ML15233A448
| ML15233A448 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 08/03/2016 |
| From: | Shawn Williams Plant Licensing Branch II |
| To: | Pierce C Southern Nuclear Operating Co |
| Williams S, NRR/DORL/LPL2-1 | |
| References | |
| CAC MF5317, CAC MF5318 | |
| Download: ML15233A448 (126) | |
Text
{{#Wiki_filter:UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 August 3, 2016 Mr. C. R. Pierce Regulatory Affairs Director Southern Nuclear Operating Company, Inc. P.O. Box 1295 I Bin 038 Birmingham, AL 35201-1295
SUBJECT:
JOSEPH M. FARLEY NUCLEAR PLANT, UNITS 1 AND 2 - ISSUANCE OF AMENDMENTS ADOPTING 21 PREVIOUSLY NRC-APPROVED TSTF TRAVELERS AND ONE REQUEST NOT ASSOCIATED WITH TSTF TRAVELERS (CAC NOS. MF5317 AND MF5318)
Dear Mr. Pierce:
The U.S. Nuclear Regulatory Commission (NRC or the Commission) has issued the enclosed Amendment No. 203 to Renewed Facility Operating License No. NPF-2, and Amendment No. 199 to Renewed Facility Operating License No. NPF-8, for the Joseph M. Farley Nuclear Plant, Units 1 and 2, respectively. The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated November 24, 2014, as supplemented by letter dated September 28, 2015. The amendments revise the TSs by adopting 21 previously NRC-approved Technical Specifications Task Force (TSTF) Travelers and one request not associated with TSTF Travelers. The TSTF-312-A, Revision 1, "Administratively Control Containment Penetrations," request is still under review and will be addressed in future correspondence. A list of the revisions are included in Enclosure 1 of the application and the enclosed Safety Evaluation.
C. Pierce A Notice of Issuance will be included in the Commission's biweekly Federal Register notice. Sincerely, Shawn A. Williams, Senior Project Manager Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-348 and 50-364
Enclosures:
- 1. Amendment No. 203 to NPF-2
- 2. Amendment No. 199 to NPF-8
- 3. Safety Evaluation cc w/enclosures: Distribution via Listserv
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SOUTHERN NUCLEAR OPERATING COMPANY. INC. ALABAMA POWER COMPANY DOCKET NO. 50-348 JOSEPH M. FARLEY NUCLEAR PLANT. UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 203 Renewed License No. NPF-2
- 1. The U.S. Nuclear Regulatory Commission (the Commission) has found that:
A. The application for amendment to the Joseph M. Farley Nuclear Plant, Unit 1, (the facility), Renewed Facility Operating License No. NPF-2, filed by Southern Nuclear Operating Company, Inc. (the licensee), dated November 24, 2014, as supplemented by letter dated September 28, 2015, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied. Enclosure 1
- 2. Accordingly, the license is amended by changes to the Technical Specifications, as indicated in the attachment to this license amendment; and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-2, is hereby amended to read as follows:
(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 203, are hereby incorporated in the renewed facility operating license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications.
- 3. This license amendment is effective as of its date of issuance and shall be implemented within 120 days of issuance.
FOR THE NUCLEAR REGULATORY COMMISSION I~ ichael T. Markley, Chief Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation
Attachment:
Changes to License No. NPF-2 and the Technical Specifications Date of Issuance: August 3 , 2O1 6
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SOUTHERN NUCLEAR OPERATING COMPANY. INC. ALABAMA POWER COMPANY DOCKET NO. 50-364 JOSEPH M. FARLEY NUCLEAR PLANT. UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 199 Renewed License No. NPF-8
- 1. The U.S. Nuclear Regulatory Commission (the Commission) has found that:
A. The application for amendment to the Joseph M. Farley Nuclear Plant, Unit 2, (the facility), Renewed Facility Operating License No. NPF-8, filed by Southern Nuclear Operating Company, Inc. (the licensee), dated November 24, 2014, as supplemented by letter dated September 28, 2015, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied. Enclosure 2
- 2. Accordingly, the license is amended by changes to the Technical Specifications, as indicated in the attachment to this license amendment; and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-8 is hereby amended to read as follows:
(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 199, are hereby incorporated in the renewed facility operating license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications.
- 3. This license amendment is effective as of its date of issuance and shall be implemented within 120 days of issuance.
FOR THE NUCLEAR REGULATORY COMMISSION
,;Lft!~
/Jf~ichael T. Markley, Chief
()- Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation
Attachment:
Changes to License No. NPF-8 and the Technical Specifications Date of Issuance: August 3, 201 6
ATTACHMENT TO LICENSE AMENDMENT NO. 203 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-2 DOCKET NO. 50-348 AND LICENSE AMENDMENT NO. 199 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-8 DOCKET NO. 50-364 Replace the following pages of the Renewed Facility Operating Licenses and Appendix "A" Technical Specifications {TSs) with the attached pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change. Remove Insert License License NPF-2, page 4 NPF-2, page 4 NPF-8, page 3 NPF-8, page 3 TSs (for both Units 1 and 2) TSs (for both Units 1 and 2) 1.1-5 3.3.1-21 3.8.1-3 1.1-5 3.3.1-21 3.8.1-3 1.3-2 3.3.2-9 3.8.1-8 1.3-2 3.3.2-9 3.8.1-8 1.3-6 3.3.2-10 3.8.1-9 1.3-6 3.3.2-10 3.8.1-9 1.3-7 3.3.2-11 3.8.1-12 1.3-7 3.3.2-11 3.8.1-12 1.4-1 3.3.2-12 3.8.1-13 1.4-1 3.3.2-12 3.8.1-13 1.4-2 3.3.4-1 3.8.4-3 1.4-2 3.3.4-1 3.8.4-3 1.4-3 3.4.2-1 3.8.4-4 1.4-3 3.4.2-1 3.8.4-4 1.4-4 3.4.5-2 3.8.9-1 1.4-4 3.4.5-2 3.8.9-1 1.4-5 3.4.5-3 3.9.1-1 1.4-5 3.4.5-3 3.9.1-1 1.4-6 3.4.9-1 3.9.3-2 1.4-6 3.4.9-1 3.9.3-2 1.4-7 3.4.9-2 3.9.5-1 1.4-7 3.4.9-2 3.9.5-1 3.1.4-2 3.4.11-1 3.9.5-2 3.1.4-2 3.4.11-1 3.9.5-2 3.1.8-1 3.4.11-3 5.5-3 3.1.8-1 3.4.11-3 5.5-3 3.2.4-1 3.4.12-4 5.5-13 3.2.4-1 3.4.12-4 5.5-13 3.2.4-3 3.5.2-1 5.5-14 3.2.4-3 3.5.2-1 5.5-14 3.3.1-9 3.5.5-1 5.5-15 3.3.1-9 3.5.5-1 5.5-15 3.3.1-14 3.5.5-2 5.5-16 3.3.1-14 3.5.5-2 5.5-16 3.3.1-15 3.6.3-6 3.3.1-15 3.6.3-6 3.3.1-16 3.6.6-1 3.3.1-16 3.6.6-1 3.3.1-17 3.7.5-1 3.3.1-17 3.7.5-1 3.3.1-18 3.7.5-2 3.3.1-18 3.7.5-2 3.3.1-19 3.7.5-3 3.3.1-19 3.7.5-3 3.3.1-20 3.8.1-2 3.3.1-20 3.8.1-2
(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 203, are hereby incorporated in the renewed license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications. (3) Additional Conditions The matters specified in the following conditions shall be completed to the satisfaction of the Commission within the stated time periods following the Issuance of the renewed license or within the operational restrictions indicated. The removal of these conditions shall be made by an amendment to the renewed license supported by a favorable evaluation by the Commission.
- a. Southern Nuclear shall not operate the reactor in Operational Modes 1 and 2 with less than three reactor coolant pumps in operation.
- b. Deleted per Amendment 13
- c. Deleted per Amendment 2
- d. Deleted per Amendment 2
- e. Deleted per Amendment 152 Deleted per Amendment 2
- f. Deleted per Amendment 158
- g. Southern Nuclear shall maintain a secondary water chemistry monitoring program to inhibit steam generator tube degradation.
This program shall include:
- 1) Identification of a sampling schedule for the critical parameters and control points for these parameters;
- 2) Identification of the procedures used to quantify parameters that are critical to control points;
- 3) Identification of process sampling points;
- 4) A procedure for the recording and management of data;
- 5) Procedures defining corrective actions for off control point chemistry conditions; and Farley - Unit 1 Renewed License No. NPF-2 Amendment No. 203
(2) Alabama Power Company, pursuant to Section 103 of the Act and 10 CFR Part 50, "Licensing of Production and Utilization Facilities," to possess but not operate the facility at the designated location in Houston County, Alabama in accordance with the procedures and limitations set forth in this renewed license. (3) Southern Nuclear, pursuant to the Act and 10 CFR Part 70, to receive, possess and use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Final Safety Analysis Report, as supplemented and amended; (4) Southern Nuclear, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (5) Southern Nuclear, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproducts, source or special nuclear material without restriction to chemical or physical form for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6) Southern Nuclear, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility. C. This renewed license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporate below: (1) Maximum Power Level Southern Nuclear is authorized to operate the facility at reactor core power levels not in excess of 2775 megawatts thermal. (2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 199, are hereby incorporated in the renewed license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications. (3) Delete per Amendment 144 (4) Delete Per Amendment 149 (5) Delete per Amend 144 Farley - Unit 2 Renewed License No. NPF-8 Amendment No. 199
Definitions 1.1
- 1. 1 Definitions PRESSURE AND The PTLR is the unit specific document that provides the TEMPERATURE LIMITS reactor vessel pressure and temperature limits, including REPORT (PTLR) heatup and cooldown rates and the Low Temperature Overpressure Protection System applicability temperature, for the current reactor vessel fluence period. These pressure and temperature limits shall be determined for each fluence period in accordance with Specification 5.6.6.
QUADRANT POWER TILT QPTR shall be the ratio of the maximum upper excore RA TIO (QPTR) detector calibrated output to the average of the upper excore detector calibrated outputs, or the ratio of the maximum lower excore detector calibrated output to the average of the lower excore detector calibrated outputs, whichever is greater. RATED THERMAL POWER RTP shall be a total reactor core heat transfer.rate to the (RTP) reactor coolant of 2775 MWt. REACTOR TRIP The RTS RESPONSE TIME shall be that time interval from SYSTEM(RTS)RESPONSE when the monitored parameter exceeds its RTS trip setpoint TIME at the channel sensor until loss of stationary gripper coil voltage. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and the methodology for verification have been previously *reviewed and approved by the NRG. SHUTDOWN MARGIN (SOM) SOM shall be the instantaneous amount of reactivity by which the reactor is subcritical or would be subcritical from its present condition assuming:
- a. All rod cluster control assemblies (RCCAs) are fully inserted except for the single RCCA of highest reactivity worth, which is assumed to be fully withdrawn.
However, with all RCCAs verified fully inserted by two independent means, it is not necessary to account for a stuck RCCA in the SOM calculation. With any RCCA not capable of being fully inserted, the reactivity worth of the RCCA must be accounted for in the determination of SOM; and (continued) Farley Units 1 and 2 1.1-5 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Completion Times 1.3
- 1. 3 Completion Times DESCRIPTION limits, the Completion Time(s) may be extended. To apply this (continued) Completion Time extension, two criteria must first be met. The subsequent inoperability:
- a. Must exist concurrent with the first inoperability; and
- b. Must remain inoperable or not within limits after the first inoperability is resolved.
The total Completion Time allowed for completing a Required Action to address the subsequent inoperability shall be limited to the more restrictive of either:
- a. The stated Completion Time, as measured from the initial entry into the Condition, plus an additional 24 hours; or
- b. The stated Completion Time as measured from discovery of the subsequent inoperability.
The above Completion Time extensions do not apply to those Specifications that have exceptions that allow completely separate re-entry into the Condition (for each train, subsystem, component, or variable expressed in the Condition) and separate tracking of Completion Times based on this re-entry. These exceptions are stated in individual Specifications. The above Completion Time extension does not apply to a Completion Time with a modified "time zero." This modified "time zero" may be expressed as a repetitive time (i.e., "once per 8 hours," where the Completion Time is referenced from a previous completion of the Required Action versus the time of Condition entry) or as a time modified by the phrase "from discovery ... " Farley Units 1 and 2 1.3-2 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Completion Times 1.3 1.3 Completion Times EXAMPLES EXAMPLE 1.3-3 (continued) ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One A.1 Restore 7 days Function X Function X train train to OPERABLE inoperable. status. B. One 8.1 Restore 72 hours Function Y Function Y train train to OPERABLE inoperable. status.
- c. One C.1 Restore 72 hours Function X Function X train train to OPERABLE inoperable. status.
AND OR One C.2 Restore 72 hours Function Y Function Y train train to OPERABLE inoperable. status. (continued) Farley Units 1 and 2 1.3-6 Amendment No. 203 (Unit 1)
- Amendment No. 199 (Unit 2)
Completion Times 1.3 1.3 Completion Times EXAMPLES EXAMPLE 1.3-3 (continued) When one Function X train and one Function Y train are inoperable, Condition A and Condition Bare concurrently applicable. The Completion Times for Condition A and Condition B are tracked separately for each train starting from the time each train was declared inoperable and the Condition was entered. A separate Completion Time is established for Condition C and tracked from the time the second train was declared inoperable (i.e., the time the situation described in Condition C was discovered). If Required Action C.2 is completed within the specified Completion Time, Conditions B and C are exited. If the Completion Time for Required Action A.1 has not expired, operation may continue in accordance with Condition A. The remaining Completion Time in Condition A is measured from the time the affected train was declared inoperable (i.e., initial entry into Condition A). It is possible to alternate between Conditions A, B, and C in such a manner that operation could continue indefinitely without ever restoring systems to meet the LCO. However, doing so would be inconsistent with the basis of the Completion Times. Therefore, there shall be administrative controls to limit the maximum time allowed for any combination of Conditions that result in a single contiguous occurrence of failing to meet the LCO. These administrative controls shall ensure that the Completion Times for those Conditions are not inappropriately extended. (continued) Farley Units 1 and 2 1.3-7 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Frequency 1.4 1.0 USE AND APPLICATION 1.4 Frequency PURPOSE The purpose of this section is to define the proper use and application of Frequency requirements. DESCRIPTION Each Surveillance Requirement (SR) has a specified Frequency in which the Surveillance must be met in order to meet the associated LCO. An understanding of the correct application of the specified Frequency is necessary for compliance with the SR. The "specified Frequency" is referred to throughout this section and each of the Specifications of Section 3.0, Surveillance Requirement (SR) Applicability. The "specified Frequency" consists of the requirements of the Frequency column of each SR as well as certain Notes in the Surveillance column that modify performance requirements. Sometimes special situations dictate when the requirements of a Surveillance are to be met. They are "otherwise stated" conditions allowed by SR 3.0.1. They may be stated as clarifying Notes in the Surveillance, as part of the Surveillance, or both. Situations where a Surveillance could be required (i.e., its Frequency could expire), but where it is not possible or not desired that it be performed until sometime after the associated LCO is within its Applicability, represent potential SR 3.0.4 conflicts. To avoid these conflicts, the SR (i.e., the Surveillance or the Frequency) is stated such that it is only "required" when it can be and should be performed. With an SR satisfied, SR 3.0.4 imposes no restriction. The use of "met" or "performed" in these instances conveys specific meanings. A Surveillance is "met" only when the acceptance criteria are satisfied. Known failure of the requirements of a Surveillance, even without a Surveillance specifically being "performed," constitutes a Surveillance not "met." "Performance" refers only to the requirement to specifically determine the ability to meet the acceptance criteria. Some Surveillances contain notes that modify the Frequency of performance or the conditions during which the acceptance criteria must be satisfied. For these Surveillances, the MODE~entry restrictions of SR 3.0.4 may not apply. Such a Surveillance is not required to be performed prior to entering a MODE or other specified condition in the Applicability of the associated LCO if any of the following three conditions are satisfied: (continued) Farley Units 1 and 2 1.4-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Frequency 1.4 1.4 Frequency DESCRIPTION a. The Surveillance is not required to be met in the MODE or other (continued) specified condition to be entered; or
- b. The Surveillance is required to be met in the MODE or other specified condition to be entered, but has been performed within the specified Frequency (i.e., it is current) and is known not to be failed; or
- c. The Surveillance is required to be met, but not performed, in the MODE or other specified condition to be entered, and is known not to be failed.
Examples 1.4-3, 1.4-4, 1.4-5, and 1.4-6 discuss these special situations. EXAMPLES The following examples illustrate the various ways that Frequencies are specified. In these examples, the Applicability of the LCO (LCO not shown) is MODES 1, 2, and 3. EXAMPLE 1.4-1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY Perform CHANNEL CHECK. 12 hours Example 1.4-1 contains the type of SR most often encountered in the Technical Specifications (TS). The Frequency specifies an interval (12 hours) during which the associated Surveillance must be performed at least one time. Performance of the Surveillance initiates the subsequent interval. Although the Frequency is stated as 12 hours, an extension of the time interval to 1.25 times the stated Frequency is allowed by SR 3.0.2 for operational flexibility. The measurement of this interval continues at all times, even when the SR is not required to be met per SR 3.0.1 (such as when the equipment is inoperable, a variable is outside specified limits, or the unit is outside the Applicability of the LCO). If the interval specified by SR 3.0.2 is exceeded while the unit is in a MODE or other specified condition in the Applicability of the LCO, and the performance of the Surveillance is not otherwise modified (refer to Example 1.4-3), then SR 3.0.3 becomes applicable. (continued) Farley Units 1 and 2 1.4-2 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Frequency 1.4 1.4 Frequency EXAMPLES EXAMPLE 1.4-1 (continued) If the interval as specified by SR 3.0.2 is exceeded while the unit is not in a MODE or other specified condition in the Applicability of the LCO for which performance of the SR is required, then SR 3.0.4 becomes applicable. The Surveillance must be performed within the Frequency requirements of SR 3.0.2, as modified by SR 3.0.3, prior to entry into the MODE or other specified condition or the LCO is considered not met (in accordance with SR 3.0.1) and LCO 3.0.4 becomes applicable. EXAMPLE 1.4-2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY Verify flow is within limits. Once within 12 hours after
~ 25% RTP 24 hours thereafter Example 1.4-2 has two Frequencies. The first is a one time performance Frequency, and the second is of the type shown in Example 1.4-1. The logical connector "AND" indicates that both Frequency requirements must be met. Each time reactor power is increased from a power level
< 25% RTP to:?: 25% RTP, the Surveillance must be performed within 12 hours.
The use of "once" indicates a single performance will satisfy the specified Frequency (assuming no other Frequencies are connected by "AND"). This typ'3 of Frequency does not qualify for the 25% extension allowed by SR 3.0.2. "Thereafter" indicates future performances must be established per SR 3.0.2, but only after a specified condition is first met (i.e., the "once" performance in this example). If reactor power decreases to
< 25% RTP, the measurement of both intervals stops. New intervals start upon reactor power reaching 25% RTP.
(continued) Farley Units 1 and 2 1.4-3 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Frequency 1.4 1.4 Frequency EXAMPLES EXAMPLE 1.4-3 (continued) SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY
----------------------------NOTE----------------------------
Not required to be performed until 12 hours after 225% RTP. Perform channel adjustment. 7 days The interval continues, whether or not the unit operation is < 25% RTP between performances. As the Note modifies the required performance of the Surveillance, it is construed to be part of the "specified Frequency." Should the 7 day interval be exceeded while operation is < 25% RTP, this Note allows 12 hours after power reaches 2 25% RTP to perform the Surveillance. The Surveillance is still considered to be performed within the "specified Frequency." Therefore, if the Surveillance were not performed within the 7 day (plus the extension allowed by SR 3.0.2) interval, but operation was
< 25% RTP, it would not constitute a failure of the SR or failure to meet the LCO. Also, no violation of SR 3.0.4 occurs when changing MODES, even with the 7 day Frequency not met, provided operation does not exceed 12 hours with power 2 25% RTP.
Once the unit reaches 25% RTP, 12 hours would be allowed for completing the Surveillance. If the Surveillance were not performed within this 12 hour interval, there would then be a failure to perform a Surveillance within the specified Frequency, and the provisions of SR 3.0.3 would apply. Farley Units 1 and 2 1.4-4 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Frequency 1.4 1.4 Frequency EXAMPLES EXAMPLE 1.4-4 (continued) SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY
--------------------------NOTE----------------------------
Only required to be met in MODE 1. Verify leakage rates are within limits. 24 hours Example 1.4-4 specifies that the requirements of this Surveillance do not have to be met until the unit is in MODE 1. The interval measurement for the Frequency of this Surveillance continues at all times, as described in Example 1.4-1. However, the Note constitutes an "otherwise stated" exception to the Applicability of this Surveillance. Therefore, if the Surveillance were not performed within the 24 hour interval (plus the extension allowed by SR 3.0.2), but the unit was not in MODE 1, there would be no failure of the SR nor failure to meet the LCO. Therefore, no violation of SR 3.0.4 occurs when changing MODES, even with the 24 hour Frequency exceeded, provided the MOOE change was not made into MOOE 1. Prior to entering MODE 1 (assuming again that the 24 hour Frequency were not met), SR 3.0.4 would require satisfying the SR. EXAMPLE 1.4-5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY I
----------------------------NOTE--------------------------
Only required to be performed in MODE 1. Perform complete cycle of the valve. 7 days (continued) Farley Units 1 and 2 1.4-5 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Frequency 1.4 1.4 Frequency EXAMPLES EXAMPLE 1.4-5 (continued) The interval continues, whether or not the unit operation is in MODE 1, 2, or 3 (the assumed Applicability of the associated LCO) between performances. As the Note modifies the required performance of the Surveillance, the Note is construed to be part of the "specified Frequency." Should the 7 day interval be exceeded while operation is not in MODE 1, this Note allows entry into and operation in MODES 2 and 3 to perform the Surveillance. The Surveillance is still considered to be performed within the "specified Frequency" is completed prior to entering MODE 1. Therefore, if the Surveillance were not performed within the 7 day (plus the extension allowed by SR 3.0.2) interval, but operation was not in MODE 1, it would not constitute a failure of the SR or failure to meet the LCO. Also, no violation of SR 3.0.4 occurs when changing MODES, even with the 7 day Frequency not met. provided operation does not result in entry into MODE 1. Once the unit reaches MODE 1 , the requirement for the Surveillance to be performed within its specified Frequency applies and would require that the Surveillance had been performed. If the Surveillance were not performed prior to entering MODE 1, there would then be a failure to perform a Surveillance within the specified Frequency, and the provisions of SR 3.0.3 would apply. EXAMPLE 1.4-6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY
---------------------------NOTE-------------------------
Not required to be met in MODE 3. Verify parameter is within limits 24 hours (continued) Farley Units 1 and 2 1.4-6 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Frequency 1.4 1.4 Frequency EXAMPLES EXAMPLE 1.4-6 (continued) Example 1.4-6 specifies that the requirements of this Surveillance do not have to be met while the unit is in MODE 3 (the assumed Applicability of the associated LCO is MODES 1, 2, and 3). The interval measurement for the Frequency of this Surveillance continues at all times. As described in Example 1.4-1, however, the Note constitutes an "otherwise stated" exception to the applicability of this Surveillance. Therefore, if the Surveillance were not performed within the 24 hour interval (plus the extension allowed by SR 3.0.2), and the unit was in MODE 3, there would be no failure of the SR nor failure to meet the LCO. Therefore, no violation of SR 3.0.4 occurs when changing MODES to enter MODE 3, even with the 24 hour Frequency exceeded, provided the MODE change does not result in entry into MODE 2. Prior to entering MODE 2 (assuming again that the 24 hour Frequency were not met), SR 3.0.4 would require satisfying the SR Farley Units 1 and 2 1.4-7 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Rod Group Alignment Limits 3.1.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2.1.2 Initiate boration to 1 hour restore SOM to within limit. AND B.2.2 Reduce THERMAL 2 hours POWER to ~ 75% RTP. AND 8.2.3 Verify SOM to be within Once per the limits provided in the 12 hours COLR. AND B.2.4 Perform SR 3.2.1.1 and 72 hours SR 3.2.1.2. AND 72 hours B.2.5 Perform SR 3.2.2.1. AND 5 days B.2.6 Re-evaluate safety analyses and confirm results remain valid for duration of operation under these conditions. C. Required Action and C.1 Be in MODE 3. 6 hours associated Completion Time of Condition B not met. Farley Units 1 and 2 3.1.4-2 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
PHYSICS TESTS Exceptions-MODE 2 3.1.8 3.1 REACTIVITY CONTROL SYSTEMS 3.1.8 PHYSICS TESTS Exceptions-MODE 2 LCO 3.1.8 During the performance of PHYSICS TESTS, the requirements of LCO 3.1.3, "Moderator Temperature Coefficient (MTC)"; LCO 3.1.4, "Rod Group Alignment Limits"; LCO 3.1.5, "Shutdown Bank Insertion Limits"; LCO 3.1.6, "Control Bank Insertion Limits"; and LCO 3.4.2, "RCS Minimum Temperature for Criticality" may be suspended and the number of required channels for LCO 3.3.1, "RTS Instrumentation," Functions 2, 3, and 17.e, may be reduced to 3 required channels, provided:
- a. THERMAL POWER is s 5% RTP;
- b. SOM is within the limits provided in the COLR; and
- c. RCS lowest loop average temperature is~ 531°F.
APPLICABILITY: MODE 2 during PHYSICS TESTS. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. SDM not within limit. A.1 Initiate boration to Immediately restore SOM to within limit. AND A.2 Suspend PHYSICS 1 hour TESTS exceptions.
- 8. THERMAL POWER not B.1 Open reactor trip Immediately within limit. breakers.
Farley Units 1 and 2 3.1.8-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
QPTR 3.2.4 3.2 POWER DISTRIBUTION LIMITS 3.2.4 QUADRANT POWER TILT RATIO (QPTR) LCO 3.2.4 The QPTR shall be:::; 1.02. APPLICABILITY: MODE 1 with THERMAL POWER~ 50% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. QPTR not within limit. A.1 Limit THERMAL 2 hours after each POWER to ~ 3% below QPTR determination RTP for each 1% of QPTR > 1.00. AND A.2 Determine QPTR. Once per 12 hours AND A.3 Perform SR 3.2.1.1, SR 24 hours after 3.2.1.2, and SR 3.2.2.1. achieving equilibrium conditions with THERMAL POWER limited by Required Action A.1 Once per 7 days thereafter (continued) Farley Units 1 and 2 3.2.4-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
QPTR 3.2.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.6 -----------N 0 TE----------- Perform Required Action A.6 only after Required Action A.5 is completed. Perform SR 3.2.1.1, SR 24 hours after 3.2.1.2, and SR 3.2.2.1. achieving equilibrium conditions at RTP OR Within 48 hours after increasing THERMAL POWER above the limit of Required Action A.1 B. Required Action and B.1 Reduce THERMAL 4 hours associated Completion POWER to< 50% RTP. Time not met. Farley Units 1 and 2 3.2.4-3 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS
NOTE Refer to Table 3.3.1-1 to determine which SRs apply for each RTS Function.
SURVEILLANCE FREQUENCY SR 3.3.1.1 --------NOTE--------- Not required to be performed for source range instrumentation until 1 hour after THERMAL POWER is< P~6. Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.1.2 ---------NOTE------------- Not required to be performed until 24 hours after THERMAL POWER is ~ 15% RTP. Compare results of calorimetric heat balance In accordance with calculation to power range channel output. Adjust the Surveillance power range channel output if calorimetric heat Frequency Control balance calculation results exceed power range Program channel output by more than +2% RTP. SR 3.3.1.3 --------------NOTES----------
- 1. Not required to be performed until 7 days after THERMAL POWER is ;:::: 50% RTP.
- 2. Performance of SR 3.3.1.9 satisfies this SR.
Compare results of the incore detector In accordance with measurements to Nuclear Instrumentation System the Surveillance (NIS) AFD. Adjust NIS channel if absolute difference Frequency Control is~ 3% RTP. Program Farley Units 1 and 2 3.3.1-9 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 1 of 8) Reactor Trip System Instrumentation APPLICABLE MODES OR NOMINAL OTHER TRIP SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE SETPOINT FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE
- 1. Manual Reactor 1.2 2 B SR 3.3.1 12 NA NA Trip 3 (a) , 4 (a), 5 (a) 2 c SR3.3.1.12 NA NA
- 2. Power Range Neutron Flux
- a. High 1.2 4 D SR 3.3.1.1 s 109.4% RTP 109%
SR3.3.1.2 RTP SR 3.3.1 .7 SR 3.3.1.10 SR 3.3.1.14
- b. Low 1(b) .2 4 E SR 3.3.1.1 s 25.4% RTP 25% RTP SR 3.3.1.8 SR 3.3.1.10 SR 3.3.1.14
- 3. Power Range 1.2 4 D SR 3.3.1.7 s 5.4% RTP 5%RTP Neutron Flux High SR 3.3.1.10 with lime with time Positive Rate SR 3.3.1.14 constant constant 2 2 sec 2 2 sec
- 4. Intermediate 1(b), 2(C) 2 F.G SR 3.3.1.1 $40% RTP 35% RTP Range Neutron SR 3.3.1.8 Flux SR 3.3.1.10 2(d) 2 H SR 3.3.1.1 S40% RTP 35% RTP SR 3.3.1.8 SR 3.3.1.10 (a) With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod Withdrawal.
(b) Below the P-1 O (Power Range Neutron Flux) interlocks. (c) Above the P-6 (Intermediate Range Neutron Flux) interlocks. (d) Below the P-6 {Intermediate Range Neutron Flux) interlocks. Farley Units 1 and 2 3.3.1-14 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 2 of 8) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT
- 5. Source Range 2(d) 2 l.J SR 3.3.1.1 ~ 1.3 E5 cps 1.0E5cps Neutron Flux SR 3.3.1.8 SR 3.3.1.10 3(a). 4(a). 5(a) 2 J.K SR 3.3.1.1 ~ 1.3 E5 cps 1.0E5cps SR3.3.1.7 SR 3.3.1.10 3(eJ, 4(e),5(e)
L SR 3.3.1.1 NIA NIA SR 3.3. 1.10
- 6. Overtemperature 1,2 3 E SR 3.3.1.1 Refer to Refer to llT SR 3.3.1.3 Note 1 (Page Note 1 (Page SR 3.3.1.7 3.3.1-20) 3.3 1-20)
SR 3.3.1.9 SR 3.3.1.10 SR 3.3.1.14
- 7. Overpower ll T 1,2 3 E SR 3.3.1.1 Refer to Refer to SR 3.3.1.7 Note 2 (Page Note 2 (Page SR 3.3.1.10 3.3.1-21) 3.3.1-21)
SR 3.3.1.14 (a) With RTBs closed and Rod Control System capable of rod withdrawal. (d) Below the P-6 (Intermediate Range Neutron Flux) interlocks. (e) With the RTBs open. In this condition, source range Function does not provide reactor trip but does provide indication. Amendment No. 203 (Unit 1) Farley Units 1 and 2 3.3.1-15 Amendment No. 199 (Unit 2)
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 3 of 8) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT
- 8. Pressurizer Pressure
- a. Low 3 M. SR 3.3.1.1 ;;;: 1862 psig 1865 psig SR 3.3.1.7 SR 3.3.1 10 SR 3.3.1.14
- b. High 1.2 3 E SR 3.3.1.1 s 2388 psig 2385 psig SR 3.3.1.7 SR 3.3.1 10 SR 3.3.1.14 9 Pressurizer Water 1 (f) 3 M SR 3.3.1.1 $ 92.4% 92%
Level-High SR 3.3.1.7 SR 3.3.1.10
- 10. Reactor Coolant 1 (f) 3 per loop M SR 3.3.1.1 ;;;: 89.7% 90%
Flow-low SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.14 (f) Above the P-7 (Low Power Reactor Trips Block) interlock. Farley Units 1 and 2 3.3.1-16 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 4 of 8) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT
- 11. Not used 1(f)
- 12. Undervoltage 3 M SR 3.3.1.6 2:: 2640 v 2680V RCPs SR3.3.1.10 1(1)
- 13. Underfrequency 3 M SR 3.3 1.6 2:: 56.9 Hz 57 Hz RCPs SR 3.3.1.10
- 14. Steam 1.2 3 perSG E SR 3.3.1.1 2::27.6% 28%
Generator (SG) SR 3.3.1.7 Waler Level - SR 33.1.10 Low Low SR 3.3.1.14 (f) Above the P-7 (low Power Reactor Trips Block) interlock. Farley Units 1 and 2 3.3.1-17 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 5 of 8) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL I SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT
- 15. Turbine Trip
- a. Low Auto Slop 1 (i) 3 p SR 3.3.1.10 ::o: 43 psig 45 psig Oil Pressure SR 3.3.1.13
- b. Turbine Throttle 1 (i) 4 a SR 3.3.1.10 NA NA Valve Closure SR 3.3.1.13
- 16. Safely Injection (SI) 1.2 2 trains R SR 3.3.1.12 NA NA Input from Engineered Safety Feature Actuation System (ESFAS)
- 17. Reactor Trip System Interlocks
- a. Intermediate 2 (d) 2 T SR 3.3.1.10 ;>: 6E-11 amp 1E-10amp Range Neutron SR 3.3.1.11 Flux, P-6
- b. Low Power 1 per train u NA NA NA Reactor Trips Block, P-7
- c. Power Range Neutron Flux, 4 u SR 3.3.1.10 SR 3.3.1.11 S30.4% RTP 30% RTP I P-8
- d. Power Range Neutron Flux, 4 u SR 3.3.1.10 SR 3.3.1.11 S50.4% RTP 50% RTP I P-9
- e. Power Range 1,2 4 T SR 3.3.1.10 ~7.6% RTP 8%RTP Neutron Flux, SR 3.3.1.11 and and P-10 s 10.4% RTP 10% RTP
- f. Turbine Impulse 2 u SR 3.3.1.1 s 11% 10%
Pressure, P-13 SR3.3.1.10 turbine turbine SR 3.3.1.11 power power (d) Below the P-6 (Intermediate Range Neutron Flux) interlocks. (i) Above the P-9 (Power Range Neutron Flux) interlock. Farley Units 1 and 2 3.3.1-18 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RTS Instrumentation 3.3.1 Table 3.3.1-1(page6 of 8) Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL I SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT
- 18. Reactor Trip 1,2 2 trains S,W SR 3.3.1.4 NA NA Breakers Ul 3 (a) , 4 (a) , 5 (a) 2 trains c.w SR 3.3.1.4 NA NA
- 19. Reactor Trip 1,2 1 each per v SR 3.3.1.4 NA NA Breaker RTB Undervoltage and 3 (a) , 4 (a) , 5 (a) c SR 3.3.1.4 NA NA Shunt Trip 1 each per Mechanisms RTB
- 20. Automatic Trip 1,2 2 trains R.W SR 3.3.1.5 NA NA Logic 3 (a) , 4 (a) , 5 (a) 2 trains C,W SR 3.3.1.5 NA NA (a) With RTBs closed and Rod Control System capable of rod withdrawal.
(j) Including any reactor trip bypass breaker that is racked in and closed for bypassing an RTB. Farley Units 1 and 2 3.3.1-19 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RTS Instrumentation 3.3.1 Table 3.3.1-1(page7 of8) Reactor Trip System Instrumentation Note 1: Overtemperature t:,, T The Overtemperature /J. T Function Allowable Value shall not exceed the following nominal Trip Setpoint by more than 0.4% of/::,,T span. (l+!4S) { (I+r1s)[ I ] } 6.T (I+ Tssl <6.To K1-K2(l+ r s) T-(l_+_T--) -T' +K3(P- P')-f1(.6.I) 2 65 Where: .!lT is measured loop .!lT, °F .
.!lT0 is the indicated loop .!lT at RTP and reference Tavg, °F.
s is the Laplace transform operator, sec- 1 . Tis the measured loop average temperature, °F. T' is the reference Tavg at RTP,::;; * °F. Pis the measured pressurizer pressure, psig. P' is the nominal pressurizer operating pressure =
- psig.
K, =
- K2 = *l°F K3 =*/psi t, 2!
- sec 't2 s:
- sec
't4 =
- sec 'ts s:
- sec 'ts s:
- sec f1(Lll) is a function of the indicated difference between top and bottom detectors of the power-range nuclear ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that:
*{* + (qt - qb)} when (qt - qb)s: * % RTP
*%of RTP when*% RTP <(qt - qb)s: *% RTP
*{(qt - qb) - *} when (qt - qb)> *% RTP Where q, and qb are percent RTP in the upper and lower halves of the core, respectively, and q, + qb is the total THERMAL POWER in percent RTP.
*as specified in the COLR Farley Units 1 and 2 3.3.1-20 Amendment No. 203 (Unit 1)
Amendment No. 199 (Unit 2)
RTS Instrumentation 3.3.1 Table 3.3.1-1(page8of8) Reactor Trip System Instrumentation Note 2: Overpower 6. T The Overpower 6.T Function Allowable Value shall not exceed the following nominal Trip Setpoint by more than 0.4% of Lff span.
~T (I+ t 4s)
(I+ t;s)
$~T-{K4-Ks o .
1' 35 ( I
- I+ T3s I+ t6s.
JT -K6[T--- -T"]-f2(~ 1 1+ r6s I)} Where: 6.T is measured loop 6.T, °F. 6.T 0 is the indicated loop 6.T at RTP and reference Tavg. °F. s is the Laplace transform operator, sec* 1 . T is the measured loop average temperature. °F. T" is the reference Tavg at RTP,:::; * °F. K4 --
- Ks= */°F for increasing Tavg Ks = */°F when T > T" K 5 = */°F for decreasing Tavg Ks = */°F when T $ T"
't3 2!
- sec
't4 =*sec
'ts :s;; *sec
'ts:::;* sec f 2(6.I) = *% RTP for all 6.1.
- as specified in the COLR Farley Units 1 and 2 3.3.1-21 Amendment No. 203 (Unit 1)
Amendment No. 199 (Unit 2)
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 1 of 4) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT
- 1. Safety Injection
- a. Manual Initiation 1,2,3,4 2 B SR 3.3.2.6 NA NA
- b. Automatic 1,2,3,4 2 trains c SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.3 and Actuation SR 3.3.2.8 Relays
- c. Containment 1,2,3 3 D SR 3.3.2.1 ::; 4.5 psig 4.0 psig Pressure - SR 3.3.2.4 High 1 SR 3.3.27 SR 3.3.2.9
- d. Pressurizer 1.2,3(a) 3 D SR 3.3.2.1 2 1847 psig 1850 psig Pressure - Low SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9
- e. Steam Line Pressure (1) Low 1.2,3(b) 1 per steam D SR 3.3.2.1 2 575(C) psig 5g5(c) psig line SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9 (2) High 1,2,3 3 per steam D SR 3.3.2.1 s 112 psig 100 psig Differential line SR 3.3.2.4 Pressure SR 3.3.2.7 Between SR 3.3.2.9 Steam Lines (a) Above the P-11 (Pressurizer Pressure) interlock.
(b) Above the P-12 (T avg - Low Low) interlock. (c) Time constants used in the lead/lag controller are t, 2 50 seconds and t2 ::; 5 seconds. Farley Units 1 and 2 3.3.2-9 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 2 of 4) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT
- 2. Containment Spray
- a. Manual Initiation 1.2,3,4 2 B SR 3.3.2.6 NA NA
- b. Automatic Actuation 1,2,3.4 2 trains c SR 3.3.2.2 NA NA Logic and Actuation SR 3.3.2.3 Relays SR 3.3.2.8
- c. Containment 1,2,3 4 E SR 3.3.2.1 s 28.3 psig 27 psig Pressure SR 3.3.2.4 High- 3 SR 3.3.2.7 SR 3.3.2.9
- 3. Containment Isolation
- a. Phase A Isolation (1) Manual 1,2.3.4 2 B SR 3.3.2.6 NA NA Initiation (2) Automatic 1,2,3,4 2 trains c SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.3 and Actuation SR 3.3.2.8 Relays (3) Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
- b. Phase B Isolation (1) Manual 1.2.3.4 2 B SR 3.3.2.6 NA NA Initiation (2) Automatic 1,2,J,4 2 trains c SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.3 and Actuation SR 3.3.2.8 Relays (J) Containment 1,2,3 4 E SR 3.3.2.1 s 28.3 psig 27 psig Pressure SR 3.3.2.4 High-3 SR 3.3.2.7 SR 3.3.2.9 Farley Units 1 and 2 3.3.2-10 Amendment No. 203 (Unit 1)
Amendment No. 199 (Unit 2)
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 3 of 4) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT
- 4. Steam Line Isolation 1 per steam
- a. Manual Initiation 1.2(d),3(d) line F SR 3.3.2.6 NA NA
- b. Automatic 1,2(d) ,3(d) 2 trains G SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.3 and Actuation SR 3.3.2.8 Relays
- c. Containment 1.2(d), 3(d) 3 D SR 3.3.2.1 s 17.5 psig 16.2 psig Pressure - High 2 SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9
- d. Steam Line 1.2(d),3(b)(d} 1 per steam D SR 3.3.2.1 ~ 575(c) psig sas(c} psig Pressure Low line SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9
- e. High Steam Flow 1,2(d) ,3(d) 2 per steam D SR 3.3.2.1 (e) (f) in Two Steam line SR 3.3.2.4 Lines SR 3.3.2.7 Coincident with 1,2(d),3(d) 1 per loop D SR 3.3.2.1 ~ 542.6°F 543°F Tavg - Low Low SR 3.3.2.4 SR 3.3.2.7 (b) Above the P-12 (Tavg - Low Low) interlock.
(c) Time constants used in the leadnag controller are t1 ~ 50 seconds and 12 s 5 seconds. (d) Except when one MSIV is closed in each steam line. (e) Less than or equal to a function defined as tiP corresponding to 40.3% full steam flow below 20% load, tiP increasing linearly from 40.3% full steam flow at 20% load to 110.3% full steam flow at 100% load. (f) Less than or equal to a function defined as tiP corresponding to 40% full steam flow between 0% and 20% load and then a l>P increasing linearly from 40% steam flow at 20% load to 110% full steam flow at 100% load. Farley Units 1 and 2 3.3.2-11 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 4 of 4) Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT
- 5. Turbine Trip and Feedwater Isolation 1.2 2 trains H SR 3.3.2.2 NA NA
- a. Automatic Actuation Logic and Actuation SR 3.3.2.3 Relays SR 3.3.2.8 SR 3.3.2.1 $ 82.4% 82%
- b. SG Water Level - 1,2 3 per SG High High (P-14) SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9
- c. Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
- 6. Auxiliary Feedwater 1,2,3 2 trains G SR 3.3.2.2 NA NA
- a. Automatic Actuation SR 3.3.2.3 Logic and Actuation SR 3.3.2.8 Relays
- b. SG Water Level - 1,2,3 3 per SG D SR 3.3.2.1 ~27.6% 28%
Low low SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9<*1
- c. Safety Injection Refer to Function 1 (Safety Injection) for all initiation functions and requirements.
- d. Undervoltage 1.2 3 SR 3.3.2.5 ~ 2640 volts 2680 volts Reactor Coolant SR 3.3.2.7 Pump SR 3.3.2.9
- e. Trip of all Main 2 per pump J SR 3.3.2.10 NA NA Feedwater Pumps
- 7. ESFAS Interlocks 1.2,3 2 trains L SR 3.3.2.2 NA NA
- a. Automatic Actuation logic and Actuation SR 3.3.2.3 Relays SR 3.3.2.8
- b. Reactor Trip, P-4 1,2,3 1 per train, 2 F SR 3.3.2.6 NA NA trains
- c. Pressurizer 1.2,3 3 K SR 3.3.2.4 ::: 2003 psig 2000 psig Pressure, P-11 SR 3.3.2.7
- d. Tavg - low Low, P-12 1,2,3 1 per loop K SR 3.3.2.4 ~ 542.6°F 543°F SR 3.3.2.7 ::: 545.4°F 545°F (Decreasing)
(Increasing) (g) Applicable to MDAFW pumps only. Farley Units 1 and 2 3.3.2-12 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Remote Shutdown System 3.3.4 3.3 INSTRUMENTATION 3.3.4 Remote Shutdown System LCO 3.3.4 The Remote Shutdown System Functions shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3. ACTIONS '1 --------------------------------------------------------N 0TE------------------------------------------------------- Separate Condition entry is allowed for each Function. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Restore required Function 30 days
- Functions inoperable. to OPERABLE status.
B. ------------NOTE----------- 8.1 Be in MODE 3. 6 hours Not applicable to Source Range Neutron Flux AND function.
... ------------------------------- 8.2 Be in MODE 4. 12 hours Required Action and associated Completion Time not met.
Farley Units 1 and 2 3.3.4-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RCS Minimum Temperature for Criticality 3.4.2 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.2 RCS Minimum Temperature for Criticality LCO 3.4.2 Each RCS loop average temperature (Tavg) shall be ~ 541°F. APPLICABILITY: MODE 1, MODE 2 with ke11 ~ 1.0. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Tavg in one or more RCS A.1 Be in MODE 3. 30 minutes loops not within limit. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.2.1 Verify RCS Tavg in each loop~ 541°F. In accordance with the Surveillance Frequency Control Program Farley Units 1 and 2 3.4.2-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RCS Loops - MODE 3 3.4.5 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. One required RCS loop C.1 Restore required RCS 1 hour not in operation, with Rod loop to operation. Control System capable of rod withdrawal. OR C.2 Place the Rod Control 1 hour System in a condition incapable of rod withdrawal. D. Two required RCS loops D.1 Place the Rod Control Immediately inoperable. System in a condition incapable of rod OR withdrawal. No RCS loop in AND operation. D.2 Suspend all operations Immediately involving a reduction of RCS boron concentration. AND D.3 Initiate action to restore Immediately one RCS loop to OPERABLE status and operation. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.5.1 Verify required RCS loops are in operation. In accordance with the Surveillance Frequency Control Program SR 3.4.5.2 Verify steam generator secondary side water levels In accordance with are 2: 30% (narrow range) for required RCS loops. the Surveillance Frequency Control Program Farley Units 1 and 2 3.4.5-2 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RCS Loops - MODE 3 3.4.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.5.3 Verify correct breaker alignment and indicated power In accordance with are available to the required pump that is not in the Surveillance operation. Frequency Control Program Farley Units 1 and 2 3.4.5-3 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Pressurizer 3.4.9 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.9 Pressurizer LCO 3.4.9 The pressurizer shall be OPERABLE with:
- a. Pressurizer water level s: 63.5% indicated; and
- b. Two groups of pressurizer heaters OPERABLE with the capacity of each group :::: 125 kW and capable of being powered from an emergency power supply.
APPLICABILITY: MODES 1, 2, and 3.
------------------------------------N 0 TE---------------------------------------------
Press urize r water level limit does not apply during:
- a. THERMAL POWER ramp > 5% RTP per minute; or
- b. THERMAL POWER step > 10% RTP.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Pressurizer water level A.1 Be in MODE 3. 6 hours not within limit. AND A.2 Fully insert all rods. 6 hours AND A.3 Place Rod Control 6 hours System in a condition incapable of rod withdrawal. AND A.4 Be in MODE 4. 12 hours B. One required group of B.1 Restore required group of 72 hours pressurizer heaters pressurizer heaters to inoperable. OPERABLE status. Farley Units 1 and 2 3.4.9-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Pressurizer 3.4.9 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Be in MODE 3. 6 hours associated Completion Time of Condition B not AND met. C.2 Be in MODE 4. 12 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.9.1 Verify pressurizer water level is::::: 63.5% indicated. In accordance with the Surveillance Frequency Control Program SR 3.4.9.2 Verify capacity of each required group of pressurizer In accordance with heaters is 2 125 kW. the Surveillance Frequency Control Program SR 3.4.9.3 Verify required pressurizer heaters are capable of In accordance with being powered from an emergency power supply. the Surveillance Frequency Control Program Farley Units 1 and 2 3.4.9-2 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Pressurizer PORVs 3.4.11 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) LCO 3.4.11 Each PORV and associated block valve shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3. ACTIONS
N 0 TE---------------------------------------------------------
S epa rate Condition entry is allowed for each PORV and each block valve. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more PORVs A.1 Close and maintain 1 hour inoperable and capable of power to associated being manually cycled. block valve. B. One PORV inoperable and B.1 Close associated block 1 hour not capable of being valve. manually cycled. AND B.2 Remove power from 1 hour associated block valve. AND B.3 Restore PORV to 72 hours OPERABLE status. Farley Units 1 and 2 3.4.11-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Pressurizer PORVs 3.4.11 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F. Two block valves F.1 Place associated 1 hour inoperable. PORVs in manual control. AND F.2 Restore one block valve 2 hours to OPERABLE status. G. Required Action and G.1 Be in MODE 3. 6 hours associated Completion Time of Condition F not AND met. G.2 Be in MODE4. 12 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.1 -----------NOTES----
- 1. Not required to be performed with block valve closed in accordance with the Required Actions of this LCO.
- 2. Only required to be performed in MODES 1 and 2.
Perform a complete cycle of each block valve. In accordance with the Surveillance Frequency Control Program Farley Units 1 and 2 3.4.11-3 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
LTOP System 3.4.12 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.12.1 Verify a maximum of one charging pump is In accordance with capable of injecting into the RCS when one or more the Surveillance RCS cold legs is s 180°F. Frequency Control Program SR 3.4.12.2 Verify a maximum of two charging pumps are In accordance with capable of injecting into the RCS when all RCS cold the Surveillance legs are> 180°F. Frequency Control Program SR 3.4.12.3 Verify each accumulator is isolated. In accordance with the Surveillance Frequency Control Program SR 3.4.12.4 Verify RHR suction isolation valves are open for each In accordance with required RHR suction relief valve. the Surveillance Frequency Control Program SR 3.4.12.5 ----------------------------N 0 TE-------------------------------- Only required to be met when complying with LCO 3.4.12.b. Verify RCS vent~ 2.85 square inches open. In accordance with the Surveillance Frequency Control Program SR 3.4.12.6 Verify each required RHR suction relief valve In accordance with setpoint. the lnservice Testing Program AND In accordance with the Surveillance Frequency Control Program Farley Units 1 and 2 3.4.12-4 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
ECCS- Operating 3.5.2 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.2 ECCS-Operating LCO 3.5.2 Two ECCS trains shall be OPERABLE.
-------------------------------------------NOTES-------------------------------------------
- 1. In MODE 3, the Residual Heat Removal or the Centrifugal Charging Pump flow paths may be isolated by closing the isolation valves for up to 2 hours to perform pressure isolation valve testing per SR 3.4.14.1.
- 2. Upon entry into MODE 3 from MODE 4, the breaker or disconnect device to the valve operators for MOVs 8706A and 8706B may be locked open for up to 4 hours to allow for repositioning from MODE 4 requirements.
APPLICABILITY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more trains A.1 Restore train(s) to 72 hours inoperable. OPERABLE status. B. Required Action and B.1 Be in MODE 3. 6 hours associated Completion Time not met. AND 8.2 Be in MODE4. 12 hours C. Less than 100% of the C.1 Enter LCO 3.0.3. Immediately ECCS flow equivalent to a single OPERABLE ECCS train available. Farley Units 1 and 2 3.5.2-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Seal Injection Flow 3.5.5 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.5 Seal Injection Flow LCO 3.5.5 Reactor coolant pump seal injection flow shall be within limits. APPLICABILITY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Seal injection flow not A.1 Adjust manual seal 8 hours within limit. injection throttle valves in accordance with SR 3.5.5.1. B. Required Action and 8.1 Be in MODE 3. 6 hours associated Completion Time not met. AND 8.2 Be in MODE 4. 12 hours Farley Units 1 and 2 3.5.5-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Seal Injection Flow 3.5.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.5.1 --------------------------NOTE-------------------------- Not required to be performed until 8 hours after the Reactor Coolant System pressure stabilizes at
~ 2215 psig ands; 2255 psig.
Verify manual seal injection throttle valves are In accordance with adjusted to give a flow within the limits of Figure the Surveillance 3.5.5-1 with the seal water injection flow control Frequency Control valve full open. Program Farley Units 1 and 2 3.5.5-2 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Containment Isolation Valves 3.6.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.3.3 --------------------------NOTES-----------------------------
- 1. Valves and blind flanges in high radiation areas may be verified by use of administrative means.
- 2. The blind flange on the fuel transfer canal flange is only required to be verified closed after each draining of the canal.
Verify each containment isolation manual valve and Prior to entering blind flange that is located inside containment and MODE 4from not locked, sealed, or otherwise secured and MODE 5 if not required to be closed during accident conditions is performed within closed, except for containment isolation valves that the previous are open under administrative controls. 92 days SR 3.6.3.4 Verify the isolation time of each automatic power In accordance with operated containment isolation valve in the IST the lnservice Program is within limits. Testing Program SR 3.6.3.5 Perform leakage rate testing for containment In accordance with penetrations containing containment purge valves the Surveillance with resilient seals. Frequency Control Program AND Within 92 days after opening the valve SR 3.6.3.6 Verify each automatic containment isolation valve In accordance with that is not locked, sealed or otherwise secured in the Surveillance position, actuates to the isolation position on an Frequency Control actual or simulated actuation signal. Program Farley Units 1 and 2 3.6.3-6 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Containment Spray and Cooling Systems 3.6.6 3.6 CONTAINMENT SYSTEMS 3.6.6 Containment Spray and Cooling Systems LCO 3.6.6 Two containment spray trains and two containment cooling trains shall be OPERABLE. APPLICABILITY: MODES 1, 2, 3, and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One containment spray A.1 Restore containment 72 hours train inoperable. spray train to OPERABLE status. B. Required Action and B.1 Be in MODE 3. 6 hours associated Completion Time of Condition A not AND met. B.2 ------------N 0 TE---------- LCO 3.0.4.a is not applicable when entering MODE4. Be in MODE 4. 54 hours C. One containment cooling C.1 Restore containment 7 days train inoperable. cooling train to OPERABLE status. Farley Units 1 and 2 3.6.6-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
AFWSystem 3.7.5
- 3. 7 PLANT SYSTEMS 3.7.5 Auxiliary Feedwater (AFW) System LCO 3.7.5 Three AFW trains shall be OPERABLE.
APPLICABILITY: MODES 1, 2, and 3. ACTIONS
N 0 TE-------------------------------------------------------
LCO 3.0.4b is not applicable. CONDITION REQUIRED ACTION COMPLETION TIME A. One steam supply to A.1 Restore affected equipment 7 days turbine driven AFW pump to OPERABLE status. inoperable. OR
---------NOTE----------
Only applicable if MODE 2 has not been entered following refueling. One turbine driven AFW pump inoperable in MODE 3 following refueling. B. One AFW train B.1 Restore AFW train to 72 hours inoperable for reasons OPERABLE status. other than Condition A. Farley Units 1 and 2 3.7.5-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
AFWSystem 3.7.5 ACTIONS (continued) CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Be in MODE 3. 6 hours associated Completion Time for Condition A or B AND not met. C.2 Be in MODE 4. 12 hours OR Two AFW trains inoperable. D. Three AFW trains D.1 --------------N 0 TE--------------- inoperable. LCO 3.0.3 and all other LCO Required Actions requiring MODE changes are suspended until one AFW train is restored to OPERABLE status. Initiate action to restore Immediately one AFW train to OPERABLE status. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1 ------------------------------N 0 TE------------------------------ AFW train(s) may be considered OPERABLE during alignment and operation for steam generator level control, if it is capable of being manually realigned to the AFW mode of operation. Verify each AFW manual, power operated, and In accordance automatic valve in each water flow path, and in both with the steam supply flow paths to the steam turbine driven Surveillance pump, that is not locked, sealed, or otherwise Frequency secured in position, is in the correct position. Control Program Farley Units 1 and 2 3.7.5-2 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
AFWSystem 3.7.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.2 ----------------------------NO TE------------------------------ Not required to be performed for the turbine driven AFW pump until 24 hours after ~ 1005 psig in the steam generator. Verify the developed head of each AFW pump at the In accordance flow test point is greater than or equal to the required with the lnservice developed head. Testing Program. SR 3.7.5.3 -----------------------------N 0 TE--------------------------------- In accordance AFW train(s) may be considered OPERABLE during with the alignment and operation for steam generator level Surveillance control, if it is capable of being manually realigned to Frequency the AFW mode of operation. Control Program Verify each AFW automatic valve that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal. SR 3.7.5.4 ---------------------------N 0 TES---------------------------------
- 1. Not required to be performed for the turbine driven AFW pump until 24 hours after ~ 1005 psig in the steam generator.
- 2. AFW train(s) may be considered OPERABLE In accordance during alignment and operation for steam with the generator level control, if it is capable of being Surveillance manually realigned to the AFW mode of Frequency operation. Control Program Verify each AFW pump starts automatically on an actual or simulated actuation signal.
SR 3.7.5.5 Verify the turbine driven AFW pump steam admission In accordance valves open when air is supplied from their respective with the air accumulators. Surveillance Frequency Control Program Farley Units 1 and 2 3.7.5-3 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
AC Sources - Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.3 Restore required offsite 72 hours circuit to OPERABLE status. B. One DG set inoperable. ------------------N 0 TE------------------ LCO 3.0.4c is applicable when only one of the three DGs is
' inoperable.
8.1 Perform SR 3.8.1.1 for 2 hours the required offsite circuit(s). AND Once per 8 hours thereafter AND 8.2 Declare required 4 hours from feature(s) supported by discovery of the inoperable DG set Condition B inoperable when its concurrent with required redundant inoperability of feature(s) is inoperable. redundant required feature(s) AND 8.3.1 Determine OPERABLE 24 hours DG set is not inoperable due to common cause failure. OR (continued) Farley Units 1 and 2 3.8.1-2 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
AC Sources - Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) 8.3.2 Perform SR 3.8.1.6 for 24 hours OPERABLE DG set. AND 8.4 Restore DG set to 10 days OPERABLE status. C. Two required offsite C.1 Declare required 12 hours from circuits inoperable. feature(s) inoperable discovery of when its redundant Condition C required feature(s) is concurrent with inoperable. inoperability of redundant required features AND C.2 Restore one required 24 hours offsite circuit to OPERABLE status. Farley Units 1 and 2 3.8.1-3 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
AC Sources -Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.7 -----------------------------NOTE------------------------------- This Surveillance shall not normally be performed in MODE 1 or 2. However, this surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Verify manual transfer of AC power sources from the In accordance with normal offsite circuit to the alternate required offsite the Surveillance circuit. Frequency Control Program SR 3.8.1.8 Verify each DG rejects a load greater than or equal to In accordance with its associated single largest post-accident load, and: the Surveillance Frequency Control
- a. Following load rejection, the speed is$; 75% of Program the difference between nominal speed and the overspeed trip setpoint; and
- b. Following load rejection, the voltage is
;:::. 3740 V ands: 4580 V.
Farley Units 1 and 2 3.8.1-8 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.9 -------------------------------N 0 TES----------------------------
- 1. All DG starts may be preceded by an engine prelube period.
- 2. This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, portions of the surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.
Verify on an actual or simulated loss of offsite power In accordance with signal: the Surveillance Frequency Control
- a. De-energization of emergency buses; Program
- b. Load shedding from emergency buses;
- c. DG auto-starts from standby condition and:
- 1. energizes permanently connected loads in ::; 12 seconds,
- 2. energizes auto-connected shutdown loads through automatic load sequencer,
- 3. maintains steady state voltage
- 2: 3740 V and:::; 4580 V,
- 4. maintains steady state frequency
- 2: 58.8 Hz and $ 61.2 Hz, and
- 5. supplies permanently connected and auto-connected shutdown loads for
- 2: 5 minutes.
Farley Units 1 and 2 3.8.1-9 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.13 ---------------------------NOTES----------------------------
- 1. This Surveillance shall be performed within 10 minutes of shutting down the DG after the DG has operated ~ 2 hours loaded ~ 4075 kW for the 4075 kW DGs and ~ 2850 kW for the 2850 kW DG.
Momentary transients below the minimum load specified do not invalidate this test.
- 2. All DG starts may be preceded by an engine prelube period.
Verify each DG starts and achieves, in ::;; 12 seconds, In accordance with voltage ~ 3952 V and frequency ~ 60 Hz. the Surveillance Frequency Control Program SR 3.8.1.14 -------------------------------NOTE------------------------------ This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, this surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Verify each DG: In accordance with the Surveillance
- a. Synchronizes with offsite power source while Frequency Control loaded with emergency loads upon a simulated Program restoration of offsite power;
- b. Transfers loads to offsite power source; and
- c. Returns to ready-to-load operation.
Farley Units 1 and 2 3.8.1-12 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
AC Sources -Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR3.8.1.15 Verify, with a DG operating in test mode and In accordance with connected to its bus, an actual or simulated ESF the Surveillance actuation signal overrides the test mode by returning Frequency Control DG to ready-to-load operation. Program SR 3.8.1.16 Verify interval between each sequenced load block is In accordance with within+/- 10% of design interval or 0.5 seconds, the Surveillance whichever is greater, for each emergency load Frequency Control sequencer. Program SR 3.8.1.17 -------------------------------NOTES-----------------------------
- 1. All DG starts may be preceded by an engine prelube period.
- 2. This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, portions of the surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.
Verify on an actual or simulated loss of offsite power In accordance with signal in conjunction with an actual or simulated ESF the Surveillance actuation signal: Frequency Control Program
- a. De-energization of emergency buses;
- b. Load shedding from emergency buses; and
- c. DG auto-starts from standby condition and:
- 1. energizes permanently connected loads in ~ 12 seconds, (continued)
Farley Units 1 and 2 3.8.1-13 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
DC Sources - Operating 3.8.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.4 Remove visible terminal corrosion, verify battery cell- In accordance to-cell and terminal connections are coated with with the anti-corrosion material. Surveillance Frequency Control Program SR 3.8.4.5 Verify post-to-post battery connection resistance of In accordance each cell-to-cell and terminal connection is ~ 150 with the microhms for the Auxiliary Building batteries and Surveillance
- 1500 microhms for the SWIS batteries Frequency Control Program SR 3.8.4.6 -------------------------------N 0 TE-------------------------------
Th is Surveillance may be performed in MODE 1, 2, 3, 4, 5, or 6 provided spare or redundant charger(s) placed in service are within surveillance frequency to maintain DC subsystem(s) OPERABLE. Verify each required Auxiliary Building battery In accordance with charger supplies~ 536 amps at~ 125 V for~ 4 hours the Surveillance and each required SWIS battery charger supplies Frequency Control
~ 3 amps at~ 125 V for~ 4 hours. Program SR 3.8.4.7 -----------------------------N 0 TES-------------------------------
- 1. The performance discharge test in SR 3.8.4.8 may be performed in lieu of the service test in SR 3.8.4.7 once per 60 months.
- 2. The modified performance discharge test in SR 3.8.4.8 may be performed in lieu of the service test at any time.
- 3. This Surveillance shall not normally be In accordance with performed for the Auxiliary Building batteries in the Surveillance MODE 1, 2, 3, or 4. However, portions of the Frequency Control Surveillance may be performed to reestablish Program OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.
(continued) Farley Units 1 and 2 3.8.4-3 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
DC Sources -Operating 3.8.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.7 (continued) Verify battery capacity is adequate to supply, and maintain in OPERABLE status, the required emergency loads for the design load profile described in the Final Safety Analysis Report, Section 8.3.2, by subjecting the battery to a service test. SR 3.8.4.8 -------------------------------NOTE------------------------------- This Surveillance shall not normally be performed for the Auxiliary Building batteries in MODE 1, 2, 3, or 4. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Verify battery capacity is :2: 80% of the manufacturer's In accordance with rating when subjected to a performance discharge the Surveillance test or a modified performance discharge test. Frequency Control Program AND 18 months when battery shows degradation or has reached 85% of expected life or 17 years, whichever comes first Farley Units 1 and 2 3.8.4-4 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Distribution Systems - Operating 3.8.9 3.8 ELECTRICAL POWER SYSTEMS 3.8.9 Distribution Systems-Operating LCO 3.8.9 Train A and Train B AC, DC, and AC vital bus electrical power distribution subsystems shall be OPERABLE. APPLICABILITY: MODES 1, 2, 3, and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more AC electrical A.1 Restore AC electrical 8 hours power distribution power distribution subsystems inoperable. subsystem(s) to OPERABLE status.
- 8. One or more AC vital 8.1 Restore AC vital bus 8 hours buses inoperable. subsystem(s) to OPERABLE status.
C. One Auxiliary Building DC C.1 Restore Auxiliary 2 hours electrical power distribution Building DC electrical subsystem inoperable. power distribution subsystem to OPERABLE status. Farley Units 1 and 2 3.8.9-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Boron Concentration 3.9.1 3.9 REFUELING OPERATIONS 3.9.1 Boron Concentration LCO 3.9.1 Boron concentrations of the Reactor Coolant System, the refueling canal, and the refueling cavity shall be maintained within the limit specified in the COLR. APPLICABILITY: MODE 6.
N 0 TE---------------------------------------------------------
0 n ly applicable to the refueling canal and refueling cavity when connected to the RCS. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Boron concentration not A.1 Suspend CORE Immediately within limit. ALTERATIONS. A.2 Suspend positive Immediately reactivity additions. A.3 Initiate action to restore Immediately boron concentration to within limit. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.1.1 Verify boron concentration is within the limit specified In accordance with in COLR. the Surveillance Frequency Control Program Farley Units 1 and 2 3.9.1-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Containment Penetrations 3.9.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.3.1 Verify each required containment penetration is in the In accordance required status. with the Surveillance Frequency Control Program SR 3.9.3.2 --------------------------------NO TE----------------------------- In accordance Not required to be met for containment purge and with the exhaust valve(s) in penetrations closed to comply Surveillance with LCO 3.9.3.c.1. Frequency Control Program Verify each required containment purge and exhaust valve actuates to the isolation position on an actual or simulated actuation signal. SR 3.9.3.3 --------------------------------NOTE----------------------------- In accordance Only required for an open equipment hatch. with the Surveillance Frequency Control Verify the capability to install the equipment Program hatch. Farley Units 1 and 2 3.9.3-2 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RHR and Coolant Circulation - Low Water Level 3.9.5 3.9 REFUELING OPERATIONS 3.9.5 Residual Heat Removal (RHR) and Coolant Circulation- Low Water Level LCO 3.9.5 Two RHR loops shall be OPERABLE, and one RHR loop shall be in operation.
------------------------------------------------N0 TES-----------------------------------------
- 1. One RHR loop may be inoperable and no RHR loop may be in the decay heat removal mode of operation for up to 2 hours for required surveillance testing.
- 2. All RHR pumps may be de-energized for :5 15 minutes when switching from one train to another provided:
- a. The core outlet temperature is maintained > 1O degrees F below saturation temperature.
- b. No operations are permitted that would cause a reduction of the Reactor Coolant System (RCS) boron concentration; and
- c. No draining operations to further reduce RCS water volume are permitted.
APPLICABILITY: MODE 6 with the water level < 23 ft above the top of reactor vessel flange. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Less than the required A.1 Initiate action to restore Immediately number of RHR loops required RHR loops to OPERABLE. OPERABLE status. A.2 Initiate action to Immediately establish ~ 23 ft of water above the top of reactor vessel flange. Farley Units 1 and 2 3.9.5-1 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
RH R and Coolant Circulation - Low Water Level 3.9.5 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. No RHR loop in operation. 8.1 Suspend operations Immediately involving a reduction in reactor coolant boron concentration. AND 8.2 Initiate action to restore Immediately one RHR loop to operation. AND 8.3 Close equipment hatch 4 hours and secure with four bolts. AND 8.4 Close one door in each 4 hours air lock. AND 8.5.1 Close each penetration 4 hours providing direct access from the containment atmosphere to the outside atmosphere with a manual or automatic isolation valve, blind flange, or equivalent. OR 8.5.2 Verify each penetration is 4 hours capable of being closed by an OPERABLE Containment Purge and Exhaust Isolation System. Farley Units 1 and 2 3.9.5-2 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.4 Radioactive Effluent Controls Program (continued)
- b. Limitations on the concentrations of radioactive material released in liquid effluents to unrestricted areas, conforming to 10 times the concentration stated in 10 CFR 20, Appendix B (to paragraphs 20.1001-20.2401),
Table 2, Column 2;
- c. Monitoring, sampling, and analysis of radioactive liquid and gaseous effluents in accordance with 10 CFR 20.1302 and with the methodology and parameters in the ODCM;
- d. Limitations on the annual and quarterly doses or dose commitment to a member of the public from radioactive materials in liquid effluents released from each unit to unrestricted areas, conforming to 10 CFR 50, Appendix I;
- e. Determination of cumulative dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the ODCM at least every 31 days.
Determination of projected dose contributions from radioactive effluents in accordance with the methodology in the ODCM at least every 31 days;
- f. Limitations on the functional capability and use of the liquid and gaseous effluent treatment systems to ensure that appropriate portions of these systems are used to reduce releases of radioactivity when the projected doses in a period of 31 days would exceed 2% of the guidelines for the annual dose or dose commitment, conforming to 10 CFR 50, Appendix I;
- g. Limitations on the dose rate resulting from radioactive material released in gaseous effluents to areas at and beyond the site boundary as follows:
- 1. For noble gases: Less than or equal to a dose rate of 500 mrem/year to the total body and less than or equal to a dose rate of 3000 mrem/year to the skin, and
- 2. For lodine-131, lodine-133, tritium, and for all radionuclides in particulate form with half lives greater than 8 days: Less than or equal to a dose rate of 1500 mrem/yearto any organ.
- h. Limitations on the annual and quarterly air doses resulting from noble gases released in gaseous effluents from each unit to areas beyond the site boundary, conforming to 10 CFR 50, Appendix I; (continued)
Farley Units 1 and 2 5.5-3 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP) (continued)
- b. Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;
- c. Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and
- d. Other appropriate limitations and remedial or compensatory actions.
A loss of safety function exists when, assuming no concurrent single failure, no concurrent loss of offsite power or no concurrent loss of onsite diesel generator(s), a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:
- a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or
- b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or
- c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.
The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system. 5.5.16 Main Steamline Inspection Program The three main steamlines from the rigid anchor points of the containment penetrations downstream to and including the main steam header shall be inspected. The extent of the inservice examinations completed during each inspection interval (IWA 2400, ASME Code, 1974 Edition, Section XI) shall provide 100 percent volumetric examination of circumferential and longitudinal pipe welds to the extent practical. The areas subject to examination are those defined in accordance with examination category C-G for Class 2 piping welds in Table IWC-2520. Farley Units 1 and 2 5.5-13 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.17 Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of containment as required by 10 CFR 50.54 (o) and 10 CFR 50, Appendix J, Option 8, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Periormance-Based Containment Leak-Test Program," dated September 1995, as modified by the following exception to NEI 94-01, Rev. 0, "Industry Guidelines for Implementing Periormance-Based Option of 10 CFR 50, Appendix J":
- 1. The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option 8 testing, will be periormed in accordance with the requirements of frequency specified by the ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.
- 2. The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be periormed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection !WE, except where relief has been authorized by the NRC.
The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa. is 43.8 psig. The maximum allowable containment leakage rate, La. at Pa. is 0.15% of containment air weight per day. Leakage rate acceptance criteria are:
- a. Containment overall leakage rate acceptance criterion is ::;; 1.0 La. During plant startup following testing in accordance with this program, the leakage rate acceptance criteria are*::;; 0.60 La for the combined Type B and C tests, and::;; 0.75 La for Type A tests;
- b. Air lock testing acceptance criteria are:
- 1. Overall air lock leakage rate is::;; 0.05 La when tested at~ Pa.
- 2. For each door, leakage rate is::;; 0.01 La when pressurized to~ 10 psig.
- c. During plant startup following testing in accordance with this program, the leakage rate acceptance criterion for each containment purge penetration flowpath is ::;; 0.05 La.
(continued) Farley Units 1 and 2 5.5-14 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.17 Containment Leakage Rate Testing Program (continued) The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program. The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program. 5.5.18 Control Room Integrity Program (CRIP) A Control Room Integrity Program (CRIP) shall be established and implemented to ensure that the control room integrity is maintained such that a radiological event. hazardous chemicals, or a fire challenge (e.g., fire byproducts, halon. etc.) will not prevent the control room operators from controlling the reactor during normal or accident conditions. The program shall require testing as outlined below. Testing should be performed when changes are made to structures, systems and components which could impact Control Room Impact (CRE) integrity. These structures, systems and components may be internal or external to the CRE. Testing should also be conducted following a modification or a repair that could affect CRE inleakage. Testing should also be performed if the conditions associated with a particular challenge result in a change in operating mode, system alignment or system response that could result in a new limiting condition. Testing should be commensurate with the type and degree of modification or repair. Testing should be conducted in the alignment that results in the greatest consequence to the operators. A CRIP shall be established to implement the following:
- a. Demonstrate, using Regulatory Guide (RG) 1.197 and ASTM E741, that CRE inleakage is less than the below values. The values listed below do not include 10 cfm assumed in accident analysis for ingress I egress.
i) 43 cfrn when the control room ventilation systems are aligned in the emergency recirculation mode of operation, ii) 600 cfm when the control room ventilation systems are aligned in the isolation mode of operation, and iii) 2,340 cfm when the control room ventilation systems are aligned in the normal mode of operation;
- b. Demonstrate that the leakage characteristics of the CRE will not result in simultaneous loss of reactor control capability from the control room and the hot shutdown panels; (continued)
Farley Units 1 and 2 5.5-15 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.18 Control Room Integrity Program (CRIP> (continued)
- c. Maintain a CRE configuration control and a design and licensing bases control program and a preventative maintenance program. As a minimum, the CRE configuration control program will determine whether the i) CRE differential pressure relative to adjacent areas and ii) the control room ventilation system flow rates, as determined in accordance with ASME N510-1989 or ASTM E2029-99, are consistent with the values measured at the time the ASTM E741 test was performed. If item i or ii has changed, determine how this change has affected the inleakage characteristics of the CRE. If there has been degradation in the inleakage characteristics of the CRE since the E741 test, then a determination should be made whether the licensing basis analyses remain valid. If the licensing basis analyses remain valid, the CRE remains OPERABLE.
- d. Test the CRE in accordance with the testing methods and at the frequencies specified in RG 1.197, Revision 0, May 2003.
The provisions of SR 3.0.2 are applicable to the control room inleakage testing frequencies. 5.5.19 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.
- a. The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program.
- b. Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1.
- c. The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.
Farley Units 1 and 2 5.5-16 Amendment No. 203 (Unit 1) Amendment No. 199 (Unit 2)
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 203 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-2 AND AMENDMENT NO. 199 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-8 SOUTHERN NUCLEAR OPERATING COMPANY, INC. ALABAMA POWER COMPANY JOSEPH M. FARLEY NUCLEAR PLANT. UNITS 1 AND 2 DOCKET NOS. 50-348 AND 50-364
1.0 INTRODUCTION
By letter dated November 24, 2014 (Agencywide Documents Access and Management System (ADAMS) Package Accession No. ML14335A689), as supplemented by letter dated September 28, 2015 (ADAMS Accession No. ML15271A223), Southern Nuclear Operating Company, Inc. (SNC or the licensee) submitted a license amendment request (LAR) to change the Technical Specifications (TSs) for the Farley Nuclear Plant, Units 1 and 2 (FNP or Farley). The proposed amendment requested to revise the Farley TSs by incorporating 22 U.S. Nuclear Regulatory Commission (NRC) approved generic changes that have been made to NUREG-1431, "Standard Technical Specifications - Westinghouse Plants" (Westinghouse Owners Group (WOG) Standard Technical Specifications (STS) - hereafter "WOG STS" or "STS"), since Farley adopted Improved Standard Technical Specifications (ISTS) based on Revision 1 of WOG STS, issued in April 1995. The changes identified by Technical Specification Task Force (TSTF) Traveler Numbers are as follows:
- 1. TSTF-27-A, Revision 3, "Revise SR [Surveillance Requirement] Frequency for Minimum Temperature for Criticality"
- 2. TSTF-46-A, Revision 1, "Clarify the CIV [containment isolation valve] surveillance to apply only to automatic isolation valves"
- 3. TSTF-87-A, Revision 2, "Revise 'RTBs [reactor trip breakers] open' and 'CROM [control rod drive mechanism] de-energized' Actions to 'incapable of rod withdrawal' "
Enclosure 3
- 4. TSTF-245-A, Revision 1, "AFW [auxiliary feedwater] train inoperable when in service"
- 5. TSTF-247-A, Revision 0. "Provide separate condition entry for each PORV [power operated relief valve] and block valve"
- 6. TSTF-248-A, Revision 0, "Revise Shutdown Margin definition for stuck rod exception"
- 7. TSTF-266-A, Revision 3, "Eliminate the Remote Shutdown System Table of Instrumentation and Controls"
- 8. TSTF-272-A, Revision 1, "Refueling Boron Concentration Clarification"
- 9. TSTF-273-A, Revision 2, "SFDP [Safety Function Determination Program] Clarifications"
- 10. TSTF-283-A, Revision 3, "Modify Section 3.8 Mode restriction Notes"
- 11. TSTF-284-A, Revision 3, "Add 'Met vs. Perform' to Specification 1.4, Frequency"
- 12. TSTF-308-A, Revision 1, "Determination of Cumulative and Projected Dose Contributions in RECP [Radioactive Effluent Controls Program]"
- 13. TSTF-312-A, Revision 1, "Administratively Control Containment Penetrations" Note that this safety evaluation and amendment to the license do not address this proposed change. This proposed change will be addressed in future correspondence.
- 14. TSTF-314-A, Revision 0, "Require Static and Transient Fa Measurement"
- 15. TSTF-315-A, Revision 0, "Reduce plant trips due to spurious signals to the NIS [nuclear instrumentation] during physics testing"
- 16. TSTF-325-A, Revision 0, "ECCS [Emergency Core Cooling System] Conditions and Required Actions with < 100% Equivalent ECCS Flow"
- 17. TSTF-340-A, Revision 3, "Allow 7 day Completion Time for a turbine driven AFW pump inoperable"
- 18. TSTF-343-A, Revision 1, "Containment Structural Integrity"
- 19. TSTF-349-A, Revision 1, "Add Note to LCO [Limiting Condition for Operation] 3.9.5 Allowing Shutdown Cooling Loops Removal from Operation"
- 20. TSTF-355-A, Revision 0, "Make Changes to RTS [Reactor Trip System] and ESF
[Engineered Safety Feature] Tables"
- 21. TSTF-371-A, Revision 1, "NIS Power Range Channel Daily SR [Surveillance Requirement]
TS Change to Address Low Power Decalibration"
- 22. TSTF-439-A, Revision 2, "Eliminate Second Completion Times Limiting Time From Discovery of Failure To Meet an LCO" The proposed changes also include one change that reflects ISTS requirements that were not covered by a TSTF Traveler as follows:
- 23. ISTS Adoption #1 - Revise Limiting Condition for Operation (LCO) 3.3.2, Engineered Safety Feature Actuation System (ESFAS) Interlock P-4 Required Action Completion Time In addition, the licensee originally proposed changes to revise the Farley LCO 3.5.5 Action Completion Time and Surveillance Requirement (SR) 3.5.5.1 Note to make them consistent with similar requirements in the Vogtle Electrical Generating Plant TSs; however, as explained in Section 3.0 of this safety evaluation, the licensee withdrew this request.
The supplement dated September 28, 2015, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staff's original proposed no significant hazards consideration determination as published in the Federal Register on February 3, 2015 (80 FR 5804).
2.0 REGULATORY EVALUATION
Title 10 of the Code of Federal Regulations (10 CFR) Section 50.36 requires TSs for nuclear reactors to include items in the following categories: (1) safety limits and limiting safety system settings; (2) LCOs; (3) SRs; (4) design features; and (5) administrative controls. The regulation does not specify the particular requirements to be included in a plant's TSs. On July 22, 1993, the Commission published the "Final Policy Statement on Technical Specifications Improvements for Nuclear Power Reactors" (58 FR 39132). This Final Policy Statement discussed criteria for determining which items must be included in the TSs as LCOs. These criteria were subsequently incorporated into 10 CFR 50.36 (60 FR 36953; July 19, 1995). Specifically, 10 CFR 50.36(c)(2)(ii) requires that an LCO be established for each item meeting one or more of the following criteria: Criterion 1: Installed instrumentation that is used to detect, and indicate in the control room, a significant abnormal degradation of the reactor coolant pressure boundary. Criterion 2: A process variable, design feature, or operating restriction that is an initial condition of a design basis accident or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier. Criterion 3: A structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.
Criterion 4: A structure, system, or component which operating experience or probabilistic risk assessment has shown to be significant to public health and safety. In determining the acceptability of TS changes, the NRC staff interprets the requirements of 10 CFR 50.36 using the guidance in the WOG STS and the associated Bases for the safety limits and LCOs, and the references cited in the Bases. As discussed in the Final Policy Statement, the NRC staff reviews, on a case-by-case basis, whether enforceable regulatory controls (e.g., 10 CFR 50.59) are needed for material moved to licensee-controlled documents, such as the updated safety analysis report, the Technical Requirements Manual, the TS Bases, the Quality Assurance Plan, etc. The NRC staff determines that plant-specific adoptions of STS format and content provide continued adequate protection when ( 1) the change is editorial, administrative, or provides clarification (i.e., no requirements are materially altered); (2) the change is more restrictive than the licensee's current requirement; or (3) the change is less restrictive than the licensee's current requirement, but nonetheless still affords adequate assurance of safety when judged against current regulatory standards and the facility's licensing basis. The NRC staff used Revision 4 of WOG STS, issued in April 2012, in its review of the TS changes proposed by Farley. The NRC staff also referred to the TSTF Travelers associated with the STS changes proposed for adoption by Farley.
3.0 TECHNICAL EVALUATION
3.1 TSTF-27-A, Revision 3, "Revise SR Frequency for Minimum Temperature for Criticality" The NRC did not issue a letter approving this change to WOG STS, Revision 1; however, this change was incorporated by the NRC into Revision 2 of the WOG STS issued in April 2001. This traveler revised WOG STS 3.4.2, "RCS Minimum Temperature for Criticality," to modify the Frequency of SR 3.4.2.1. TS SR 3.4.2.1 currently states: Verify RCS Tav 9 in each loop_::: 541°F at a frequency of "30 minutes thereafter," as modified by a Note which states, "Only required if low low Tavg alarm not reset and any RCS loop Tavg < 547°F." In a two-step process, the licensee first proposes to revise the Frequency from "Once within 30 minutes and every 30 minutes thereafter when the Tavg - Tret deviation alarm is not reset and any reactor coolant system (RCS) loop Tavg < 547°F." to "Once every 12 hours" in accordance with TSTF-27-A, Revision 3, which the NRC staff accepts, as discussed below. Then, in a second step, the licensee further proposes to revise the Frequency to "In accordance with the Surveillance Frequency Control Program," per TSTF-425.
The licensee explains the differences between the proposed changes and the approved traveler as follows: The frequency for ISTS SR 3.4.2.1, and its associated Note, is modified by TSTF-27-A. The changes in TSTF-27-A would modify the Frequency for SR 3.4.2.1 to a periodic frequency of 12 hours. As described in TS 5.5.21, Farley has adopted a Surveillance Frequency Control Program (SFCP) to control surveillances with periodic frequencies. The Frequency for SR 3.4.2.1, as modified by the changes identified in TSTF-27-A, will become a periodic frequency, and can be controlled under the SFCP. The Frequency for SR 3.4.2.1 is therefore modified to indicate that it is "In accordance with the Surveillance Frequency Control Program." The initial Frequency for this Surveillance will be 12 hours. The changes to SR 3.4.2.1 and the Bases for this SR are modified from that in TSTF-27-A to reflect this difference. NRC approval of the license change implementing the SFCP was provided in Amendment Numbers 185/180, dated July 18, 2011 (ACN ML11167A226).
NRC Staff Evaluation
(a) Assessment for the licensee's adoption of TSTF-27-A change: In this LAR, the licensee stated that TS 3.4.2, "RCS Minimum Temperature for Criticality," is designed to prevent criticality outside of the normal operating regime. There are no safety analyses that dictate the minimum temperature for criticality, but most low power accident analyses assume a specific starting temperature. During the approach to criticality, RCS temperature is closely watched. There are indications in the control room of deviations between actual and reference RCS temperature and on low RCS temperature to alert the operator if temperature is deviating from the program value. Verification that operation is within the Pressure and Temperature Limits Report limits is required when RCS pressure and temperature conditions are undergoing planned changes. In addition, the operators are trained to be sensitive to RCS temperature during approach to criticality and will ensure that the minimum temperature for criticality is met as criticality is approached. The proposed frequency of once every 12 hours is considered reasonable in view of the control room indication available to monitor RCS status. (b) Assessment for the licensee's adoption of TSTF-425 program for the change: The licensee's proposed changes to the Farley TSs are different from those contained in TSTF-27-A in that the "12-hours" is replaced with, "In accordance with the Surveillance Frequency Control Program." Farley has previously adopted TSTF-425-A, which allows relocation of selected SR frequencies from the TSs to a licensee-controlled document established in accordance with the SFCP described in TS 5. 5. 21. Adoption of the SFCP includes removal of the discussion of each surveillance frequency's basis from the Bases for frequencies to be governed by the SFCP. NRC staff approval of the license amendment for adoption of TSTF-425-A was provided in Amendment Nos. 185 and 180, dated July 18, 2011 (ADAMS Accession No. ML11167A226).
According to the approved TSTF-425, all surveillance frequencies can be relocated to the licensee's controlled document except:
- Frequencies that reference other approved programs for the specific interval (such as the lnservice Testing Program or the Primary Containment Leakage Rate Testing Program);
- Frequencies that are purely event driven (e.g., "each time the control rod is withdrawn to the 'full out' position");
- Frequencies that are event-driven but have a time component for performing the surveillance on a one- time basis once the event occurs (e.g., "within 24 hours after thermal power reaching<:: 95% RTP"); and
- Frequencies that are related to specific conditions (e.g., battery degradation, age, and capacity) or conditions for the performance of an SR (e.g., "drywell to suppression chamber differential pressure decrease").
The NRC staff concludes that relocation of the subject surveillance frequency is not considered to be within the scope of TSTF-425's four exceptions (discussed above) for which the TSTF-425 allowance is not allowed. Furthermore, the staff's approval letter referenced above for the licensee's TSTF-425 program stated: The licensee's adoption of TSTF-425 requires application of Nuclear Energy Institute (NEI) 04-10 in the SFCP. NEI 04-10 requires performance monitoring of structures, systems, and components (SSCs), whose surveillance frequency has been revised as part of a feedback process to assure that the change in test frequency has not resulted in degradation of equipment performance and operational safety. The monitoring and feedback includes consideration of maintenance rule monitoring of equipment performance. In the event of degradation of SSC performance, the surveillance frequency will be reassessed in accordance with the methodology, in addition to any corrective actions which may apply as part of the maintenance rule requirements. The performance monitoring and feedback specified in NEI 04-10 is sufficient to reasonably assure acceptable SSC performance and is consistent with Regulatory Position 3.2 of RG [Regulatory Guide] 1.177 "An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications." The NRC staff reviewed the licensee's submittals relative to the TSTF and WOG STS and concludes that relocation of this frequency to the licensee's SFCP meets 10 CFR 50.36 and is, therefore, acceptable. 3.2 TSTF-46-A, Revision 1. "Clarify the CIV surveillance to apply only to automatic isolation valves" The NRC did not issue a letter approving this change to WOG STS Revision 1; however, this change was incorporated by the NRC into Revision 2 of the WOG STS issued in April 2001. The TSTF deletes WOG STS, SR 3.6.3.5 (corresponding Farley SR 3.6.3.4), requirement to verify
the isolation time of "each power operated" containment isolation valve (CIV) and only requires verification of each "automatic power operated isolation valve." TS SR 3.6.3.4 currently states: Verify the isolation time of each power operated or automatic containment isolation valve in the IST [inservice testing] Program is within limits. The proposed change would revise the SR as follows: Verify the isolation time of each power operated and eaGh automatic power operated containment isolation valve in the IST Program is within limits.
NRC Staff Evaluation
The original wording states that the surveillance applied to power operated or automatic containment isolation valves, which could result in an interpretation that power operated valves that do not receive an automatic closure signal for design-basis events are also required to have a closure time associated with them. These changes removed the unintended requirement to verify isolation times of non-automatic power operated CIVs. Appropriate changes to the Bases for surveillance and LCO 3.6.3 were also made. The changes proposed for the corresponding CIV SRs in Farley TS 3.6.3 are identical to those contained in the traveler. These changes only clarify the original intended scope of CIVs covered by the existing surveillance, and therefore, are administrative. The current scope of these surveillances has not changed; there is no impact to safety. The NRC staff concludes that the requirements of 10 CFR 50.36(c)(3) continue to be met because the revised SR provides the appropriate surveillance to ensure the necessary quality of components is maintained and the LCO will be met. 3.3 TSTF-87-A, Revision 2. "Revise 'RTBs open' and 'CROM de-energized' Actions to
'incapable of rod withdrawal' "
The NRC did not issue a letter approving this change to STS Revision 1; however, this change was incorporated by the NRC into Revision 2 of the WOG STS issued in April 2001. This traveler modifies certain Required Actions in WOG STS 3.4.5, "RCS Loops - MODE 3," and STS 3.4.9, "Pressurizer," as explained in the licensee's proposed changes. The following specifies changes to LCOs 3.4.5 and 3.4.9:
- TS LCO 3.4.5 currently specifies the following Conditions and Required Actions:
Current Condition C states: One required RCS loop not in operation, and reactor trip breakers closed and Rod Control System capable of rod withdrawal.
Revised Condition C would state: One required RCS loop not in operation, and reactor trip breakers closed aR6 with Rod Control System capable of rod withdrawal. Current Required Action C.2 states: De-energize all control rod drive mechanisms (CRDMs) in 1 hour. Revised Required Action C.2 would state: Place the Rod Control System in a condition incapable of rod withdrawal in 1 hour. Current Required Action D.1 states: De-energize all CRDMs immediately. Revised Required Action D.1 would state: Place the Rod Control System in a condition incapable of withdrawal.
- TS LCO 3.4.9 currently specifies the following Conditions and Required Actions:
Current Required Actions A.1 and A.2 state: Be in MODE 3 with reactor trip breakers open in 6 hours, AND Be in MODE 4 in 12 hours Revised Required Action A.1 would state: Be in MODE 3 in 6 hours. The proposed change renumbers Required Action A.2 to Required Action A.4 (with no change) and adds new Required Actions A.2 and A.3 as follows. New Required Action A.2 states: Fully insert all rods in 6 hours, AND
New Required Action A.3 states: Place Rod Control System in a condition incapable of rod withdrawal in 6 hours, AND
NRC Staff Evaluation
The licensee's proposed changes are the same as those contained in the traveler. In this LAR, the licensee states that the intent of these Required Actions is to assure that rods cannot be withdrawn and thereby increase potential of heat input to the reactor coolant. While the proposed changes replace the specific methods of precluding rod withdrawal, rod withdrawal remains assured of being prohibited by plant/system configuration. The specific methods are still provided in the Bases as examples to guide plant operators, if needed. In addition, the TSTF states for Westinghouse plants (Farley is a Westinghouse facility) that these changes are necessary to eliminate undesirable secondary effects of opening the reactor trip breakers (RTB). In particular, by opening the RTBs, plant interlock P-4 is tripped, which results in a trip of the main turbine and will close the main and bypass feedwater lines if RCS Tavg is below the low setpoint in MODE 3. Forcing reliance on Auxiliary Feedwater (AFW) in this condition is not the intent, nor is it desirable, over continued use of normal feedwater. The NRC staff concludes that the requirements of 10 CFR 50.36(c)(2) continue to be met because the minimum performance level of equipment needed for safe operation of the facility is contained in the LCO, and the appropriate remedial measures are specified if the LCO is not met. Based on the above, the NRC staff concludes that these changes are acceptable. In addition, the change is consistent with guidance in NUREG-1431, Revision 4, because the TSTF-87-A, Revision 2, changes have been incorporated into the Farley TSs. 3.4 TSTF-245-A. Revision 1, "AFW train inoperable when in service" The NRC did not issue a letter approving this change to WOG STS, Revision 1; however, this change was incorporated by the NRC into Revision 2 of the WOG STS issued in April 2001. This traveler revised WOG STS 3.7.5. The proposed change modifies TS SRs 3.7.5.1, 3.7.5.3, and 3.7.5.4 by adding a Note stating that, "AFW train(s) may be considered OPERABLE during alignment and operation for steam generator (SG) level control, if it is capable of being manually realigned to the AFW Mode of operation." TS SR 3.7.5.1 currently specifies the following Note: Not required to be performed for the AFW flow control valves when :5 10% RTP or when the AFW system is not in automatic control.
TS SR 3.7.5.3 currently states: Verify each AFW automatic valve that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal. TS SR 3.7.5.4 currently specifies the following Note:
--------------------------------------N()TE-------------------------------------------
Not required to be performed for the turbine driven AFW pump until 24 hours after ;;::: 1005 psig in the steam generator. The proposed change (a) replaces the current Note (stated above) in SR 3.7.5.1 with the following Note, (b) adds the same Note below, in SR 3.7.5.3, and (c) renumbers the current Note (stated above) in SR 3.7.5.4 as Note 1 and adds the same Note below as Note 2.
------------------------------------N ()TE--------------------------------------------
AFW train(s) may be considered ()PERABLE during alignment and operation for steam generator level control, if it is capable of being manually realigned to the AFW mode of operation." The licensee explains the differences between the proposed changes and the approved traveler as follows: Farley SR 3.7.5.1 contains a Note stating that the SR is, "Not required to be performed for the AFW flow control valves when s 10% RTP or when the AFW flow control system is not in manua!l*l control." This Note does not appear in the ISTS, and functionally serves the same purpose as the Note that is added in TSTF-245-A. The existing Note in SR 3.7.5.1 is deleted and replaced with the SR Note from TSTF-245-A, and conforming changes to the Bases text are made to reflect deletion of the plant-specific Note. ISTS SR 3.7.5.3 contains a note stating that the SR is "Not applicable in M()DE 4 when steam generator is relied upon for heat removal." The approved traveler replaces this note. Farley SR 3.7.5.3 does not currently include this note, and will add the note identified in the approved Traveler under this change.
- NRC staff notes that the licensee incorrectly quoted the Farley SR 3.7.5.1. The Farley SR 3.7.5.1 Note states:
Not required to be performed for the AFW flow control valves when s 10% RTP or when the AFW flow control system is not in automatic control.
NRC Staff Evaluation
The licensee proposed changes to the requirements of Farley TS SRs 3.7.5.1, 3.7.5.3, and 3.7.5.4 in order to conform to the provisions in TSTF-245, Revision 1 (ADAMS Accession
No. ML040611028). The proposed changes would add a Note to these SRs that would allow an AFW train to be considered operable during low power operation when its components are being operated manually for SG level control in MODES 1, 2, and 3, and can be manually realigned for the AFW mode of operation. The TSTF evaluation includes a letter from the NRC staff to the licensee for the Indian Point Nuclear Generating plant, dated May 23, 1997, which outlines the NRC staff's position on taking credit for manual actions. The letter states, in part, "In general, it is not appropriate to take credit for manual action in place of automatic action for protection of safety limits to consider equipment operable." Thus, credit for any manual actions should be part of the plant's licensing basis. In order to credit manual actions, the licensee must evaluate physical differences between automatic and manual actions and the ability to perform the manual actions. The letter states that the NRC staff has made a determination that for the AFW system on a typical pressurized-water reactor, such as Farley, Units 1 and 2, manual actions versus automatic operation are permissible in certain circumstances. In particular, an AFW train may be considered fully operable when an operator is controlling AFW manually to maintain SG levels in the normal control band during startup, normal shutdown, and hot standby conditions. TS SR 3.7.5.1 verifies the correct alignment of manual, power operated, and automatic valves in the AFW system water and steam supply flow paths provides assurance that the proper flow paths will exist for AFW operation. While the licensee is utilizing AFW in manual during low power operations (i.e., during unit startup and shutdown), the plant operators must take manual control of the AFW pump(s) and control valves to maintain proper SG level. In doing so, the valves may no longer be in the position assumed in the accident analyses. The licensee's application states that the Farley Operating Procedures and Emergency Operating Procedures contain steps to support realignment of the AFW system from the manual SG level control mode to the emergency operation mode when required. The NRC staff concludes that the licensee's proposed changes are consistent with TSTF-245-A in the Farley TSs. The NRC staff concludes that the requirements of 10 CFR 50.36(c)(3) continue to be met because the revised SR provides the appropriate surveillance to ensure the necessary quality of components is maintained and the LCO will be met. Based on the above, the NRC staff concludes the proposed changes are acceptable. 3.5 TSTF-247-A, Revision 0. "Provide separate condition entry for each PORV [Power Operated Relief Valve) and block valve" The NRC did not issue a letter approving this change to WOG STS, Revision 1; however, this change was incorporated by the NRC into Revision 2 of the WOG STS issued in April 2001. This traveler modified WOG STS 3.4.11, "Pressurizer Power Operated Relief Valves (PORVs)," to extend the Actions Note, which allows separate Condition entry for each PORV to apply also for each block valve. Current Farley TS and Proposed Changes The licensee proposed the following changes to Farley TS 3.4.11. (Added text is shown in bold face; removed text is lined out.)
- The Actions table Note is revised as follows:
Separate Condition entry is allowed for each PORV and each block valve.
- Condition F is revised as follows:
F. More than one Two block va+ire-valves inoperable.
- Required Action F.3 is deleted as follows:
H Restore remaining block valve to OPERABLE status. I 72 hours
NRC Staff Evaluation
Currently, the Note in LCO 3.4.11 allows a separate condition entry for each PORV. The LCO requires each PORV and associated block value to be operable. This allows each PORV to be treated separately with a separate Completion Time for each inoperable PORV. The proposed change adds the PORV block valves to the Note, which would, along with PORVs, also allow the PORV block valves to be treated as separate entities with a separate Completion Time for each inoperable PORV block valve. The change extends the separate condition entry for the PORVs in the current TSs to the PORV block valves. This treats the PORV block valves in the same manner as the PORVs. Since the PORV block valves are being credited as backup valves to the PORVs, the NRC staff concludes that this proposed change is acceptable. The proposed Condition Fis modified to apply when two block valves are inoperable. The licensee's original application submittal proposed to delete Required Actions F.1 and F.3 in TS 3.4.11. However, per the submittal dated September 28, 2015, in response to the staff's RAI letter, dated August 14, 2015 (ADAMS Accession No. ML15195A468), the licensee withdrew the proposed deletion of LCO 3.4.11, Required Action F.1, since according to the licensee, the TSTF Bases for elimination of Required Action F.1 are based on low temperature overpressure protection (LTOP) considerations. According to the licensee, these considerations are not applicable to Farley; therefore, the licensee determined that the proposed change to F.1 was not needed. The licensee's current Conditions and Required Actions provide compensatory actions for separate condition entry for each block valve, such as when a PORV block valve is declared inoperable. LCO 3.4.11, Condition C, Required Action C.1, requires placing the associated PORV in manual control within 1 hour AND Required Action C.2 requires restoring the block valve to operable status within 72 hours. These required actions and Completion Times are not affected by the proposed changes. TS 3.4.11 is applicable in MODES 1 through
- 3. LTOP protection is required in MODE 4 when the temperature of one or more RCS cold legs is less than the LTOP system applicability temperature specified in the Pressure and Temperature Limits Report and cold leg temperature is below 200 degrees Fahrenheit (°F) for MODE 5 and MODE 6, when one or more reactor vessel head closure bolts are less than fully tensioned. If a licensee has inoperable block valves, the PORVs would need to be taken out of manual control once MODE 3 is exited in order to provide LTOP protection, if required.
When a PORV block valve is declared inoperable, there is entry into Condition C, one block valve inoperable. The required actions are (1) to place the associated PORV in manual control within 1 hour and (2) restore the block valve to operable status within 72 hours. These required actions and Completion Times are not being changed in this amendment. Therefore, there would be a separate entry into Condition C for each inoperable block valve requiring the associated PORV to be in manual control within 1 hour. The NRC staff concludes that allowing separate condition entry for PORV block valves makes Required Action F.3 redundant to Required Action C.2, and is, therefore, no longer necessary. Therefore, the NRC staff finds that a separate condition entry for the PORV block valves is acceptable. The NRC staff concludes that the requirements of 10 CFR 50.36(c)(2) continue to be met because the minimum performance level of equipment needed for safe operation of the facility is contained in the LCO, and the appropriate remedial measures are specified if the LCO is not met. Based on the above, the NRC staff concludes the proposed changes are acceptable. 3.6 TSTF-248-A. Revision 0, "Revise Shutdown Margin definition for stuck rod exception" The NRC approved this change to WOG STS, Revision 1, on October 31, 2000. This traveler revised WOG STS 1.1. This change revised the definition of shutdown margin (SOM) to eliminate the requirement that SOM calculations must assume the single rod cluster control assembly (RCCA) of highest worth is fully withdrawn if all RCCAs can be verified to be fully inserted by two independent means. The Farley TS Section 1.1 definition of the defined term "SHUTDOWN MARGIN (SOM)" currently includes the following paragraph a.: All rod cluster control assemblies (RCCAs) are fully inserted except for the single RCCA of highest reactivity worth, which is assumed to be fully withdrawn. With any RCCA not capable of being fully inserted, the reactivity worth of the RCCA must be accounted for in the determination of SOM; and The proposed change to paragraph a. is as follows. (The added text is shown in bold face.) All rod cluster control assemblies (RCCAs) are fully inserted except for the single RCCA of highest reactivity worth, which is assumed to be fully withdrawn. However, with all RCCAs verified fully inserted by two independent means, it is not necessary to account for a stuck RCCA in the SOM calculation. With any RCCA not capable of being fully inserted, the reactivity worth of the RCCA must be accounted for in the determination of SOM; and
NRC Staff Evaluation
The proposed Farley TSs change the definition of SOM to reflect the definition in the latest revision to WOG STS. The revised definition includes a provision allowing an exception to the
highest reactivity RCCA penalty if there are two independent means of confirming that all RCCAs, or control rods, are fully inserted in the core. SOM is the instantaneous amount of reactivity by which the reactor is subcritical or would be subcritical from its present condition if all RCCAs are fully inserted, except for the single RCCA of highest reactivity worth, which is assumed to be fully withdrawn. The Farley core operating limits report (COLR) is the unit-specific document that provides cycle-specific parameter limits for the current fuel cycle. These cycle-specific parameter limits are determined for each fuel cycle. The analytical methods used to determine the core operating limits shall be those previously reviewed and approved by the NRC, and specifically, those described in the documents listed in Farley TS Section 5.6.5, "Core Operating Limits Report (COLR)." The COLR, in conjunction with the TSs, ensures for each specific fuel cycle that all parameters, including SOM, meet the licensing basis requirements. While the control rods are withdrawn from the reactor core, the required amount of SOM includes the penalty for the single control rod of highest reactivity worth, which is assumed to be fully withdrawn. Once all control rods are fully inserted into the reactor and verified by two independent means, the SDM limit in the COLR assures that adequate SOM as assumed in the updated final safety analysis report for accidents, and transients that initiate from a shutdown condition are meet. Once all control rods have been verified to be fully inserted into the core, requiring the SDM calculation to include the penalty for the single control rod of highest reactivity worth fully withdrawn would be overly conservative. Per the Farley final safety analysis report (FSAR), the axial position of shutdown rods and control rods is indicated by two separate and independent systems, which are the Bank Demand Position Indication System (commonly called group step counters) and the Digital Rod Position Indication (DRPI) System. The Bank Demand Position Indication System counts the pulses from the rod control system that moves the rods. There is a one-step counter for each group of rods. Individual rods in a group all receive the same signal to move and should, therefore, all be at the same position indicated by the group step counter for that group. The Bank Demand Position Indication System is considered highly precise (+/- 1 step or+/- % inch). If a rod does not move one step for each demand pulse, the step counter will still count the pulse and incorrectly reflect the position of the rod. The DRPI System provides a highly accurate indication of actual control rod position, but at a lower precision than the step counters. This system is based on inductive analog signals from a series of coils spaced along a hollow tube with a center-to-center distance of 3.75 inches, which is six steps. To increase the reliability of the system, the inductive coils are connected alternately to data systems A or B. Thus, if one system fails, the DRPI will go on half accuracy, with an effective coil spacing of 7.5 inches, which is 12 steps. Therefore, the normal indication accuracy of the DRPI System is +/- 4 steps (all coils operable and 1 step added for manufacturing and temperature tolerances), and the maximum uncertainty is+/- 10 steps (only one data system A or B coils operable). With an indicated deviation of 12 steps between the group step counter and DRPI, the maximum deviation between actual rod position and the demand position could be 22 steps. The deviation alarm alerts the operator to rod deviation with respect to the group position in excess of 5 percent of span (12 steps). Therefore, since indication from one system is sufficient to maintain alignment within 24 steps, operation with one system (in the event of failure of the other) is acceptable.
The NRC staff has reviewed the independence of the control rod indication and finds that Farley has two independent systems that verify all rods are fully inserted. The change in the SOM definition does not change continued compliance with all applicable regulatory requirements and design criteria (e.g., train separation, redundancy, and single failure). The change simply allows the elimination of a calculational assumption when it can be demonstrated by the two sources to not be applicable. All plant systems will continue to function as designed, and all plant parameters will remain within their design limits. Revising the TS definition of SOM would not require core designers to revise any SOM boron calculations. Rather, it would afford the analytical flexibility for determining SOM for a particular circumstance. The proposed change does not involve any change in the design, configuration, or operation of the nuclear plant. The current plant safety analyses remain complete and accurate in addressing the design-basis events and in analyzing plant response and consequences. The LCOs, limiting safety system settings, and safety limits specified in the TSs are not affected by the proposed change. As such, the plant conditions for which the design-basis accident analyses were performed are not changed. Furthermore, margin of safety is related to confidence in the ability of the fission product barriers to perform their accident mitigation functions. These barriers include the fuel and fuel cladding, the RCS, and the containment and containment-related systems. The proposed changes will not impact the reliability of these barriers to function. Radiological doses to plant operators or to the public will not be impacted as a result of the proposed change. The change in the TS definition of SOM will have no impact to these barriers. The NRC staff reviewed the licensee's submittals relative to the TSTF and WOG STS and concludes that the proposed change meets 10 CFR 50.36 and is, therefore, acceptable. Based on the above, the NRC staff concludes the licensee's proposed change to the TS definition of SOM is acceptable. 3.7 TSTF-266-A. Revision 3, "Eliminate the Remote Shutdown System Table of Instrumentation and Controls" The NRC approved this change to WOG STS, Revision 1, on September 10, 1999. This traveler revised WOG STS 3.3.4 by removing the list of Remote Shutdown System instrumentation and controls from the TSs and placing them in the TS Bases. Current Farley TS and Proposed Changes TS LCO 3.3.4 currently states: The Remote Shutdown System Functions in Table 3.3.4-1 shall be OPERABLE. Revised TS LCO 3.3.4 would state: The Remote Shutdown System Functions shall be OPERABLE.
The proposed change removes TS Table 3.3.4-1, "Remote Shutdown System Instrumentation and Controls," from the Farley TSs and places the table in the Bases for Farley TS 3.3.4.
NRC Staff Evaluation
Farley's Remote Shutdown System provides the operator with sufficient instrumentation and controls to place and maintain the unit in a safe shutdown condition from a location other than the control room. This capability is necessary to protect against the possibility that the control room becomes inaccessible. If the control room becomes inaccessible, the operators can establish control at the remote shutdown panel and place and maintain the unit in MODE 3. Not all controls and necessary transfer switches are located at the remote shutdown panel. Some controls and transfer switches will have to be operated locally at the switchgear, motor control panels, or other local stations. Table 3.3.4-1 lists the readout location, transfer switch location, and controls location for remote shutdown instrumentation. The proposed change would relocate these requirements to the TS licensee-controlled documents. General Design Criterion 19 requires that remote shutdown capability be provided. Farley FSAR, Chapter 3, specifies Farley's position on General Design Criterion 19, and states: In the event that the operators are forced to abandon the control room, panel-mounted instrumentation and controls are provided on the train-related shutdown panels to achieve and maintain the plant in the safe shutdown condition. Therefore, the NRC staff concludes that the relocation of instrumentation listed in TS Table 3.3.4-1 to TS Bases will continue the licensee's compliance with its statement regarding operations of its remote shutdown functions, as the licensee has not proposed any change to its position. The definition of "operable" in the Farley specifications states that a system shall be operable or have operability when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, electrical power, cooling and seal water, lubrication, and other auxiliary equipment that are required for the system to perform its specified safety function(s) are also capable of performing their related support function. This definition requires that all instrumentation and controls that are necessary for the remote shutdown function be operable in order for the Remote Shutdown System LCO to be met. The ability to transfer control of a function from the main control room to the remote shutdown panel is a required support function by the TS definition of operability. Therefore, LCO 3.3.4 is sufficient to ensure that the instruments and control circuits will be OPERABLE if unit conditions require that the Remote Shutdown System be placed in operation. SR 3.3.4.2 still requires the local panel transfer function to be tested, which is sufficient to assure that the system will be operable. The relocation of the Remote Shutdown System Instrumentation and Controls Table from the TSs to the Bases is acceptable because it will be adequately controlled by NRC requirements in
the TS 5.5.14 Bases control program. This approach provides an effective level of regulatory control and provides for a more appropriate change control process. The NRC staff concludes that the requirements of 10 CFR 50.36(c)(2) continue to be met because the minimum performance level of equipment needed for safe operation of the facility is contained in the LCO, and the appropriate remedial measures are specified if the LCO is not met. Based on the above, the NRC staff concludes that the changes are acceptable. 3.8 TSTF-272-A. Revision 1. "Refueling Boron Concentration Clarification" The NRC approved this change to WOG STS, Revision 1, on December 21, 1999. This traveler revised WOG STS 3.9.1, "Boron Concentration," to add an Applicability Note to clarify that boron concentration limits do not apply to the refueling canal and the refueling cavity when those volumes are not connected to the RCS. TS LCO 3.9.1 currently states: Boron concentrations of the Reactor Coolant System, the refueling canal, and the refueling cavity shall be maintained within the limit specified in the COLR. The proposed change would add a Note to the Mode 6 Applicability statement of TS 3.9.1, as follows:
------------------------------------------N 0 TE-------------------------------------------------
Only applicable to the refueling canal and refueling cavity when connected to the RCS.
NRC Staff Evaluation
The licensee states that TS 3.9.1 limits the boron concentrations of the RCS, the refueling canal, and the refueling cavity during refueling to ensure that the reactor remains subcritical during MODE 6. The staff finds the proposed change acceptable because boron concentration limits do not apply to the refueling canal and refueling cavity when these areas are not connected to the RCS, as any water in the refueling canal and refueling cavity would not be in communication with the reactor fuel. For MODE 6, current Farley TS SR 3.9.1.1 ensures that the coolant boron concentration in all filled portions of the RCS, the refueling canal, and the refueling cavity is within the COLR limits. The boron concentration of the coolant in each volume is determined periodically by chemical analysis. The licensee's revised SR 3.9.1.1 TS Bases state that if any dilution has occurred while the cavity or canal were disconnected from the RCS, this SR would ensure the correct boron concentration prior to communication with the RCS. The NRC staff concludes that the requirements of 10 CFR 50.36(c)(2) continue to be met because the minimum performance level of equipment needed for safe operation of the facility is contained in the LCO, and the appropriate remedial measures are specified if the LCO is not met.
Based on the above, the NRC staff concludes the licensee's proposed change to the TSs is acceptable. In addition, the proposed change is consistent with guidance in the WOG STS and approved TSTF-272. 3.9 TSTF-273-A, Revision 2, "SFDP Clarifications" The NRC approved TSTF-273-A, Revision 2, to WOG STS Revision 1, as documented in a letter from William Beckner (NRC) to James Davis (Nuclear Energy Institute (NEI)), dated August 16, 1999 (ADAMS Legacy Library Accession No. 9908250220). This traveler modified WOG STS 5.5.15, "Safety Function Determination Program (SFDP)," which implements the requirements of LCO 3.0.6. The LCO requires that an evaluation shall be made to determine if loss of safety function exists. The proposed change to TS 5.5.15 would add the following text shown in bold type in two separate paragraphs: A loss of safety function exists when, assuming no concurrent single failure, no concurrent loss of offsite power or no concurrent loss of onsite diesel generator(s), a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and: The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.
NRC Staff Evaluation
SNC proposed to revise its TS 5.5.15 by incorporating the TSTF-273-A, Revision 2, changes without deviations. The changes to the SFDP TS 5.5.15 and the Bases for LCO 3.0.6 are intended to clarify the intent of LCO 3.0.6 in the event a single inoperable TS support system makes both redundant subsystems of a supported system inoperable (a loss of safety function condition). The WOG STSs were developed such that the LCO Actions for a single support system inoperability would be addressed by that support system's Actions without cascading to the supported system's LCO Actions. If a support system does not have an LCO associated with it, then the plant will enter the TS-supported system LCO, per the operability determination. LCO 3.0.6 establishes this exception to LCO 3.0.2 for support systems that have an LCO specified in the TSs. However, LCO 3.0.6 also requires an evaluation under the SFDP to ensure that a loss of operability does not exist. The staff finds that these changes do not affect the design, operation, or maintenance of Farley, Units 1 and 2, but only add clarification for determining when a loss of safety function condition exists and all applicable LCO Actions are required to be taken when a safety function is lost. By clarifying the intent of the existing requirements of the SFDP and LCO 3.0.6, these changes remove an ambiguity that could lead to a misinterpretation of those requirements.
The NRC staff concludes that the requirements of 10 CFR 50.36(c)(2) continue to be met because the minimum performance level of equipment needed for safe operation of the facility is contained in the LCO, and the appropriate remedial measures are specified if the LCO is not met. Based on the above, the NRC staff concludes the licensee's proposed change to the TSs is acceptable. 3.10 TSTF-283-A, Revision 1. "Modify Section 3.8 Mode restriction Notes"
Background
This TSTF proposed changes to Revision 1 of NUREG-1431, WOG STS 3.8.1, "AC Sources Operating," and Specification 3.8.4, "DC Sources - Operating." In these STS subsections, several SRs contained surveillance column Notes prohibiting their performance in MODE 1 or 2, or in MODE 1, 2, 3, or 4. The TSTF proposed to revise these Notes to allow full or partial performance of the SRs to reestablish operability, provided a pre-test-performance assessment determines the safety of the plant is maintained or enhanced by doing so. Current Farley TSs and Proposed Changes: SR 3.8.1.7 (STS SR 3.8.1.8), which tests the transfer of alternating current (AC) sources from normal to alternate offsite circuits, contains a Note prohibiting performance in MODE 1 or 2. The proposed change would modify the Note to add the following text shown in bold: This Surveillance shall not normally be performed in MODE 1 or 2. However, this surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. SR 3.8.1.9 (STS SR 3.8.1.11 ), which tests the response to a loss of offsite power signal, contains a Note prohibiting performance in MODE 1, 2, 3, or 4. The proposed change would modify the Note to add the following text shown in bold: This Surveillance shall not normally be performed MODE 1, 2, 3, or 4. However, portions of the surveillance may be performed to reestablish OPERABILITY provided an assessment determining safety of the plant is maintained or enhanced. SR 3.8.1.14 (STS SR 3.8.1.16), which verifies the transfer from diesel generator to offsite power, contains a Note prohibiting performance in MODE 1, 2, 3, or 4. The proposed change would modify the Note to add the following text shown in bold: This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, this surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plan is maintained or enhanced.
SR 3.8.1.17 (STS SR 3.8.1.19), which verifies the response to a loss of offsite power signal and engineered safety feature (ESF) actuation signal, contains a Note prohibiting performance in MODE 1, 2, 3, or 4. The proposed change would modify the Note to add the following text shown in bold: This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, portions of the surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. SR 3.8.4.7 (STS SR 3.8.4.7) is a modified performance discharge test, which is a test of the battery capacity and its ability to provide a high rate, short duration load (usually the highest rate of the duty cycle). This will often confirm the battery's ability to meet the critical period of the load duty cycle 1, in addition to determining its percentage of rated capacity. The SR contains a Note prohibiting performance in MODE 1, 2, 3 or 4. Per the licensee's supplemental letter dated September 28, 2015, the proposed change would modify the Note to add the following text shown in bold: This Surveillance shall not normally be performed for the Auxiliary Building batteries in MODE 1, 2, 3, or 4. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. SR 3.8.4.8 (STS SR 3.8.4.8) is a battery performance discharge test, which is a constant current capacity test to detect any change in the capacity determined by the acceptance test. The SR contains a Note prohibiting performance in MODE 1, 2, 3, or 4. Per the licensee's supplemental letter dated September 28, 2015, the proposed change would modify the Note to add the following text shown in bold: This Surveillance shall not normally be performed for the Auxiliary Building batteries in MODE 1, 2, 3, or 4. However, portions of the Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Deviation from TSTF-283 The following Farley, Unit 1 and 2, TS SRs do not contain a Note restricting the modes in which the SR may be performed, although the corresponding SRs in Revision 1 of WOG STS, do. Farley TS STS Revision 1 SR 3.8.1.8 SR 3.8.1.9 SR 3.8.1.10 SR 3.8.1.12 SR 3.8.1.11 SR 3.8.1.13 SR 3.8.1.12 SR 3.8.1.14 SR 3.8.1.15 SR3.8.1.17 SR 3.8.1.16 SR 3.8.1.18 SR 3.8.1.18 SR 3.8.1.10 SR 3.8.4.6 SR 3.8.4.6
As such, the TSTF change to the Notes that provide an exception to the mode restrictions is not applicable to the above Farley TS SRs, and is not adopted. In the application, the licensee
- stated, The MODE restriction Notes for these SRs, which appear in NUREG-1431, Rev. 1, were not adopted as part of the Farley Units 1 and 2 [improved TS]
conversion (license amendments] because they were not part of the plant licensing basis that was described in the plant Custom Technical Specifications. Licensee's Justification The licensee provided the following justification for the proposed changes: The proposed changes to Specification 3.8.1 will potentially avoid a plant shutdown if corrective maintenance (planned or unplanned) performed during power operation results in the need to perform any of the revised Surveillances to demonstrate Operability. The proposed changes do not affect either the frequency of conducting the SRs, the surveillance to be performed, or the performance criteria specified in the SRs. The only change is to the reactor modes during which the surveillance may be performed. The allowance to perform the Surveillances in currently prohibited Modes is restricted to only allow the Surveillances to be performed for the purpose of reestablishing Operability (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated operability concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed Surveillance, a successful Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when the Surveillance is performed. Note that the Maintenance Rule provision contained in 10 CFR 50.65(a)(4) states that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. This includes the performance of Surveillances to re-establish Operability. Therefore, in addition to the assessment required by the Surveillance Notes, an assessment of plant risk will also be performed. Regarding proposed changes to SR 3.8.4.7 and SR 3.8.4.8, the supplemental letter dated September 28, 2015, states: The MODE restrictions in Note 2 of Farley SR 3.8.4.7 and SR 3.8.4.8 on normally performing the Surveillance are applicable in MODES 1, 2, 3, or 4. However, the applicability of the allowance provided in the supplemental BASES text from TSTF-283-A is limited to "MODES 1 or 2."
The intent of TSTF-283-A is to allow performance of surveillance testing for the purposes of reestablishing OPERABILITY provided an assessment of the effects of performance in these MODES compared to the effects of a plant shutdown and startup demonstrate a safety benefit or safety neutral situation. The supplemental BASES text provided in TSTF-283-A is therefore expanded from "MODES 1 or 2" to "MODES 1, 2, 3, or 4," which is consistent with the MODE restrictions in Note 2 of Farley SR 3.8.4.7 and SR 3.8.4.8, and the intent of TSTF-283-A, Rev. 3. The proposed changes to the Bases for SR 3.8.4.7 and SR 3.8.4.8 will allow performance of the testing specified by these SRs in all Modes of operation. This will help to reduce the complexity of coordinating work and testing activities during refueling outages and could potentially reduce outage critical path time. The change will also maximize flexibility in responding to an event during shutdown when other engineered safety features (ESF) equipment may be out of service. In addition, this change could potentially avoid a plant shutdown if maintenance (planned or unplanned) performed in MODES 1, 2, 3, or 4 results in the need to perform the surveillance to demonstrate operability.
NRC Staff Evaluation
The NRC did not issue a letter approving this change to Revision 1 of WOG STS; however, this change was incorporated by the NRC into WOG STS, Revision 2, issued in April 2001. The intent of the TSTF is to allow testing of the emergency diesel generators (EDGs) and Class 1E batteries in modes not currently allowed for the purpose of maintaining or reestablishing system or component operability (e.g., post corrective maintenance testing), provided the licensee performs a safety assessment, as described in the application, that determines the safety of the plant would be maintained or enhanced by conducting the operability testing before the testing begins. The above-described proposed change to SR Notes in TS 3.8.1 for the AC electrical power sources and TS 3.8.4 for the direct current (DC) electrical power sources would provide flexibility in outage scheduling and reduce outage critical path time, since these EDGs and battery surveillance tests would no longer have to be performed during an outage. In addition, the changes will potentially allow avoiding a plant shutdown if corrective maintenance (planned or unplanned) performed during power operation results in the need to perform any of the above surveillances to demonstrate operability and to maximize the licensee's flexibility in responding to an event during shutdown when other ESF equipment may be out-of-service. The NRC staff concludes that the requirements of 10 CFR 50.36(c)(3) continue to be met because the minimum performance level of equipment needed for safe operation of the facility is contained in the LCO, and the appropriate remedial measures are specified, if the LCO is not met. Based on the above, the NRC staff concludes the licensee's proposed change to the TSs is acceptable.
3.11 TSTF-284-A, Revision 3. "Add 'Met vs. Perform' to Specification 1.4. Frequency" TSTF-284-A, Revision 3, was approved by the NRC as documented in a letter from William Beckner (NRC) to James Davis (NEI), dated February 16, 2000 (ADAMS Accession No. ML003684596). The change inserts a discussion paragraph into Specification 1.4, and several new examples are added to facilitate the use and application of SR Notes that utilize the terms "met" and "perform." The changes also modify certain SRs to appropriately use the "met" and "perform" exceptions. Current Farley TS and Proposed Changes: TS 1.4, "Frequency," third paragraph, currently states: Situations where a Surveillance could be required (i.e., its Frequency could expire), but where it is not possible or not desired that it be performed until sometime after the associated LCO is within its Applicability, represent potential SR 3.0.4 conflicts. To avoid these conflicts, the SR (i.e., the Surveillance or the Frequency) is stated such that it is only "required" when it can be and should be performed. With an SR satisfied, SR 3.0.4 imposes no restriction. The proposed change replaces the paragraph in its entirety with the following: Sometimes special situations dictate when the requirements of a Surveillance are to be met. They are "otherwise stated" conditions allowed by SR 3.0.1. They may be stated as clarifying Notes in the Surveillance, as part of the Surveillance, or both. Situations where a Surveillance could be required (i.e., its Frequency could expire), but where it is not possible or not desired that it be performed until sometime after the associated LCO is within its Applicability, represent potential SR 3.0.4 conflicts. To avoid these conflicts, the SR (i.e., the Surveillance or the Frequency) is stated such that it is only "required" when it can be and should be performed. With an SR satisfied, SR 3.0.4 imposes no restriction. The revised TS 1.4, "Frequency," description would also state: The use of "met" or "performed" in these instances conveys specific meanings. A Surveillance is "met" only when the acceptance criteria are satisfied. Known failure of the requirements of a Surveillance, even without a Surveillance specifically being "performed," constitutes a Surveillance not "met." "Performance" refers only to the requirement to specifically determine the ability to meet the acceptance criteria. Some Surveillances contain notes that modify the Frequency of performance or the conditions during which the acceptance criteria must be satisfied. For these Surveillances, the MODE-entry restrictions of SR 3.0.4 may not apply. Such a Surveillance is not required to be performed prior to entering a MODE or other specified condition in the Applicability of the associated LCO if any of the following three conditions are satisfied:
- a. The Surveillance is not required to be met in the MODE or other specified condition to be entered; or
- b. The Surveillance is required to be met in the MODE or other specified condition to be entered, but has been performed within the specified Frequency (i.e., it is current) and is known not to be failed; or
- c. The Surveillance is required to be met, but not performed, in the MODE or other specified condition to be entered, and is known not to be failed.
Examples 1.4-3, 1.4-4, 1.4-5, and 1.4-6 discuss these special situations. TS 1.4, "Frequency," currently includes examples up through Example 1.4-3 regarding the Frequency based on a specified Condition. The proposed change would add Examples 1.4-4, 1.4-5, and 1.4-6 on Surveillance requirements as shown in revised TS pages 1.4-5, 1.4-6, and 1.4-7 in the preceding Attachment to this license amendment. TS SR 3.4.11.1 currently specifies the following requirement: SURVEILLANCE FREQUENCY SR 3.4.11.1---------------------NOTES-------------------------- In accordance
- 1. Not required to be met with block valve closed in with the accordance with the Required Action of Condition Surveillance B or E. Frequency Control Program
- 2. Not required to be performed prior to entry into MODE 3.
Perform a complete cycle of each block valve. The proposed change would revise the Notes 1 and 2 as shown in bold text below: SURVEILLANCE FREQUENCY SR 3.4.11.1---------------------NOTES-------------------------- In accordance with
- 1. Not required to be performed with block valve the Surveillance closed in accordance with the Required Frequency Control Actions of this LCO. Program
- 2. Only required to be performed in MODES 1 and 2.
Perform a complete cycle of each block valve.
TS SR 3.4.12.5 Note currently states: Only required to be performed when complying with LCO 3.4.12.b. The proposed change would revise the Note as follows: Only required to be met when complying with LCO 3.4.12.b. TS SR 3.9.3.2 currently states: Verify each required containment purge and exhaust valve actuates to the isolation position on an actual or simulated actuation signal. The proposed change would add the following Note in SR 3.9.3.2: Not required to be met for containment purge and exhaust valve(s) in penetrations closed to comply with LCO 3.9.3.c.1. The licensee explains the differences between the proposed changes and the approved traveler as follows: TSTF-284-A, Revision 3 includes changes to SR 3.1.11.1 and SR 3.1.11.2 of ISTS Specification 3.1.11, "SOM Test Exceptions." This LCO allows suspension of SOM requirements in MODE 2 provided specific conditions are met in order facilitate measurement control rod worth and SOM. The Farley Technical Specifications do not include a Specification that is analogous to ISTS TS 3.1.11, "SOM Test Exceptions," or SRs that are analogous to ISTS SRs 3.1.11.1 and 3.1.11.2. Therefore, the TS and Bases changes identified in TSTF-284-A for ISTS 3.1.11 are not adopted. The Farley Section 3.9 specification numbers are different from the ISTS Section 3.9 specification numbers. Farley Specification 3.9.3, "Containment Penetrations," is equivalent to Specification 3.9.4 in the ISTS. This has no effect on the requested change. Changes to the Actions Bases for Specification 3.4.11, "Pressurizer PORVs," are not adopted. The changes described in the TSTF are related to a Note in the ISTS that provides an exception to LCO 3.0.4 that allows entry into MODES 1, 2, and 3 to perform cycling of the PORVs or block valves in order to demonstrate their operability. Consistent with NUREG-1431, Farley Technical Specification 3.4.11, and its associated Bases, do not include the Note providing this exception to LCO 3.0.4. Changes identified in TSTF-284-A to ISTS SR 3.4.11.2, and its associated Bases, are also not adopted. Farley SR 3.4.11.2 requires performance of a complete cycle of each PORV during MODE 3 or 4, and is modified by a Note stating that this testing is not required to be performed prior to entering MODE 3.
This is substantially different from the requirements in analogous ISTS SR 3.4.11.2, which requires performance of a complete cycle of each PORV, but does not specify the MODES in which it must be performed. These differences are such that the changes in TSTF-284-A are not appropriate. TSTF-284-A identifies changes to ISTS 3.4.12, "LTOP System," SR 3.4.12.8. This SR requires performance of a Channel Operational Test (COT) for each required PORV, excluding actuation. The Farley Technical Specifications do not include an SR that is analogous to ISTS SR 3.4.12.8. Therefore, the TS and Bases changes identified in TSTF-284-A for ISTS SR 3.4.12.8 are not adopted. In adopting TSTF-284, Revision 3, a licensee must verify that Notes such as illustrated by these four examples are used properly and only as necessary. This includes ensuring the associated Bases are also correct. Proper application of these Notes in the individual SRs in the NUREGs was verified. The staff's review of the proposed changes finds that Farley's adoption of the TSTF changes conforms to the guidance provided in the NUREGs described above. These changes are administrative in nature because they only serve to clarify the meanings of the terms "met" and "performed" as used in SR Notes throughout the Farley TSs. This change serves to improve TS usefulness by clarifying terminology usage and providing additional examples of the application of SR Notes. Therefore, these changes are acceptable. In addition to the changes discussed above, the licensee also proposed a change to the Note in SR 3.4.11.1, which currently states that the SR is not required to be performed with block valve closed in accordance with the Required Action of Conditions A, B, or E. The proposed change concerns deletion of Conditions A, B, or E from the Note in the SR. These Conditions provide actions for the inoperability of one or more PORVs.
NRC Staff Evaluation
The staff reviewed the licensee's proposed change, the approved TSTF-284, and the WOG STS. The staff considers the testing of the PORV block valve to be unnecessary if the block valve has been closed due to an inoperable PORV. The additional assurance of block valve operability gained from the surveillance test is outweighed by the risk associated with the development of an unisolable leak in the RCS. Accordingly, the provision of TSTF-284, Revision 3, which allows the extension of the range of circumstances under which the surveillance testing of the PORV block valve is not required to any of the Actions of TS 3.4.11, instead of limiting to Conditions A, B, or E as currently specified in the SR, is acceptable as a change to Farley TSs. Therefore, the change to remove the surveillance testing under the specific conditions of the revised PORV block valve SR 3.4.11.1 of TS 3.4.11 is acceptable for Farley, Units 1 and 2. Lastly, the staff review of the licensee's proposed addition of a new Note requiring that SR 3.4.11.1 is only required to be performed in MODES 1 and 2 is acceptable, since it allows the test to be performed in MODE 3 under operating temperature and pressure conditions prior to entering MODE 1 or 2. The NRC staff concludes that the requirements of 10 CFR 50.36(c)(2) continue to be met because the minimum performance level of equipment needed for safe operation of the facility
is contained in the LCO, and the appropriate remedial measures are specified if the LCO is not met. These changes are consistent with the approved TSTF-284. Based on the above, the NRC staff concludes the licensee's proposed change to the TSs is acceptable. 3.12 TSTF-308-A. Revision 1. "Determination of Cumulative and Projected Dose Contributions in RECP" The NRC did not issue a letter approving this change to WOG STS, Revision 1; however, this change was incorporated by the NRC into the WOG STS, Revision 2, issued in April 2001. This traveler modified WOG STS 5.5.4, "Radioactive Effluent Control Program," to describe the original intent of the dose projections. Current Farley TS and Proposed Changes: TS 5.5.4, paragraph 'e,' currently states: Determination of cumulative and projected dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the ODCM at least every 31 days; The proposed change revises paragraph 'e' in its entirety to state: Determination of cumulative dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the ODCM [offsite dose calculation manual] at least every 31 days. Determination of projected dose contributions from radioactive effluents in accordance with the methodology in the ODCM at least every 31 days.
NRC Staff Evaluation
The regulation in 10 CFR 50.36a, "Technical specifications on effluents from nuclear power reactors," requires each licensee to submit a report to the NRC that will allow an estimation of the maximum potential annual radiation doses to the public resulting from effluent releases. Generic Letter (GL 89-01 ), "Implementation of Programmatic Controls for Radiological Effluent Technical Specifications in the Administrative Controls Section of the Technical Specifications and the Relocation of Procedural Details of RETS to the Offsite Dose Calculation Manual or to the Process Control Program," provides guidance in support of implementing programmatic controls in TSs for radioactive effluents and for radiological environmental monitoring that conforms to the applicable regulatory requirements. The regulation in 10 CFR 20.1302, "Compliance with dose limits for individual members of the public," paragraph (b), requires that a licensee shall show compliance with the annual dose limit in 10 CFR 20.1301 by demonstrating by measurement or calculation that the total effective dose equivalent to the
individual likely to receive the highest dose from the licensed operation does not exceed the annual dose limit. GL 89-01 combines two SRs - the cumulative and projected dose determinations, into one program element. In combining these requirements, the new program element can be interpreted to require determining projected dose contributions for the calendar quarter and current calendar year every 31 days. This wording was misleading and resulted in misinterpretation of the intent of the original STS and was not consistent with the original surveillance. Therefore, TSTF-308-A was developed and subsequently approved by the NRC to not require dose projections for a calendar quarter and a calendar year every 31 days (i.e., to describe the actual intent of the dose projections). Farley TS 5.5.4, "Radioactive Effluent Controls Program," states: This program conforms to 10 CFR 50.36a for the control of radioactive effluents and for maintaining the doses to members of the public from radioactive effluents as low as reasonably achievable. The program shall be contained in the ODCM, shall be implemented by procedures, and shall include remedial actions to be taken whenever the program limits are exceeded. TS 5.5.4.e is one of the elements in the program, which states the following: Determination of cumulative and projected dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the ODCM at least every 31 days; The licensee proposed to revise this element as indicated by the following markup, consistent with TSTF-308-A. (Added text is shown in bold face; deleted text is lined out.) Determination of cumulative and projected dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the ODCM at least every 31 days. Determination of projected dose contributions from radioactive effluents in accordance with the methodology in the ODCM at least every 31 days. The NRC staff reviewed the change proposed by the licensee as clarifications that were prepared using the guidance in TSTF-308-A, and finds that the revised wording for paragraph 'e' of Farley TS 5.5.4 meets the requirements of 10 CFR 50.36a and 10 CFR 20.1302, and is, therefore, acceptable. 3.13 TSTF-312-A. Revision 1. "Administratively Control Containment Penetrations" The NRC staff decoupled TSTF-312 from its review under the current request to be processed by a separate amendment.
3.14 TSTF-314-A, Revision 0. "Require Static and Transient Fa Measurement" The NRC approved this change to WOG STS, Revision 1, on January 13, 1999. This traveler revised WOG STS 3.1.5, "Rod Group Alignment Limits," and 3.2.4, "Quadrant Power Tilt Ratio (QPTR)," to require measurement of both the steady state and transient portions of the Heat Flux Hot Channel Factor, Fa(Z). Farley TS 3.1.4, "Rod Group Alignment Limits," and 3.2.4, "QPTR," are equivalent to WOG STS 3.1.5 and 3.2.4, respectively.
- Currently, when Farley TS LCO 3.1.4 is not met because one rod is not within alignment limits (Condition B), Required Action B.2.4 requires performing SR 3.2.1.1, "Verify Fa(Z) is within steady state limit."
The proposed change would revise Required Action B.2.4 by adding a requirement to also perform SR 3.2.1.2, "Verify Fa(Z) is within the transient limit."
- Similarly, current TS LCO 3.2.4, when QPTR is not within its limit (Condition A),
Required Actions A.3 and A.6 currently require the performance of SR 3.2.1.1 and also 3.2.2.1, "Verify FNL'iH is within limits specified in the COLR." The proposed change would revise Required Actions A.3 and A.6 by adding a requirement to also perform SR 3.2.1.2 "Verify Fa(Z) is within the transient limit."
NRC Staff Evaluation
The licensee proposes to add Required Actions to perform SR 3.2.1.2, which requires confirming that the transient component of the Heat Flux Hot Channel Factor, Fo(Z), is within its limits, to Condition B associated with TS LCO 3.1.4, "Rod Group Alignment Limits," and to Condition A associated with LCO 3.2.4, "QUADRANT POWER TILT RATIO (QPTR)." The NRC staff review considered the acceptability of the proposed additions. As the licensee notes, Fa(Z) is approximated by both a steady-state and a transient component of Fa. The proposed Required Actions will modify the TS to include, along with the present requirement to verify the steady-state Fa is within limits, a new requirement to verify the transient Fa. In Conditions in which other LCOs may not be met (i.e., the LCOs for rod group alignment limits and quadrant power tilt ratio), this added Required Action, in addition to other Required Actions for the specified Condition, would ensure that the power distribution remains appropriately limited within the bounds of the safety analyses. Since Fa(Z) is approximated by both a transient and a steady-state component, the additional action to require performance of the surveillance to confirm that the transient component is also within its limits, is consistent with 10 CFR 50.36 requirements. Specifically, the requirement to perform both surveillances will provide an additional remedial action to follow until the LCO can be met, consistent with 10 CFR 50.36(c)(2)(i). Since the proposed change will add a new remedial action, it is more restrictive than the existing action requirements for TS 3.1.4, Condition B, and TS 3.2.4, Condition A. Based on the considerations that (1) the proposed Required Actions will be more restrictive than the existing Required Actions, and (2) the proposed Required Actions are consistent with
10 CFR 50.36 requirements, the NRC staff concludes that the addition of the requirement to perform SR 3.2.1.2 to the Required Actions for TS 3.1.4, Condition B, and TS 3.2.4, Condition A, is acceptable. 3.15 TSTF-315-A. Revision 0. "Reduce plant trips due to spurious signals to the NIS during physics testing" This traveler revised WOG STS 3.1.10, "PHYSICS TESTS Exceptions - MODE 2," to allow the number of channels of Functions 2, 3, 6, and 18e (as explained below) required by LCO 3.3.1, "Reactor Trip System (RTS) Instrumentation," to be reduced from four to three to allow one nuclear instrumentation channel to be used as an input to the reactivity computer for physics testing without placing the affected nuclear instrumentation channel in a tripped condition. Current Farley TS. Proposed Changes, and Differences from the Traveler: Farley TS LCO 3.1.8, "PHYSICS TESTS Exceptions - MODE 2" (equivalent to STS TS LCO 3.1.10), currently identifies LCOs for which certain requirements rated thermal power RTS instrumentation," Functions 2, 3, and 17.e, may be reduced to "3" required channels." The following provides a description for the functions listed above: STS LCO 3.3.1 Equivalent Farley RTS Function TS LCO 3.3.1 Number RTS Function Function Title Number 2 2 Power Range Neutron Flux
- High, and - Low 3 3 Power Range Neutron Flux High Positive Rate 6 No change (see Overtemperature 6. T below) 18.e 17.e RTS Interlocks, Power Range Neutron Flux, P-1 O Current TS 3.1.8 LOC states:
During the performance of PHYSICS TESTS, the requirements of LCO 3.1.3, "Moderator Temperature Coefficient (MTC)"; LCO 3.1.4, "Rod Group Alignment Limits"; LCO 3.1.5, "Shutdown Bank Insertion Limits"; LCO 3.1.6, "Control Bank Insertion Limits"; and LCO 3.4.2, "RCS Minimum Temperature for Criticality" may be suspended, provided:
- a. THERMAL POWER is s 5% RTP;
- b. SOM is within the limits provided in the COLR; and
- c. RCS lowest loop average temperature is~ 531°F.
Revised TS 3.1.8 LCO would state: During the performance of PHYSICS TESTS, the requirements of LCO 3.1.3, "Moderator Temperature Coefficient (MTC)"; LCO 3.1.4, "Rod Group Alignment Limits"; LCO 3.1.5, "Shutdown Bank Insertion Limits"; LCO 3.1.6, "Control Bank Insertion Limits"; and LCO 3.4.2, "RCS Minimum Temperature for Criticality" may be suspended, and the number of required channels for LCO 3.3.1, "RTS Instrumentation," Functions 2, 3, and 17.e. may be reduced to 3 provided:
- a. THERMAL POWER is s 5% RTP;
- b. SOM is within the limits provided in the COLR; and
- c. RCS lowest loop average temperature is~ 531°F The changes to Revision 1 of WOG STS provided in TSTF-315-A are based on a four-loop Westinghouse plant design. Farley, Units 1 and 2, are three-loop Westinghouse plants and have only three, not four, channels of the Overtemperature ~ T trip function instrumentation.
The TSTF-315-A change, which allows reducing the minimum number of required channels from four to three for STS 3.3.1, Function 6, "Overtemperature ~ T," is, therefore, not applicable to Farley TS 3.3.1, Function 6, and is not proposed for adoption in equivalent Farley TS 3.1.8, "PHYSICS TESTS - MODE 2."
NRC Staff Evaluation
Adopting the traveler allowance in the LCO statement of TS 3.1.8, "Physics Tests - MODE 2," is acceptable for the reasons stated in the licensee's justification. In particular, the resulting two-out-of-three logic for these trip functions still satisfies the single failure criterion. The three required channels of the Power Range Neutron Flux - Low, Power Range Neutron Flux High Positive Rate, and Overtemperature ~ T trip functions, and the two required channels of the Intermediate Range Neutron Flux trip function will provide adequate reactor protection in case of an unexpected increase in power that exceeds an associated low power reactor trip setpoint. The change in LCO 3.1.8 does not change the LCO 3.3.1 requirement for four operable channels for Functions 2, 3, and 17.e in MODE 2 when not conducting physics tests, and the added allowance will also reduce the risk of unnecessary reactor trips during the performance of physics tests.
The NRC staff concludes that the requirements of 10 CFR 50.36(c)(2) continue to be met because the minimum performance level of equipment needed for safe operation of the facility is contained in the LCO, and the appropriate remedial measures are specified if the LCO is not met. Based on the above, the NRC staff concludes that this change is acceptable. It is also consistent with guidance in the WOG STS and TSTF-315-A, Revision 0. 3.16 TSTF-325-A. Revision 0. "ECCS Conditions and Required Actions with less than 100% Equivalent ECCS Flow" TSTF-325-A, Revision 0, was approved on June 29, 1999, in a letter from William D. Beckner, Chief, Technical Specifications Branch, NRC, to James Davis, Director, Operations Department, NEI (ADAMS Legacy Library Accession No. 9907060395). The traveler proposed a change to Revision 1 of WOG STS 3.5.2, "Emergency Core Cooling System (ECCS) - Operating, action requirements to prevent incorrect application of these action requirements stemming from a possible strict interpretation of the logic rules specified by STS 1.3, "Completion Times." Applying this interpretation could result in an inappropriate extension of the intended 72-hour Completion Time to restore an inoperable ECCS train to operable status. Farley TS 3.5.2, "ECCS - Operating, Condition A, currently states: A One or more trains inoperable. At least 100% of the ECCS flow equivalent to a single OPERABLE ECCS train available. Revised TS 3.5.2 Condition A would relocate the second part of the Condition statement ("AND at least 100% ECCS flow equivalent to a single OPERABLE ECCS train available") from Condition A to be a new Condition C, which states: C. With less than 100% of the ECCS flow equivalent to a single OPERABLE ECCS train available. Associated Required Action C.1 will require the unit to enter LCO 3.0.3 immediately. This change matches the change made by the traveler to the Actions table of STS 3.5.2.
NRC Staff Evaluation
The current Condition A could lead to problems due to application of a strict interpretation of the Completion Time logic rules of TS Section 1.3. As currently stated, Condition A would allow inoperability to be present in both ECCS trains, as long as 100 percent equivalent ECCS flow is available, by combining the remaining capability of both ECCS trains. If, while in Condition A, the available ECCS flow decreased below 100 percent, LCO 3.0.3 would be entered because no Condition corresponding to that configuration is specified in the Actions table of TS 3.5.2. However, the stated conditions for Condition A would also no longer be applicable, since there
is now less than 100 percent equivalent flow available. A possible interpretation of the Completion Time rules could lead an operator to think that Condition A is exited (which resets the 72-hour Completion Time of Required Action A.1) when LCO 3.0.3 is entered because of the "AND" logical connector. Subsequently, if the available ECCS flow is restored to at least 100 percent of the equivalent flow of one train, LCO 3.0.3 would be exited. Since the plant configuration now corresponds to Condition A again, the operator might incorrectly conclude that Condition A may be reentered with a new 72-hour time period to restore compliance with the LCO (i.e., two operable ECCS trains). This conclusion is contrary to the intent of Farley TS Section 1.3, "Completion Times." According to TS Section 1.3, the TS should not allow exiting Condition A and resetting the 72-hour Completion Time clock upon entering LCO 3.0.3. Until both trains of ECCS are restored to operable status, or the unit is placed outside the ECCS Specification's mode of applicability (i.e., MODE 4), the unit remains in Condition A, Required Action A.1 remains applicable, and its Completion Time clock continues to run. Stating the original Condition as two separate Conditions ensures that the intent of Farley TS Section 1.3 is met. If the plant enters the new Condition (Condition C) because of low ECCS flow availability, Required Action C.1 requires immediate entry into LCO 3.0.3. However, by TS Section 1.3, the plant would also remain in the inoperable train Condition (Condition A), enabling a smooth transition in the event ECCS flow availability is restored before expiration of the 72-hour clock. In that case, since the low flow condition (Condition C) would no longer apply, it would be exited, and plant operation could continue in Condition A. Since this clarification of the Farley TS 3.5.2 action requirements does not change the technical basis or intent of the action requirements, the proposed change is consistent with TSTF-325-A. The NRC staff concludes that the requirements of 10 CFR 50.36(c)(2) continue to be met because the minimum performance level of equipment needed for safe operation of the facility is contained in the LCO, and the appropriate remedial measures are specified if the LCO is not met. Based on the above, the NRC staff concludes that this change is acceptable, and it is consistent with guidance in the WOG STS and TSTF-325-A, Revision 0. 3.17 TSTF-340-A. Revision 3, "Allow 7 day Completion Time for a turbine driven AFW pump inoperable" The NRC approved this change to Revision 1 of WOG STS on March 16, 2000. The traveler proposed a change to Revision 1 of WOG STS 3.7.5, "Auxiliary Feedwater System," Actions table Condition A to allow a 7-day Completion Time to restore an inoperable turbine-driven AFW pump to operable status with the unit in MODE 3, "if MODE 2 has not been entered following refueling." Current Farley TS and Proposed Changes: The Farley TS LCO 3.7.5, "Auxiliary Feedwater (AFW) System," is identical to Revision 1 of STS LCO 3.7.5. Accordingly, the licensee proposed to apply, without deviation, the TSTF
changes to Condition A and Required Action A.1 of current Farley TS LCO 3.7.5 as stated below. The proposed text is shown in bold text; removed text is lined out. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One steam supply to A.1 Restore steam supply 7 days turbine driven AFW affected equipment pump inoperable. to OPERABLE ANG status. OR 10 days from disoovery of failure to
---------1\i!O"TE:--------- meet the LCO Only applicable if MODE: 2 has not been entered following refueling.
One turbine driven AFW pump inoperable in MODE: 3 following refuelina. B. One AFW train B.1 Restore AFW train to 72 hours inoperable for OPERABLE status. reasons other than Condition A. 10 days from disoovery of failure to meet the LCO
NRC Staff Evaluation
The licensee proposed to modify TS LCO 3.7.5 Condition A to allow a 7-day Completion Time to restore to operable status an inoperable turbine-driven AFW pump with the unit in MODE 3, if MODE 2 has not been entered following refueling. This change was proposed on the basis that it could reduce the number of unnecessary mode changes by providing added flexibility in MODE 3 to repair and test the turbine-driven AFW pump following a refueling outage, provided MODE 2 has not been entered. In this condition, there is reduced decay heat due to the decay of the irradiated fuel during the refueling outage and the replacement of irradiated fuel with unirradiated fuel. The NRC staff agrees with this rationale and finds the proposed change to be reasonable, given the redundant capabilities afforded by the AFW system, the time needed to perform repairs and testing of the turbine-driven pump, and the low probability of an accident occurring during this time period that would require the operation of the turbine-driven pump. In addition, there are alternate methods, such as feed and bleed, available to remove decay heat if necessary. The NRC staff concludes that the requirements of 10 CFR 50.36(c)(2) continue to be met because the minimum performance level of equipment needed for safe operation of the facility is contained in the LCO, and the appropriate remedial measures are specified if the LCO is not met. Based on the above, the NRC staff concludes that this change is acceptable. It is also consistent with guidance in WOG STS and TSTF-340-A, Revision 3. 3.18 TSTF-343-A, Revision 1, "Containment Structural Integrity" The NRC approved this change to Revision 1 of WOG STS on December 6, 2005. This traveler revised Revision 3 of WOG STS 5.5.6, "Pre-Stressed Concrete Containment Tendon Surveillance Program," and 5.5.16, "Containment Leakage Rate Testing Program," to indicate that the inspection frequencies and acceptance criteria shall be in accordance with ASME Code, Section XI, Subsection IWL and Subsection IWE, for the Containment tendons and the Containment structure, respectively, as a result of rule changes to 10 CFR 50.55a in 1996. Per the application, (a) no change to Farley TS 5.5.6 is proposed and (b) Farley TS 5.5.17 is equivalent to STS 5.5.16. The following markup of the affected first paragraph of Farley Specification 5.5.17 illustrates these changes. (Added text is shown in bold type, removed text is lined out.) 5.5.17 Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September, 1995, as modified by the following exceptions to NEI 94-01, Rev. 0, "Industry Guidelines for Implementing Performance-Based Option of 10 CFR 50, Appendix J":
Section 9.2.3: The next Type A test, after the March 1994 test for Unit 1 and the March 1995 test for Unit 2, shall be performed during refueling outage R22 (Spring 2009) for Unit 1 and during refueling outage R20 (Spring 2010) for Unit 2. This is a one time exception.
- 1. The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.
- 2. The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI code, Subsection IWE, except where relief has been authorized by the NRC.
The licensee explained the above difference between the proposed changes to Farley Specification 5.5.17 and the changes in the approved traveler as follows: The Farley Containment Leakage Rate Testing Program, as described in TS 5.5.17, contains the following exception: Section 9.2.3: The next Type A test, after the March 1994 test for Unit 1 and the March 1995 test for Unit 2, shall be performed during refueling outage R22 (Spring 2009) for Unit 1 and during refueling outage R20 (Spring 2010) for Unit 2. This is a one-time exception. This exception provided a one-time exception for actions that have now been performed. Retention of this exception in the TS for historical purposes is not necessary, and the exception is therefore deleted from TS 5.5.17. The licensee explained that changes corresponding to the other changes in the traveler had previously been incorporated in Farley Specification 5.5.6, "Pre-stressed Concrete Containment Tendon Surveillance Program"; in the Bases for SR 3.6.1.2; and with a reference to Regulatory Guide (RG) 1.35, Revision 3, "lnservice Inspection of Ungrouted Tendons in Prestressed Concrete Containments," July 1990, in the "References" section of the Bases for Specification 3.6.1, as follows: The changes identified in TSTF-343-A, Revision 1, for the TS 5.5.6,
"[Pre-Stressed Concrete] Containment Tendon Surveillance Program," and conforming changes to the Bases for SR 3.6.1.2 and the TS 3.6.1 Bases References, are not adopted. The changes in TSTF-343-A that affect this program are already reflected in the Farley Technical Specifications, and are therefore not necessary.
In response to a request for additional information, the licensee also stated: Changes corresponding to those identified in TSTF-343-A, Rev. 1 for TS 5.5.6, "Pre-stressed Concrete Containment Tendon Surveillance Program, the TS Bases for SR 3.6.1.2, and the Bases References for TS 3.6.1 were approved by the NRC under license amendment 172/165 in a letter from Robert. E. Martin (NRC) to L. M. Stinson (SNC), dated April 14, 2006 (ADAMS Accession Nos. ML060830368 and ML061150446).
NRC Staff Evaluation
Implementation of the inservice inspection (ISi) program for the inside and outside surfaces of the containment structure in accordance with ASME Code, Section XI requirements is separate and independent of similar requirements imposed under the containment leakage rate testing program for Type A tests. The proposed addition of two exceptions to RG 1.163 in TS 5.5.17 are meant, in essence, to take credit for the more rigorous inspections performed to fulfill requirements 10 CFR 50.55a(g)(6)(ii)(B) under the ISi program to meet similar inspections in the containment leakage rate testing program, albeit with a slightly relaxed schedule for the inspection of outside concrete surfaces (i.e., from three inspections every 10 years to two inspections every 10 years). The NRC staff agrees with the licensee's conclusion that, "the combination of the Code requirements for the rigor of the visual examinations plus the third party review more than offsets the fact that fewer visual examinations of the concrete will be performed during a 10-year interval." The NRC staff notes that the request is consistent with the approved TSTF. Based on the above, the NRC staff finds the relaxed schedule for the inspection of outside concrete surfaces acceptable. The NRC approved this TSTF-343-A change to STS, Revision 3, on December 6, 2005, in a letter from Thomas H. Boyce (NRC) to TSTF (ADAMS Accession No. ML053460302), which states: TSTF-343, Rev. 1, "Containment Structural Integrity" proposed to revise the Pre-Stressed Containment Surveillance Program and Containment Leakage Rate Program in the STS to reflect changes made to 10 CFR 50.55a in 1996. The final rule became effective on September 9, 1996, and required licensees to implement Subsection IWE and IWL of Section XI, Div. I of the ASME Boiler and Pressure Vessel Code. The staff concluded that the proposed revision to adopt the changes in 10 CFR 50.55a was acceptable, since the requirements of 10 CFR 50.55a adequately provided for the testing of containment leakage and containment tendons. Based on the above, and the licensee's stated justification, the NRC staff concludes the proposed addition of two exceptions to RG 1.163 in TS 5.5.17, which is consistent with guidance in the WOG STS, and TSTF-343-A, Revision 1, acceptable and meets 10 CFR 50.36 requirements. In addition, the proposed deletion of the exception to Section 9.2.3 of NEI 94-01, Revision 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, is administrative in nature, because the Type A tests, to which the one-time
extension to a 15-year interval for Type A tests for Unit 1 (scheduled Spring 2009) and Unit 2 (scheduled Spring 2010) applied, have been completed. Therefore, there is no need to keep this historical information in the Farley TSs, and the proposed deletion is acceptable. 3.19 TSTF-349-A. Revision 1, "Add Note to LCO 3. 9. 5 Allowing Shutdown Cooling Loops Removal from Operation" The NRC did not issue a letter approving this change to WOG STS, Revision 1; however, this change was incorporated by the NRC into Revision 2 of the WOG STS issued in April 2001. This traveler revised Revision 3 of WOG STS 3.9.6, "Residual Heat Removal (RHR) and Coolant Circulation - Low Water Level," by adding a Note to the LCO statement to allow securing all RHR pumps for up to 15 minutes to support switching operating trains. Current Farley TS and Proposed Changes: The licensee proposed changes to corresponding Farley TS 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation - Low Water Level," as shown by the following text in bold: LCO 3.9.5 Two RHR loops shall be OPERABLE, and one RHR loop shall be in operation.
--------------------------------------------------N 0 TES------------------------------------------------------
- 1. One RHR loop may be inoperable and no RHR loop may be in the decay heat removal mode of operation for up to 2 hours for required surveillance testing.
- 2. All RHR pumps may be de-energized for S 15 minutes when switching from one train to another provided:
- a. The core outlet temperature is maintained> 10 degrees F below saturation temperature;
- b. No operations are permitted that would cause a reduction of the Reactor Coolant System (RCS) boron concentration; and
- c. No draining operations to further reduce RCS water volume are permitted.
NRC Staff Evaluation
The RHR system is used to remove core decay heat and reactor coolant sensible heat during unit cooldown and cold shutdown, and to provide adequate mixing of borated coolant. Currently, Farley LCO 3.9.5 requires two RHR loops to be operable and one in operation when a unit is in MODE 6 with less than 23 feet of water above the top of the reactor vessel flange. The existing LCO 3.9.5 also contains a Note that allows operational status changes in the RHR system to support surveillance testing.
With the adoption of TSTF-349-A, the licensee proposed to add a second Note to allow all RHR pumps to be de-energized for up to 15 minutes when switching from one RHR train to another. As stated by the licensee, 15 minutes is a short period of time to be without coolant flow through the reactor core. The new Note includes three restrictions prior to entering this condition. These restrictions will minimize the risk while switching trains and will improve the likelihood that RHR will be safely restored. In addition, the proposed changes are also consistent with similar allowances currently in Farley TS 3.4.8, "RCS Loops - MODE 5, Loops Not Filled," which are applicable to similar RCS conditions as those allowed by TS 3.9.5. Based on the above, which notes the short duration and the three limitations, the NRC staff concludes that the proposed changes meet the requirements of 10 CFR 50.36 and are acceptable. The proposed changes are consistent with the guidance in the STS, and TSTF-349-A, Revision 1, since the two notes in the TSTF have been incorporated into the Farley TSs. 3.20 TSTF-355-A. Revision 0, "Make changes to RTS and ESFAS Tables" This traveler revised Revision 1 of WOG STS 3.3.1, Table 3.3.1-1, "Reactor Trip System Instrumentation," and 3.3.2, Table 3.3.2-1, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation," by (1) changing the last column's title from "Trip Setpoint" to "Nominal Trip Setpoint" in both tables; (2) inserting "Nominal" before "Trip Setpoint" in the first sentence of Note 1 for Overtemperature /1 T and Note 2 for Overpower /1 T in Table 3.3.1-1; and (3) removing the symbols ~ and s, as appropriate, from the nominal trip setpoint values in the last column of both tables. Current Farley TS. Proposed Changes, and Differences: The licensee proposed administrative changes to Farley TS Tables 3.3.1-1 and 3.3.2-1 and associated Bases that are consistent with the administrative changes approved by the NRC staff as described in TSTF-355-A for Revision 1 of WOG STS. Specifically, the changes to RTS and ESFAS function instrumentation table entries regarding the removal of the symbols ~ and s from the nominal trip setpoint values in the last column of the tables were the following, with differences from the traveler noted:
- Farley TS Table 3.3.1-1, "RTS Instrumentation" RTS functions with the trip setpoint value expressed using an inequality symbol, for which the symbol is removed, consistent with the traveler change to the corresponding RTS function in STS Table 3.3.1-1, are the following, with the current and revised nominal trip setpoint entries listed:
Farley RTS Function Applicable Modes (STS Revision 1 RTS Function Number or Other Specified Current Trip Nominal Trip if Different) Conditions Setpoint Set point 2.a. Power Range Neutron Flux - High 1, 2 s 109% RTP 109% RTP 2.b. Power Range Neutron Flux - Low 1(b), 2 s 25% RTP 25% RTP
- 3. Power Range Neutron Flux High Positive 1, 2 s 5% RTP 5% RTP Rate (3.a) with time with time constant constant 2! 2 sec 2! 2 sec
- 4. Intermediate Range Neutron Flux 1(b)' 2(c). 2(d) s 35% RTP 35% RTP
- 5. Source Range Neutron Flux 2(d), 3(a), 4(a), 5(a) s 1.0 E5 cps 1.0 E5 cps 8.a. Pressurizer Pressure - Low 1(I) 2! 1865 psig 1865 psig 8.b. Pressurizer Pressure - High 1, 2 s 2385 psig 2385 psig
- 9. Pressurizer Water Level - High 1(I) S92% 92%
- 10. Reactor Coolant Flow - Low (1 O.a and 1(I) 2! 90% 90%
10.b)
- 12. Undervoltage RCPs 1(I) 2! 2680 v 2680V
- 13. Underfrequency RCPs 1(I) 2! 57 Hz 57 Hz
- 14. Steam Generator (SG) Water Level - 1, 2 2! 28% 28%
Low Low 15.a. Turbine Trip on Low Auto Stop Oil 1(i) 2! 45 psig 45 psig Pressure (16.a) 17.a. RTS Interlocks, Intermediate Range 2(d) 2! 1E-10 amp 1E-10amp Neutron Flux - P-6 (18.a) 17.c. RTS Interlocks, Power Range Neutron 1 s 30% RTP 30% RTP Flux- P-8(18.c) 17.d. RTS Interlocks, Power Range Neutron 1 s 50% RTP 50% RTP Flux - P-9 (18.d) 17.e. RTS Interlocks, Power Range Neutron 1, 2 2! 8% RTP 8% RTP Flux - P-10 (18.e) and and s 10% RTP 10% RTP 17.f. RTS Interlocks, Turbine Impulse 1 $10% 10% turbine Pressure, P-13 (18.f) turbine power power
Farley RTS Function Applicable Modes (STS Revision 1 RTS Function Number or Other Specified Current Trip Nominal Trip if Different) Conditions Set point Setpoint (a) With reactor trip breakers (RTBs) closed and Rod Control System capable of rod withdrawal. (b) Below the P-10 (Power Range Neutron Flux) interlocks. (c) Above the P-6 (Intermediate Range Neutron Flux) interlocks. (d) Below the P-6 (Intermediate Range Neutron Flux) interlocks. (f) Above the P-7 (Low Power Reactor Trips Block) interlock. (i) Above the P-9 (Power Range Neutron Flux) interlock. The change to remove inequality symbols from RTS function nominal trip setpoint entries does not apply to the following Farley TS 3.3.1-1 RTS functions because there are no inequality symbols for them in the TS. Farley RTS Function Applicable Modes (STS Revision 1 RTS Function Number or Other Specified Current Trip Nominal Trip if Different) Conditions Set point Setpoint
- 1. Manual Reactor Trip 1, 2, 3(a), 4(a), 5(a) NA NA
- 6. Overtemperature i0. T 1, 2 Note 1 Note 1
- 7. Overpower i0. T 1, 2 Note 1 Note 1
- 11. Not used 15.b. Turbine trip Turbine Throttle Valve 1(i) NA NA Closure (16.b)
- 16. Safety Injection (SI) Input from 1, 2 NA NA Engineered Safety Feature Actuation System (ESFAS) (17) 17.b. RTS Interlocks, Low Power Reactor Trips 1 NA NA Block, P-7 (18.b)
- 18. Reactor Trip Breakers rn ( 19) 1, 2, 3(a), 4(a), 5(a) NA NA
- 19. Reactor Trip Breaker Undervoltage and 1, 2, 3(a), 4(a), 5(a) NA NA Shunt Trip Mechanisms (20)
- 20. Automatic Trip Logic (21) 1, 2, 3(a), 4(a), 5(a) NA NA (a) With RTBs closed and Rod Control System capable of rod withdrawal.
(i) Above the P-9 (Power Range Neutron Flux) interlock.
Farley RTS Function Applicable Modes (STS Revision 1 RTS Function Number or Other Specified Current Trip Nominal Trip if Different) Conditions Setpoint Setpoint U) Including any reactor trip bypass breaker that is racked in and closed for bypassing an RTB. The Farley TS Table 3.3.1-1 does not contain RTS functions corresponding or equivalent to the following STS, Revision 1, Table 3.3.1-1, "RTS Functions": 3.b Power Range Neutron Flux High Negative Rate
- 15. SG Water Level - Low
- 15. SG Water Level - Low (coincident with steam flow/feedwater flow mismatch) 16.b Turbine Trip on Turbine Throttle Valve Closure (the STS do have a numerical trip setpoint expressed as an inequality for this function)
- Farley TS Table 3.3.2-1, "ESFAS Instrumentation" ESFAS functions with the trip setpoint value expressed using an inequality symbol, for which the symbol is removed, consistent with the traveler change to the corresponding ESFAS function in STS Table 3.3.2-1, are the following, with the current and revised nominal trip setpoint entries listed:
Farley ESFAS Function Applicable Modes (STS Revision 1 ESFAS Function Number or Other Specified Current Trip Nominal Trip if Different) Conditions Setpoint Set point 1.c Safety Injection, Containment Pressure 1, 2, 3 s 4.0 psig 4.0 psig
- High 1 1.d Safety Injection, Pressurizer Pressure - 1, 2, 3(a) ~ 1850 psig 1850 psig Low 1.e.(1) Safety Injection, Steam Line Pressure - 1, 2, 3(b) ~ 585(c) psig 585(c) psig Low 1.e.(2) Safety Injection, Steam Line Pressure - 1,2, 3 s 100 psig 100 psig High Differential Pressure Between Steam Lines 2.c Containment Spray, Containment 1,2, 3 s 27 psig 27 psig Pressure High - 3 3.a.(3) Containment Isolation, Phase A 1, 2, 3 See See Isolation - on Safety Injection Functions Functions (Functions 1.c, 1.d, and 1.e) 1.c, 1.d, and 1.c, 1.d, and 1.e 1.e
Farley ESFAS Function Applicable Modes (STS Revision 1 ESFAS Function Number or Other Specified Current Trip Nominal Trip if Different) Conditions Setpoint Setpoint 3.b.(3) Containment Isolation, Phase B 1, 2, 3 Isolation - on Containment Pressure - High 3 4.c Steam Line Isolation, on Containment 1, 2(d), 3(d) :::; 16.2 psig 16.2 psig Pressure - High 2 4.d Steam Line Isolation, Steam Line 1, 2(d), 3{b)(d) ~ 585(c) psig 585(c) psig Pressure Low (4.d(1)) 4.e Steam Line Isolation, High Steam Flow 1, 2<d), 3(d) (e) (f) in Two Steam Lines Coincident with T avg - Low Low 1, 2<d) 3(d) I
~ 543°F 543°F 5.b Turbine Trip and Feedwater Isolation, 1, 2 $ 82% 82%
SG Water Level - High High (P-14) 5.c Turbine Trip and Feedwater Isolation - 1, 2, 3 See See on Safety Injection (Functions 1.c, 1.d, Functions Functions and 1.e) 1.c, 1.d, and 1.c, 1.d, and 1.e 1.e 6.b Auxiliary Feedwater - SG Water Level - 1, 2, 3 ~28% 28% Low Low (6.c) 6.d Auxiliary Feedwater - Undervoltage 1, 2 ~ 2680 volts 2680 volts Reactor Coolant Pump (6.f) 7.c ESFAS Interlocks - Pressurizer Pressure, 1,2, 3 :::; 2000 psig 2000 psig P-11 (8.b) 7.d ESFAS Interlocks - Tav 9 - Low Low, P-12 (Decreasing) (8.c) 1, 2, 3 ~ 543°F 543°F Tavg - Low Low, P-12 (Increasing) (8.c) 1, 2, 3 :s; 545°F 545°F
Farley ESFAS Function Applicable Modes (STS Revision 1 ESFAS Function Number or Other Specified Current Trip Nominal Trip if Different) Conditions Setpoint Setpoint (a) Above the P-11 (Pressurizer Pressure) interlock. (b) Above the P-12 (Tavg - Low Low) interlock. (c) Time constants used in the lead/lag controller are t1 ~ 50 seconds and 12 ~ 5 seconds. (d) Except when one MSIV is closed in each steam line. (e) Less than or equal to a function defined as ,ilP corresponding to 40.3% full steam flow below 20% load, ,ilP increasing linearly from 40.3% full steam flow at 20% load to 110.3% full steam flow at 100% load. (f) Less than or equal to a function defined as ,ilP corresponding to 40% full steam flow between 0% and 20% load and then a ,ilP increasing linearly from 40% steam flow at 20% load to 110% full steam flow at 100% load. The change to remove inequality symbols from ESFAS function nominal trip setpoint entries does not apply to the following Farley TS 3.3.1-1 ESFAS functions because they have no trip setpoint. Farley ESFAS Function Applicable Modes (STS Revision 1 ESFAS Function Number or Other Specified Current Trip Nominal Trip if Different) Conditions Setpoint Setpoint 1.a Safety Injection - Manual Initiation 1, 2, 3,4 NA NA 1.b Safety Injection - Automatic Actuation 1, 2, 3,4 NA NA Logic and Actuation Relays 2.a Containment Spray - Manual Initiation 1, 2, 3,4 NA NA 2.b Containment Spray - Automatic 1, 2, 3, 4 NA NA Actuation Logic and Actuation Relays 3.a(1) Containment Isolation, Phase A Isolation 1, 2, 3, 4 NA NA
- Manual Initiation 3.a(2) Containment Isolation, Phase A Isolation 1, 2, 3,4 NA NA
- Automatic Actuation Logic and Actuation Relays 3.a(3) Containment Isolation, Phase A Isolation 1, 2, 3,4 NA NA
- on Safety Injection (Functions 1.a and 1.b) 3.b(1) Containment Isolation, Phase B Isolation 1, 2, 3, 4 NA NA
- Manual Initiation 3.b(2) Containment Isolation, Phase B Isolation 1, 2, 3, 4 NA NA
Farley ESFAS Function Applicable Modes (STS Revision 1 ESFAS Function Number or Other Specified Current Trip Nominal Trip if Different) Conditions Setpoint Setpoint
- Automatic Actuation Logic and Actuation Relays 4.a Steam Line Isolation - Manual Initiation 1, 2(d), 3(d) NA NA 4.b Steam Line Isolation - Automatic 1, 2(dl, 3(d) NA NA Actuation Logic and Actuation Relays 5.a Turbine Trip and Feedwater Isolation - 1, 2 NA NA Automatic Actuation Logic and Actuation Relays 5.c Turbine Trip and Feedwater Isolation - 1, 2, 3, 4 NA NA on Safety Injection (Functions 1.a and 1.b) 6.a Auxiliary Feedwater - Automatic 1, 2, 3 NA NA Actuation Logic and Actuation Relays 6.c Auxiliary Feedwater - on 1, 2, 3, 4 NA NA Safety Injection (Functions 1.a and 1.b) 6.e Auxiliary Feedwater - on 1 NA NA Trip of all Main Feedwater Pumps (6.g) 7.a ESFAS Interlocks - Automatic Actuation 1, 2, 3 NA NA Logic and Actuation Relays 7.b ESFAS Interlocks - Reactor Trip, P-4 1, 2, 3 NA NA (d) Except when one main steam isolation valve is closed in each steam line.
The Farley TS Table 3.3.2-1 does not contain ESFAS functions corresponding or equivalent to the following STS Revision 1, Table 3.3.2-1, "ESFAS functions": 1.f Safety Injection, High Steam Flow in Two Lines, Coincident with Tavg - Low Low 1.g Safety Injection, High Steam Flow in Two Lines, Coincident with Steam Line Pressure - Low 4.d(2) Steam Line Isolation, Steam Line Pressure Negative Rate - High 4.f Steam Line Isolation, High Steam Flow in Two Lines Coincident with Steam Line Pressure - Low 4.g Steam Line Isolation, High Steam Flow in Two Lines Coincident with Safety Injection and T avg - Low Low 4.h Steam Line Isolation, High High Steam Flow Coincident with Safety Injection
6.e Auxiliary Feedwater, Loss of Offsite Power 6.h Auxiliary Feedwater, Auxiliary Feedwater Pump Suction Transfer on Suction Pressure - Low 7.b Automatic Switchover to Containment Sump, Reactor Water Storage Tank (RWST) Level - Low Low, Coincident with Safety Injection 7 .c Automatic Switchover to Containment Sump, RWST Level - Low Low, Coincident with Safety Injection and Containment Sump Level - High Licensee's Justification: The licensee provided the following justification for the proposed changes: TSTF-355 addresses a generic NRC concern with the Technical Specifications for RTS and ESFAS instrumentation functions that are structured to reflect the ISTS prior to Revision 2. The concern is related to an observed practice involving setting of RTS and ESFAS Trip Setpoints in a manner inconsistent with the trip setpoint inequalities, with tolerances beyond the maximum and minimum (inequalities) trip setpoint values shown in the TS. This practice can render the instrument inoperable based on the ITS surveillance requirements, Limiting Conditions for Operation (LCOs), and Actions. The inequalities on the ISTS Trip Setpoints were being interpreted as limits that, when exceeded, would require entry into the appropriate LCO Action. The proposed change revises the trip setpoint column of the RTS and ESFAS instrumentation tables to utilize a nominal trip setpoint value. Additionally, notes are provided in the Bases to clarify how the nominal trip setpoints are to be applied in the field; the relationship between the nominal trip setpoint, the allowable value, and the plant approved setpoint methodology; and how the Allowable Value relates to the Limiting Safety System Setting.
NRC Staff Evaluation
The proposed changes provide clarity between the nominal set points and the range of acceptable as-found trip settings for each RTS and ESFAS function. The changes document the basis for the use of allowable values rather than the trip setpoint as the Limiting Safety System Setting. The clarification does not adversely affect the requirements of 10 CFR 50.36. The proposed changes are consistent with guidance in Revision 4 of WOG STS. Therefore, the NRC staff finds that the proposed changes are acceptable. 3.21 TSTF-371-A Revision 1, "NIS Power Range Channel Daily SR TS Change to Address Low Power Decalibration" This traveler revised WOG STS LCO 3.3.1, RTS Instrumentation," SR 3.3.1.2, regarding the value of the difference between power range neutron flux power and calorimetric heat balance calculation power, which requires adjustment of the power range neutron flux channels to match the heat balance calculation power. It also revised STS SR 3.3.1.3 regarding the value of the difference between the axial flux difference using the excore power range neutron flux detectors
and the axial flux difference using incore neutron flux detector measurements that require adjustment of the power range neutron flux channels to match the incore neutron flux detector measurements. Farley TS LCO 3.3.1 specifies similar requirements. The application states: The proposed change to the Farley Technical Specifications is editorial, not technical. The Farley Technical Specifications already contain the technical change proposed in TSTF-371-A. This technical change was approved by the NRC in Farley License Amendment Number 144/135, dated October 1, 1999. It is noteworthy that the Farley amendment is referenced in the justification of TSTF-371-A. However, the generic Traveler addressing the technical issue was not approved by the NRC until April 2, 2002. As a result, the presentation in the Farley Technical Specifications is different from the generic presentation. The proposed change to the Farley Technical Specifications revises the presentation to be consistent with the ISTS and the other SNC [Southern Nuclear Operating Company] fleet plants.
- TS SR 3.3.1.2 Note 1 currently states:
Adjust NIS channel if calorimetric calculated power exceeds NIS indicated power by more than +2% RTP. The content of the current Note 1 is incorporated into SR 3.3.1.2. Note 2 is renumbered as Note 1. The proposed revision to SR 3.3.1.2 is shown in bold text below (removed text is lined out): Compare results of calorimetric heat balance calculation to Nuclear Instrumentation System (NIS) channel output power range channel output. Adjust power range channel output if calorimetric heat balance calculation results exceed power range channel output by more than +2% RTP.
- TS SR 3.3.1.3, Note 1 currently states:
Adjust NIS channel if absolute difference is ~ 3%. The content of Note 1 is incorporated into SR3.3.1.3. Note 2 is renumbered as Note 1. The proposed revision to SR 3.3.1.3 is shown in bold text below: Compare results of the incore detector measurements to Nuclear Instrumentation System (NIS) AFD. Adjust NIS channel if absolute difference is ~ 3% RTP.
NRC Staff Evaluation
The NRC staff's letter dated, October 1, 1999 (ADAMS Accession No. ML013130371 ), approved SNC's Amendment Nos. 144 (Unit 1) and 135 (Unit 2), dated October 1, 1999, by stating: SNC's proposed TS changes are based on Westinghouse Technical Bulletin ESBU-TB-92-R1 recommendations and SNC's plant-specific evaluations support the changes. Specifically, setting the PR [power range] neutron flux-high bistable to ::; 85 percent RTP [rated thermal power], 1) whenever the NIS [nuclear instrumentation system] indicated power is adjusted in the decreasing power direction below 50 percent RTP, or 2) before post refueling startup effectively addresses the current TS limitations mentioned in the Westinghouse bulletin. Based on the above Section 3.0 evaluation, the staff concludes that the proposed CTS [current TS] and ITS changes are acceptable. We are processing the ITS changes separately under the ITS Conversion program. Since the licensee's proposed changes do not affect the staff's conclusion stated above, especially the requirements of the Westinghouse Technical Bulletin ESBU-TB-92-R 1 (as required per the TSTF), there is no reduction in the current requirements for adjusting NIS channels. Therefore, the NRC staff concludes that the proposed changes meet the requirements of 10 CFR 50.36 and are acceptable. In addition, the proposed changes are consistent with the guidance in the WOG STS and TSTF-371-A, Revision 1. 3.22 TSTF-439-A. Revision 2. "Eliminate Second Completion Times Limiting Time From Discovery of Failure To Meet an LCO" This traveler modified Revision 2 of the WOG STS 3.6.6, 3.7.5, 3.8.1, and 3.8.9, by deleting the second Required Action Completion Time for Conditions in Actions tables that, without the second Completion Time, would logically permit alternating entry into two or more Conditions in such a manner that plant operation could continue indefinitely, without restoring compliance with the LCO. The traveler also modified the example in STS Section 1.3 associated with the application of these Completion Times. Current Farley TS and Proposed Changes: Farley TS 3.6.6, "Containment Spray and Cooling Systems"; 3.7.5, "Auxiliary Feedwater (AFW) System"; 3.8.1, "AC Sources - Operating"; and 3.8.9, "Distribution Systems - Operating," contain Required Actions with a second Completion Time to establish a limit on the maximum time allowed for plant operation in any combination of Conditions that result in a single, continuous failure to meet the LCO. These Completion Times (hereafter referred to as "second Completion Times") are joined by an "AND" logical connector to the Condition-specific Completion Time and state, "X days from discovery of failure to meet the LCO" (where "X" is a number that varies by specification). The proposed change deletes these second Completion Times from the affected Required Actions.
The proposed change also revises Farley TS Section 1.3, Example 1.3-3, as explained below: (a) Farley TS Section 1.3, "Completion Times," currently states: Example 1.3-3 illustrates one use of this type of Completion Time. The 10 day Completion Time specified for Conditions A and B in Example 1.3-3 may not be extended. (b) Example 1.3-3 currently reflects, for Conditions A and B, a first Completion time of 7 days and 72 hours, respectively, and a second Completion Time as "AND 10 days from discovery of failure to meet the LCO," for both Conditions. Condition C in the example does not contain a second Completion Time. (c) Farley TS Section 1.3 currently describes second completion time as follows: The Completion Times of Conditions A and B are modified by a logical connector with a separate 10 day Completion Time measured from the time it was discovered the LCO was not met. In this example, without the separate Completion Time, it would be possible to alternate between Conditions A, B, and C in such a manner that operation could continue indefinitely without ever restoring systems to meet the LCO. The separate Completion Time modified by the phrase "from discovery of failure to meet the LCO" is designed to prevent indefinite continued operation while not meeting the LCO. This Completion Time allows for an exception to the normal "time zero" for beginning the Completion Time clock". In this instance, the Completion Time "time zero" is specified as commencing at the time the LCO was initially not met, instead of at the time the associated Condition was entered. The proposed changes delete the statement in (a) above; revise the Example 1.3-3 in (b) above to eliminate the second Completion Times, "10 days from discovery of failure to meet the LCO," in Conditions A and B; and replace the discussion in (c) regarding second Completion Times with the following: It is possible to alternate between Conditions A, B, and C in such a manner that operation could continue indefinitely without ever restoring systems to meet the LCO. However, doing so would be inconsistent with the basis of the Completion Times. Therefore, there shall be administrative controls to limit the maximum time allowed for any combination of Conditions that result in a single contiguous occurrence of failing to meet the LCO. These administrative controls shall ensure that the Completion Times for those Conditions are not inappropriately extended.
NRC Staff Evaluation
On June 20, 2005 (ADAMS Accession No. ML051860296), the Technical Specifications Task Force submitted a proposed change, TSTF-439, Revision 2, "Eliminate Second Completion Times Limiting Time From Discovery of Failure To Meet an LCO," on behalf of the industry (TSTF-439, Revisions 0 and 1, were prior draft iterations). TSTF-439 proposed a new TS
convention to limit the maximum time allowed for any combination of LCO Conditions that could result in a single continuous failure to meet the LCO. By letter dated January 11, 2006 (ADAMS Accession No. ML060120272), the NRC approved TSTF-439, Revision 2. This traveler has been incorporated into Revision 4 of NUREG-1431. Second Completion Times are those joined by an "AND" logical connector to the condition-specific Completion Time and which state, "X hours/days from discovery of failure to meet the LCO." At the time the format and usage rules of the STS were created, there were no regulatory requirements or programs to preclude entry into and out of the actions for an indefinite period of time without meeting the LCO. A second Completion Time was included in the STS for certain Required Actions to establish a limit on the maximum time allowed for any combination of conditions that result in a single continuous failure to meet the LCO. The intent of the second Completion Time was to preclude entry into and out of the actions for an indefinite period of time without meeting the LCO. The second Completion Time provides a limit on the amount of time that an LCO would not be met for various combinations of conditions. The licensee's TSs are modeled after the STS. The licensee justified the proposed changes in its amendment request by referring to the controls of the Maintenance Rule and the new requirement proposed in Section 1.3 of the TSs. Specifically, the licensee stated: The proposed change is appropriate because multiple continuous entries into Conditions, without meeting the LCO, will be controlled by licensee's configuration risk management programs, which were implemented to meet the requirements 10 CFR 50.65 (the Maintenance Rule) to assess and manage risk, and controlled by the Use and Application convention discussed in Section 1.3 of the Technical Specifications. These controls provide adequate assurance against inappropriate use of combinations of Conditions that result in a single contiguous occurrence of failing to meet the LCO. Licensee Proposed Procedural Changes to Adopt this Change: SNC commits to revise Operations procedure FNP-O-SOP-0.13 to include a statement similar to the following: "Alternating between LCO Conditions, in order to allow indefinite continued operation while not meeting the LCO, is not allowed." This procedure will be revised prior to implementation of the proposed change. The Maintenance Rule: 10 CFR 50.65 (a)(1) (the Maintenance Rule) requires each licensee to monitor the performance or condition of structures, systems, and components (SSCs) against licensee-established goals to ensure that the SSCs are capable of fulfilling their intended functions. If the performance or condition of an SSC does not meet established goals, appropriate corrective action is required to be taken. The NRC resident inspectors monitor the licensee's Corrective Action process and can take action if the licensee's maintenance program allows the systems required by a single LCO to become concurrently inoperable multiple times. The performance and condition monitoring activities required by 10 CFR 50.65 (a)(1) and (a)(2) would identify if poor maintenance practices resulted in multiple entries into the Actions of the TSs and unacceptable
unavailability of these SSCs. The effectiveness of these performance monitoring activities, and associated corrective actions, is evaluated at least every refueling cycle, not to exceed 24 months, per 10 CFR 50.65 (a)(3). Prior to 10 CFR 50.65, TSs were the primary rules governing operations, including what equipment must normally be in service, how long equipment can be out of service, compensatory actions, and surveillance testing to demonstrate equipment readiness. A goal of the TSs is to provide adequate assurance of the availability and reliability of equipment needed to prevent, and, if necessary, mitigate, accidents and transients. The Maintenance Rule shares this goal and operates through a dynamic and comprehensive process. The objective of the cornerstone is to monitor the availability, reliability, and capability of systems that mitigate the effects of initiating events to prevent core damage. Licensees also reduce the likelihood of reactor accidents by maintaining the availability and reliability of mitigating systems. Mitigating systems include those systems associated with safety injection, decay heat removal, and their support systems, such as emergency AC power systems (which encompasses the AC Sources Distribution System LCOs, as noted by the licensee), and the AFW system. Inputs to the mitigating systems cornerstone include both inspection procedures and performance indicators to ensure that all reactor oversight process objectives are being met. Satisfactory licensee performance within the mitigation systems reactor oversight process cornerstone provides reasonable assurance in monitoring the inappropriate use of TS condition Completion Times. The NRC approved this change to WOG STS, Revision 2, on January 11, 2006. TSTF-439-A revised Example 1.3-3 of the TSs to state, in part, "There shall be administrative controls to limit the maximum time allowed for any combination of Conditions that result in a single contiguous occurrence of failing to meet the LCO. These administrative controls shall ensure that the Completion Times for those Conditions are not inappropriately extended." The NRC has asked licensees adopting TSTF-439-A to provide the location of these administrative controls. SNC plans to revise Operations Procedure FNP-O-SOP-0.13 to include a statement similar to the following: "Alternating between LCO Conditions, in order to allow indefinite continued operation while not meeting the LCO, is not allowed." This procedure will be revised prior to implementation of the proposed change. The NRC staff has determined that the proposed changes establish a new TS convention to appropriately limit the time allowed for the plant to operate in any combination of LCO Conditions that could result in a single continuous failure to meet the LCO. The new convention meets the intent of the Completion Times. As a result, the NRC staff concludes that the requirements of 10 CFR 50.36(c)(2) remain unaffected by the proposed changes and would continue to be met because the minimum performance level of equipment needed for safe operation of the facility is contained in the LCO, and the appropriate remedial measures are specified if the LCO is not met. Based on the above, the NRC staff concludes the proposed changes are acceptable.
3.23 ISTS Adoption #1 - Revise LCO 3.3.2 ESFAS Interlock P-4 Required Action Completion Time When SNC converted the Farley, Units 1 and 2, plant-specific custom TSs to plant-specific Improved TSs (in 1997), it elected not to increase the 24-hour Completion Time to restore to operable status an inoperable channel of the P-4 (Reactor Trip) ESFAS interlock, TS 3.3.2, Function 7.b, to a Completion Time of 48 hours, which had been the requirement in WOG STS since 1981. In this LAR, the licensee proposed to adopt the 48-hour Completion Time by changing the specified Condition for this function in Table 3.3.2-1 from C to F.
NRC Staff Evaluation
The NRC requested additional information by letter dated August 14, 2015, to provide justification consistent with the safety basis for the 48-hour Completion Time. SNC responded by supplement dated September 28, 2015. The provided justification is consistent with the safety basis for the 48-hour Completion Time in the STS; therefore, the NRC staff finds the response and the 48-hour Completion Time acceptable. The NRC staff further concludes that the requirements of 10 CFR 50.36(c)(2) remain unaffected by the proposed change and that the LCO would continue to be met, because the minimum performance level of equipment needed for safe operation of the facility is contained in the LCO, and the appropriate remedial measures are specified if the LCO is not met. 3.24 Revise LCO 3.5.5 Action Completion Time and SR 3.5.5.1 Note In response to a letter from the NRC sent on August 14, 2015, requesting additional information to justify the requested change in a Required Action Completion Time and a Note in SR 3.5.5.1 of Farley TS 3.5.5, SNC withdrew this request. The withdrawal is acceptable to the NRC staff since the proposed change is not considered in the staffs justification for the changes discussed in this safety evaluation.
4.0 STATE CONSULTATION
In accordance with the Commission's regulations, the Alabama State official was notified of the proposed issuance of the amendments. The State official had no comments.
5.0 ENVIRONMENTAL CONSIDERATION
The amendments change requirements with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20 and changes SRs. The NRC staff has determined that the amendments involve no significant increase in the amounts and no significant change in the types of any effluents that may be released offsite and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding (80 FR 5804, February 3, 2015). Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.
6.0 CONCLUSION
The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public. Principal Contributors: T. Tjader, NRO C. Harbuck, NRO H. Le, NRO D. Scully, NRO R. Grover, NRR Date: August 3, 2016
C. Pierce A Notice of Issuance will be included in the Commission's biweekly Federal Register notice. Sincerely, IRA/ Shawn A. Williams, Senior Project Manager Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-348 and 50-364
Enclosures:
- 1. Amendment No. 203 to NPF-2
- 2. Amendment No. 199 to NPF-8
- 3. Safety Evaluation cc w/enclosures: Distribution via Listserv DISTRIBUTION:
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