ML030280542

Response to a Request for Additional Information, License Basis Document Change Request 2-1-02 Limiting Safety System Settings & Instrumentation

ML030280542
Person / Time
Site:	Millstone
Issue date:	01/16/2003
From:	Price J Dominion Nuclear Connecticut
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
B18807
Download: ML030280542 (26)

Text

Dominion Nuclear Connecticut, Inc.

"MillstonePower Station Rope Ferry Road Waterford, CT 06385 JAN 16 2003 Docket No. 50-336 B18807 RE: 10 CFR 50.90 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555:

Millstone Power. Station, Unit No. 2 Response'to a Request for Additional Information License B1a'sis.pocumeJt Change Request 2-1-02 Limitinq'Safety System ettinqs and Instrumentation In a letter dated May 7, 2002,0') Dominion Nuclear Connecticut, Inc. (DNC) proposed changes to the Millstone Unit No. 2 Technical Specifications relating to the facility's limiting safety systems settings and instrumentation technical specifications. On November 8, 2002,(2) a request for additional information (RAI), which contains ten (10) questions, was received from the Nuclear Regulatory Commission (NRC) in regards to the DNC May 7, 2002, license amendment request.

These ten (10) questions were discussed in a December 19, 2002, conference call with the NRC. Attachment 1 provides the DNC response to the November 8, 2002, RAI. provides the revised marked up pages associated with this RAI response. provides the revised retyped pages reflecting the proposed changes associated with this RAI response.

The additional information provided in this letter will not affect the conclusions of the Safety Summary and Significant Hazards Consideration discussions provided in the DNC May 7, 2002, submittal.

There are no regulatory commitments contained within this letter.

(1) J. Alan Price to U.S. NRC, "Millstone Nuclear Power Station, Unit No. 2, License Basis Document Change Request (LBDCR) 2-1-02, Limiting Safety System Settings and Instrumentation," dated May 7, 2002.

(2) Richard B. Ennis, U.S NRC, to J. A. Price, "Request for Additional Information, Limiting Safety System Settings and Instrumentation, Millstone Power Station, Unit No. 2 (TAC No MB5008)," dated November 8, 2002.

AVoo

U.S. Nuclear Regulatory Commission B18807/Page 2 If you should have any questions on the above, please contact Mr. Ravi Joshi at (860) 440-2080.

Very truly yours, DOMINION NUCLEAR CONNECTICUT, INC.

it J.

Si ice President - Millstone Sworn to and subscribed before me this day of ' t-..w.%N0 2003 Notary PYKic My Commission expires WM. E. BROWN v-Onm TiiBLIC MY COMMISSION EXPIRES MAR. 31,2006 Attachments (3) cc: H. J. Miller, Region I Administrator R. B. Ennis, NRC Senior Project Manager, Millstone Unit No. 2 Millstone Senior Resident Inspector Director Bureau of Air Management Monitoring and Radiation Division Department of Environmental Protection 79 Elm Street Hartford, CT 06106-5127

Docket Nos. 50-336 B18807 Attachment 1 Millstone Power Station, Unit No. 2 Response to a Request for Additional Information License Basis Document Change Request 2-1-02 Limiting Safety System Settings and Instrumentation

A I U.S. Nuclear Regulatory Commission B18807/Attachment 1/Page 1 Millstone Power Station, Unit No. 2 Response to a Request for Additional Information License Basis Document Change Request 2-1-02 Limiting Safety System Settings and Instrumentation Question 1: TS Change Nos. 1, 5, and 10 The proposed changes would delete the current TS requirements associated with the Reactor Coolant Pump (RCP) underspeed trip.

Although the underspeed trip is not credited in the accident analyses (reference Final Safety Analysis Report (FSAR) Section 14.3.1.6), FSAR Section 7.2.3.3.1 states that the trip initiation ensures rapid protection of the core against Departure from Nucleate Boiling (DNB) when there is a loss of two or more RCPs. As indicated by a letter to the NRC from the then-licensee (Northeast Utilities) dated November 8, 1978, an NRC meeting summary dated January 3, 1979 (for a meeting held on November 21, 1978), MP2 Amendment No. 52 dated May 12, 1979, and Licensee Event Report 99-006-00 dated March 30, 1999, the addition of the RCP underspeed TS trip function was part of the changes deemed necessary to justify an increase in the MP2 licensed maximum power level from 2560 MWt to 2700 MWt.

Since the addition of the TSs associatedwith the RCP underspeed trip (In Amendment No. 52) was part of the basis for the current licensed maximum power level, provide justification for deleting the current TSs with respect to the requirements of 10 CFR 50.36(b) which states:

"Each license authorizing operation of a production or utilization facility of a type described in §50.21 or §50.22 will include technical specifications.

The technical specifications will be derived from the analyses and evaluation included in the safety analysis report, and amendments thereto, submitted pursuant to §50.34. The Commission may include such additional technical specifications as the Commission finds appropriate."(emphasis added)

The justification should include discussion of why safe operation of the facility will not be adversely impacted and address how the TSs that are retained will continue to provide appropriatelimits and remedial measures sufficient to ensure adequate protection is maintained.

Response: The following discussion provides a justification for the deletion of the RCP underspeed trip and show why safe operation of the facility will not be adversely impacted by the proposed change.

U.S. Nuclear Regulatory Commission B18807/Attachment 1/Page 2 The RCP underspeed trip was added to Millstone Unit No. 2 to support Cycle 3 operation with an increased licensed maximum power level from 2560 to 2700 MWt. As was described in the safety evaluation for License Amendment Number 52,(3) the RCP underspeed trip was necessary to provide protection for the Four RCP Loss of Forced Reactor Coolant Flow Event. For Cycle 3 through Cycle 9 operation, the RCP underspeed trip was credited to provide core protection for the Four RCP Loss of Forced Reactor Coolant Flow Event. For Cycle 10 operation, Millstone Unit No. 2 first proposed the use of fuel designed and fabricated by Advanced Nuclear Fuels (ANF) (currently Framatome ANP). As part of the change in fuel vendors, changes were required to the facility accident analyses.

On October 28, 1988,(4) Northeast Utilities submitted the revised Cycle 10 Analysis of Chapter 15 Events (Chapter 14 of the Millstone Unit No. 2 FSAR). On March 20, 1989,(5) the NRC issued Amendment No. 139 to the Millstone Unit No. 2 operating license which authorized the use of fuel designed and fabricated by Advanced Nuclear Fuels Corporation. As stated in Section 2.5.5 of the NRC's Safety Evaluation for this amendment, the NRC staff accepted the ANF analysis for the Forced Reactor Coolant Flow Event, which no longer credited the RCP underspeed trip. The revised Four RCP Loss of Forced Reactor Coolant Flow Event analyses credited the Reactor Coolant Flow Low Trip for accident mitigation. For Cycle 10 operation through the current operating cycle, the RCP underspeed trip is not credited to mitigate any FSAR Chapter 14 analyzed event.

Licensee Event Report 99-006-00(6) identified that the RCP underspeed trip provides core protection to prevent DNB should a four RCP loss of flow occur. Licensee Event Report 99-006-00 also states that no credit is taken for the RCP underspeed trip for the FSAR Section 14.3 Loss of Forced Reactor Coolant Flow Event, or any other analyzed accident.

Consistent with the requirements of 10 CFR 50.36, DNC has proposed to eliminate the RCP Underspeed Trip from the Millstone Unit No. 2 Technical Specifications since this functional unit is not credited in the (3) Robert W. Reid, U.S. NRC, to W.G. Counsil, "Amendment No. 52 to Facility Operating License DPR-65, Millstone Nuclear Power Station, Unit No. 2," dated May 12, 1979.

(4) E. J Mroczka to U.S. NRC, "Millstone Nuclear Power Station, Unit No. 2, Cycle 10 Analysis of Chapter 15 Events," dated October 28, 1988.

(5) Guy S. Vissing, U.S. NRC, to Edward J. Mroczka, "Amendment No 139 to Facility Operating License DPR-65, Millstone Nuclear Power Station, Unit No. 2," dated March 20, 1989.

(6) Licensee Event Report 99-006-00, "Failure to Satisfy Reactor Coolant Pump Underspeed Sensing Circuit Response Time Technical Specifications Surveillance Requirement 4.3 1.1 3," dated March 30, 1999

U.S. Nuclear Regulatory Commission B18807/Attachment 1/Page 3 facility accident analysis. As noted in Item 5 of Attachment 1 to our May 7, 2002, submittal, DNC has stated its intent to retain the design features associated with the RCP pump underspeed trip functional unit, including administrative control and verification of its functionality. DNC considers that retention of this functional unit within the facility technical specifications as not having an impact on safe operation of the facility. As noted in FSAR Section 14.3.1.7, the reactor scram on RCS low flow provides sufficient protection such that the DNB Ratio limits are not exceeded.

FSAR Section 7.2.3.3.1 states that Reactor Coolant Pump Underspeed trip initiation ensures rapid protection of the core against DNB when there is a loss of two or more RCPs. DNC has developed a change to the Millstone Unit No. 2 FSAR which removes the discussion in FSAR Section 7.2.3.3.1 relating to rapid protection of the core against DNB. This change to the facility FSAR will be implemented concurrent with the proposed license amendment discussed herein. Discussion of the Reactor Coolant Pump Underspeed Trip will also be removed from the Millstone Unit No. 2 FSAR Chapter 1, Appendix 1A, General Design Criteria 13 and 20 discussions, as well as from the Chapter 14 discussion of the Decrease in Reactor Coolant System Flow transient (Section 14.3.1.3).

Question 2: TS Change No. 2 Provide information regarding the operation of the "Wide Range Logarithmic Neutron Flux Monitor - Shutdown" functional unit with respect to its RPS trip function in order to explain why it does not have a trip setpoint or allowable value per the proposed changes to TS 2.2.1, Table 2.2-1.

Response: The wide range logarithmic channels are designed to provide the operator with a measure of the neutron flux level at the detector assembly and a measure of the rate of change of neutron flux level from source level (shutdown) to 200% of full power reactor operation.

The wide-range logarithmic channels provide:

a) power level and startup rate indication, b) a signal to the enabling circuitry of the Reactor Protection System (RPS) Zero Power Mode Bypass function, and c) a signal to the circuitry in the Control Element Assembly (CEA)

Position Display System that blocks the CEA motion inhibit signals when reactor power is less than 10 E-4% power.

U.S. Nuclear Regulatory Commission B18807/Attachment 1/Page 4 Although this functional unit is being added to Table 2.2-1, "Reactor Protection Instrumentation Trip Setpoint Limits," it does not trip the reactor or actuate any equipment. Therefore, a trip setpoint or allowable value has not been proposed. The addition of this functional unit to Table 2.2-1 will make Table 2.2-1 consistent with Tables 3.3-1 and 4.3-1.

Question 3: TS Change Nos. 6 and 7 The proposed revision to TS 3.3.1.1, Table 3.3-1 to include new functional units, Item 13 (RPS Logic Matrices) and Item 14 (RPS Logic Matrix Relays) is not consistent with Standard Technical Specification (STS)

NUREG-0212 as stated in the applicationor with STS NUREG-1432. The staff notes that NUREG-1432 is the acceptable model TSs for Combustion Engineering (CE) plants (analog and digital instrumentation designs). The staff will accept the NUREG-1432 model TSs for MP2 with an appropriate justification for deviations from the STS requirements based on the MP2 design and on an established safety basis for operation under new requirements that result from the proposed changes Therefore, provide a safety analysis discussion for proposed Items 13 and 14 in TS Table 3.3-1 with respect to Limiting Condition for Operation (LCO) operability requirements, applicabilityrequirements, and the action requirementlimits including the 48-hour repairallowed outage time (AOT) and the channel bypass allowance for surveillance testing. Show that the proposed TSs provide appropriate operational limits and are consistent with the accepted MP2 design basis and the precedents for the TSs as provided by NUREG-1432.

Response: The following discussion shows that the proposed changes to items 13 and 14 of Specification 3.3.1.1, Table 3.3-1 provide appropriate operational limits, and are consistent with the Millstone Unit No. 2 design basis.

Current Technical Specification (CTS) 3.3.1.1 includes Reactor Protection System (RPS) manual trip, RPS initiation logic, matrix logic and reactor trip circuit breakers (RTCBs). As described in our submittal dated May 7, 2002, (page 2 of Attachment 1), four independent measurement channels normally monitor each plant parameter which can initiate a reactor trip. Individual channel trips occur when the measurement channel reaches a preselected value. The channel trips are combined into six (6) two-out-of-two logic matrices (as identified in proposed functional unit 13 of Table 3.3-1). Each two-out-of-two logic matrix provides trip signals to four one-out-of-six logic units (matrix relays), each of which causes a trip of the RTCB in the associated alternating current (AC) power supply. Therefore, total number of channels, minimum

4-U.S. Nuclear Regulatory Commission B18807/Attachment 1/Page 5 number of channels, and number of channels required to trip included in the proposed change (i.e. items 13 and 14 of Table 3.3-1) are consistent with the Millstone Unit No. 2 design. The applicability requirement specified for items 13 and 14 are also consistent with NUREG-0212, Revision 2, (functional unit 12 of Table 3.3-1).(')

Revision 2 of NUREG-0212, Specification 3.3.1.1 for the RPS logic, Action 4 requires that the unit be placed in HOT STANDBY condition within six (6) hours with the number of channels OPERABLE less than minimum channels OPERABLE requirements. The proposed Action for proposed functional unit 14 would require that the unit be placed in HOT STANDBY condition within six (6) hours with number of channels OPERABLE less than minimum channel OPERABLE requirements.

Therefore, the proposed changes applicable to functional unit 14 are appropriate and consistent with the precedents of NUREG-0212, Revision 2.

CTS 3.3.1.1 does not contain a specific action and associated restoration time, or allowed outage time, for the RPS Logic when one or more channels are inoperable. The proposed Action for proposed functional unit 13, Reactor Protection System Logic Matrices, would allow 48-hours to restore the channel to OPERABLE status. The 48-hour allowed outage time is appropriate because it is unlikely that a second matrix logic would fail within a 48-hour period. This allowed outage time is based on operating experience, which has demonstrated that a random failure of a second channel occurring during the 48-hour period is a low probability event. The allowed outage time of 48-hours provides the operator time to take appropriate actions and still ensures that any risk involved in operating with a failed channel is acceptable. Operating experience has shown that allowing 48-hours with one channel inoperable, the remaining system logic (channels to trip) is still capable of performing its safety function. The proposed allowed outage time provides for sufficient time to assess the nature of inoperability for the affected component(s), including determination and completion of any necessary repairs, thereby avoiding an unnecessary plant transient (reactor shutdown). Additionally, the proposed allowed outage time is consistent with the allowed outage time specified in NUREG-1432(8 ) for the RPS Logic (LCO 3.3.3, Action A.1). If the RPS Logic Matrix cannot be restored to service within 48-hours, action must be taken to bring the unit to HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. A (7) NUREG-0212, "Standard Technical Specifications for Combustion Engineering Pressurized Water Reactors," Rev. 2, dated Fall 1980.

(5) NUREG-1432, "Standard Technical Specifications, Combustion Engineering Plants," Rev.

2, dated April 2001.

U.S. Nuclear Regulatory Commission B18807/Attachment 1/Page 6 completion time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach the required MODE from full power conditions in an orderly manner and without challenging plant systems and to open RTCBs.

NUREG-0212, Revision 2, Technical Specification 3.3.1, Table 3.3-1, Action 4, allows for the Reactor Protection System Logic to be bypassed for up to one (1) hour for surveillance testing per Specification 4.3.1.1. In this case, the redundant set of RTCBs will provide the necessary protection. If a single matrix power supply or vital bus failure has opened two sets of RTCBs, Manual Trip and RTCB testing on the remaining breakers cannot be performed without causing a trip. The channel bypass allowance for surveillance testing of one (1) hour is also appropriate since it is unlikely that a second logic matrix would fail within this time frame.

Proposed Millstone Unit No. 2 Table 3.3-1, Actions 5 and 6 are consistent with this guidance in that the RPS Logic and Reactor Trip Breakers are allowed to be bypassed for up to one (1) hour for surveillance testing.

Additionally, as noted in our May 7, 2002, submittal, the one (1) hour allowance for surveillance testing is consistent with NUREG-0212, Revision 2, (Table 3.3-1, Action Statement 4).

Question 4: TS Change No. 8 NUREG-0212 used "channels"requirements in Table 3.3-1 and the action requirement allowance includes a 1-hour channel bypass for surveillance testing, but the functional units in the NUREG TSs apply to digital instrumentation CE plant design. NUREG-1432 TSs for analog plants do permit a 1-hour surveillance test bypass. Provide discussion for Item 15 (Reactor Trip Breakers), TS Table 3.3-1 with respect to LCO operability requirements, applicabilityrequirements, and the action requirement limits including the channel bypass allowance for surveillance testing. Show that the proposed TS provides appropriate operational limits and is consistent with the accepted MP2 design basis.

Response: The following discussion shows that the proposed changes to Table 3.3-1, functional unit 15, for the Reactor Trip Breakers provide appropriate operational limits and are consistent with the Millstone Unit No. 2 design basis.

Revision 2 of NUREG-0212, was issued on October 17, 1980. It is DNC's understanding that the requirements of NUREG-0212, Revision 2, are based on analog RPSs. The Millstone Unit No. 2 RPS Logic consists of both matrix and initiation logic and employs a scheme that provides a reactor trip when bistables in any two out of the four channels sense the

.4 1 U.S. Nuclear Regulatory Commission B18807/Attachment 1/Page 7 same input parameter trip. This is called a two-out-of-four trip logic.

Bistable relay contact outputs from the four channels are configured into six logic matrices. Each logic matrix checks for a coincident trip in the same parameter in two bistable channels. The matrices are designated the AB, AC, AD, BC, BD, and CD matrices to reflect the bistable channels being monitored. When a coincidence is detected, a parameter trip in two of the four (A, B, C, and D) measurement channels, one logic matrix is satisfied and the four (4) matrix relays for the affected logic matrix de energize. The matrix relay contacts are arranged into trip paths, with each matrix relay opening contacts in one of the four trip paths. Millstone Unit No. 2 Final Safety Analysis Report (FSAR) Figure 7.2-1 provides a simplified block diagram of the RPS Logic.

Each RPS trip path provides power to one of the four normally energized Reactor Trip Circuit Breaker (RTCB) control relays (K1, K2, K3, and K4).

The trip paths thus each have six contacts in series, one from each matrix, and perform a logical OR function, opening all the RTCBs if any one or more of the six logic matrices indicate a coincidence condition.

As noted in Insert H to Page B 3/4 3-1 of the DNC May 7, 2002, submittal, the reactor trip switchgear consists of eight reactor trip circuit breakers, which are operated in four sets of two breakers (four channels). Each of the four trip legs consists of two reactor trip circuit breakers in series. The two reactor trip circuit breakers within a trip leg are actuated by separate initiation circuits. For example, if a breaker receives an open signal in trip leg A, an identical breaker in trip leg B will also receive an open signal.

This arrangement ensures that power is interrupted to both Control Element Drive Mechanism buses, thus preventing a trip of only half of the control element assemblies (a half trip). Any one inoperable breaker in a channel will make the entire channel inoperable.

Three (3) RTCB control relays must de-energize for the shutdown and regulating group Control Element Drive Mechanism (CEDM) buses to de energize. If the right combination of two (2) RTCB control relays (K1 and K2, or K3 and K4) were to remain energized (malfunction) upon receipt of a trip signal, the shutdown and regulating group CEDM buses would remain energized, and a full reactor trip would not occur (potential half trip). Therefore, three (3) RTCB control relays, and the resultant three (3) channels of RTCBs (two breakers per channel), must receive a trip signal and open to ensure a reactor trip will occur.

CTS 3.3.1.1, Table 4.3-1, Functional unit 14 requires that a monthly channel functional test be performed while operating in MODES 1, 2, and

• with "" being defined as "with reactor trip breakers closed." However,

U.S. Nuclear Regulatory Commission B18807/Attachment 1/Page 8 CTS Table 3.3-1 does not list "Reactor Trip Breakers" as a specific function. The purpose of the proposed change is to make Table 3.3-1 consistent with Table 4.3-1 by using the identical applicability requirements that currently exists in Table 4.3-1 for the Reactor Trip Breakers. The proposed applicable modes requires that the RTCBs be OPERABLE whenever the protective system breakers are in the closed position, including operation in Modes 1 and 2. With the protective system breakers open, a Reactor Control Element is incapable of withdrawal, and the RTCBs are not credited with performing any function.

In summary, the proposed changes provide appropriate operational limits and are consistent with the Millstone Unit No. 2 design basis.

Question 5: TS Change No. 11 Similar to the discussion in Question 3 for TS Changes 6 and 7, the proposed changes to TS 3.3.1.1, Table 4.3-1, Items 13 and 14, are not consistent with NUREG-0212 (i.e., NUREG-0212 does not show the RPS Logic as consisting of matrices and matrix relays). NUREG-1432 is the acceptable model TS for CE plants (analog and digital instrumentation designs). Compare the MP2 design to NUREG-1432 and justify any surveillance requirement differences, including changes to surveillance applicability changes to include mode "*"(i.e., whenever the reactor trip circuit breakers (RTCBS) are closed).

Response: As stated in the response to Question 3, CTS 3.3.1.1, Tables 3.3-1 and 4.3-1 do not specifically list the RPS Logic Matrices and Logic Matrix Relays. CTS Table 4.3-1, functional unit 13, requires a channel functional test (CFT) to be performed for the RPS logic (which includes Logic Matrices and Logic Matrix Relays) in MODES 1 and 2. The RPS logic was split into two separate functional units (RPS Logic Matrices and Logic Matrix Relays) to facilitate better understanding of the OPERABILITY requirements for the RPS Logic (see proposed TS 3.3.1.1, Table 3.3-1, items 13 and 14). As discussed in the responses to Question 3, proposed items 13 and 14 are consistent with the existing Millstone Unit No. 2 design.

Proposed items 13 and 14 are also consistent with the Calvert Cliffs Unit No. 1 Technical Specification Table 3.3-1, functional units 12 and 13 (Amendment No. 169 to TS pages 3/4 3-3 and 3/4 3-5), as they existed prior to the conversion of the Calvert Cliffs Unit No. 1 Technical Specifications to the Improved Standard Technical Specifications format (NUREG-1432, Revision 1), except for one more restrictive deviation.

The action requirement (proposed Action 6) for proposed functional unit 15 does not provide for a 48-hour restoration time before commencing

U.S. Nuclear Regulatory Commission B18807/Attachment 1/Page 9 reactor shutdown, given the significance of a failed Reactor Protection System Logic Matrix Relay has on the probability of an inadvertant reactor trip. Proposed functional unit 15 requires immediate action be taken to commence reactor shutdown if the number of channels OPERABLE is less than required by the Minimum Channels OPERABLE requirement.

The proposed surveillance requirements for Items 13 and 14 of TS Table 4.3-1 are the same surveillance requirements which currently exist within CTS Table 4.3-1, Item 13. The proposed changes will increase the applicability of the surveillance requirements for Table 4.3-1, Items 13 and 14, to include whenever the reactor trip breakers are closed (existing surveillance requirements only apply while in Modes 1 and 2). This addition constitutes a more restrictive change which will not adversely affect plant safety.

Question 6: TS Change Nos. 13.a - 13.f and 13.h Forproposed TS changes 13.a, 13.b, 13.c, 13.d, 13.e, 13.f, and 13.h, with respect to the proposed TS Table 3.3-3, Action 5 requirements, Attachment 1, page 6 of the application states: "The 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> completion time is also consistent with the existing technical specification requirements for restoration of an inoperable manual trip channel for the associated ESFAS functional unit." What is the importance of this comparison? Does it relate to the MP2 design or NUREG-1432? Note, if NUREG-1432 contains TS values in [ J then plant-specificjustification is needed for establishing an appropriate safety basis. Provide detailed supporting design information justification for the Action 5 48-hour repair AOT.

In addition, provide detailed supportingjustification for TS changes 13.a 13.f, and 13.h. In general, the discussions of change need to establish a safety basis for operation under new requirements that result from the proposed changes. Justification for deviations from STS requirements should include discussion of the MP2 design.

Response: The following discussion provides a justification for the Action 5, 48-hour allowed outage time and in general a justification for changes 13.a, 13.b, 13.c, 13.d, 13.e, 13.f, and 13.h of the DNC May 7, 2002, submittal.

CTS Table 3.3-3 and 3.3-4 do not specifically list the Automatic Actuation Logic (AAL) for each function. However, Table 4.3-2 specifically lists the AAL for each function. The purpose of the proposed change was to make these Tables consistent to each other and add appropriate OPERABILITY

U.S. Nuclear Regulatory Commission B 18807/Attachment 1/Page 10 requirements (Table 3.3-3) and trip setpoints (Table 3.3-4). CTS Table 3.3-3 does not provide a specific action for an inoperable AAL channel.

The proposed change (Action 5) will provide a specific reference for the AAL to be OPERABLE in MODES 1, 2, and 3, consistent with the applicability of Table 4.3-2. The AAL is credited in the Millstone Unit No. 2 Safety Analysis for MODES 1, 2, and 3. Therefore, once the plant is in Mode 4, it is outside the modes of applicability for the AAL and there is no need to go to MODE 5. Additionally, the current applicability for the AAL surveillance requirements, as found in Technical Specification Table 4.3 2, is "MODES 1, 2, and 3."

The proposed change provides for an allowed outage time of 48-hours for inoperable AAL. This allowed outage time is based on operating experience, which has demonstrated that a random failure of a second channel of AAL occurring during the 48-hour period is a low probability event. The allowed outage time is also commensurate with the importance of avoiding the vulnerability of a single failure in the only remaining OPERABLE channel. Additionally, the proposed allowed outage time provides for sufficient time to assess the nature of inoperability for the affected component(s), including determination and completion of any necessary repairs, thereby avoiding an unnecessary plant transient (reactor shutdown). Additionally, the proposed allowed outage time is consistent with the allowed outage time specified in NUREG-1432 for the ESF AAL (LCO 3.3.5, Actions A.1 and C.1).

Question 7: TS Change No. 13._

For Item 13.g, the staff notes that the proposed TS deviates from NUREG-0212 because the NUREG does not include Automatic Actuation Logic (AAL) for either emergency bus undervoltage protection channel.

Provide detailed supporting justification for including emergency bus undervoltage protection channel AAL. Discussions of change need to establish a safety basis for operation under new requirements that result from the proposed changes. Justification for deviations from STS requirementsshould include discussion of the MP2 design.

Response: Upon further review and consideration, DNC is withdrawing the proposed changes associated with the emergency bus undervoltage protection channel AAL. Attachments 1 and 2 provide the marked up and retyped pages (pages 3/4 3-14, 3-19, and 3-24) which have been revised to reflect this withdrawal.

U.S. Nuclear Regulatory Commission B18807/Attachment 1/Page 11 Question 8: TS Chanqe No. 17 Provide justification for performing response time testing of the control room isolation function (Table 3.3-6, Item 1.b) on a staggered test basis frequency.

Response: The control room isolation function consists of two (2) channels, with at least one (1) channel required OPERABLE during ALL MODES as per Table 3.3-6, Item 1.b. The control room isolation function is critical for maintaining radiological dose assumptions for control room personnel within accident analysis assumptions and regulatory limits. Given the significance of this function, the frequency of response time testing was selected consistent with the frequency specified for the Engineered Safety Features (ESF) Systems (see Technical Specification Surveillance Requirement 4.3.2.1.3).

Technical Specification Surveillance Requirement 4.3.2.1.3 requires that each test shall be performed at least once every N times 18 months where N is the total number of redundant channels in a specific ESF function. For a two (2) channel system, a control room isolation channel would be tested every 18 months, with each channel tested once every 36 months, consistent with proposed Technical Specification Surveillance Requirement 4.3.3.1.3.

Question 9: TS Change No. 21 The proposed TS Action changes are consistent with NUREG-1432 and are less restrictive than the current TSs; however, the staff notes the proposed surveillance requirements do not include testing to verify each required control circuit and transfer switch is capable of performing its intended safety function. In addition, the proposed TS does not test the RTCB open/close indication. Provide discussion regarding the MP2 design of installed control circuit, transfer switches and remote shutdown RTCB open/close indication. Identify and provide citations for any existing procedures that are used to ensure these components are tested in order for the Table 3.3-9 Instrumentation to be operable.

Response: Based on our discussion with the NRC staff on December 19, 2002, DNC understands that the NRC will not approve the proposed changes for extension of the Remote Shutdown instrumentation allowed outage time from 7 days to 31 days without additional proposed changes to Millstone Unit No. 2 Technical Specification 3.3.3.5 such that this specification is consistent with NUREG-1432, Revision 2, Technical Specification 3.3.12, "Remote Shutdown System (Analog)." Based on this decision, DNC

U.S. Nuclear Regulatory Commission B18807/Attachment 1/Page 12 withdraws the proposed changes associated with the extension of the allowed outage time for an inoperable channel of Remote Shutdown Instrumentation (Attachment 1, item 23 of the DNC May 7, 2002, license amendment request). Attachments 1 and 2 provide the marked up and retyped page reflecting this withdrawal.

DNC also understands based on our discussion with the NRC staff that this question, Question 9, is a result of the proposed extension to the allowed outage time for an inoperable channel of Remote Shutdown Instrumentation from 7 days to 31 days. Since DNC is withdrawing the proposed change to extend the allowed outage time of an inoperable channel of Remote Shutdown Instrumentation, citations are not provided for existing procedures used to ensure the control circuit, transfer switches, and remote shutdown RTCB open/close indication are tested.

DNC continues to request approval of the remaining proposed changes for Technical Specification 3.3.3.5 (Attachment 1, Items 21, 22, and 23 of the DNC May 7, 2002, submittal).

Question 10: TS Chanqe No. 23 The proposed TS Action repair AOT for inoperable remote shutdown instrument channels is consistent with NUREG-1432. The safety summary discussion states the potential risk increase associated with the proposed extension of the surveillance frequency from 7 days to 31 days is insignificant. Provide supporting documentation for this conclusion.

Response: The safety summary discussion related to the proposed extension of surveillance frequency from 7 days to 31 days is not correct. The statement should have referred to extension of the allowed outage time for minimum channel requirements (i.e. from 7 days to 31 days). As noted in the response to Question 9, DNC is withdrawing the proposed changes relating to the extension of the allowed outage time for the Remote Shutdown Instrumentation from 7 days to 31 days. Therefore, DNC is not providing documentation applicable to the potential risk increase associated with this extension.

Docket Nos 50-336 B18807 Attachment 2 Millstone Power Station, Unit No. 2 Response to a Request for Additional Information License Basis Document Change Request 2-1-02 Marked Up Pagqes

U.S. Nuclear Regulatory Commission B18807/Attachment 2/Page 1 License Basis Document Change Request 2-1-02 Limiting Safety System Settings and Instrumentation List of Affected Paqes Technical Affected Page with Specification Title of Section Amendment Number Section Number 3.3.2 Engineered Safety Feature Actuation 3/4 3-14, Amendment 245 System Instrumentation 3/4 3-20, Amendment 245 3/4 3-24, Amendment 245 3.3.3 5 Instrumentation - Remote Shutdown 314 3-39, Original Issue Instrumentation

TABLE 3.3-3 (Continued)

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION MINIMUM z

C TOTAL NO. CHANNELS CHANNELS APPLICABLE

-4 FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION j%3.

7. DELETED

8. LOSS OF POWER

a. 4.16 kv Emergency Bus Undervoltage - level one 4/bus 2/Bus 3/bus 1, 2, 3 2

b. 4.16 kv Emergency Bus Undervoltage - level two 4/Bus 2/Bus 3/Bus 1, 2, 3 2 Q

TABLE 3.3-4 (Continued)

• -'I ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP VALUES ENGINEERED SAFETY FEATURE ACTUATION ALLOWABLE

--4 FUNCTIONAL UNIT .TRIP SETPOINT VALUES--

0 z

Co

8. LOSS OF POWER

a. 4.16 kv Emergency Bus Undervoltage level one _ 2912 volts with a > 2877 volts with a 2.0 +/- 0.1 second time 2.0 +/- 0.1 second time delay delay b, 4.16 kv Emergency Bus Undervoltage

> 3700 volts with > 3663 volts with level two an 8.0 + 2.0 second an 8.0 + 2.0 second time delay time delay

9. AUXILIARY FEEDWATER

a. Manual Not Applicable Not Applicable

b. Steam Generator Level - Low > 26.8% > 25.2%

md- ag

10. STEAM GENERATOR BLOWDOWN

a. Steam Generator Level - Low > 26.8% k 25.2%

".*4 r=

~CL (D

"rt.

.r,4 I

TABLE 4.3-2 (Continued)

FN1TNFFFR AFFTY PFATIIPF ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REOUIRFMENTS FNnTNFFPrn UPPTY PPATHDP 2 ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS t-.

L1 I CHANNEL MODES IN WHICH 0

CHANNEL CHANNEL FUNCTIONAL SURVEILLANCE 2 FUNCTIONAL UNIT CHECK CALIBRATION TEST REQUIRED m

6. CONTAINMENT SUMP C

2 RECIRCULATION (SRAS)

B

-I N. a. Manual SRAS (Trip Buttons) N.A. N.A. R N.A.

b. Refueling Water Storage Tank - Low S R M 1, 2, 3

c. Automatic Actuation Logic N.A. N.A. M(1) 1, 2, 3

7. DELETED

8. LOSS OF POWER

a. 4.16 kv Emergency Bus Undervoltage - level one S R M 1, 2, 3 CL

b. 4.16 kv Emergency Bus Undervoltage - level two S R M I, 2, 3

9. AUXILIARY FEEDWATER

a. Manual N. A. N.A.. R N.A.

b. Steam Generator Level - Low S R M 1, 2, 3 C. Automatic Actuation Logic N.A. N.A. M 1, 2, 3 0 10. STEAM GENERATOR BLOWDOWN

a. Steam Generator Level - Low S R M i, 2, 3 I

"Z-4 "W4

INSTRUMENTAT ION REMOTE SHUTDOWN INSTRUMENTATION LIMITING CONDITION FOR OPERATION instrumentation channels shown in 3.3.3.5 The remote shutdown monitoring displayed external to the Table 3.3-9 shall be OPERABLE with readouts control room.

PPLICABILITY: MODES 1, 2 and 3.

ACTION:

inoperable, either:

Witha remote shutdown monitoring channel

a. c immediately &eonte~h PERABILITY of a redun~dant chanl

c. "b, Restore the i-oerable chan to OPERABLE status within 7 days, or

,6,-G, Be in HOT SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SURVEILLANCE REQUIREMENTS instrumentation channel shall be 4.3.3.5 Each remote shutdown monitoring of the CHANNEL CHECK and CHANNEL demonstrated OPERABLE by performance shown in Table 4.3-6.

CALIBRATION operations at the frequencies MILLSTONE - UNIT 2 3/4 3--3&.

Docket Nos. 50-336 B18807 Attachment 3 Millstone Power Station, Unit No. 2 Response to a Request for Additional Information License Basis Document Change Request 2-1-02 Retyped Pages

°p.'

I TABLE 3.3-3 (Continued)

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION z MINIMUM TOTAL NO. CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

7. DELETED

8. LOSS OF POWER

a. 4.16 kv Emergency Bus Undervoltage - level one 4/bus 2/Bus 3/bus 1, 2, 3 2

b. 4.16 kv Emergency Bus Undervoltage - level two 4/Bus 2/Bus 3/Bus 1, 2, 3 2 (ii w

C.

0 r1 z

0

'N

".4

°!

y (,

I TABLE 3.3-4 (Continued)

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP VALUES 0

z mr ALLOWABLE FUNCTIONAL UNIT TRIP SETPOINT VALUES

.=

z

-4 8. LOSS OF POWER

a. 4.16 kv Emergency Bus Undervoltage > 2912 volts with a > 2877 volts with a level one 2.0 + 0.1 second time 2.0 + 0.1 second time delay delay

b. 4.16 kv Emergency Bus Undervoltage > 3700 volts with > 3663 volts with level two an 8.0 + 2.0 second an 8.0 + 2.0 second time delay time delay

9. AUXILIARY FEEDWATER

a. Manual Not Applicable Not Applicable

b. Steam Generator Level - Low > 26.8% > 25.2%

c. Automatic Actuation Logic Not Applicable Not Applicable I

10. STEAM GENERATOR BLOWDOWN

-4 a. Steam Generator Level - Low > 26.8% > 25.2%

r!:

'-4 0

TABLE 4.3-2 (Continued) .79 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL MODES IN WHICH CHANNEL CHANNEL FUNCTIONAL SURVEILLANCE z

m FUNCTIONAL UNIT CHECK CALIBRATION TEST REQUIRED

6. CONTAINMENT SUMP RECIRCULATION (SRAS)

a. Manual SRAS (Trip Buttons) N.A. N.A. R N.A.

b. Refueling Water Storage Tank - Low S R M 1, 2, 3

c. Automatic Actuation Logic N.A. N.A. M(1) 1, 2, 3

7. DELETED

8. LOSS OF POWER

a. 4.16 kv Emergency Bus Undervoltage - level one S R M 1, 2, 3

b. 4.16 kv Emergency Bus Undervoltage - level two S R M 1, 2, 3

9. AUXILIARY FEEDWATER

a. Manual N.A. N.A. R N.A.

b. Steam Generator Level - Low S R M 1, 2, 3

c. Automatic Actuation Logic N.A. N.A. M 1, 2, 3

10. STEAM GENERATOR BLOWDOWN

a. Steam Generator Level - Low S R M 1, 2, 3

INSTRUMENTATION REMOTE SHUTDOWN INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.5 The remote shutdown monitoring instrumentation channels shown in Table 3.3-9 shall be OPERABLE with readouts displayed external to the control room.

APPLICABILITY: MODES 1, 2 and 3.

ACTION:

With less than the minimum required channels of a remote shutdown monitoring channel inoperable, either:

a. Restore the minimum required channels to OPERABLE status within 7 days, or

b. Be in HOT SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SURVEILLANCE REQUIREMENTS 4.3.3.5 Each remote shutdown monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3-6.

MILLSTONE - UNIT 2 3/4 3-28 Amendment No.

0811