the time for shutdown margin to be lost and the reactor to become critical is 16.4 min." As can be seen, there is plenty of time for the operator to identify the high count rate and to take appropriate actions.

No Unreviewed Safety Question exists because the probability of occurrence and the consequences of a startup of an inactive loop or inadvertent criticality accident are not affected. In addition, there are no postulated accidents or malfunctions that could be generated by the proposed activity.

01-SE- PROC-10 Description VPAP - 2201, CH-97.100 Rev. 6, VPAP - 0306 Att.3 "CHEMCALC Ver. 2 Mod 5.

from the current The change will implement a change of reactor coolant chemistry pH control "coordinated" program [constant pH(t) = 6.9] to a "modified" program which allows the pH(t) to increase of 7.4. Currently lithium is as the fuel cycle progresses from an initial pH(t) of 6.9 to a final pH(t) a value near 0.2 ppm controlled from near a maximum value of 3.5 ppm at the beginning of a fuel cycle to maximum lithium value at the end of a fuel cycle. The change to "modified" chemistry will not change the concentration near 0.7 ppm.

at the beginning of a fuel cycle but will result in an end of fuel cycle lithium on RCS Tavg(305.5 degrees Celsius)

An additional change is that the coordinated pH program was based of 300 degrees Celsius.The change will and the new program will be based upon a reference temperature concentration in accord with EPRI Primary Water also implement new control bands for the lithium Chemistry Guidelines, Rev. 4, March 1999.

dose rates than Operation with modified chemistry is expected to result in less crud on the fuel and lower of- 20% for modified coordinated chemistry. Industry data confirms this expectation with a reduction based on a fixed reference chemistry compared to coordinated chemistry. The calculation of pH of pH is primarily controlled by temperature is based on the observation that the temperature dependence Kw, with temperature. It will eliminate lithium the strong variation in the dissociation constant of water, to this sensitivity of addition and removal operations that would be demanded when the plant ramps due to different plants and to the historical corrosion product Kw to temperature. It also facilitates comparisons solubility data base, which was developed for 300 degrees C.

and lower dose In summary, this change will result in reduced corrosion of primary system components in use at Surry Power Station, as rates in the plant. It is the same type of reactor coolant chemistry control well as a number of other stations in the industry (Spring 2001) and This change would be implemented for North Anna Unit 2 at startup of Fuel Cycle 15 for North Anna Unit 1 at startup of Fuel Cycle 16 (Fall 2001).

Summary the fuel cladding There are no unreviewed safety questions determined. Major issues considered included post LOCA sump pH integrity, materials of construction of the RCS (primarily cracking of Alloys 600),

the items mentioned previously are analyses, and the development of Axial Offset Anomaly. None of previously analyzed nor are they expected to expected to lead to any problems or conditions that have been produce any new scenarios not previously analyzed.

of Alloy 600 Paraphrasing the EPRI Primary Water Chemistry Guidelines, Revision 4 - Crack growth rates and lithium) with the limits material are not systematically dependent upon water chemistry ( including pH crack growth rate was second order of the PWR Water Chemistry Guidelines. The effect of chemistry on has relatively small effect on Primary Water compared to heat to heat variability. pH in the operating range in highly stressed Stress Corrosion Cracking (PWSCC) of Alloy 600 materials. PWSCC occurs typically in steam generators with susceptible Alloy 600 regions (U-bends and tube sheet expansion transitions vessel head and pressurizer penetrations. For Alloy 600, there is an tubing, Alloy 600 tube plugs, and 3.5 ppm and little approximate 20% decrease in characterisitic life with increasing lithium from 0.7 to of lithium and no additional effect of lithium above 3.5 ppm. The station already operates within this range to more dominant effects of deleterious impact has been seen. The effect of lithium is small compared significant if there is long term operation stress, heat to heat variations, and temperatures and only becomes chemistry at or above 3.5 ppm lithium, which is not expected for this pH program change. In summary, ppm should not cause a significant increase in Alloy regimes with initial lithium concentrations up to 3.5 600 crack growth rates.

pH and the amount of The actual pH of the coolant system has no effect on fuel cladding corrosion but the on fuel cladding lithium do have an impact on fuel crud deposition which in turn can have impacts operate below a pH(t) of corrosion. One of the important principles of reactor coolant pH control is to not deposition of significant core crud.

6.9. Operation below pH(t) 6.9 can lead to the formation and

Additionally, another principle of reactor coolant pH control is to operate at pH(t) 6.9 at the beginning of extended fuel cycles. Both of these principles are addressed by this pH change proposal. In terms of fuel performance, the difference in strategies between coordinated and modified pH control programs have little effect on cladding corrosion when the effects of coolant chemistry on crud deposition are accounted for, particularly for the more corrosion resistant cladding materials now being used for current generation fuels.

The move to a higher pH during the fuel cycle as proposed, will reduce the amount of core crud deposits and thus reduce the impact on the cladding. Additionally, reductions in core crud also reduce the likelihood of Axial Offset Anomaly developing.

Nuclear Analysis and Fuel has determined that this proposed pH change has no impact on post LOCA sump pH analyses previously performed.

This change is a change to the existing reactor coolant system chemistry control program for pH(t) control.

The pH(t) will be allowed to increase from an initial value of 6.9 at the beginning of a fuel cycle with lithium maintained at - 3.5 ppm to a final value of 7.4 with a final lithium value of - 0.7 ppm. This compares to the current program which maintains a constant pH(t) of 6.9 throughout the fuel cycle and allows lithium to vary from - 3.5 ppm to 0.2 ppm. Cracking of Alloy 600 materials is not expected. Water chemistry has a second order effect on this mode of cracking. No corrosion issues are expected since higher pH will result in lower corrosion and dose rates because fewer corrosion products are expected to be generated. This in turn will result in lesser amounts of activated corrosion products such as Co-58.

Because higher pH results in less corrosion, the possibility of Axial Offset Anomaly development is reduced as well. The higher pH proposed has an insignificant impact on post LOCA sump pH analyses.

Per Technical Report NE-1267, Rev. 0, a Westinghouse assessment of the proposed chemistry change and the temperature change concluded that for the current cladding material a significant amount of margin remains to the design limit. The projected end of life corrosion levels are also small enough that no impacts are expected on other fuel rod design criteria that may be impacted by the thermal effects of high corrosion, such as rod internal pressure.

Therefore, it is determined that no unreviewed safety question exists for this change.

01-SE- PROC-11 Description Procedure 0-OP-4.13, Rev. 0 "Inspection of Fuel Assembly Thimble Sleeves" Procedure 0-OP-4.13 provides instructions for the visual inspection of irradiated fuel assemblies which may possibly have degraded thimble sleeves. Fuel handling performed under this procedure consists of lifting the fuel assembly a maximum of four (4) feet, while the assembly remaining inside the spent fuel pool rack cell, in order to perform the visual inspections. Lifting of the fuel assembly is performed using the station's spent fuel handling tool (not the "nozzleless" handling tool). Limitation of the height of the lift will be accomplished by the use of a sling in series with the hoist hook and the handling tool.

Summary As a result of Plant Issue PI N-2001-0886 "Dropped Fuel Assembly G45", all fuel assemblies with 304 SS thimble sleeves are considered susceptible to the failure mechanism (Intergranular Stress Corrosion Cracking, IGSCC) and are restricted from movement by normal means. Successful visual inspection of the thimble sleeves will permit reclassification of unaffected fuel assemblies to allow movement with normal fuel handling tools.

Procedure O-OP-4.13 provides instructions for the visual inspection of irradiated fuel assemblies which may have degraded thimble sleeves. As such, it is assumed that during the course of the visual inspection a fuel assembly with degraded sleeves may experience a top nozzle separation event (similar to G45) and fall back into its spent fuel pool rack cell location. This procedure limits the upward movement of the fuel assembly to be inspected to four (4) feet. Analysis provided in Reference 2 concludes that no fuel rod failures will occur should a nozzle separation event occur and the fuel assembly falls from this height.

The probability of occurrence or the consequences of an accident or malfunction of equipment important to safety previously evaluated in the safety analysis report is not increased as a result of the use of this procedure. The Fuel-Handling Accident Outside Containment accident is defined as "...dropping of a spent fuel assembly onto the spent fuel pool floor or the racks that hold the spent fuel." Inherent in the treatment of such an event as an accident is that there is an associated release of fission products. For North Anna the UFSAR states: "it is conservatively assumed for this analysis that the cladding of all the fuel rods in one assembly rupture." The fuel assemblies being inspected may possibly have degraded thimble sleeves, which would increase the potential for separation of the top nozzle from the remainder of the fuel assembly, allowing the fuel assembly to drop. However, the procedure permits the fuel assembly being inspected to be lifted a maximum of four (4) feet. The analysis of Reference 2 concludes that no fuel rods will rupture for a fall of this height into the spent fuel pool rack cell. As no fuel rods are failed and no fission product release occurs, a nozzle separation event which occurs during the completion of this procedure would not be construed as a fuel handling accident. In addition, the minimum cooling time of any susceptible fuel assembly (time since discharge from the reactor) would preclude the presence of 1-131.

Therefore, the conditions for a Design Basis Accident are not present. All fuel handling will be performed in accordance with this procedure and existing fuel handling procedures insuring that all of the bounding assumptions of the Fuel Handling Accident Outside Containment, including requirements for spent fuel pool crane travel, water level, and fuel building ventilation, remain valid. The sling used to limit the upward movement of the fuel assembly to four (4) feet meets the safety requirements for hoisting cables in Reference 4 (safety factor of five (5)). Therefore, there is no increase in the probability of malfunction of any fuel handling equipment. This insures there is no increase in the probability of occurrence or consequences of this accident.

The possibility for an accident or malfunction of a different type than any evaluated previously in the safety analysis report is not increased. Fuel assembly video inspection involves the nonintrusive use of simple hand held tools to inspect a single fuel assembly. As such, there is no possibility that an accident of a different type than previously evaluated in the SAR will be created. As discussed above, it is postulated that a nozzle separation event may occur. Analysis has concluded that no fuel rods will fail (rupture) and no radioactive releases will occur as a result of any such event. Analysis in Reference 3 concludes that the resulting stresses and strains on the spent fuel pool racks and the concrete of the pool floor are within the allowable code limits for the case of a fuel assembly dropped through a storage cell. As all fuel handling

will be performed in accordance with this procedure and existing fuel handling procedures, the limiting failure of any fuel handling equipment remains bounded by the Fuel Handling Accident Outside Containment described in the UFSAR.

The margin of safety as defined in the basis for any Technical Specification is not reduced. The margin of safety associated with the spent fuel pit crane travel and fuel building ventilation system, as described in the bases section of the Technical Specifications is based on the assumption that all of the radioactive material from the fuel pellet to clad gap of an irradiated fuel assembly is released to the spent fuel pool. As this and all other bounding assumptions for the Fuel Handling Accident remain valid, this margin of safety is not reduced.

01-SE- PROC-12 Description New Procedures 1-MOP-31.35A, Removal of 1-FW-E-5A, l-FW-E-6A, and 1-CN-DC-1A from service for maintenance 1-MOP-31.35B, Removal of 1-FW-E-5B, 1-FW-E-6B, and 1-CN-DC-1B from service for maintenance 2-MOP-31.35A, Removal of 2-FW-E-5A, 2-FW-E-6A, and 2-CN-DC-1A from service for maintenance 2-MOP-31.35B, Removal of 2-FW-E-5B, 2-FW-E-6B, and 2-CN-DC-1B from service for maintenance These new procedures permit removal from service and return to service of selected Drain Coolers and Feedwater Heaters. These procedures were written to permit maintenance on these heat exchangers during plant operation.

Summary MAJOR ISSUES:

It is sometimes desirable to take a Feedwater Heater or Drain Cooler out of service during plant operation in order to perform repairs such as tube plugging or to replace leaking relief valves. During the year 2000, these procedures (MOPs for Unit I and Unit 2) were drafted in order to provide more complete guidance on removing 5th and 6 th point FW heaters and drain coolers from service and returning them to service following maintenance. Note that these procedures may be performed with the Main Turbine in operation.

These procedures do not permit complete isolation of their associated heat exchangers. High energy fluid will remain on the shell side of the heat exchangers. These procedures provide the steps to align the heat exchangers for Condensate side maintenance.

The primary plant operational concerns are related to system transients experienced during removal and return to service of these heat exchangers. One concern is the rate of heat-up and cool-down of these heat exchangers during such evolutions. Another concern is that the turbine load must be reduced before taking feedwater heaters out of service. This concern is described in the Westinghouse Steam Turbine Technical Manual, 59-W893-00100, I.L. 1250-4116, page 15,Section VI, Feedwater Heater Ops.

JUSTIFICATION:

Implementation of these new procedures should be permitted, since they are in compliance with the Technical Specifications, the Safety Analysis Report, and the design basis requirements of the Unit 1 and Unit 2 Main Turbines and their associated plant systems. The SAR does not provide sufficient level of detail to describe such equipment operations.

Removal of Feedwater Heaters and Drain Coolers is commonly practiced in the industry and isolation valves are installed for this purpose. The Vendor Technical Manual (Ul: 59-W893-00100, U2: 59-W893 00095) suggests limitations on removing feedwater heaters from operation. Namely, turbine power must be reduced from full power, turbine vibrations must be monitored, and heatup and cooldown rates of heat exchangers must be observed. These limitations are included in the Precautions and Limitations section of the new procedures. The overall operation of associated plant systems and equipment, including Condensate, Feedwater, and the Main Turbine remains unchanged.

UNREVIEWED SAFETY QUESTION ASSESSMENT:

1. Condition does not increase the probability of occurrence or the consequences of an accident or malfunctions of equipment important to safety and previously evaluated in the Safety Analysis Report.

All activities associated with these procedures are bounded by existing analysis. Failure of all associated piping and components is bounded by analysis of Minor Secondary System Pipe Breaks and Major Secondary System Pipe Rupture. In addition, these activities do not increase the probability of any turbine or main steam related accidents, since all of the turbine governor valves will still be capable of closure from turbine trip signals.

2. Condition does not create a possibility for an accident or malfunction of a different type than was previously evaluated in the Safety Analysis Report.

Providing specific procedures for removal and return to service of these heat exchangers will allow for better control of these evolutions. All accidents that involve the turbine require isolating main steam from the turbine to control and limit the accident. The steam isolation capability of the main turbine has not been affected by this change. Further, failure of all associated piping and components is bounded by analysis of Minor Secondary System Pipe Breaks and Major Secondary System Pipe Rupture.

3. Condition does not reduce the margin of safety of any part of the Technical Specifications as described in the bases section.

There are no Technical Specifications directly relating to the feedwater heaters or drain coolers.

Technical Specification margin as it relates to the main turbine is concerned with isolation of steam flow from the turbine in the event of a turbine trip or overspeed condition. Neither of these is affected by the removal of feedwater heaters or the drain cooler from service during power operations. Thus, the evolutions controlled by the proposed new procedures do not reduce the margin of safety of any part of the Technical Specifications as described in the Bases Section. Removal of associated heat exchangers from service will result in a decrease in feedwater temperature and a corresponding insertion of positive reactivity. While there is a potential for a slight increase in reactivity due to this reduction in feedwater temperature, this is adequately addressed in these new procedures and does not impact the margin of safety.

01-SE- PROC-13 Description O-OP-52.1, Rev 3 "Domestic Water System" Three changes are proposed by this revision.

An electrical jumper to defeat the alternating circuits input to a Domestic Water (DW) Booster Pump when it is removed from service and restore the alternating circuits input when the DW Booster Pump is returned to service. Noun names are being added to procedure steps to clarify and improve usability. A Procedure step to cross-tie Well House 2 well supply with other Wells is being deleted since check valve, 1-DW-7, located in the discharge line of Well 2 prevents this action.

Summary This Safety Evaluation considers allowing the installation and removal of an electrical jumper that will defeat a Domestic Water (DW) Booster Pump's alternating circuit input in order to facilitate maintenance on a DW Booster Pump.

Two DW Booster Pumps are provided, one being a 100% spare, which deliver water to the DW Hydropneumatic Tank. The DW Hydropneumatic Tank's pressure and level are controlled by a combination pressure-level controller connected to the tank. The controller controls the operation of the DW Booster Pumps, the air compressors and vent valve. An Alternating Circuit is utilized to equalize the number of pump starts between the two DW Booster Pumps.

This jumper will allow the removal of one of the two DW Booster Pumps for maintenance. Removal of the alternating circuit's input to a DW Booster Pump that has been removed from service for maintenance will prevent the possible loss of the DW Hydropneumatic Tank level and pressure. The jumper will prevent the alternating circuit from trying to call for the start of a DW Booster Pump that has been removed from service, thus preventing the loss of the inservice DW Booster Pump and ensuring DW Hydropneumatic Tank level is maintained.

The Domestic Water (DW) System is described in Section 9.2.3.1 of the UFSAR. The DW system pressure is designed to be maintained between 40 and 60 psig by the pressure maintenance equipment.

Two DW Booster Pumps are provided, one as 100% capacity spare. Therefore, the removal of the alternating circuits input to a DW Booster Pump that has been removed from service for maintenance is acceptable to ensure the DW system remains operable.

CONCLUSION:

The jumper does not alter or affect the function or operation of the Domestic Water System. During a Design Basis Accident, the DW system would be lost since the lines are not seismically supported and the power supplies are not safety related. Therefore, the impact of the jumper during an accident is negligible.

The system does not provide any safety function required for safe shutdown or accident mitigation. The jumper does not alter the system function or performance. Therefore, the change does not increase the probability of an accident or malfunction previously evaluated in the UFSAR. Likewise, the change does not increase the consequences of an accident or malfunction previously evaluated. The change involves a simple jumper which will only be placed in service when a DW Booster Pump is removed from service for maintenance; therefore, no new accidents or malfunctions are created. The Domestic Water System is not required by the Technical Specifications. Thus no Technical Specification requirements are altered by the change, nor are new requirements necessitated. For these reasons, an Unreviewed Safety Question is not created, and the Temporary Modification should be allowed.

01-SE- PROC-14 Description ET NAF 2001-0071, REV. 0, DESIGN BASIS ADEQUACY OF WESTINGHOUSE NOZZLELESS FUEL ASSMBLY HANDLING TOOL 0-OP-4.1 1, Rev. 0, NOZZLELESS FUEL ASSEMBLY HANDLING TOOL using Type 304 Dominion and Westinghouse, the fuel vendor, have concluded that all fuel assemblies sleeves may be susceptible to separation of the top nozzle from the remainder stainless steel guide thimble fuel handling. North Anna Unit I fuel Batches 1 - 8 and Unit 2 fuel Batches 1 - 7 of the assembly during are in this population. A fuel handling tool, which does not require the availability of intact guide thimble assemblies. The Engineering sleeves, has been procured from Westinghouse to handle affected fuel the tool. The Operating Procedure gives Transmittal provides a review of the design basis adequacy of detailed instructions for assembly, operation, and maintenance of the tool.

Summary that expand The nozzleless fuel handling tool uses an alternative means of gripping the fuel assembly (collets rather than lifting at the top nozzle). The UFSAR design into the inner surface of the guide thimbles requirements for the fuel handling system are:

transfer

1. Fuel-handling devices have provisions to avoid dropping or jamming of fuel assemblies during operation.

design-basis

2. Fuel lifting and handling devices are capable of supporting maximum loads under earthquake conditions.

minimum

3. Cranes and hoists used to lift spent fuel have a limited maximum lift height so that the required depth of water shielding is maintained.

accident The tool meets these requirements, therefore, the frequency of occurrence of a fuel handling caused by failure of the tool has not been increased.

the use of a However, the nozzleless tool is slightly more complicated to use and maintain. It requires assembly and manual adjustment of the gripping collets. To address the torque wrench to latch onto the fuel Procedure 0-OP-4.11 (currently Step 5.2.14) calls for briefly stopping increase in complexity, a step in at approximately 12 inches to verify there is no slipping between upward movement of the fuel assembly the fuel assembly and the grippers.

of a fuel Since the nozzleless fuel handling tool itself will not increase the frequency of occurrence use of the nozzleless fuel handling accident and procedural steps mitigate human performance concerns, handling tool will not cause more than a minimal increase in the frequency of occurrence of this accident.

and The nozzleless tool is more mechanically complex than the other tools. Maintenance, adjustment, procedure, after the tool is assembled and on a periodic basis.

testing of the tool are required by the as noted Detailed steps in the procedure instruct the operators in completion of these activities. In addition, the procedure calls for briefly stopping upward movement of the fuel above, when the tool is being used to verify there is no slipping between the fuel assembly and the assembly at approximately 12 inches in the likelihood of occurrence of a malfunction of the fuel handling grippers. Thus, there is no increase equipment in general and specifically the nozzleless fuel handling tool.

(0-OP All fuel handling using the nozzleless tool will be performed in accordance with this procedure operation and 4.11). All bounding assumptions of the accident analyzed in the UFSAR (time since reactor movement using the depth of spent fuel pool water) remain valid should the accident occur during fuel outside of containment are not nozzleless tool. Therefore, the consequences of a fuel handling accident fuel handling equipment, and specifically the increased. The limiting consequence of a malfunction of Since the consequences of the fuel handling nozzleless fuel handling tool, is a fuel handling accident.

fuel handling accident remain bounded by the UFSAR analyzes, the consequences of a malfunction of the equipment are also not increased.

The use of the nozzleless fuel handling tool involves movement of fuel assemblies in the spent fuel pool only. Therefore, the only credible accident is the fuel handling accident. Use of the nozzleless tool does not create a possibility for an accident of a different type than any previously evaluated in the UFSAR. The nozzleless fuel handling tool uses a different means of latching to a fuel assembly than the "normal" handling tools. All other fuel movement operations are the same. Thus, use of the nozzleless tool does not create a possibility for a malfunction of an SSC important to safety with a different result than any previously evaluated in the UFSAR.

Use of the nozzleless fuel handling tool as prescribed in Procedure O-OP-4.11 involves movement of fuel assemblies in the spent fuel pool only. Therefore, the only fission product barrier that could be affected is the fuel cladding. Use of the nozzleless tool to move fuel within the spent fuel pool has no impact on the integrity or any design basis limit that could affect the integrity of the fuel cladding.

Use of the nozzleless fuel handling tool to move fuel assemblies in the spent fuel pool does not result in any change in any method of evaluation described in the UFSAR. The current accident analysis (Fuel Handling Accident Outside Containment), and its calculated consequences, remain bounding for this activity.

01-SE- PROC-15 Description Fuel-Handling Accident Outside Containment Summary Procedure 0-OP-4.13 provides instructions for the visual inspection of irradiated fuel assemblies, which may possibly have degraded thimble sleeves. Fuel handling performed under this procedure consists of lifting the fuel assembly a maximum of four (4) feet, while the assembly remaining inside the spent fuel pool rack cell, in order to perform the visual inspections. Lifting of the fuel assembly is performed using the station's spent fuel handling tool (not the "nozzleless" handling tool). Revision 1 of the Procedure removes the requirement that the lift be accomplished using a sling in series with the hoist hook and the handling tool, thereby limiting the height of the fuel assembly lift. Henceforth, the limitation of the lift height is to be controlled administratively with the operator utilizing visual reference indicators marked on the fuel handling tool.

All of the fuel assemblies susceptible to the thimble sleeve cracking/failure (fuel batches N1B8/N2B7 and older) have been discharged from the reactor for a minimum of 20 months (since 3/12/2000). Should a nozzle separation occur with the fuel assembly be lifted above 4 feet, the possibility exists that a failure of some or all of the fuel rods may result.

For this evaluation the UFSAR accident "Fuel Handling Accident Outside Containment" and a malfunction of the fuel handling equipment were considered. The evaluation concludes:

1. There is no increase in the frequency of occurrence or the consequences of a fuel handling accident outside of containment. The requirement to perform the thimble sleeve inspection at a maximum height of 4 feet remains in the procedure. Reference 2 of the Safety Review/Regulatory Screen concludes that no fuel rods will rupture for a fall of this height into the spent fuel pool rack cell.

2. There is no increase in the likelihood of occurrence or the consequences of a malfunction of the fuel handling equipment. Lifting of the fuel assembly is performed using the station's spent fuel handling tool (not the "nozzleless" handling tool). The limitation of the lift height is to be controlled administratively with the operator utilizing visual reference indicators marked on the fuel handling tool. Use of these visual cues is normal operator practice when moving fuel. A malfunction of the fuel handling equipment could result in a fuel assembly being lifted to a height greater than 4 feet during completion of the inspection procedure. Should a nozzle separation occur with the fuel assembly be lifted above 4 feet, the possibility exists that a failure of some or all of the fuel rods may result. All bounding assumptions of the fuel handling accident outside containment analyzed in the UFSAR (time since reactor operation and depth of spent fuel pool water) remain valid.

3. There is no possibility that an accident of a different type than previously evaluated in the UFSAR or a malfunction of an SSC important to safety with a different result than any previously evaluated in the UFSAR will be created. This fuel assembly visual inspection involves the nonintrusive use of simple hand held tools to inspect a single fuel assembly lifted a maximum of 4 feet in the spent fuel pool rack cell. Only one fuel assembly is being handled at any given time. The limitation of the lift height is to be controlled administratively with the operator utilizing visual reference indicators marked on the fuel handling tool.

4. The only fission product barrier that could be affected is the fuel cladding. The possibility of a rupture of all of the fuel rods in the fuel assembly has been considered in the UFSAR (Fuel-Handling Accident Outside Containment). Completion of the inspection procedure does not result in a design basis limit for a fission product barrier as described in the UFSAR being exceeded or altered.

5. Visual inspection of fuel assemblies in the spent fuel pool does not result in any change in any method of evaluation described in the UFSAR. The current accident analysis (Fuel-Handling Accident Outside Containment), and its calculated consequences, remain bounding for this activity.

SAFETY EVALUATION LOG OTHER 2001 SNSOC Unit Document System Description Date 01-SE-OT-01 1,2 UFSAR FN 00-044 Eliminates the requirement for prior SNSOC review & 1-25-01 approval of all procedural changes to NUREG-0612 safe load paths or exclusion areas, as currently stated in NAPS UFSAR Section 9.6.4.1.

01-SE-OT-02 1,2 UFSAR FN 01-001 Table 3C-2 (High Energy Lines [Outside Containment]) will 2-01-01 be revised to correct operating pressure & temperature values listed in the table (identified in PI N-2000-0636-R2) &

resolved in engineering transmittal CME-0047.

01-SE-OT-03 2 Tech Rpt NE-1 266 Refueling & operation of North Anna Unit 2, Cycle 15, 2-15-01 Pattern OX FN 2001-004 01-SE-OT-04 1,2 TS Chg 385 Implements the revised LOCA containment integrity 2-20-01 analysis UFSAR FN 00-042 1 &2-ES-1.3 01-SE-OT-05 1,2 UFSAR FN 00-046 Allows RSST load shed circuit to be defeated with both 3-06-01 ET CEE 00-0009, R. 0 units on-line for a period of up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> ET NAF 01-0023, R. 0 0-OP-26.7, Rev. 7, P1 01 -SE-OT-07 1,2 UFSAR FN 00-047 Updates UFSAR Section 15.2.6 to reflect the current design 3-20-01 Tech Rpt NE-1200 bases that credit TS controls to preclude the preconditions P1 N-2000-2489-R2 for significant & uncontrolled reactivity insertion during the startup of an inactive loop.

01-SE-OT-09 1,2 UFSAR FN 00-049 SW Defines the required number of SW system reservoir spray 3-27-01 arrays that are required to be operable to meet minimum 0-PT-75.11 design basis requirements.

0-OP-49.1 01-SE-OT-10 1,2 UFSAR FN 01-010 Updates the description of zinc materials in the 4-17-01 assumptions section of the containment hydrogen generation analysis. (Ref. PI N-2001-0488) 01-SE-OT-11 1,2 UFSAR FN 01-002 1. Changes all references of Calgon biocide H-510 to the 4-17-01 active chemical ingredient "Isothiazolin".

2. Eng. Calc ME-0567, Rev. 1, corrected several math errors, thus changing the maximum expected concentrations in the control room following a chemical spill.

Clarifies hazard levels associated with zinc chloride &

sodium molybdate.

01-SE-OT-11 1,2 UFSAR FN 01-002 Replacement of Calgon biocide H-510 with NALCO 2894 6-21-01 Algaecide (copper-free) in the bearing cooling system.

REV. 1 ET N 01-108, Rev. 0, has been prepared as a supplement to calculation ME-0567 to document the acceptability of the NALCO 2894 algaecide with respect to control room habitability & provide the maximum expected chemical concentrations in the control room following a chemical spill I

SAFETY EVALUATION LOG OTHER 2001 SNSOC Date System Description Unit Document 5-01-01 2 UFSAR FN 01-013 Includes a revised 10 CFR 50.61 pressurized thermal shock 01-SE-OT-12 screening calculation result for NAPS U2 reactor vessel to weld material fabricated from weld wire heat 4278 (nozzle intermediate shell weld 04A, OD 94%), with consideration given to Sequoyah U2 plant specific surveillance program data.

5-08-01 Includes a statement in Bases %.3.1 & %.3.1.2 to identify 1,2 TS CHG 290A 01-SE-OT-13 that a plant specific risk analysis was performed to support the increased AOTs & decreased surveillance frequencies for the functional units in Block 4 of referenced TS.

5-17-01 References to VEPCO will be changed in Units 1 & 2 01-SE-OT-14 1 1,2 TS CHG 389 operating licenses & TS to Dominion Generation Corporation 5-22-01 Incorporates criteria & methodology of Generic 1,2 FN 01-007 01-SE-OT-V1 Implementation Procedure (GIP) developed by the Seismic Qualification Utility Group & endorsed by the NRC. Also adds description of the in-structure median centered spectra that can be used in evaluations using the GIP.

5-29-01 01-SE-OT-16 1,2 IUFSARFN01-011 Addresses discrepancies identified in Oversight Audit 01

02. Discrepancies consisted of an incorrect description of the foam hose stream capabilities for protection of fuel oil storage tank & pumphouse (9.5.1.2.1 & 9.5.1.3.1.2), an incorrect reference to a halon system that has been removed (9.5.1.4.1.2), and an unclear description of SCBAs use for fire fighting (9.5.1.2.4.4).

5-31-01 UFSAR FN 01-005 Updates Section 15.2.7 & associated tables & figures to 01 -SE-OT-1 8 1,2 incorporate a loss of load accident reanalysis 6-07-01 Upgrades the TRM to capture revisions to the EQ Barrier 01-SE-OT-19 1,2 TRM Chg #44 Program over the last several years. Changes are administrative in nature.

6-21-01 Fuel Anomaly Fuel Anomaly NDCO1-9, Addendum 2, documents NAF's 01-SE-OT-20 1,2 intention to conditionally remove the handling restrictions NDC01-9, Add. 2 from fuel assemblies that were identified as susceptible to intergranular stress corrosion cracking of thimble sleeves based upon results of video inspections.

7-19-01 TRM chg 45 This change incorporates recommendations from ET 01-SE-OT-22 1,2 ET N-00-01 38, R. 0 N-00-1 38, Rev. 0, by (a) clarifying Appendix R /fire DR/PI N-99-0774 protection compensatory measures, (b) clarifying fire NAPS App. R .report brigade manning, and (c) clarifying Appendix R alternate shutdown equipment fire watch locations and their bases.

2

O1-SE-OT-01 Description NAPS UFSAR, Section 9.6.4.1 & NAPS UFSAR Change Request No. FN 2000-044 Eliminate the requirement for prior SNSOC review and approval of all procedural changes to NUREG 0612 safe load paths or exclusion areas, as currently stated in NAPS UFSAR, Section 9.6.4.1.

Summary NAPS UFSAR, Section 9.6.4.1, currently requires prior SNSOC review and approval of all deviations to NUREG-0612 safe load paths (also interpreted to include deviations to safe load path exclusion areas). The main issue associated with this Safety Evaluation is to determine whether this NAPS UFSAR statement is tied to any NUREG-0612 program commitment or can this current NAPS UFSAR requirement be deleted.

Virginia Power's original commitment to such procedure changes can be found in a December 15, 1982 letter to the US NRC (see Ref 1). In that letter Virginia Power stated, "information concerning deviations to procedures with existing load paths.. .could be found in Section 5 of.. [the] Quality Assurance Manual and in Section 6 of North Anna Power Station Technical Specifications." In other words, Virginia Power would follow the review process for such procedure changes, as set forth in our license bases, which at that time, required review by a station supervisory personnel with a follow-up review by SNSOC. In the Final NAPS TER, dated May 1984, Section 2.1.2.a, Summary of Licensee Statements and Conclusions (see Ref.

2), reiterated "Current plant procedures require that deviations to safe load paths be reviewed by station supervisory personnel with a follow-up review by the station nuclear safety and operating committee."

Section 2.1.2.b, of the TER, stated the basis for acceptability as "Deviations from load paths are acceptably handled on the basis that prior approval is required and that the additional procedures and changes prepared receive at least two levels of supervisory review." The NRC's SER for Heavy Loads dated May 25, 1984 (see Ref 3), has the simple conclusion "The staff has reviewed the TER and concurs with its findings that the guidelines in NUREG-0612, Sections 5.1.1 and 5.3 have been satisfied."

NAPS Technical Specifications, Section 6.8, denotes the requirements for SNSOC review of new and changed procedures. As stated in NAPS Plant Issue Evaluation Response N-2000-0389-E1 & RI, this section was recently revised by amendment 191/172. Currently, these NAPS Technical Specifications state that a procedure change requiring a Safety Evaluation is reviewed by SNSOC and a procedure change not requiring a Safety Evaluation is reviewed as discussed in the UFSAR. The NRC's SER for Amendment 191/172 noted that we stated "the screening process would be specified in [the] Operational Quality Assurance Program Topical Report and that procedure changes that do not require a safety evaluation must be approved by cognizant management and a senior reactor operator. Based on the screening process and procedure change approval by cognizant management and a senior reactor operator, the staff finds the proposed change ... acceptable." The QA Topical Report is now controlled as Chapter 17 of the UFSAR.

Section 17.2.5, Instructions, Procedures, and Drawings, states the current process for review of procedure changes and requires cognizant management and SRO review, but does not require SNSOC review, of changes that do not require a safety evaluation. If a change has a safety evaluation, SNSOC review is required.

In conclusion, the original licensing basis has been properly modified (TS Amendment 191/172) and the current licensing basis for review of procedure changes to safe load paths for North Anna is based upon the NAPS Technical Specification requirement that the change receive SNSOC approval when the change is screened to require a safety evaluation. Therefore, the cited NAPS UFSAR, Section 9.6.4.1 statement, listed above, requiring prior SNSOC review and approval of all deviations to NUREG-0612 safe load paths, is not a program commitment and can be deleted. All procedure change review and approvals currently meet the commitments, as described in NAPS Technical Specifications and the Topical Report (UFSAR Chapter 17). As such, no unreviewed safety questions exist.

01-SE-OT-02 Description UFSAR Change Request FN 2001-001 In response to Plant Issue N-2000-0636-R2, Engineering Transmittal CME 00-0047 has identified changes to Table 3C-2, High-Energy Lines (Outside Containment), Chapter 3 of the UFSAR are required. These changes are to the information provided in that table and will have no adverse affect on the evaluation for high energy line breaks documented in Appendix 3C of the UFSAR.

Summary This safety evaluation addresses the changes to Table 3C-2, Appendix 3C of the UFSAR. The changes made provide corrections to the table as a result of the review conducted and documented in Engineering Transmittal CME-00-0047. Plant Issue N-2000-0636-R2 identified discrepancies between values listed in Table 3C-2, Appendix 3C of the UFSAR and the Line Designation Table listed in a parameter set of EDS.

The discrepancies were the operating pressure and temperature, line size, seismic class, and quality class with the operating pressure and temperature data encompassing the bulk of the discrepancies. Review of the controlling documents in which Table 3C-2 and the Line Designation Table database provided the definitions by which each document bases its data on. Section 3C.2.2.1 of that Appendix defines operating temperature and pressure, "as the maximum temperature and pressure in the piping system, during occurrences that are expected frequently in the course of power operation, start-up, shutdown, standby, refueling, or maintenance of the plant." The EDS parameter set for the Line Designation Table provides fields for the "normal" pressure and temperature for each line contained within the table. The controlling document for the Line Designation Table is found in Mechanical Engineering Nuclear Standard STD MEN-0022, Piping Line Designation Tables. Mechanical Engineering Nuclear Standard STD-MEN-0022 provides the definition of the "normal" pressure and temperature fields listed in the EDS database as such, "The normal pressure and temperature will correspond to the values encountered during normal operation of the system." The difference in the definitions could account for the differences in the published values in each document. Whereas the Appendix 3C is using maximum operating values to determine the type of high energy line break analysis, the Line Designation Table in EDS is listing conditions during steady state normal operating conditions in the plant, not start-up, standby, etc. conditions that may yield higher or lower pressure and/or temperature conditions. Regardless all changes to Table 3C-2 are bounded by the existing high-energy line break analysis for the lines addressed herein. Therefore changes required in the data appearing in Table 3C-2 of the UFSAR will be made.

In regard to line size, seismic class, pipe break evaluation type, and quality class discrepancies that were few in number, a definite source or cause of the discrepancies proved difficult to identify. It appears that the discrepancies are a result of typographical errors, errors in electronic data transfers, or failure to update a data base/document as a result of a design change or maintenance activity. To state a definite cause for each would be speculation. However, most of the minor discrepancies have been corrected with the issuance of Revision 36 of the UFSAR with the balance corrected by the review performed and documented in Engineering Transmittal CME-00-0047.

The change in Table 3C-2 of the North Anna UFSAR does not affect the operation of any plant system.

The changes addressed and evaluated by this safety evaluation are used to determine if the affected lines are still bounded by their high-energy line break evaluations. It has been determined that there is no affect to the evaluations. There is no physical change to any plant system that would increase the probability or possibility of an accident or component malfunction previously analyzed, nor will it increase the probability or possibility of an accident or component malfunction of a different type. The evaluation performed to determine the effects of a high energy line break outside of containment and documented in Appendix 3C, Table 3C-2 remains valid and is not affected by the changes evaluated in engineering transmittal CME-00-0047. It can therefore be concluded that the changes to Table 3C-2 do not involve an unreviewed safety question.

01-SE-OT-03 Description Technical Report, NE-1266, Revision 0, "Reload Safety Evaluation, North Anna 2 Cycle 15 Pattern OX,"

T. R. Flowers, February 2001.

UFSAR Change Request FN-2001-004.

Refueling and operation of North Anna Unit 2 Cycle 15 Pattern OX.

Incorporation of the following features described in Technical Report NE-1266, Revision 0:

1. Use of short (127.2") poison stack BP rods as in Cycle 14.

2. Twenty-eight of the peripheral assemblies will have replacement top nozzles.

3. Effects of a potential change in the RCS coolant chemistry program on safety.

4. A minor change in the fabrication of the top nozzle adapter plate, the use of cast top nozzles, and bead blasted Alloy 718 hold-down spring screws for the fresh fuel. Prior to this reload, Chapter 4, Section 2, Mechanical Design, of the UFSAR must be revised in order to incorporate the changes in the material of the hold-down spring screws that attach the springs to the top nozzle. These changes are included in UFSAR Change Request Number FN-2001-004. The basis for this change is Technical Report NE-1266, Revision 0.

The UFSAR change does not affect any of the Safety Analyses contained in Technical Report NE-1266.

Summary A safety evaluation has been performed to determine whether an unreviewed safety question will result from the refueling and operation of North Anna Unit 2 Cycle 15. In this evaluation, reload cycle parameters have been calculated and compared to the existing safety analysis assumptions. These parameters have been shown to be either explicitly bounded or accommodated by existing safety analysis margin and/or conservatism.

The impact of the following features and assumptions have been accounted for in the appropriate evaluations performed for N2C 15:

1. Cycle 15 burnup limit is 20,900 MWD/MTU for EOC14 = 19,000 MWD/MTU, or 20,400 MWD/MTU for EOC14 = 19,900 MWD/MTU. These limits include up to a 5 'F Tavg coastdown at full power, followed by a customary power coastdown for a total coastdown of approximately 2500 MWD/MTU, past the end of normal Tavg full power reactivity. Tavg coastdown operation was approved for both North Anna units by NAPS Safety Evaluation No. 99-SE-OT-26, Revision 1, 08/05/99; and has already been implemented in N2C14 (Safety Evaluation No. 99-SE-OT-45, 9/23/99). The maximum Tavg reduction is limited to the value specified in the cycle-specific reload safety evaluation. N2C15 is limited to a 5 'F coastdown (NE-1266, Revision 0).

2. An RCCA fully withdrawn position of 226 steps.

3. Use of short (127.2") poison stack BP rods as in Cycle 14.

4. Twenty-eight of the peripheral assemblies will have replacement top nozzles.

5. A maximum FQ of 2.19 during normal operation, but reduced to 2.15 for the EOC Tavg and power coastdown, modified by K(z), as presented in Appendix A of Technical Report NE-1266.

6. Effects of a potential change in the RCS coolant chemistry program on safety.

7. A minor change in the fabrication of the top nozzle adapter plate, the use of cast top nozzles, and bead blasted Alloy 718 hold-down spring screws for the fresh fuel. Prior to this reload, Chapter 4, Section 2, Mechanical Design, of the UIFSAR must be revised in order to incorporate the changes in the material of the hold-down spring screws that attach the springs to the top nozzle. These changes are

included in UFSAR Change Request Number FN-2001-004. The basis for this change is Technical Report NE-1266, Revision 0. The UFSAR change does not affect any of the Safety Analyses contained in Technical Report NE-1266.

One of the reload parameters was found to be outside the range of the generic safety analysis input VEP-FRD assumptions, and therefore required specific evaluation. In accordance with the Topical Report Design Methodology," an evaluation was performed to determine the 42, Rev. 1-A, "Reload Nuclear impact of the parameter on the currently applicable safety analyses, as described below.

on the The reload cycle fuel rod FAIH census is not bounded by the reference limit for all values. Based known DNBR sensitivity to FAH in a thermal hydraulic evaluation (Reference 3), a penalty has been assessed against retained DNBR margin to accommodate the unbounded values in the census.

The results of this evaluation can be summarized as follows:

1. No increase in the probability of occurrence or consequences of an accident will result from this core reload. The reload creates only incremental changes in the values of parameters previously shown to be significant in determining core response to known accidents. Since the currently applicable safety analyses remain bounding for North Anna Unit 2 Cycle 15, it is concluded that operation with the proposed reload core will neither increase the probability of occurrence nor the consequences of initiating events for any known accident.

2. It has been determined that the effect on system operation and accident response is frilly described by the parameters evaluated. Therefore, operation of this core does not create the possibility of an accident of a different type than any previously evaluated in the Safety Analysis Report.

3. The margin of safety is not reduced. The effects of core parameter variations were accommodated within the conservatism of the assumptions used in the applicable safety analyses. These analyses have demonstrated that calculated results meet all design acceptance criteria as stated in the UFSAR.

01-SE-OT-04 Description UFSAR Change Request FN 2000-042 for North Anna Power Station UFSAR Chapters 6.2 and 6.3 Technical Specification Change Request 385 (Containment Air Partial Pressure Operating Curve) affecting TS 3.6.1.4 with Figure 3.6-1, 4.6.2.2.1, and 4.8.1.1.2 (Table 4.8-1)

Change to North Anna Power Station Emergency Operating Procedures 1/2-ES-1.3, "Transfer to Cold Leg Recirculation" Also, this safety evaluation addresses the containment response analysis effects from the design changes listed in Block #7 (Items 2, 3, 4 and 5). However, specific safety evaluations for those changes may be required in accordance with the nuclear design control program.

Implementation of the revised LOCA containment integrity analysis requires changes to the North Anna Technical Specifications, Sections 6.2 and 6.3 of the North Anna UFSAR, and emergency operating procedure 1/2-ES-1.3. Explicit containment integrity analyses were performed to incorporate several revised design inputs related to containment initial conditions and heat removal systems. The current licensing basis includes evaluations of the revised inputs. The new analysis incorporates all of the changes into the LOCTIC computer code calculations, providing a complete, more robust accident analysis.

The new safety analysis provides justification for the following changes to the North Anna Technical Specifications:

"* Revise TS Figure 3.6-1, containment air partial pressure versus service water temperature operating curve.

"* Revise the TS IRS delay time from 195 to 400 seconds in TS 4.6.2.2.1 and TS 4.8.1.1.2 (Table 4.8-1).

"* Revise the TS IRS delay timer uncertainty from 9.75 sec to 5.0 sec in TS 4.6.2.2.1 and TS 4.8.1.1.2 (Table 4.8-1).

"* Revise the TS ORS delay timer uncertainty from 21.0 sec to 5.0 see in TS 4.6.2.2.1 and TS 4.8.1.1.2 (Table 4.8-1).

The containment design criteria are satisfied for operation with the revised TS containment air pressure operating curve and the revised RS delay time values. The intent of the UFSAR update is to revise the analysis assumptions and results in Sections 6.2 and 6.3 for the containment peak pressure, depressurization, LHSI and RS pump NPSH, and inadvertent QS actuation event analyses to be consistent with the new safety analysis documented in technical report NE-1257, Rev. 0 [Reference 1 in Item 18].

This safety evaluation does not evaluate the plant design changes listed in Item 7 except as they relate to the containment response analysis. Rather, this evaluation supports the use of revised analysis assumptions that are based on the Item 7 plant changes. Separate safety evaluations will be performed for the plant design modifications described in Item 7. This safety evaluation only implements the revised safety analysis and the assumptions thereof.

Summary Description of Change This safety evaluation is performed for the implementation of a revised containment integrity analysis for North Anna Units I and 2. The analysis includes LOCA containment integrity and safeguards pumps NPSH analyses with the Stone & Webster Engineering Corporation (SWEC) LOCTIC computer code, which is also the basis for the existing licensing basis containment integrity analyses. The main steam line break containment integrity analysis was also evaluated. The containment response to the design basis LOCA was analyzed with revised design inputs to address findings from internal design basis review teams and items from industry and internal operating experience. One of the more significant changes is the incorporation of instrumentation uncertainty in areas of the analysis where nominal response had previously been assumed.

Some plant instrumentation changes must be made in order to reduce uncertainties to acceptable values.

The plant changes are identified in Item 7. The new containment analysis basis is documented in technical report NE-1257, Rev. 0 [Reference 1]. LOCTIC analyses were documented by SWEC in References 2-5.

The list of revised design inputs includes: uncertainties for refueling water storage tank (RWST) temperature, service water (SW) temperature, casing cooling temperature, containment air partial pressure,

and containment bulk temperature; revised flow rates for quench spray (QS), inside recirculation spray (IRS),

outside recirculation spray (ORS), QS bleed, and SW; RS heat exchanger (RSHX) tube plugging and fouling; QS nozzle efficiency; RS and QS start times; RWST level for low head safety injection (LHSI) recirculation mode transfer (RMT); and accumulator discharge pressure. Significant design input changes were evaluated and included in the analysis basis as they were found. The main objective of the reanalysis was to explicitly include all revised design inputs in the LOCTIC simulations.

Technical Specification Change 385 A revised Technical Specification (TS) Figure 3.6-1 containment air partial pressure versus SW temperature operating domain was developed such that operation in the acceptable domain ensures that the containment design criteria are satisfied. The IRS delay timer setpoint and the IRS and ORS timer uncertainties were revised in the analysis such that new values must be incorporated into TS 4.6.2.2.1 and 4.8.1.1.2 (Table 4.8-1). The TS changes do not involve any changes to plant systems, structures, and components. The change to Figure 3.6-1 is a minor shift in the allowable containment air pressure operating domain but does not represent a change in operating philosophy. Analysis results with the proposed TS changes meet the applicable acceptance criteria. Specifically,

"* The maximum containment pressure is less than the 44.1 psig containment leakrate pressure limit (TS 3.6.1.2 and 3.6.1.3), and the peak containment temperature is less than the design limit of 280'F.

"* The containment depressurizes to less than 14.7 psia in less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and remains subatmospheric thereafter.

"* The LHSI and RS pumps have adequate NPSH to ensure pump integrity during the postulated LOCA.

"* The containment liner design criteria are satisfied based on analysis of the inadvertent QS actuation event.

"* The environmental zone description equipment qualification profiles for pressure and temperature are not exceeded during the postulated accident.

UFSAR Change Request FN 2000-042 Chapters 6.2 "Containment Systems" and 6.3 "Emergency Core Cooling System" of the North Anna UFSAR include extensive discussion of the containment design, system operating requirements, and analyses to ensure containment integrity and adequate NPSH for the safeguards pumps. The new safety analysis affects several sections in those chapters. This safety evaluation supports the changes included in UFSAR Change Request FN 2000-042.

A. Emergency Operating Procedure 1/2-ES-1.3 The safety analysis assumption for the RWST level at which LHSI recirculation mode transfer (RMT) occurs was changed from 23% to 20%. To accommodate the setpoint change, emergency operating procedure 1/2-ES-1.3 "Transfer to Cold Leg Recirculation" [Reference 7] will be modified to hold manual operator RMT actions until the automatic RMT setpoint of 20% RWST level is reached. This procedure change ensures that manual RMT could not be completed before reaching the safety analysis limit. As a result, the auto setpoint will initiate RMT, and the operator will verify the actions and perform manual backup, if necessary. The EOP change is required to ensure the plant procedures are consistent with the new analysis basis.

Item #7 lists the plant design changes that are required to support the implementation of the revised containment analysis. The design changes may require separate safety evaluations to support each change, because this safety evaluation only supports the use of analysis assumptions based on the plant changes in Item #7 as they affect the containment response analysis. The design changes are consistent with the revised safety analysis will not change the conclusions from the unreviewed safety question determination that follows.

It is expected that the RTDs located inside containment will be replaced during an outage. The TS change submittal will request that operation under the revised TS containment air pressure operating curve begin during the next outage sufficiently after NRC approval, rather than the normal implementation window.

Unreviewed Safety Question Determination The results of this evaluation can be summarized as follows:

• No increase in the probability of occurrence of an accident or malfunction will result from the changes to the Technical Specifications, UFSAR, and EOPs. The probability remains unaffected since the accident analyses involve no change to a system, component, or structure that affects initiating events for any of the accidents evaluated. The analyses meet the applicable acceptance criteria (peak containment pressure less than 44.1 psig, containment pressure is subatmospheric within I hour and remains subatmospheric thereafter, available NPSH is greater than required NPSH for RS and LHSI pumps, the minimum containment pressure from an inadvertent QS event is greater than the containment liner design pressure, and the equipment qualification envelopes are not exceeded) for operation in the acceptable domain shown on revised TS Figure 3.6-1 for containment air partial pressure versus service water temperature. Since the containment design criteria are satisfied, radiological consequences of accidents previously evaluated in the North Anna Units 1 and 2 UFSAR will not be increased.

• The implementation of the proposed changes does not create the possibility of an accident of a different type than was previously evaluated in the SAR. The proposed Technical Specification, UFSAR, and EOP changes do not alter the nature of events postulated in the UFSAR nor do they introduce any unique precursor mechanisms. Therefore, there is no possibility for accidents of a different type than previously evaluated.

• The implementation of the proposed changes does not reduce the margin of safety. The containment analysis results satisfy the applicable acceptance criteria for operation within the acceptable operating limits of revised Technical Specification Figure 3.6-1 "Containment Air Partial Pressure Versus Service Water Temperature" and with the TS changes to the RS delay timer values. The change to EOP 1/2-ES-1.3 ensures adequate safety margin for the NPSH analyses. It is concluded that the margin of safety will not be reduced by the implementation of the changes to the Technical Specifications, UFSAR, and EOPs.

01-SE-OT-05 Description ET CEE 00-0009, Rev. 0, Defeating the RSST Load Shed Circuit with Both Units On-Line ET NAF 2001-0023, Rev. 0, PRA Evaluation of Defeating RSST Load Shed Circuit with Both Units On-Line 0-OP-26.7, Rev. 7, P1, Reserve Station Service Load Shed UFSAR Change Request No. FN 2000-046 0-OP-26.7 will be revised to permit defeating the circuit for a period of up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> during operation of both Units 1 and 2. The UFSAR, section 8.3.1.1, will be revised to reflect the fact that the circuit can be defeated for maintenance activities.

Summary Currently, there are no provisions to defeat the RSST load shed to allow any maintenance activities during those times when the load shedding must be enabled. In some cases, it is desirable to defeat the load shed circuit when both units are on-line. This change will allow the RSST load shed circuit to be defeated for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with both units on-line in order to allow maintenance to be performed. Due to the already low likelihood of two-unit loading of the RSST's (e.g., simultaneously two units trip and transfer and the generator breaker on Unit 1 fails to operate), defeating the RSST load shed circuit for a short period of time is acceptable. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> limit is an administrative limit. The Safety Monitor model will be modified to include this evolution and will be used to determine the acceptability of defeating the load shed when necessary.

The RSST load-shedding scheme will initiate whenever both the Unit 1 and Unit 2 Station Service Buses are fed from the associated Reserve Station Service transformer. The load shedding is also dependent on two control switches and the operating status of the associated Main Feedwater Pump motors. The load shedding of certain non-safety-related secondary plant electrically driven equipment is intended to alleviate potential low-voltage profile conditions on the Reserve Station Service system during combined unit operation using only the Reserve Station Service transformers.

Before and during start-up of Unit 2, Station Service Buses 2A, 2B, and 2C are supplied from Reserve Station Service transformers A, B, and C, respectively. After the Unit 2 generator is on-line, the Station Service Buses are transferred to the Station Service transformers. For several events, principally a Unit 2 trip, the buses will be automatically transferred to the associated Reserve Station Service transformers.

Unit 1 Station Service buses 1A, IB, and 1C are normally supplied from the Station Service transformers at all times. The 22kV main generator breaker eliminates the need to routinely supply the buses from the Reserve Station Service transformer. For several events, principally equipment failures, the Unit 1 Station Service buses will automatically transfer to the associated Reserve Station Service transformers, similar to Unit 2. However, the installation of the Unit 1 main generator breaker greatly reduces the likelihood of combined loading from both Units 1 and 2 Station Service Buses on the Reserve Station Service transformers.

In the event of two-unit loading of the RSST's with the load shed circuit defeated, the higher load would result in lower voltage. The RSST's would be overloaded and it is probable that one or more Emergency Buses would separate from the offsite power supplies via the undervoltage relays and transfer to the Emergency Diesel Generators. While the EDG's are capable of supplying the loads under any condition, this event would be very undesirable and is in direct conflict with the goals of GDC-17. If both units are operating in a normal configuration, some type of failure would be required on Unit 1 to initiate transfer of the station service loads to the RSST's in conjunction with the transfer of the Unit 2 loads.

The probability or consequences of an accident or malfunction previously evaluated in the safety analysis report are not increased.

The Electrical Distribution System is fully operable and the performance characteristics of safety related systems are unaltered. The RSST load shed circuit will be defeated during maintenance activities to preclude inadvertent actuation, which could result in the loss of normal feedwater and a turbine trip. This change does not increase the probability of a turbine trip, loss of normal feedwater, or a loss of offsite power to the station auxiliaries. Defeating the RSST load shed circuit does not impact the consequences of an accident. The load shed circuit alleviates potential low-voltage profile conditions on the reserve station

service system during combined unit operation using only the reserve station service transformers. For the load shed circuit to operate, both units must trip and a failure must occur to initiate transfer of the Unit 1 station service loads to the RSST's. (Normally, the main generator breaker operates and Unit I buses do not transfer.) The defeat of the load shed will be procedurally controlled to minimize the likelihood of combined unit loading on the RSST's. Therefore, the probability of loss of offsite power to the emergency bus(es) is not increased. The consequences of a loss of offsite power to the emergency buses are unchanged. The EDG's are fully capable of supplying the necessary loads to maintain the plant in a safe condition or to mitigate the consequences of an accident.

The possibility of an accident or malfunction of a different type than previously evaluated in the safety analysis report is not created.

No new accident precursors are introduced. Two unit loading of the RSST's with no load shedding could result in low voltage and separation of the emergency bus(es) from offsite power. This would require that the buses be supplied from the EDG's. While this is undesirable, a total loss of offsite power has been previously evaluated in the SAR. Defeating of the RSST load shed circuit will be procedurally controlled to minimize the likelihood of this event. This change will allow use of a control switch to defeat the load shed circuit. This does not create the possibility for a malfunction of equipment of a different type than was previously evaluated in the SAR. The changes do not affect the outcome of the accident analyses.

The margin of safety as defined in the basis for any Technical Specification is not reduced.

The emergency power system capability to power the safe shutdown and accident mitigation equipment is not affected. The operation of other systems is unaffected. No safety limits or limiting safety system settings are altered. Therefore, the margin of safety has not been reduced.

01-SE-OT-07 Description Plant Issue Number N-2000-2489-R2 UFSAR Change Request FN 2000-047 Startup of an Inactive Loop Accident Analysis Design Basis Document (AADBD) update tracked by NAF Level I tern 1272. Technical Report NE-1200, "Key Operator Actions Assumed in Safety Analyses",

Update tracked by NAF Level I Item 1274.

The proposed UFSAR changes update Section 15.2.6, "Startup of an Inactive Loop", to reflect the current design bases that credit Technical Specification controls to preclude the preconditions for significant and uncontrolled reactivity insertion during the startup of an inactive loop (i.e., reduced boron concentration or temperature in an isolated loop). A conservative analysis of the reactivity effects of the isolated loop recirculation activity required by Technical Specification 3.4.1.5.a is also being incorporated into Section 15.2.6.

Summary Purpose The purpose of the Safety Evaluation is to implement a revised discussion of the Startup of an Inactive Loop accident analysis into North Anna UFSAR Section 15.2.6. The existing UFSAR discussion of the Startup of an Inactive Loop (SUIL) accident analysis in UFSAR Section 15.2.6 does not accurately reflect the current NRC-approved licensing position. In addition, the existing UFSAR discussion does not present an analysis of the reactivity effects of the isolated loop recirculation activity required by Technical Specification 3.4.1.5.a. The proposed UFSAR changes modify UFSAR Section 15.2.6 to correct these deficiencies. The technical bases for the proposed UFSAR changes are documented in Calculation SM 1275, "Startup of an Inactive Loop Accident Analysis for North Anna Units 1 and 2," dated February 2001 (1).

Background

As of this writing, UFSAR Section 15.2.6.2.1.2 (ICMP Database Record 31089) states the following:

The start-up of an inactive reactorcoolant loop with the loop stop valves initially closed has been analyzed assuming the inactive loop to be at a boron concentration of O ppm while the active portion of the system is at 1200 ppm, a conservatively high value for the requiredshutdown marginfor beginning of life. The flow through the reliefline is assumed at its maximum value of 330 gpm.

The conclusions regarding the analysis of this scenario of the startup of an inactive loop accident are documented in Section 15.2.6.2.2.2 (ICMP Database Records 31094 and 52722):

15.2.6.2.2.2 Loop Stop Valves Closed. Even with the assumption that administrative procedures are violated to the extent that an attempt is made to open the loop stop valves with 0 ppm in the inactive loop while the remainingportion of the system is at 1200 ppm, the dilution of the boron in the core is slow. The initialreactivity insertion rate is calculatedto be less than 2.6 x 1 0 s delta-k/sec, considerably less than the reactivity insertion rates considered in Section 15.2.2. For these conditions, the time required for the shutdown margin to be lost and the reactor to become critical is 16.4 minutes. This calculation takes into account the reduced reactor coolant system volume due to the isolated loop. This is ample time for the operator to recognize a high count rate signal and terminate the dilution by turning off the pump in the inactive loop or by boratingto counteract the dilution.

Nuclear Analysis and Fuel (NAF) / Reactor Engineering staff observed that the range of RCS boron concentrations considered in the UFSAR analysis (i.e., 0 ppm to 1200 ppm) do not conservatively bound the range of expected boron concentrations required to meet shutdown margin requirements at cold, no xenon (Xe), all rods in (ARI) conditions. Critical boron concentrations (cold, no Xe, ARI) in the range of 1300 ppm to 1400 ppm have been experienced in recent North Anna core designs. NAF staff investigated

this discrepancy and concluded that the analysis is conservative in terms of the boron concentration difference considered in the analysis relative to boron concentration differences that can realistically be achieved under the constraints of current Technical Specifications. NAF also concluded that the SUIL "Loop Stop Valves Closed" analysis presented in the UFSAR is historical in nature. Specifically, licensing actions subsequent to the incorporation of this analysis into the UFSAR have credited Technical Specification controls for precluding the pre-conditions necessary for the SUIL "Loop Stop Valves Closed" scenario to result in a significant and uncontrolled reactivity addition. A discussion of the licensing history for the Startup of an Inactive Loop accident analysis is presented below.

The original North Anna Units 1 and 2 Technical Specifications included requirements for un-isolation of isolated reactor coolant loops. The purpose of the requirements was to prevent inadvertent criticality during the process of bringing the loop into service, and to avoid reactor vessel thermal shock and the imposition of excessive thermal fatigue on vessel components, paticularly on the cold leg nozzles. The Technical Specifications required that the isolated loop remain closed unless (a) the isolated loop had been operated on a recirculation flow of greater than or equal to 125 gpm for at least 90 minutes, (b) the temperature of the cold leg of the isolated loop was within 20'F of the highest cold leg temperature of the operating loops, and (c) the reactor was subcritical by at least 1.77%Ak/k. As of this writing, these requirements still remain in effect. The recirculation activity required by Technical Specifications is performed under strict administrative control, and does not by itself constitute a boron dilution event.

Nonetheless, UFSAR Section 15.2.6.2.1.2 evaluates the reactivity effects of inadvertent startup of an inactive loop with the loop stop valves closed. The most recent analysis performed for the North Anna Core Uprating effort (described below) assumes two loops are in operation and one loop is isolated (i.e., N-I loop operation), even though this operating mode was eliminated by Technical Specification Amendment

32. (Letter from R. A. Clark to J. H. Ferguson, Serial No. 354 dated June 2, 1981. Additional information on licensing history is available in Letter from J. P. O'Hanlon to USNRC, "Virginia Electric and Power Company, North Anna Power Station Units 1 and 2, Proposed Technical Specifications Change, Revised Loop Stop Valve Operation," Serial No.96-532, dated November 6, 1996.)

An analysis of the SUIL "Loop Stop Valves Closed" case was performed as part of the North Anna Core Uprating effort to determine the time required for complete loss of shutdown margin. (See Letter from W.

L. Stewart to H. R. Denton (NRC), "Amendment to Operating Licenses NPF-4 and NPF-7, North Anna Power Station Unit Nos. I and 2, Proposed Technical Specification Changes," dated May 2, 1985.)

Because N-i loop operation is precluded by Technical Specifications, this analysis is historical in nature.

However, the analysis does provide a technical basis (although an incomplete technical basis) for concluding that sufficient time exists for corrective operator action in response to boron dilution resulting from procedurally-controlled coolant recirculation with a loop stop valve closed. The Core Uprating analysis assumed that the coolant in the inactive loop contained 0 ppm boron, while the active portion of the system contained 1200 ppm boron. At the time of the analysis, this boron concentration was considered consistent with estimates of the boron concentration required to meet the minimum shutdown margin at Beginning-of-Life (BOL). Flow through the relief line was assumed to be at its maximum value of 330 gpm. The initial reactivity insertion rate was calculated to be less than 2.6E-5 Ak/sec, which is considerably less than the reactivity insertion rates considered in the Rod Withdrawal from Subcritical event analyses. For these conditions, the time required for the minimum Technical Specification shutdown margin to be lost, and the reactor to become critical was calculated to be 16.4 minutes. This was concluded to be ample time for the operator to recognize a high Source Range count rate signal and terminate the dilution by turning off the pump in the inactive loop, or by borating to couteract the dilution. The core uprating analysis further concluded that the reactivity addition at End-of-Life (EOL) is less limiting than that assumed above to occur at BOL.

By letter dated November 6, 1996 (Letter from J. P. O'Hanlon to USNRC, "Virginia Electric and Power Company, North Anna Power Station Units 1 and 2, Proposed Technical Specifications Change, Revised Loop Stop Valve Operation," Serial No.96-532, dated November 6, 1996), Virginia Power requested amendments to the Technical Specification requirements for isolated loop startup to permit filling a drained and isolated loop via backfill from the RCS through partially opened loop stop valves. The Technical Specification change submittal included the technical basis for elimination of the loop stop valve interlocks based on temperature and relief line flow. (Note that the loop stop valve interlock requirements were not

governed by Technical Specifications.) However, the 20'F temperature difference and 90-minute recirculation flow requirements remained in the Technical Specifications. The basis for elimination of the loop temperature and recirculation flow portions of the loop stop valve interlocks was the establishment of procedural controls governed by Technical Specifications to preclude the possibility of inadvertent reactivity addition due to temperature reduction or boron dilution. The Technical Specifications and associated plant procedures include the following controls:

a. The boron concentration in the isolated loop is required to be maintained higher than the boron concentration in the operating loops, thus eliminating the potential for introducing coolant from the isolated loop that could dilute the boron concentration in the operating loops.

(Note: this requirement has been modified to require a boron concentration in the isolated loop that is greater than that which satisfies the mode-dependent shutdown margin requirement as applicable for the active volume of the RCS. See Letter from S. R. Monarque (NRC) to D. A. Christian, "North Anna Power Station Units 1 and 2 - Issuance of Amendments Re: Technical Specification Change for Reactivity Controls - Return Isolated Reactor Coolant System Loops to Service," (Amendments 223 and 204), Serial No.00-465, dated August 25, 2000.)

b. The reactor must be subcritical by at least 1.77% Ak/k prior to opening a cold leg loop stop valve. This ensures that any minor reactivity changes associated with temperature gradients cannot result in inadvertent criticality.

c. Prior to opening a cold leg loop stop valve, the isolated loop must operate on a recirculation flow of greater than or equal to 125 gpm for at least 90 minutes. This ensures a slow, controlled mixing of the contents of the isolated and active loops.

d. The temperature of the cold leg of the isolated loop must be within 20'F of the highest cold leg temperature of the operating loops. This restriction limits the potential reactivity addition due to cooldown to a small amount that is readily accommodated by the available shutdown margin.

The November 6, 1996 submittal was followed by responses to various NRC Requests for Additional Information (RAIs). (See Letter from N. Kalyanam to J. P. O'Hanlon, "Request for Additional Information

- Revised Loop Stop Valve Operation; North Anna Power Station Units I and 2," Serial No.98-179, dated March 16, 1998. See also Letter from J. P. O'Hanlon to USNRC, "Virginia Electric and Power Company, North Anna Power Station Units I and 2, Proposed Technical Specifications Change, Revised Loop Stop Valve Operation," Serial No.98-179, dated April 15, 1998. See also Letter from N. Kalyanam to J. P.

O'Hanlon, "Request for Additional Information - Revised Loop Stop Valve Operation; North Anna Power Station, Units 1 and 2," Serial No.98-364, dated June 9, 1998.) Of particular interest is the letter dated April 15, 1998, in which Virginia Power responded to an NRC inquiry concerning the erosion of shutdown margin due to the introduction of coolant with reduced temperature but with adequate boron concentration.

0 The analysis considered introduction of 32 F water into a core operating at 200'F with no mixing between the cold loop and the other loops. The analysis demonstrated that the net reactivity addition was less than one half of the minimum shutdown margin required by Technical Specifications. Thus, neither the inadvertent opening of a loop stop valve nor the loop stop valve bypass line recirculation activity required by Technical Specifications presents any concerns relative to loss of shutdown margin under conditions of reduced isolated loop temperature. Approval of the November 6, 1995 submittal, and the associated RAI responses, was granted by Letter from N. Kalyanam to J. P. O'Hanlon, "North Anna Power Station, Units 1 and 2 - Issuance of Amendments - Startup of Isolated Loop by Backfill," dated October 30, 1998.

By letters dated June 22, 2000 (Letter from D. A. Christian to USNRC, "Virginia Electric and Power Company, North Anna Power Station Units 1 and 2, Proposed Technical Specification Changes, Response to Request for Additional Information," Serial No.00-304, dated June 22, 2000) and July 25, 2000 (Letter from D. A. Christian to USNRC, "Virginia Electric and Power Company, North Anna Power Station Units 1 and 2, Corrected Pages for Proposed Technical Specification Changes, Reactivity Controls - Return of Isolated RCS Loops to Service," Serial No. 00-304A, dated July 25, 2000), Virginia Power requested Technical Specification changes to accommodate the vacuum-assisted fill technique for returning isolated RCS loops to service. In addition to providing additional Technical Specification requirements to support the vacuum-assisted loop backfill technique, these submittals affirmed the continued applicability of the

addition during or Technical Specification controls that preclude the possibility of inadvertent reactivity following loop stop valve operations. The NRC Safety Evaluation Report for these submittals is R. Monarque to D. A. Christian, "North Anna Power Station Units 1 and 2 documented in a Letter from S. Isolated Controls - Return

- Issuance of Amendments Re: Technical Specification Change for Reactivity System Loops to Service," Serial No.00-465, dated August 25, 2000. In the SER, the Reactor Coolant controls to ensure that the NRC states "The licensee's proposed TS changes provide necessary RCS loop accident are precluded."

preconditions related to reactivity for the startup of an inactive and uncontrolled reactivity By eliminating the possibility of the pre-conditions necessary for a significant loop, the accident analysis presented in UFSAR Section addition during the startup of an inactive considered "historical" in nature.

15.2.6.2.1.2 is no longer relevant to the North Anna design basis, and is relevant analysis that might be Because of the Technical Specification controls described above, the only of the operational impact of performed for the Startup of an Inactive Loop accident is an evaluation in the presence of a hypothetical performing the recirculation activity required by Technical Specifications of this type is presented Calculation SM reduced boron concentration in the isolated loop. An evaluation 1275 (1).

Basis for UFSAR Update Stop Valves Closed" case Nuclear Analysis and Fuel has performed an analysis of the SUIL "Loop recirculation activity required assuming that three RCS loops are isolated and RHR is in operation when the the volume of the active by Technical Specification 3.4.1.5.a is initiated. As a result 3of this configuration, The analysis assumes an initial RCS boron portion of the reactor coolant system is reduced to 3345 ft . boron conservatively bounds the predicted concentration of 1800 ppm. This boron concentration of Specification minimum shutdown margin requirement concentration required to meet the Technical (Xe)

Beginning of Cycle (BOC), All Rods In (ARI), No Xenon 1770 pcm at Cold Zero Power (CZP),

ppm, 500 ppm less than the conditions. The isolated loop boron concentration was assumed to be 1300 RCS. The concentration 1800 ppm concentration assumed to exist initially in the active portion of the restoration of isolated and difference is conservative, given that the Technical Specifications governing isolated loop will be greater than or drained loops to service ensure that the boron concentration in the (e.g.,

shutdown margin requirement equal to the boron concentration corresponding to the mode-dependent to be line flow rate of 330 gpm was assumed 1800 ppm). The design maximum loop stop valve bypass assumes a differential boron worth that conservatively transferred to the reduced RCS volume. The analysis bounds values expected to occur over core life.

front" model. In the These conditions were analyzed with a "perfect mixing" model as well as a "dilution each time step was "perfect mixing" model, the inventory transferred from the isolated loop during the active portion of the reactor coolant system.

assumed to be instantaneously distributed throughout portion of the reactor coolant system during each time Likewise, the inventory transferred from the active model distributed throughout the isolated loop. The "dilution front" step was assumed to be instantaneously causes a from the isolated loop assumes that, because of the relative flow rates, the inventory transferred of the boron concentration diluted slug of water to pass through the reactor core. With each loop transit, "steps down" to a value calculated as a weighted average based on the dilution flow rate the slug of water of coolant in the active portion and boron concentration and the RHR flow rate and the boron concentration of the RCS.

("dilution front" model)

The Nuclear Analysis and Fuel calculation determined that between 17.0 minutes operator action in response to and 50.5 minutes ("perfect mixing" model) are available for corrective rates during the transient are increasing source range neutron count rate. The estimated reactivity insertion Withdrawal from Subcritical well within the range of reactivity insertion rates considered in the Rod in Standard Review Plan accident analysis. The NRC staff criteria for boron dilution events set forth action between the time an alarm Section 15.4.6 require 15 minutes to be available for corrective operator and complete loss of shutdown margin (2).

makes the operator aware of unplanned moderator dilution time and monitored evolution, 17.0 minutes is sufficient Because the recirculation activity is a controlled for operators to identify a dilution in progress and to terminate the evolution.

Unreviewed Safety Ouestion Determination The proposed revised UFSAR discussion of the Startup of an Inactive Loop accident analysis documented in UFSAR Change Request FN 2000-047 does not create the possibility of a new or different kind of accident, increase the probability of occurrence or consequences of accidents previously analyzed, nor decrease any margin of safety inherent in previously performed accident analyses. Technical Specification controls described in North Anna TS 3.4.1.5 and 3.4.1.6 preclude the possibility of a significant and uncontrolled reactivity addition during the startup of an inactive loop. The loop stop valve bypass line recirculation activity required by TS 3.4.1.5.a is a procedurally controlled evolution, and does not itself constitute a boron dilution event. A conservative analysis of this event demonstrates that there is adequate time for corrective operator action in response to credible scenarios of reactivity insertion due to reduced boron concentration or temperature. No new operating modes or allowable plant conditions are being introduced by the proposed UFSAR changes that could create the possibility of a new or different type of accident, or which could increase the probability of occurrence or consequences of accidents previously analyzed.

(1) Calculation SM- 1275, "Startup of an Inactive Loop Accident Analysis for North Anna Units 1 and 2,"

dated February 2001.

(2) Letter from W. J. Chipiwalt (VEPCO) to B. C. Rusche, "Amendment No. 44", Serial No. 827, dated December 29, 1975 (citing requirements of Standard Review Plan, NUREG-0800, Section 15.4.6, April 1975 as applicable to the North Anna Power Station license application).

01-SE-OT-09 Description SAR Change Request FN-2000-049, SW Spray Array Clarification, O-PT-75.11 and OP-49.1 VP. Calculation ME-062 and addendum determines the minimum number of spray arrays needed to support design basis requirements. The UFSAR will be clarified (revised) and changed to indicate the minimum number of spray arrays required to be operable to meet design basis minimum requirements. Evaluation indicates that three spray arrays out of eight are required to meet the design basis requirements of the NAPS Service Water Spray Array System with two SW headers operable following a single failure. To meet minimum design basis requirements whether with a single SW header in operation or both SW headers operating, no less than three spray arrays must always be operable including any single failure considerations that may be appropriate.

Summary Since this UFSAR change reflects only a clarification to existing design basis information in the UFSAR no Unreviewed Safety Question exists for this safety evaluation. A UFSAR change has been requested by station personnel to clarify the design basis minimum number of spray arrays needed to support the plant design basis.

During repairs to a NAPS SW spray array in May 1998, initial engineering reviews were performed which indicated that one of four spray arrays on each SW header could be removed from service without affecting operability of the SW header. Additionally, a UFSAR change request is warranted since the design basis calculation ME-062 states that only 3 of 4 arrays are required for a header to be operable (minimum safeguards). Whereas the UFSAR states that 4 arrays (2 pairs) are required for DBA mitigation (1 pair per header or two pair on a single header). This apparent discrepancy generated a plant deviation report (DR 98 1750). The following paragraphs provide the required clarifications to the UFSAR.

The LOOP and LOCA are the design basis accidents previously considered and are not effected by the clarifications to the UFSAR as a result of this UFSAR Change request. Clarification of the UFSAR does not increase the probability of occurrence for any accident considered. Since the accidents previously considered are not affected, by this clarification of the UFSAR no consequences of a previously considered accident are increased. Clarifications to the UFSAR will not result in the possibility for an accident of a different type than was previously considered.

Equipment failure such as the spray array valves and headers and supporting equipment, which have been previously considered, have been considered for this Safety Evaluation. The clarifications to the UFSAR to do not increase the probability of occurrence of malfunctions previously identified. No malfunctions of a different type are suggested by the new clarifications added to the UFSAR by this UFSAR Change Request.

The clarifications to the UFSAR that increase the understanding of the functionality of the Spray Array system have not been addressed in the Technical Specification bases section. Therefore, no reduction in any margin of safety results from these clarifications to the UFSAR.

The proposed change does not require a change to the Operating License or Technical Specifications since they are editorial in nature and only provide clarifications to the design basis requirements of the Service Water Spray array system.

The following will be added to the UFSAR as a clarification of the minimum design basis of the Service Water Spray array system:

"Under the most limiting conditions, a single SW supply and return header will meet the SW system accident design basis requirements of a simultaneous loss-of-coolant-accident (LOCA) for one unit and loss of offsite power for both units. Assuming the most limiting single failure, the minimum design basis requirements for the SW system reservoir spray array are met with either one or both SW headers in

operation as long as a minimum of three spray arrays remain OPERABLE following the failure. Three out of four spray arrays are required with only one SW header (supply and return) in operation or three out of eight spray arrays with both SW return headers in operation.

A failure in the SSPS system of a master relay or the slave relay (K608) can result in the failure of four spray isolations MOV's to automatically open, if initially closed. If two spray array isolation MOV's are closed and inoperable prior to the event, potentially six spray arrays will fail to open during a design basis accident. Therefore, to ensure three spray arrays remain operable, only one spray array out of the eight total spray arrays may be closed and out of service. However, two spray arrays may be inoperable if they are on separate SI trains. If a spray array is inoperable solely due to the inability of its associated MOV to automatically open, the array may be considered operable if the MOV is administratively maintained in the open position."

O1-SE-OT-1O Description UFSAR Change Request FN 2001-010 for North Anna Power Station UFSAR Section 6.2.5.3 The change adds description to specify the bounds of applicability of the zinc material assumptions (relative to the actual plant configuration) in the North Anna containment hydrogen generation analysis in UFSAR Section 6.2.5.3. The current licensing basis analysis includes distinct inputs for zinc paint and zinc metal, but the hydrogen generation rate per unit of surface area is assumed to be the same for both zinc subcategories in the analysis of record. Materials/ISI Engineering reports in Reference 4 that the zinc metal in containment exceeds the analysis input while the zinc paint assumption is much greater than the zinc paint in containment. The evaluation concludes that it is important that only the total zinc mass and surface area be verified against the total assumed in the safety analysis, and that subcategory verification is not required. The UFSAR change clarifies the limits on zinc material in containment that are imposed by the safety analysis.

Summary Description of Change This safety evaluation is performed to add description regarding the bounds of applicability of the zinc material assumptions (relative to the plant configuration) in the containment hydrogen generation analysis in Section 6.2.5.3 of the North Anna UFSAR [1]. No reanalysis was performed. Rather, the description of material inputs is amended to clarify that the total zinc mass and surface area, not individual subcategories of zinc, are the parameters that must be verified against the containment inventory.

Currently, UFSAR Section 6.2.5.3 and Table 6.2-59 and the safety analysis [2] present the zinc inputs to the analysis in two subcategories: paint and galvanized metal. Materials/ISI Engineering verification of the containment inventory [3,4] concluded that there is more metal than the safety analysis input, while there is no or very little exposed zinc paint. ET NAF 2001-0025 [5] was written to evaluate the impact on the hydrogen generation analysis of the metal inventory being larger than the safety analysis input.

Reference 2 concluded that the analysis of record hydrogen generation rate per unit of zinc surface area is the same for paint and metal (this conclusion was verified for Surry's Reference 6 analysis). Therefore, the analysis of record remains bounding because the total zinc mass and total exposed zinc surface area are less than the total assumed in the safety analysis. The UFSAR change adds this clarification to avoid future PI's after each inventory that documents more galvanized metal than the safety analysis assumption.

ET NAF 2001-0025 establishes the total zinc mass and surface area limits for Materials/ISI Engineering to ensure that the containment hydrogen analysis continues to bound the plant configuration.

In conclusion, the maximum hydrogen concentration of 3.9% calculated in Reference 2 remains the analysis basis. This safety evaluation supports the changes included in UFSAR Change Request FN 2001 010.

The results of this evaluation can be summarized as follows:

" No increase in the probability of occurrence of an accident or malfunction will result from the changes to the UFSAR. The probability remains unaffected since the accident analysis is not revised. A brief description is added to the UFSAR to clarify the bounding nature of the zinc inputs in the containment hydrogen analysis. There is no change to a system, component, or structure that affects initiating events for any of the accidents evaluated in the SAR. The containment hydrogen generation analysis of record is not affected and continues to meet the applicable acceptance criteria. Since the containment design criteria are satisfied, radiological consequences of accidents previously evaluated in the North Anna Units I and 2 UFSAR will not be increased.

" The implementation of the proposed UFSAR changes does not create the possibility of an accident of a different type than was previously evaluated in the SAlR. The proposed UFSAR changes do not alter the nature of events postulated in the UFSAR nor do they introduce any unique precursor mechanisms.

Therefore, there is no possibility for accidents of a different type than previously evaluated.

The implementation of the proposed UFSAR changes does not reduce the margin of safety. The containment hydrogen generation analysis results are not altered and the applicable acceptance criteria continue to be met. It is concluded that the margin of safety will not be reduced by the implementation of the UFSAR changes.

O1-SE-OT-11 Description UFSAR Change Request FN 2001-002 of Calgon biocide H-5 10 with Applied Specialties The UFSAR requires revision to support the replacement (BC) system. The generic chemical name, Inc. biocide AS-590 (copper-free) in the bearing cooling and the appropriate chemistry and operations VPAP,

'Isothiazolin', should be referenced in the UFSAR, in the name. Isothiazolin is a common pesticide used for algae control procedures, rather than the vendor act only to promote the shelf life of in Calgon H-510 BC system. The addition of copper-based chemicals must use blowdown of the BC water to Lake Anna, we the product. In order to facilitate continuous shelf life is not relatively small volumes that are kept on site, copper-free forms of Isothiazolin. Due to the name, the chemical biocide, rather than the vendor product a concern. By referencing only the basic active UFSAR or procedural changes.

chemical can be purchased without the need for changing the corrected several mathematical errors, thus Engineering calculation ME-0567, Rev. I chemical spill. The affected chemicals Room following a maximum expected concentrations in the Control levels associated with Zinc Chloride Biocide. The hazard include Hydrazine, Ethanolamine, and H-510 only pose a significant threat to humans two chemicals and Sodium Molybdate were also clarified. These Rev. 1 require are inhaled. These changes to ME-0567, when solid particles or fumes created by burning that the UFSAR be updated.

Summary

Background

ME-0567, Rev. 1 to correct several mathematical P1 N-2001-0397 required the revision of calculation chemical concentration in the control room following a errors. These errors impact the maximum expected Room remain "Control Room," requires that the Control spill. Criterion 19 of I OCFR50, Appendix A, performed As a result of the above changes, Engineering habitable during normal and accident conditions.

will be maintained following a chemical spill.

an evaluation to ensure Control Room habitability replaced with a warm weather months, Calgon H-5 10 is being To support continuous BC blowdown during ME-0567, Rev. 1. The maximum was evaluated in copper-free form of Isothiazolin. This change to be 5.0%.

allowable concentration of Isothiazolin was determined each chemical addressed:

The evaluation considered the following areas for

• Quantity, toxicity, and state in the plant.

intakes.

"* Chemical transport into the MCR via the emergency air

"* Worst-case concentration level in the MCR Control Room determine if any chemicals pose a threat to Calculation ME-0567, Rev. I was initiated to concentration less than would have a Control Room habitability. The calculation showed that all chemicals stored on site in a evaluation concluded that no chemical their toxicity limit in the event of a spill. The a release.

Room personnel following quantity over 100 pounds could adversely affect Control Major Issues Considered and

- No modifications are being made to plant systems Probability or Consequences of Malfunctions events or mechanisms evaluated condition has no impact on their operation as a result of this change. The and SAR. There are also no physical changes to plant systems that could initiate the accidents listed in the type is not created as a An accident of a different components that perform accident mitigation functions. system.

the biocide used in the BC result of this document change or the change in

Specification sections relevant to Control Technical Specification / Operating License - The Technical Room Habitability are:

LCO and 4.7.7.1,

"* Plant Systems, Control Room Emergency Habitability System Section 3.7.7.1, Surveillance Requirements 3/4.7.7

"* Plant Systems, Bases, Control Room Emergency Habitability System Sections by this change. The Mechanical Engineering The Technical Specifications are not affected in any way safety of Control Room habitability with the evaluation and corresponding UFSAR changes document the on-site chemical storage configuration per VPAP 2202.

UFSAR changes are performed to ensure the Safe Shutdown Capability - The SE and corresponding on-site chemical storage configuration. In safety of the plant based on an updated evaluation of the of any system, component or structure as addition, the storage of the biocide does not alter the operation to the plant operating systems and defined in the UFSAR. Because there are no physical modifications on the station's ability to achieve and maintain components associated with the changes, there is no impact from the Auxiliary Shutdown Panel will not be safe shutdown in the event of a fire. In addition, operation adversely affected.

available does not present a fire hazard.

The use of Isothiazolin in the concentrations commercially bi-products found in the biocides. Isothiazolin Magnesium chloride and Magnesium Nitrate are chemical available biocides are non-volatile in the and the chemical bi-products contained in the commercially available concentrations.

the plant to be safe with respect to the Environmental Impact - Mechanical Engineering has determined replacement of Calgon H-510 with Applied current chemical storage configuration. In addition, the more than 5% WT concentration Isothiazolin Specialties AS-590 or an equivalent biocide containing no of the plant. Therefore, there will be no impact will not adversely affect the chemical storage configuration being made to the plant operating systems or on the environment or the FES. Since no changes are expected. No change to the Environmental components, no changes in power level or effluents are Protection Plan is required.

(Rev. 1) do not create an unreviewed safety For these reasons, these changes to the UFSAR & ME-0567 question.

O1-SE-OT-11 Rev 1 Description UFSAR Change Request FN 2001-002 Calgon biocide H-510 with NALCO 2894 The UFSAR requires revision to support the replacement of chemical name, 'Isothiazolin',

Algicide (copper-free) in the bearing cooling (BC) system. The generic and the appropriate chemistry and operations procedures, should be referenced in the UFSAR, VPAP, that has been used for appropriate. Isothiazolin is a common pesticide rather than the vendor name, where added to promote the shelf Calgon H-5 10 are algae control in the BC system. Copper-based chemicals in in controlling algae.

the biocides effectiveness life of the product, however the copper additives do increase use copper-free forms Lake Anna, we must In order to facilitate continuous blowdown of the BC water to life is not a concern. By are kept on site, shelf of Isothiazolin. Due to the relatively small volumes that vendor product name, the chemical can be referencing only the basic active chemical, rather than the purchased without the need for UFSAR or procedural changes.

mathematical errors, thus changing the Engineering calculation ME-0567, Rev. 1 corrected several a chemical spill. The affected chemicals maximum expected concentrations in the Control Room following hazard levels associated with Zinc Chloride include Hydrazine, Ethanolamine, and H-510 Biocide. The only pose a significant threat to humans and Sodium Molybdate were also clarified. These two chemicals inhaled. These changes to ME-0567, Rev. 1 require when solid particles or fumes created by burning are N 01-108, Rev, 0, has been prepared as a that the UFSAR be updated. In addition, engineering transmittal acceptability of the NALCO 2894 Algicide supplement to calculation ME-0567 in order to document the expected chemical concentrations in with respect to Control Room habitability and provide the maximum the Control Room following a chemical spill.

Summary

Background

Rev. 1 to correct several mathematical PI N-2001-0397 required the revision of calculation ME-0567, in the control room following a chemical errors. These errors impact the maximum expected concentration requires that the Control Room remain spill. Criterion 19 of 10CFR50, Appendix A, "Control Room,"

of the above changes, Engineering performed habitable during normal and accident conditions. As a result following a chemical spill.

an evaluation to ensure Control Room habitability will be maintained Calgon H-5 10 is being replaced with a To support continuous BC blowdown during warm weather months, in ME-0567, Rev. 1, and in engineering copper-free form of Isothiazolin. This change was evaluated transmittal N 01-108, Rev. 0.

addressed:

The evaluation considered the following areas for each chemical

"* Quantity, toxicity, and state in the plant.

". Chemical transport into the MCR via the emergency air intakes.

"* Worst-case concentration level in the MCR chemicals pose a threat to Control Room Calculation ME-0567, Rev. 1 was initiated to determine if any a Control Room concentration less than habitability. The calculation showed that all chemicals would have that no chemical stored on site in a their toxicity limit in the event of a spill. The evaluation concluded personnel following a release. Engineering quantity over 100 pounds could adversely affect Control Room Transmittal N 01-108 was prepared to document the acceptability of using a replacement chemical, System, to be stored on site in chemical storage tank 1-BC NALCO 2894 Algicide, in the Bearing Cooling TK-3.

Major Issues Considered

Probability or Consequences of Malfunctions - No modifications are being made to plant systems and their operation as a result of this change. The evaluated condition has no impact on events or mechanisms that could initiate the accidents listed in the SAR. There are also no physical changes to plant systems and components that perform accident mitigation functions. An accident of a different type is not created as a result of this document change or the change in the biocide used in the BC system.

Technical Specification / Operating License - The Technical Specification sections relevant to Control Room Habitability are:

"* Plant Systems, Control Room Emergency Habitability System Section 3.7.7.1, LCO and 4.7.7.1, Surveillance Requirements

"* Plant Systems, Bases, Control Room Emergency Habitability System Sections 3/4.7.7 The Technical Specifications are not affected in any way by this change. The Mechanical Engineering evaluation and corresponding UFSAR changes document the safety of Control Room habitability with the on-site chemical storage configuration per VPAP 2202.

Safe Shutdown Capability - The SE and corresponding UFSAR changes are performed to ensure the safety of the plant based on an updated evaluation of the on-site chemical storage configuration. In addition, the storage of the biocide does not alter the operation of any system, component or structure as defined in the UFSAR. Because there are no physical modifications to the plant operating systems and components associated with the changes, there is no impact on the station's ability to achieve and maintain safe shutdown in the event of a fire. In addition, operation from the Auxiliary Shutdown Panel will not be adversely affected.

The use of Isothiazolin compounds in the concentrations commercially available does not present a fire hazard. Magnesium chloride and Magnesium Nitrate are chemical bi-products found in the biocides.

Isothiazolin compounds and the chemical bi-products contained in the commercially available biocides are non-volatile in the available concentrations.

Environmental Impact - Mechanical Engineering has determined the plant to be safe with respect to the current chemical storage configuration. In addition, the replacement of Calgon H-5 10 with the NALCO 2894 Algicide or a copper-free biocide, equivalent to Calgon H-510 containing no more than 5% WT concentration of Isothiazolin compounds will not adversely affect the chemical storage configuration of the plant. Therefore, there will be no impact on the environment or the FES. Since no changes are being made to the plant operating systems or components, no changes in power level or effluents are expected. No change to the Environmental Protection Plan is required. Potentially increasing the % weight concentration of Isothiazolin compounds used in Calgon H-510 and Applied Specialties AS-590 from approximately 1.5

- 2.0% to 5.0%, or the use of NALCO 2894 Algicide containing a maximum 4.5% concentration of a slightly different Isothiazolin compound, will not violate our VPDES permit. The quantities of the biocide used in and discharged from the BC system are insignificant relative to the volumes of water involved, and there is no environmental impact.

For these reasons, these changes to the UFSAR & ME-0567 (Rev. 1) do not create an unreviewed safety question.

01-SE-OT-12 Description UFSAR Change Request FN 2001-013 Thermal Shock (PTS)

The UFSAR is being updated to include a revised 10 CFR 50.61 Pressurized material fabricated from weld 2 reactor vessel weld screening calculation result for the North Anna Unit OD 94%), with consideration given to Sequoyah wire heat 4278 (nozzle to intermediate shell weld 05A, Unit 2 plant-specific surveillance program data.

Summary PURPOSE an evaluation of the application of Sequoyah 2 The purpose of this Safety Evaluation document weld material fabricated from weld wire Heat 4278.

surveillance data to North Anna Unit 2 reactor vessel to the UFSAR description of the 10 CFR 50.61 The evaluation documented herein supports an update result for the North Anna Unit 2 reactor vessel Pressurized Thermal Shock (PTS) screening calculation to intermediate shell weld 05A, OD 94%).

weld material fabricated from weld wire heat 4278 (nozzle DISCUSSION Protection Against Pressurized Thermal Shock 10 CFR 50.61, "Fracture Toughness Requirements for information that could affect the level of Events", requires that licensees "consider plant specific surveillance program analysis results have been embrittlement." Sequoyah Unit 2 reactor vessel materials as well as into calculations that demonstrate incorporated into 10 CFR 50.61 PTS screening calculations, with 10 CFR 50 Appendix G, "Fracture the conservatism of analyses previously performed for compliance Revision 0, "Application of Sequoyah 2 Toughness Requirements". (See Technical Report NE-1274, Weld Material Fabricated from Weld Wire Heat Surveillance Data to North Anna Unit 2 Reactor Vessel 4278, North Anna Unit 2," dated April 2001 (14).)

SAFETY SIGNIFICANCE Integrity Database (RVID) by letters dated Dominion provided updates to the NRC's Reactor Vessel The updates considered available reactor vessel November 19, 1999 (1) and September 19, 2000 (2).

the North Anna Units 1 and 2 plant-specific materials surveillance data, including data obtained from programs (3) (4) (5) (6). During review of surveillance program as well as from other utilities' surveillance Reactor Coolant System (RCS)

Specifications proposed changes to the North Anna Units 1 and 2 Technical Overpressure Protection System (LTOPS) pressure/temperature (P/T) operating limits, Low Temperature (8) (9), the NRC reviewer noted that Sequoyah setpoints, and LTOPS enabling temperatures (Tenable) (7) 1 Nozzle-to-Intermediate Shell Weld 05B (ID Unit 2 surveillance data had been applied to the North Anna Shell Weld 05A (OD 94%) (2). Both of these 6%) (1), but not to the North Anna 2 Nozzle-to-Intermediate The NRC reviewer agreed that the North Anna welds were fabricated with weld wire heat number 4278.

non-limiting materials in terms of their Reference Units 1 and 2 Nozzle-to-Intermediate Shell Welds were but requested that Dominion provide updated RVID Temperatures for the Nil Ductility Transition (RTNDT),

2 surveillance data for the North Anna Unit data tables that included explicit consideration of the Sequoyah 2 weld fabricated from weld wire heat 4278.

Vessel Integrity Database (RVID) and an Revised North Anna Unit 2 data tables for the NRC's Reactor North Anna Unit 2 (2) have been prepared (14).

evaluation of changes relative to the previous RVID update for Sequoyah Unit 2 surveillance data on North Anna The evaluation in Reference (14) considers the impact of the (P/T) limit curves, (b) the associated 2 (a) licensing basis reactor coolant system (RCS) pressure/temperature enabling temperature, and (c) 10 setpoints and Low Temperature Overpressure Protection System (LTOPS)

The evaluation is performed in a manner CFR 50.61 Pressurized Thermal Shock (PTS) screening calculations.

the calculation of the Reference Temperature for consistent with applicable regulatory guidance. Specifically, Guide 1.99 Revision 2 (11),

the Nil Ductility Transition (RTNDT) is performed in accordance with Regulatory

minutes from the November 12, 1997 NRC/Industry and the regulatory guidance provided in the meeting 10 screening calculations were performed in accordance with meeting on reactor vessel integrity (12). PTS Evaluation results are presented in documented in Reference (13).

CFR 50.61 (10). Supporting calculations are Integrity Database (RVID).

of the NRC's Reactor Vessel a format consistent with the data requirements CONCLUSIONS screening criteria.

Anna Unit 2 continue to meet the applicable The PTS screening calculation results for North Technical Specification P/T of the current North Anna Unit 2 Further, the RTNDT value used in the development temperature remains conservative.

limits, LTOPS setpoints, and LTOPS enabling Specification 4, 2001 (8), and March 22, 2001 (9), a Technical By letters dated June 22, 2000 (7), January the North Anna Units 1 and 2 P/T request was submitted to the NRC for the purpose of modifying Units I and 2 change applicability limits for the existing North Anna limits, and extending the cumulative core bumup After consideration of the Sequoyah Unit 2 Capsule W LTOPS setpoints and LTOPS enabling temperatures. NRC by letters dated the RTNDT values previously provided to the analysis results, it has been determined that Technical Specification 2000 (2) that support the aforementioned November 19, 1999 (1) and September 19, change submittal remain valid and conservative.

of UFSAR changes do not increase the probability of occurrence or consequences The proposed PTS screening changes update the North Anna Unit 2 accidents previously analyzed. The proposed The 10 CFR 50.61 PTS screening criteria are 10 CFR 50.61.

calculations performed in accordance with of PTS events beltline materials. Therefore, the consequences met for all North Anna Unit 2 reactor vessel properties are not PTS calculations. Reactor vessel material are not increased by the revised screening by the revised PTS of occurrence of PTS events is not increased event initiators. Therefore, the probability screening calculation results.

type than UFSAR changes do not increase the possibility for an accident of a different The proposed were performed in Report. The PTS screening calculations previously identified in the Safety Analysis constitute new 10 CFR 50.61. None of the analysis parameters accordance with the methods prescribed by of a different type no possibility exists for creating an accident or unique accident initiators. Therefore, Report.

than previously analyzed in the Safety Analysis Revision the margin of safety. Technical Report NE-1274 The proposed UFSAR changes do not reduce margin of safety.

analyses provide an acceptable 0 (14) demonstrates that the proposed revised in UFSAR Change Request FN 2001-013.

Required UFSAR changes are documented

01-SE-OT-13 Description 290A - This Bases change will incorporate the Technical Specification Bases Change Request No.

outage time, bypass time, and surveillance plant-specific risk analysis performed to extend the allowed Pump Breaker Position (RTS Functional Unit 20 in frequency for the following functional units: 1) RCP Emergency Bus Undervoltage (Loss of Voltage)

Table 3.3-1), 2) ESFAS Loss of Power, 4.16 Kv of Power, 4.16 Kv Emergency Bus Undervoltage (Functional Unit in Table 3.3-3) and ESFAS Loss to in Table 3.3-3), and 3) Automatic Switchover (Grid Degraded Voltage) (Functional Unit 7.b table 3.3.2-1).

Containment Sump (Function 7 in our ITS submittal Bases to identify that a plant specific risk analysis was performed to support the Include a statement in the for the functional units in block 4.

increased AOTs and decreased surveillance frequencies Summary study which recommended an increase WCAPs noted in references 1, 2, and 3 document a Westinghouse to quarterly and the permissive interlocks to in the surveillance intervals of the analog instruments be shown to remain within the assumptions of the refueling, when protection setpoint drift data could the use of these WCAP's in licensing submittals to applicable safety analyses. The NRC has approved plant data. As approved by the NRC in amendments extend the surveillance intervals when supported by Specifications were revised to incorporate the 221/202, dated 03/09/00, North Anna Plant Technical and reduced functional testing of the Reactor Trip relaxations of Allowed Outage Times, test times (RTS/ESFAS) protection circuitry consistent with System/ Engineered Safety Features Actuation System (RCP Breaker Position Trip Above P-7, the WCAP references. However, three of the functional units 4.16 Kv Emergency Bus Undervoltage Loss of Power -

Functional Unit 20 in Table 3.3-1), 2) ESFAS

- Grid Degraded Voltage in Table 3.3-3), and 3)

(Functional Units 7a - Loss of Voltage, and 7b

7. in our ITS submittal) included and approved for Automatic Containment Sump Switchover (Function in the reference WCAP and NRC SERs.

the relaxations in the amendments were not fully evaluated to establish a basis for implementing the Therefore, a plant-specific risk assessment was performed approved relaxations for these functional Units.

outage times and completion times, The WCAP-14333P evaluated the impact of the relaxation of allowed damage frequency is 3.1 percent for frequency. The change in core and action statements on core damage not implemented the proposed surveillance test those plants with two out of three logic schemes that have evaluated in WCAP-10271 and its supplements.

interval, allowed outage times, and completion times in core damage frequency than the WCAP-10271 This analysis calculates a significantly lower increase realistic maintenance intervals used in the current analysis calculated. This can be attributed to more an alternative method of initiating the auxiliary feedwater analysis and crediting the AMSAC system as to be 3.1% for the proposed changes per the pumps. Therefore, the overall increase in CDF is estimated Westinghouse generic analysis.

impact on core damage frequency and large early The NRC performed an independent evaluation of the is indicate that the increase in core damage frequency release frequency. The results of the staffs review 4 percent for 2 frequency would increase by only small (approximately 3.2%) and the large early release allowed outage proposed surveillance test interval, out of 3 logic schemes that have not implemented the and its supplements.

times, and completion times evaluated in WCAP-10271 due to an increase in the RPS and ESFAS AOTs The impact on the Probabilistic Risk Assessment (PRA) considered minor. The evaluation used the North and surveillance interval from monthly to quarterly is in the CDF of approximately one percent. For Anna PRA model to estimate an overall change components such as those addressed by this configurations involving the instrumentation and protection impact is typically bounded by the CDF impact.

package, the Large Early Release Frequency (LERF)

(Reference 6) the relaxations to the RPS and ESFAS Amendments 221/202 to the North Anna TS approved However, two of the functional units for the current instrumentation AOTs and surveillance frequencies.

were not Technical Specifications and an additional function unit that is part of our ITS submittal to implement. This Bases modeled in the WCAP and therefore, required a plant-specific risk assessment to establish the acceptable change will document that a plant-specific risk assessment has been performed risk associated with the relaxations for these functional units.

model. However, its The reactor trip function on RCP breaker position is not included in the PRA with and without operator action, both above and below unavailability was specifically evaluated cause failures were evaluated. In each case, the total signal Permissive P-8. Both random and common of the signal unavailability is increased by about 60% by the proposed TS limits. The magnitude used to estimate the risk unavailability remains very small in every case. When these unavailabilities are by comparison to the risk sensitivity, their net impact is negligible. This latter point is made clear NOT risk-significant. Individual sensitivity of the trains of reactor protection, which are individually components of the reactor protection system are of proportionally lower impact.

may be assessed more The undervoltage/degraded voltage (UV/DV) EDG start is modeled and DV signals were evaluated. The net impact of the proposed TS change rigorously. Both the UV and the This failure mode is only is an increase in the EDG start-failure probability of approximately 0.8 percent.

failure probability marginally risk significant in a zero-maintenance configuration. The increase in start yields a CDF increase on the order of only 0.0 1%or <lE-8/yr.

UV/DV, and the Automatic The reactor trip function on RCP breaker position, the EDG auto-start on contributors at most to the core damage frequency. The Switchover to Containment Sump are minor AOTs have a negligible impact on CDF with a combined impact proposed increases in their TS STIs and sensitivities are easily bounded by the generic and plant-specific analyses of only about 0.01%. These previously reviewed and approved by the NRC for similar functions.

Water Storage Tank level The Automatic Switchover to Containment Sump occurs when the Refueling included in the North Anna Technical drops to the established setpoint. This function is not presently Anna converts to the Improved Technical Specifications, but it will be included when North to Containment Sump is being addressed in this Specifications. Thus, the Automatic Switchover estimated to increase by approximately 1.3E-4 as a result of the submittal. Its failure probability is function has a negligible proposed changes. However, the Automatic Switchover to Containment Sump unavailability also results in risk impact in the zero-maintenance configuration. This minor increase in its a negligible CDF impact.

(Amendments 221//202)

This Bases change supplements the original Technical Specifications change which relaxed the AOTs and modified the surveillance frequency requirements for the RTS and ESFAS start circuitry. As noted above, a plant-specific risk analog instrument channels, including the EDG UV/DV channels that were not included in the original WCAP-10271, Supp 1 assessment was performed for those addition, the following and 2 and WCAP-14333P risk analysis to establish the basis for the relaxations. In summarizes the safety evaluation determination of no unreviewed safety question.

ESFAS analog The increase in the allowed outage and maintenance times for the RTS and and the reduced surveillance frequency have no impact on instrumentation and the actuation logic any accident previously evaluated in chapter 15 of the UFSAR. The the probability of occurrence of to be operated in RTS and ESFAS Systems including the EDG UV/DV start circuitry will continue the same manner.

analog The increase in the allowed outage and maintenance times for the RTS and ESFAS circuitry have no impact on the instrumentation, the actuation logic and EDG UV/DV start data review specifically confirmed that quarterly consequences of the accident identified herein. The As such, the instrument drift remains within the assumptions of the protection setpoint analysis.

that all accident consequences remain within acceptable levels.

setpoints remain adequate to ensure and systems will be operable as assumed in the safety analysis to All safety components, structures, of the mitigate the consequences of the previously evaluated accidents. Therefore the consequences accidents identified above are not increased by the changes to the AOTs, bypassed times,

actuation logic and interlocks, surveillance interval for the RTS and ESFAS analog instrumentation, and EDG UV/DV start circuitry.

UV/DV start circuitry, will continue to be The RTS and ESFAS Systems, including the EDG outage and maintenance times for the analog operated in the same manner. The increased allowed logic and the decreased surveillance instrumentation channels and the automatic actuation do not establish any new method of plant frequencies for the analog instrumentation channels or accident precursors are generated by the operations. Therefore, no new modes of operation proposed Technical Specification changes.

generate unique accident risk. The RTS and No hardware or procedural changes will be made which will continue to be operated in the same manner.

ESFAS Systems and EDG UV/DV start circuitry in the TS are maintained.

requirements The operability requirements and minimum redundancy of operation are generated by the proposed Therefore, no new accident precursors or method Thus there is no reduction in the margin of changes. Existing safety analyses remain applicable.

safety.

01-SE-OT-14 Description Technical Specification Change Request No. 389 Operating Licenses References to Virginia Electric and Power Company in the North Anna Units 1 and 2 to Dominion Generation Corporation as a result of the and Technical Specifications will be changed as part of the Dominion's functional separation into regulated and pending license transfer being prepared unregulated entities.

Summary the licenses for its Virginia Electric and Power Company (Dominion Virginia Power) is transferring to electric industry restructuring nuclear facilities to Dominion Generation Corporation pursuant electric utilities in Virginia to separate laws in the Commonwealth of Virginia, which require functions. Dominion Virginia Power's generation generation from transmission and distribution Power Generation Corporation, while Dominion Virginia facilities will be transferred to Dominion conforming changes will retain its transmission and distribution assets and functions. Consequently, Licenses and accompanying Technical Specifications for North Anna to the Facility Operating of North Anna Power Power Station Units 1 and 2 are necessary to reflect the transfer of ownership changes delete references to Virginia Station to Dominion Generation Corporation. The proposed replace them with references to Dominion Electric and Power Company and variations thereof and operator of North Anna Power Station and make Generation Corporation as the new owner and transfers. No physical modifications are being made to plant minor changes that support the license changes in day-to-day operation of the units being affected. The systems or components nor are any as a result of the license personnel responsible for the safe operation of the plant will not change the proposed changes are solely administrative in nature and will not adversely transfer. Therefore, safety question does not affect nuclear safety or safe plant operation. Consequently, an unreviewed exist.

01-SE-OT-15 Description UFSAR Change Request No. FN 2001-007 of Generic Implementation The proposed UFSAR change incorporates the criteria and methodology Utility Group (SQUG) and endorsed by the NRC Procedure (GIP) developed by the Seismic Qualification enhancements, can be used as an alternative in their Safety Evaluations. The GIP methodology, with some verification of existing, modified, new and to the current licensing basis methods for seismic design and includes a brief description of median replacement equipment and components. The UFSAR change also the GIP, and minor editorial changes.

centered in-structure spectra that can be used in evaluations using Summary use of the GIP method as a cost-effective The proposed change to the UFSAR is being made to allow the of equipment. Relative to the current North Anna alternative method for demonstrating seismic adequacy in an equivalent or superior level of licensing basis, the GIP method, with additional considerations, results during and after a seismic event.

assurance that equipment will perform the required safety functions Therefore, the following applies:

a potential accident initiator

" The impact of the proposed change is considered on a seismic event as initiator of accidents previously and the change will have no impact on a seismic event as a potential analyzed in the UFSAR.

of the GIP method are the

" The only accidents in the SAR that could potentially be affected by the use Earthquake (DBE). However, the GIP Operating Basis Earthquake (OBE) and the Design Basis not increase the adequacy of equipment, will method, being a method for demonstrating seismic event as an a DBE. Therefore, with respect to the seismic likelihood of the occurrence of an OBE or a seismic event of occurrence of occurrence, the proposed change will not increase the probability because this event is the result of natural phenomena.

and performance of

" Assumptions in previously analyzed accidents in the USAR regarding availability Therefore, the proposed equipment to mitigate an accident following a seismic event are unchanged.

evaluated in the UFSAR.

change does not increase the consequences of an accident previously release consequences

" The only accidents in the UFSAR that could potentially have radiological in the UFSAR associated with the affected by the use of the GIP method are those accidents analyzed above, the However, as described Operating Basis Earthquake and the Design Basis Earthquake.

change no accident consequences.

proposed change will have no effect on them and will potentially affect the

" Use of a new method for demonstrating equipment seismic adequacy could important to safety to perform required safety ability of safety-related equipment or equipment affecting radiological release consequences. However, functions during or after a seismic event, thus equipment seismic will provide equivalent or superior assurance of the use of the GIP method will have no Thus, use of GIP adequacy to that provided by the current North Anna licensing basis.

effect on radiological release consequences.

a subset of equipment

" The UFSAR requirements regarding seismic adequacy of equipment include adequacy requirements. The UFSAR also (i.e., safety-related and NSQ) that must meet seismic will provide an adequacy. The proposed change discusses the method for demonstrating seismic of equipment adequacy and does not change the subset alternative method for demonstrating seismic that regulatory requirements. The change will continue to ensure that must meet seismic adequacy requirements regarding seismic adequacy of equipment are met.

meet seismic adequacy

" The proposed change does not affect the set of equipment that must UFSAR, therefore, it does not create requirements or the level of seismic adequacy as defined in the in the UFSAR.

the possibility of an accident of a different type than previously evaluated UFSAR is considered to

" Malfunction of safety-related or NSQ equipment previously evaluated in the during and after a seismic event.

ensure that such equipment would perform required safety functions change. Therefore, the proposed change No equipment important to safety is affected by the proposed malfunction of equipment important to safety will not increase the probability of occurrence of a previously evaluated in the UFSAR.

assurance that equipment will withstand

• The GIP method provides an equivalent or superior level of discussed in Appendix A, the GIP method various potential seismic failure modes. Further, as real earthquakes that are not addressed in the addresses specific seismic failure modes identified during proposed change will not introduce any new current North Anna licensing basis method. The possibility of a malftnction of equipment equipment failure modes and thus does not create the evaluated in the UFSAR.

important to safety of a different type than any previously is required.

"* No change to Operating License or Technical Specifications and maintain safe shutdown

"* The proposed change does not affect the ability of the Station to achieve in the event of a fire.

whether previously evaluated

" The proposed change does not cause any adverse environmental impact or not in the FES.

level

"* The proposed change will not involve any change in effluents or power plan.

protection

"* The proposed change will not cause any change to the environmental safety question is created by this UFSAR change The safety evaluation herein shows that no unreviewed The use of the GIP will not affect the ability of and, as such, the use of the GIP method is acceptable.

to perform required safety functions during or safety-related equipment or equipment important to safety with this evaluation is summarized as after a seismic event. The background information associated follows.

- The GIP method has been extensively reviewed.

GIP has been reviewed and accepted by the NRC USI A-46, which was issued by the NRC to address GIP-2 was approved by the NRC [4] for resolution of concerns with early seismic qualification techniques.

The NRC has also approved GIP-3 in SSER NO. 3 [5].

used in GIP-2 and GIP-3 have been reviewed and GIP meets the intent of the regulations - The methods A-46 plants in SSER No. 2 [4] and SSER No. 3 accepted by the NRC for Unresolved Safety Issue (USI)

"satisfy the pertinent seismic requirements of

[5]. In SSER No. 2, the NRC stated that the GIP-2 methods NRC regulations relevant to equipment seismic General Design Criterion 2 and the purpose of the 2 statement covers application of GIP-2 to not only adequacy including 10 CFR Part 100." This SSER No.

also new and replacement equipment which may be existing as-installed equipment in USI A-46 plants, but installed in USI A-46 plants.

an unreviewed safety question or in a reduction of To demonstrate that the use of the GIP will not result in a detailed comparison of the GIP with key safety margin relative to the North Anna licensing basis, This comparison is shown in Appendix A to this elements of the North Anna licensing basis is performed.

and the North Anna licensing basis are identified safety evaluation. Differences between the GIP method safety margin is determined. The results cumulative relative and the effect of the differences on the overall plant margin of safety.

demonstrate that the use of the GIP method will not reduce

01-SE-OT-16 Description UFSAR Change Request FN 2001-011 with an additional minor change to The change is to chapter 9.5.1 of the UFSAR, Fire Protection System, will consist of revisions to the description for manual Chapter 3.5, Missile Protection Criteria. The change Tank, so that it is consistent with current fire foam hose streams for the protection of the Fuel Oil Storage system within the records storage room will be fighting strategies. In addition, a reference to a halon have been removed. Associated with that deleted, since the records stored there and the halon system sprinkler system protecting the records room change, will be the addition of a description of the preaction used for fire fighting will be clarified.

within the Records Building. Lastly, the description of SCBA's Summary 9.5.1, Fire Protection System, Nuclear Oversight Audit 01-02 identified some discrepancies within section foam hose stream capabilities of an inadequate description of of the UFSAR. These discrepancies consist 9.5.1.3.1.2), an incorrect reference to a halon for protection of the Fuel Oil Storage Tank (9.5.1.2.1 and description of SCBA's used for fire fighting system that has been removed (9.5.1.4.1.2), and an unclear discrepancies, such that the UFSAR descriptions (9.5.1.2.4.4). The changes will correct and clarify these capabilities.

are consistent with current fire protection equipment and 2.C.(23) allow the Licensee to make Unit 1 license condition 2.D.(3).u and Unit 2 license condition affect the ability to achieve and would not adversely changes to the fire protection program if those changes to achieve and maintain safe shutdown in the maintain safe shutdown in the event of a fire. The ability using a foam hose stream to protect the Fuel event of a fire will not be degraded. The UFSAR describes stream, if needed, will be supplied from one of Oil Storage Tank from a nearby hose house. The foam hose UFSAR describes a halon system for the records the portable foam carts available on site. In addition, the from this room; therefore, the halon system room in the office building. The records have been removed are now stored within the records room in the was no longer needed, and has been removed. The records for this room in the form of an automatic Records Building. Adequate fire suppression is provided with Reg. Guide 1.88 and NFPA 232-1975, as preaction sprinkler system. This is in conformance for SCBA use for fire fighting has not described in Chapter 17 of the UFSAR. The method of operation been changed.

to the Fuel Oil Tank and Pumphouse does The change to the method used for applying foam hose streams on the tank or within the pumphouse. The not adversely affect the ability to manually combat a fire did not specify the quantity of foam required.

original description for the use of a manual foam hose stream 266, identified the original intent was for a manual foam hose A review of the original specification, NAS and Pumphouse. In both cases, the system was stream for spill protection of the Fuel Oil Storage Tank systems installed. NAS 266 specified intended to be a back-up suppression system to the fixed suppression stream. A total often, 5 gallon cans, were the use of 5 gallon cans of concentrate to produce the foam hose units contain 32 gallons of foam, specified to be contained within the hose house. The existing portable a total of 4 - 32 gallon portable There are and have an approximate discharge time of 18 to 20 minutes.

to the fire fighting strategy provides greater units available for fire brigade use. In addition, the change on the Fuel Oil Storage Tank or Pumphouse.

flexibility to the fire brigade for providing a foam hose stream hydrant they chose. This ensures a foam The use of portable units will allow the brigade to use any nearby blocked by smoke and flames. A sufficient hose stream can be applied even if access to one hydrant is by the fire brigade, to combat a fire on quantity of foam is available on site, and can be quickly retrieved the existing foam hose stream capabilities the Fuel Oil Storage Tank or adjacent pump room. As a result, within the UFSAR.

exceed those original specified within NAS 266, and described within the Office Building area since The elimination of the halon system does not decrease the protection been provided for the records within the the records storage has been moved. Adequate suppression has are administrative, and do not impact their Records Building. The changes to the description of SCBA's the station's compliance with 10CFR50 function or operation. The UFSAR changes do not impact

Appendix R, and it's ability to safely shutdown in the event of a fire. The changes do not relax established requirements or change the method in which safe shutdown is achieved and maintained.

The current North Anna License condition allows the licensee to make changes to the fire protection program without NRC approval if those changes do not adversely affect that ability to achieve and maintain be safe shutdown in the event of a fire. The ability to achieve and maintain safe shutdown will not adversely affected. 10CFR50, Appendix A, General Design Criteria (GDC) 3, discusses the minimum system level of fire protection that must be maintained at the station. This change will eliminate the halon records room. This is acceptable since the records have been removed from this for the office building has not been area. The capability to apply a foam hose stream to the Fuel Oil Storage Tank and pumphouse systems adversely affected, only the description on the equipment used to achieve this has changed. All and equipment relied upon to meet Appendix R requirements will continue to be in place and operable.

or There will be no adverse impact on the station's compliance with GDC 3. This change does not create impact an unreviewed safety question.

01-SE-OT-18 Description Units 1 and 2 UFSAR Section 15.2.7, "Loss of Change Request No. FN-2001-005 for North Anna 15.2-1 and the associated figures.

External Electric Load and/or Turbine Trip," Table the 15.2.7 and the associated table and figures of This safety evaluation supports a revision to Section accident Analysis Report (UFSAR). The loss of load North Anna Units 1 and 2 Updated Final Safety analysis techniques within the constraints of applicable reanalysis was performed using updated in-house analysis requirements.

Summary PURPOSE Turbine 15.2.7, "Loss of External Electric Load and/or This Safety Evaluation supports a revision to Sections Final Safety Analysis Report (UFSAR), for the Updated Trip," Table 15.2-1 and the associated figures of North Anna Units 1 and 2.

BACKGROUND of the the incorporation of a revised UFSAR description This safety evaluation has been prepared to support analysis. The primary technical reference (LOL) accident Loss of External Electric Load and/or Turbine Trip description is Calculation SM-1259, Revision 0 (Reference 1), which summarizes an for the revised UFSAR 1 and 2. Calculation SM-1259, Revision 0 was prepared updated LOL accident analysis for North Anna Units techniques and the associated figures. These updated analysis to revise UFSAR Sections 15.2.7, Table 15.2-1 IBM main frame; (b) Use IBM-AIX 4.3.2 platform instead of include: (a) Use of RETRAN2, Mod5.2 code on and (c) Use of decay heat side of steam generator, of Local Condition Heat Transfer model in the secondary model based on ANSI 1979 decay heat model.

SUMMARY

OF LOL ACCIDENT ANALYSIS or a event resulting from loss of external electrical load The Loss of Load/Turbine Trip transient is a heatup rise in secondary flow from the SG resulting in a quick turbine trip. This causes a rapid reduction of steam pressures. The transient is terminated either by a direct Rx side pressures and primary side temperatures and pressure. The primary and secondary side pressure trip or, in the limiting case, a Rx trip on high pressurizer limits. The limit the maximum pressures to within design relief systems are confirmed to be adequate to and is not limiting with respect to core core thermal limits transient continues to have ample margin to the thermal margins.

available for the continued operation of plant components During this event, offsite power is assumed to be the Loss with loss of all offsite power is covered under such as the RCPs. The case of the transient occurring of Offsite Power event.

that Turbine Trip analysis is performed to demonstrate One case of the Loss of External Electric Load and/or limiting reactor criterion. Another case assesses the the limiting minimum DNBR is above the acceptance their respective acceptance criteria. As a result of this coolant and main steam system peak pressures against generator from 2740.4 psia to 2737.5 psia, the peak steam analysis, the peak cold leg pressure decreased 2.15 to 2.186. The accident The MDNBR increased from pressure decreased from 1184.4 psia to 1174.6 psia.

analysis satisfies the applicable event acceptance criteria.

description of the LOL accident analysis, the following With respect to the proposed revision to the UFSAR conclusions are applicable:

is not increased by the incorporation of the revised

a. The probability of occurrence of the LOL accident The analyses, Table 15.2-1 and the associated figures.

UFSAR Section 15.2.7 description of the accident requirements to ensure that Specification and procedural proposed UFSAR text relies on existing Technical

or method of operation is being the LOL accident analysis remains valid. No system configuration, design the LOL accident is not increased.

changed. Therefore, it is concluded that the probability of occurrence of does not create the possibility of an

b. The implementation of the proposed changes to the UFSAR section in the SAPR. All applicable accident analysis accident of a different type than was previously evaluated will continue to be met. No system configuration, acceptance criteria, including accident propagation criteria, are introduced. The No new or unique accident precursors design or method of operation is being changed.

to control the plant under normal and proposed changes that will not compromise the ability of operators remains adequate.

accident conditions since the heat removal capacity of the system by the incorporation of the revision to

c. The margin of safety in the LOL accident analyses is not reduced The proposed UFSAR change does not UFSAR Section 15.2.7, Table 15.2-1 and the associated figures.

accident analysis for the LOL event shows adequate change the plant configuration or mode of operation. The the margin of safety will not be reduced by the margin to the event acceptance criteria. Therefore, implementation of the proposed UFSAR change.

01-SE-OT-19 Description Technical Requirements Manual, Section 12.2, EQ Doors Probabilistic The change to the Technical Requirements Manual (TRM) is the result of revisions to the and the evolution of the EQ Barrier Program. These changes are Safety Assessment, clarifications and limitations of administrative in nature and are designed to aid the user in understanding the restrictions the Program.

Summary 12.2, EQ Doors.

The change being evaluated is a revision to the Technical Requirements Manual, Section The change to the TRM is the result of revisions to the Probabilistic Safety Assessment (PSA),

the EQ Barrier Program. These changes are administrative in nature and clarifications and the evolution of are designed to aid the user in understanding the restrictions and limitations of the Program.

as they are maintained Four (4) EQ Doors which are not captured in the Probabilistic Safety Assessment, doors are being added to provide a more closed and locked are added with a note stating such. These identified that not all EQ Doors were listed in comprehensive list of EQ Doors. Plant Issue N-2000-2032 two (2) additional doors, which had been added in the the TRM. One of the initial actions incorporated PSA but had not been incorporated into the TRM at that time.

Specifically:

unless evaluated by Note a. on page 12.2-3 is being revised to ensure only one door is breach at a time Engineering.

the ESGR 1 & 2 Note c. on page 12.2-3 is being revised to add Chiller Room doors. The doors separating to the PSA. The same restrictions applied to the Unit 2 and the Chiller Rooms were added by a revision apply to these doors as the Potentially Harsh Environment (Turbine ESGR to the Turbine Building Building) and the affects on equipment are the same.

& 2 and the Chiller Note c. & d. on page 12.2-3 are being applied to the doors separating the ESGR 1 ESGR-2 to Turbine Building, but as Rooms. These notes were originally applied to the door separating the stated above these two (2) doors and areas are subject to the same Harsh Environment.

Revised note b. on page 12.2-4 for clarity and readability.

two (2) doors in Added note c. to page 12.2-4 to clarify the EQ Door Breach Duration of 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> for the the Unit 2 ESGR is a total for the zone not 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> per door.

of EQ Doors. They Added four (4) doors to Table 12.2-2 on page 12.2-4 to provide a more complete list are:

01-BLD-STR-A59-1 Electrical Penetration Area Unit 1 to Auxiliary Building 01-BLD-STR-A80-1 Control Rod Drive Room Unit Ito Auxiliary Building 01-BLD-STR-A59-2 Electrical Penetration Area Unit 2 to Auxiliary Building 01-BLD-STR-A80-2 Control Rod Drive Room Unit 2 to Auxiliary Building do not have PSA Added note d. to page 12.2-4 to inform the user the doors added to Table 12.2-2 (above) closed and locked. A breach to these doors requires a separate time as they are normally maintained Engineering evaluation on a case by case basis.

profile of the EQ This TRM revision is administrative in nature intended to provide a more comprehensive Barrier/Door Program is Door Program. These changes do not direct any Operator actions. The EQ sections of the TRM being revised are administered by Engineering and controlled via VPAP-0305. The created by this TRM revision.

informative only. As a result, there is no unreviewed safety question

01-SE-OT-20 Description Fuel Anomaly NDCO 1-9 Addendum 2 intention to conditionally remove the handling Fuel Anomaly NDCO1-9 Addendum 2 documents NAF's references 3 and 5 as susceptible to Intergranular restrictions from fuel assemblies that were identified in based upon the results of video inspections.

Stress Corrosion Cracking (IGSCC) of thimble sleeves Summary criteria for conditionally removing the handling Reference 2 provides video inspection acceptance in references 3 and 5 as susceptible to Intergranular restrictions from fuel assemblies that were identified Reference 2 concludes that fuel assemblies that Stress Corrosion Cracking (IGSCC) of thimble sleeves.

or other abnormalities at the bulge joints attaching have no indications of reddish-brown oxide, cracking, using the normal spent fuel tool. Fuel Anomaly the guide thimble to the top grid sleeves may be moved remove the handling restrictions from inspected fuel NDC01-9 Addendum 2 documents NAF's intention to documented in Reference 2. This will allow fuel assemblies that meet the video inspection criteria using the normal spent fuel tool and established assemblies that are susceptible to IGSCC to be moved are currently considered valid only until the procedures. Reference 2 indicates that the visual inspections whichever comes first, after which the bulge fuel is handled using the normal tooling or for three months, before moving the assembly using the normal spent joints should be re-inspected to confirm their integrity to IGSCC will be controlled by References 4 fuel tool. The handling status of fuel assemblies susceptible and 8.

fuel in the spent fuel pool using the normal The activity evaluated involves the movement of irradiated Accident Outside Containment, discusses the spent fuel tool. Section 15.4.5 of the UFSAR, Fuel-Handling and analyzed therein as the drop of a freshly applicable accident analysis. The accident is described leading to the damage of all the rods in the fuel discharged fuel assembly (100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> after shutdown) assembly and the subsequent release of activity.

that have been in the spent fuel pool in excess of The proposed activity involves movement of assemblies with these assemblies; additionally the whole one year. Therefore there is no iodine source term associated the assembly would be significantly less than analyzed body doses associated with the failure of all rods in in the UFSAR. Therefore the consequences cannot be increased.

above cannot be increased by the proposed activity The probability of occurrence of the accident identified by virtue of several independent considerations, namely:

increased, because the visual inspection program

1) The probability of dropping a fuel assembly is not (Reference 1) is designed to identify fuel assemblies in the approved in Safety Evaluation 01-SE-PROC-11 cracking that exhibit corrosion. Only assemblies population susceptible to thimble sleeve stress corrosion from handling restrictions. In accordance with that do not exhibit signs of corrosion are being removed a period of 3 months provided no additional handling Reference 2, the handling restriction is removed for or the 3 month period expires then new video occurs during that period. If additional handling is required, of the thimble sleeve has occurred. Assemblies that inspections are required to verify that no degradation in the normal manner. Thus eliminating the exhibit signs of corrosion remain restricted from handling failure.

potential to drop a fuel assembly due to thimble sleeve fuel assembly is not increased. The assemblies in

2) The probability of dropping a freshly discharged of one year. Note that there is no 1-131 source question have all been in the spent fuel pool for in excess and analyzed in the UFSAR (drop of a freshly term in these assemblies, so the accident defined, identified cannot have its probability increased.

discharged fuel assembly (100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> after shutdown))

of equipment important to safety. 1) Failure to The safety evaluation also considered several malfunctions charcoal filter. 2) Failure of the monitors to divert fuel building exhaust to the particulate and activated incident. It was concluded that alarm on a high radiation level to indicate a possible dropped-fuel-assembly

moving the assemblies in question would have no effect on the availability and reliability of equipment excess important to safety. Also, since the assemblies in question have all been in the spent fuel pool for in so there are no consequences of losing these of one year there is no 1-131 source term in these assemblies, design features.

by this proposed Finally, since the results of the UFSAR fuel handling accidents remain unchanged activity, there is no reduction in safety margin.

01-SE-OT-22 Description Technical Requirements Manual (TRM) Change Request # 45, ET N-00-0138, Rev 0. Deviation / Plant Issue Report: N-99-0774. NAPS Appendix R Report Changes to the TRM are the result of revisions needed to clarify: a) Appendix R / Fire Protection compensatory measures, b) Fire Brigade manning, and c) Appendix-R Alternate Shutdown Equipment fire watch locations and their bases.

Summary This Safety Evaluation supports changes / enhancements to applicable sections of the North Anna Technical Requirements Manual (TRM) relative to: a) Appendix R / Fire Protection compensatory measures, b) Fire Brigade manning, and c) Appendix-R Alternate Shutdown Equipment Fire Hose Station locations and their bases.

During planning to replace fire protection isolation valve 1-FP-157, per Work Order # 00356864-01, it was noted that verbatim compliance with TRM 7.1.5 was not reasonably achievable. The replacement of this valve would require all the fire hose stations within the Auxiliary Building to be inoperable. The existing compensatory measures required that additional equivalent capacity fire hose be routed to the Auxiliary Building from operable hose stations. This could not reasonably be achieved. As a result, ET N-00138, Rev-0 was developed to provide alternative required actions involving: a) the establishment of an hourly fire watch and b) staging additional fire protection mandated by the Safety and Loss Prevention Department.

A re-assessment of a recent revision to TR 7.3, requiring that two of the five Fire Brigade members per shift be from the Security Department was determined to undermine the smooth operation of the Brigade and has subsequently been deleted. Further review noted that 10 CFR 50, Appendix R, and North Anna Emergency Procedures only require that the Fire Brigade have at least five (5) qualified members on each shift and that the brigade leader and at least two (2) brigade members have sufficient training in or knowledge of plant safety-related systems to understand the effects of the fire and fire suppressants on safe shutdown capability, and these requirements remain in the TRM.

Deviation Report N-99-0774 identified inadequacies associated with TRM 7.5 relative to Appendix R Alternate Shutdown Equipment. Corrective actions included in ET N-00138, Rev-0, consisted of providing better descriptions, including footnotes, for Fire Watch Locations in Table 7.5-1, as well as the development of a Bases to further describe Appendix R Alternate Shutdown Equipment.

Unit I License condition 2.D. (3). u and Unit 2 License Condition 2.c.(23) allow the Licensee to make changes to the fire protection program if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. The ability to achieve and maintain safe shutdown in the event of a fire will not be degraded. The recommended changes enhance compensatory measures for alternate shutdown equipment and fire hose stations, and provide a bases for the fire watch locations listed for alternative shutdown equipment. The changes to the Compensatory measures within TRM 7.1.5, Fire Hose Stations are necessary to allow normal maintenance on fire protection components. The additional, proposed, compensatory measure provides an equivalent measure of protection to those existing. As a result, the changes do not relax established requirements or change the method in which safe shutdown is achieved and maintained.

The current North Anna License condition allows the licensee to make changes to the fire protection program without NRC approval if those changes do not adversely affect that ability to achieve and maintain safe shutdown in the event of a fire. The ability to achieve and maintain safe shutdown will not be adversely affected since the changes do not affect the ability of any system to function as designed. 10CFR50, Appendix A, General Design Criteria (GDC) 3, discusses the minimum level of fire protection that must be maintained at the station. This change will not eliminate any fire protection

system or equipment. All systems and equipment relied upon to meet Appendix R requirements will continue to be in place and operable. There will be no adverse impact on the station's compliance with GDC 3. This change does not create or impact an unreviewed safety question since this is a document update that enhances compensatory measures and provides a bases for alternative shutdown equipment compensatory measures.

SAFETY EVALUATION LOG MODIFICATIONS 2001 SNSOC Date Unit Document Sys te m u Des , , o n,,

3-2-95 1,2 Pressurizer Heater Electrical Repairs DCP 94-159-3 95-SE-MOD-1 3 8-1-95 DCP 95-131 Nuclear Building Ground Water Intrusion 1,2 "95-SE-MOD-53 4-24-97 Refurbishment of Service Water Pumps 1,2 DCP 95-015 95-SE-MOD-80, Rev. 3 12-14-95 Fire Damper Modifications 1,2 DCP 94-271 95-SE-MOD-83 Plugs 2-5-96 Removal of Containment Concrete Floor 1,2 DCP 95-242 96-SE-MOD-06 3-14-96 Repair/Replacement of Exposed Service Water Piping Exchangers  : to I 1,2 DCP 94-010, Field Cooling Heat 96-SE-MOD-20 from Component Change No. I Tank 4-15-96 Refueling Water Storage Tank / Casing Cooling 96-SE-MOD-23 I 2 DCP 95-190 Manway Strongbacks 8-7-96 Con~densatee Polishing SytemUgae 2 DCP 95-002 96-SE-MOD-33, Rev.1 -arrging Pump isDischarge Head and Seal Housing 7-3-96 1,2 DCP 95-216 Replacements 96-SE-MOD-34 12-5-97 Component Cooling Heat Exchanger Replacement 97-SE-MOD-34, 2 DCP 97-003 Rev. 1 Outside Recirculation Spray Pump Motor Replacement 3-30-98 2 1 DCP 97-014 98-SE-MOD-1 0 Test Dike 4-1-99 Relocate Recirculation Spray Pump Temporary Water DCP 99-125 Reactor Head Stand 99-SE-MOD-03 2 Panel Storage for Installation of Shields 4-15-99 Service Water Install Recirculation Spray Heat Exchanger 2 DCP 98-172 Check Valve Inspection Ports 99-SE-MOD-05 6-10-99 Security System Magnetic Door Lock Enhancements 1,2 DCP 99-106 99-SE-MOD-06 7-29-99 Blowdown System Upgrade 1,2 DCP 99-119 99-SE-MOD-1 2 1 DCP 99-135 Lube Oil Sample Test Ports j 8-3-99 99-SE-MOD-14 Orifice 8-24-99 Charging Pump Minimum Flow Recirculation 1,2 DCP 99-142 Replacement 99-SE-MOD-19 I

SAFETY EVALUATION LOG MODIFICATIONS 2001 SNSOC Date System Description S.E. # Unit Document 8-24-99 1,2 DCP-98-007 Feedwater Flow Calorimetric 99-SE-MOD-20 8-31-99 Permanent Installation of Thermocouple Cards into 2-MUX 99-SE-MOD-21 2 1 DCP 99-145 21A 3-29-00 Main Generator Redundant Protection and Negative 99-SE-MOD-24, DCP 97-007 Sequence Detection I Alarm Rev. I 5-16-00 Auxiliary Building Central Area Exhaust Damper Instrument 99-SE-MOD-28, 1,2 IDCP 99-130 Air and Electrical Power Modification Rev. 1 10-3-00 IDCP 00-138 Reactor Vessel Level Indication System (RVLIS) Sensor 2 Bellows Reorientation 00-SE-MOD-1 3 10-5-00 Main Feedwater Regulating Valve Actuator Air Supply 00-SE-MOD-14 2 DCP 00-148 Modification 11-8-00 Modifications to NUREG-0612 Special Lifting Devices 00-SE-MOD-1 13 1,211 DCP 00-005 7-17-01 Replaces the current Kaman process & vent stack DCP 99-006 & test 01-SE-MOD-02 1,2 plan particulate, iodine, &gaseous radiation monitors 1-GW-RM UFSAR FN 99-065 178, 1-VG-RM-179, & 1-VG-RM-180 with a radiation P1 N2000-2146 monitor system manufactured by MGP Instruments.

Special Rpt 01-295 Currently installed Westinghouse, NRC, &General Atomic &

HP-3010.040 radiation monitors 1-GW-RM-101/102, 1-VG-RM-103/104, HP- 3010.031 1-VG-RM-1 12/113 will be removed.

HP PT-453.01 HP PT-406.01 0-NAT-1-002 0-NAT-M-005 EPIP-1.01; EPIP-4.08; EPIP-4.09; EPIP-4.24 EALs B-4, B-7, C-7, C 9, E-3, E-5, G.1 & G-2 VPAP-2103 (N) 0-WP-G99006 L-----

2

95-SE-MOD-13 Summary to the pressurizer heaters.

DCP 94-159-3 authorizes a different method of making electrical connections of using standard mechanical hardware. Also the replacement This method utilizes brazing the lug instead of damaged and shortened high temperature cables with a new type.

Description failure rate due to corrosion.

The pressurizer heater connections have been demonstrating an unacceptable new replacement cable should reduce The new connection method combined with the Cu/Ni alloy of the Further, some of the cable replacements the corrosion resulting in improved pressurizer heater reliability. due to the heaters that have been left disconnected and connector repairs should allow restoration of some damage caused by the connector failures.

An unreviewed safety question does not exist because:

of

"* The implementation of this DCP will not increase the probability of occurrence or the consequences in the UFSAR evaluated an accident or malfunction of equipment important to safety and previously The different cable terminations are because the components being modified are not safety-related.

like for like. The replacement cables are like for like with qualified material.

of a

"* The implementation of this DCP will not create a possibility for an accident or a malfunction UFSAR because the individual components will different type than any evaluated previously in the The exposed to any different risk factors than before.

operate the same as before and will not be termination method is expected to provide improved reliability.

basis of any

"* The implementation of this DCP will not reduce the margin of safety as defined in the the ability of the pressurizer heaters to contribute to their Technical Technical Specification because improved reliability.

Specification role will not be altered and may be enhanced by virtue of

95-SE-MOD-53 Summary DCP 95-13 1, Nuclear Building Ground Water Intrusion buildings. This The purpose of the design change is to eliminate ground water intrusion into various plant as liquid radwaste. It amount of ground water that is processed out of the building drains will minimize the area housekeeping.

will also reduce the potential for the spread of contamination and improve Description ground water. The leaking expansion Various building expansion joints and concrete joints are leaking repair by removing the metal expansion joint cover and joints will be disassembled for inspection and by placinga compressible hydro active existing compressible joint filer material. The leak will be repaired leaking concrete construction joints chemical grout foam expanded gasket within the expansion joint. The that are angled to intersect the crack will be repaired by drilling small diameter holes adjacent to the joint injected with a hydro active chemical near the midpoint of the structure. The construction joints will be grout to stop the leak.

This modification / repair should be allowed because:

are not increased. Repair of the The probability of occurrence of an accident or equipment malfunction no effect on the probability of a leaking building expansion joint and concrete construction joints have of safety equipment due to ground LOCA, MSLB or earthquake occurring. The probability of malfunction since the charging pump cubicle blocks water intrusion flooding in the Auxiliary Building has not increased floor at elevation 244'-6".

are conservatively sealed to a minimum of 44" above the increased since leaktight integrity of the The consequences of an accident or equipment malfunction are not the containment and adjacent containment will be maintained. Sealing the expansion joints between accommodate movements of building structure that house safe shutdown equipment is designed to differential building seismic containment associated with LOCA/MSLB internal pressure and building expansion joints to meet displacements. Adequate compressible material will be installed in the with non compressible material or original design basis and prevent the space from inadvertently filling buildings is therefore maintained.

debris. Structural integrity of safety-related and seismic type than was previously evaluated The possibility for an accident or equipment malfunction of a different joints and concrete construction cannot be attributed to the inspection and repair of leaking expansion interior fire areas and backfilled joints. The expansions joints provide an opening between building is no possibility for the passage or building exterior. Since there are no below grade fire hazards, there small diameter holes for grout injection at spread of heat or flame from one fire area to another. Drilling of the massive concrete structures since no rebar will be construction joints will not compromise integrity of approval. The expansion joint repair will utilize a cut without prior Engineering evaluation and will maintain seismic independence of adjacent concrete structures.

compressible chemical grout foam that not reduce the margin of safety as The implementation of this DCP is not described and therefore will defined in the basis of any Technical Specification.

Safety 3hraluation Page 1 of 12 VPAP-3001 MV

2. Applicable Station 3. Appilsda*t Unft F . Safety Evaluation Nuinbe 95-SE-NODM-80, Itev.3 Ex] North Anne Pyowr station Ex] Unit I ExI Unit 2 E I Surry Power station I Unit I C 3 unit 2*

4. List the governing documnta for which this safety evaluation me parfrotd.

DCP-95-015, REA No.9s-/40 S. Surmmrize the change, test, or experimnt evaluated.

Service Water (SI) pump 2-SW-P-1A is currently in the Atert range for vibration based on results of recent periodic test 2-PT-75.ZA. This pumpus in the ALert rawe twice in the last two years. The pump aLso show 20 ft of head degradation since 19M9. Other SW pumps are also experiencing degradetion, although not as severe as pump 2-3W-P-1A.

AtU four pimps are beyoni the Cr ce add 10 year interval for tear dawn and inspection. KP-95-015 is an evaluation and guideline for one at a time repltaIment of the existing SI pumps with the mn ams which are similar but not exact replacemnt-In-kind of the existing ones (stainless steel impqasir instead of bronze impeller, slightly different pump performmnce).

6. State the purpose for this change, test, or experiment.

Purpose of DCP-95-01S Is on evaluation and guideline for one at a time reptacement of the existing St pumps with the now ones which are similar but not exact replacement-in-kind of the existing ones (stainless steel ispeLLer instead of bronze iptelLer, slightly different pimp perforamnce). Note, that this revision of the M is issued to incorporate ehunges which were done due to final issue CRev.1) of JC0-95-03 and to reflect possibility of installation of alternate support of the SM pimp coLumim.

7. List all limiting conditions and special requirements identified or assumed by this safety analysis. For eah item, indicate the forml tracking mechenim that will be used to ensure that these conditione and/or rq*i emen mill be met.

Since one at a time replacement of the SW pumps requires more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, entering TS Section 3/4.7.4.1.a wiLl be required for the each pump replacement. Three other pumps should be operable during this reptaceent. SW pump replacement will require temporary removal of removabLe blocks on the SW pump house roof, i.e. missile protection barrier will be partially removed. RemovaL of the blocks will be guided by station procedures O-AP-41, Operations tandard 007 and 0-N*O-1304-01. Note, that in accordance with the latest revision of JCD-95-03 (Rev.1 dated 02-06-9) all required limitations including requirements of Standing Order No 213 have been incorporated into corresponding documentation, so standing order No.213 and the JCO have been closed on 03-18-96.

8. Will the proposed activity/condition result in or constitute an unreviewed safety question, an unrevieved env.rone.entaL question, a change to the Fire Protection Program that affects (C Yes Exl No the abiIity of the station to achieve and maintain safe shutdown in the event of a fire, or require a license men I ant or Technical Specifications change?

sf*ofty zvaluatiJ.au Page 2 of 12 the reomn the

18. Summarize from Part D, 1-,revtemad Safety Osustiion Ieterslintion, the major Issues considered; statedoes nit mist dmlinge, test, or exmper 'eat should be allowed; and state why an unrielewed safety question does or (a simple conclusion statotsnt is insufficient).

of recent periodic Service Water (IW) plmp 2-SM-P-1A is currently in the Alert rnge for vibration besed an results 20 ft of heed test 2-PT-75.2A. This pump Was in the Alert raie twice in the last two years. The pImp also shom degradation since 1W69. Other SM pus are also eperencing degradation, othee* not as ~ere as PP 2-S1-P-IA.

is an All four pumps are beyond the Ro recommended 10 yer interval for tear down and Inspection. 00-0-MS but evatuation end guideline for one at a ties replacement of the existing S pops with the new ones which ore similar not exact rpla mnt-in-kind of the existing ones (stainless steet ispetler instead of bronze iquetter, slightly different pimp performance). Note, that this revision of the E Is issued to Incorporate chm g l-hich were done due to final issue (Nev.1) of JCO-95-03 and to reflect possibility of installation of alternate support of she Si o This DC does not involve an unreviewed safety question:

Three out of four I pumpS and two SM heAders wilt be avaitable during the pimp replacermnt (the pumps wiI be replaced on at a tie). With ane SY puep inoperable during the pep replaement, Action Statement per TS Section 314.7 .4.1a will be entered, and flow of SW to CCHXs wiLl be throttled to ensure sufficient SW flow to the R*iNs of the accident Unit in the event of a OSA.

The following matfunctions of equipment related to safety wre previously evaluated in the UFSAR:

Failure of operating sw pump and rupture of the win U1l heeder.

In case of failure of the operating SM pump during the accident, two rmining pueps will deliver sufficient flow for the Unit safe shutdowm. If one out of three qwprabte SM pueps fails during Units' normal pratIon, AS per TS Section 3/4.7..1..b will be oplementad. In this case the failed pump should be restored to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or both Units should be in HOT STAIDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdowm within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />, in case of rupture of the main SW header, all components will be connected to the remaining operable header.

RepLacement of the SM pumps wi Lt be done one at a tim W tla the other three pusn are operable. The new pepes wiLL be instaLLed in place of the existing ones. During the replacement pump installation, the corresponding removable block the pmp house roof mill be removed. This creates a temporary opening in the missile barrier. Should a severe oWran weather worning occur during this time, Severe Weather Condition Procedure O-AP-I1, procedure O-NOI-1304-O and Operations Standard 007 wilt be adhered to, i.e. the Work will be stopped and rmowd block wilt be reinstalled.

Therefore, the possibility for an accident of a different type than was previously evaluated in the Safety Analysis Report witL not be created.

Replacement of the SM pumps will be done within the existing TS (Section 3/7.4.1.0). Therefore, no margin of any TS as described in the basis section will be reduced.

The new pump total developed head (TDN) mitt exceed the TON of the replaced deteriorated pemps and the required IDO of original pump Specification NAS-98. Therefore. replacement of the deteriorated SW pueps with the now ones will Iqprwv performance characteristics of the SWsystem and associated system (CC, RS, etc.).

An NPSH required test for the replacement puep (this test ma performed on puep which is in-kind replacement of the existing pump) was conducted by Johnston Pumps on Iloaaber 9. 1995. As a result of the test evaluation, Deviation Report No. N-95-1829 and Standing Order No. 213. Rev.O has been Issued to direct operations to implmmnt Isolation of two RSHXs after one hour but no longer than two hours after the SI/IDA initiation. The RSINIs which are secured shalt be one RSHX associated with one inside RS pump and mne&R associated with me outside RS peep, if possible, to maintain a full coverage spray pattern. since initial issue of JC0 95-03, investilgation was completed on required compensatory actions per this JCD. Calculations were performed for evaluation of summer mode of operation, strong/weok pump interaction, two pump operation with throttlingr CClXs and isolation of two RS;N~s after the contalinnnt depressurization. Results of this investigation oere the basis for revision of the JCO idwich eas aproved an 02-06-96 (Rev.1 of the JCO). In accordance with the recommendations of Rev. I of the JCO, requirements of Standing Order 1o.213 were incorporated into the station operating procedures on peromwt basis. This WiLL enhance SW system performa and eliminate unnecessary U pump high flow operation. For detailed scope of recommendations for various modes of SM system operations see JCO 95-03. Rev.1 (Ref. 6.10).

Since all required compensatory actions of JCO 95-03 were implemented, the JCO Was closed out on 03-18-96.

New pImpsI itt be manufactured with interchanging of the first o second stge impellers. UPSM test of this puep proved that the required NPSH is below than avai table lPSN af 36.9'. New peup performnce test showed better than specified pump performance. Therefore, no problem with the IPSII or other performance related problem Wit be observed.

Faor No. 73r91 (Oct 945

Safety Evaluation Page 1 of 12 e

t/IRGI&14 POWER VPAp- .3flf1 GOV 02 AP-3001 W. 1. Safety Evaluation Number 2. Applicable Station 3. Applicable Unit tNorth 22 Power Power Surry Anna E xnJ-Surr- Power Sation-Unit1C Station Station Unit 1I

X unit C x I Unit E Unit b a~ m. .. . . . .. . . . . .. . . .. ...

was performed.

4. List the governing documents for which this safety evaluation DCP 94-271 Summarize the change, test, or experiment evaluated.

5.

dampers which are no longer part of fire area boundaries.

This DCP changes the function of twenty-six (26) fire and have new mark nutber labels installed. Ductwork for seven (7)

These dampers will be modified to be nonfunctional Procedures for periodic testing as recommended by NFPA.

dampers will be modified to allow access for functional accordingly.

inspection and functional testing will be modified test, or experiment.

6. State the purpose for this change, (7) to reflect disabling twenty-six (26) darpers and seven Existing station fire darpers need to be relabeled furctional testing. This design change openinms to facilitate fire dampers require larger or additional access implements uoa.soers which are modified to be nonfunctional and performs the mark nurrber changes for twenty-six (C?=- dampers as to provide sufficient access to perform the four (4) year functional test of fire ductwork modifications recoummended by NFPA.

identified or assuned by this safety analysis. For each

7. List all limiting conditions and special requirements these conditions and/or requirements that will be used to ensure that item, indicate the formal tracking mechanism will be met.

performed within the limitations of existing Technical None - implementation of this modification will be 3/4.8.2.3.

The Battery Room and Battery Room door activities are covered by T.S. 3/4.7.7.1 and Specifications. prior Ventilation System activities are covered by 3/4.7.8(Exhaust Ventilation will be flow tested Safeguards Building Fuel Building activities are covered by T.S. 3/4.9.12. Control Room habitability is also to return to service).

for implementation will have applicable LCO's incorporated.

covered in UFSAR Section 6.4. Maintenance procedures safety question,

8. Will the proposed activity/condition result in or constitute an unreviewed C I Yes [X] No envirornental question, a change to the Fire Protection Program that affects an unreviewed in the event of a fire, the ability of the station to achieve and maintain safe shutdown a license amendment or Technical Specifications change?

or require

Safety Evaluation Page 2 of 12 VPAP-3001 Gay 02

.7".r. -- IM:.I"

?ui*.A't*r.ott.r*..

the reason the 15.-SSrmarize from Part 0, Unrevmiewd Safety Question Determination, the major Issues considered; state or does not exist chonge, test, or experiment should be allowed; and state why an unreviewed safety question does (a simple conclusion statement is insufficient).

the fire dampe.rr as The major issues considered in this design change are the ability to functionaLLy test recommended by the National Fire Protection Association (INFPA). Additionally, conformance with the Appendix F fire area boundaries and the operation of the ventilation systems was considered.

funrttionat testing as Access plates installed or modified in ductwork adjacent to seven (7) fire daspers will allow Twenty-six (26) of the existing station fire dampers are not part of the Appendix R fire area recomnended by NFPA.

to make them nonfunctional. Mark rnumers for these darpers wilt be changed and the boundaries and wilt be modified fusible links disabLed or damper internaLs removed to preclude spurious closure. installation of this design change does not alter the design or operation of the associated ventilation sytems.

Specifications.

Itrplerentation of this modification wilt be performed within the limitations of existing Technical Safeguards Building The Battery Room and Battery Room door activities are covered by T.S. 3/4.7.7.1 and 3/4.8.2.3.

Ventilation System activities are covered by 5/4.7.8. Fuel Building activities are covered by T.S. 3/4.9.12.

the appropriate Separate maintenancO procedures for each damper modification are being written which incorporates Technicat Specification Limiting Condition for eperation.

or operation of the Modification to the fire dampers or adjacent ductwork does not atter the configuration, design will be flow tested associated ventilation systems. Additionally, the Safeguards Area Exhaust Ventilation System Therefore, an unreviewed prior to return tc service to ensure comupliance with Technical Specification requirements.

safety question is not created.

flflA4L f7 .f Forml No. t~wo*u..-/

Barety vaixuation Page I of 12

=/mm4Pon=r VPAP-3001 '=V

1. Safety EvaLuation Nuber 2. Applicable Station 3. Alicable Unit MXVo-th Anne Power station no Uni tI M VM1

• 2 I Surry Power Station CI6ENIZ-06 I Unit 1 :13 Unit 2

. 'lowXO

4. List the governing docLnmts for inhich this safety evaluation wes pprformed.

DCP 95-221 (unit 1) and DCP 95-2&2 (unit 2), Removal of Contaimment Concrete Floor Plugs

5. Sunmarize the change, test, or w2periaent evaluated.

RemovaL of aLt 22 concrete floor plugs at contaiment elevation 291M, and repLace*ment with flush mounted grating plugs.

6. State the purpose for this change, test, or experiment.

Renvat of cots'ainnt floor ptuM .at mtMabMIt elevation 291'-I10 wilt etimifrte he foed to perform ieatmuve repositioning of the fLoor blocks at the beginming d ,end *ofeach refueling matage. The floor plugs aremsirald to be remwovd from t.he floor opaning during Mnrt operation to ]provide pesa relief and ventilation spam .

.e The concrete floor ptug are .inserted Into the floor openings for Laydounw spae diring refuelltig outages.

7. List all limiting conditions and special requirements .identified or aaaunedlbythis -safety analysis. For ea item, -indicate the forest tracking mechanism that wiLL be used to ensure that these conditions and/or requi e wiLt be met.

None B. UitL the proposed activity/condition result in or constitute an surviewed safety question.

an unreviewed enviroammntal question, a change lo the Fire Protection Program that affects I I IO ms ,No the abi ity of the station to achieve and maintain safe shutdown In the amnt of -fire, or require a License amendent mor Technical Specifications thange?

i DCP # O4.-01R., r* Safety

.PageI of Dvaluation 12 Pon= APPENDIX - AAP.300 VFM GOV02 SPAGE t OF ,2.

1. Safety Evaluation Number '2. AppLicabLe Station 3. Applicable, Unit CUP 45E" *.* ix I North Area Power Station Ex ) Unit I Ex I Unit 2

[ ] Surry Power Station I]uni t I I I uLIMt 2

4. List the governing documents for which this safety evaluation anc performed.

DCP-94-010, FC#I

5. Sumarize the change, test, or experiment evaluated.

Installation of Calgon's permanent bloftsr sampling device (CSD) is planned in the SW valve house. The installation will include two 1' branches from SW tines 18"-wS-D83-151-03 and 24N--S-D88-151-03 upstream of valves 1-SII-NOV-1223 and 2-SW-MOV-2221. 'wo SR one inch diameter tines with valves wilt be cmnected together downstream of the valves and the 1" line wilt go to the M seismic metal box (compartment) where the sampling device is installed. The NS, non-seismic BSD consists of 1/2" piping, 1/2" balt valves* and replaceable staples located inside the sapling cylinder. To eliminate adverse effects of the device's failure, the box is drained to the reservoir. Two inch drain line is calculated to remove water from the box without overf low in case of failure of the 1/20 piping within the box.

6. State the purpose for this change, test, or experiment.

The purpose of the ISD installation is to analyze the effectiveness of the 5W chemical treatment.

7. List all Limiting conditions and special requirements identified or assumed by this safety nalysis. For each item, indicate the format tracking mechanism that will be used to ensure that these conditions and/or requirenamts will be met.

Connections of the 1" lines to discharge SW headers 18"-WS-D83-151-03 and 240-1S-D88-151-03 require Isolation of the main SW headers. Per DCP-94-010 each mrin SW header will be Isolated three times. Therefore, the one inch connection to the BSD will be installed during main SW header isolation for the SW Lines replacement to/from CCHXs.

B. Will the proposed activity/condition result in or constitute an unreviewed safety question.

an unreviewed environmental question, a change to the Fire Protection Program that affects I3 Yes [xW no the ability of the station to achieve and maintain safe shutdown in the event of a fire, or require a license amendment or Technical Specifications change?

In as I I ad i 8 QI .,,~III itI

safetyI zvalustiefon of 12 page O VVAYJWI VPAP-3W I 0VY02

3. Applicble Unit

2. Applicable Station

1. Safety Evaluation Nuaer I :T" 7Wl O EX 3 North Arna Power Station E I Surry Power Station lUnIt

[ ) Unit I

[ XI Unit2

[ i Unit2 performed.

Wdi ch. this safety evaluation was List the governing documanta f DCP 95-190 evaluated.

Summarize the change, test, or experiment casing cooling

5. welded to the flange of the A diaphragm plate is to be storage tank (RWST) lower manways. A and refueling water and the manway covers tank (CCT) be fabricated for the RWST new manway cover is to provide backing for the plates.

will be reinstalled to test, or experiment. leakage.

6. State the purpose for this change, unit 2 CCT and RWST have experienced The lower manways on the borated and may be contaminated and any The water in the tanks is The tanks are difficult to drain for repairs leakage is undesirable. permanently sealed to prevent possible leakage so the manways will be in the future.

For each or assimd by this safety analysis.

conditions and special requirements identified these conditions mdor requirements mill 6 7. List all Limiting to ensure that mechanism that will be used item, indicate the format tracking be met.

None"' ""

safety question, result in or constitute an unreviewed [ I Yes DU No

8. WiLL the proposed activity/condition a change to the Fire Protection Program that effects an unreviewed envirormental question, mid maintain safe shutdown in the event of a fire, the ability of the station to achieve Specifications change?

or require a License mendment or Technical

a Safety ZV&3uatiZa Page 2 of 12 VPAP-301 a the Waor Issuies considered; state the roaom the Is. Suemmrize from Part 0, Uw~nrved Safety auestion osetnlnstio, an unrnsvived safety qulestion don or doen not exist Ohng-, test, or oxpelmwvt sdmuld be sloitswe; and state whly (a siaple conclusion stastemnt Is insufficient).

The unit 2 RWST and CCT have had problems with leakage at the lower manways. The tanks are difficult torequirements drain for repair of the leaks due to the Technical Specification for the tanks and will be drained the difficulty staring the borated water. The tanks lower manways. A new and a diaphragm plate is to be welded to the RWST to remove the raised manway cover is to be fabricated for the covers shall be reinstalled to face of the cover. The manway integrity ij not provide backing to the diaphragms so that tank of the tanks are not affected. The design, function and operation affected by this change.

The applicable action for fire protection shall be taken as required the RWST inventory is per the Technical Requirements Manual while less than 51,000 gallons.

are LOCK and main The accidents which are applicable to this change are failure of the steam line break. Applicable malfunctions HHSI, quench spray and casing cooling) and e related pumps (LHSI, piping.

UNREVIEWED SAFETY QUESTION ASSESSMENT the RWST and

1) Accident probability will not be increased as both CCT are used for accident mitigation only.

2) Accident consequences are not affected. The not diaphragm plates are being installed to prevent leakage and will affect Technical for the tanks. The pressure boundary specification requirements will be maintained by the blind flange.

RWST and CCT

3) No urique accident possibilities are created.The The diaphragm plates are only used in the event of an accident.

from the tanks but will not affect the will prevent any leakage systems.

operation of either the quench spray or recirc spray

4) Margin of Safety is maintained because the operation of the tanks spray systems is not affected.

and the quench spray and recirc and systems Technical Specification requirements for the tanks will not be affected.

Form No. 7309%6 (oat 94)

saf ety Bvaluation 0 -mm Page I of 12 VPAP-3001 WO02 r

MW1. Safety Evaluation Number 2. ApplicabLe Station 3. AppLicable Unit 96-SE-14M-33 0 I-eV. I I x. North AnneI aier Station UnitlII I II)Unit EInit2

)IUnt 2 C I SurryPower! Station

... 41

4. .List the governing documents for which this safety evaluation ms performed.

OCP 95-002

5. Summarize the change, test, or experiment evaluated.

I&

This DCP mill install new condensate polishing filters, filter to tube sheet locking hardware, upper vessel filter retention hardware and a draft distribution tube in condensate polishing vessels 2-CP-FD-IA/I/IC/I1D/tE.

6. State the purpose for this change, test, or experiment.

This design change milt provide operational flexibility for condensate vessels 2-CP-FD-lA/1S/1C/ID/1E. The new fitter elements can function as a precoated resin filter and, after bIckuashing the resin from the elements, the fitters can function as a mechanical fiLter for the removal of suspended solids (i.e. iron). The purpose of this design change is alao to test/evaluate the performance of the new elements in the filtration and ion exchange mode of operation.

7. List all limiting conditions and special requirements Identified or assumed by this safety analysis. For each item, indicate the formal tracking mechanism that will be used to ensure that these conditions and/or requirements will be met.

The Condensate Polishing System mill be out of service during the modification work of this design change. Testing of the new filters miLL be accomplished with the CP system in service. The new filters and hardware mill meet the design requirements of the Condensate Polishing System.

8. Will the proposed activity/condition result in or constitute an unrevIewed safety question, an unreviewed environmentat question, a change to the Fire Protection Program that affects C 3 Yes Cx] no the ability of the station to achieve and maintain safe shutdown in the event of a fire, or require a License amendment or Technical Specifications change?

safety yaluatlon Page 2 of 12 WAP-31001C

18. Sumartze free Part D, Unroviewed Safety Question Determination, the MiJOr Isous considered; state the reison the change, test, or oxperimnt should be allowed; and state why an unrsviewed safety question does or does not exist (a siepte conclusion statesnt is insufficient).

The Condensate Polishing (CP) System Is a nn-safaty system. The system ws originally designed to operate at lOU condensate flow. The CP Systom currently operates, only as required, for the reouval of imiurities in the cundesate by using a precast of resin oan the fitter elements. The -ethod of attachment of th- filter atelents to the tube sheet has been suspect in pet resin intrusion events. for exampte. it has been postulated that during poems cause transient* (i.e. the starting of a third condensate pmp). the 80 inch etemints have the potential to flex and fitter the bae of the elements to deflect and permit resin to slip by into the condensto strain. The existing eteimnts (except for the Unit 2 "@- end Non vessels) utilize a spring and latch mechenim for the retention of the fitter eatIt to the tube sheet. This potential instability of the fitter lemants tead to th reduce operationat use of the system because of the concern for stipping rein to the atm generators. it should be noted that the D"

Unit 92 "ii and N vessels haew nt been identified as causing any resin slippage problem. Unit 92 Wr and in all of the vesseltalready ar utilizing on early version of tiw Seatfast locking hardore which wilt be Instatled of vessels. in addition, because of the we of the existing Lift plates for retention and spacing of the top pert of the the filter element, there was inefficient use of precast resin deu to sm of the resin being deposited on top tift ptates as opposed to the surface of the fitter elements.

This design change will provide operational flexibility for all of the condensate polishing Vessels, 2-CP-FD 1AIl/1IC/D/IE. The new fitters, AFA Dial Guard, are sioptled by Graver Chemical. The new fitter etleents can function as a precoated resin filter and, after beclkiIshing the min f rem the elemets, the fitters can function as a mechanical fitter for the removal of suspinded sotide (i.e. iron). The beckf Lush protocol iltt be the lattice same for both the precosted and non-proccated fitter elements. A flou distribution tube wi an iqroved open design at the top of the fitter eleis will allow iqtoi vd vessel hydraulics and increase resin efficiency (te resin not applied to the filters). Therefore, the new fitter elemnts and associated herdMre wiL maintain the designed secondary water chemistry and will reduce the potentiat for daagoe to the stems generator tiues by the intrusion of resin into the condentate strem.

in Immry, it is concluded that the bosve mentioned non-safety related modification to condensate vessels 2-CP-IFD IA/II/lC/ID/IE will not result in en unrvioed safety question because:

1) This modification does not adversely affect the operation of non-safety retated Condensate Polishing System. The design change does not increase the probability of occurrence or increase the consequences for the accidents previously evatusted in the SAR or create the possibility for en accident of a different type.

2) This modification does not increase the probability of occurrence or consequence of malfunctions of equipment previously identified in the SAl or does it create the possibility for a malfonction of equipment of a different type than was previously evaluated in the SAl.

3) The modification has not reduced the margin of safety of any pert of the Technical Specifications as described in the bases section.

C.rn M. 7WI& tt US I E= N. 73M6 COC 3

Safety Evaluation 0

ViRGINMA POWER V

Page 1 of 12 VPAP-300i GOV 02 VPAP-3001' G-I OV 02 0 1. Safety Evaluat ion Number 96-SE-MOD- 034

2. Applicable Station CXX) North Anna Power Station I Surry Power Station

3. Applicable Unit

[XX) Unit 1

[ ) Unit I

[XX] Unit 2 E I Unit 2 PATA

4. List the governing documents for which this safety evaluation was performed.

DCP 95-127, DCP 95-216

5. Sumnarize the change, test, or experiment evaluated.

SA-182 F304 SS (1-CH-P-1 & I-CH-P-1C).

"*Carbon/stainless steel cladded charging pump casing replaced with head

"- A-266 carbon steel discharge head replaced with a SA-182 F304 SS (1-CH-P-1B,IC & 2-CH-P-1A,1B,1C)

"*A276 Type 410 SS seal housings replaced with SA-182 F304 SS seat housings (1-CH-P-1B,1C & 2-CH-P-1A,1B,1C).

"*A2?6 Type 410 SS alloy seat plates retained for use on new housings (1-CH-P-1B,1C & 2-CH-P-1AIB,1C).

"- installation of additional seat retainer plate (I-CH-P-IA,IB,1C & 2-CH-P-1A,IB,1C).

"*Removal of existing seat coolers (1-CM-P-1A,1B,1C & 2-CH-P-1A,1B,1C). puip/driver aligrment. Minor modifications

"* Relocation of the cradle boss and keyway as required& toIC).ensure correct as required for the casing mounting feet (1-CH-P-1B

6. State the purpose for this change, test, or experiment.

pump casing Previous inspections of the carbon steel charging pump casings discovered indications which warranted replacement. in lieu of further inspections, th- t;ings wilt be replaced for the remaining carbon steel pump casings associated with 1-CH-P-lB & 1C. RepLacer*ent of the discharge head and seal housings is required to properties.

eLiminatt tne stress that could be created by using different materials with different thermal expansion without Re-use of the existing Type 410 seal plates is an acceptable alternative to installing new plates compromising pump operability. Addition of seat retainer plate will allow even loading of the seat unit.

Installation of the new seaL housings will allow removal of the seal coolers since they will not be required for the upgraded seal hous'ng.

V-II m

17. List all limiting conditions and special requirements identified or assumed by this safety analysis. For each and/or requirements item, indicate the formal tracking mechanism that wilt b- jsed to ensure that these conditions wiltL be met.

None

8. Wilt the proposed activity/cor~it on result in or-constitute an unreviewed safety question,

[ I Yes (XI No an unreviewed environmental question, a change to the Fire Protection Program that affects the ability of the station to achieve and maintain safe shutdown in the event of a fire, or require a license amendxment or Technical Specifications change?

Safety Evaluation Page 2 of 12 VPAP-3001 GOV 02

• Part A - Resolution Summry Report

18. Summarize from Part D, Unreviewed Safety Question Determination, the mejor issues corncidered; state the reason the or does not exist change, test, or experiment shoutd be allowed; and state why an -inreviewed safety question does (a simple conclusion statement is insufficient).

The charging pump manufacturer had previiusly issued a bulletin advising owners of the pumps that h:1 casings or damage when constructed of carbon steel cLadded with stainless steel to inspect them for cladding cracks, erosion were disassenbtled. Past inspections o0 the carbon steel chareing ltump casings at NAPS discovered indications whi-h severe enough to warrant casing replac' sent rather than repair the existing casing. The existing puimp casings for I CH-P-IA, 2-CH-P-IA,1IB &1C were replaced with solid stainless steel casings.

with I-CM-P-.B &

Due to the failure rate exhioited ty previous inspections, the carbon steel pump casing associated IC wiLl be replaceda. The replacement stainless steel casings are supplied bý'the original pump marnJfacturer, IngersolL-Dresser Pur.Vp Company (Pacific Pumps). The replacement p casing is superior to the original due to irrproved corrosion resistance. The new casing meets or exceeds al't design requirements for the original equipment.

Ali nozzles and connections on the new casing are of the same size and location, so no piping changes are required.

The puersinternals, which determine the ptprr's performince characteristics, are reinstalled in the new casing to been avoid generating changes to the purnps pressure and flow features. Minor changes to the puim mounting have reviewed and approved by the pLjmP vendor.

carbon steel Previous casing replacements for the Unit 2 charging pumps aid not include repLacement of the A-266 discharge heads or the A-276 Type 410 seat housings. As documented in Deviation Report N-95-1070, the difference in in the therm.*l expansion between these comDonerts and the pump casing had the potential to produce bending stresses discharge head and seal ho.JsiNg botting which cause the combined stresses to exceed code allowable values.

SS is required to maintain Replacement of the discharge heaO and seat housings with those constructed of SA-IZ F301, or restore the pump design to an acceptable conficration and limit the stress within the basic allowable value.

Replacement of the pu-p ccmponents will not ir-.....t the operation or performance of the charging puaips.

Installation of upgraded 2nrd gernration seat housings eliminate the n for external seat flush piping and associated heat exchangers. the seal coolers from both Unit 1 L 2 charging pumps will be rem.oved and the service water tines to the coolers will be capped. No adverse affects on the SW systat wilt result from this change.

that the Existing A-276 Type 410 seal plates wilt be re-used on the rnw seats housings since it has been determined difference in rra:erials b>etween the plate and housing wilt not coepromise , operability.

SULWART OF SAFETY ANALYSIS in IOCFR50.59 The replacement of the charging pump casing did not constitute an unreviewed safety question as defined since it did not.

A) Increase the protability of occurrence or the consequences of an accident or malfutic'ic of equipment important to safety and previously evaluated in UFSAR.

1-CH-P-1B L The activity wilt replace the remaining carbon steel, cladded with stainless charging pump casings for

C with a SS casing that meets or exceeds the design requirements of the original equipment. Replacement of the discharge head and seat housings with those constructed of the same material (304, SS) as the pump casing is required to eliminate undesired stresses caused by differential thermal expansion. Minor modifications to the pump mounting wilt not affect the operability or performance capability of the pump. Pump reliability is increased by the modification. The operational characteristics of the pump remain the same since the pump internals will be retained for use in the new casing. Replacement of the other charging pump cceonents will not affect pump operability. The MHSI/charging pump will continue to perform it's intended furnction for mitigation of applicable accidents.

8) Create a possibility for an accident or malfunction of a different type than any evaluated previously in the UFSAR.

Pu*p casing and component repLacemen"T are essenitlally a one-for-one replacemtnt which ipjgrade the p design.

All modifications involved with the charging pump components wilt in no way affect pi*p performance or operation.

The new Upgraded seat housings eliminate the need for external seat coolers and thus improve pump reliability.

components have the same form, fit and function as the old parts. The pump wilt continue to operate in the sa manner as before this modification is performed. The possibility of generating a different type of accident or malfunction than previotsi.y evaluated is not credible.

C) Reduce the margin of safety as defined in the basis of any Technical Specification.

Pump component replacement and seal cooler elimination will not have any adverse impact on the Tech Specs associated with the charging pump nor will any margin of safety be affected by this modification. Pump operation remains unchanged as a result of the design change.

,.. 77 '

Safety val *UatJion page 1 69 12' vPAP-3001ýA Nmber 2. Alpplicable Station '3. AppLicob&unt . .. .;.i.;-=

1. safety Evaluatio 97-sE-NOD-34, Rev.¶ 1zxj Sur]ry fte Pow orth xmiq sttostation .t' IIl=i 13 I[ 3I Unit Uni t> 1 nit.2

4. List the goves ing deiants for whiich this safety evaluation was performed DCP 97-003, Iteplacement of CCNX9 North Anne, Unit 2

5. Siinrize the rhwI a, test, or m,4imertnt-evaLuted.

CCXshve experienced tube tlWeaa dus to microbolot cll.tty InfLwnced pitting corrosion. Leakin tubes have been teaks in the plugged, but a significant nmer of tubes exhibit evidence of pitting corrosion and could develop adversely future. Calculation NE-0530, Iev.0 estabtlihed the limit C2) of tubes ti. can be plugged without effecting cc system performsnc and up to 30% of thubs if SWtemerature is limited to U5F. since plugging of the tme Is approaching the above tlmits, It wm decided to reube Unit 1 Ccus and replace Unit 2 CC* s. Unit .2 = s.

ports of the IIX-h4h6 will be replaced utilizing high crrosion resistance materiet (Titanitu) for tubes and other contact SW.

6. State the purpose for this cAn-ge, test, or xperaiment.

utilizing corrosion The purpose of W 97-003 Is to restore original capacity of Unit 2 CClx by replacing them resistant mterial (Titaniwm) tubes.

7. List sll limiting condition and smpiat requirements identifiled or assumed bythose this softy analysis. For each item, Indicate the format tracking mechanism that Milt be used to ensure that conditions anmor requirements wilt be mt.

See page IA.

S. WIlt the proposed activity/condition result in or constitute a unreviewd safety question,

. 9... -, .1 .l t a g4-te to the Fire Protection Program that affects [ ] Tes UI3 No the abilIty of the station to achieve and maintain safe shutdonm in the event of a fire, 1mb or require a License PeI I or Technical Specifications ohane?

Safety Evaluatiom Sappimfn i1 Page IA of 12 WAP-WGl* - ~ ~ wl i.temO ,-p e .- m il itt done hader L*s per TS Section 3.7.3.1. One CCIIX mitl be replaced at a tim;. thefore.

1. Th etellCOn MnM* iw drN.2 r ple rt h elcsnt C-906-04. JCOare.C-0741 and stanigowIng* Ol--.,ds-*, vt e o TS AS is conditions no- Limiting

2. r*.,t thefothrJCO Per re MM* qe *Wa* No.21are appie d~jno c-rth relaemnt Note:: ntbmubqatrUt I CCIX. Ot retubed, one out of two unit 2 CCNX Is repaced and Decm l 2 C.........cis ated fo . -r . tanm two rt.*..d and one replaced cCIx are oper ting and fr t CCII ie i of SE 944-SO01-0 of jeo c460 ~.WC90 11ntb are operting or isolated for replaceamet Also., limiting conditions i.e. regardles Wch three out of four CEi applicable when all four CCax are retuld/replaced, e

ait four are operating.

channeL upper priortrl of the beat exchange will be guided

3. Removal ofOperations the roof of the blocks InItendard Auxiliary Building aboverigging developed for this WCP.

toaawvmm-.

procedure by O-AP-41 4 007, O-OX-1304-01. and specialoperable prior to removing 30" elbow from CC discharge A.LLUnit 2 charging pp and all four CC pumps shaLl be operable nozzle of heat exchanger 2-CC-E-1A.

2 CCNX replac -1t (for details see be observed during ptgemanitation of Unit The following LCOs per US TUG wiLL response to Item 440):

from elevation 286' i-W-F-75A and 750) will be temporarily diseitid 11C, lip0, 11U. Alsoe,

1. Appendix Rtsupply duct (ducts from fans see drawings 1.978034-060SA.

elevation 270', After dli'Ohing of the ei*sting best wOwe below AuxILIary Building roof) to approximatiely ill be teporri- y re*m*ov.

the suction bell on fen 1-mVr willt e restored to ahir original configuration.

and installation of new ones, the ducts the eiffected artin.s"lbeipemne In acoranc wih sctin 75, page 7-36 of NAPS TIN, hourly fire watch In A). It is expected that ducts will he shall be done within 60 days (Condition Perim within 14 days aid duct restoration wilt be entered by.op.er*ations o A. Corresponding Action Statement restored within requirements of Condition requi rements.

B A uilding P water supply wilttl be Interrted for Mtateen

2. For relocation of FP water hours (valives i

lines nside the Auxiliary 2-PP-8S and 2-FP-24 will be closed, ref. drawing 120150483-104A). Action approximately 20-24 measure temperature wiLl be miotded As a contingency per section 7.1.3, page 7-12 of UnitNA TN will Unit be entered. watch 2 end fire wilt be established in the Aumfiliary Building.

vuithin the Reactor Contairient I and entrances of the AMI tiiry Built ing.

Temporary f ire hoses wil he stage to the contai'ment persoMel hatches and Wreqirments.

within ame hour or prior to the4 piping Isolation per DCP The hoses will be staged Building Action Statement per Section ?.1.7.

poge 7-19, condition A

3. For inoperable sprinklers within the Auxiliary will be entered per DCP requirements.

to eccommete the CCOX wilL be permnently relocated closer to wall

4. Low pressure C02 tine at elevation 2911'-0" opproximtety 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Action Statement per The relocation witt take replacement (drawing U-97003-2-1FB10C). per DCP reqirements.

Section 7.1.2. Condition A iltt be entered guru Ug. -. M r*m * * *wwvw

safety 3fl4tt10Cs Page 2 of 12 PA-WrI - , 1-I. j IS. Summarize from PartD Unreviewed--Saet uaation Oetermi;fnaf, the injor isusconsletd charge, tastoexrie n shud be allowed; and stateSyanareewdsftqutinosorosntext (a siqmpe conclusion stateminIs Insufficient).

s~tat the rmeasn " 1 S

.4 CCIIU have experienced tube leakage due to micrebolotgically infltuenced pitting corrosion. Leasking tube haveben plugged, but a signififcatnt mbsr of thes exhibit evidec of pitIting corrosioan and could developý laia" in the future. The purpose of DCP 970411 to restore original capacity of Unit 2 CUMi~ by replacing' them utitLizing corrosiont resistant titenium tubes.

The replacement does not Involve an unrevisved safety question:

The CC water system (CCCW) Is an intermediate cooling aystem which transfers heat from heat exchangers containingr reactor coolant or other redioactive liq-uids to the Si The MaI is not a system of system. The design bests the CCMSI@s fast cooldamn of%-n whmich functimn to mitigate £ dp*sign unit whi Is maintaining noist Loads en the other unit. ofa fisoardc edr h refoe the praobabliy basis accident (DNA) or presents a challenge to the Integrityanalyzed in the UIDE will not be Incresd of wccurrence or the consequences of en a'ccident previously CCIII serves no accident mitigation function. Repleacment ofTherefore, -n Ci~s- at a time will leave three CC system operableaIn whmich is enoa* for CCUI to perform its design functions. consequene of accidents previously saltyzed.

the LI9SAM will not be increased. Replacement of CCi~s .11It be done within requirements of exiting TISecto 3/4.7.3.1.

Replacement CCHXs will be furnished with corrosion resistant welded titanium tubes ASO*01-33B *A instead of welded stainless steel tubes ASTN-306L in the existing CCHXs. The replacement heat exchangers have been designed for the same heat loads and flowm rates as the existing CCNHs, therefore, COIX thereMi andwhith'" hydiraulic perfoisnoewws are not affected by this replacement. Note also, that the new heat exchangers are interchaneable, the existingif ones, i.e. ell nozzles and supporting Interfaces metch up with the configuration of the existing heat exchaI ers Thswilinmzth work. Table 9.2.5 of the UFAR wll be revised to incoI rpor.a Ite tube itriel chanige. UFWA Chane required replacelment Increase retliability of the Us, therefore, Request is included in Appendix 1-1 of the DCP. Replaceiment of C~is will malfunctions (CCIX tubme rtptn r) previously analyzted In 'the C1it will decrease probability of occurence of equipment UWIDE.

Lifting end rigging of the -o CCHXs and old (existing) ones, concrete blocks above the heat exchwgeqrs and other toads In excess of 2000 lbs will be guided by approprilate station procedures eid IRII-10612 HNeavy Loads Progra.

Neither the replacement nor the activities required to iqlulmnt it will create the possibility for a emifuttion; of equipment of a different type than waspreviously evalusted in the IIFIAR.

One CCHX will be replaced at a time. The replacement will not reduce mergin of safety of the CCIII as described -inthe TI cince it does not reduce the nia1ber of heat exchangers available to mee design heat transfer re,quirements per TS Bases Section 3/4.7.3.1 and 3/4.7.3.2.

form 9 Met 1W 0

Safety Evaluation Page 1 of 12 VPAP-3001 GOCV02

2. Applicable Station 3. Applicable Unit

1. Safety Evaluation Number S-[x] North Anna Power Station I I Unit I [x] Unit 2 I

I,*- Su Star"Unit Power [] Unit 2 PART A- Resolution Sum taary.. rt".." ....... " .""

4 List the governing documents for which this safeLy evaluation was performed.

DCP 97-014 - Outside Recirc Spray Pump Motor Replacement 5 Summarize the change, test, or experiment evaluated.

that is a modem replacement for the existing mot The existing unit 2 Outside Recire Spray Pump Motor (2-RS-P-2A-Moter) will be replaced with a motor frame and some special adjustments will and has the same performance characteristics, but different physical characteristics. The new motor is built on a square be required to install it in the same location as the existing motor.

6 State the purpose for this change, test, orexperiment The existing motor has a bent shaft 7 List all limiting conditions and special requirements identified or assumed by this safety analysis. For each item. indicate the formal tracking mechanism that will be used to ensure that these conditions and/or requirements

%ill be met Specs. A This uork will be done with the unit ofT line in mode 5 or 6 (tracked by the Special Implementing Instruction section of the DCP) as required by Tech that the overhead securi% i. atch may be required while the overhead block is out of place (informational action item). A severe weather event will require Infontation section of'the block is replaced (informational action item). The Informational Action Items are addressed in the Supplemental Implmenting DCP X Will the proposed activity/condition result in or constitute an unreviewed safety question, an unri iewced environmental question. a change to the Fire Protection Program that affects [ Yes [x] No the abiltv of the station to achieve and maintain safe shutdown in the event of a fire, or require a license amendment or Technical Specifications changej

Safety ' valuation Page 2 of 12 VfP"-3002- Q 7-1i 4tOV 02 Part A- Resolutim Sinmary Report issues considered; state the reason the I1. Summarize fromPaut D, Lleviwd Safety Question Determination, the major o doe or does not exist change, test, or experiment should be allowed; and state why anmnreviewed sdety ques" (a simple conclusion stemnent is insufficient).

due to the misting motor having a dampgd shafL- The rpaemem This project is to replace a motor on the unit 2 Outside Rgcirculating Spray Pump (2A) motor is a modem replacement for the existing motor and is a close match electrically to the exbistin motor, but 1modem maoms ofthis size andtype *e built d replcing It with a newmot. The new, squam-frue, motor will on square fIames. The project involves lifting the vertical sh"t motor from is mounting require some physical adjustments to adjacent seismic supports.

scenario. The system is designed to respond (in The function of the Recirculaing Spray system will not be affected, thus them is no impact an ay accient inside containment after a LOCA. Changing the motor on one oftbe pumps conjunction with thdequench spray system) to reduce the temperatnre mad prems a motor that meets all of the original design requirements does not introduce any new accident tye nor does it inceasie the probability or consequences of with any accident already analyzed.

this moto is saotyrlated end Failure of any motor is already analyzed in the redundancy of trains. A Loss Of Offsie Power is included in the fact that by diesel-backed power. The new motor meets all ofth original dsin requiremnts for the existing motor ant will be just as reliable.

supplied Terefore, All existing Technical Specification surveillance requirements, Bases descriptions and Margins of Saft we unchaged by this motor replacemet.

this motor replacement should be allowed.

4) fo m l-.- ..... 6. . ...

U Safety Evaluation Page I of 12 I

1. Safety Evaluation Number 2. Applicable Station 3. Applicable Unit 99-SE-MOD-03 (XJ North Anna Power Station [x) Unit I [x] Unit 2 I]Surry. Power Station [ ]Unit1 [1 Unit2 SPart A#,Reso i di " ' _______________________.

4. List the governing documents for which this safety evaluation was performed.

DCP 99-124 (Unit 1) and DCP 99-125 (Unit 2) Relocate RS Pump Temporary Test Dike Panel Storage for Installation of Reactor Head Stand Water Shields

5. Summarize the change, test, or experiment evaluated.

Stainless steel water shield tanks will be stored Inside the reactor head storage stand during the'operating cycle.

The tanks will be filled with water during a refueling outage to provide radiation shielding for personnel Inspecting, removing and replacing the reactor head 0-ring seals. The water shield tanks shall be emptied at the end of the outage. Also, RS Pump temporary test dike panels that are currently permitted to be stored In the reactor head stand will be stored in another designated location In the containment basement.

6. State the purpose for this change, test, or experiment Stainless steel water shield tanks will replace fiberglass water shield barrels that are currently brought Into and removed from the containment each outage. Storing the stainless steel water shields Inside the reactor head stand will minimize the time spent to install and remove the shielding each outage. Possible damage to the shield containers due to personnel handling required for storage outside containment will be eliminated.

7. List all limiting conditions and special requirements identified or assumed by this safety analysis. For each Item, indicate the formal tracking mechanism that will be used to ensure that these conditions andlor requirements will be met.

The reactor head stand water shield tanks shall be drained by radiation protection personnel at the end of each outage and the local drain plugtvalve left In the open position. These requirements shall be Independently verified prior to unit start up by procedure 112-OP-1B as applicable.

8 Will the proposed activitylcondition result in or constitute an unreviewed safety question, an unreviewed environmental question, a change to the Fire Protection Program that affects the ability of the station to ( I Yes [XI No achieve and maintain safe shutdown in the event of a fire, or require a license amendment or Technical Soecifications change?

Safety Evaluaton Page 2 of 12

18. Summarize from Part D. Unreewed Safety Question Determination, the major issues considered; state the rason the change, test, or experiment should be allowed; and state why an unreviewed safety question does or does not exist (a simple conclusion statement Is Insufficient).

Stainless steel water shield tanks will be stored Inside the reactor head storage stand during the operating cycle.

The tanks will be filled with water during a refueling outage to provide radiation shielding for personnel inspeeting.

removing and replacing the reactor head 0-ring seals. The reactor head stand wate shield tanks will hold a total of approximately 2,000 gallons of unborated water when filled. Therefore, the water shield tanks shall be emptied at the end of the outage to avoid a possible concern with water leakage from the shield tanks diluting RS sump boron concentration after a LOCA. The design of the tanks will have open vent and drain connections to provide containment pressure equalization and prevent water hold up in the tanks. Recirculation flow paths to the RS sump during design basis accident conditions will not be affected. The open vent and drain connections will allow the shield tanks to fill up with water during a LOCA so that they will not float. The water shield tanks are effectively restrained by the reactor head stand structure to prevent interaction with safety related components during a seismic event.

During shutdown operations, when the shield tanks are filled with water, significant damage to the tanks resulting in gross leakage Is not considered credible In the event that the RS sump is required for maintain altemate core cooling using Forced Feed and Spill In accordance with D-GOP-13.0.

Also, RS Pump temporary test dike panels that are currently permitted to be stored in the reactor head stand will be stored in another designated location. The RS Pump temporary test dike panels will be stored In the containment basement away from the RS sump In an area that does not have the potential for the dike panels to interact with safety related components during a seismic event.

This change does not constitute an unreviewed safety question because:

1) No increase in the probability of occurrence or consequence of an accident or malfunction of equipment will Result from the installation of stainless steel water shield tanks inside the reactor head storage stand or by storage of RS Pump temporary test dike panels In containment. The water shield tanks will be drained prior to unit start-up to prevent possible dilution of RS sump boron concentration after a LOCA. The water shield tanks and RS Pump temporary test dike panels are stored In locations where no interaction with safety related Components during a seismic event is possible.

2) The installation of stainless steel water shield tanks inside the reactor head storage stand and storage of RS Pump temporary test dike panels In containment does not create the possibility of an accident or malfunction of equipment of a different type than any which have been evaluated previously In the Safety Analysis Report.

No new or unique accident precursors have been Introduced.

3) The margin of safety as defined in the basis of the Technical Specifications Is not reduced. Installation of Stainless steel water shield tanks Inside the reactor head storage stand and storage of RS Pump temporary test dike panels in containment will not degrade or compromise safety related components required for design basis accident mitigation.

S*e*~~~..Jma1 ,* .mt p, r M 1FW. SO1W uq4 m

99-SE-MOD-05 Description Inspection ports are to be added for inspection of the service water to RSHX check valves. Each port is to consist of a sockolet and a blind flange with pipe as required.

Summary Inspection ports are to be added to the SW to RSHX lines. The ports are to be used to inspect the SW to RSHX check valves to ensure that they are normally closed. The IST Program requires that the check valves be inspected. Removal of the valves is labor intensive and a visual inspection is an acceptable method of testing. The ports are to include a sockolet, blind flange and a short section of pipe.

Pipe stress and supports were evaluated and found acceptable for all specified loading conditions including seismic.

The accidents considered were those which result in containment depressurization, including LOCA and Main Steam Line Break.

UNREVIEWED SAFETY QUESTION ASSESSMENT

1. Accident probability will not be increased because the recirculation spray heat exchanges are used for accident mitigation only.

2. Accident consequences are not affected. The inspection ports are required to ensure that the check valves are closed. A check valve stuck in the open position could divert water from the RSHX. The resultant flow would still meet system design requirements, per calculation ME-0547, but to maintain margin of flow available the check valves are to be inspected. System leakage, should a port fail, would be bound by this calculation.

3. No unique accident possibilities are created. The inspection ports are basically passive components which will only be used when the unit is shutdown. The service water lines affected are only used after a DBA. System design bases are unchanged.

Margin of Safety is maintained because the integrity and reliability of the system are not affected. The margins of safety as described in the bases of the Technical Specifications are not affected.

Safety Evaluation VIRGINIA POWER Page 1 of 12 B

q F27 30 -Atcmn 3 . -

T1.NSf~ety Evaluation Number 2. Applicable Station 3. Applicable Unit qq - MO -OG Ix North Anna Power Station IX Surry Power Station

[XI Unit I I I Unit1

[x] Unit2 1 1 Unit 2

- Part A ýý Rolutio Uf l ..V8a.I-.

tJmf *

• 9.-" .- -. * .

4. List the governing documents for which this safety evaluation was performed.

DCP 99-106 *SECURITY SYSTEM MAGNETIC DOOR LOCK ENHANCEMENTS" 5.. Summarize the change, test, or experiment evaluated.

This DCP replaces access control devices (electric strikes) with magnetic door locks, and removes the existing security latchsets for Emergency Switchgear Room door (02-BLD-STR-S54-11-ACCESS), Chiller Room to Turbine Area Doors (01-BLD-STR-554-1 ACCESS, 02.BLD-STR-S54-14-ACCESS). Magnetic door lock assemblies will be added to Main Control Room doors (01-BLD STR.S76-26-ACCESS &02-BLD-STR-S76-25-ACCESS), EDG to Turbine Area doors (01-BLD-STR-S71- 17 &19-ACCESS, 02 BLD-STR-S71-16 & 18-ACCESS), New Fuel Recovery door (01-BLD-DR-F72-1-ACCESS), Fuel Building to Auxiliary Building door (01-BLD-DR-F91-1-ACCESS) and Security Inverter Room door (01-BLD-DR-CC71-3-ACCESS) to supplement the existing security electric strikes. Magnetic door lock assemblies will replace the security electric strikes on Rod Control doors (01-BLD-DR-M80-1 ACCESS and 02-BLD-DR-M80-2-ACCESS), Quench Spray Pump House doors (01-BLD-DR-0S72-1-ACCESS & 02-BLD-DR QS72-3-ACCESS). and Main Steam Valve House doors (01-BLD-DR-MS72-1-ACCESS &02.BLD-DR-MS72-2-ACCESS).

6. State the purpose for this change, test, or experiment 4 e purpose oars of this in referenced design change section 5. Is to still provide security against sabotage and resolve multiple door latch problems for the

7. Ust all limiting conditions and special requirements identified or assumed by this safety analysis. For each item, Indicate the formal tracking mechanism that will be used to ensure that these conditions and/or requirements will be met.

The plant may be in any mode of operation for this design change. Work on doors S54- 1, S76-26 &25 require that the Control Room pressure boundary be breached. This will require entering the action statement of Section 3.7.7.1 of Technical Speclfcations ifthe Control Room differential pressure can not be kept within limits while these doors are being worked under this design change.

Shift supervisor notification is required by DCP 99-106 Supplemental Implementing Information.

8. Will the proposed activity/condition result In or constitute an unreviewed safety question, an unreviewed environmental question, a change to the Fire Protection Program that affects the ability of the station to I ]Yes [X]No achieve and maintain safe shutdown In the event of a fire, or require a license amendment or Technical Specifications change? I

Safety Evaluation Page 2 of 12

.. *P360 -*Atahen MUK V4110~

parA:.Reiob~tldtkiOwS mfYU Question Determination, the major issues considered; stae the reason the change,

18. Summarize from Part D. Unreviewed Safety safety question does or does not exist (a simple test, or experiment should be allowed; and state why an unreviewed conclusion statement Is Insufficient).

the Emergency Switchgear Room, Chiller Rooms, Main The purpose of this design change is to control access to New Fuel Recovery, Fuel Building to Aux. Building and Control Room, EDG Rooms, Rod Control, MSVH, QSPH, problems. These areas will remain security controlled Security Inverter Room doors and resolve multiple door latch Existing security bypass and emergency egress areas where ingress but not egress is controlled and logged.

by DCP 99-106.

requirements for the appropriate doors will still be maintained Switchgear Room, Chiller Rooms, EDG Rooms, Main Operability of the safety-related equipment within the Emergency by this design change. The security system neither Control Room, QSPH and MSVH will not be adversely affected The magnetic door locks are powered by sources that are supports nor is supported by any safety-related equipment mode of failure for the equipment being added by this DCP independent of other plant systems. There Is no credible within the envelope established by the new magnetic door that would adversely impact any safety-related equipment Rigid mounting of the lock assemblies to the door locks. The seismic adequacy of the doors will not be compromised.

secured during a seismic event.

and the door frame, will ensure that the assemblies will stay in cases where the Control Room is no longer habitable.

Access to the Emergency Swltchgear Room is necessary system is both UPS and security diesel power backed Operators will still have access with their keycards. The security in order to remain operational. It should be noted that the and therefore does not depjend on any station power system does not require the use of a latchiet atshortest the top of the door.

magnetic door lock will fail safe (unsecuired) which Room and Chiller Room doors. Finally, the path to the e latchsets will be removed from the Switchgear Rooms will remain avaible as It stairwell from the Logic uxiliary shutdown panels from the Control Room via the back any security barriers to operators utilizing change will not add is now with no new card readers In the path. This design will not adversely affect operator access design change this path to the Emergency Switchgear Room. Therefore, this to the auxiliary shutdown panels.

the installation of a new security key lock switch for Access to and egress from the EDG Rooms will remain unchanged, because another means of access and egress already each EDG door to defeat the magnetic door lock is not required exists.

will remain unchanged, the installation of a new Access to Unit I Control Room via 01-BLD-STR-S76-26-ACCESS will be performed under DCP 99-106. An emergency egress security key lock switch to defeat the magnetic door lock conjunction with the existing panic bar.

pushbutton will be installed under DCP 99-106 to be used in compensated by posting the appropriate EQ and fire Temporary breaches of EQ and Appendix R fire doors will be in accordance with the Technical Requirements Manual watches while work is in progress. The watches will be done Compensatory measures have been provided In Sections and also VPA-2401 for Appendix R and VPAP-0305 for EQ. compensatory measures wil be in procedures adequate 3.3, 3.4 and 3.16 of the design change. By utilizing these place so as not to compromise plant safety.

boundary be breached while work is in progress. This This design change will require that the Control Room pressure 3.7.7.1 of Te"-'nical Specifications If the Control Room will make it necessary to enter the action statement of Section the required wc,'k will be completed in less time than the differential pressure can not be kept within limits. However, these breaches In an emergency will be available 24-hour period of the action statement Material to temporarily close while work is in progress.

door (01-BLD.DR-F91-1-ACCESS) will be controlled via FME concerns for work performed on Fuel Building to Auxiliary BuildingO-GOP-4.16 via DCP 99-106.

'Fuel Building FME Assessment of Maintenance Activities! procedure result in any unreviewed safety questions.

Therefore, it has been concluded that this design change will not ParMft3W@J70S6lWl r

Safety Evaluation 0 Page 1 of 12 VPP. 00 -Atahmn 3

2. Applicale So 3. Applicable Unit

1. Safety Evmaluon Number W(1 North Anna Power Station [/] Unit1 1/1 Unit2 99-SE-MOD-... I I Unit I E ] Unit2

[ ] SunyPower Station Wift this sa w

4. Ust the governing do==Wf 2-OP-32.3, 2-AR-32 and 2.ICP.BD-G-O01 , I.MOP-32.4 and 2-MOP-32.4 Procedures: I.OP-32.3, I-AR-32, I.ICP.BD-G-001, system trip of the high capacity SIG blowdown system.

ET SE 99.034 - ConpensakwY measures required for bbodng an automatic Field Change for DCP-98-130. Unit I Blow Down System Upgrade DCP-9119: Unit 2 Blow Down System Upgrade.

5. Summarize the chaige, test, or expemeT evaluated.

the following automatic trips for the Unit I and 2 High This evaluation assesses the acceptabllity of individually overridng Capacity Steam Generator (SG) Slowdown (BD) System:

AISIC), 2. Slowdown Flash Tank High Outlet Flow Trip

1. Slowdown Flash Tank Inlet Flow Trip (1(2)-.D.FT-102 (202)

Tank HI-HI Pressure Trip (I (2)-BD.PT-1 00 (200)), 4. Slowdown Flash Tank (1 (2)-BD-FT-105 (205)). 3. Slowdown Flash High Temperature Trip (I(2).BD-RTD-101 (201)) and 6. Low Level Trip (I (2).BD-LT-100 (200)), 5. Blowdown Outlet Coler Condenser Vacuum Trip (1(2).CN-PT-101 (201) AI).

field changes associated with DCP4--130. Additionally, These changes are Included In DCP 99-119 and several of the software and several *human factors" enhancements for the DCP 99-119 the field changes for DCP 98-130. Install Y2K ready 99-119 also provide for the Installation of Y2K ready hardware for Units I and 2 Hijh Capacity SG BD System. DCP 2-SS-RM-225, the reinstaliation of Interposing relay 2-SBDGN02 and the Installation of Y2K ready software on a portable compger that will be used to set up radiation monitors (1)2-SS-RM-125 (225).

6. State the purpose for this dmge, toti, or experiment.

Indlvidually overriding trip signals from several The purpose of this evaluation Isto determine and document the acceptability of BD System. The evaluation also addresses the acceptability of transmitters (see item 5 above) associated with the high capacity Interosing rela 2-*BDGN02.

the Y2K changes; human factor enhancements and reinstallation of and special requirements ident*ifie or assumed by this safety analysis. For each item, Indicate the

7. List all limiting conditions and/or requirements will be meeL that these conditions formal tracking mechanism that will be used to ensure Transmittal SE 99-034 Sets out the compensatory measures to Only one trip signal Is to be overridden at any time. Engineering the basis for revising applicable procedures. The SD be proceduralized when any system trip is blocked. This ET will provide NI_ Year 2000 Team to ensure year 2000 readiness.

System Software and Radiation Monitor will be tested by the result in or constitute an unrevewed safety question, an unreviewed [ ]Yes [I]No

8. Will the proposed activltylcondition . 0-,,. .-... 4, pmm fthataffecstheabilityofthestation to A...

ernvi rnmental quamwigr. 8 11WWou* mr. .,.*,*, .. -... ... . .

or Technical achieve and maintain safe shutd 4n Inthe event of a fire, or require a license amendment Specificatfions change?

MMU" Safety Evaluation Page 2 of 12 IVP P-00 -sAta h e t01111111 Part A.;ResOluuon,*Uai...

the change,

18. Summarize from Pad D. Unreviewed Sa Question Determination, the major issues considered; state the reason and state why an unreviewed safety question does or does not exist (a simple test, or experiment should be allowed; conclusion statement is Insufficient).

shutdown when the system detects that the The high capacity steam generator blowdown system Is designed to automatically 02 (202) A/B/C) has been attained tank Inlet flow (as sensed by 11 2-BD-FT-1 setpoint for maximum or minimum blowJown flash attained. Also, the system (205)), has been or the blowdown flash tank maximum outlet flow (as sensed by 1/ 2-BD-FT-105 by 11 2-SD-PT-100 (200)).

flash tank high pressure (as sensed automatically shuts down when the setpoint for the blowdown cooler high outlet temperature the blowdown the blowdown flash tank high or low level (as sensed by 112-BD-LT-100 (200)), 11 2-CN-PT-101 (201)) have high pressure (as sensed by (as sensed by RT1 12-BD-RTD-101 (201)) and the main condenser been attained or exbeeded.

System was upgraded to Y2K readiness per During the spring 1998 Unit 1 refueling outage, the Unit I High Capacity SG BD as human pirformance improvements requested DCP 98-130. Also, included in that package were enhancements categorized the capability for overriding specified system trip signals that were requested by the by the Operations Department. However, received a safety review.

I&C Department was omitted from the package, because that item had not it Y2K reedy and add human DCP 99-119 will implement changes to the Unit 2 High Capacity SG BD System to make during the Unit I blowdown system modifications. In addition, both the performance enhancements similar to those added from the Individual System trip signals Units I and 2 Systems are to be further enhanced by adding the capability of overriding win be added be Included in DCP 99-119 and the Unit I enhancements transmitters listed above. The Unit 2 enhancements will by way of a field ct;ange to DCP 98-130.

high capacity BD system is in service.

At present, the transmitters listed above cannot be serviced or recalibrated while the trip signal that may be actuated during a maintenance or This is so because it Is not possible to disable the automatic In order to facilitate online maintenance or calibration of these transmitters, i the need should arise, the calibration evolution.

for disabling the trip signal from the transmitter that has been software for the system will be changed to provide the capability software changes will include the addition of a maintenance screen that will Include several selected for maintenance. The screen via a button bar titled "Main. Screen" and a safety features. The maintenance screen will be accessed from the mimic capability has an In the maintenance screen each component that has on line maintenance new separate user and password.

function is in "Startup", or FW Maint. is in "Yes". Also, "ON' and an 'OFF" pushbutton which will not operate ifthe Startup/Run these buttons will not operate unless the appropriate device is placed In manual.

be changed. Only one When a transmitter Is placed in maintenance, the status of the Startup, and the FW Maint. button cannot for maintenance will enable n flashing red display transmitter at a time can be placed in maintenance. The transmitter selected to visually display its status. This flashing status indicator will be visible from on of "MAINT" in close proximity to the transmitter In maintenance will be displayed on the both the mimic end maintenance screen. The numeric display for the transmitter will be alarm selpoint for the transmitter In maintenance is exceeded an alarm indication blowdown computer screen. When an displayed on the computer screwv" 1o verify functionality of the alarm.

blowdown non CE-821 AC controllers associated with PY/CN201A-2 and PY/CN2OI B-2 directly feed a steam generator isolated digital input module. This misapplication was a potential cause for a high copacity blowdown trip (Ref DR N-97-2778 DCP 99.119 Will incorporate the reconnection of an Interposing relay for Unit 2 to eliminate the potential for a and N-97-3046).

already been successfully performed on NAPS Unit I via DCP spurious high capacity blowdown trip. The same change has98-130.

with NUREG-0700. STD-GN A Human Factors analysis has been performed and the proposed modifications are In compliance by NBU Year 0005 and GN-STD-.003. The computer, the software and the programming wil be tested by a test plan provided The Blowdown Radiation Monitor will also be tested by a test plan provided by 2000 Team to ensure year 2000 readiness.

NBU Year 2000 Team to ensure year 2000 readiness.

steam None of the changes to be implemented will affect the likelihood of a loss of offsae power to station auxiliaries, a generator tube rupture or an excessive load increase incident These changes affect only the software associated with the high system which Is In no way connected to safeguards systems designed to operate during capacity steam generator blowdown Compensatory measures to be Included the events listed above. Thus the consequences of those accidents am not changed.

or level in applicable maintenance and operations procedures will prevent failures resulting from loss of flow. temperature protecton for the blowdown flash tank will still be available duMng the activity. The creation of new control. Overpressure question does not exist, and accident or malfunction possibilities is not Introduced. For these reasons, an unreviewed safety should be allowed. ....

this activity

Safety Evaluation 0

>~RINl1A P01w~ln Page I of 12

• VAP*00 -IAtahmn 2 Applicable Station 3. Applicable Unit

1. Safety Evaluation Number Station [XI Unit 1 [ Unit 2

[x) North Anna Power ]Unit1 [ ] Unit2 3 Surry Power Station 7t7

• PartA -'"ResoUtlsu was performed.

4. List the governing documents for which this safety evaluation DCP 99-135, "Lube Oil Sample Test Ports'

6. Summarize the change, test, or experiment evaluated.

1-FW-P pumps, I-CC-P-1AB and pump motors, I-CC-P-AB, Lube oil sample test ports are being installed on safety related pumps and pump motors that are operating satisfactorily.

on non-safety related 3A,B, similar to the installations already completed

6. State the purpose for this change, test, or experiment.

operation. This lube oil samples without removing the equipment from The lube oil sample test ports provide a method to obtain the lube oil samples.

just to obtain prevents equipment from having to be rotated off and on the or assumed by this safety analysis. For each item, indicate

7. List all limiting conditions and special requirements identified 6 formal tracking mechanism that will be used to ensure that None.

these conditions and/or requirements will be met.

safety question, an unreviewed Yes (X] No

8. Will the proposed activitylcondition result in or constitute an unreviewed to [

environmental question, a change to the Fire Protection Program that affects the ability of the station a license amendment or Technical achieve and maintain safe shutdown in the event of a fire, or require Specifications change?

Safety Evaluation Page 2 of 12

18. summarize from Pert D, Unr*vwed Safety Question Ddutrmntion, the major issues consider state the reason the an unrevimwed safy question does or does not exist (a simple change, test, or expeiment should be allowed; and state why conclusion statement Is insufficient).

DCP 99-135 isbeing issued to intetal lube oil sample test ports on safety related equipment similar to those installed onenon-saety lube oil related equipment in Unit I and Unit 2 by prior DCPs. The installtion of the sample test ports will enable repressn exposing the lube oil systems to contamination. The lube oil samples to be obtained withotd equipment shutdowns and without samples. The test port is sef sealin to prevent leakage. end a samples will be smaller and require less labor for obtaining the cap Issupplied with the test port to ensure the system is sealed and doesn' leak oil.

safety question as defined in 10 CFR The installation of the lube oil sample test ports does not constitute an unreviewed 50.59 because it does not te Increase the probability of occurrence or %malnctiol oseu nes o foanac ce or Of equpme n mportanttto safety and previously evaluated in the SAR. N nor function wil be degraded by th function of the system Is installation. The installation meets the design crteri of the system, and the safety rlt unchanged.

Createsa possibility of an accident or malfunction ofe diffeOrtypOthe any eluted previously in theae SR. No new equipment accidents or malfunctions created by degradation mechanisms are created by the lnstallution. No new the installation.

a Technical Specification or Operating Ucense. The pedormance capabilities, function, does not require a change to the Reduce the margin of safety as defined in the basis of the Technical Specifications andreliability and capacity ofthe affected systems am not altered by the installation.

Reduce the ability to achieve and maintain safe shutdown in the event of a fire.

change effluents or power levelas, Increase any environmental impact evaluated In the Final Environmental Statement, Plan.

have an adverse environmental impact and does not change the Environmental Protection El

Safety Evaluation 0

VIRGINIA POWER Page 1 of 12

• VPP*00 __Atahmn Applicable Unit

2. Applicable Station 3. A*pplicable Unit

1. Safety Evaluation Number

[XJ Unit 1 [X] Unit2

[X] North Anna Power Station I Unit2 99-SE-MOD-019 I I Surry Power Station [ I Unit I

• PartA - ResWIuU --- m--W-r--'t-. .. ..... . .

governing documents for which this safety evaluation was performed.

4. List the DCP 99-142, "CHARGING PUMP MINIMUM FLOW RECIRC ORIFICE REPLACEMENT'

5. Summarize the change, test, or experiment evaluated.

recirculation orifice assembly with a new 22-stage Design change 99-142 will replace the charging pump. 11-stage minimum-flow orifice assembly.

6. State the purpose for this change, test, or experiment.

that the gas intrusion source for North Anna Based on experience gained in the industry regarding gas voids, it has been postulated minimum-flow recirculation line. Specifically, the gas is being mechanically is caused by gas stripping In the charging pump and testing at other facilities has orifice. Evaluation striped from solution by the jetting process in the charging pump mini-flow flow returns back to the common flow: water and gas bubbles. The two-phase shown that the orifices were discharging two-phase Light's Beaver Valley Power Station other plants, Duquesne charginglSI suction header via the seal water heat exchanger. Two pump recirculation mini-flow orifice Power Station, found that replacing the charging and Pacific Gas & Electric's Diablo Canyon gas voids in the charging header.

significantly reduced with 22-stage orifices specifically designed to eliminate gas stripping, a

7. List all limiting conditions and special requirements identified or assumed by this safety analysis. For each item, Indicate tfle

7. List all limiting conditions and special requirements identified or assumed by this safety analysis. For each Item, indicate the will be met.

formal tracking mechanism that will be used to ensure that these conditions and/or requirements None

8. Will the proposed activitylcondition result in or constitute an unreviewed safety question, an unreviewed C IVes [XJNo of the station to [ ]Yes [X]No environmental question, a change to the Fire Protection Program that affects the ability amendment or Technical achieve and maintain safe shutdown in the event of a fire, or require a license Specifications change?

Safety Evaluation Page 2 of 12 VPP30 -1 Atahmn 3 Part A l-ResolutiowSUMrf* - .y.- .f-.-- " .

state the reason the

18. Summarizefrom Part D, Unreviewed Safety Question Determination, the major issues considered; why an unreviewed safety question does or does not exist (a simple change, test, or experiment should be allowed; and state conclusion statement is insufficient).

The issuance of SOER 97-01, "Potential Loss of High Pressure Injection and Charging Capability from Gas Intrusion',

and charging pumps.

characterized several events in the nuclear industry related to gas intrusion of the high-pressure injection and individual 6" charging A 1989 study conducted at North Anna determined that gas voids do indeed exist in the common 8' it was believed that gases coming out of solution from the VCT supply caused the pump suction headers. At the time of the study, of gas pockets gas formation. The study concluded that due to system piping layout and flow velocities during a DBA, ingestion capable of causing HHSI pump damage was not possible.

likely cause of As a result of discussions with other utilities and by review of OE data, it has been recently concluded that a more exists. Based on experience gained in the industry regarding gas voids, it has been postulated that the gas the gas formation in the charging pump minimum-flow recirculation line. Specifically, the intrusion source for North Anna is caused by gas stripping and gas is being mechanically stripped from solution by the jetting process in the charging pump mini-flow orifice. Evaluation testing at other facilities has shown that the orifices were discharging two-phase flow. water and gas bubbles. The two-phase flow returns back to the common charging/SI suction header via the seal water heat exchanger. Two other plants, Duquesne Light's Beaver Valley Power Station and Pacific Gas & Electric's Diablo Canyon Power Station, found that replacing the charging pump recirculation mini-flow orifice with 22-stage orifices specifically designed to eliminate gas stripping, significantly reduced gas voids in the charging header. It is requested that North Anna modify Its charging mini-flow recirculation lines by replacing the existing orifices with 22-stage orifices.

SUMMARY

OF SAFETY ANALYSI The modification did not constitute an unreviewed safety question as defined in 10CFR50.59 since it did not:

A) Increase the probability of occurrence or the consequences of an accident or malfunction of equipment important to safety and previously evaluated in UFSAR.

The activity does not generate new initiators that would affect the probability of occurrence for analyzed accidents. The status of the mini-flow recirculation orifice assembly is not a precursor to these accident scenarios. The operational characteristics of the charging pump remain the same. Replacing the charging pump mini-flow recirculation orifice with 22-stage orifices specifically designed to eliminate gas stripping, will significantly reduce gas voids in the charging header. This will increase pump reliability. The new orifice assembly is designed to provide a charging pump recirculation flow rate of 60 gpm, which is the same as the original 11-stage orifice assembly. The modification will not adversely affect ECCS flow characteristics that could challenge flow requirements for existing LOCA analysis or HHSI pump runout limits. Operability of the charging pumps will not be compromised by this activity. The HHSI/charging pump will continue to perform Its intended design function for mitigation of the analyzed accidents.

B) Create a possibility for an accident or malfunction of a different type than any evaluated previously in the UFSAR.

Replacement of the charging pump mini-flow recirculation orifice is intended to increase pump reliability without changing pump operating characteristics. The activity will not prevent the charging pump from performing as designed during both normal and DBA conditions. The new 22-stage orifice assembly will develop the same pressure drop and flow rate as the original 11-stage orifice. The new components are constructed of materials that are compatible for use in the CVCS/HHSI system and meet all design pressure/temperature requirements. The pumps will continue to operate in the same manner as before this modification is performed. Accidents or malfunction of equipment of a different type than was previously evaluated is not credible due to the nature of the modification.

C) Reduce the margin of safety as defined in the basis of any Technical Specification.

Charging pump mini-flow recirculation orifice replacement will not have any adverse impact on the Tech Specs associated with the charging pump nor will any margin of safety be affected by this modification. ECCS operability and flow characteristics will not be impacted by this activity.

FOMmNO. 7=ogS(Jkm*S)

Safety Evaluation VIR7GINIA POWER Page 1 of 12 091 IMTIT"M 1 Safety Evaluat-oin Number 2 Applicable Stat;on 3. Applicable Unit

- "00- ZO [x] North Anna Power Station (X) Unit 1 fxI Unit 2 i I Surry Oower Station [ I Unit 1 ] Unit 2 Pa rt A - Re s o l u tio n S u r m a y R ep t- . .. . _ _. . _ ..

4 List the governing documents for which this safety evaluatiorn v,=s a) North Anna Power Station Technical Specification Ch.ange Requestperformed. No. 371 b) DCP 98-007, Revisions 2 and 3 (FC2 and FC3), FW Flow Calorimetrc / North Anna / Units 1 and 2

5. Summarize the change, test, or experiment evaluated.

North Anna Tech Spec Change No. 371 is being intiated to correct the Tech Spec Bases for the Steam Flow - Feed Flow Mismatch Reactor Trip in order to support DCP 98-007. Field Changes 2 and 3. DCP 98-007. FC2 and FC3 provide revised Steam and Feedwater Flow Protection System scaling per commitments made in the original DCP The scaling changes described below will enhance the operation of the functions described below~

1) Steam Flow Protection and Control will be normalized to Reference Feedwater Flow (i e.. the Feedwater Flow calculated by the P-250 and PCS Computers via Feedwater FI.OWCALC) This change will increase the accuracy of Steam Flow Indication and 2

the RPS / ESFAS Steam Flow signal used in the 7300 Process Control System.

) The Feedwater Flow Trarnsmitters will be re-scaled so that their spans are calculated based on the same parameters as those used in the P-250 and PCS Feedwater FLOWCALC programs This scaling change will enhance the accuracy of Feedwater Flow indication along with the feedwater flow portion of the Steam Flow / Feed Flow Mismatch RX Trip. In addition, this change coupled with the steam f,)w changes will improve the operation of the Steam Generator Level Control System (3GLCS) by matching the steam flow signal more closely to the feedwater flow signal. Matching the Steam and Feedwater Flow signals will reduce the offset experienced by the Feedwater Flow Controllers during normal operation.

3) The SF-F Mismatch RX Trip Setpoint will be changed from 34 % of Flownom the operating margin for this trip while ensuring that the UFSAR and Design to 40 % of Flownom. This change will increase Basis assumptions are still bounded. Tech Spec Change 371 will change the existing incorrect Tech Spec Bases Setpoint values and account for this scaling change.

4) The Steam Flow Feed Flow Mismatch Summing Amplifiers in the Steam Generator Level Control System will be re-scaled to reflect the Post-SGRP design flow of 4.247 - 106 PPH. This change along with the changes described above will improve the operation and stability of the Steam Generator Level Control System based on the design conditions documented in References 21a. and 21b 6 State the purpose for this change, test. or experiment.

The purpose of DCP 98-007 FC2 and FC3 is to provide revised scaling for the Steam and Feedwater Flow Protection and Control System These scaling changes will ensure that the Reactor Protection System Trips generated from Steam and Feedwater Flow accura:ely reflect actual plant conditions and are meeting the Tech Spec Allowable Summator in the SGLCS is being re-scaled to reflect the Post-SGRP Values As stated aLove. the SFFF Mismatch Design Flow of 4.247

• 106 PPH at 100 % Power.

7ýList a!!llimiting conditions and special requirements identified or assumed by this safety analysis. For each item. -indicate the formal tracking mechanism that will be used to ensure that these conditions and/or requirements will be met.

For the DCP Field Changes. FW and STM Flow Transmitter span changes and P-250 ] PCS Computer changes must be made/

installed prior to startup. For the Technical Specification Change (Bases Change), no changes are needed. 1-18OG-ll-s:*.

18 WilI the proposed activity/condition result in or constitute an unreviewed safety question. an unreviewed environmental question, a change to the Fire Protection Program that affects the ability of the station to [ ' Yes [X) No achieve and maintain safe shutdown in the event of a fire, or require a license amendment or Technical Specifications change?

Safety Evaluation Page 2 of 12 0 Part A Reou umm Rport...

LYA-64, Atahmn 3

18. Summarize from Part D. Unreviewed Zafety Question Determination, the major issues considered; state the reason the change, test, or experiment should be allowed; and state why an unreviewed safety question does or does not exist (a simple conclusion statement is insufficient).

Statement of Problem During the preparation of DCP 98-007, discrepancies were identified involving the installed Feedwater Flow Transmitter spans on both units. Specifically, the calculation that determined the Feedwater Flow Transmitter spans for both untIs (i.e., EE-0445, Revision 0 with ADDO0A and ADDOOB) assumed that Tap Set 1 on each flow venturi was connected to the respective Channel IV transmitter and that Tap Set 2 was connected to the respective Channel III transmitter.

Based on Engineering Transmittal ET SE-99-002, Revision 0, it has been determined that Tap Set 1 is connected to the Channel III transmitters and Tap Set 2 is connected to the Channel IV transmitters.

This means that the transmitter spans installed on the Channel III transmitters should be installed on the Channel IV transmitters and the Channel III spans should be installed on the Channel IV transmitters. In addition, a calculation error was found on the span used for transmitter FT-2487. Based on this information, the bounding offset between the existing Feedwater Flow Transmitter spans and the required spans is + 0.661 % of the AP span. This equates to an offset of + 1.13 % of Flow,,

at approximately 40 % power and decreases to + 0.46 % of Flow,. at 100

% power (Ref 4.20). These offsets are bounded by the existing margin to the Technical Specification Allowable Value for the SFFF Mismatch RX Trip. Based on this evaluation, it %as decided that the re-scaling of the Feedwater Flow Transmitters could wait until the next outage for each unit and that no Unreviewed Safety Question exists concerning Feedwater Flow. Additionally, the advar,,ages of postponing the re-scaling of the transmitters until the outage allows the scaling to be based on process/design inputs that are derived from actual plant data and further, the scaling will be now be based on the same I. calculational methodology as that used by the P-250 and PCS FLOWCALC programs.

Arlother item that re-surfaced during the preparation of the DCP was instrument scaling. Specifically, Corporate I&C/C was asked to determine if increasing power (and thus flow) would have any affects on the 7300 Protection and Control System.

The review determined that North Anna's Steam and Feedwater Flow Protection System was not exceeding Tech. Specs but was very close on some of the loops. The original DCP stated that Steam Flow would be normalized to Feedwater Flow during the next outage on each unit. Normalizing Steam Flow to Feedwater Flow will ensure that the Reactor Protection System is scaled as close as possible to the ideal values and accurateiy reflects actual plant operating conditions. Note the example below for the High Steam Flow in 2/3 Lines ESFAS Trip Function (Refer to Figure 1 on Page 2A)

Referring to Figure 1 on Page 2A, The High Steam Flow Setpoint for Channe!s 3 and 4 is set at the same voltage value of 8.730 VDC equating to 110 % of Flow,, (i.e., 4.247

• 106 PPH

• 1.1 = 4.6717

• 106PPH). The High Steam Flow Setpoint voltage is calculated based on the average steam pressure for the unit at 100 % power (i.e., known as P,,,). The calculation of the High Steam Flow Setpoint is provided in Technical Report EE-0085, Appendix 18-2, Revision 0, Turbine First Stage Pressure (TIP) Protection and Control (Ref 21.c). The methodology is illustrated below:

VSTPT ((Flow,,.

• 1.1) / Flow,,. ) 2 10 VsT=( (4.247 E6 - 1.1) / 5.0 E6 ) *10 2 V~rpT = 8.730 VDC Note that for conditions of Pr,,, the pressure coml eiisation applied to the raw Steam Flow AP input voltage signal as it applies to the High Steam Flow Setpoint is equal to 1.0. The voltage calculated above is presently installed as the High Steam Flow Setpoint for all the loops in Unit 2. The same also applies for Unit 1.

Continued on Page 2B of 12 .....

Fom No. 730918(June S)

Safety Evaluation Supplemental Page 2A of 12

...- 0K-ýtahnn 3I TRIP STPT - 0.000 VDC

" 0.0 % DEVIATION 2 STEAM FLOW = 4.279 MPPH

@ 100 % POWER TRIP STPT = 0.000 VDC

"- 0.0 % DEVIATION FIGURE 1 - UNIT 2 "LOOP A" HIGH STEAM FLOW IN 2)3 LINES ESFAS TRIP NOTE:

The transmitter spans (i.e., 0-1629.9 " W.C. is the non-high line pressure corrected span equivalent to 1613 " W. C.) given above are based on the presently installed spans as specified in Instrument Calibration Procedures 2-ICP-MS-F-2474, Revision 6 and 2-ICP-MS-F 2475. Revision 6. All other data shown in Figure 1 above is based on plant data taken from the PCS Computer over a 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> period on May 10. 1999. This data can also be found in Technical Report EE-0085, Appendix 12-2, Revision 0, Steam and Feedwater Flow Protection

Safety Evaluation Supplemental Page 2B of 12 I Part. '-:.- - .... .-='.rUse an-Alpha SauffrkPage N .be'(kg. 6A'o,12 ). . - . . - ** -... "-,.:.

As shown in Figure 1, for the same Reierence Flow of 4.279 MPPH (this flow value takes SG Blowdown of 0.03 MPPH into account), the raw Steam Flow AP voltage input signal bo the High Stam Flow Bistable from Channel 3 (FQ-2474) is different than the raw Steam Flow AP voltage input signal to the High Steam Flow Bistable from Channel 4 (FQ-2475). However, the setpoint for both channels is the same as shown above. For ideal conditions, both transmitters should be outputting the same voltage (or close to the same voltage) for the same flowrate. In aodition to correcting the voltage offset between cnannels, both of the Steam Flow Transmitters should be scaled so that the Steam Flow AP input voltage to the High Steam Flow Setpoint Bistable at 100 % power is equal to the following:

V=, (Flow,, / Flow,) 2 10

= (4.279 E6 / 5.0 E6) 2 10 Vw = 7.324 VDC Like the High Steam Flow Setpoint, for 100 % power conditions, the pressure compensation applied to the raw Steam Flow AP input signal should also be equal to 1.0, thus flow is equal to (AP)" 2 . This means for a normalized system, both Channel 3 and 4 Steam Flow Transmitters would4-utput the same voltage to their respective High Steam Flow Setpoint Bistable even though they are measuring a different AP. The maximum offsets for both Units with respect to the "Ideal Value" were analyzed during the preparation o. the- odginal DCP*,and were,.found,,to be bounded by.Technical Specifications and by the Safety Analysis.

However, some of the loops were close to the Tech Spec Allowable value. This is one of the major reasons why Steam Flow is being normalized to Reference Feedwater Flow. This method of normalization is applied to many other Reactor Protection Functions such as AT, Reactor Coolant Flow, NIS Power Range and Turbine First Stage Pressure (now known as Turbine Load).

Similar to the High Steam Flow Function illustrated above, the scaling for the Steam Flow Feed Flow (SFFF) Mismatch RX Trip and Steam Flow Indication is also less than ideal. Presently, the Process Gain (K,) used for the Steam Flow Multiplier Divider Square Root (NMD) Card is the same for all channels and all loops on Unit 2. The same also applies for Unit 1. Having the same Process Gain on all the NMD Cards is acceptable if the transmitters are normalized. However, if the transmitters are not normalized and if the NMD Card Process Gain is not set correctly (i.e.. based on P,,* at 100 _%_pa.er),then~the,7300 Protection System will not accurately represent the actual flow in the loop. This will affect the SFFF Mismatch RX Trip and Control Room indication. The example below illustrates how Steam Flow is calculated based on.the current scaling:

From Figure 1 (Page 2A), Unit 2 "Loop A" Reference Flow is 4.279 MPPH. The Steam Flow NMD Card calculates flow using the following Module Equation:

VFLow = (VP

• VPRss

• KP) 12 Where:

VF1oW" = Output voltage from the Steam Flow NMD Card V", = Steam Flow AP input voltage VPRESS = Steam Pressure input voltage KK = Process Gain = 1.7362 VN for Unit 2 Using test data from Technical Report EE-0085, Appendix 12-2. Revision 0 (Ref 21.d) and Figure 1 (Page 2A), we have the following calculated Steam Flows for Unit 2 "Loop A", Channels 3 and 4 at 100 % power.

Form No. T409MSNov 91)

Safety Evaluation Supplemental Page 2C of 12 a Part .. Use ah.Alpha Suffix Page Number (e.g..4_ of 12):.

IVAP301 ig rmet m

Channel 3 VFLOICK == (7.182

• 5.934 - 1.7362) 12 VFLowc 3= 8.602 VDC and FLOWc, 3 = (8.602/10)

• 5.0 E6 PPH FLOWC1 3 = 4.301 MPPH Channel4 VFLOWCH 4= (7.312

• 5.941 " 1.7362) 112 VLOWC,= 8.685 VDC and FLOWcH, = (8.685/10)

• 5.0 E6 PPH FLOWc, . = 4.343 MPPH Comparing the flow values above, it can be seen that the Channel 3 and 4 values are different and that neither one matches the Reference Flow of 4.279 MPPH. This Steam Flow offset combined with the Feedwater Flow offset described above was analyzed for worst case conditions during the preparation of DCP 98-007 to ensure that the SFFF Mismatch RX Trip was not exceeding the Thcfi Spec Allowable Value. The analysis determined that the trip was bounded by Tech Specs because the actual trip setpoint in the plant is set in the conservative direction with respect to the Nominal Setpoint given in Tech Specs by 6.0 % of Flown,, Additionally, the SFFF Mismatch RX Trip is not credited in the Safety Analysis (Ref 21.0 and thus no Safety Margin analysis is required. Based on the above discussion, no Unreviewed Safety Question exists with respect to the SFFF Misnatch RX Trip for current plant conditions.

As stated in Chapter 7.0, Section 7.2.2.3.5. of the UFSAR, the value where the SFFF Mismatch RX Trip is assumed to be available is 50 % Power. The existing setpoint of 34 % of Flow,,=

and thus 34 % Power is 16 % conservative with respect to thi3 assumed value The current 16 % margin is excessive for this function based on current plant conditions and is overly bounding when compared to the Channel Statistical Allowance Value for this function (i.e.. 6.21 % of Flown,, = 7.31 % of Flow,.,j. For this reason, the SFFF Mismatch RX Trip Setpoint on Unit 1 will be changed from the existing setpoint value of 1.448 MPPH based on 34 % of Flow, .*, Pre-SGRP Design Flow to 1.699 MPPH which is based on the Tech Spec Setpoint value of 40 % of Full Flow at Rated Thermal Power (i.e., Design Flow @ 100 % Power

= 0.4

• 4.247 MPPH = 1.699 MPPH). The Unit 2 SFFF Mismatch RX Trip Setpoint will be changed from 1.444 MPPH based on Flow,,* (i.e., 1.699 MPPH, same as Unit 1). With this SFFF Mismatch 34 % of Flown,., Post - SGRP Design Flow to 40 % of RX Trip Setpoint change, both units will be set at the same trip setpoint and the plant will recover 6 % operating margin while still remaining within Technical Specification, UFSAR and Design Basis Requirements. In order to implement the Steam Flow - Feed Flow Mismatch Setpoint change, Tech Spec Change No. 371 has been prepared to change the Bases for Section 2.0 2.2. 1. Steam / Feedwater Flow Mismatch and Low Steam Generator Water Safely Limits and Limiting Safety System Settings. Section of % of nominal flow instead of an actual flow value given in lbs/hour. Level so that the setpoint value will now be specified in terms See Tech Spec Change No. 371 for the exact wording of the Bases change When Steam Flow is properly normalized to Feedwater Flow, both the raw Steam Flow AP voltage and the calculated Steam Flow voltage from each channels NMD Card will be equal or close to the required (i.e., the Ideal) values as described above.

Additionally, the calculated flow from the Steam Flow NMD Card will closely match the Reference Flow when the plant is at 100

% power. An example of the effects of normalizing Steam Flow to Feedwater is provided in DCP 98-007, Revision 2 (FC2):

Section 2.0.

Form No. 730928(Nov 91)

Safety Evaluation Supplemental Page 2D of 12 I

Part.. Use an Alpha Suffix Page Numbelfe.g., 6A of 12)..,- -.- .

Asa result of re-scaling the Feedwater Flow Transmitters and normalizing Steam Flow to Feed Flow, the FLOWCALC programs used in the P-250 and PCS Computers must be updated to reflect the new transmiter spans and Steam Flow NMD Card Process Gain (Kp,). These changes will be transparent to Operations and will not affect the calculation of Steam Flow or Feedwater Flow in any way as long as the NEW (correct) transmitter spans and NMD Card Process G.. is (PCS Computer only) are entered into the FLOWVCALC program files. The changes made to the P-250 and PCS Computers will he managed and controlled in accordance with VPAP-0306. Therefore, an Unreviewed Safety Question does not exist with respect to the FLOWCALC programs or Reactor Power.

Lastly, the Steam Flow / Feed Flow Mismatch Summing Amplifier used in the Steam Generator Level Control System is being re-scaled to reflect the Post-SGRP Design Flow of 4.247

• 106 PPH. At the present time, the scaling installed on this card represents the Pre-SGRP Design Flow of 4.26

• 106 PPH. The scaling change made on the three SFFF Mismatch Summing Amplifiers in each unit will be minimal and will not affect or even be noticeable to plant operations. These summing amplifiers are part of the NSSS Control System and thus they are not addressed in the Safety Analysis or in Technical Specifications.

To summarize, the scaling changes included in DCP 98-007 FC2 and FC3 will enhance the accuracy of the Steam and Feedwater Flow portions of the Westinghouse 7300 Protection and Control System. These changes will have no impact on the Safety Margins that are in place for the functions derived from these parameters. In addition, these scaling changes will not change the calculation?' results of the Feedwater or Steam FLOWCALC programs in the P-250 or DCS Computers. In fact, these changes will increase the margin of safety for the applicable trip functions and make the Control Room Indications much mornrccurate.

IMow -" *.....

• Form No. 730g2$(Nov 91)

99-SE-MOD-21 Description DCP-99-145 makes permanent a Temporary Modification (TM N2-1128). This involves replacement of buffer amplifier cards with thermocouple amplifier cards for three feedwater temperature computer inputs.

DCP 99-148 makes these card changes via DCP, no TM involved.

Summary This activity does not involve any physical modification to the facility. The new thermocouple amplifier (TC) cards (installed by TM N2-1128) are manufactured by the same company as the buffer amplifier (BA) cards, and they are designed to fit the same slots. Bench testing and the performance since having been installed by TM has shown that the TC card has a more stable output than the BA card. The affected cards send a MFW temperature signal to the plant computer system (PCS) and emergency response facility computer system (ERFCS) only. The signal to the P-250 is not affected. Thus, the P-250 FW flow calorimetric is not affected by this activity.

Operations department calorimetric procedures currently "auctioneer" to the most conservative (or highest power) calorimetric indication. Currently the Unit 1 and Unit 2 calorimetrics using their PCS are the highest, thus they are used as the official indication. Since the accuracy of the calorimetric is in question due to the sensitivity of the BA cards to instrument drift, this condition may be requiring an unnecessary reduction in unit electrical output.

Failure of the activity, for the near term, is bounded by the evaluations performed for the FW flow calorimetric performed under 99-SE-MOD-01. Additionally, the PCS indications of FW temperature or FW flow calorimetric will not be adversely affected. This has been proven empirically by comparing the results obtained with the new cards vice U-1 results using the old (pre-modification) cards. Thus, there is no adverse affect on nuclear safety. No new accidents are created, and consequences of analyzed accidents are not affected. There is no reduction in the margin of safety or ability to mitigate accidents. For these reasons, an unreviewed safety question does not exist.

Since the activity will install amplifier cards in the circuit that are better suited for the application and result in a more accurate FW flow calorimetric, unnecessary reductions in unit electrical output may be eliminated. Therefore, this activity should be allowed.

Safety Evaluation e

.WflWM POWER Page 1 of 12 VPP-00 -IAtc hmn

2. Applicable Station 3. Applicable Unit

1. Safety Evaluation Number qq,.., -,* P 2,, / / (x] North Anna Power Station Surry Power Station

[x] Unit 1

[ ] Unit 1

[ I Unit 2

( I Unit2 Part A - Resolution S*mmary Report

4. List the governing documents for which this safety evaluation was performed.

DC 97-007 USFAR update #99-026

5. Summarize the change, test, or experiment evaluated.

to trip main generator breaker, the exciter field breaker and thebe tui.ine auto stop Proposed changes consist of: (1)rewiring the over excitation signal trip indication for over excitation, (2) a test switch will not provided in solenoid trip, to prevent damage to the main generator and to lock-in the for unit 2) since breaker G-12 will be open when the generator is off line, (3) circuit ISPGNO2 to defeat the K3 over excitation signal (as provided Relay to provide a adding a Percent Negative Sequence Ammeter, on the generator control panel, wired to the existing SGC Negative Sequence ALERT" annunciation in inthe Main Generator. (4) providing "NEGATIVE SEQUENCE visual indication of the Percent Negative Sequence Current and allow for operator action, before unit trip occurs, (5) addItions and or the control room to alert the operator of the degrading condition 11& IC, (b) Isophase Duct Backup Lockout Relay, (c) switchyard aux relay turbine trip corrections to the event recorder for: (a) switchyard breakers LO RELAY TURB TRIP" and "GEN BACKUP LO RELAY TURB TRIP annunciator and (d) Generator Breaker G12, (6)Combine *GEN DIFF windows Into a single window 'GEN LO RELAY TURB TRIP'.

6. State the purpose for this change, test, or experiment.

as an Induction generator. To improve the operators visual Indication of the To enhance the protection of the main generator against operatingimproved operator response to high negative sequence current. To lock-in the trip negative sequence current In the generator and to support provided to the event recorder.

indications for the Volts/Hertz Relay. To increase and/or correct the information by this safety analysis. For each item, indicate the M7. List all limiting conditions and special requirements identified or assumed and/or requirements will be met.

formal tracking mechanism that will be used to ensure that these conditions None safety question, an unreviewed

8. Will the proposed activity/condition result in or constitute an unreviewed affects the ability of the station to [ ]Yes [XINo environmental question, a change to the Fire Protection Program that in the event of a fire, or require a license amendment or Technical achieve and maintain safe shutdown Specifications chanae?

Safety Evaluation Page 2 of 12 VPA 301*- tahmn

-Part A.R.,oltUUofln 9MtV -1ý the change, Summarize from Part 0, Unreviewed Safety Question Determination, the major issues coidered; state the reason

18. safety question does or does not exist (a simple conclusion test, or experiment should be allowed; and state Why an unreviewed statement is insufficient).

of sufficient tie-ins) will be performal during a unit outage mzplementatiOn of this DCIC (i.e. prior to return of the unit to testing of modifications duration to support modifications and with Operations approval. The implementation of service. Somes non-outage work can be performed the ability of the of the unit main generator and improve this DCl will improve the protection to negative sequence current and possibly avoid operator to monitor generator status related below.

unit trips. The work involved is discussed in detail inappropriate the 0211-1 relay 33 condition when the unit is -on-line, At present, during an over ezcitation the generator remains tied to the system. the operates to trip the xciter Field Breaker, however field and draw high reactive generatorwhen loosing its generator will act am an induction and stator temperatures to increase and will will cause rotor current. The high reactive current the system in time.

is not removed (discounncted) from damage the generator if the generator trip the 86W lockout which DCI modifies this circuit and the K3 relay will now Therefore this and turbine via the turbine auto stop breaker, the generator breaker trips the exciter field switch as Aon for unit 2, to isolated, by a test solenoid trip. The 13 relay contacts will not be is performed in the when unit 1 is off line and maintenance prevent tripping of the 0-12 breaker being tested. 1hen unit 1 is off line, the relay circuitry Is voltage regulator cabinet or the X3 tripping the breaker G-12.

is no need to be concerned about breaker 0-12 is open. Therefore there LO RMlAY TURD TRRI This DCP will combine the "G DZtr LO RULAY TURB TRXP and -4= BACIUP N M .0 RELAY TU TRX10.

annunciator windows into a single window alarm light on the 9*C of negative sequence current is the Currently, the only visual indication that the negative sequence current has which indicates relay in the Emergency Switchgear Room The annunciator window 13-5S will be connected to the relay reached the relay alarm set point. indication when the p*erator In the control room a visual alarm contacts and will provide the the percent negative sequence ammeter in the addition of relay alarm met point is reached. The an auxiliary Operator to trend the the touring operator or EmergencySwitchgear Rom will allow (SOC) negative sequence relay. The combination of the negative sequence current, sensed by the the necessary allow the control room operator to take the negative sequence current Impacts the time cmeter and the annunciator can possibly a unit trip, The magnitude of the action to prevent and in cases where the negative sequence current operator has to react to the abnormal condition to relay operation and thereby trip the unit- Whe is high may preclude operator action prior to take if normal readings and instr.ctions for action eammeter label Shows a range for expected For cases, 'where the current is high enough to the reading is outside of the specified range. room, response joill be per the appropriate control cause the annunciator to activate in the Annunciator Procedure.

IC9s 11 & 1c, to provide Information for the wiLtcbyard The Zvent recorder is being changed Bs AMNK Relay Trip and Generator Breaker Trip, Switchyard Iaslated Phase Duct Backup Lockout Relay G12.

the type of an accident of a different type than This work does not create the possibility The contacts for over excitation relay are Analysis Report.

previously evaluated in the Safety iREPU01 to the Generator Over Excitation Control circuit relocated from the Exciter Field Breaker trip the exciter field breaker, the arrangement will portion of the circuit 15?P02. This This will cause a turbine trip and in many auto stop solenoid.

generator breaker and the turbine are previously analysed conditions.

however, these cases (above 30% power) a reactor trip, in the of occurrence of a malfunction identified This work does not increase the probability non-safety. Tripping the turbineo and the main generator is Safety Analysis Report (Sam). This work 15.2.7 of the UFSAR.

the tripping c! t reactor is discussed in Section ossibly resulting in (continued on page 2A of 12)

Fm No. 73016(*b 00)

II Safety Evaluation Supplemental Page 2A of 12 S. .h. .

I Part AUMLL -!f A 18 (continued)

While an line, the unit (turbine and generator in all cases, and reactor under most coUditions) Will now be tripped on overez* itation by either the Beckwith voltu per herts overeCitation relay modification, the (present design) or the Westinghouo molter circuit (MS relay). Prior to thisunit was on-line. by (K3 relay) only tripped the exciter field breaker if the Westinghouso circuit tripping the unit usig the Westinghouse overemaitation detection, the trip could in most cases occur probability of trip before the Beckwith relay would have tripped the unit and thereby improves the Additionally this modification will provide for a lock-in of the before generator damage occurs.

to possibly damaging the gonerai or the overexacitation trip Indication. By providing a trig prior of danage to a najor non-safety component has been reduced with no adverse Impact on probability probability of other malfunctiams.

to any part of the %ech.

This work does not affect the margin of safety of or require any changes Specs. or the Operating License.

or the Operating This work Is non-safety and does not result In a*y changes to the Tech. Spoms.

dinput signal for over excitation of the main generator is relocated to another circuit to License. The breaker, the exaitor field breaker and the turbine auto stop enable the tripping of the generator eociter field breaker solenoid trip by tripping the 86U lockout relay. The tripping circuits for the and the generator breaker are eisting.

of the raw*rking the Based oan the review, an unreviewed safety question does not esist, as a result signal to trip the exciter field breaker, the generator breaker and the Westinghouse overescitation aan nd blu auto trip stop solencid, remorking overexcitation trip Indication, prviding of negative sequence current, revising generator lock out amunitation and e indication fying the identification of points an the event recorder.

is within Also, there is no impact to the enviroment or increase In occupational exposure an all work clean areas of the service building and the turbine building.

ama" generator Visual enhancement is provided to monitor the percent negative sequence current In the A

my the addition of the ameter in the moergency hwitchgear Room and the "'M9 S3Q annunciator window in the control roac.

is provided to Tripping for negative sequence cwurent is not changed by Ohis MM. Visual enhancemnt sequence current In the min generator by the addition of the percent monitor the percent negative 3MQ AT*M*

negative sequence current smeter in the mrgency uitchasea Room and the window in ,ontrol the room. The visual enhancement will reduce the probability of a unit annunciator be able to take nation trip, due to negative sequence curreznt, because in some cases the operator m to reduce the negative sequence current below the trip setpoint before the time delay empires.

Form NIL 730928(NOY 91)

I .*................. 1.-.....

• ':.. .. ....- - .:-.,-- , 1 7- I . , -.

"2 "

Safety Evaluation Page 1 of 12 h 1A POIWER ..

S Number 2 Applicable Station 3. Applicable Unit

[x] Unit 1 EX) Unit2 X 1 North Anna Power Station Revx powereoStation tUnit i iIUnit 2 99-S E-MOD-28 RGc1 ev lu tio .ws. urryer.r

• .......h.hthi.sfe evaluation was performed.

4. List the governing documents for which tis safety NAPS Unit I &2 Damper Instrument Air & Electrical Power Modification/

DCP 99-130. Auxiliary Building Central Area Exhaust NSS 99130. Test Engineerin Procedure D-NAT-99-130-1 test, or experiment evaluated.

5. Summarize the change, after a seismic event or loss the Auxiliary Building central Area exh.ust dampers The design change enhances the ability to operate supply, upgrading the damper instrument air supply tubing to seismic category I and of offsite power by adding a seismic reserve air also provides damper position from a safety related source. The design change upgrading the power supply to the control SOVs uirements.

r indication for corn hence with R. Guide 1.97 "6.State the purpose for this change, test, or experiment.

with post-LOCA ECCS were written to identify ventilation concerns Deviation Report N98-0395 and PPR 98-001 15.4.1.7 Identifies that the Auxiliary Building Central Area contamination. UFSAR section leakage and airborne realignment, a 60-minute be manually aligned to filtered exhaust and to account for the manual ventilation system must In the event of a loss of in the analysis of doses resulting from a LOCA.

delay in filtration of ECCS leakage is included fail positions.

to the filtered exhaust configuration due to damper offsite power, the system can not be realigned atmospheric cleanup all components of an engineered-safety-feature Reg. Guide 1.52 section C.2.c specifies that supply and distribution should I. Section C.2.h specifies that power system should be designated as seismic Category Table 6.2-51, COMPLIANCE WITH REGULATORY GUIDE 1.52, UFSAR be designed in accordance with IEEE-308. requirements, the that the system meets the C.2.c and C.2.h requirements. Contrary to these REV. 1, indicates Area exhaust damper operation and the power source that controls the Auxiliary Building Central Instrument air supply "Bypass dampers are In addition, UFSAR section 8.4.8.2 states for filtered exhaust alignment are not in compliance. in series to satisfy the single Two pressure-tight dampers are installed provided for each system and filter assembly. filter bank". The Auxiliary contaminated exhaust to leak around the failure criterion at locations that would permit air tubing configuration.

this requirement with the current instrument Building Central Area dampers may not fulfill the design and license basis criteria.99-130 will upgrade and configure components to comply with Design Change ch item, indicate the sIdenied or assumed by this safety analysis.

7. List all limiting.conditons and sp eciaireto ensure that these conditions and/or requirements will be met.

formal tracking mechanism that will be used See attached item 7, age 1A constitute an unreviewed safety question, an unreviewed

8. Will the proposed activitylcondition result in orProtection Program that affects the ability of the station to [ ]Yes [X]No environmental question, a change to the Fire ._ amendment or Technical license achieve and maintain change? safe shutdown Inthe event of a fire, or require a Spe.c._._fications

I Safety Evaluation of 12 Supplemental Page IA S~ ____

exhaust for filtration of ECCS

7. analysis assumes manual alignment of the Auxiliary Building Central Area accident initiation.

leakage within 60 minutes after filtration dampers, one on the exhaust system has four dampers. two by-pass dampers in series and two The central area filter inlet and one on the filter outlet. the operability of the Cental Aea exhaust system damrs.

ill directly oerab l oft ret der al idAreaxso n

TWO activities during DCP impleme.ntation air and electrical power will render cM t of all four MAItio mperlinkage *1ials .1 Demolition and tie-in of Instrument on the as inoperable. Installation ofthe actuation arms for position indiation exhaust dampers impact damper operation.

Area exhaust dampers will be To maintain compliance with the accident analysis, the Auxiliary Building Central eectrical and the iactuation dma in their filtration positions. The instrument air and will be functional as blocked/mechanically secured with blocked. The by-pass dampers still function from the control mr e:d.....mptem rom wl0t:be installations be performed will ssitioned Slation dampers filtration the..910Iproom will be postoe the dampers 811O firation but opening

.... to allow and dosing,,,.h umZOOuu dampers are* ..... i th 1'

The Implementation steps identify that the.lock5imedwnlclas Iestraints sSht supervisor. .oprtinShift Supervisor sign-off when the m sgjaton positions. :Steps are als include f...

the Operations Soteps f posiin. for are removed and the dampers have been restored.

with the dampers blocand the actutorunbcTed-.

Testing of individual components will be performed are reconnected and the dampers are l ed m n their functional testing to stroke the dampers, the actuators D 30le tos uNAT-99-1 t a contingency, steps are included In the Test Engineering Procedure results.

As (stroking the dampers) produces unacceptale blocked accident positions iffunctional testing

Safety Evalgation Page 2 of 12 F - ,

F does or does not exist (a simple test, or experiment should be allowed; and state why an unreviewed safety question conclusion statement IsInsufficient).

and toprovide Building Central Area exhaust serves the charging pump cubicles to maintain temperature The Auxiliary during accident conditions.

the availability of a filtered ventilation exhaust path plant components Building Central Area exhaust system physical Design Change 99-130 was Initiated to bring Auxiliary in the UFSAR. New SOVs, air accumulators, air pressure vegulators, to perform functions discussed air with separate into compliance Isolation val ll be installed to seismic category I requirements. Backup check valves, single-ailurecriteria.

will be controlled through redundant SOVs to meet air supply tubing to each of the in-line dampers accumulator isolation valves. Seismicallyair Installed between an existing vent valve and the isolation to the check valves and Copper tubing will besteel tubing will be Installed from the accumulator valves supported stainless the air accumulators to the air pressure qeguletor, SOV and tubing from accumulators. The instrument with seismically supported stainless steel tubing. Electc powerto the now SOVs air supply damper actuators will be installed Vital Buses 1-4 and 2-11.

will be supplied from safety-related 120 VAC UNREVIEWED SAFETY QUESTION ASSESSMENT:

ofthe because the design change conforms to the requirements increaseth

1) Accident probability has not been increased of instrument air components and power source do applicable codes and standards. The upgrade the ventilation system function, damper srrangement and 0 probability of occurrence of an accident because Central Area exhaust ventilation system can not Iiftiate an operation have not changed. The Auxiliary Building accident.

The Auxiliary Building serves the charging um Central Area exhaustconditions.

2) Accident consequences are not increased. The pg d ventilation exhaust path during accident cubicles to provide the availability of a filtered ..

enhances the ability for operation of the system In e.....ice.ol Its instrument air components and .power source design

.............- A _.,, ,im,1-f- FO:CS leakage maintain compliance with system licensing and bases in the event of an unfiltered release.

Sintended

3) No unique funcoon.

accidentM, mmunsu probabilities are created.

i codes and standards.

design meets the requirement of the applicabli

4) Margin of Safety is maintained because the

Safety Evaluation 0

VJIRINIA PObWERi Page l of 12

• I.P- 0 -SAtah et3-

1. Safety Evaluation Number 2. Applicable Station 3. Applicable Unit 00-SE-MOD- 13 Ix] North Anna Power Station I ] Unit I [x] Unit 2

[ ] Surry Power Station [ I Unit 1 ( I Unit2

4. List the governing documents for which this safety evaluation was performed.

Design Change 00-138 "RVLIS Sensor Bellows Reorientation" - Unit 2

5. Summarize the change, test, or experiment evaluated.

The "A" and "B" train reactor head sensor bellows assemblies In the reactor vessel level instrumentation system (RVLIS) will be inverted such that the capillary connections are reoriented from the top to the bottom of the sensor assemblies in order to preclude air intrusion into the sealed tubing system.

6. State the purpose for this change, test, or experiment.

Westinghouse Technical Bulletin TB-101RI "RVLIS Calibration Anomalies Due to Air Inleakage" reported that at several plants, recalibration of the reactor vessel level instrumentation system during refueling shutdowns have indicated that air inleakage into the sealed portion of the system have caused errors in readings and Inaccurate calibrations. In almost all cases, air was found in the section of tubing from the reactor vessel head sensor and the operating deck. To prevent possible air inleakage through the sensor bellows, o-ring seal, and fill valve, Westinghouse recommends that the vessel head sensor be inverted so that the capillary tubing connection Is on the bottom.

7. List all limiting conditions and special requirements identified or assukiied by this safety analysis. For each item, indicate the formal tracking mechanism that will be used to ensure that these conditions and/or requirements will be met None

8. Will the proposed activitylcondition result in or constitute an unreviewed safety question, an unreviewed environmental question, a change to the Fire Protection Program that affects the ability of the station to [ ] Yes [x] No achieve and maintain safe shutdown in the event of a fire, or require a license amendment or Technical Specifications change?

Safety Evaluation Page 2 of 12

18. Summarize from Part 0, Unreviewed Safety Question Determination, the major issues considered; state the reason thesimple change, test, or experiment should be allowed; and state why an unreviewed safety question does or does not exist (a conclusion statement Is insufficient).

Westinghouse Technical Bulletin T9-101 RI RVUS Calibration Anomalies Due to Air Inleakage' reported that at several plants, recalibration of the reactor vessel level instrumentation system during refueling shutdowns have indicated that air inleakage into the sealed portion of the sysktem have caused aeors in readings and Inaccurate calibrations. In almost all cases, air was found in the section of tubing from the reactor vessel head sensor and the operating deck.

Westinghouse determined that when the sensor Is disconnnected from the reactor for refueling, the sensor bellows is exposed to atmospheric pressure, and the water in the tubing above this elevation is below atmospheric pressure.

There are three locations with mechanical connections, having the potential for inleakage: the fill valves at the head connection and operating deck, and the bellows or Its o-rlng seal in the head sensor.

To prevent possible air Inleakage through the sensor bellows, o-ring seal, and reactor head connection fill valve, Westinghouse recommends that the vessel head sensor be Inverted so that the capillary Aubing connection is on the bottom. During refueling, the bellows and seal would then be exposed to a positive pressure and could be covered with water to block air inleakage. Also, air trapped In the bellows could not reach the tubing connection at the bottom of the bellows. The modification also moves the fill valve at the sensor to a lower elevation, resulting In a positive pressure at this potential leakage location. In order to accomplish the sensor inversion, the existing capillary tubing will be cut and additional tubing added. Westinghouse reports that they have not been advised of any air inleakage problems where the sensors were Installed in the inverted position.

Also, based on experience reorienting the RVLJS bellows on Unit I (Design Change No.00-101 "RVLIS Sensor Bellows Reorientation'), upon rotation of the reactor head sensor bellows, the wide part of the assembly housing may interfere with the existing sensor protection plates that surround the bellows "semblies. (items 5 on drawing 13075-FK-I3AB).

In order to avoid the Interference between the sensor assembly housings and the sensor protection plates, the sensor assemblies will be moved horizontally back towards the reactor cavity wall approximately 1.625" on the existing assembly support. Two new holes for the U-bolt support mounting bolts will be drilled, while reusing one of the ed-ting holes for each U-boit. A new 3/8' Swagelok union and short length of 3/8W tubing will be installed in the removable section of 3/8"-RC-648-1CN9-Q2 between isolation valve 2-RC-209 and the existing 3/4" x 318" Swagelok reducer to accommodate the horizontal relocation of the sensor housing assemblies. The additional Swagelok union connection is being provided for ease of future repair of the 314" x 3/8' Swagelok reducer connection which is taken apart each refueling outage, as well as for ease of installation.

The reorientation of the RVLIS reactor head sensor bellows assemblies does not create an unreviewed safety question.

The operation and function of the RVLIS system Is not affected. The sensor bellows assemblies are mechanical pressure boundary separation devices that are designed to operate In any position. The design and Installation of the new tubing extension pieces Is consistent with the original system design requirements. Thus, this design change does not affect any previously evaluated accidents or create any new accidents of a different type.

0 In accordance with Technical Specifications 3.3.3.6, the new reorientation of the RVLIS sensor assemblies will be performed during a refueling outage when the RVLIS system may be removed from service for maintenance.

V

• m

AM Safety Evaluation Page 1 of 12 VPAP-3001 -AWm t

2. Applicable Station 0. pwPlivau = "%

1, Safety Evaluation Number IX] North Anna Power Station [xj Unit I IxiIUnit2 Unit2 0.-SE-MOD-O 14 C ] Surry Power Station 1 jUnit1I Pa"* - R-_-_ution summar- Report

4. Ust the governing documents for which this safety evaluation was performed.

UNIT 1 DCP 00-147, MFRV ACTUATOR AIR SUPPLY MODIFICATION DCP 00-148, MFRV ACTUATOR AIR SUPPLY MODIFICATION UNIT 2

5. Summarize the change, test, or experiment evaluated.

from each Main Feedwater Regulating The design change will remove the Air Lock-up valves and the air supply, filter regulators with an in-line air filter with the same micron rating.

Valve (MFRV) actuator assembly. The filter regulator will be replaced

6. State the purpose for this change, test, or experiment.

of these components in their current The MFRVs can safely operate as designed without these actuator components. Failure Unit operation. Removal of these components will configuration could lead to a loss of MFRV control, which could jeopardize improve system reliability and maintainability.

rasmdb f~5stt niss i-o eur wii . Ia ai I

m Tisi i.odtinidPca euieet dniid ...

r7. List all limiting conditions and special requirements identified or assumed boy this safety analysis. F-or each Rzem, ,indictet,it will be met.

formal tracking mechanism that will be used to ensure that these conditions and/or requirements None

8. Will the proposed activity/condition result in or constitute an unreviewed safety question, an unreviewed f ]Yes [X]No the station to C ]Yes [X]No environmental question, a change to the Fire Protection Program that affects the ability of achieve and maintain safe shutdown in the event of a fire, or require a license amendment or Technical Specifications change?

Safety Evaluation Page 2 of 12 m

s.~Ifon~ Rtepoft -.. I

18. Summarize from Part D. Unreviewed Safety Quetion Determinaton, the major issues considered; state the reason th change.

(a simple test, or experiment should be allowed; and state why an unreviewed safety question does or does not exist conclusion statement is insufficient).

The MFRVs were modified in 1993 which replaced the Copes-Vulcan valve trim and sprng diaphragm type valve actuator with the current piston actuator. This retrofit included the installation of the VB-1 1 air lock-up (1/2-FW-AOV-1/2 CCI Drag trim and pneumatic when IA decreased to 65 esig to allow the MFRV to fail close 4XX-1) to each actuator assembly. The air lock-up valve was added force exerted on the diaphragm was provided by the actuator spring, which overcame the or lower. The previous failure mechanism can be removed without by a decreasing IAsupply to shut the valve. Recent studies have concluded that the air lock-up valve testing have confirmed that the adverse affect to system operation. Consultations with the actuator manufacturer (CCI) and actualthe MFRVs will no longer trip MFRVs will fail close on a local, catastrophic loss of IA. On a gradual loss of IA header pressure, in the event that IA pressure close at 65 psig. However, 1/2-AP-28 requires the reactor be tripped and the MFRVs be dosed on a gradual toss of IAwhen the fail close decreases to less than 70 psig. Even without operator action, the MFRVs will eventually weight of the valve plug and stem overcome the forces acting on the pneumatic piston.

typically runs at approximately 105 The MFRV actuators are currently supplied with IA regulated to 100 psig. IA system pressure to actuator components or the affects psig upstream of the filter regulator. The filter regulator can be removed without any adverse Main Feedwater upon receipt of an MFRVs themselves. This modification will not affect the existing MFRV closure time for Isolating remain in that configuration following ESF actuation signal. The volume tank is currently supplied with unregulated IA and will installed such that all MFRV actuator implementation of this design change. An air filter with the same micron rating will be that has exhibited air leakage components receive a filtered air supply. Eliminating the air regulator will remove a component problems without sacrificing system operation.

adversely affecting FW This modification should be allowed since it will increase system reliability and maintainability without system operation.

ANUMMARY OF SAFETY ANALYSIS it did not:

The modification did not constitute an unreviewed safety question as defined in 10CFR50.59 since important to safety and A) Increase the probability of occurrence or the consequences of an accident or malfunction of equipment previously evaluated in UFSAR.

accidents. MFRV control and The activity will not generate new initiators that would affect the probability of occurrence for existing by this modification, the operation remain unchanged. Since the fail-safe operation of the pneumatic actuator remains unchanged not increased. The valves will continue to fail close on a loss of Instrument Air probability to prevent isolation on an ESF signal is The MFRVs can operate without the air lock-up valve in place. The modification should improve valve reliability and maintainability.filter. Removing a air filter requirements with the installation of an in-line air safely without the regulators while maintaining the potential for the MFRV component (air lock-up valve) whose failure could cause a sudden closure of the feed reg valve reduces the MFRVs be closed in to inadvertently fail open or closed. Plant procedures currently exist that require the reactor be tripped and by this activity.

the event that IA pressure decreases to less than 70 psig. Operation and control of the MFRVs remains unchanged B) Create a possibility for an accident or malfunction of a different type than any evaluated previously in the UFSAR.

modification.

Malfunction of equipment of a different type than was previously evaluated is not credible due to the nature of the such as feed reg Removal of the regulator and lock-up valve will not create new equipment malfunctions. Types of malfunctions erratic control, and overfeed presently exist in the SAR and are not changed by this modification. The new valve spurious closure, as the original air filter is constructed of materials that is compatible for use in the IA system, has the same filtering requirements its code integrity filter regulator, and meets all design pressure/temperature requirements. The ability of the FW system to maintain, is performed. The will not be compromised and the system will continue to operate in the same manner as before this modification possibility of generating a different type of accident than previously evaluated is not credible.

C) Reduce the margin of safety as defined in the basis of any Technical Specification.

of safety be The activity will not have any adverse impact on the Tech Specs associated with the FW system nor will any margin with affected by this modification. Following implementation of the modification, testing will be performed to ensure compliance of safety has not been reduced since the FW system will still be isolated within the time stot in Tech Spec 3.3.2.1. The margin the Tech Specs. Tech Spec basis remains unaffected by this activity.

rotm No. 7=01G(JW*u200)

Safety Evaluation e

Awhh Pe Page 1 of 12 I . VPP 00 - Atahmn 3

2. APPlica Station 3. Applicable Unit

1. Safety Evaluation Number EX) Unit I IX) Unit 2

[XI Noiitih Anna Power Station E ] Unit I t I Unit 2 00.SE-MOD-

• 1 ] Suny Power Station 7-3 was pe o ..

4* Ust the governing douments for which this Safty euation

& R4 9.6.4.4 & Plant Issue Resolution N-2000-0282-R3 DCP #00-005; VPAP.0809; NAPS UFSAR, Section evaluated.

5. Sumnarize the change, test, or experiment UPSAR, Section 9.A.4.4, to Add two (2), newly Identified NUREG4612 special lifting devices to VPAP-0809 and NAPS Seal the Ring Flip Rig. Modifydetail Lift Rig & Reactor Cavity officially document the existence of the Reactor Head StudanRack bail hook detail end add a seal weld to the lug Rig to correct adverme ball book of the Reactor Head Stud Rack ft Flip Rig to Improve the corrosion resistance of the lug weld detail.

of the Reactor Cavity Seal Ring

6. State the purpose for this change, test, or em+,,ent.

& R4, two (2) new NUREG-0612 special lifting devices were In response to Plant Issue Resolution N.2000-0282-R3to be modified and officially documented Into the NAPS NUREGsin12 Identified. These specal lifting devices need and CDS forms in DCP tet associated NAPS UFSAR Change Request Program. Documentation will be controlled under DCP No. 004005.

under No. 0-005. Modifications will be Implemented each item, indicate the identified orasswred by this safety analysis. Forbe met.

7. ist all limiting conditions and special requirementS ensure that these conditions andlor requirements will formal tracking mechanism that will be used to Evaluation, are assumed for this Safety implementation for this Safety Evaluation. The special requirements, to ensure No limiting conditions existspecial lifting devices In VPAP4SO9. The formal tracking mechanism Nos. N as stated for NUREG4612 Issue Resolution under the corrective action assignments to Planttwo-(2), new NUREG-0612 of these special requirements will be tracked un il ensure that the modifications to the 2000f0282-R3 & R4. These tracking mechanisms have been completed and ta the appropriate sections of NAPS devices, discussed In No.

-CP 00-005, devices into the NAPS special lifting the addition of these two.(2) new special lifting UFSAR and VPAP-0809 have been revised to reflect thru 0? 8 59004352694-1.

NUREG-061 2 program, specifically W.O. 5900435237-01 constitute an L*nreviewed safety question, an unreviewed

8. Will the proposed actiitylcnditiMon result in orProtection Program that affects the ability of the station to Yes [Xl No environmental question, a change to the Fire of a fire, or require a license amendment or Technical achieve and maintain safe shutdown in the event Sp*cifications change?

Safety Evaluation I

Page 2 of 1.2

.. *-301ýAtacrei Question Deterinafori, the major issuesdoes considered; state the reason the change.

18. Summarize;fomPartD, Unreviawed an urireviewed safety question or does not exist (a simple test, or experiment should be allowed; and state why conclusion statement is insufficient).

to bring the following two (2). newly Evaluation deal with the modifications needed The major issues associated with this Safety I guidelines of NUREG-0612 ("Heavy Loads"), as compliance with the Phase identified special lifting devices into programmatic Cavity Seal Ring Lift Rig..

Reactor Vessel Head Stud Rack and the Reactor stated in NAPS UFSAR, Section 9.6 and VPAP-0809:

2,000 pounds. A load is a heavy load as any load that weighs more than NAPS NUREG-0612 Phase I report has established carred over irradiated fuel, safe shutdown or decay 2,000 pounds and is subject to the requirements of NUREG-0612 if it exceeds buildings to temporarily hold Stud Rack Lift Rig is used inside containment hoat removal equipment. The Reactor Vessel Head The stud rack weighs mrs than 2,000 pounds during refueling outages.

vessel head studs during head removal and replacement moved inside containment, loaded or unloaded. The load lift whenever when empty and shall constitute a NUREG-0612 heavy reactor seal ring over for seal replacement containment buildings to turn the Reactor Cavity Seal Ring Flip Rig is used inside the pounds empty. The reactor cavity seal ring weighs approximately 2.000 during refueling outages. The lip rig weighs less than the flip rig would be considered to be a "heavy load" lift, whenever 18,000 pounds. Under the Phase I guidelines of NUREG-0812. buildings.

containment loaded with the reactor cavity seal ring inside the devices should satisfy the 5.1.1(4), "Special Lifting Devices, special lifting In accordance with US NRC NUREG-0612, Section Weighing 10.000 pounds (4500 kg) or Lifting Devices for Shipping Containers guidelines of ANSI N14.6-1978, "Standard for Special this NUREG-0612 Phase I guideline is outlined in NAPS UFSAR, response to More for Nuclear Materials". Virginia Powees original the ANSI N14.6-1978 requirements for were not in strict compliance with Section 9.6.4.4. In summary, these special lifting devices compliance, as noted in the following discussions.

and continuing design, fabrication, acceptance testing, and maintenance, visual inspections and be located for either special lifting device. Engineering No official design or fabrication documentation could with good quality workmanship, out of devices appear to have been fabricated evaluations have concluded that both special lifting 0 materials at least equal to ASTM A 36. Calculation tensile stresses meet the allowable stress limits of Addendum CE-0798, Revs. 1B ANSI N14.6-1978 (i.e. F.S. > 3.0 for yield and the stud racks and the spreader and IC beams have for demonstrated F.S.

the

> 5.0 flip'rig have that all shear and for ultimate tensile been checked strength) for both special lifting devices. In addition, buckling does not preclude either special lifting device from safely against AISC (ASD), gth Edition to ensure that compressive document the design and "as-built" DCP sketches have been prepared to supporting its full rated load capacity. Design calculations and final configuration of these special lifting devices.

receive annual load ANSI N14.6-1978 requires that special lifting devices With respect to acceptance testing and maintenance, testing. By virtue of the satisfactory initial visual and non-destructive tests at 150% of the rated load capacity or annual dimensional, inspections that are required, annual 150% load tests or annual visual 150% load test that were performed and the prior-to-lift periodic non-destructive be waived. To ensure a higher level of reliability, dimensional, visual and non-destructive testing may ISI Program. The US NRC has previously accepted, for other augmented examinations will be performed under the NAPS 10-year periodic nondestructive examinations of critical inspections, coupled with NUREG-0612 special lifting devices, prior-to-lift visual in lieu of annual 150% load testing (reference NAPS UFSAR, Section elements under the NAPS 10-year augmented ISl Program, as specified in ANSI visual dimension and nondestructive examinations, 9.6.4.4). Similarly. the 150% annual load tests or annual of special lifting devices N1 4.6-1978, may be waived for these two-(2) types which will be subject to a non-destructive examination (NDE) program, 10 years.

NAPS requires that all NUREG-0612 special lifting devices inservice inspection

,stu racks. interval Based onofthe above welds and critical parts overA,a normal  ;,.-)1 mr 0-orovide for periodic inspection and NDE of all critical Specific baseline and 10-year inservice inspection attributes are provio*uo U.]. ui m,-, ...

All shear and have been reached for these special lifting devices: (1)

Safety Evaluation discussions, the following conclusions ANSI N14.6-1978 requirements for design, fabrication, and quality of ANSI N14.6-1978. (2) with ANSI N14.6 tensile stresses meet the design criteria -Athose

,,,h

. gner~y usld for these devices. (3) Although not in strict compliance assurance are generaBy in re assurnce ague==*,;,

muuv.~...e......

1978 requirements, pnor-to-lift visual inspection of the load lne and 10-year interval NDE of critical welds and critical parts, meets the intent of ANSI N14.6-1978 for acceptance testing and maintenance.

Section 9.6.4.4, to justify NUREG-0612 Phase I programmatic Similar conclusions were originally reached in NAPS UFSAR, coolant pump the reactor vessel heads, reactor internals, and reactor compliance for the special lifting devices associated with are also in compliance with the Phase I identified special lifting devices motors. Therefore, it is concluded that these two (2), newly be stated that the use of these special lifting devices does not such, it can guidelines of NUREG-0612 for special lifting devices. As UFSAR, for an accident previously identified within the NAPS increase the probability of occurrence or severity of consequences kind.

nor does it create the potential for an accident of a different Fmm No. 730915(JUnO 2000)

Safety Evaluation E A WR Page 1 of 12 U

1. Safety Evaluation Number 2. Applicable Station 3. Applicable Unit (x] North Anna Power Station [x] Unit1 Cx] Unit2 I Surry Power Station [ I Unit 1 [ I Unit 2

'Part A - Resolution Summary Report

4. List the governing documents for which this safety evaluation was performed.

Plant Issue N2000-2146. RM Letter, Special Report Serial No 01 -295, Docket No 50-338, 50-339, License No NPF-4, NPF-7.

DCP 99-006, "Replacement of Ventilation Radiation Monitors, NAPS, Units 1 & 2. UFSAR/ISFSI SAR Change Request NO 99-065.

Health Physics procedures.HP-3010.040, HP-3010.031, HP PT-453.01, HP PT-456.01. Wiring Verification r-NAT-I-002.

Procedure Emergency Preparedness documents EPIPs 1.01, 4.08, 4.09, 4.24. EALs B-4, B-7, C-7, C -9, E-3, E-5, G-l, G-2. VPAP -2103(N).

NSS work procedure t-WP-G99006.

Installation Test Procedure o-NAT-M-005.

ved5

.ý 7- P.,-fz. PCP 2-c c

5. Summarize the change, test, or experiment evaluated.

The current KAMAN process and vent stack particulate, iodine and gaseous radiation monitors 1-GW-RM-178, 1 -VG-RM-1 79 & 1 VG-RM-1 80 will be replaced by radiation monitor system manufactured by MGP Instruments. The currently installed Westinghouse, NRC and General Atomic radiation monitors 1-GW-RM-1 01/102, 1-VG-RM-1 03/104 & 1-VG-RM-1 12/113, currently installed in parallel with, and redundant to the KAMAN monitors, will be removed.

6. State the purpose for this change, test, or experiment.

The new monitors are being installed to replace the KAMAN monitors because the manufacturer has ceased production and support of the monitors. The current Radiation Monitoring System installation, performing redundant functions, is comprised of a parallel combination of different manufacturers' equipment that has been difficult and expensive to maintain and operate. The intent is to replace the current installation with a more flexible, state of the art system.

7. List all limiting conditions and special requirements identified or assumed by this safety analysis. For each item, indicate the formal tracking mechanism that will be used to ensure that these conditions and/or requirements will be met.

The corresponding Westinghouse and General Atomics skids need to be in operation to provide coverage of channel monitoring when the Kaman equipment is being replaced. Work Procedure 0-WP-G99006 will ensure that the Westinghouse and General Atomics are maintained and operable during these periods.

A procedurally controlled jumper will be installed on the process vent radiation monitoring system to enable the process vent automatic control function to be performed by the Westinghouse and General Atomics monitors while the Kaman monitors are being replaced. The replacing MPGI equipment will take over this function. Installation and removal of this jumper will be controlled via Work Procedure 0-WP-G99006.

8. Will the proposed activity/condition result in or constitute an unreviewed safety question, an unreviewed environmental question, a change to the Fire Protection Program that affects the ability of the station to ( ] Yes [x] No achieve and maintain safe shutdown in the event cf a fire, or require a license amendment or Technical Specifications change?

0 Safety Evaluation vIGIA POWER Page 2 of 12 I

Part A - Resolution Summary Report

18. Summarize from Part D, Unreviewed Safety Question Determination, the major issues considered; state the reason the change, test, or experiment should be allowed; and state why an unreviewed safety question does or does not exist (a simple conclusion statement is insufficient).

"*This50.59 evaluation includes aspects of 1). the DCP, 2). changes to the UFSAR and 3). the Temporary Modifications.

1). Evaluation of DCP Aspects:

"*The Unit 1 & 2 Ventilation Radiation Monitoring (KAMAN) system will be removed and replaced by a system manufactured by MGP Instruments. The currently installed redundant radiation monitors, situated in parallel with KAMAN monitors, will also be removed by this modification. This Design Change Package will be implemented "non-outage". The old equipment, that is, the monitors, samplers, skids, and local instrumentation mounted on the turbine deck and normal switchgear room, and the indicators, recorders, annunciators, controls and electronics in the main control room, will be removed and replaced in phases.

• During the phased replacement of the Kaman equipment, alarm annunciation signals will not be available from the Kaman skids. During this time the readings and associated alarms from the Westinghouse and General Atomic radiation detectors for these vents will be used as a substitute for the Kaman skid signals because they are part of the current radiation monitoring system which monitor the vents in parallel with the Kaman installation. These Westinghouse and General Atomic radiation detectors will be removed at a later phase of the modification.

• Automatic actions are initiated by the process vent RM which, on high radioactivity, open contacts which close the flow control valve GW-FCV-101 from the Gaseous Waste System and close the Containment Vacuum Pump discharge valves (GW-TV-102A&B) to the process vent system. The Containment Vacuum Pumps then stop automatically when their respective TRIP VALVE leaves the full open position. These actions stop the flow from the gaseous waste system and stop the transfer of containment atmosphere to the process vent system, therefore the actions are fail safe. The Westinghouse monitors, 1-GW-RM-101 and 1-GW-RM-1 02, will provide this control function while the Kaman Monitor 1-GW-RM-178 is being replaced. Once the replacement MGPI monitor 1-GW-RM-178 is installed, it will provide the control function. There are no redundancy requirements associated with this control function therefore there is no need to provide a replacement control signal when the Westinghouse monitors 1-GW-RM-101 and 1-GW-RM-102 are removed.

• The phased replacement will be controlled by NSS work procedure 0-WP-G99006. However, to enhance communication, the necessary actions will be discussed in look ahead meetings and daily meetings, as necessary, between NSS and Operations departments and will have timely placement in the POD. Similar restrictions are currently encountered during normal maintenance of this equipment and are handled by existing station procedures.

• Should any of these Westinghouse/General Atomic skids fail while this replacement is ongoing, Technical Specification, Table 3.3-6, Action 21, concerning fuel movement activities, or Action 35, concerning the identification of preplanned alternate means to provide high range monitoring to meet RG 1.97 requirements, will be in effect. The "B"vent stack Kaman skid replacement will be implemented during periods of no scheduled fuel movement and the preplanned alternate means to provide high range monitoring capability will be implemented by use of the NRC high range gas monitors.

"*When the accidents previously evaluated in UFSAR, Chapter 15, Section 15.3.5 were considered, it was seen that the activities during and after the modification will not increase the probability of occurrence of these accidents. The radiation monitoring system monitors ventilation radiation under normal operation and accident conditions but can not, of itself, increase the probability of accidents. During replacement of Kaman skids the loss of alarm annunciation from these skids will be compensated by taking alarm signals from the parallel Westinghouse monitors. Compensatory measures will include increased monitoring of plant parameters for the annunciation lost.

Also, for the process vent, Westinghouse monitors will provide the normal automatic control function to operate SOVs while the Kaman system is being replaced. The equipment will be replaced or removed in a sequence that will ensure the necessary monitoring and sampling of variables continues during the modification. Therefore, the probability of occurrence of an accident is net increased and the consequences of an accident are not increased.

"*Until a Technical Specification update, not associated with this DCP, is completed later than the DCP, the T.S. units for Stack "B"normal range gas and particulate channels are given as cpm while the units indicated in the control room by the MGPI equipment is microCuries/cc. For the convenience of Operations Department plaques will be mounted adjacent to associated 1-EI-CB-49E indicators giving the necessary microCuries/cc to cpm conversion factor.

Form No. 730916(June 2000)

0 Safety Evaluation w.ONI POwER Supplemental Page 2A of 12 ll Part A -. Resolution Summary Report

• The Health Physics stack "A"and "B" grab sample stations will be relocated, one at a time, from the current situation in the roof enclosure to elevation 291' 10", where they will be seismically supported and restrained as part of the last phase of this modification. The previously installed MGPI skids will have grab sample stations available that may be used should a grab sample be required while the HP sample stations are being relocated.

"*The DCP will replace an existing system with new, state of the art equipment that will perform all the functions of the current system.

The replacement radiation monitoring equipment is by a manufacturer with a design different from that used previously for ventilation radiation systems by Virginia Power. Although information on this equipment is not available on the EPIX system, it has been installed in several nuclear plants and is reported to have performed satisfactorily without incident by the manufacturer. The new equipment performs indication, alarm and one control function, in a manner similar to the presently installed system. Should a monitor fail, it will be declared inoperative and measures taken similar to those taken on failure of the currently installed system. It is therefore concluded that this modification to the ventilation radiation monitoring system will not create the possibility for an accident of a different type to that evaluated.

"*The DCP does not involve or impact any safety-related equipment or system. On DCP completion, the new equipment will perform the functions of the existing equipment. There are devices, not included in the old skids, which perform functions that will be performed by the new equipment skids. These devices will be removed by this DCP in a phased manner as their functioning is tested and proved.

"*This modification will not affect any reactor protection or reactor control circuits, nor will station isolation be affected by the evolution.

These radiation monitors will detect, monitor and indicate radiation activities and release rates, including annunciate alarms.

Control activities are limited to those described in the previous paragraphs. The installation of this equipment, monitoring in nature, will not cause an unreviewed safety question to exist, thus the changes required by DCP should be allowed.

2). Evaluation of UFSAR Aspects:

The DBD UFSAR Engineer has requested that the following be text be added on the acceptability of deleted wording in the UFSAR:

Section 11.4.2.1. The original statement was that the entire radiation monitoring system was fail safe. The proposed change removes the condition that the entire radiation monitoring system is "fail-safe" but leaves the statement that it is designed "with emphasis on system reliability and availability". This change is proposed for clarity, but is not considered editorial because of the criteria associated with the term "fail-safe". As used in the radiation monitoring system, it refers to items or criteria such as: reliable power, alternate monitors, loss-of-power indications, independence from other detectors, etc. However, the term "lail-safe"can be associated with more stringent criteria that evaluates all possible failure modes, and requires the component to always fail to the conservative condition. The radiation monitors do not fit this definition. The specifications for the radiation monitors do not require the systems to meet this conservative and rigorous definition of "fail-safe". What the specifications do require leads to reliable and available systems. This proposed text change will, therefore, ensure the UFSAR does not overstate the capabilities or design requirements of the radiation monitoring system. The system Is not required to be fail-safe, therefore such a statement should be removed. This statement should have been corrected at the time of the last UFSAR update. A similar change to Surry's UFSAR was also performed during their IRT review. For these reasons the change of wording of the UFSAR does not cause to be put into effect an unreviewed safety question.

Section 11.4.2.2. The last sentence in this section, pertaining to the particulate monitoring function for the Process vent system, "The sample system is controlled from the control room" is removed. This statement was validated under the UFSAR update effort (ref. ICMP database record identifier #30401) as referring to indications, which are recorded on strip charts located in the control room, and to the local annunciated alarms. This validation record also states that the radiation monitor can be source checked from the control room though this is not stated in this section of the UFSAR. These aspects of the instrumentation are not considered to be elements of control and in fact the new MGPI equipment will no longer have a source check feature nor will sample pump control originate from the control room. This statement is considered superfluous and not applicable to the new equipment, therefore it is deleted. However, the operators still have the capability of monitoring the indication and alarms of the sample system. For these reasons the change of wording in this section of the UFSAR does not invoke an unreviewed safety question.

Section 11.4.2.5. The statements made in this section regarding low sensitivity to changes in background radiation level and low tendency to over respond to different noble gas nuclides, as compared to gamma sensitive detectors, are being removed. These are subjective in nature and do not provide a reference scale or basis by which these statements can be compared and as such are not statements that are relevant indicators of safety of the plant. The statement concerning sensitivity to Kr-85 is retained as it is still applicable to the noble gas detector, though the word "excellent" is removed, as it is subjective in nature and without basis. For these reasons the change of wording in this section of the UFSAR does not invoke an unreviewed safety question. The change in reference to B vent duct size from 84" to 90" is due to utilizing the existing nozzle, which is located in the 90" portion of the vent duct, and which is currently used by the KAMAN vent stack monitors, for the new MPGI equipment. This was done because the GA Technologies monitor associated isokinetic nozzle, located in a portion of the 84" duct, will no longer be used for this function. This function is now performed Form No. 7309?8(Nov 91)

0 VIRGINIA POWER Safety Supplemental Evaluation Page 2B of 12 Um Part A - Resolution Summary Report system. The change of wording in the UFSAR does by the MGPI equipment, which uses the original installed nozzle used for the Kaman not invoke an unreviewed safety question.

and sample tubing up to the existing Kaman Section 11.4.3.1.1 statement concerning ANSI 13.1: Although the original isokinetic nozzles the reference to ANSI-N 13.1 is removed because isokinetic sampling is no longer employed with the new monitors are being retained, proportion to the variances in stack flow. This is still considered to meet MGPI monitors but rather sample flow is automatically adjusted in described in Regulatory Guide 1.21, and referenced in NUREG-0737, and complies with vendor the intent of representative sampling UFSAR requirements of below 1 scfm. Some questions of recommendations which indicated that particulate monitoring is ineffective 3 Root Cause Evaluation Guide 1.21 are addressed, and satisfactory answers found, in Category representative samples regarding Reg invoke an unreviewed safety question.

Response N-2001-0071-El. The change of wording in the UFSAR does not the built in response source is no longer Section 11.4.3.1.1 statement concerning built-in response source: The statement concerning MGP Instruments monitors-on the effluent gas applicable with the new monitors as they do not contain check source features. The Their electrical self-check introduces a known and fixed level of pulses into the channels perform various self-checks automatically.

Additionally, the electronics electronics, excluding the detector, and verifies that the response is correct or a fault is generated. the change of otherwise a fault alarm is generated. For these reasons continuously monitors the detector for a minimum count rate wording in the UFSAR does not cause to be put into effect an unreviewed safety question.

the DCP and of the changes that the A review has been made of the methodologies used in this DCP, of the implementation of the probability of occurrence or the consequences of an accident or implementation of this DCP has had upon the UFSAR. In each case, to safety previously evaluated in the safety analysis report will not be increased. Also, the possibility malfunction of equipment important in the safety analysis report will not be created and the for an accident or malfunction of a different type than any evaluated previously margin of safety as defined in the basis for any technical specification will not be reduced.

3). Evaluation of TM Aspects:

adjacent to the Effluent Monitoring Panel There are two temporary modifications involved in this DCP. 1) A temporary rack will be located to allow the control function of the Process vent monitor to remain continuously available during and 2) A temporary jumper will be placed Kaman skid replacement.

modification is required which places

• To accommodate the necessary phased replacement of the currently installed system, a temporary control panel in the control room. The existing control panel components will be a temporary rack adjacent to the existing effluent phased location of the new equipment. The relocated to the temporary rack and tested before being returned to service thus enabling to Operations DCP drawings, and the associated requirements communicated layout and location of the temporary rack is given in department via NSS procedure 0-WP-G99006.

control signal for the waste gas decay

• A second temporary modification is required in which the Kaman skid relay contacts providing the This modification will be procedurally controlled by tank and containment vacuum pump releases is replaced by a temporary jumper.

jumper will replace the normally closed contacts provided by the Kaman skid. Administrative NSS work procedure 0-WP-G99006. The particulate and control of this modification will not be required because this function will continue to be performed via the Westinghouse jumper and on a high radiation signal. Following MGPI skid installation and testing, the temporary gas detectors' series circuit contacts Westinghouse monitors will be removed.

valves to be installed. Plugs will be

• It should be noted that the sample lines from stack A and B vents will be opened to allow isolation effluent activity occurs. The use of available, at the sites of line openings, for use in blocking the sample flow paths should an increase in these plugs is controlled by Work Procedure, 0-WP-G99006.

with design criteria. Test department

• The test department will confirm that the temporary rack and jumper are located in accordance procedures to demonstrate operability of the circuits prior to and I&C department will use the applicable installation, wiring and calibration into service and after each temporary modification is removal. Control and testing shall be via NSS work the modifications being put procedure 0-WP-G99006.

installation of these modifications

• Compensatory measures and contingency plans will be taken to ensure that during the is unchanged. The functionality of alternate methods of indication and control are available ensuring that total functionality are as before DCP implementation. The the new equipment is as the old with the indication, alarm and control functions failure rate that the equipment being removed.

equipment is considered to be more reliable, thus have a lower that these modifications to the

• It is therefore concluded that the above measures and plans, implemented by procedure, ensure without constituting an unreviewed safety question.

ventilation radiation monitoring system will be implemented I--m Mr 7flQ9R(Nrw Qi I

P- M- 730928(Nov 91

Unit Document System Description Date 1,2 DCP99-010, F. C 2 SW F. C. 2 extends the time for operation of the charging pumps 4-10-01 00-SE-MOD-12 on the intermediate configuration from the end of April to REV. 2 UFSAR FN 00-036 May 10.

1,2 DCP 00-004 SW Rev. 2 in for a chg in 0-OP-49.7 (not the DCP) - states that 4-12-01 00-SE-MOD-19 alarm indications on MCR vertical board associated with REV. 1 UFSAR FN 99-032 open position of 1-SW-MOV-120B & 2-SW-MOV-220A will be temporarily removed. If temporary (< it72may hours) 0-OP-49.7 interruption of the blowdown is required, be done by closing 2-SW-MOV-120B or 2-SW-MOV-220A, or 1-SW 1351 or any combination of the above valves.

2 DCP 99-001, F. C. 1 Rev. 2 modifies the requirement of maintaining 2 one-inch 3-22-01 99-SE-MOD-08 drain valves tagged open as described in Rev. 1 to REV. 2 2-OP-1.3, 2-OP-3.3, maintaining at least one shellside drain per MSR open 2-OP-1 5.2 during shutdown, which will be an indicator of water in the 1-OP-26.8 MSR.

1,2 QA Topical / UFSAR Rev. 2 incorporates latest NRC comments: Changes the 2-06-01 00-SE-OT-13 3 Chg FN 00-04B retention requirements for fuel from Lifetime(a)( ) to REV. 2 Lifetime(a)(1) plus 3 years after the transfer of fuel.

QA Topical / UFSAR Rev. 3 incorporates latest NRC comments: Changes the 2-15-01 00-SE-OT-13 1,2 3 Chg FN 00-04C retention requirements for fuel from Lifetime(a)( ) to REV. 3 Lifetime(a)(1) plus 3 years.

Supersedes FN 00-04B packa-ge, which contained a misleading retention requirement.

UFSAR 00-027 Rev. 1 corrects an oversight in UFSAR change FN 00-027, 6-21-01 00-SE-OT-31 1,2 UFSAR 00-027A i.e., failure to reflect the revised cold-to-hot leg recirculation REV. 1 TS Chg #375 switchover interval previously evaluated in 00-SE-OT-31, Rev. 0. Also corrects a typo in the revision number of Reference 6 in Question 18.

1,2 TS CHG 376A Rev. 1 incorporates revised P/T limit curve data applicable 3-20-01 00-SE-OT-60 UFSAR EN 00-048 to heatup to address a Westinghouse computer code error.

REV. I TSCR 376B 1,2 1-OP-10.2 (R.5-P1) Rev. 1 allows connecting 2 suction hoses & 2 discharge 3-30-01 99-SE-PROC-22 hoses to the temporary air operated pump to allow a higher REV. I 1-OP-10.2 (R. 8-P1) flowrate.

1,2 TM Ni-I681 Rev. SW The PRV (1-SW-RV-1 02) providing protection to I-SW-TK-2 5-25-01 00-SE-TM-03 -

1 will need to have its set pressure lowered to 115 psig due to REV. I the projected thinning rate of the tank's wall thickness.

I

00-SE-MOD-12, Rev. 2 Description DCP 99-010, Replacement of Service Water lines to/from Charging Pumps and Instrument Air Compressors, and UFSAR Change Request No. FN 2000-036 Summary The scope of the design change includes replacement and modification of deteriorated four-inch diameter carbon steel (CS) and stainless steel (SS) service water (SW) headers and adjacent SW piping to/from charging pumps (CP) and instrument air compressors (IAC) with high corrosion resistant alloy AL-6XN.

Investigation (Calculation ME-0586) shows that adequate supply of SW to the CP and IAC can be achieved utilizing one pair 4" diameter SW headers (four 4" diameter lines) instead of the existing two pairs of headers (eight 4" diameter lines). This will simplify the existing piping layout and will cost less than a one to one replacement.

This SW piping replacement and modification does not involve unreviewed safety questions since replacement of the deteriorated CS with 316L SS piping with 6% Mo stainless alloy is replacement of the existing piping with superior quality (higher stress allowables and corrosion resistance ) material.

Therefore, the long term consequences of this replacement will increase reliability of the SW system. The intermediate and final stages of the modification satisfy redundancy and flow rate requirements for all modes of operation. No changes to the Operating Licenses or Technical Specification are required.

Basic SWS functions are not altered as a result of this piping upgrade. The SW piping configuration to/from charging pumps and IA compressors will be simplified. The existing complex piping is the result of multiple repairs and replacement since the original construction. This upgrade will not adversely affect the basic functions of the SW system and will not create an accident of a different type than was previously evaluated in the UFSAR. Replacement of the deteriorated SW piping with superior material will increase reliability of the SW system. Therefore, the possibility for an accident of a different type than previously evaluated in the Safety Analysis Report will not be created.

Calculations ME-0582, 0586 show that required flow rates to the charging pumps and IACs will be satisfied for the design basis range of SW temperatures during the temporary arrangement. However, there is a very small margin on SW flow rate to the non safety-related IACs during maximum design SW temperature during the temporary piping arrangement. To increase the margin, transfer charging pumps to final arrangement will be planned during a time period between October to May 10 when expected 0

temperature in the SW reservoir will be below 85 F. This will increase flow to IACs during summer weather conditions and allow transferring IACs to final piping arrangement during the summer weather.

00-SE-MOD-19, Rev. 1 Description DCP 00-004, Service Water (SW) Blowdown UFSAR Change FN 99-032 Procedure 0-OP-49.7 Summary The scope of the design change include the design of a SW blowdown line with a capacity of approximately 900 gpm. The existing SW discharge path (lines 24"-WS-C42-151-Q3 and 24"-WS-C43 151-Q3 to the Unit 2 circulating discharge tunnel, outfall 108) will be used.

Implementation of the proposed SW blowdown does not involve an unreviewed safety or environmental question since:

1. The probability of the SW Design Basis Accident does not increase (LOCA on one Unit with simultaneous LOOP on both Units) since SW cannot be a LOCA or LOOP initiating event. The basic functions of the SW System are not altered and SW will be provided to all accident cooling loads in accordance with the original design as described in the UFSAR. The consequences of a DBA are not increased.

2. The 30-day inventory for the SW System will be preserved. There is a small chance that in case of SW DBA the operating safety-related screen wash pump may become inoperable due to failure of corresponding diesel. In this event, SW inventory may be losing 900 gpm due to uncompensated blowdown. Operator action will be required to close one out of two MOVs (2-SW-MOV-220A or 1 SW-MOV- 120B) or manual valve 1-SW- 1351 to terminate the blowdown. Calculated allowable time for this action, based on 900 gpm blowdown rate and maximum drift, is 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br /> (calculation ME 0605) from the initiation of the event. The conservatively established time for these manual actions (closing one out of three valves) is 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> from the initiation of the event. Note, that from the standpoint of safety a blowdown flow rate of 1400 gpm is acceptable to allow for a 30 hour3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> isolation time in the event of a makeup loss.

3. The malfunction of equipment important to safety previously evaluated in the safety analysis is not increased. Three valves for isolation of the blowdown, as described above, are provided. Other equipment in the SW system is not affected. Constant alarm indication on the main control room vertical board associated with open position of valves 1-SW-MOV-120B and 2-SW-MOV-220A will be temporarily removed for the duration of the blowdown evolution. This is acceptable as it preserves the blackboard concept of alarm panel on the main control board while maintaining capability for other valves.

4. The probability of an accident or a malfunction of a different type than previously evaluated in the Safety Analysis Report is not created. Although a new flow path and manual actions are introduced, the actions, times and controls are consistent with the existing SW operations. The possibility of operator error resulting in the inadvertent opening of the 24" SW overboard valves will be eliminated by de-energizing the valves in the closed position, therefore the blowdown will be possible only through the 6" line. The operator allowable time to close one out of three valves in the blowdown path (two of them are safety-related MOVs supplied from different safety-related busses) was calculated as 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br /> after the initiation of a DBA. Note that 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> was conservatively established to close one out of three valves.

5. The margin of safety of any part of the Technical Specifications as described in the basis section will not be reduced since operation of the SW system will not be adversely affected and the 30-day cooling water supply will be preserved by maintaining the reservoir level between 314'-0" and 315'-0", more than one foot above the minimum Technical Specification SW reservoir level of 313'-0". Calculated allowable time for operator action is 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br />.

6. The discharge of the SW reservoir to Outfall 108 is currently included in the VPDES permit. This discharge has been analyzed and is an approved discharge path. Additionally, no significant change in radiological effluents is expected since the SW system does not contain fission by-products. If a RSHX tube leak were to occur concurrent with a CDA with the overboard flowpath open, procedural guidance would isolate the flowpath after receipt of a radiation alarm.

99-SE-MOD-08, Rev. 2 Summary DCP 99-001, Moisture Separator Reheater (MSR) Replacement Procedures: 2-OP- 1.3, 2-OP-3.3, 2-OP-15.2, 1-OP-26.8 Field Change #1 to DCP 99-001 Description bundles and shells)

The existing MSRs (2-MS-E-l A, -i B, -1C, -I D) will be removed in their entirety (tube raises the allowable MWe limit on the and replaced with new MSRs. Field Change #1 to DCP 99-001 main generator.

to MSR replacement, are The accidents previously considered in the Safety Analysis Report, and applicable secondary system pipe breaks. The new MSRs utilize Main Steam Main Steam Line Breaks and minor heat the high pressure turbine exhaust ateam. Although portions of the MS (MS) from the MS header to new MSRs will be system are safety-related, the MS header and supply lines to the MSR are not. The Boiler and Pressure Vessel designed, built, and tested in accordance with Section VIII, Div 1 of the ASME Accordingly, the integrity of Code, and will be installed in accordance with approved station procedures.

be adversely affected. The replacement of the the MS system piping associated with the MSRs will not or consequences of the accidents identified above.

MSRs will not increase the probability of occurrence Analysis Report, and The malfunctions of equipment related to safety, previously evaluated in the Safety Breaks. The MSRs applicable to MSR replacement, are Main Steam Trip Valve malfunction and MS Line MS system, downstream are non safety and are supplied with steam from a non safety-related portion of the the probability of occurrence of the MS Trip Valves. Therefore, replacement of the MSRs will not increase or consequences of the malfunctions identified above.

of a different type Replacement of the MSRs will not create the possibility for an accident or malfunction Safety Analysis Report. The new MSRs will perform the same than was previously evaluated in the use a portion of the MS flow to reheat the high pressure turbine exhaust function as the existing (i.e.,

existing piping connections. All existing instrumentation and control components steam), and will utilize tested in accordance will remain functional and unchanged. The new MSRs will be designed, built, and range of design with Section VIII of the ASME Boiler and Pressure Vessel Code for operation in the full higher thermal efficiency and FAC basis conditions for the MS system. With the exception of the resistance, the new MSRs are essentially a like-for-like replacement.

The MSRs and associated piping and instrumentation are not required for safe shutdown of the unit, No change accident mitigation, safe shutdown capability, or compliance with the Technical Specifications.

the associated changes in steam and to the Operating License will be required. An increase of 1OMwe, and condensate flows, will not affect the Final Environmental Statement or the ISFSI.

00-SE-OT-13, Rev. 2 Summary QA Topical Report/UFSAR Chapter 17 Change FN 2000-04B - Incorporate additional NRC comments into UFSAR/QA Topical Report change Description The purpose of the change is to reduce the length of time records are being maintained for documenting quality activities. This package incorporates the latest NRC comment into the package. In order to address the NRC concern the retention requirement for fuel is being changed from Lifetime(a)(3) to Lifetime(a)(l) plus three years after transfer of fuel. This will address the NRC interpretation of the requirements of 10 CFR 71.135, Quality Assurance Records.

The Operational QA Program change does not affect the operation or design of the plant or any system, structure or component. No accident analysis assumptions are modified or challenged by this change.

Plant equipment will not be operated in a different manner. This change is administrative in nature and redefines the record retention requirements, clarifies the definition of a QA Record, and establishes Lifetime as a record retention period. Therefore, this proposed Operational QA Program change will not:

"* Increase the probability of occurrence or consequences of any accident or malfunction of equipment important to safety previously analyzed in the SAR

"* Create an accident or malfunction of equipment of a different type than was previously evaluated in the SAR

"* Reduce the margin of safety as defined in any Technical Specification Bases.

00-SE-OT-13, Rev. 3 Summary QA Topical Report/UFSAR Chapter 17 Change FN 2000-04C - Incorporate additional NRC comments into UFSAR/QA Topical Report change and corrects a proposed misleading retention requirement in the B package.

Description This package incorporates the latest NRC comments. In order to address the NRC concern the retention requirement for fuel is being changed from Lifetime(a)(3) to Lifetime(a)(l) plus three years. This will address the NRC interpretation of the requirements of 10 CFR 71.135, Quality Assurance Records, which requires the licensee to retain records for 3 years beyond the date when the licensee last engages in the licensed activity. This package supercedes the "B" package, which contained a misleading requirement for the record retention requirements for fuel.

The Operational QA Program change does not affect the operation or design of the plant or any system, structure or component. No accident analysis assumptions are modified or challenged by this change.

Plant equipment will not be operated in a different manner. This change is administrative in nature and redefines the record retention requirements, clarifies the definition of a QA Record, and establishes Lifetime as a record retention period. Therefore, this proposed Operational QA Program change will not:

"* Increase the probability of occurrence or consequences of any accident or malfunction of equipment important to safety previously analyzed in the SAR

"* Create an accident or malfunction of equipment of a different type than was previously evaluated in the SAR

"* Reduce the margin of safety as defined in any Technical Specification Bases.

00-SE-OT-31, Rev I Description

"* Technical Specification Change Request #375

"* UFSAR Change Request FN-2000-027

"* UFSAR Change Request FN-2000-027A The current Technical Specifications requirements specify that the refueling water storage tank (RWST) and the casing cooling tank (CCT) be at a concentration between 2300 and 2400 ppm and the safety injection accumulators (SlAs) be at a concentration between 2200 and 2400 ppm. The boron concentration of the spent fuel pool (SFP) is not explicitly stated in the Technical Specifications. This change will increase the boron concentration limits in the RWST, CCT, and SFP to 2600 - 2800 ppm and to 2500 2800 for the SIAs. The boron concentration of the SFP is being increased to keep the boron concentration consistent with the refueling canal and all portions of the reactor coolant system during refueling.

Revision I corrects an oversight in UFSAR Change Request FN 2000-027 (i.e., failure to reflect revised cold-to-hot leg recirculationswitchover interval previously evaluated in O0-SE-OT-31, Revision 0). A typo in the revision number of Reference 6 (SM-415, Rev. 2) on Question 18 (supplementalpage 2D) was corrected.In addition, Revision 1 uses a revised 50.59form (June 2000). Other than these changes 00-SE OT-31, Revision 1 is identicalto 00-SE-OT-31, Revision 0.

Summary This change involves increasing the boron concentration in the refueling water storage tank (RWST),

casing cooling tank (CCT), and the spent fuel pool (SFP) from the current Technical Specification limits of 2300 - 2400 ppm to 2600 - 2800 ppm and from 2200 - 2400 ppm to 2500 - 2800 ppm for the safety injection accumulators (SIAs).

It has been the Company's outage planning philosophy to stagger outages whenever possible in order to avoid load management, logistical, and economic disadvantages associated with concurrent outages. In order to accommodate this outage planning philosophy, the fuel management plan for each unit provides for flexibility in the final end-of-cycle bumup including the use of power and RCS average temperature (Tavg) coastdowns.

While end-of-cycle coastdowns are fully evaluated from a safety analysis perspective, they represent an off-nominal operational mode that is undesirable from the standpoint of maximizing electrical generation.

Designed reload cores with increased initial core reactivity is one means to reduce the need for extended end-of-cycle coastdowns. Increased core reactivity will require higher boron concentrations than previous cycles to meet increased shutdown requirements. One of the limiting parameters for core designers is the post-LOCA sump boron concentration limit. Increasing the boron concentration in the RWST, CCT, SIAs, and SFP will remove one obstacle currently preventing longer full power cycles.

Therefore, more reactive cores will reduce the duration of T-avg and power coastdowns, resulting in more energy production. Wider control bands on boron concentration limits will also provide greater operational flexibility.

Safety, Significance The following evaluations were performed to assess the impact of the proposed Technical Specification changes:

"* Non-LOCA transients were evaluated, and it was determined that only the boron dilution event was potentially affected by the proposed increased boron concentrations.

"* The effects of increased boron concentrations in LOCA evaluations were also considered. The time to switchover from cold to hot leg recirculation for long-term cooling following a loss of coolant accident

The post-LOCA (LOCA) was analyzed to determine the impact of the increased boron concentrations.

shutdown margin.

sump boron concentration limit was recalculated to ensure adequate post-LOCA with an increased boron The post-LOCA containment sump and quench spray (QS) pH were calculated within acceptable limits.

concentrations in the RWST, CCT, and SIAs to ensure that the pH remains

• Other evaluations, such as boron solubility, equipment qualification, and RWST and boric acid storage impact tank requirements were reviewed to ensure that a higher boron concentration does not adversely the safe operation of the plant.

and SFP These evaluations revealed that increased boron concentration limits in the RWST, CCT, SIAs, analytical benefit from a reactivity management and accident mitigation standpoint.

generally provide an process Potential adverse effects in the boron dilution event are accommodated in the reload verification

1) continue to be met with (Reference 2). The pH limits specified in the Standard Review Plan (Reference from cold-to-hot leg recirculation to increased boron concentration limits. The time interval for switchover and will be implemented upon approval of the avoid boron precipitation in the vessel has been recalculated, increased limits. The increased boron concentration limits cause no adverse effects on the environmental is qualification of equipment in the containment. A detailed discussion of these safety considerations presented below.

Non-LOCA Chapter 15 Transients found to be Of the non-LOCA transients, only the results of the Boron Dilution accident analysis were boron concentrations. The adverse effect is a potentially adversely affected by the proposed increased that would become feasible with the increased RWST result of the increased RCS boron concentrations transients were either not impacted or were made less severe as boron concentration. The other non-LOCA boron concentrations. For example, an increased boron concentration in the a result of the increased Steamline Break RWST and, hence, in the safety injection system, would provide less limiting Main analysis results. The Startup of an Inactive Loop accident analysis is insensitive to the refueling boron requirements governing loop stop concentration, since this accident is precluded by Technical Specification valve operations.

Shudown The Boron Dilution event at Refuieling, Cold Shutdown, Intermediate Shutdown, and Hot lock-out of the primary grade water flow path in accordance with conditions is precluded by administrative 2 Technical Specification 3.1.1.3.2. However, the Boron Dilution at Startup and at North Anna Units 1 and concentration. The Power analyses are potentially impacted by the proposed increased RWST boron critical impact on the Startup and At Power scenarios is indirect, and is a result of the increased allowable concentration. An increased RCS RCS boron concentrations resulting from the increased RWST boron evaluations of the boron dilution event at startup and boron concentration is explicitly considered in reload the current analysis of record, the reload evaluations of the Boron at power scenarios. As required by action Dilution at Startup and at Power ensure that at least 15 minutes are available for corrective operator between positive indication of a dilution in progress and complete loss of shutdown margin.

boron As previously indicated, the proposed increased boron concentrations can result in increased critical rates during a boron dilution event. The concentrations, which would result in higher reactivity insertion of these increased reactivity insertion rates were also Departure from Nucleate Boiling (DNB) effect considered, and were determined to be easily bounded by the rod withdrawal at power analysis. Therefore, the DNB acceptance criterion for the boron dilution event continues to be met.

Large Break LOCA for both the The effect of increased boron concentrations on the LOCA transient analysis was considered is characterized by a rapid depressurization that large and small break scenarios. The large break LOCA RCS. In accordance with Appendix K, the docketed causes the generation of significant voiding in the in the North Anna LBLOCA analysis does not assume control rod insertion. As a result, heat generation by negative void reactivity. Therefore during the blowdown phase of core is reduced to decay heat levels the LBLOCA the core is shutdown and remains shutdown due to void reactivity.

The refill/reflood portion of the injection phase begins with the highly voided core and continues from downcomer refill through core reflood. During this time, void reactivity is of primary importance at the start and gradually begins to be replaced by boron as the primary source of negative reactivity. The docketed North Anna LBLOCA analysis shows that the peak clad temperature is reached prior to the time the boron becomes significant in maintaining core shutdown. In fact, boron concentrations are not modeled in peak clad temperature cases. Therefore, the increased boron concentration has no effect on the calculated results for the LBLOCA and would in fact provide a benefit if accounted for in the analysis. The proposed increase in RWST and SIA boron concentrations provides additional unmodeled conservatism.

Small Break LOCA The small break LOCA (SBLOCA) analysis falls into the category of those transients that cause safety injection actuation. The small break LOCA model assumes the insertion of control rods in the calculation of core shutdown. Consequently, the boron concentration required to achieve the level of negative reactivity necessary to assure shutdown for the small break LOCA is significantly lower than the concentration required to assure shutdown for a large break LOCA. The increase in RWST and SIA boron concentration provides additional conservatism for the small break LOCA.

Cold-to-Hot Leg Recirculation Switchover Time Following a LOCA, borated water from the RWST and accumulators enters the core region through the cold leg during the injection phase of the transient. Assuming a cold leg break, borated coolant enters the core region from the intact cold leg, down the downcomer, and into the core. Steam exits through the hot leg, and excess safety injection water spills out the break. Although the water vapor exits the core and condenses in the containment, only a small fraction of the dissolved boron is carried off in the steam. Therefore, the concentration of boron increases over time in the reactor vessel. If the boron concentration reaches the solubility limit, boron will begin to precipitate out of solution, forming a sticky paste that can block the coolant flow channels in the core. Such a condition may lead to inadequate cooling of the fuel.

If the break is in the hot leg or in the pressurizer, safety injection water will flow down the downcomer, up through the core, and out the break, thereby continuously replacing the boric acid solution in the core region. In such a situation, switchover to hot leg recirculation is not necessary. However, there is no unambiguous way to locate the pipe break from the control room, so switchover from cold leg to hot leg injection is required at a specific time for all LOCAs.

Because of the proposed boron concentration increase, the recirculation switchover time must occur sooner to avoid boron precipitation in the reactor vessel. The currently accepted boron precipitation limit is 23.5 weight percent boron, which includes a four weight percent safety margin to account for uncertainties.

With a RWST and CCT boron concentration between 2600 - 2800 ppm and a SIA boron concentration between 2500 - 2800 ppm, a 5.26 hour3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br /> switchover time has been calculated (Reference 4). For convenience, a 5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> switchover time will be implemented, replacing the 7 hour8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> time to prepare for switchover and the 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> switchover time currently in the North Anna Emergency Operating Procedures.

A potential issue was raised by Westinghouse concerning the possibility of inadvertent recriticality following switchover from cold leg to hot leg injection (Reference 9). The accumulation of boron in the reactor vessel following a large break LOCA, and prior to cold-to-hot leg switchover, results in a decrease in the sump boron concentration. Westinghouse postulates that switchover from cold leg to hot leg injection may wash out the concentrated boric acid in the core region, and replace it with the sump fluid which is depleted in boric acid. If the reduction in sump boron concentration during cold leg injection is sufficient, the cold-to-hot leg switchover may result in inadvertent re-criticality. This issue has been addressed by developing a Reload Safety Analysis Checklist (RSAC) parameter that ensures that the sump boron concentration and xenon reactivity at the time of cold-to-hot leg switchover is adequate to keep the reactor subcritical.

Post-LOCA Sump Boron Concentration Limit

Following a Small or Large Break Loss of Coolant Accident (SBLOCA or LBLOCA), fluid from various volumes accumulate in the containment sump. At North Anna, these volumes include the RWST, the chemical addition tank (CAT), the SLAs, the safety injection system piping (SI Piping), the reactor coolant system (RCS), the boron injection tank (BIT) and the CCT. All of these volumes contain boric acid solution with the exception of the CAT, which contains a sodium hydroxide solution. Depending on the magnitude of the loss of coolant accident (LOCA), some or all of the liquid contained in these volumes will be introduced to the containment, and will ultimately accumulate in the containment sump.

It is assumed in the sump boron analysis for the design basis LBLOCA, that all of the liquid in these volumes is transferred to containment.

It is necessary to have a sufficiently high boric acid concentration in the sump mixture to ensure that the reactor remains subcritical. As more reactivity is loaded into the core, increased amounts of boron are required. The post-LOCA sump boron concentration limit for an increased boron concentration of 2600 to 2800 ppm in the RWST and CCT has been recalculated and will be incorporated into the Reload Safety Analysis Checklist (RSAC) (Reference 2) upon approval of the boron concentration increase (Reference 5).

Post-LOCA Sump and Quench Spray pH Limits Limits are placed on the containment sump and QS pH because of material considerations and to reduce the evolution of iodine from the liquid. A post-LOCA sump pH range of 7.0 to 9.5 is specified in the Standard Review Plan (SRP) to avoid to onset of stress corrosion cracking (Reference 1). A pH range from 8.5 to 10.5 is specified in the SRP (Reference 1) to minimize the evolution of iodine during post-LOCA operation of the containment spray system.

The pH of the post-LOCA sump is determined by a volume-weighted average of the boric acid and sodium hydroxide concentrations from each analyzed volume. Because the data table used to interpolate the pH assumes that boric acid and sodium hydroxide concentrations are expressed as molarities (moles solute per liter), each volume's concentration (weight percent) is converted to a molarity prior to mixing the contents of the individual volumes in the sump.

The pH of the QS is calculated on the basis of the molarity and volumetric flow rate of liquid drawn from the RWST and CAT into the QS pump suction. The molarity of the RWST and CAT solutions is a simple conversion based on the weight percentage of the solute in the solution, and the specific gravity of the solution.

After consideration of the proposed increased RWST, CCT, and SIA boron concentrations, the post-LOCA containment sump and QS pH continue to meet the acceptance criteria (i.e., post-LOCA sump pH must be greater than 7.0 and less than 9.5 and the QS pH must be greater than 8.5 and less than 10.5) (Reference 6).

Boron Solubility A boron concentration of 2800 ppm does not approach the solubility limit at the temperatures of the RWST. The temperature of the RWST fluid is limited to between 40 'F and 50 'F in Technical Specification 3.5.5. Figure 6.3-18 of Reference 3 shows that a boron concentration of about 2.5 weight percent boron (-4370 ppm) remains soluble at temperatures above 32 'F (Reference 3).

Equipment Qualification Chemical spray is one of the environmental factors used to qualify the class 1E electrical equipment to assure operation when required. For the North Anna units, this environmental factor is considered for equipment inside containment experiencing a LOCA environment. There are two sources of chemical spray: quench spray and recirculation spray. The quench spray takes borated water from the RWST and a NaOH solution from the chemical addition tank (CAT). The recirculation spray system takes suction from the containment sump.

Increasing the boron concentration to 2600 - 2800 ppm in the RWST and CCT and to 2500 - 2800 ppm in the SIAs will not adversely affect the environmental qualification of equipment in the Equipment Qualification Master List (EQML). The corrosive agent in chemical spray is primarily NaOH. Increasing the boron concentration lowers the solution pH making it less corrosive (more neutral). Therefore, higher boron concentration limits are acceptable, even for those components qualified at a lower boron concentration (Reference 7).

RWST and Boric Acid Storage Tank (BAST) Volume Requirements Technical Specification Bases 3/4.1.2 requires that the boration capability of the RWST and the boric acid storage tank (BAST) be sufficient to provide a 1.77%Ak/k shutdown margin from end-of-cycle (EOC) hot full power conditions after xenon decay and cooldown to 200 'F. Furthermore, the same shutdown margin must be maintained after cooldown from 200 'F to 140 'F.

The volume requirements are calculated by determining the reactivity required to achieve cooldown to either 200 'F from HFP or to 140 'F from 200 'F. The volume required to achieve this concentration is determined by converting the required reactivity by a differential boron worth. The required reactivity is determined in a conservative fashion by adding the temperature defects, xenon reactivity, and shutdown margin. A simple mixing model is used to determine the volume of RWST and BAST volume needed to achieve the required boron concentration in the vessel (Reference 8).

As part of this evaluation, Reload Safety Analysis Checklist (RSAC) parameters have been developed in order to ensure the BAST requirements are met on a cycle to cycle basis. The revision and incorporation of RSAC parameters is included in the Technical Specification Change Action Plan.

Based on the above evaluation, the proposed changes to the RWST, CCT, SIA, and SFP boron concentration do not adversely affect the safe operation of the plant.

Transition Consideration for Use of Opposite Unit's RWST Upon increasing the boron concentration limits for the first unit, and prior to implementing the increased concentrations in the second unit, charging header cross-connect will allow flow from the opposite unit's RWST which will be at a higher or lower boron concentration than the accident unit. Accidents requiring flow from the opposite unit's RWST are outside of the design basis and therefore not formally analyzed.

However, use of the cross-connect in beyond design basis events (loss of all injection flow from the accident unit, for example) will continue to be effective (that is, water of slightly lower boron concentration but high with regard to SDM requirements is preferable to no water, for instance). Therefore no changes to the procedural guidance for RWST/charging header cross-connect is required for this change.

Summary

1. Increasing the boron concentration limits for the RWST, CCT, SIAs, and SFP will not increase the probability of occurrence of any known accident and does not adversely affect the safe operation of the plant. Appropriate design constraints were analyzed for changes to T.S. 3.1.2.7, 3.1.2.8, 3.5.1, 3.5.5, 3.6.2.2, 3.9.1, and Bases 3/4.1.2 and 3/4.9.1 and none were found to be more limiting than currently documented in the UFSAR.

2. Increased boron concentration limits for the RWST, CCT, SIAs, and SFP will not increase the consequences of any accident previously evaluated in the Safety Analysis Report. The increased boron concentration limits reduce the time to switchover from cold to hot leg recirculation, which will prevent boron precipitation in the reactor vessel following a LOCA. A reduced switchover time will be implemented in the EOPs as part of the Technical Specification Implementation Plan.

The post-LOCA sump boron concentration limit is revised to ensure adequate post-LOCA shutdown margin. The post-LOCA containment sump and quench spray (QS) pH remain within the limits specified in the Standard Review Plan. All other transients either were not impacted or were made less severe as a result of the increased boron concentrations. Therefore, accident analysis results meet all design criteria as stated in the UFSAR.

3. The proposed boron concentration increases do not add new or different equipment to the facility, nor do they significantly change the manner that installed equipment is being operated. There are no changes to the methods utilized to respond to plant transients and no alterations to the way that the plant is normally operated. The proposed UFSAR and Technical Specification changes do not alter instrumentation setpoints that initiate protective or mitigative actions. As a result, no new failure modes are being introduced.

Therefore, the possibility for an accident of a different type than was previously evaluated in the SAR is not created.

00-SE-OT-60 Rev 1 Description Technical Specification Change Request No. 376A (Supplement to TSCR 376)

UFSAR Change Request FN 2000-048 (Supersedes FN 2000-016)

TSCR 376B (Supplement to TSCR 376 and TSCR 376A)

A supplement to Technical Specification Change Request (TSCR) No. 376 (TSCR 376A) and a revised UFSAR Change Request (FN 2000-048) are needed to address an NRC request for additional information (RAI) on TSCR 376. The NRC has requested consideration of pressure and temperature measurement uncertainties in the proposed revised design basis Reactor Coolant System (RCS) Pressure/Temperature (P/T) Operating Limits, Low Temperature Overpressure Protection System (LTOPS) Setpoints, and LTOPS Enable Temperatures. The NRC has requested inclusion of instrument uncertainties in order for them to grant an exemption to the requirements of 10 CFR 50 Appendix G to permit utilization of ASME Section XI Code Case N-640 (use of the Appendix A K1, fracture toughness curve, Figure A-4200-1). This safety evaluation also supports a reduction in the Units 1 and 2 reactor vessel head bolt-up temperatures from 90'F to 60'F.

Revision I incorporates revised P/T limit curve data applicable to heatup to address a Westinghouse computer code error.

Summary PURPOSE Note to reader: Revision 1 changes are presented in bold throughout the document.

This safety evaluation supports Technical Specification Change Request 376A and 376B, which supplement TSCR 376 (2). TSCR 376 and TSCR 376A propose revisions to the Technical Specifications to implement revised design basis analyses for the North Anna Units 1 and 2 Technical Specification Reactor Coolant System (RCS) Pressure/Temperature (P/T) operating limits, Low Temperature Overpressure Protection System (LTOPS) setpoints, and the LTOPS enable temperature (Tmable). TSCR 376A addresses an NRC Request for Additional Information (RAI) requiring incorporation of margin to accommodate pressure and temperature measurement uncertainties in the P/T limits and LTOPS setpoints. TSCR 376B provides corrected RCS P/T limit curves applicable to heatup to address a Westinghouse computer code error. This safety evaluation also supports implementation of a revised reactor vessel head bolt-up temperature. Although the revised reactor vessel head bolt-up temperature does not require NRC review and approval for implementation, this change will be implemented as part of the TSCR 376A Action Plan.

DISCUSSION TSCR 376A A Technical Specification Change Request (TSCR) concerning the North Anna Units 1 and 2 RCS pressure/temperature (PIT) limits and low temperature overpressure protection system (LTOPS) setpoints was submitted to the NRC on June 22, 2000 (2). The basis for this TSCR is described in Reference (3). The objective of the submittal was to justify continued use of the existing Technical Specification P/T limits and LTOPS setpoints on the basis of a margin assessment. The margin assessment required an exemption to the requirements of 10 CFR 50 Appendix G to permit application of ASME Section XI Code Case N-640. N-640 supports use of the ASME Section XI Appendix A K1 , fracture toughness curve (Figure A-4200-1), instead of the ASME Section XI Appendix G Kia curve (Figure G-2210-1) that was employed in the development of the existing Technical Specification P/T limits and LTOPS setpoints. During a November 7, 2000 teleconference, NRC staff indicated that application of margin to accommodate pressure and temperature measurement uncertainties would be required in order for this exemption request to be granted. Therefore, it became necessary to supplement the Reference (2) submittal with an evaluation of the effects of incorporating pressure and temperature measurement uncertainties into the proposed design basis P/T limits.

As demonstrated in Reference (1), the existing Technical Specification LTOPS setpoints remain conservative and valid to 32.3 EFPY and 34.3 EFPY for North Anna Units 1 and 2, respectively, after application of pressure and temperature measurement uncertainties to the LTOPS design basis P/T limit curve. However, the

conservatism of the existing Technical Specification P/T limits could not be confirmed. Therefore, the proposed revised design basis P/T limits, including allowances for pressure and temperature measurement uncertainty, must be incorporated into the Technical Specifications and supporting operating procedures.

TSCR 376B that their During a teleconference on Monday, February 26, 2001, Westinghouse informed the NRC had an error that adversely affected the Reactor computer code used to calculate RCS P/T limits (P/T) limits used in the North Anna Units 1 and 2 RCS Coolant System (RCS) pressure/temperature Change Request (TSCR) (2) (10). The Westinghouse computer P/T limits Technical Specification and code OPERLIM Version 5.0 calculates RCS P/T limits by calculating combined pressure The code was thermal stresses in the reactor vessel during normal operation heatup and cooldown.

modified to incorporate changes associated with the 1996 Addenda to ASME Section XI Appendix G, (1/4-T) and including separate membrane (i.e., "pressure") stress formulations for the 1/4-thickness conditions, it is possible for the location 3/4-thickness (3/4-T) reactor vessel locations. During heatup 3/4-T location to the 1/4-T location. Although the of limiting combined stresses to change from the intended to account for this situation, the computer code modifications to OPERLIM 5.0 were that which modifications failed to include logic to switch the membrane stress formulation from to that which applies at the 1/4-T location when the location of limiting applies at the 3/4-T location error is a slight stresses changes from the 3/4-T location to the 1/4-T location. The net effect of this generated for the TSCR non-conservatism in the high temperature region of the heatup curves described above.

Units 1 Westinghouse has provided corrected heatup P/T operating limits (14) for the North Anna request. The revised heatup curves have been modified to and 2 Technical Specification change and pressure measurement instrument uncertainties, and to include allowances for temperature the point of account for the pressure difference between the point of measurement (RCS hot leg) and revised and modified interest (reactor vessel beltline) (15). (See Appendix B of Reference (15).) The curves are being incorporated into an NRC submittal that supplements TSCR 376 and 376A.

to the The LTOPS setpoint analysis presented to the NRC in Reference (16) is unaffected by the changes uses the isothermal P/T limit curve as a design limit.

heatup curves, since the LTOPS setpoint analysis analysis presented in Reference 1161 is unaffected by the Similarly, the LTOPS enable temperature since the proposed LTOPS enable temperature is a function of the design changes to the heatup curves, proposed value of RTNDT only, which is unaffected by the changes to the heatup curves. Only the by the changes described Technical Specification RCS P/T limit curves applicable to heatup are affected curves herein. Therefore, with the exception of the previously proposed Technical Specification heatup 121 and supplemented in Reference [161 presented in Reference 1161, the TSCR presented in Reference remains valid.

Revised Reactor Vessel Minimum Bolt-Up Temperature The current design and licensing basis composite RCS pressure/temperature operator curves for North Anna This bolt-up Units 1 and 2 [4] [5] include a minimum reactor vessel head bolt-up temperature of 90'F.

reactor vessel flange RTNDT value, including temperature was designed to conservatively bound the highest uncertainty. ASME Section HI Paragraph G-2222(c) allowance for the effects of temperature measurement region provides recommendations for the bolt-up temperature, indicating that the temperature of the stressed flanges) must be greater than the limiting RTNDT value of the stressed (i.e., the vessel and closure head vessel materials. As documented in UFSAR Tables 5.2-26 and 5.2-27, and in Reference (6), the highest reactor materials).

flange or closure head flange RTNDT value for the North Anna Units 1 and 2 is -22°F (vessel flange As documented in Reference (7), Westinghouse developed a generic minimum bolt-up temperature of 60'F, (a) the based on an evaluation of available flange RTNDT values for Westinghouse-designed plants. Because RTNDT values for the North Anna Units 1 and 2 vessel flanges and closure head flanges are all well below 40'F, temperature measurement uncertainty is less than 20'F (8), a revised reactor vessel and (b) the RCS wide range

bolt-up temperature of 60°F is being implemented by the attached safety evaluation. The revised vessel bolt-up temperature will be implemented as part of the Action Plan for TSCR 376A.

CONCLUSIONS the analysis bases for the Changes to North Anna Units 1 and 2 Technical Specification P/T limits, and to These changes include:

Technical Specification LTOPS setpoints and Tenable values are proposed.

P/T limits, including the

1. Replacement of the current North Anna Units 1 and 2 Technical Specification constitutes the design limit for the LTOPS setpoint isothermal (steady-state) P/T limit curve that documented in Appendix F of Reference (1) and the heatup analysis, with the cooldown curves B of Reference (15). The proposed curves have been modified to curves documented in Appendix pressure difference account for RCS pressure and temperature measurement uncertainty, and for the (reactor vessel beltline).

between the point of measurement (RCS hot leg) and the point of interest and the associated

2. Replacement of the current design and licensing basis RTNDT calculations, vessel neutron fluence, with those previously relationship of cumulative core burnup to reactor submitted in References (9) and (10), and values with a plant

3. Modification of the analysis basis for the Technical Specification LTOPS Tenable analysis methodology that supports ASME Section XI Code Case N specific implementation of the 514 (12).

Implementation of these proposed revised analysis bases requires:

application of ASME

1. An exemption from the requirements of 10 CFR 50 Appendix G to permit Section XI Code Case N-640 [11] to North Anna Units 1 and 2, and application of

2. An exemption from the requirements of 10 CFR 50 Appendix G to permit plant-specific supports ASME Section XI Code Case N-514 [12] to North Anna Units the analysis methodology that l and 2.

the following After consideration of the information provided herein, and in the Reference (2) submittal, conclusions are made:

setpoints, enabling

1. The existing North Anna Units 1 and 2 Technical Specification LTOPS requirements ensure that the RCS pressure during design temperatures, and component operability revised LTOPS basis low temperature mass and heat addition transients will not exceed the proposed design basis P/T limit curve.

basis reactor vessel

2. The proposed revised Technical Specification P/T limits ensure that the design for heatup rates up to 60 °F/hr, and for flaw will not propagate under conditions of normal operation cooldown rates up to 100°F/hr.

34.3 EFPY for North These conclusions remain valid for cumulative core burnups up to 32.3 EFPY and Anna Units 1 and 2, respectively.

head bolt-up temperatures The proposed changes to the North Anna Units 1 and 2 minimum reactor vessel ensures that ASME Code requirements continue to be met.

UNREVIEWED SAFETY QUESTION DETERMINATION previously analyzed for the There is no increased probability of occurrence or consequences of accidents Units 1 and 2 Technical proposed changes. The proposed revised analysis bases for the North Anna operation of any system Specification LTOPS setpoints and LTOPS enable temperatures do not affect the the proposed revised or component. No changes to any systems or components are required to implement the existing North Anna Units 1 and 2 LTOPS analysis bases. The revised analysis bases demonstrate that and component operability requirements Technical Specification LTOPS setpoints, enabling temperatures, design basis low temperature mass and heat addition are adequate to ensure that the RCS pressure during LTOPS design basis P/T limit curve. The proposed revised transients will not exceed the proposed revised that the design basis reactor vessel flaw will not propagate under Technical Specification P/T limits ensure

up to 100F/hr.

conditions of normal operation for heatup rates up to 60°F/hr, and for cooldown rates of occurrence and Therefore, the design basis requirements continue to be met, and the probability consequences of accidents previously evaluated are not increased.

than previously identified in the There is no creation of the possibility for an accident of a different type The revised analysis only changes the stress intensity Safety Analysis Report as a result of these changes.

pressure/temperature operating limits (i.e., utilizes Klc formulation used in the development of RCS instead of Ki a), and replaces the generic ASME Section XI LTOPS enable temperature formulation (i.e.,

enable temperature analysis based on a reactor vessel RTNDT + 50'F) with a plant-specific LTOPS RCS P/T limits are not substantially different, in terms of allowable fracture criterion. The proposed Specifications. None of operating pressures and temperatures, than the existing P/T limits in the Technical no possibility exists for the modified analysis parameters are new or unique accident initiators. Therefore, Safety Analysis Report.

creating an accident of a different type than previously analyzed in the 0 (3) and ET-NAF-2000-0136 There is no reduction in the margin of safety. ET-NAF-2000-0031 Revision revised analysis methods provide an acceptable margin of Revision 1 (13) demonstrate that the proposed temperatures continue to meet safety. Because the proposed revised minimum reactor vessel head bolt-up governing reactor vessel head ASME Code requirements, the margin of safety inherent in the procedures bolt-up is not reduced.

99-SE-PROC-22 Rev 1 Description 1-OP-10.2, Rev. 5, P1 l-OP-10.2, Rev. 8, PI A temporary modification is to be added to procedure 1-OP-10.2 as an alternate method for loop stop valve leakage recovery. This procedure will allow the installation of a hose(s), an air pump and a check valve(s) between the suction of the PDTT pump and a LMC valve on a line going to the RP pumps.

Summary A temporary modification is to be added to procedure l-OP-10.2 as an alternate method for loop stop valve leakage recovery. This procedure will allow the installation of a hose(s), an air pump and a check valve(s) between the suction of the PDTT pump and a LMC valve on a line going to the RP pumps.

The temporary modification will be leak checked after installation. Failure of the hose would result in water from the PDTT being pumped onto the containment floor until the leak is terminated. The Loop Stop Valves will be closed during the period that this temporary modification is installed which will limit any leakage to the PDTT. Water from the RP system will be preserved by the check valve(s) that is to be installed near where this temporary modification ties into the RP system. Failure of the check valve(s) will cause a reduction in Refueling Cavity and Spent Fuel Pit level with the Spent Fuel Pit low level alarm. The failure can be quickly terminated by closing the associated LMC(s) valve. Configuration of the jumper prevents it from being able to cause a Loss of RHR condition due to air entrainment. Therefore, implemetation of this TM will not increase the probability of occurrence of an accident or malfunction of equipment previously analyzed.

Failure of the TM will not affect equipment and systems used to respond to the considered accidents. The ability to provide makeup to the RCS and cavity are not reduced by implementing this TM. Implemetation of this TM has no effect on systems or equipment required to provide backup cooling to the reactor vessel or spent fuel pit. Therefore, implementation of this TM will not increase the consequences of an accident or malfunction of equipment previously analyzed.

Configuration of the jumper prevents it from being able to create a Loss of RHR condition due to air entrainment of RHR pumps or loss of vessel level. Implementation of this jumper has no effect on equipment required for the stable maintenance of reactor vessel or spent fuel pit level and temperature. Therefore, implementation of this TM will not create the possibility of an accident or malfunction of equipment not previously analyzed.

Implementation of this jumper has no effect on the basis section of the Tech Specs. Therefore, the margin of safety as defined in the bases to the Tech Specs is not reduced.

For these reasons, an Unreviewed Safety Question does not exist.

00-SE-TM-03 Rev 1 Description Temporary Modification TM-N 1-1681 Due to corrosion, the wall thickness of the bottom head of the Service Water Air Compressor Receiver Tank was found to be less than the code allowable for the 150 psig design pressure rating of the air receiver. The maximum allowable pressure in the vessel for the minimum wall thickness found during UT was calculated in accordance with ASME Section VIII. To prevent overpressurizing the vessel, a new relief valve with a relief setpoint of 115 psig will be installed.

Summary The design Service Water Air Compressor Receiver Tank relief valve has a setpoint of 150 psig which is the same as the rated design pressure of the tank as stated in UFSAR Table 9.2-4. The existing relief valve has a setpoint of 118 psi as evaluated by 00-SE-TM-03. Due to further wall thinning, a lower allowed pressure is needed until the tank can be replaced. The new relief valve setpoint will be 115 psig. This value allows for any projected additional wall thinning that may occur between now and the scheduled date of replacement for the tank. Section 9.2.1.2.4 of the UFSAR states that the SW Air Compressors operate to provide 100 psig air to the receiver tank where it is stored for use by the traveling water screen differential level control system and the SW Reservoir level indicating and alarm system. One compressor starts when the air receiver tank pressure drops to 75 psig and the other starts when the receiver pressure drops to 50 psig. The System Engineer has indicated that the lead compressor actually operates between 75 and 90 psig and the maximum pressure that the compressors provide is 100 psig. Installation of a relief valve with a setpoint of 115 psig will therefore not affect the operation of the SW Air System. The relief valve will be the same size as the former relief valve and have the same relieving capacity. The only difference in the valves will be the spring that controls the relief setpoint of the valve, therefore seismic qualification is not a concern. The relief valve relieves to the atmosphere in the SWPH.

Installation of a relief valve with a lower setpoint will protect the air receiver from possible damage due to overpressurization and will also prevent injury of station personnel. Operation of the SW Air System will be unaffected by the lower relief valve setpoint since the maximum operating pressure of the system is still approximately 15 psig less than the new setpoint. The new setpoint of 115 psig will be less than the ASME VIII code allowable pressure based on the minimum wall thickness reading obtained by UT examination.

Based on the above discussion, an unreviewed safety question does not exist for this temporary modification.