ML13113A344

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Response to Request for Additional Information Regarding Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program
ML13113A344
Person / Time
Site: Millstone Dominion icon.png
Issue date: 04/17/2013
From: Grecheck E
Dominion, Dominion Nuclear Connecticut
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
13-138, TAC ME9733
Download: ML13113A344 (25)
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Text

Dominion Nuclear Connecticut, Inc.

5000 Dominion Boulevard, Glen Allen, VA 23060 Dominion Web Address: www.dom.com April 17, 2013 U. S. Nuclear Regulatory Commission Serial No.13-138 Attention: Document Control Desk NSSL/WDC RO Washington, DC 20555 Docket No. 50-423 License No. NPF-49 DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION UNIT 3 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING RELOCATION OF SPECIFIC SURVEILLANCE FREQUENCY REQUIREMENTS TO A LICENSEE CONTROLLED PROGRAM (TAC NO. ME9733)

By letter dated October 4, 2012, Dominion Nuclear Connecticut, Inc. (DNC) submitted a license amendment request (LAR) for Millstone Power Station Unit 3 (MPS3). The proposed amendment would relocate certain technical specification (TS) surveillance frequencies to a licensee controlled program by adopting Technical Specification Task Force (TSTF)-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control

- RITSTF [Risk-Informed Technical Specification Task Force Initiative] 5b." The proposed change would also add a new program, the Surveillance Frequency Control Program, in accordance with TSTF-425. In a letter dated December 18, 2012, the NRC transmitted a request for additional information (RAI) to DNC related to the LAR. DNC responded to the RAI in a letter dated January 4, 2013. In a letter dated March 8, 2013, the NRC transmitted a second RAI to DNC related to the LAR. DNC agreed to respond to the RAI by April 22, 2013. provides DNC's response to the NRC's RAI. Attachment 2 contains the marked-up pages to reflect the proposed changes to the TS.

If you have any questions regarding this submittal, please contact Wanda Craft at (804) 273-4687.

Sincerely, VICKI L. HULL Eugene S. Grecheck f

Notary Public Vice President - Nuclear Engineering and Development Commonwealth of Virginia 140542 My Commission Expires May 31. 2014 COMMONWEALTH OF VIRGINIA JN COUNTY OF HENRICO The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Eugene S. Grecheck, who is Vice President - Nuclear Engineering and Development of Dominion Nuclear Connecticut, Inc. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that company, and that the statements in the document are true to the best of his knowledge and belief.

Acknowledged before me this I7 *day of tID 2013.

/RAv 31.R)14,L My Commission Expires: -"

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-NoraFy Public kJILL

Serial No.13-138 Docket No. 50-423 Page 2 of 2 Attachments:

1. Response to Request for Additional Information Regarding Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program
2. Marked-up Technical Specifications Pages Commitments made in this letter: None cc: U.S. Nuclear Regulatory Commission Region I 2100 Renaissance Blvd Suite 100 King of Prussia, PA 19406-2713 J. S. Kim Project Manager - Millstone Power Station U.S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Mail Stop 08-C2A Rockville, MD 20852-2738 NRC Senior Resident Inspector Millstone Power Station

Serial No.13-138 Docket No. 50-423 ATTACHMENT 1 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING RELOCATION OF SPECIFIC SURVEILLANCE FREQUENCY REQUIREMENTS TO A LICENSEE CONTROLLED PROGRAM DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION UNIT 3

Serial No.13-138 Docket No. 50-423 Attachment 1, Page 1 of 8 By letter dated October 4, 2012, Dominion Nuclear Connecticut, Inc. (DNC) submitted a license amendment request (LAR) for Millstone Power Station Unit 3 (MPS3). The proposed amendment would relocate certain technical specification (TS) surveillance frequencies to a licensee controlled program by adopting Technical Specification Task Force (TSTF)-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control

- RITSTF [Risk-Informed Technical Specification Task Force Initiative] 5b." The proposed change would also add a new program, the Surveillance Frequency Control Program (SFCP), in accordance with TSTF-425. In a letter dated December 18, 2012, the NRC transmitted a request for additional information (RAI) to DNC related to the LAR. DNC responded to the RAI in a letter dated January 4, 2013. In a letter dated March 8, 2013, the NRC transmitted a second RAI to DNC related to the LAR. This attachment provides DNC's response to the NRC's RAI.

Question 1 The response to Question 5 of the RAI, dated January 4, 2013, discussed a process and noted a procedure. However, the response is future-looking, and the question is related to what has been done to-date to support the application. The original question is repeated. Gap #2. The disposition of this supporting requirements states this is a documentation issue only; however, no discussion is provided on the plant walkdowns and interviews mentioned in the supporting requirement. Please discuss these walkdowns and interviews which address this supportingrequirement (SR).

DNC Response System engineer interviews have been completed and documented to confirm the system analysis correctly reflects the as-built, as-operated plant for the following systems:

" Circulating Water System

  • Chemical and Volume Control System
  • High Pressure Safety Injection System
  • Reactor Plant Component Cooling Water System

" Service Water System The feedback provided in the interviews has been incorporated into the appropriate model notebooks and model files. The feedback for these systems was primarily editorial and did not have a significant impact on the model.

System walkdowns have also been completed and documented to confirm the system analysis correctly reflects the as-built, as-operated plant for the following systems:

  • Charging Pump Cooling System

Serial No.13-138 Docket No. 50-423 Attachment 1, Page 2 of 8

" Chemical and Volume Control System

" Reactor Plant Component Cooling Water System

" Safety Injection Pump Cooling System Walkdowns of these systems did not identify any modeling or documentation issues.

Question 2 The response to Question 6 of the RAI, dated January 4, 2013, states that Gap #3 (HR-G5) is based on outdated (circa 2006) talk-through documentation with Operations, and proposes to perform a sensitivity analysis on human errorprobabilities (HEPs) in lieu of updating operator survey information to support the basis for revised or new human failure events. The license amendment request proposes to use a sensitivity analysis using an a-priori multiple of 10; however, this a-prior approach cannot be known to represent a bounding sensitivity analyses for the HEPs. Therefore, since the last update to the HEPs which considered operatorsurvey information was performed a long time ago, ether complete the talk-throughs or provide assurance that the HEPs will be treatedin a bounding manner.

DNC Response Question 6 of the RAI, dated January 4, 2013, is associated with a technical adequacy gap in the ASME/ANS Supporting Requirement (SR) HR-G5 Category II, which states:

"When needed, BASE the required time to complete actions for significant

[human failure events] HFEs on action time measurements in either walkthroughs or talkthroughs of the procedures or simulator observations."

In 2012, a focused probabilistic risk assessment (PRA) peer review identified the MPS3 PRA model, M310A, did not meet the category II requirements for HR-G5. The peer review team identified the existing human reliability analysis documentation for talkthroughs with Operations was outdated (circa 2006). In addition, no new operator survey information was provided to support the basis for revised or new HFEs.

In March 2013, an operator walkthrough/talkthrough was performed with a MPS3 Operations Unit Supervisor for the significant HFEs as required to meet ASME/ANS SR HR-G5. In addition, operator walkthrough/talkthrough of the non-significant HFEs were performed. The [Electric Power Research Institute] EPRI HRA Calculator for MPS3 was revised to include the changes identified during the walkthrough/talkthrough. The final analysis resulted in no impact to the HEP values within the MPS3 PRA model.

Therefore, no sensitivity studies will be required to address SR HR-G5.

Serial No.13-138 Docket No. 50-423 Attachment 1, Page 3 of 8 Question 3 In response to Question 7 of the RAI, dated January 4, 2013, it is noted that the MPS3 probabilistic risk assessment (PRA) Internal Flooding notebook states: "Thus, only equipment within the area that may be affected by spray or jet impingement damage are assumed to fail, and there is no propagation to other areas and no damage due to submersion." Providejustification for the assumption that action can be taken such that there is no propagationor submersion.

DNC Response The flooding zones within MPS3 have been re-evaluated to augment the modeling of human-induced flooding events during maintenance activities. The review identified five flood areas and flood sources where new maintenance-induced flooding events could potentially occur. When these new events were added to the model, collectively, the average maintenance core damage frequency (CDF) and large early release frequency (LERF) values increase by significantly less than 1%. Since the MPS3 PRA, M310A has not been updated to include the newly identified maintenance-induced flooding events, a sensitivity study will be performed when needed to support PRA assessments in the SFCP.

The sentence referenced in the RAI from the MPS3 PRA Internal Flooding notebook IF.2 has been revised to state, "Flood zones have been assessed to ensure that spray, jet impingement, submersion, and propagation were evaluated and documented as required."

Question 4 Gap #9 is related to the potential for flood barrier unavailability and flood pathways through floor drain check valves. Please discuss your assessment and the risk significance of the flood barrierunavailability and the floor drain check valves for the application in more detail, as well as planned updates, if necessary, to the flood PRA model based on the assessment.

DNC Response Technical adequacy Gap #9 is associated with ASME/ANS SR IFSN-A8 Category II, which states:

"IDENTIFY inter-area propagation through the normal flow path from one area to another via drain lines; and areas connected via backflow through drain lines involving failed check valves, pipe and cable penetrations (including cable trays),

doors, stairwells, hatchways, and [heating, ventilation and air conditioning] HVAC

Serial No.13-138 Docket No. 50-423 Attachment 1, Page 4 of 8 ducts. INCLUDE potential for structural failure (e.g., of doors or walls) due to flooding loads."

The 2012 focused peer review team stated, "There are indications throughout the IF.1 and IF.2 documents that inter-area propagation was appropriately considered, although there is no single location in one of the documents where inter-area propagation paths are listed."

The MPS3 internal flooding notebooks (IF.1 and IF.2) have been revised to support easier retrieval and understanding of inter-area propagation through normal flow paths, including drain line backflow and potential flood barrier structural failure/unavailability. A review of the inter-area propagation paths did not identify any new flooding events.

Revision of the documentation addresses the peer review's findings and no update to Model M310A is planned or necessary.

Question 5 For fire events and external events risk assessment, responses to Questions 10 and 11 of the RAI, dated January 4, 2013, state that information from the Millstone Individual Plant Examination of External Events (IPEEE) report will be screened. In addition, the responses to Questions 10 and 11 of the previous RAI indicate that the IPEEE information will be qualitativelyassessed.

a. Please clarify which methods (e.g., an IPEEE method or other)would be used if a bounding analysis is to be performed for fire events or extemal events.
b. If a bounding analysis is to be performed for fire events or external events, discuss steps of your analysis process which help to ensure the analysis is bounding and considers the currentplant configurationand operation DNC Response DNC is committed to evaluating changes to surveillance frequencies in accordance with the guidance provided in NEI 04-10, Rev. 1. NEI 04-10 methodology allows a qualitative screening or bounding analysis to provide justification for acceptability of proposed surveillance frequency changes. Since the MPS3 PRA model does not currently include fire and other external events, the NEI 04-10 guidance will be used to evaluate the potential risk impact of external events associated with surveillance frequency changes. Specifically, external event information from the Millstone Individual Plant Examination of External Events (IPEEE) report will be initially screened.

The information will be reviewed and qualitatively assessed based on engineering judgment to determine the impact of the external events on surveillance frequency changes. If the qualitative information is deemed not to be sufficient then a bounding analysis will be performed.

Serial No.13-138 Docket No. 50-423 Attachment 1, Page 5 of 8 DNC will perform bounding analysis in accordance with Step 10b, Bounding Analysis Below IE-07/yr CDF and 1E-08/yrLERF?, of NEI 04-10 Rev. 1, which states, in part:

"Alternative evaluations for the impact from external events and shutdown events are also deemed acceptable at this point. For example, if the ACDF and ALERF values have been demonstrated to be very small from an internal events perspective based on detailed analysis of the impact of the SSC being evaluated for the STI change, and if it is known that the CDF or LERF impact from external events (or shutdown events as applicable) is not specifically sensitive to the SSC being evaluated (by qualitative reasoning), then the detailed internal events evaluations and associated required sensitivity cases ... can be used to bound the potential impact from external events and shutdown PRA model contributors.

As an another example, if the ACDF and ALERF values have been demonstrated to be very small from an internal events perspective based on detailed analysis of the impact of the SSC being evaluated for the STI change, and if it is known that the plant CDF and LERF results of the external event or shutdown PRA are much smaller than the corresponding values for the internal event full power PRA, (that is, less than 10%), then the results of the internal events analysis alone would suffice for the STI consideration."

If the above NEI 04-10 guidance is not sufficient to address the bounding analysis requirements, then a quantitative bounding analysis will be performed using tools currently in use to support the Significance Determination Process (SDP). For example, in recent years Dominion has performed several fire PRA evaluations and would implement the same process for any STI changes, if necessary.

1. The IPEEE fire analysis will be reviewed to determine whether the SSCs associated with the STI may impact fire risk.
2. If the STI will be fire risk impacting, a fire PRA bounding analysis will be developed to allow calculation of the delta risk by generating an accident sequence analysis that credits the affected SSCs. The bounding fire analysis will be based on IPEEE methodologies to calculate fire initiating event frequencies and will use mitigating system and operator action analyses completed for the current internal events MPS3 PRA model. This will ensure the analysis reflects the current plant configuration and operation.
3. Then sensitivity calculations will be performed using the accident sequence model to calculate the STI change delta CDF and delta LERF and to identify dominant fire risk contributors associated with the STI change.
4. Reasonable variations to the appropriate basic event values associated with the dominant fire risk contributors will then be made to determine the potential bounding fire risk impact of the STI change. This bounding evaluation process is consistent with the guidance provided in NEI 04-10, Step 1Ob. The basis for the changes made will be documented in the PRA analysis supporting the STI change.

Serial No.13-138 Docket No. 50-423 Attachment 1, Page 6 of 8

5. The delta CDF and delta LERF results of the sensitivity calculations will be compared to 1 E-7/yr CDF and 1E-8/yr LERF.

The process outlined above will be used for required bounding analysis of other external events.

Question 6 SR 4.2.4.2 is only performed if >75% power AND one power range channel is inoperable (Frequenciesthat are related to specific condition) and cannot be relocated to the Surveillance Frequency Control Program (SFCP).[Part 1] Also, Table 4.7.1, Secondary Coolant System Specific Activity Sample and Analysis Program,proposes to relocate a "ProgramFrequency"to the SFCP. This is prohibitedbecause it is a program requirement (Frequencies that reference other approved programs for the specific interval).[Part 2] And even if they could be relocated, note that 2(a) and (b) are conditional (SR performance is dependent upon on (1) Gross Radioactivity Determination SR results. I had a similar issue with the Oconee TSTF-425 license amendment request where the licensee proposed relocating an Oconee TS Chapter 5 component "test interval," that is located in the Standard Technical Specification (Section 3, Surveillance), to the SFCP.[Part3]

DNC Response Part 1 Because of format variations in the MPS3 TSs (NUREG -0452 format), the frequency in SR 4.2.4.2, Quadrant Power Tilt Ratio [QPTR] appears conditional; however, comparison of this surveillance with the QTPR surveillance in TSTF-425 (i.e., SR 3.2.4.2) for Westinghouse plants (NUREG-1431 format) shows that these surveillance requirements are identical, therefore, permitted to be relocated to the SFCP.

Part 2 The approved programs for MPS3 are described in Section 6.0, "Administrative Controls," of the MPS3 TSs. The title descriptor in Table 4.7.1 (i.e., Secondary Coolant System Specific Activity Sample and Analysis "Program.") may be misconstrued since there are no program requirements for secondary coolant specific activity sampling and analysis in Section 6.0 of the TSs. To preclude future misunderstanding, DNC proposes to delete the word 'Program" from the title in Table 4.7.1. This change is reflected in the mark-up for Table 4.7-1 provided in Attachment 2.

Serial No.13-138 Docket No. 50-423 Attachment 1, Page 7 of 8 Part 3 In DNC's submittal of October 4, 2012, DNC proposed to relocate the surveillance frequencies contained in Section 2a and 2b of Table 4.7-.1 to the SFCP. The NRC states above that these frequencies are conditional and therefore cannot be relocated to the SFCP. Upon review of these requirements, DNC agrees that the frequency in Section 2a is conditional and not a candidate for relocation. However, the frequency in Section 2b is associated with the normal condition of dose equivalent 1-131 < 10% of allowable limit and therefore can be relocated to the SFCP. This is consistent with the standard TSs changes for dose equivalent 1-131 (i.e., SR 3.7.18.1) presented in TSTF-425 for Westinghouse plants. The revised mark-up for Table 4.7-1 is provided in .

Question 7 The response to Question 13 of the RAI, dated January4, 2013, is unacceptable. The Frequency (the "when') can be located in the SFCP - NOT the Surveillance Requirement ("what" is being tested) i.e., "each train shall be tested." This is very clearly identified in the FR Notice for Availability. The frequency (62 days) and the reference to the staggered'test basis can be replaced by "the frequency specified in the Surveillance Frequency Control Program," as the licensee identified in the RAI response.

DNC Response The proposed TS mark-ups for Table 4.3-1 (i.e., Notation 7) and Table 4.3-2 (i.e.,

Notation 1) have been revised to relocate the surveillance frequency to the SFCP while still maintaining reference on "what is being tested." Since these table notations are no longer being deleted in their entirety, the notation numbers have been added back into the applicable table.

Similarly, the markup for SR 4.3.1.2 has been revised to address the same issue described above in Question 7. Specifically, the surveillance frequency in SR 4.3.1.2 is still proposed for relocation; however, the requirement on what to test is being maintained.

The revised marked-up TS pages reflecting these changes are provided in Attachment 2.

Additional Information During the RAI clarification call between the NRC and DNC on February 5, 2013, the NRC questioned relocating the surveillance frequencies for SRs 4.4.1.2.1, 4.4.1.3.1 and 4.4.1.4.1.3 to the SFCP since the frequencies appeared to be conditional/event-driven.

Serial No.13-138 Docket No. 50-423 Attachment 1, Page 8 of 8 Upon review of these surveillances, DNC concludes that relocation of these surveillance frequencies to the SFCP is consistent with the TSTF-425 changes for Westinghouse plants (see SRs 3.4.5.3, 3.4.6.3 and 3.4.7.3) and therefore qualifies for relocation.

In addition, DNC has reviewed the MPS3 TS markups submitted to the NRC in letter dated October 4, 2012, to ensure the surveillance frequencies, originally proposed for relocation to the SFCP, do not meet any one of the four exclusion criteria defined in TSTF-425. Because of the format of Millstone's custom TS, the wording of some SRs seem to be conditional, but review concludes these surveillances are performed under normal operating conditions and are not associated with abnormal or degraded conditions. Therefore, relocation of SRs 4.4.6.2.1, 4.4.9.3, 4.6.3.2, 4.8.1.1.2, 4.8.2.1.d, 4.8.2.1 .e, 4.10.2.1.1, and 4.10.2.1.2 to the SFCP is consistent with TSTF-425.

However, the review also determined three SRs are not eligible for relocation to the SFCP. SR 4.7.1.2.1.b is controlled by the station's inservice testing program and therefore not eligible for relocation. SRs 4.7.5.b and 4.10.1.1 are associated with a specific condition and therefore are not eligible for relocation. New marked-up TS pages are provided in Attachment 2 for these SRs. The TS page for SR 4.10.1.1 is included and labeled "for Information only" to identify that no changes are being made to this page and it can be removed from the October 4, 2012 submittal.

Serial No.13-138 Docket No. 50-423 ATTACHMENT 2 MARKED-UP TECHNICAL SPECIFICATIONS PAGES DOMINION NUCLEAR CONNECTICUT, INC.

MILLSTONE POWER STATION UNIT 3

Nvme 3, 2066 3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.1 As a minimum, the Reactor Trip System instrumentation channels and interlocks of Table 3.3-1 shall be OPERABLE.

APPLICABILITY: As shown in Table 3.3-1.

ACTION:

As shown in Table 3.3-1.

SURVEILLANCE REQUIREMENTS 4.3.1.1 Each Reactor Trip System instrumentation channel and interlock and the automatic trip logic shall be demonstrated OPERABLE by the performance of the Reactor Trip System Instrumentation Surveillance Requirements specified in Table 4.3-1.

4.3.1.2 The REACTOR TRIP SYSTEM RESPONSE TIME of each Reactor trip function shall be verified to be within its limit a least,@ te per- 1 monthc. Neutron detectors and speed sensors are exempt from response ti erification. Each verification shall include at least one train SHIAK th÷ I , t.1 ......... ; I ....... F m* -- and one channel (to include input relays to both trains) per fu tion .... that all channe.. are Y.rifi. d f.t letto... , 1,N Ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 3 3/4 3-1 Amendment No. 4-5, 79, 94-, 4-00,41 lReplace each marked through surveillance frequency in the Check, Calibrate, and Test columns with "SFCP" TABLE 4.3-10ntinued)

REACTOR TRIP SYSTEM INSTRUMY2A$I IURVEILLANCE REOUIREMENTS z P MODES FOR C EL DDEVI

ýP WHICH CHANN -ýL-ý4C L 0 RATIONAL I PERATýý V ACTUATION SURVEILLANCE rATION T ST FUNCTIONAL UNIT CWH C4 RATION ST T LOGIC TEST IS REQUIRED Ir- JANLOG v  :"AA AATING ME-

18. Reactor Trip Breaker N.A. N.A. N.A. +f(7, 11) N.A. 1, 2, 3*,

4*, 5*

19. Automatic Trip and N.A. N.A. N.A. N.A. -W7) 1,2,3*,

Interlock Logic 4*, 5*

20. DELETED
21. Reactor Trip Bypass N.A. N.A. N.A. -M(7, 15) N.A. 1, 2,3*,

I Breaker -R(16) 4*, 5*

22. DELETED z

0

September 14, 2001 TABLE 4.3-1 (Continued)

TABLE NOTATIONS When the Reactor Trip System breakers are closed and the Control Rod Drive System is capable of rod withdrawal.

    • Below P-6 (Intermediate Range Neutron Flux Interlock) Setpoint.
      • Below P-10 (Low Setpoint Power Range Neutron Flux Interlock) Setpoint.
    • Above the P-9 (Reactor Trip/Turbine Interlock) Setpoint.
          • Above the P-7 (At Power) Setpoint (1) If not performed in previous 31 days.

(2) Comparison of calorimetric to excore power indication above 15% of RATED THERMAL POWER. Adjust excore channel gains consistent with calorimetric power if absolute difference is greater than 2%. The provisions of Specification 4.0.4 are not applicable to entry into MODE 2 or 1.

(3) Single point comparison of incore to excore AXIAL FLUX DIFFERENCE above 15% of RATED THERMAL POWER. Recalibrate if the absolute difference is greater than or equal to 3%. The provisions of Specification 4.0.4 are not applicable for entry into MODE 2 or 1.

(4) Neutron detectors may be excluded from CHANNEL CALIBRATION.

(5) Detector plateau curves shall be obtained, and evaluated and compared to manufacturer's data. For the Source Range, Intermediate Range and Power Range Neutron Flux channels the provisions of Specification 4.0.4 are not applicable for entry into MODE 2 or 1.

(6) Incore - Excore Calibration, above 75% of RATED THERMAL POWER. The provisions of Specification 4.0.4 are not applicable for entry into MODE 2 or 1.

(7) Each train shall be tested at .....

aft r; 4-2 .... an a STAGGERED TET B ASIS.

a6 (8) (Not used)

(9) Qte4elyrveillanc in MODES 3*, 4*, and 5* shall also include verification that permissives P-6 an P-10 are in their required state for existing plant conditions by observation of th ermissive annunciator window.

9the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 3 3/4 3-13 Amendment No. 60, 70, 409,224

IReplace each marked through surveillance frequency in the Check, Calibrate, and Test columns with "SFCP" I ENGNEREDSAET FETUE AM N STEM NTUETTO SRVEI LL IV~WREMENTS

-3 A ALO MODES 0

z A L DE OP]

CEMASTER SLAX FOR WHICH CHANNEL CHANNE OPE IONA STION UATION RELAY REL/ kY SURVEILLANCE FUNCTIONAL UNIT CHECK CALIB TI TEST TE ST OG TEST TEST TES7F IS REQUIRED

1. Safety Injection (Reactor Trip, Feedwater Isolation, Control Building /

Isolation (Manual Initiation Only), Sta Diesel Generators, and Service W r)

a. Manual Initiation N.A. N.A. N.A. N.A. N.A. N.A. 1,2,3,4
b. Automatic Actuation N.A. N.A. N.A. N.A. -4(1) -M(1) -Q-(4) 1,2,3,4 0aO Logic and Actuation Relays
c. Containment Pressure- -S N.A. N.A. N.A. N.A. 1,2,3 High-1
d. Pressurizer Pressure- -S -Q N.A. N.A. N.A. N.A. 1,2,3 Low
e. Steam Line Pressure- -R N.A. N.A. N.A. N.A. 1,2,3 Low
2. Containment Spray z0 a. Manual Initiation N.A. N.A. N.A. N.A. N.A. N.A. 1,2,3,4
b. Automatic Actuation N.A. N.A. N.A. N.A. -WA1) -M(1) -Q(4) 1,2,3,4 Logic and Actuation Relays
c. Containment Pressure- -S -R N.A. N.A. N.A. N.A. 1,2,3,4 High-3

IReplace each marked through surveillance frequency in the Check, Calibrate, and Test columns with "SFCP" I ENGINEERED SAFETY FEAR j IN SYSTEM INSTRUMENTATION A AL G A AMODES 0 HAZELL DEVI EMASTER SLAVE FOR WHICH zH CHANNEL CHA EL OPE ION OPE ONA C TION RELAY RELAY SURVEILLANCE FUNCTIONAL UNIT CHECK C LB ON TES TEST L IC TEST TEST IS REQUIRED

3. Containment Isolation
a. Phase "A" Isolation
1. Manual Initiation N.A. N.A. N.A. -R-- N.A. N.A. N.A. 1,2,3,4
2. Automatic Actuation N.A. N.A. N.A. N.A. Wt(1) -M(1) -Q-(4) 1,2,3,4 Logic and Actuation Relays
3. Safety Injection See Item 1. above for all Safety Injection Surveillance Requirements.
b. Phase "B" Isolation
1. Manual Initiation N.A. N.A. N.A. -N.- N.A. N.A. N.A. 1,2,3,4
2. Automatic Actuation N.A. N.A. N.A. N.A. -4M(l) M(1) -t(4) 1,2,3,4 Logic and Actuation Relays z 3. Containment N.A. N.A. N.A. N.A. 1,2,3,4 Pressure-High-3 0
c. DELETED I yt* 4. Steam Line Isolation
d. Manual Initiation
1. Individual N.A. N.A. N.A. -R N.A. N.A. N.A. 1,2,3,4
2. System N.A. N.A. N.A. N.A. N.A. N.A. 1,2,3,4

I IReplace each marked through surveillance frequency in the Check, Calibrate, and Test columns with "SFCP" I NIN RLAT4.N R ETTContinued)

C,,

z MODES SC EL \DEVI MASTER SLAVE FOR WHICH NEL IOP TIONAL\OPERA NAL U N RELAY RELAY SURVEILLANCE FUNCTIONAL UNIT CHECK , ILIB TION TE NE LO E ST IS REQUIRED TE____ST

4. Steam Line Isolation (Continued
b. Automatic Actuation N. . N.A. N.A. N.A. -M(1) -M(1) -Q-(4) 1,2,3,4 Logic and Actuation Re[ays
c. Containment Pressure- -S -R N.A. N.A. N.A. N.A. 1,2,3,4 High-2
d. Steam Line Pressure- -S "R-- N.A. N.A. N.A. N.A. 1,2,3 Low 00
e. Steam Line Pressure- -S- --R- - N.A. N.A. N.A. N.A. 3 Negative Rate-High
5. Turbine Trip and Feedwater z* Isolation 0o a. Automatic Actuation N.A. N.A. N.A. N.A. -M(1) +M(1) Q(4) 1,2 Logic and Actuation Relays
b. Steam Generator Water -S -*-. N.A. -4(1) -(1) -9(4) 1,2,3 I Level-High-High
c. Safety Injection N.A. N.A. N.A. -R N.A. N.A. N.A. 1,2 Actuation Logic
d. Tave Low Coincident N.A. -R " N.A. N.A. N.A. N.A. 1,2 with Reactor Trip (P-4)

IReplace each marked through surveillance frequency in the Check, Calibrate, and Test columns with "SFCP" I TABLE 4.3-12 (Continued)

ENGINEERED SAFETY FEATURES AMrION SYSTEM INSTRUMENTATION SURVEILL,&CA 0 )-[,IMENTS H

MODES CHA DEVIMASTER L SLAVE FOR WHICH CHANNEL C OPE TIONA OPERAT AL U N RELAY RELAY SURVEILLANCE FUNCTIONAL UNIT CHECK -ALIB TION TE TEST LOG ES ST TEST IS REOUIRED

6. Auxiliary Feedwater
a. Manual Initiation N.A. N.A. N.A. -R-" N.A. N.A. N.A. 1,2,3
b. Automatic Actuation and N.A. N.A. N.A. N.A. 44(l) -K(I) -Q*(4) 1,2,3 Actuation Relays r-1
c. Steam Generator Water N.A. N.A. N.A. N.A. 1,2,3 Level-Low-Low
d. Safety Injection See Item 1. above for all Safety Injection Surveillance Requirements.
e. Loss-of-Offsite Power See Item 8. below for all Loss of Power Surveillance.
f. Containment See Item 2. above for all CDA Surveillance Requirements.

Depressurization Actuation (CDA)

7. Control Building Isolation
a. Manual Actuation N.A. N.A. N.A. -R- N.A. N.A. N.A.

Cz b. Manual Safety Injection N.A. N.A. N.A. -R-- N.A. N.A. N.A. 1,2,3,4 Actuation

c. Automatic Actuation N.A. N.A. N.A. N.A. -W l) +4(l) -Q(4) 1,2,3,4 Logic and Actuation Relays
d. Containment Pressure-- N.A. N.A. N.A. N.A. 1,2,3 t

High-1

IReplace each marked through surveillance frequency in the Check, Calibrate, and Test columns with "SFCP" I TABLE 4.31(Continued)

ENGINEERED SAFETY FEATURES A42bTJ0N SYSTEM INSTRUMENTATION SU ILLALVC& AENN-tptEMENTS 4j MODES CHAEL FOR WHICH CHANNEL C /ELOPE TIONAL N PERATIOL A UA T'TVCMASTER RELAY SLAVE SURVEILLANCE RELAY FUNCTIONAL UNIT CHECK BB ION TES OGI1 S ST TEST ISREQUIRED

7. Control Building Isolation (Conti
e. Control Building Inlet --S-- -- N.A. N.A. N.A. N.A.

Ventilation Radiation

8. Loss of Power
a. 4 kV Bus Undervoltage N.A. N.A. -M(3) N.A. N.A. N.A. 1, 2, 3, 4 (Loss of Voltage) -R-

,0

b. 4 kV Bus Undervoltage N.A. N.A. "f3) N.A. N.A. N.A. 1,2,3,4 (Grid Degraded Voltage)
9. Engineered Safety Features Actuation System Interlocks
a. Pressurizer Pressure, N.A. N.A. N.A. N.A. N.A. 1,2,3 P-1I
b. Low-Low Tavg, N.A. _R N.A. N.A. N.A. N.A. 1,2,3 z0 P-12
c. Reactor Trip, P-4 N.A. N.A. N.A. N.A. N.A. N.A. 1,2,3
10. Emergency Generator N.A. N.A. N.A. N.A. (1, 2) N.A. N.A. 1, 2,3,4 Load Sequencer
11. Cold Leg Injection Permissive, P-19 N.A. N.A. N.A. N.A. 1, 2,3

'4-

Septemnber 18~, 2008 TABLE 4.3-2 (Continued)

TABLE NOTATION

1. Each train shall be tested atileast gve- Q ays 6an a STA G GEP, TESTE BA 819.
2. This surveillance may be perfo ed continuously by the emergency generator load sequencer auto test system as I g as the EGLS auto test system is demonstrated OPERABLE by the performa e of an ACTUATION LOGIC TEST at lpaet @nee per -92
3. On a mbathly ba.is, a loss o voltage condition will be initia at each undervoltage onitoring relay to verify i dividual relay operation. Se mt verification and actuation of the associated logic and larm relays will be perf ed as part of the CHANNEL
4. For Engineered Safety atures Actuati ysterm functional units with only Potter &

Brumfield MDR series elays uZs*a clean, environmentally controlled cabinet, as discussed in Westingh se Ow s Group Report WCAP- 13900, the surveillance interval for slave relay testing s R.

At the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 3 3/4 3-41 Amendment No. 45, 74, 79, +00, 1-29, 4-98, 203,21-W,2-29, 242, 24-3

PLANT SYSTEMS AUXILIARY FEED WATER SYSTEM LIMITING CONDITION FOR OPERATION ACTION: (Continued)

Inoperable Equipment Required ACTION .4-

e. Three auxiliary feedwater e.

pumps in MODE 1, 2, or 3.

- - - - - -- NOTE --------

LCO 3.0.3 and all other LCO required ACTIONS requiring MODE changes are suspended until one AFW pump is restored to OPERABLE status.

Immediately initiate ACTION to restore one auxiliary feedwater pump to OPERABLE status.

SURVEILLANCE REQUIREMENTS the frequency specified in the Surveillance Frequency Control Program 4.7.1.2.1 Each auxili feedwater pump shall be demonstrated OPERABLE:

a. At lea*t cANAL npr 3 1 days, by:

- -- - - - ------- NOTE ---------------

Auxiliary feedwater pumps may be considered OPERABLE during alignment and operation for steam generator level control, if they are capable of being manually realigned to the auxiliary feedwater mode of operation.

Verifying each auxiliary feedwater manual, power operated, and automatic valve in each water flow path and in each required steam supply flow path to the steam turbine driven auxiliary feedwater pump, that is not locked, sealed, or otherwise secured in position, is in the correct position.

b. At least once per 92 days on a STAGGERED TEST BASIS, tested pursuant to Specification 4.0.5, by:
1) Verifying that on recirculation flow each motor-driven pump develops a total head of greater than or equal to 3385 feet;
2) Verifying that on recirculation flow the steam turbine-driven pump develops a total head of greater than or equal to 3780 feet when the secondary steam supply pressure is greater than 800 psig. The provisions of Specification 4.0.4 are not applicable for entry into MODE 3.

MILLSTONE - UNIT 3 3/4 7-5 Amendment No. 96, 4-00, 4-27, 1-39, 206, *3

TABLE 4.7-1 SECONDARY COOLANT SYSTEM SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROQPAM TYPE OF MEASUREMEN [T SAMPLE AND ANALYSIS AND ANALYSIS FREQUENCY

1. Gross Radioactivity Determination
2. Isotopic Analysis for DOS] -:/a) Once per 31 days, when-EQUIVALENT 1-131 ever the gross radio-Concentration activity determination indicates concentrations greater than 10% of the allowable limit for radioiodines.

b) Ornee per 6 m.-on-ths., when-ever the gross radio-activity determination indicates concentrations less than or equal to 10%

of the allowable limit for radioiodines.

qAt the frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 3 3/4 7-8

Atitst 8 996 PLANT SYSTEMS 3/4.7.5 ULTIMATE HEAT SINK LIMITING CONDITION FOR OPERATION 3.7.5 The ultimate heat sink (UHS) shall be OPERABLE with an average water temperature L of less than or equal to 75°F. 4 APPLICABILITY: MODES 1, 2,3, and 4.

ACTION:

If the UHS temperature is above 75°F, monitor the UHS temperature once per hour for 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

If the UHS temperature does not drop below 75°F during this period, place the plant in at least HOT STANDBY 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 SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. During this period, if the UHS temperature increases above 77°F, place the plant in HOT STANDBY 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 SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

4e SURVEILLANCE REQUIREMENTS 4.7.5 The UHS shall be determined OPERABLE:

a. At l.t... @,,, per 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> by verifying the average water temperature to be within li *s
b. At least once per 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> by verifying the average water temperature to be within limits when the average water temperature exceeds 70'F.

ithe frequency specified in the Surveillance Frequency Control Program MILLSTONE - UNIT 3 3/4 7-13 Amendment No. +44

I For Information Only May 17,1995 3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 SHUTDOWN MARGIN LIMITING CONDITION FOR OPERATION 3.10.1 The SHUTDOWN MARGIN requirement of Specification 3.1.1.1 may be suspended for measurement of control rod worth and SHUTDOWN MARGIN provided reactivity equivalent to at least the highest estimated control rod worth is available for trip insertion from OPERABLE control rod(s).

APPLICABILITY: MODE 2.

ACTION:

a. With any full-length control rod not fully inserted and with less than the above reactivity equivalent available for trip insertion, immediately initiate and continue boration at greater than or equal to 33 gpm of a solution containing greater than or equal to 6600 ppm boron or its equivalent until the SHUTDOWN MARGIN required by Specification 3.1.1.1 is restored.
b. With all full-length control rods fully inserted and the reactor subcritical by less than the above reactivity equivalent, immediately initiate and continue boration at greater than or equal to 33 gpm of a solution containing greater than or equal to 6600 ppm boron or its equivalent until the SHUTDOWN MARGIN required by Specification 3.1.1.1 is restored.

SURVEILLANCE REQUIREMENTS 4.10.1.1 The position of each full-length control rod either partially or fully withdrawn shall be determined at least once per 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

4.10.1.2 Each full-length control rod not fully inserted shall be demonstrated capable of full insertion when tripped from at least the 50% withdrawn position within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to reducing the SHUTDOWN MARGIN to less than the limits of Specification 3.1.1.1.

MILLSTONE - UNIT 3 3/4 10-1 Amendment No. 113

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