ML062860267
| ML062860267 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 10/05/2006 |
| From: | Crouch W Tennessee Valley Authority |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| TAC MC3743, TAC MC3744, TAC MC3812, TVA-BFN-TS-418, TVA-BFN-TS-431 | |
| Download: ML062860267 (131) | |
Text
Tennessee Valley Authority, Post Office Box 2000, Decatur, Aabama 35609-2000 October 5, 2006 TVA-BFN-TS-431 TVA-BFN-TS-418 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN:
Document Control Desk Mail Stop OWFN, Pl-35 Washington, D. C.
20555-0001 Gentlemen:
In the Matter of
)
Docket Nos. 50-259 Tennessee Valley Authority
)
50-260 50-296 BROWNS FERRY NUCLEAR PLANT (BFN)
UNITS 1, 2,
AND 3 -
TECHNICAL SPECIFICATIONS (TS)
CHANGES TS-431 AND TS-418 -
EXTENDED POWER UPRATE (EPU)
RESPONSE TO ROUND 10 REQUEST FOR ADDITIONAL INFORMATION (RAI)
(TAC NOS.
By letters dated June 28, 2004 and June 25, 2004 (ADAMS Accession Nos. ML041840109 and ML041840301, respectively),
TVA submitted license applications to the NRC for the EPU of BFN Unit 1 and BFN Units 2 and 3, respectively.
On September 27, 2006, the NRC staff issued the Round 10 RAI regarding the EPU license amendment requests.
to this submittal provides TVA's responses to the Round 10 RAI questions.
In addition to the Round 10 RAI responses, included in is a supplement to TVA's response to question ACVB-62 that was provided in response to the Round 9 RAI by TVA letter of September 15, 2006.
U.S. Nuclear Regulatory Commission Page 2 October 5, 2006 In a previous EPU submittal, by letter dated May 15, 2006 (ML061450390),
TVA provided the Supplemental Reload Licensing Report (SRLR) for the Cycle 7 operation of BFN Unit 1. The analyses summarized in that SRLR are based on a Cycle 7 operating plan that assumed EPU operation (i.e., 120% of original licensed thermal power (OLTP)).
However, the licensing of BFN Unit 1 for EPU operation is now planned to occur in two steps as outlined in TVA's letter of September 22, 2006 (ML062680459).
Because the initial operation of Unit 1 Cycle 7 will be at 105% of OLTP, the core analyses are being reperformed consistent with an interim 105%
OLTP level of 3458 MWt.
To support operation of BFN Unit 1 at 105% OLTP, TVA and its fuel supplier are reevaluating the core design for Cycle 7 and performing revised analyses, which will result in a revised SRLR.
TVA expects to provide the revised SRLR to the NRC by January 31, 2007.
Note that Enclosure 1 contains information that General Electric Company (GE) considers to be proprietary in nature and subsequently, pursuant to 10 CFR 9.17(a) (4),
2.390(a) (4) and 2.390(d) (1),
such information should be withheld from public disclosure. is a redacted version of with the GE proprietary material removed and is suitable for public disclosure.
Enclosures 1 and 2 contain an affidavit from GE supporting this request for withholding from public disclosure.
Enclosures 3 and 4 provide information requested in Round 10 RAI question APLA-27/29 for BFN Units 2 and 3, respectively.
To facilitate NRC's review of the proposed TS-418 TS
- changes, TVA has remarked in Enclosure 5, the current Unit 2 and Unit 3 TS pages to reflect those changes necessary for full EPU operation.
These changes reflect recently issued TS amendments and a revision to a page (i.e., Unit 2 TS page 3.7-17) that was incorrectly marked in TVA's submittal of September 1, 2006 (ML062500197).
TVA has determined that the additional information provided by this letter does not affect the no significant hazards considerations associated with the proposed TS changes.
The proposed TS changes still qualify for a categorical exclusion from environmental review pursuant to the provisions of 10 CFR 51.22(c) (9).
U.S. Nuclear Regulatory Commission Page 3 October 5, 2006 Two new regulatory commitments are made in this submittal. describes these commitments.
If you have any questions regarding this letter, please contact me at (256)729-2636.
I declare under penalty of perjury that the foregoing is true and correct.
Executed on this 5 th day of October 2006.
Sincerely, William D. Crouch Manager of Licensing and Industry Affairs
Enclosures:
- 1. Response to Round 10 RAI Questions (Proprietary Information Version)
- 2.
Response to Round 10 RAI Questions (Non-Proprietary Version)
- 3. Reply to RAI APLA-27/29 for Unit 2
- 4. Reply to RAI APLA-27/29 for Unit 3
- 5.
EPU TS Changes Remarked Using Current TS Pages
U.S. Nuclear Regulatory Commission Page 4 October 5, 2006 Enclosures cc: (Enclosures):
State Health Officer Alabama Dept. of Public Health RSA Tower - Administration Suite 1552 P.O. Box 303017 Montgomery, AL 36130-3017 U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-3415 Mr. Malcolm T.
Widmann, Branch Chief U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-8931 NRC Senior Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, Alabama 35611-6970 NRC Unit 1 Restart Senior Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, Alabama 35611-6970 Margaret Chernoff, Project Manager U.S. Nuclear Regulatory Commission (MS 08G9)
One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739 Ms.
Eva A. Brown, Project Manager U.S. Nuclear Regulatory Commission (MS 08G9)
One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739
NON-PROPRIETARY VERSION ENCLOSURE 2 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)
UNITS 1, 2, AND 3 TECHNICAL RESPONSE TO SPECIFICATIONS (TS)
CHANGES TS-431 AND TS-418 -
EXTENDED POWER UPRATE (EPU)
ROUND 10 REQUEST FOR ADDITIONAL INFORMATION (RAI)
(TAC NOS.
RESPONSE TO ROUND 10 RAI QUESTIONS (NON-PROPRIETARY VERSION)
This enclosure is a redacted version of the response to NRC's September 27, 2006, Round 10 RAI questions in Enclosure 1 with the proprietary material removed.
This enclosure contains an affidavit from General Electric Company supporting the request for withholding the proprietary information contained in from public disclosure.
AFFIDAVIT I, George B. Stramback, state as follows:
(1) I am Manager, Regulatory Services, General Electric Company ("GE") and have been delegated the function of reviewing the information described in paragraph (2) which is sought to be withheld, and have been authorized to apply for its withholding.
(2) The information sought to be withheld is contained in Enclosure 1 to GE letter GE-ERI-AEP-06-349 Larry King (GE) to J. Valente (TrVA), GE Responses to NRC Requests for Additional Information - SBWB - 50/75, dated September 29, 2006.
The proprietary information in Enclosure 1, GE Responses to NRC RAI - SBWB-
.50/75, is delineated by a double underline inside double square brackets. Figures and large equation objects are identified with double square brackets before and after the object. In each case, the superscript notation (3) refers to Paragraph (3) of this affidavit, which provides the basis for the proprietary determination.
(3) In making this application for withholding of proprietary information of which it is the owner, GE relies upon the exemption from disclosure set forth in the Freedom of Information Act ("FOIA"), 5 USC Sec. 552(bX4), and the Trade Secrets Act, 18 USC Sec. 1905, and NRC regulations 10 CFR 9.17(aX4), and 2.390(a)(4) for "trade secrets" (Exemption 4). The material for which exemption from disclosure is here sought also qualify under the narrower definition of "trade secret", within the meanings assigned to those terms for purposes of FOIA Exemption 4 in, respectively, Critical Mass Energy Project v. Nuclear Regulatory Commission, 975F2d871 (DC Cir. 1992), and Public Citizen Health Research Group v. FDA, 704F2d1280 (DC Cir. 1983).
(4) Some examples of categories of information which fit into the definition of proprietary information are:
- a.
Information that discloses a process, method, or apparatus, including supporting data and analyses, where prevention of its use by General Electric's competitors without license from General Electric constitutes a competitive economic advantage over other companies;
- b.
Information which, if used by a competitor, would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing of a similar product;
- c.
Information which reveals aspects of past, present, or future General Electric customer-funded development plans and programs, resulting in potential products to General Electric;
- d.
Information which discloses patentable subject matter for which it may be desirable to obtain patent protection.
The information sought to be withheld is considered to be proprietary for the reasons set forth in paragraphs (4)a, and (4)b, above.
GBS-06-05-afBFN 1 EPU RAT Responses GE-ER1-AEP-06-349 9-29-06.doc Affidavit Page I of 3
(5) To address 10 CFR 2.390 (b) (4), the information sought to be withheld is being submitted to NRC in confidence. The information is of a sort customarily held in confidence by GE, and is in fact so held. The information sought to be withheld has, to the best of my knowledge and belief, consistently been held in confidence by GE, no public disclosure has been made, and it is not available in public sources. All disclosures to third parties including any required transmittals to NRC, have been made, or must be made, pursuant to regulatory provisions or proprietary agreements which provide for maintenance of the information in confidence.
Its initial designation as proprietary information, and the subsequent steps taken to prevent its unauthorized disclosure, are as set forth in paragraphs (6) and (7) following.
(6) Initial approval of proprietary treatment of a document is made by the manager of the originating component, the person most likely to be acquainted with the value and sensitivity of the information in relation to industry knowledge. Access to such documents within GE is limited on a "need to know" basis.
(7) The procedure for approval of external release of such a document typically requires review by the staff manager, project manager, principal scientist or other equivalent authority, by the manager of the cognizant marketing function (or his delegate), and by the Legal Operation, for technical content, competitive effect, and determination of the accuracy of the proprietary designation. Disclosures outside GE are limited to regulatory bodies, customers, and potential customers, and their agents, suppliers, and licensees, and others with a legitimate need for the information, and then only in accordance with appropriate regulatory provisions or proprietary agreements.
(8) The information identified in paragraph (2), above, is classified as proprietary because it contains detailed results and conclusions from evaluations of the safety-significant changes necessary to demonstrate the regulatory acceptability for the power uprate of a GE BWR, utilizing analytical models, methods and processes, including computer codes, which GE has developed, obtained NRC approval of and applied to perform evaluations of the transient and accident events in the GE Boiling Water Reactor ("BWR").
The development and approval of these system, component, and thermal hydraulic models and computer codes was achieved at a significant cost to GE, on the order of several million dollars.
The development of the underlying evaluation process along with the interpretation and application of the analytical results is derived from the extensive experience database that constitutes a major GE asset.
(9) Public disclosure of the information sought to be withheld is likely to cause substantial harm to GE's competitive position and foreclose or reduce the availability of profit-making opportunities. The information is part 'of GE's comprehensive BWR safety and technology base, and its commercial value extends beyond the original development cost. The value of the technology base goes beyond the extensive physical database and analytical methodology and includes development of the expertise to determine and apply the appropriate ievaluation process. In addition, the technology base includes the value derived from providing analyses done with NRC-approved methods.
GBS-06-05-aftBFN 1 EPU RAI Responses GE-ERI-AEP-06-349 9-29-06.doc Affidavit Page 2 of 3
addition, the technology base includes the value derived from providing analyses done with NRC-approved methods.
The research, development, engineering, analytical and NRC review costs comprise a substantial investment of time and money by GE.
The precise value of the expertise to devise an evaluation process and apply the correct analytical methodology is difficult to quantify, but it clearly is substantial.
GE's competitive advantage will be lost if its competitors are able to use the results of the GE experience to normalize or verify their own process or if they are able to claim an equivalent understanding by demonstrating that they can arrive at the same or similar conclusions.
The value of this information to GE would be lost if the information were disclosed to the public. Making such information available to competitors without their having been required to undertake a similar expenditure of resources would unfairly provide competitors with a windfall, and deprive GE of the opportunity to exercise its competitive advantage to seek an adequate return on its large investment in developing these very valuable analytical tools.
I declare under penalty of perjury that the foregoing affidavit and the matters stated therein are true and correct to the best of my knowledge, information, and belief.
Executed on this 2 9 th day of September 2006.
Gerge W. Strambiek General Electric Company GBS-06-05-afBFN I EPU RAI Responses GE-ERI-AEP-06-349 9-29-06.doc Affidavit Page 3 of 3
NON-PROPRIETARY VERSION NRC RAI EEMB-115/85 The Nuclear Regulatory Commission (NRC) staff requested a discussion of any weld reinforcement following fatigue cracking of drain channel in the BFN steam dryers.
In its response to this request (identified as EEMB-C.1 on page El-106 of the July 26 submittal),
the Tennessee Valley Authority (TVA, the licensee) states it has periodically inspected the Units 2 and 3 repaired drain channel welds subsequent to 105 percent original licensed thermal power (OLTP) operation.
- a.
Identify the inspection technique used for Units 2 and 3 and explain whether that technique was qualified to detect fatigue cracks.
- b.
Specify whether these periodic inspections will be performed subsequent to 105 percent OLTP operation for Unit 1. If so, identify the inspection technique to be used and explain whether that technique is qualified to detect fatigue cracks.
TVA Response to EEMB-115/85 The inspection technique originally used to visually examine the Unit 2 and Unit 3 steam dryer drain channel welds was VT-3.
When GE Service Information Letter (SIL) No.
- 474, "Steam Dryer Drain Channel Cracking," was issued, a VT-3 inspection was considered adequate to detect fatigue cracking of this component.
Using this technique, fatigue cracks were identified and subsequently repaired on the steam dryers for Units 2 and 3.
Limited VT-I inspections were made on both Unit 2 and Unit 3 steam dryers during refueling outages that occurred in the Spring of 2005 and the Spring of 2004, respectively, and no fatigue cracking was identified.
Prior to EPU operation, the drain channels of all three BEFN units are required to be inspected to meet VT-I requirements per the guidelines of BWRVIP-139 and GE SIL No.
644, Revision 1. VT-I is the current examination method recommended for this component and is considered adequate to detect fatigue cracking.
The examination method used for the Unit 1 steam dryer drain channel inspections was VT-I.
Following implementation of EPU, periodic inspection of the BFN steam dryers will be conducted in accordance with the guidance of SIL No.
644, Revision 1, and BWRVIP-139, which include the use of the VT-I inspection technique.
E2-1
NON-PROPRIETARY VERSION NRC RAI EEMB-116/86 The NRC staff requested a discussion of the post-modification inspection procedures for the BFN steam dryer modifications.
In its response to this request (identified as EEMB-C.19 on pages El-125 and 126 of the July 26 submittal),
TVA stated that the post-modification inspection will be conducted employing visual inspection (VT-2).
Discuss the adequacy of this inspection method, and the ability to conduct a more detailed inspection of the BFN Unit 1 steam dryer.
TVA Response to EEMB-116/86 The response to RAI question EEMB-C.19 contained a typographical error.
The correct reference to the visual inspection required is VT-I.
VT-I is currently recommended by the GE SIL 644, Revision 1, and BWRVIP-139 for these dryer examinations of concern, and is required by the TVA BFN Reactor Pressure Vessel Internals Inspection procedure.
NRC RAI EEMB-117/87 Section 9.9 of Rev. 2 of the steam dryer stress report states that TVA plans to use pressure transducers mounted in holes in the main steam lines (MSLs) to measure fluctuating pressures as input to the acoustic circuit model (ACM).
Provide a schematic of the proposed installation, which shows clearly the location of the pressure transducer with respect to the inner surface of the MSL walls.
Since pressure transducers exposed to steam flow will measure acoustic pressure and turbulence traveling through the MSLs and over the pressure transducer, quantify any bias error or uncertainty that might be introduced to the dryer leads computed with the Bounding Pressure ACM by the presence of turbulence-induced pressures in the ACM inputs.
TVA Response to EEMB-117/87 As discussed with the NRC staff on September 28,
- 2006, TVA will install strain gages on the exterior of the main steam lines instead of the dynamic pressure transducers.
NRC RAI EEMB-118 In the July 26, 2006 response, the licensee indicated that Unit 1 is currently performing restart modifications and that the final stress analysis results, which reflect the as-built configuration, are not available for most of the reactor coolant pressure boundary and balance-of-plant systems.
Provide the schedule for completion of the piping-system evaluation for Unit 1. Upon completion, provide the evaluation summary for piping systems and their supports including main steam, feedwater, recirculation, residual heat removal, and torus-E2-2
NON-PROPRIETARY VERSION attached piping systems.
The information should include the calculated maximum stresses and fatigue usage factors, as necessary, for piping systems and their supports similar to those provided for the Units 2 and 3 extended power uprate (EPU) evaluation.
TVA Response to EEMB-118 Evaluations of Unit 1 piping and supports associated with restart modifications are ongoing.
As noted in TVA's letter of September 22, 2006, engineering activities in support of these modifications are scheduled for completion in December 2006.
Upon completion next February, an evaluation summary for piping systems (including main steam, feedwater, recirculation, residual heat removal (RHR),
and torus attached piping) will be provided to the NRC staff.
The information provided will include the calculated maximum stresses for piping systems similar to the information provided for the EPU application of Units 2 and 3.
The design basis code of record for BFN is the USAS B31.1.0-1967 code; consequently, fatigue usage factors have not been calculated for the balance-of-plant piping systems.
NRC RAI APLA-27/29 For this request, an operator action is "important to risk" if any one of the following criteria is met:
(1) Fussell Vesely (FV) importance to core damage frequency (CDF) greater than 0.005; (2)
FV importance to large early release frequency (LERF) greater than 0.005; (3) risk achievement worth (RAW) importance to CDF greater than two; or (4) RAW importance to LERF greater than two.
Provide the following information for operator actions modeled in the probabilistic risk assessment that are important to risk:
- a.
Basic event (operator action) name
- b.
Description
- c.
Where action is performed (e.g., control room, outside control room, both)
- d.
For the pre-EPU model;
- i.
- v.
time available to the operator from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release vi.
Human error probability E2-3
NON-PROPRIETARY VERSION
- e.
For the post-EPU model:
- i.
- v.
Time available to the operator from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release vi.
Human error probability TVA Response to APIA-27/29 The requested information for pre-EPU and post-EPU for Units 2 and 3 is provided in Enclosures 3 and 4, respectively.
The EPU values are based on the current revisions of the probabilistic risk assessments (PRAs) for Units 2 and 3.
The differences between the pre-EPU PRAs and the current PRAs involve several changes including EPU operation, Unit 1 operation, and model corrections.
Currently, the Unit 1 PRA is being revised to resolve comments from a recent (late September) PRA Peer Review Certification effort.
Since Unit 1 did not have a pre-EPU PRA and the Unit 1 PRA was built from the Unit 2 and 3 PRAs, the information regarding Unit 2 and Unit 3 is representative of all three BFN units.
NRC RAI ACVB-62 (BFN Units 1, 2, and 3)
The August 4, 2006 response to Request for Additional Information (RAI) Risk Assessment Containment & Ventilation Branch (ACVB) 37/35 states that, for the CS pump, the operator is instructed to maintain flow less than 4000 gallons per minute (gpm) and within the NPSH limit curves.
However, for determining adequate NPSH, it is assumed that the operator would reduce flow in response to the NPSH limit curves, but not less than 3125 gpm.
It appears that at a flow rate of 4000 gpm and the peak calculated suppression pool temperature, the pumps are in the acceptable region of the Emergency Operating Instruction NPSH limit curves.
Therefore, explain what prompts the operator to reduce flow to 3125 gpm.
If the operator can operate acceptably at 4000 gpm, address why shouldn't this more conservative flow rate be used in the NPSH analyses.
E2-4
NON-PROPRIETARY VERSION TVA Response to ACVB-62 (BFN Units 1, 2, and 3)
The following information was provided in TVA's September 15, 2006, response to the EPU Round 9 RAI:
In the long-term LOCA event, the operator will control ECCS pump flow in accordance with the EOIs and within the NPSH limit curves based on plant symptoms.
The NPSH analysis for long-term LOCA shows that at the peak suppression pool temperature, margin is available between the required and available wetwell pressures.
The margin indicates that adequate NPSH would be available at 4000 GPM and the operator would not and should not be prompted by the EOIs to reduce core spray flow.
In contrast to the symptomatic EOIs, the safety analysis that forms the basis for COP credit is based on worst case conditions.
The objective is to demonstrate that the ECCS pumps will be able to perform their safety function given bounding events and worst case assumptions.
Consistent with this objective, the pump flow rates used are the minimum acceptable flows needed for the safety function plus a conservative margin.
This flow is 3125 GPM in the case of core spray.
By performing the analysis at this value, the safety function is assured and COP margin is established.
At flows above this value, operator action will ensure adequate NPSH is maintained as dictated by the symptoms as they exist.
The following is provided as additional clarification and supplements the previous response.
The purpose of the design basis NPSH analysis is to demonstrate the adequacy of plant design.
The core spray system NPSH calculation for the long-term DBA-LOCA case shows that adequate NPSH will be available such that the operator will not be directed to reduce core spray pump flow below the flow required by the ECCS-LOCA performance analysis (10 CFR 50.46 safety analyses).
The core spray pump minimum flow rate used in the ECCS-LOCA performance analysis is 3125 gpm.
Therefore, the value of 3125 gpm was used in the NPSH calculation.
By performing the NPSH evaluations at 3125 gpm, it is ensured that adequate NPSH is provided at the minimum flow required by the safety analyses.
E2-5
NON-PROPRIETARY VERSION NRC RAI ACVB-68/66 The staff has determined that the information in the May 24, 1976, report may not be sufficient to justify credit for a value of required net positive suction head (NPSH) less than the 3%
head loss value.
- a.
Provide any supporting information not included in the May 24, 1976, report which supports the use of a lower value such as:
- i.
accelerometer data, ii.
time that the Residual Heat Removal (RHR) pump was in cavitation, and iii.
the inspections performed on the pump before and after testing.
- c.
Describe the operational history of RHR pump 3A.
Address whether pump RHR 3A experienced any abnormal operation since this testing.
TVA Response to ACVB-68/66 Except for the case of RHR pumps injecting into a broken recirculation loop, sufficient NPSH has been demonstrated to be available for all licensing basis NPSH cases and meets vendor requirements.
This case is different than the remainder of the NPSH analysis in that the concern is not for pump performance, but only for pump survivability.
The most limiting NPSH condition identified for the RHR pumps exists during the 5 to 10 minute approximate timeframe immediately following a postulated DBA LOCA involving a break of a recirculation discharge pipe.
This event forms the basis for the short term NPSH analysis.
The NPSH results are presented in Figure ACVB-56/54-1 from the August 4, 2006, submittal (ML062220647) and indicate that available suppression pool pressure is 0.85 psi less than that required to maintain the vendor recommended NPSH.
This issue dates back to 1976 when the potential for runout flow on the broken loop RHR pumps was identified in TVA letters to the NRC dated May 21, 1976, and July 21, 1976.
At that time a reduced NPSH flow test was performed with the 3A RHR pump in order to demonstrate conservatism in vendor NPSH requirements.
In the RHR pump broken loop analysis, the affected pumps are not performing any function during the time period that negative NPSH margin exists.
The success criteria for this analysis is no pump damage occurs that results in failure of the RHR pumps, so they can be credited later in the event (>10 minutes) while operating in the containment cooling mode in the event of a single failure (such as loss of RHR service water) which could disable the heat removal function on the other loop of RHR.
The 1976 test data is referenced for EPU in response to RAI question SPSB-A-lI in TVA letters of March 23, 2006 (ML060880460 and ML060880395 for BFN E2-6
NON-PROPRIETARY VERSION Unit 1 and BFN Units 2 and 3, respectively),
to demonstrate that vendor NPSH requirements used in NPSH calculations are conservative.
This is particularly true when considering the success criteria of interest in this scenario, which is no damage resulting in RHR pump failure.
The test performed by TVA in 1976 demonstrates that the vendor's NPSH curves used to calculate NPSH margin are conservative relative to the negative NPSH margin shown in the analysis.
This provides reasonable assurance that the pumps will not experience severe operational problems in the broken loop transient scenario.
Vendor review of the 1976 data was inconclusive with regard to determining pump behavior at reduced suction pressure and high flows; the pump vendor's (Sulzer) report E12.5.1296 RO, "NPSH Transient Study," concludes that catastrophic damage to the pump should not occur for the broken loop transient.
Therefore, even if the pumps do experience some cavitation for this short period of time
(-
5 minutes),
it is not expected that the pumps would be severely damaged, and thus, the pumps are expected to function later in the event in the containment cooling mode.
In response to the specific RAI questions posed:
- a.
By letter dated July 21,
- 1976, TVA provided to NRC the results of the testing performed on the RHR pump for the reduced NPSH performance tests.
Included in that submittal were the pump vibration data that was taken and the durations of the tests at reduced NPSH.
In August/September 1994, the 3A RHR pump impeller was replaced to address generic wear ring cracking concerns.
A review of documentation associated with this replacement did not indicate any abnormal impeller wear.
- b.
TVA has performed a search of completed surveillances and work orders associated with the 3A RHR pump during the two year time frame following the reduced NPSH testing conducted in 1976.
No anomalies in surveillance testing or pump maintenance were identified.
NRC RAI ACVB-69/67 Describe the peak short-term loss of coolant accident (LOCA) suppression pool temperature at 105% power.
Provide the service water temperature assumed in this analysis.
E2-7
NON-PROPRIETARY VERSION TVA Response to ACVB-69/67 The peak short-term (< 10 minutes) LOCA suppression pool temperature utilized for 105% power is 149.7°F.
Service water temperature is not an input into the short-term (<10 minutes) analysis because the transition to RHR suppression pool cooling mode does not occur until 10 minutes into the event.
NRC RAI ACVB-70/68 Verify that at 105% power, for the short-term LOCA, the available NPSH is always greater than the required NPSH at the peak RHR pump flow (11,500 gpm) without reliance on the testing reported in the May 24, 1976 report.
TVA Response to ACVB-70/68 At 105% OLTP, the available suppression pool pressure for the RHR pumps that inject into the broken recirculation system discharge piping in the short term analysis would improve relative to 120%
OLTP, but the lower power level alone would not result in a
positive NPSH margin for the short-term case.
This is determined by accounting for the difference in vapor pressure between peak suppression pool temperature short-term at 105% OLTP (see ACVB-69/67) and the same value at 120% OLTP (149.7 0 F versus 155.4°F).
However, conservatism in the overall NPSH analysis is sufficient to offset the negative NPSH margin even at 120% OLTP and provides a high degree of confidence that the RHR pumps will be available after the initial broken loop operation.
For example:
- 100% mixing of the broken loop flow with the drywell atmosphere is assumed, which results in under-prediction of drywell and suppression pool pressure during the short term analysis.
This is conservative relative to the likely break geometries and limited distribution of cooler water throughout the drywell.
- Initial drywell relative humidity is assumed to be 100%,
which limits the amount of non-condensable gas initially present in the drywell airspace.
However, due to the design of the drywell and drywell cooling system, relative humidity is not expected to exceed 50%.
- NPSH required limits in the calculations are based on 11,500 gpm, whereas the calculated maximum flow for the broken loop of RHR is 11000 gpm.
This results in a more restrictive NPSH required value.
E2-8
NON-PROPRIETARY VERSION An NPSH sensitivity analysis at 120% OLTP was performed assuming 50% relative humidity and 11000 gpm which shows that more realistic, but still conservative, values for these assumptions results in a positive NPSH margin for the broken loop case.
Results are shown in Figure ACVB-70/68-1.
E2-9
NON-PROPRIETARY VERSION Figure ACVB-70/68-1 NPSH Requirements for DBA-LOCA - Short Term ST LOCA 0.
E 160 150 140 130 120 110 100 22 20 18 16 E U) 14 12 10 600 0
100 200 300 400 500 Time (seconds)
Suppression Pool Temperature
-e--Wetwell Pressure Atmospheric Pressure RHR Pump Broken Loop Containment Pressure Required E2-10
NON-PROPRIETARY VERSION NRC RAI SBWB-50/75 Provide the sequence of events tables for the limiting Appendix K Large Break LOCA and the limiting Appendix K Small Break LOCA (0.06 ft 2) discharge break with a battery failure and only 5 automatic depressurization system (ADS) valves actuated.
The staff also requests the licensee to provide the low pressure coolant system and low pressure coolant injection head versus flow curve, limiting axial power shape, and ADS relief valve set pressure and relief capacity used in the analysis TVA Response to SBWB-50 (BFN Unit 1)
The information requested regarding the low pressure core spray (LPCS) and low pressure coolant injection (LPCI) head versus flow curves was transmitted to NRC on September 1, 2006, in the response to SBWB-49 from the TVA EPU Round 9 RAI reply (ML062500197).
These flow curves are independent of the break size, break location, and fuel type.
The axial power shapes in the hot and average bundle for GE14 fuel with the plant operating at rated EPU power and flow were also provided in the referenced SBWB-49 response.
These shapes are used for both the limiting large and small pipe breaks for GE14 fuel.
The sequence of events (SOEs) for the limiting Appendix K large break LOCA is shown in Table SBWB-50-1.
The limiting large break LOCA is a DBA recirculation suction line break with a battery failure.
The sequence of events for the limiting Appendix K small break LOCA (0.06 ft 2), which is a recirculation discharge line break with a battery failure and six automatic depressurization system (ADS) valves actuated, is shown in Table SBWB-50-2.
The LOCA analyses with five ADS valves actuated were performed as a sensitivity study, however, these five ADS analyses are not licensing basis calculations.
The key parameters for the ADS are shown in Table SBWB-50-3.
The key parameters for the relief valves are shown in Table SBWB-50-4.
E2-11
NON-PROPRIETARY VERSION Table SBWB-50-1 Sequence of Events for GE14 EPU Appendix K Limiting Large Break (Recirculation Suction Line DBA Break with Battery Failure)
Event Time (sec) i
- 1-
+
.t.
.4.
+
E2-12
NON-PROPRIETARY VERSION Table SBWB-50-2 Sequence of Events for GE14 EPU Appendix K Limiting Small Break (Recirculation Discharge Line 0.06 ft? Break with Battery Failure -
6 ADS Valves)
Event Time (sec)
(( +
I
.4-
+/-
+
1-E2-13
NON-PROPRIETARY VERSION Table SBWB-50-3 Key Automatic Depressurization System Parameters Variable Units Analysis Value Total number of valves available 6
Total number of valves assumed available in 6
analysis Minimum flow capacity per valve at vessel lbm/hr 800000 pressure psig 1125 Initiating signal to start ADS blowdown timer ECCS ready permissive (at least 1 LPCI or 2 core spray pumps are running)(')
and Low-low-low water level (LI) in.
AVZ(')
372.5 and Low water level (L3) in.
AVZ(21 518 and either High drywell pressure psig 2.6 or High drywell pressure bypass timer elapsed(3) sec 360 Automatic timer delay time from initiating signa sec 120 completed to initiation of valve opening.
(1) For small recirculation line breaks, the ECCS ready permissive occurs 21 seconds after Li is reached.
This time delay includes 2 sec. signal processing delay.
(2) Above vessel zero.
(3) Bypass timer starts on low-low-low water level (LI) signal.
a E2-14
NON-PROPRIETARY VERSION Table SBWB-50-4 Key Relief Valve Parameters Valve Group A
B C
Number of valves in group 4
4 5
Opening setpoint, psig 1135.0 1145.0 1155.0 Closing setpoint, psig 1100.5 1110.2 1119.9 SRV capacity at 103% of 1090 870,000 870,000 870,000 psid, lbm/hr TVA Response to SBWB-75 (BFN Units 2 and 3)
The AREVA NP limiting licensing basis LOCA for ATRIUM-10 fuel is a 0.5 ft 2 recirculation line discharge split break with a battery failure (SF-BATT) at 102% EPU power and 105% rated core flow as specified in TVA's September 1, 2006 (ML062500197),
reply to the EPU Round 9 RAI question SBWB-65.
For this analysis, the available Emergency Core Cooling System is a single LPCS loop with 6 ADS valves operable.
The licensing basis LOCA analysis was performed with 6 ADS valves and the limiting Peak Clad Temperature (PCT) case is based on this analysis.
Therefore, no 5 ADS valve LOCA cases are being submitted.
The injection head versus flow curves for LPCS and LPCI as well as the axial power shape for the limiting LOCA case were also provided in the TVA reply to NRC RAI SBWB-65.
The ADS valve characteristics used in break spectrum analysis are attached in Table SBWB-75-1.
The ADS Safety Relief Valve pressure setpoints are not used in the LOCA analyses since the ADS valves are actuated based by reactor water level signals after timer delays.
Table SBWB-75-2 provides the sequence of events (SOEs) for the limiting large break LOCA, which is a 1.0 discharge coefficient recirculation line suction guillotine (DEG) break with battery failure.
The SOE for a small break LOCA (0.05 ft 2 recirculation line discharge split break with battery failure) is shown in Table SBWB-75-3.
This is the closest break size to the requested 0.06 ft 2 break that was analyzed in the AREVA NP break spectrum.
The SOE for the limiting PCT LOCA analysis (0.5 ft 2 recirculation line discharge split break with battery failure) is provided in Table SBWB-75-4.
E2-15
NON-PROPRIETARY VERSION Table SBWB-75-1 Automatic Depressurization System (ADS) Parameters Parameter Value Number of valves installed 6
Number of valves available 6
Minimum flow capacity of available 4.8 Mlbm/hr at valves 1125 psig ADS Initiating Signals and Setpoints Water level(')
Li (372.5 in)
LPCS ready permissive(2)
Li + 40 sec (max)
ADS Time Delays Delay time (from ADS timer permissive to time valves are open) 120 sec (1) Relative to vessel zero.
(2) ADS timer initiation occurs after level trip Li is met and LPCS pumps reach the ADS ready permissive.
Credit is conservatively not taken for the RHR pump ready permissive that would occur 8 seconds earlier.
E2-16
NON-PROPRIETARY VERSION Table SBWB-75-2 Event Times for Large Break LOCA 1.0 DEG Recirculation Line Suction SF-BATT Mid-Peaked Axial 102% EPU 105% Flow Event Time (sec)
Initiate break 0.0 Initiate scram 0.5 Low-low liquid level, L2 (448 in) 5.7 Low-low-low liquid level, Li (372.5 in) 7.3 Jet pump uncovers 8.4 Recirculation suction uncovers 11.3 Lower plenum flashes 13.9 LPCS valve pressure permissive 38.0 LPCI valve pressure permissive 38.0 LPCI high-pressure cut off 39.0 LPCS valve starts to open 40.0 LPCS permissive for ADS timer 40.0 LPCI valve starts to open 40.0 LPCS high-pressure cutoff 41.2 LPCS pump at rated speed 43.0 LPCS flow starts 43.0 LPCI pump at rated speed 44.0 LPCI flow starts 44.0 RDIV pressure permissive 49.4 RDIV starts to close 51.4 Rated LPCS flow 70.5 Blowdown ends 70.5 LPCS valve fully open 73.0 LPCI valve fully open 80.0 RDIV fully closed 87.4 Bypass reflood 94.5 Core reflood 100.8 PCT 100.8 ADS valves open 160.0 E2-17
NON-PROPRIETARY VERSION Table SBWB-75-3 Event Times for Small Break LOCA 0.05 ft 2 Split Recirculation Line Discharge SF-BATT Mid-Peaked Axial 102% EPU 105% Flow Event Time(sec)
Initiate break 0.0 Initiate scram 0.5 Low-low liquid level, L2 (448 in) 132.9 Low-low-low liquid level, Li (372.5 in) 215.1 LPCS permissive for ADS timer 244.1 LPCS pump at rated speed 247.1 Jet pump uncovers 329.2 ADS valves open 364.1 Lower plenum flashes 366.9 LPCS valve pressure permissive 517.2 LPCS valve starts to open 519.2 LPCS high-pressure cutoff 536.7 LPCS flow starts 536.7 Recirculation suction uncovers 541.0 LPCS valve fully open 552.2 RDIV pressure permissive 594.3 RDIV starts to close 596.3 PCT 610.0 RDIV fully closed 632.3 Bypass reflood 674.5 Rated LPCS flow 695.2 Blowdown ends 695.2 Core reflood 695.2 E2-18
NON-PROPRIETARY VERSION Table SBWB-75-4 Event Times for Limiting Break LOCA 0.5 ft 2 Split Recirculation Line Discharge SF-BATT Mid-Peaked Axial 102% EPU 105% Flow Event Time (sec)
Initiate break 0.0 Initiate scram 0.5 Low-low liquid level, L2 (448 in) 16.4 Low-low-low liquid level, Li (372.5 in) 26.7 Jet pump uncovers 35.5 LPCS permissive for ADS timer 55.7 Recirculation suction uncovers 57.2 LPCS pump at rated speed 58.7 Lower plenum flashes 71.3 ADS valves open 175.7 LPCS valve pressure permissive 193.1 LPCS valve starts to open 195.1 LPCS high-pressure cutoff 201.4 LPCS flow starts 201.4 RDIV pressure permissive 222.0 RDIV starts to close 224.0 LPCS valve fully open 228.1 RDIV fully closed 260.0 Rated LPCS flow 277.2 Blowdown ends 277.2 Core reflood 358.3 PCT 358.3 Bypass reflood 421.4 E2-19
ENCLOSURE 3 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)
UNITS 1, 2, AND 3 TECHNICAL SPECIFICATIONS (TS)
CHANGES TS-431 AND TS-418 -
EXTENDED POWER UPRATE (EPU)
RESPONSE TO ROUND 10 REQUEST FOR ADDITIONAL INFORMATION (RAI)
(TAC NOS.
TVA REPLY TO RAI APLA-27/29 FOR UNIT 2 This enclosure provides TVA's Reply to APLA-27/29 for Unit 2.
The following footnote applies to the attached tables:
C'i The Riskman quantification method produced a number of FV negative values and RAW values less than 1.0.
The underlying cause for these valves can be found in the frequency truncation of scenarios.
These values are presented in the attached tables as 0 (FV) and 1 (RAW).
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OAD1 Inhibit ADS actuation, given ATWS with an unisolated RPV Basic Event: HOAD1 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 3.33E-03 1.05E-02 RAW, CDF 3.27E+00 3.05E+00 FV, LERF 1.61 E-02 4.31 E-02 RAW, LERF 1.19E+01 9.43E+00 Human Error Prob.
1.47-03 5.09E-03 (Monte Carlo Mean)
Time Available*
Time to -122" dependent on Time to -122" dependent on suppression pool heatup, suppression pool heatup, but but approx. 10 minutes.
approx. 8.5 minutes. Four min.
Four min. provided by timer provided by timer after reaching -
after reaching -122" for 14 122" reducing time available to min.
12.5 min Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-1
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OAD2 Inhibit ADS actuation, given ATWS with an isolated RPV Basic Event: HOAD2 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 1.96E-04 1.44E-03 RAW, CDF 1.13E+00 1.15E+00 FV, LERF 9.66E-04 5.96E-03 RAW, LERF 1.65E+00 1.62E+00 Human Error Prob.
1.48E-03 9.49E-03 (Monte Carlo Mean)
Time Available*
Level drops to -122" within Level drops to -122" within 2 min. without injection, 105 seconds without injection. No Cont. Press. > 2.45 psig change to timeout length following when RPV is isolated. Must
-122", so time available reduces by inhibit prior to 95 sec-15 seconds.
timeout.
Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-2
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OF1 Control one Feedwater Pump and hotwell level, given auto control was successful Basic Event: HOF1 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 1.62E-03 4.16E-03 RAW, CDF 5.37E+00 2.62E+00 FV, LERF 3.OOE-04 8.OOE-04 RAW, LERF 1.81 E+00 1.31 E+00 Human Error Prob.
3.70E-04 2.56E-03 (Monte Carlo Mean)
Time Available*
Monitor during cooldown (up Action is required after water has to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />). Respond to been injected in the RPV alarm within 5 min to avoid automatic trip Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-3
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OHC1 Control RPV level and pressure with HPCI and/or RCIC during first 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Basic Event: HOHC1 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
1.09E-01 RAW, CDF 1.0OE+00(1 )
1.10E+02 FV, LERF 6.71 E-05 2.13E-02 RAW, LERF 1.06E+00 2.25E+01 Human Error Prob.
1.06E-03 9.92E-04 (Monte Carlo Mean)
Time Available*
Continuous requirement -
Same as pre-EPU react within 5 min of high level alarm to prevent automatic HPCI trip at +55" Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-4
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OHC2 Control RPV level and press with HPCI during first 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, given RCIC failed or insufficient Basic Event: HOHC2 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 0.00E+00(1) 4.49E-03 RAW, CDF 1.00E+00(1 )
6.21 E+00 FV, LERF 0.00E+00( )
6.63E-04 RAW, LERF 1.0OE+00(")
1.77E+00 Human Error Prob.
9.18E-04 8.62E-04 (Monte Carlo Mean)
Time Available*
Continuous requirement; Same as pre-EPU react within 5 min of high level alarm to prevent automatic HPCI trip at +55" Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-5
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OHC3 Control RPV level and press during first 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, given HPCI failed.
Basic Event: HOHC3 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
8.99E-04 RAW, LERF 1.OOE+00(1 )
2.20E+00 Human Error Prob.
7.36E-04 7.49E-04 (Monte Carlo Mean)
Time Available*
Continuous requirement; Same as pre-EPU after recovery of RPV level react within 5 min after alarm to prevent automatic HPCI trip at +55" Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-6
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OHL2 Recover and control RPV level and pressure with HPCI and/or RCIC up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, given short term control failed Basic Event: HOHL2 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
1.18E-01 RAW, CDF 1.OOE+00 2.71E+01 FV, LERF 0.O0E+00(1) 2.29E-02 RAW, LERF 1.OOE+00 6.05E+00 Human Error Prob.
4.49E-03 4.51 E-03 (Monte Carlo Mean)
Time Available*
Continuous requirement.
Same as pre-EPU React to alarm within 15 min of indication to prevent automatic trip at +55" Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-7
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OLA1 Control LPCI to maintain RPV level at TAF, given ATWS Basic Event: HOLA1 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 8.23E-03 6.41 E-03 RAW, CDF 1.10E+00 1.08E+00 FV, LERF 3.95E-02 2.63E-02 RAW, LERF 1.47E+00 1.31 E+00 Human Error Prob.
7.75E-02 7.84E-02 (Monte Carlo Mean)
Time Available*
Continuous requirement for Same as pre-EPU close control until sub-criticality and refill Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-8
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OLP1 Control RPV level using LPCI mode of RHR or the Core Spray Basic Event: HOLP1 System Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 7.01 E-03 2.06E-03 RAW, CDF 3.64E+02 1.10E+02 FV, LERF 1.92E-02 2.35E-03 RAW, LERF 9.96E+02 1.26E+02 Human Error Prob.
1.93E-05 1.89E-05 (Monte Carlo Mean)
Time Available*
Initiate after cooldown.
Same as pre-EPU Over 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to core uncovery from normal RPV level with no injection Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-9
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OLP2 Open the hardened wetwell vent, partial AC power available Basic Event: HOLP2 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 1.71 E-01 1.32E-01 RAW, CDF 2.03E+00 1.80E+00 FV, LERF 0.O0E+00(')
2.01 E-02 RAW, LERF 1.00E+00(1) 1.12E+00 Human Error Prob.
1.43E-01 1.42E-01 (Monte Carlo Mean)
Time Available*
Hours for suppression pool Same as pre-EPU heat up Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-10
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OP1 Operator depressurizes RPV (Level 2)
Basic Event: None (Screening Value)
Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
O.OOE+00()1 RAW, CDF 1.0OE+00()
1.OOE+O00(t FV, LERF 1.99E-02 8.11E-03 RAW, LERF 1.02E+00 1.01E+00 Human Error Prob.
4.55E-01 4.55E-01 (Monte Carlo Mean)
Time Available*
Not time sensitive Not time sensitive Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-11
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OP3 Operator depressurizes RPV (Level 2)
Basic Event: None (Screening Value)
Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF O.OOE+00(1 O.OOE+00(1)
1.O0E+00( )
FV, LERF 2.07E-02 8.04E-02 RAW, LERF 1.33E+00 2.28E+00 Human Error Prob.
5.90E-02 5.90E-02 (Monte Carlo Mean)
Time Available*
Not time sensitive Not time sensitive Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-12
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: ORVD1 Emergency depressurize given failure of HPCI and RCIC Basic Event: HORVD1 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
(note the corresponding split fraction in the pre EPU model is ORVD2)
FV, CDF 1.02E-01 3.11E-01 RAW, CDF 2.21 E+02 1.60E+03 FV, LERF 2.20E-02 6.37E-02 RAW, LERF 4.82E+01 3.29E+02 Human Error Prob.
4.66E-4 1.95E-04 (Monte Carlo Mean)
Time Available*
30 minutes to recognize Ten min available based on MAAP need to emergency CASE01, loss of all injection into depressurize. 3 to 5 vessel minutes to -190" once -162"
(= TAF) reached Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-13
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: ORVD2 Emergency depressurize by manually opening MSRVs, given manual control of HPCI and RCIC failed Basic Event: HORVD2 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
(this is ORVD3 in the pre EPU model)
1.18E-01 RAW, CDF 1.OOE+00 1.73E+00 FV, LERF 0.O0E+00()
2.29E-02 RAW, LERF 1.00E+00 1.14E+00 Human Error Prob.
6.32E-03 1.40E-01 (Monte Carlo Mean)
Time Available*
30 minutes to recognize Ten min available based on MAAP need to emergency CASE01, loss of all injection into depressurize. 3 to 5 vessel minutes to -190" once -162"
(= TAF) reached Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-14
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OSLI Activate SLC unisolated RPV Basic Event: HOSL1 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 1.20E-02 3.79E-02 RAW, CDF 3.72E+00 3.32E+00 FV, LERF 5.77E-02 1.55E-01 RAW, LERF 1.40E+01 1.05E+01 Human Error Prob.
4.40E-03 1.61 E-02 (Monte Carlo Mean)
Time Available*
3 to 5 min available to avoid Lowered T, in HCR model from level/ power control 180 to 158 seconds t to reflect 7/8 requirement.
available time due to assumed (HCR used 240 sec.)
120%/105% power ratio Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-15
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OSL2 Activate SLC isolated RPV Basic Event: HOSL2 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 5.83E-03 1.99E-02 RAW, CDF 1.28E+00 1.24E+00 FV, LERF 2.80E-02 8.14E-02 RAW, LERF 2.36E+00 2.OOE+00 Human Error Prob.
2.02E-02 7.54E-02 (Monte Carlo Mean)
Time Available*
at 50% power SP reaches EPU lowered time available to 110 F in about 2 min and 158 seconds 170 F in about 7 min. Used 180 second as time available Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-16
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OSP1 Align RHR for suppression pool (SP) cooling Basic Event: HOSP1 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 1.18E-01 6.94E-02 RAW, CDF 1.56E+03 9.48E+02 FV, LERF 3.44E-02 3.69E-02 RAW, LERF 4.55E+02 5.04E+02 Human Error Prob.
7.57E-05 7.33E-05 (Monte Carlo Mean)
Time Available*
Not time sensitive - about Same as pre-EPU 90 min before SP temperature exceeds 140 F Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-17
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OSP2 Align RHR for SP cooling, given ATWS Basic Event: HOSP2 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 3.57E-03 2.62E-03 RAW, CDF 1.58E+00 1.43E+00 FV, LERF 1.74E-02 1.10E-02 RAW, LERF 3.82E+00 2.81E+00 Human Error Prob.
6.15E-03 6.01E-03 (Monte Carlo Mean)
Time Available*
Approximately 9 min until Time available due to integrated HCTL if unit at 50% power ATWS heat generation for baseline was very conservative and judged to not be worsened by EPU Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-18
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OSP3 Align RHR for SP cooling, given one path unavailable Basic Event: HOSP3 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 6.48E-04 4.78E-04 RAW, CDF 1.05E+01 8.09E+00 FV, LERF 0.0OE+00()1 1.06E-04 RAW, LERF 1.00E+00()1 2.57E+00 Human Error Prob.
6.82E-05 6.74E-05 (Monte Carlo Mean)
Time Available*
Not time sensitive - much Same as pre-EPU more than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> before SP temperature exceeds 140 F Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-19
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OSV1 Defeat MSIV closure logic, given ATWS with turbine trip Basic Event: HOSV1 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 1.89E-02 1.28E-02 RAW, CDF 1.19E+00 1.13E+00 FV, LERF 9.11E-02 5.28E-02 RAW, LERF 1.91 E+00 1.55E+00 Human Error Prob.
9.11E-02 8.70E-02 (Monte Carlo Mean)
Time Available*
Accomplish in first 10 min of Time available due to integrated transient, after reaching ATWS heat generation for BIIT; circa 7 minutes before baseline was very conservative SP reaches 1 10°F, forcing and judged to not be worsened by lowering of level EPU Where is this operator action performed?
Back panels within the Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-20
Unit 2 Human Failure Events Operator Action Name Description Split Fraction: OSW1 Transfer Mode Switch to REFUEL/ SHUT DOWN in response to scram Basic Event: HOSW1 Pre-EPU (Model C2051602)
Post-EPU (Model U2060706)
FV, CDF 2.40E-03 1.23E-03 RAW, CDF 4.22E+00 2.68E+00 FV, LERF 7.25E-03 O.OOE+00()
RAW, LERF 1.07E+01 1.OOE+00(1 Human Error Prob.
7.44E-04 7.31 E-04 (Monte Carlo Mean)
Time Available*
Not time significant for Same as pre-EPU typical pressure reduction rates Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E3-21
ENCLOSURE 4 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)
UNITS 1, 2, AND 3 TECHNICAL SPECIFICATIONS (TS)
CHANGES TS-431 AND TS-418 -
EXTENDED POWER UPRATE (EPU)
RESPONSE TO ROUND 10 REQUEST FOR ADDITIONAL INFORMATION (RAI)
(TAC NOS.
TVA REPLY TO RAI APIA-27/29 FOR UNIT 3 This enclosure provides TVA's Reply to APLA-27/29 for Unit 3.
The following footnote applies to the attached tables:
(1) The Riskman quantification method produced a number of FV negative values and RAW values less than 1.0.
The underlying cause for these valves can be found in the frequency truncation of scenarios.
These values are presented in the attached tables as 0 (FV) and 1 (RAW).
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OADI Inhibit ADS actuation, given ATWS with an unisolated RPV Basic Event: HOAD1 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 2.19E-03 5.74E-03 RAW, CDF 2.49E+00 2.15E+00 FV, LERF 1.47E-02 3.87E-02 RAW, LERF 1.10E+01 8.78E+00 Human Error Prob.
1.47E-03 4.95E-03 (Monte Carlo Mean)
Time Available*
Time to -122" dependent on Time to -122" dependent on suppression pool heatup, suppression pool heatup, but but approx. 10 minutes.
approx. 8.5 minutes. Four min.
Four min. provided by timer provided by timer after reaching -
after reaching -122" for 122" reducing time available to 14 min.
12.5 min.
Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-1
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OAD2 Inhibit ADS actuation, given ATWS with an isolated RPV Basic Event: HOAD2 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 1.28E-04 7.66E-04 RAW, CDF 1.09E+00 1.08E+00 FV, LERF 8.79E-04 5.22E-03 RAW, LERF 1.59E+00 1.56E+00 Human Error Prob.
1.48E-03 9.19E-03 (Monte Carlo Mean)
Time Available*
Level drops to -122" within Level drops to -122" within 2 min. without injection, 105 seconds without injection. No Cont. Press. > 2.45 psig change to timeout length following when RPV is isolated. Must
-122", so time available reduces by inhibit prior to 95 sec-15 seconds.
timeout.
Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-2
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OF1 Control one Feedwater Pump and hotwell level, given auto control was successful Basic Event: HOF1 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 1.05E-03 2.44E-03 RAW, CDF 3.83E+00 1.88E+00 FV, LERF 2.75E-04 7.66E-04 RAW, LERF 1.74E+00 1.28E+00 Human Error Prob.
3.70E-04 2.75 E-03 (Monte Carlo Mean)
Time Available*
Monitor during cooldown (up Action is required after water has to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />). Respond to been injected in the RPV alarm within 5 min to avoid automatic trip Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-3
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OHC1 Control RPV level and pressure with HPCI and/or RCIC during first 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Basic Event: HOHC1 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 0.00E+00(1) 6.17E-02 RAW, CDF 1.OOE+00(1) 6.23E+01 FV, LERF 1.17E-03 2.17E-02 RAW, LERF 2.10E+00 2.26E+01 Human Error Prob.
1.06E-03 1.01 E-03 (Monte Carlo Mean)
Time Available*
Continuous requirement -
Same as pre-EPU react within 5 min of high level alarm to prevent automatic HPCI trip at +55" Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-4
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OHC2 Control RPV level and press with HPCI during first 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, given RCIC failed or insufficient Basic Event: HOHC2 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF O.00E+00(1) 2.69E-03 RAW, CDF 1.00E+00(
t )
3.83E+00 FV, LERF 1.01 E-05 8.13E-04 RAW, LERF 1.01 E+00 1.86E+00 Human Error Prob.
9.18E-04 9.50E-04 (Monte Carlo Mean)
Time Available*
Continuous requirement; Same as pre-EPU react within 5 min of high level alarm to prevent automatic HPCI trip at +55" Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-5
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OHC3 Control RPV level and press during first 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, given HPCI failed Basic Event: HOHC3 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
t
)
9.42E-04 RAW, LERF 1.00E+00(')
2.22E+00 Human Error Prob.
7.36E-04 7.69E-04 (Monte Carlo Mean)
Time Available*
Continuous requirement; Same as pre-EPU after recovery of RPV level react within 5 min after alarm to prevent automatic HPCI trip at +55" Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-6
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OHL2 Recoverand control RPV level and pressure with HPCI and/or RCIC up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, given short term control failed.
Basic Event: HOHL2 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
6.76E-02 RAW, CDF 1.00E+00 1.62E+01 FV, LERF 0.00E+00t')
2.28E-02 RAW, LERF 1.OOE+00 6.13E+00 Human Error Prob.
4.49E-03 4.42E-03 (Monte Carlo Mean)
Time Available*
Continuous requirement.
Same as pre-EPU React to alarm within 15 min of indication to prevent automatic trip at +55" Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-7
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OLA1 Control LPCI to maintain RPV level at TAF, given ATWS Basic Event: HOLAI Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 5.40E-03 3.66E-03 RAW, CDF 1.06E+00 1.04E+00 FV, LERF 3.60E-02 2.46E-02 RAW, LERF 1.43E+00 1.29E+00 Human Error Prob.
7.75E-02 7.89E-02 (Monte Carlo Mean)
Time Available*
Continuous requirement for Same as pre-EPU close control until sub-criticality and refill Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-8
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OLPI Control RPV level using LPCI mode of RHR or the Core Spray System Basic Event: HOLP1 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 7.80E-03 2.25E-03 RAW, CDF 4.05E+02 1.25E+02 FV, LERF 2.19E-02 3.39E-03 RAW, LERF 1.14E+03 1.88E+02 Human Error Prob.
1.93E-05 1.81 E-05 (Monte Carlo Mean)
Time Available*
Initiate after cooldown.
Same as pre-EPU Over 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to core uncovery from normal RPV level with no injection Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-9
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OLP2 Open the hardened wetwell vent, partial AC power available Basic Event: HOLP2 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 1.52E-01 9.16E-02 RAW, CDF 1.91 E+00 1.55E+00 FV, LERF 7.50E-03 2.06E-02 RAW, LERF 1.05E+00 1.12E+00 Human Error Prob.
1.43E-01 1.44E-01 (Monte Carlo Mean)
Time Available*
Hours for suppression pool Same as pre-EPU heat up Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-10
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OP1 Operator depressurizes RPV (Level 2)
Basic Event: None (Screening Value)
Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
O.O0E+00(1 )
1.00E+00 FV, LERF 5.42E-02 6.33E-03 RAW, LERF 1.06E+00 1.01E+00 Human Error Prob.
4.55E-01 4.55E-01 (Monte Carlo Mean)
Time Available*
Not time sensitive Not time sensitive Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-11
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OP3 Operator depressurizes RPV (Level 2)
Basic Event: None (Screening Value)
Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF O.00E+00()1 0.00E+00(1 )
1.00E+00(Q
)
FV, LERF 1.86E-02 7.48E-02 RAW, LERF 1.30E+00 2.19E+00 Human Error Prob.
5.90E-02 5.90E-02 (Monte Carlo Mean)
Time Available*
Not time sensitive Not time sensitive Where is this operator action performed?
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-12
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: ORVD1 Emergency depressurize by manually opening MSRVs, given HPCI/RCIC hardware failed Basic Event: HORVD1 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
(this is ORVD2 in the pre EPU model)
FV, CDF 6.71 E-02 1.64E-01 RAW, CDF 1.45E+02 8.99E+02 FV, LERF 1.96E-02 5.73E-02 RAW, LERF 4.30E+01 3.15E+02 Human Error Prob.
4.66E-04 1.82E-04 (Monte Carlo Mean)
Time Available*
30 minutes to recognize Ten min available based on MAAP need to emergency CASE01, loss of all injection into depressurize. 3 to 5 vessel minutes to -190" once -162"
(= TAF) reached Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-13
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: ORVD2 Emergency depressurize by manually opening MSRVs, given HPCI/RCIC failed due to operator control error Basic Event: HORDV2 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
(this is ORVD3 in the pre EPU model)
6.76E-02 RAW, CDF 1.OOE+00 1.41 E+00 FV, LERF O.0OE+00(1) 2.28E-02 RAW, LERF 1.00E+00(1) 1.14E+00 Human Error Prob.
6.32E-03 1.40E-01 (Monte Carlo Mean)
Time Available*
30 minutes to recognize Ten min available based on MAAP need to emergency CASE01, loss of all injection into depressurize. 3 to 5 vessel minutes to -190" once -162"
(= TAF) reached Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-14
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OSL1 Activate SLC unisolated RPV Basic Event: HOSL1 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 7.91 E-03 2.14E-02 RAW, CDF 2.79E+00 2.31 E+00 FV, LERF 5.27E-02 1.43E-01 RAW, LERF 1.29E+01 9.75E+00 Human Error Prob.
4.40E-03 1.61 E-02 (Monte Carlo Mean)
Time Available*
3 to 5 mmn available to avoid Lowered Tw in HCR model from level/ power control 180 to 158 seconds t to reflect 7/8 requirement. (HCR used available time due to assumed 240 sec.)
120%/105% power ratio Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-15
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OSL2 Activate SLC isolated RPV Basic Event: HOSL2 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 3.81E-03 1.16E-02 RAW, CDF 1.19E+00 1.14E+00 FV, LERF 2.54E-02 7.82E-02 RAW, LERF 2.23E+00 1.92E+00 Human Error Prob.
2.02E-02 7.84E-02 (Monte Carlo Mean)
Time Available*
At 50% power SP reaches EPU lowered time available to 110 F in about 2 min and 158 seconds 170 F in about 7 min. Used 180 second as time available Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-16
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OSP1 Align RHR for suppression pool (SP) cooling Basic Event: HOSPI Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 9.64E-02 5.15E-02 RAW, CDF 1.27E+03 6.78E+02 FV, LERF 4.05E-02 4.32E-02 RAW, LERF 5.35E+02 5.69E+02 Human Error Prob.
7.57E-05 7.60E-05 (Monte Carlo Mean)
Time Available*
Not time sensitive - about Same as pre-EPU 90 min before SP temperature exceeds 140 F Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-17
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OSP2 Align RHR for SP cooling, given ATWS Basic Event: HOSP2 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 2.29E-03 1.50E-03 RAW, CDF 1.37E+00 1.25E+00 FV, LERF 1.55E-02 1.03E-02 RAW, LERF 3.51 E+00 2.70E+00 Human Error Prob.
6.15E-03 6.03E-03 (Monte Carlo Mean)
Time Available*
Approximately 9 min until Time available due to integrated HCTL if unit at 50% power ATWS heat generation for baseline was very conservative and judged to not be worsened by EPU Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-18
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OSP3 Align RHR for SP cooling, given one path unavailable Basic Event: HOSP3 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 5.52E-04 2.35E-04 RAW, CDF 9.10E+00 4.47E+00 FV, LERF 0.00E+00(1) 1.40E-05 RAW, LERF 1.0OE+00()
1.21 E+00 Human Error Prob.
6.82E-05 6.79E-05 (Monte Carlo Mean)
Time Available*
Not time sensitive - much Same as pre-EPU more than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> before SP temperature exceeds 140 F Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-19
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OSV1 Defeat MSIV closure logic, given ATWS with turbine trip Basic Event: HOSV1 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 1.26E-02 7.89E-03 RAW, CDF 1.13E+00 1.08E+00 FV, LERF 8.45E-02 5.35E-02 RAW, LERF 1.84E+00 1.55E+00 Human Error Prob.
9.11 E-02 8.92E-02 (Monte Carlo Mean)
Time Available*
Accomplish in first 10 min of Time available due to integrated transient, after reaching ATWS heat generation for BIIT; circa 7 minutes before baseline was very conservative SP reaches 11 0°F, forcing and judged to not be worsened by lowering of level EPU Where is this operator action performed?
Back panels within the Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-20
Unit 3 Human Failure Events Operator Action Name Description Split Fraction: OSW1 Transfer Mode Switch to REFUEL/ SHUT DOWN in response to scram Basic Event: HOSW1 Pre-EPU (Model C3051602)
Post-EPU (Model U3060706)
FV, CDF 1.68E-03 8.OOE-04 RAW, CDF 3.26E+00 2.10E+00 FV, LERF 6.51 E-03 2.54E-04 RAW, LERF 9.74E+00 1.35E+00 Human Error Prob.
7.44E-04 7.29E-04 (Monte Carlo Mean)
Time Available*
Not time significant for Same as pre-EPU typical pressure reduction rates Where is this operator action performed?
Control Room
- Time available is the time from receipt of the appropriate cue until the action must be complete for successful mitigation of core damage or large early release.
E4-21
ENCLOSURE 5 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)
UNITS 1, 2, AND 3 TECHNICAL SPECIFICATIONS (TS)
CHANGES TS-431 AND TS-418 -
EXTENDED POWER UPRATE (EPU)
RESPONSE TO ROUND 10 REQUEST FOR ADDITIONAL INFORMATION (RAI)
(TAC NOS.
TS-418 TS CHANGES REMARKED USING CURRENT TS PAGES This enclosure provides a revised markup of the Unit 2 and Unit 3 TS changes for full 120% EPU operation.
-3.
sealed neutron sources for reactor startup, sealed sources for reactor Instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (4)
Pursuant to the Act and 10 CFR Parts 30, 40, and 70, to receive, possess, and use in amounts as required any byproduct, source, or special nuclear material without restriction to chemical or physical form for sample analysis or equiprhent and instrument calibration or associated with radioactive apparatus or components; (5)
Pursuant to the Act and 10 CFR Parts 30 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 operating license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations In 10 CFR Chapter I:
Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; 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 incorporated below.
(1)
Maximum Power Level The licensee is authorized to operate the facility at steady state reactor core power levels not in excess ofýmegawatts thermal.
(2)
Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 295, are hereby Incorporated in the renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.
For Surveillance Requirements (SRs) that are new In Amendment 253 to Facility Operating License DPR-52, the first performance is'6ue at the end of the first surveillance Interval that begins at implementatlon of Amendment 253. For SRs that existed prior to Amendment 253, including SRs with modified acceptance criteria and SRs whose frequency of performance is being extended, the first performance is due'at the end of the first surveillance interval that begins on the date the surveillance was last performed prior to implementation of Amendment 253.
(3)
The licensee is aulhorized to relocate certain requirements included in Appendix A and the former Appendix B to licensee-controlled documents.
Implementation of this amendment shall include the relocation of these requirements to the appropriate documents, as described in 'the licensee's BFN.UNIT 2 Renewed License No. DPR-52 May 04,2006
Definitions
- 1.1 1.1 Definitions (continued)
PHYSICS TESTS PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation. These tests are:
- a. Described In Section 13.10, Refueling Test Program; of the FSAR;
- b. Authorized under the provisions of 10 CFR 50.59; or
- c. Otherwise approved by the Nuclear Regulatory Commission.
RTP shall be a total reactor core heat transfer rate to the reactor coolant of 9MW SDM shall be the amount of reactivity by which the reactor Is subcritical or would be subcritical assuming that RATED THERMAL POWER (RTP)
I
- a. The reactor is xenon free;
- b. The moderator temperature is 680F; and
- c. All control rods are fully inserted except for the single control rod of highest reactivity worth, which is assumed to be fully withdrawn. With control rods not capable of being fully Inserted, the reactivity worth of these control rods must be accounted for in the determination of SDM.
(continued)
BFN-UNIT 2 1.1-6 Amendment No. 254 September 08, 1998
SLs 2.0 2.0 SAFETY LIMITS (SLs) 2.1 SLs 2.1.1 Rearctor Core SLs 2.1.1.1 With the reactor steam dome pressure < 785 psig or core flow
< 10% rated core flow:
THERMAL POWER shall be <&Ah RTP.
2.1.1.2 With the reactor steam dome pressure ; 785 psig and core flow
- 10% rated core flow
- .
MCPR shall be > 1.08 for two recirculation loop operation or k 1.10 I for single loop operation.
2.1.1.3 Reactor vessel water level shall be greater than the top of active irradiated fuel.
2.1.2 Reactor Coolant &Sstem Pressure SL Reactor steam dome pressure shall be < 1325 psig.
2.2 SL Violations With any SL violation, the following actions shall be completed within 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />s:
2.2.1 Restore compliance with all SLs; and 2.2.2 Insert all insertable control rods.
BFN-UNIT 2 2.0-1 Amendment No. 2 280 February 28, 2003
i SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY Verify the concentration and temperature of Once within boron in solution are within the limits of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after Figure 3.1.7-1.
discovery that SPB concentration is
> 9.2% by weight 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter SR 3.1.7.5 Verify the minimum quantity of Boron-ID In the SLC solution tank and available for injection Is
- lp* *ounds" 31 days I
SR 3.1.7.6 Verify the SLC conditions satisfy the following equation:
31 days I
(
'if r)
)
E I
(13 wt. %)(86 gpm(1 9.8 atom%)
Once within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after water or boron is added to the solution
- where, C = sodium pentaborate solutionI concentration (weight percent)
Q = pump flow rate (gpm)
E = Boron-lO enrichment (atom percent Boron-iO)
SR 3.1.7.7 Verify each pump develops a flow rate 2t 39 24 months gpm at a discharge pressure > 1325 psig.
f=f 1
ntinuier4*
Ivw,,,,, o*w=jr BFN-UNIT2 3.1-25 Amendment No. 2W., 290 September 27, 2004
MCpR
'3.2.2 3.2 POWER DISTRIBUTION LIMITS 3,2.1 AVERAGE PLANAR LINEAR HE'AT GENERATION RATE (APLHGR)
LCO 3.2.1 All APLHGRs shall be less than or equalto the limits Specified in the COLR.
APPLICABILITY:
THERMAL POWER Yo% RTP.
ACTIONS CONDITION REQUIRED ACTION COMPLETION.
TIME A. Any APLHGR not within A.A1 Restore APLHGR(s) to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> limits.
within limits.
B. Required Action and B.1 Reduce THERMAL 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />'s associated Completion POWER to ýc Q2%
RTP.
Time not met..
.. BFN-UNIT 2 3.2-1 Amiendmeht NO' 253
MCPR 3.2.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.1.1 Verify all APLHGRs are less than or equal to Once within the limits. specified in the COLR.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after z
!% RTP AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter-BFN-UNIT 2 3.2-2 Amendment No. 253
MCPR 3.22 3.2 POWER DISTRIBUTION LIMITS 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)
LCO 3.2.2 All MCPRs shall be greater than or equal to the MCPR operating limits specified In the COLR.
APPLICABILITY:
THERMAL POWER.- Ž2Z%
RTP.
ACTIONS CONDITION REQUIRED ACTION
-COMPLETION TIME
-A. Any MCPR not Within A.1
,ReStore MCPR(s) to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> limits.
.within limits.
B. Required Action and -
B.1 Reduce THERMAL 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated completion POWER to. <2o%
RTP.
Time not met..
BFN-UNIT 2 3*2-3 Amendment No. 253
MCPR 3.2.2 SURVEILLANCE REQUIREMENTS
- SURVEILLANCE FREQUENCY SR 3.2.2.1 Verify all MCPRs aregreater than or equal tothe Once within limits specified in the COLR.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after 26 2,3% RTP AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter SR 3.2.2.2 Determine the MCPR lImits.
Once within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after.
each completion of SR 3.,14,1 AND Once within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after.
each completion of SR3.1.42
.0Q
.3.2-4
.Amendment'No.
253 BFN-UNIT 2
LHGR 3.2.3 3.2 POWER DISTRIBUTION LIMITS 3.2.3 LINEAR HEAT GENERATION RATE (LHGR)
LCO 3.2.3 APPLICABILITY:
All LHGI~s shall be less than or equal to the limits Specified in the COLR.
THERMAL POWER P2%
RTP.
AC TIO N S CONDITION REQUIRED ACTION COMPLETION TIME A.I Any LHGR not within A.!
Restore LHGR(s) toqWithin 2hours
- limits, limits.
,B.
Required Acton and b.1 Reduce THERMAL....
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated POWER to < 5 RTP.
Completion Time not met.
S V5 BFN-UNIT 2 3.2-5 2Amendment No. 253
LHGR 3.2.3 SURVEILLANCEREQUIREMENTS SURVEILLANCE.
FREQUENCY sR 3.2.3.1 Verfy all LHGRs are less than or equal to0the limits Once within Specified in tie COLR.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after
_.% RTP AND' 24hours thler'eafter 0, 8 r BFN-UNIT 2 3.2-6.
Amendment No. 253
RPS Instrumentation 3.3.1.1 ACTIONS (continued)...
CONDITION, REQUIRED ACTION COMPLETION TIME B. *
.NOTE B.1 Plac*e channel in one-trip 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Not applicable for
-system* in trip.
Functions 2,a,%2.b, 2,c, 2.d, or 2.f.
B.2 Place one trip system in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> One or more Functionhs trip.
with one or more required channels Inoperable in both trp systems.° C.
One or more'..
CA Restore RPS trip 1 hour*
Functionswith RPS capability.
trip capability not maintained..
D.
Required Action and' D.1
- Enter the Condition.
Immediately associated referenced in Completion: Time of Table 3.3.1.1-1 for the Condition A, B, or C channel..
not met.
E.
As required by E.1 ReduceTHERMAL 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ReqUired Action D.1 POWER to < 3
% RTP.
and referenced in Table 3.3.1.1 -1.
F.
As required by F.1 Be in MODE 2.
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Required Action D.1
- and referenced in Table 3.3.1.1-1.
(continued)
- Pj r.'%
Sw 4--"
ný_
3.3-2 BFN-UNIT 2.
Amendmeht No. 258 March 05, 1999
RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS NOTES
- 1. Refer to Table 3.3.1.1 -Ito determine which SRs apply for each RPS Funttion.
2 When a channel is plaided in an. inoperablestatus s0oely forperforma.nceof required Surveillances, entry:into associated Conditions and Required Actions may be delayed for up to.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> prOvided the associated Functioh maintains RPS trip capability.
SURVEILLANCE FREQUENCY SR 3.3.1.1.1 Perform" CHANNEL CHECK.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.1.1.2.
- .NOTE-Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER
- o,* RTP, Verify the absolutb difference betweeh the 7 days average power range monitor (APRM) channels and the calculated power is, 2% RTP whileoperating at> ý23% RTP.
-SR 3.3.l.!3
'NOTE.
Not required to be performed when entering MODE 2 from MODE -I until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE.2.
Perform CHANNEL 7 days FUNCTIONAL TEST.-
(continued)
BFN-UNIT 2
.3.3-4 Amendment No. 253
RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued.
SURVEILLANCE FREQUENCY SR 3.3.1.1.J0 Perform CHANNEL CALIBRATION.
184 days SR 33.1.1.11 (Deleted)
SR 3.3.1.1.12 Perform CHANNEL FUNCTIONAL TEST.
24 months SR; 33.1.1.13 NOTE Neutron detectors are excluded.
Perform CHANNEL
.24 months CALIBRATION.
SR 3.3.1.1.14 Perform LOGIC SYSTEM FUNCTIONAL TEST.
24 months
'SR 3.3.1.1.15 Verify Turbine Stop Valve - Closure and 24 months Turbine Control Valve Fast Closure, Trip Oil Pressure -..Low Functions are not bypassed when'THERMAL PoWER is ;2 4026% RTP.
SR 3.3.1.1.16
=
NOTE For Function 2.a, not: required to'be peWrformed When enterng MODE 2 from MODE. I Until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after ehtering MODE 2.
Perform CHANNEL FUNCTIONAL 184 days TEST.
'SR 3.31.1.17 Verify OPRM is not bypassed when APRM 24 months Simulated Thermal Power is°> 25% and.
recirculation drive flow is < 60% of rated recirculation drive flow.
BFN-UNIT 2 Amendment No. 258.
March 05,1999
RPS Instrumentation 33.1.1 table l.1.: (page 1 of 3)
Reactok Pr6tecton System Insftmenttion APPLICABLE CONDITIOkS MODES OR REQUIRED REFERENCED FUNCTION OTHER.
CHANNELS FROM SURVEILLANCE ALLOWABLE
-SPECIFIED.
PER TRIP, REQUIRED:"
REQUIREMENTS VALUE CONDITIONS SYSTEM ACTION'D.1
- i.
Inlermid~ate Range Monit.ors a.' Neutron Flux - High 2
s(a)
.3 3
3
.3 G
- SR.33.1.1.3 SR 3.3.1*1.5 SR 3.3.1.1.6 SR 3.3."1.1.9
- SR 3.3.1.1.14 H
SR 3;3.1.1.1 SR 33.31,1A.
SR 3.3.1.1.9 SR 31.3.1.1;14 SR 3.3.1.1.14
<120/125 divisions of full scali
- 5120/125 dlVlsions of full scale
- b. tnop
- 2 NA' H
SR 3.3..1.4 NA SR :3.3.1.11i4
- 2. AMere Power Range Monitors
- a. Neutroi Flux-High.
(Setdown)
- b. Flow Blaisd Simulated Thermal Power - High
- c. Neutron Flux, High 2-1 3 (b)
G SR 3.3.1.1.1.
SR 3.3.1.6 SR 3.3.1.1.7 SR.3.3.1.11:13 SR 3.3.1.1.16 3(b) f
'SR.343.1.1..1 SR '3.3.1.1.2 SSR '3.3.1. 1A7 SR 3.3.1.1.13 SR 3.3.1.1,16 3(b) 1:
SR S.3.1.1.1
.SR.3.3.1.1,2 SR 3.3,A.1.7 SR 3.3.1.1.13 SR 3.3.1.1.16
... p.c)
."120%nRTP (contin'ued)
I (a) With any control rod wtrawn frim a core cell conlaling one or more fulassmbies.
(b)
Each APRM channel provides Inputs to both trip syslems.
I R
,'t v
n f.e*.:e.t
- k a l p'. Uu~n p r,*
L
,S.,4'.1 R
.oop..
BFN-UNIT 2 le 01 3.3 0 c Amendment No. 256 December'23, 1998
RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 3 of 3)
Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED FUNCTION OTHER CHANNELS FROM SURVEILLANCE ALLOWABLE SPECIFIED PER TRIP REQUIRED REQUIREMENTS VALUE CONDITIONS SYSTEM ACTION D.1
- 7. Scram Discharge Volume Water Level - High (continued)
- b. Float Switch 1,2 2
- 5 46 gallons SR 3.3.1.1.13 SR 3.3.1.1.14 5(a) 2 H
< 46 gallons SR 3.3.1.1.13 SR 3.3.1.1.14
- 8. Turbine StopValve - Closure z;RTP 4
<10% closed SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.15
- 9. Turbine Control Yalve Fast RTP 2
E SR 3.3.1.1.8 2 550 psig Closure, Trip Oil.Pressure -
SR 3.3.1.1.13 LOW(d)
I.
SR 3.3.1.1.14 SR 3.3.1.1.15
- 10. Reactor Mode Switch -
1,2 1
G SR 3.3.1.1.12 NA Shutdown Position SR 3.3.1.1.14 5(a)
I H
SR 3.3.1.1.12 NA SR 3.3.1.1.14
- 11. Manual Scram 1,2 1
G SR 3.3.1.1.8 NA SR 3.3.1.1.14 5(s) 1 H
SR 3.3.1.1.8 NA SR 3.3.1.1.14
- 12. RPS Channel Test Switches 1,2 2
G SR 3.3.1.1.4 NA 5(a) 2 H
SR 3.3.1.1.4 NA
- 13. Deleted I
(a)
(d)
With any control rod withdrawn from a core cell containing one or more fuel assemblies.
During Instrument calibrations, If the As Found channel setpoint Is conservative with respect to the Allowable Value but outside its acceptable As Found band as defined by Its associated Surveillance Requirement procedure, then there shall be an Initial determination to ensure confidence that the channel can perform as required before returning the channel to service In accordance with the Surveillance. If the As Found Instrument channel setpoint Is not conservative with respect to the Allowable Value, the channel shall be declared Inoperable.
Prior to returnIng a channel to service, the Instrument channel setpolnt shall be calibrated to a value that Is within the acceptable As Left tolerance of the setpoint; otherwise, the channel shall be declared Inoperable.
The nominal Trip Setpolnt shall be specified on design output documentation which Is Incorporated by reference In the Updated Final Safety Analysis Report. The methodology used to determine the nominal Trip Setpolnt, the predefined As Found Tolerance, and the As Left Tolerance band, and a listing of the setpoint design output documentation shall be specified In Chapter 7 of the Updated Final Safety Analysis Report.
BFN-UN IT 2 3.3-9 Amendment No. 25, 2-6, 296
-I.I Feedwater and Main Turbine High Water Level Trip Instrurnentation 3.3.2.2 3.3 INSTRUMENTATION 3.32:2 Feedwater and Main Turbine High WaterLevel Trip Instrumentation Two~~g canloffeWater'L and maintrnehgwarlvl LCO 3.3.2.2 APPLICABILITY:
TWo chainnels 6f feedwater and m~ain turbine highi water level trip instrumentation -per trip system shall be OPERABLE.
THERMAL POWER > Q% RTP.
ACTIONS U Ir Separate Condition entry is allowed for each channe.l CONDITION REQUIRED ACTION COMPLETION TIME A.
One or more A.A Place channel(s) in trip.
7.days feedwater and main turbine high waterl level trip channels.
inoperable, In one trip system.,
B.
One or more feedWater and main turbine high water level trip channels inoperable in each trip system.
B.1 Restore feedwater, and mainhturbine high water leel trip capability.'
2.hours C.
Required Action and C.;
RedUce THERMAL 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated-
-POWER to <-
'RtO.
Complletion Time not met.
BAe-22.
BFN-UNIT 2 Amendment No. 2ý3
EOC-RPT Instrumentation 3.3.4.1 3.3 INSTRUMENTATION 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation LCO 3.3.4.1
- a. Two channels per trip system for each EOC-RPT instrumentation Function listed below shall be OPERABLE:
- 1. Turbine Stop Valve (TSV) - Closure; and
- 2. Turbine Control Valve (TCV) Fast Closure. Trip Oil Pressure Low.
limits for inoperable EOC-RPT as specified in the COLR are made applicable; and
limits for inoperable EOC-RPT as specified in the COLR are made applicable.
APPLICABILITY:
THERMAL POWER ?:>)% RTP.
BFN-UNIT 2 3.3-30 Amendment No. 26;*.287 December 30, 2003
EOC-RPT Instrumentation 3.3.4.1 ACTIONS Separate Condition entry is allowed for each channel.
-II -I--
CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Restore channel to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> inoperable.
OPERABLE status.
OR A.2 T-Not applicable if Inoperable channel is the result of an inoperable breaker.
Place channel in trip.
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> B. One or more Functions B. I Restore EOC-RPT trip 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> with EOC-RPT trip capability.
capability not maintained.
AND B.2 Apply the MCPR and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> MCPR and LHGR limit for LHGR limit for inoperable Inoperable EOC-RPT not EOCRPT as specified In made applicable, the COLR.
C. Required Action and C.1 Reduce THERMAL 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated Completion POWER to <Q)% RTP.
Time not met.
BFN-UNIT 2 3.3-31 Amendment No. 243, 287 December 30, 2003 I.
EOc-;PT Instrumentation 3.3.4A1 SURVEILLANCE REQUIREMENTS I
.K lf T l
'1 IU 1
When a channel Is placed in an inoperable status solely for performance of requiied Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Funrtion maintains EOC-RPT trip capability.
SuRVEILLANCE FREQUENCY SR 3.3.4A.1 Perform CHANNEL FUNCTIONAL 92 days TEST.
SR 3.3.4.1.2 Verify TSV Closure and TCV Fast 24 months Closure,. Trip Oil Pressure'- Low Functions:
are not bypasse d Whein THERMAL POWER is Ž 42% RTP, SR 3.3.4.1.13 Pefobrm CHANNEL CALIBRATION.
24rmonths TheAllowable Values shall be:.
- TSV - Closure: < 10% closed; and TCV F ast Closure, Trip Oil PresSUre - Low::
.550 psig.
SR 3.3.4..4:
Perform LOGIC-SYSTEM 24 mfonths FUNCTIONAL TEST including breaker actuation.
BFN-UNIT 2
.3.3-32 Amendment NO. 255 November 30, 1998 I II
Jet Pumps 3.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.2.1
-NOTES Not required to be performed until 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after associated recirculation loop Is In operation.
- 2.
Not required to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after > A
% RTP.
Verify atleast one of the following cdteria (a, 24:hours b, or c).is satisfied for each operating recirculation loop:.,
- a.
Recircuation pumnp flow to speed ratio'.
differs by <5% from established patterns, and jet pump loop flow to recirculation pump speed ratio differs by *55% from established patterns.
- b.
Each jetpump diffuser to lower plenum differential pre~ssUre differs by 5.20% from established patterns.
- c.
Each jet pumpý flow differs by
- 10%
from established patterns.
So Q
v
ý BFN-UNIT 2 3.4-.6 2Amendment No. 253
RHRSWSystem PO*s.
3.7.1 3.7 PLANT SYSTEMS 3.7 1 Residual Heat Rem oval Service W ater (RHRSW ) Syste m.nd.,.
'..'-NOTE Thle number-of reqdired RHRSW pumps may be reduced.I byone for each fueled unit thatkhas been in MODE 4 or 5 for >24 hours.
Four RHRS*swSubsystems
2.2 units fueled -six OPERABLE RHRSW pumps.
APPLICABILTY:
'MODES 1, 2,.:and3.
elk BFN-UNIT 2 3.7-1 Amendment No. 254 September 08, 1998 l II II
RHRSW System jedUM8 3.7.1 ACTIONS CONIbTION REQUIRED ACTION COMPLETION TIME A. One required RHRSW A.1 NOTES-. -
pump inoperable.
- 1. Only applilcble for the 2 units fueled condition.
2> Only four RHRSW
-pumps powered from Sa separate4 kV S shutdown board are req. uired to be OPERABLE if the other4 fueled unit has been in MODE 4.or,5 for > 24hours.°
'Verify fivie RHRSW Immediately; pumps powered from.
-separate 4 kV shutdown boards are OPERABLE.
'OR.
A.2 Restor'e required RHRSW 30 days
-pump to"OPERABLE (statUs.
(continued)
CL TA CL BFN-UNIT 2 3.7-2 Amendment No. 254 September 08, 1998
RHRSW System 04M4$
3.7.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME; B. One RHRSWsubsystem B.1 OTE---."-
Enter applicable Conditions and Required Actions of LCO 3.4.7,
- HOt Shutdown," forRHR shutdown cooling made Inoperable by the RHRSW system.
R estore RHRSW
.30 days.
subsYstem to OPERABLE status.
C. Two requirqdRHRSW C.J1
.Restore one inoperable 7.days pumps inoperable.
RHRSW pump to OPERABLE status.
D. Two RHRSW subsystems D.A NOTE
- inoperable..
.En*ter applicable Conditions a6d Re quired
- Actions of LCO 3-4;7, for RHR shutdown cooling.
made I opbrable by the RHRSW.System.
Restore one RHRSW 7 days.
Sdbs..ystem to OPERABLE status.
(continued)
BFN-UNIT 2 Amendment No. 254 September 08, 1998
RHRSW System U'48 3-7.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME E. Three or more required E.1 Restore one RHRSW 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> RHRSW pumPs pump toOPERABLE inoperable, status.
F. Three or more RHRSW F.1 NOTE subsystems inoperable.
-Enter applicable Conditions and Required Actions of LCO 3.47 for" RHR-I shutdown cooling made inoperable by the RHRSW System.
Restore one. RHRSW t) hours subsystem to OPERABLE.
status.
G. Required Action and
ýG.l.Be In MODE 3.
- 12hours:
associated Completion Time not met.
AN G.2 Be in MODE 4.-
ho' urs UH$
- .-';i':i o
- kIZ, tt6*
le*%
t"A
'ýr BFN-UNIT 2 3.7-4 Amendment No. 254 September 08, 1998
RHRSW Syotem 40,443.7.1 SURVEILLANCE REQUIREMENT-S SURVEILLANCE FREQUENCY SR 3.7.1.1 Verify each RHRSW manual and power 3i days operated valve In the flow 'ath, that is not locked, seaied, or otherwise Secured in, position, is in the cofrec position or can be aligned to the correct position.
'.A*
BFN-UNIT 2 3.7-5 Amendment NO. 254 September 08, 1998
RHRSWV System Ap 3 7.1 I I BFN-UNIT.2 3:7-6 AnmendmentNo. 254 September 08, 1998
EECW System and U-HS 3.7.2 SURVEILLANCE REQUiREMENTS SURVEILLANCE FREQUENCY
,SR 3.7.2.1 Verify the average water temperature of UHS 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is 950 F.
SR 3.7.2.2 NOTE Isolation of how to individua!, components does not render.EECW System inoperable.
Verify each EECW systei.manual and.power 31 days operated valve in the flow paths servicing safety related systems os r components, that :is not locked, sealed,0or otherwise secured in position, is in the correct position.
SR'3.7.2.3 Verifyeach required EECW pump actuates On 24 months an actual.or simulated:initiation signal.
BFN-UNIT 2 3.7-8 Amendment No. 255
- November 30,1998
Main Turbine Bypass System 3.7.5 3.7 PLANT SYSTEMS 3.7.5 Main Turbine Bypass System LCO 3.7.5 The Main Turbine Bypass System shall be OPERABLE.
OR The following limits are made applicable:
- a. LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," limits for an inoperable Main Turbine Bypass System, as specified In the COLR; and
limits for an Inoperable Main Turbine Bypass System, as specified in the COLR; and
limits for an Inoperable Main Turbine Bypass System, as specified In the COLR.
THERMAL POWER ;e/0,RTP.
APPLICABILITY:
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Requirements of the LCO A.1 Satisfy the requirements 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> not met.
of the LCO.
B. Required Action and B.1 Reduce THERMAL 4.hours essociated Completion POWER to <Wi RTP.
Time not met.
BFN-UNIT 2 3.7-17 Amendment No.-254 287 December 30,2003
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Primary Containment Leakaoe Rate Testing Proaram (continued)
The peak calculated containment Internal pressure for the design basis loss of coolant accident, Pa, ls(.psig. The maximum allowable primary containment leakage rate, !4 shallbe 2% of primary containment air weight per day at Pa..
n QýO Leakage Rate acceptance criteria are:
- a. The primary containment leakage rate acceptance criteria Is *- 1.0 L.
During the first unit startup following the testing perforrihed in accordance with this program, the leakage rate acceptance criteria are _0.60 L., for the Type B and Type C tests, and S 0.75 L for the Type A test; and
- b. Air lock testing acceptance criteria are:
- 1) Overall air lock leakage rate *0.05 La when tested at k PN.
- 2) Air lock door seals leakage rate is < 0.02 La when the overall air lock Is pressurized to >_ 2.5 psig for at least 15 minutes.
The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program. The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program.
BFN-UNIT 2 5.0-21 Amendment No. 2 3 -293 March 9, 2005 (3)
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; (4)
Pursuant to the Act and 10 CFR Parts 30,40, and 70, to receive, possess, and use in amounts as required any byproduct, source, or special nuclear material without restriction to chemical or physical form for sample analysis or equipment and instrument calibration or associated with radioactive apparatus or components; (5)
Pursuant to the Act and 10 CFR Parts 30 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 operating license shall be deemed to contain and Is subject to the conditions specified in the following Commission regulations In 10 CFR Chapter 1: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; 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 Incorporated below.
(1)
Miaximum Power Level The licensee is authorized to operate the facility at steady state reactor core power levels not In excess o tq megawatts thermal (2)
Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 253, except for Amendment No. 248, are hereby incorporated in the renewed operating license. The licensee shall operate the facility in accordance with the Technical Specifications.
For Surveillance Requirements (SRs) that are new in Amendment 212 to Facility Operating License DPR-68, the first performance is due at the end of the first surveillance interval that begins at implementation of the Amendment 212. For SRs that existed prior to Amendment 212, including SRs with modified acceptance criteria and SRs 'whose frequency of performance is being extended, the first performahce Is due at the end of the first surveillance interval that begins on the date the surveillance was last performed prior to implementation of Amendment 212.
BFN-UNIT 3 Renewed License No. DPR-68 May 04,2006
Definitions 1.1 1.1 Definitions (continued)
PHYSICS TESTS PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation. These tests are:
- a.
Described in Section 13.10, Refueling Test Program; of the FSAR;
- b.
Authorized under the provisions of 10 CFR 50.59; or
- c.
Otherwise approved by the Nuclear Regulatory Commission.
RTP shall be a total reactor core heat transfer rate to the reactor coolant of 3458=5 MWt.
SDM shall be the amount of reactivity by which the reactor is subcritical or would be subcritical assuming that:
SHUTDOWN MARGIN (SDM) b.
C.
The moderator temperature is 68°F; and All control rods are fully inserted except for the single control rod of highest reactivity worth, which is assumed to be fully withdrawn. With control rods not capable of being fully inserted, the reactivity worth of these control rods must be accounted for in the determination of SDM.
(continued)
BFN-UNIT 3 1.1-6 Amendment No. 214 September 08, 1998
SLs 2.0 2.0 SAFETY LIMITS (SLs) 2.1 SLs 2.1.1 Reactor Core SLs 2.1.1.1 With the reactor steam dome pressure < 785 psig or core flow
< 10% rated core flow.
THERMAL POWER shall be. a'/* RTP.
2.1.1.2 With the reactor steam dome pressure Z! 785 psig and core flow a 10% rated core flow-MCPR shall be > 1.09 for two recirculation loop operation or " 1.11 for single loop operation.
2.1.1.3 Reactor vessel water level shall be greater than the top of active irradiated fuel.
2.1.2 Reactor Coolant System Pressure SL Reactor steam dome pressure shall be s 1325 psig.
2.2 SL Violations With any SL violation, the following actions shall be completed within 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />s:
2.2.1 Restore compliance with all SLs; and 2.2.2 Insert all insertable control rods.
BFN-UNIT 3 2.0-1 Amendment No. a46,-234-.246 February 24, 2004
I""
SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY 4
Verify the concentration and temperature of boron In solution are within the limits of Figure 3.1.7-1.
Once within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after discovery that SPB concentration is
> 9.2% by weight AND 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter SR 3.1.7.5 Verify the minimum quantity of Boron-1 0 in the 31 days SLC solution lank and available for injection is
__z _
?
pounds.
SR 3.1.7.6 Verify the SLC conditions satisfy the following 31 days equation:
AND C C )( Q )(
E
)
newti (13 wt. %)(86 gpm)(19.8 atom%) -
24Once rathin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after
- where, water or boron is added to the solution C = sodium pentaborate solution concentration (weight percent)
Q = pump flow rate (gpm)
E = Boron-10 enrichment (atom percent Boron-1 0)
SR 3.1.7.7 Verify each pump develops a llow rate 2 39 24 months gpm at a discharge pressure ?. 1325 psig.
(continued)
BFN-UNIT 3 3.1-25 Amendment No. 2--,
249 September 27, 2004
APLHGR 132.1
.3.2-POWER DISTRIBUTION LIMITS 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)
LCO 3.2.1 All APLHGRs shall be less than or equal to the limits specified in the COLR.
APPLICABILITY:
THERMAL POWER >
°6oRTP.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.ý Any APLHGR not AA1 Restore APLHGR(s) to
=2 hours within limits, within limits.
B.
Required Action and 8.1
- Reduce THERMAL 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated COmpletion POWER to <*°i%
RTP.
Time not met.
F BFN-UNIT &
3;2 Amendment No. 212
APLHGR 3.2.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.1.1 Verify all APLHGRs are less than or Once within equal to the. limits specified in -the COLR.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after
" Ž 62% RTP AND
- 24. 1urs thereafter A,
BýN-UNIT-3 3.2-2 Amendment No. 212
.3.2.2 3.2 POWER DISTRIBUTION LIMITS 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)
LCO. 3.2,2 APPLICABILITY:
' All MCPRs shall be greater than. or eq~ual. to the MCPR operating limits specified in the COLR.'
'THERMAL POWER 42
/% RTP.
A C T IO N S CONDITION REQUIRED'ACTION
-COMPLETION TIME A.
ny MCPR not within A.1 Restore MCPR(s) to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> limits.
within limin.s.
B.
Required Action and B.I Reduce THERMAL
.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated POWER to <
-6%
- RTP, Completion Time not met.
Bl#N-UNIT 3 3.Z233 BAmendment No. 212
.MCPR 3.2.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.2.1 Vedify all MCPRs are greater than or Once within equal to the :limits specifiedlin the COLR.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after" AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter SR 3.2.2.2 Determine thd!MCPR limits.
Once within 72.hours0afer each,ompletionh of SR 3.1.41 AND Once. within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after' each 0comletion of SR 311.4.2 o
LQ..9 BON-UNil T* 3 3.2-4 Amendment No. 212
ml LHGR 3.2.3 3.2 POWER DISTRIBUTION LIMITS 3.2.3 LINEAR HEAT GENERATION RATE (LHGR)
LCO 3.2.3 All LHGRs shallbe less than or equal to the limits specified in the COLR.
APPLICABILITY:
THERMAL POWER z_> Q >%/
RTP ACTIONS CONDITION
'REQUIRED ACTION
'COMPLETIO N TIME A.
Any LHGR not within A.i Restore LHGR(s) to within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> limitsi i p.
B. Require :d Ac.tion and B.1 ReueTEML4 hours associated.
POWER to<2%RP
-Completion Time not met.
BFN-UNIT-3 3;2-5 Amendment No. 212
LHGR 312;3 SURVEILLANCE REQUIREMENTS............
SURVEILLANCE FREQUENCY SR 3.2.3.1 Verify all LHGRsare less than-or equal Once Within to the limitsspecified in the COLR.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after
? 02% RTP AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter
- c. C J\\6 v
9 BFN-UNIT 3 3.2-6 Amendment No. 212
RPS Instrumentation 3.3.1.1 ACTIONS (continued)
CONDITION
.REQUIRED ACTION COMPLETION
.TIME.
B.
NOTE --
"6B Place channel in:ne trip 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Not applicabie'for system in trip.
Functions 2.a,2.b, 2.c, 2.d, or 2.f.
OR B.2
- Place one trip system in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> One or more Functions trip.
With one or more required channels inoperable in both 1trip Systems.;
C. One or more Functions C.1 Restore RPS trip i hour" with RPS trip capability not
-capability.
maintained.
D. Requirced Actionand DA1 Enterthe condition Immediately associated Completion referencedin Time of Con'diion.A, B,*or Table 3.3.1.1.1 for the C not met channel..
E. As reqUired by Required E.1 ".Reduce THERMAL 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Action O.I and refernced POWER to <:
0/% RTP. -
- in Table3.3.1.1-1.
F. As required by Required F.1
.Be in MODE 2,
.6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />sg Action D. :and referenced-in Table 3.3.1.1-1.
(continued) 3.3-2 Amendment No. 242, 243, 221 September 27, 1999 BFN-UNIT 3
RPS Instiumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS
,NO1rn*,
I.
Refer to TabWle 3.3.1.1-1 to determine which SRs apply for each RPS Function.
- 2.
When a channel is placed in an inoperable status solely for performance of required Surveillances, entry. into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains RPS trip capability.
SURVEILLANCE FREQUENCY SR 3.3.1.1.1 Perform.CHANNEL CHECK.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.1.1.2
.. NOTE Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
.afteirTHERMAL POWER Žk 0/% RTP, Verify the absOlute difference 7 days*
between the average power range monitor (APRM) channels and the c'al:culated power is
SR: 3.3.1.1.3.
NOTE
..Not required to be petrforied Whený entering.
MODE 2fromdMODE` Iuntil 12 -hLours after entering MODE 2.
Perform CHANNEL 7 days FUNCTIONAL TEST.
i, ontinuea) 3.3-4 BFN-UNIT 3 Amendment No. 213 September 03,.1998
RPS Instrumentation 3.31..1 SURVEILLANCE REQUIREMENTS (conitinued)_
SURVEILLANCE FREQUENCY
- SR 3.3.1.1.10 Perform CHANNEL CALIBRATION.
184'days SR,3.3.1.S.ll (Deleted)
SR 3.3.1.1.12 Perform CHANNEL FUNCTIONAL TEST.:
24 months SR 3.3.1.1.13 OTE
'Neutron detectorsware excluded.
Perform CHANNEL CALIBRATION.
24 months SR 3.3.1.1.14.
Perform LOGICSYSTEMFUNCTiONAL 24 months TEST.
SR 3.311.A15 Verify Turbine Stop Valve - Closure and 24 months Turbine Control Valve Fast Closure, Trip Oil Pressure. Low'Functions are nbypassed when THERMAL POWER is $Z% RtP.
.R 3'.3 1
6 For Function 2.a, not required to be performed when entering MODE 2 from
- MODE 1 until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE 2.
Perform CHANNEL 184 days.
FUNCTIONAL TTEST.
SR 3.3.1.1.17 Verify OPRM is not bypassed when APRM 24 months Simulated Thermal Power Is; :25% and recir6ulation drive flow is< 60% of rated recirculation drive flow.
BFN-UNIT 3 3.3-6 Amendment No. ý24 243, 4 424.5221 September 27, 1.999
RPS Instrumentation 3.131.1 Table3.3.1.1-1 (oaael o!3~
Reacto Protection SY..
ru.ntat APPUCABLE' CONDITIONS.
MODES OR REQUIRED REFERENCED FUNCTION OTHER CHANNELS FROM SURVEILLANCE ALLOWABLE SPECIFIED PER TRIP REQUIRED REQUIREMENTS VALUE CONDITIONS SYSTEM ACTION DA.
- 1..
Interinediate Range SMon*0ors 2
3 SR 3.3.1:1.1.
.12(/126
- a. Neutron Flux - High SR 3.3.1.1.3 divisionss of full SR 3.3.1.1.5 scale SR 3.3.1.1.6 SR 33*1.1.9 SR 3.3.1.1..14 5(a) 3 H
R 33111 1201125 SR 3.3.1.1.4 divisions of full
-SR 3.3.1".9 scale SR 3.3.1:1.14
- b. mtop "2
3 2.
SR 3.I3.f..3 NA SR 13.3.1..1.14 5(a) 3 H
SR 3.3.1..4 NA SR 3.3.1.1.14
- 4.
Average Power Range Monitors.C.
2 b(b)
G SR 33.11.1.1 5 4ý19% RTP
- a. Neutron Flux. -. High,
(,S.tdown)
.*BSR 3.3.1.1.7 SR. 3.311.1-13 b..
Flow iased Simulated I
- (b)
F SR :3.3.1.1.1 Thermal Power.. High SR 3:3.1.1:2 p
SR 3
' 3 '3I1'1.7 SR 3.3,1.1713 G.4 SR,313.1.1,16
- c. Neutr*o ux. - High 1
3(b)
.F SR 3.311.1,1 q120% RTP SR 3j3.1.1.2
- SR.3.3.1.1.7 SR.3.3.1.1,13 SR 13.3.1.1;16 (nied)
(a) Wlth any control rod wiftmwn from a coeceU conwanng* oneor *mor f, asmlis (b) Eac *A channel provides Input.s to both:trip.
W~~
rP F
~criao r
. BFN-UNIT 3 Amendment No. 216 December 23, 1998*
.It.
, tVj.)
RPS Instrumentation 3.3.1.1 Table 3.3.1.1.1 (page 3 of 3)
Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED FUNCTION OTHER CHANNELS FROM SURVEILLANCE ALLOWABLE SPECIFIED PER TRIP REQUIRED REQUIREMENTS VALUE CONDITIONS SYSTEM ACTION D.1
- 7. Scram Discharge Volume Water Level - High
- b. Float Switch 1,2 2
<46gallons SR 3.3.1.1.13 SR 3.3.1.1.14 5(a) 2 H
- C 46 gallons SR 3.3.1.1.13 SR 3.3.1.1.14
- 8. Turbine Stop Valve - Closure i
RTP 4
< 10% closed SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.15
- 9. Turbine Control alveFast
>eP/RTP 2
E SR 3.3,1.1.8
>550psig Closure, Trip Oil Pressure -
SR 3.3.1.1.13 Low(d)
SR 3.3.1.1.14 SR 3.3.1.1.15
- 10. Reactor Mode Switch -
1,2 1
G SR 3.3.1.1.12 NA Shutdown Position SR 3.3.1.1.14 5(a) 1 H
SR 3.3.1.1.12 NA SR 3.3.1.1.14
- 11. Manual Scram 1.2 1
G SR 3.3.1.1.8 NA SR 3.3.1.1.14 5(a) 1 H
SR 3.3.1.1.8 NA SR 3.3.1.1.14
- 12. RPS Channel Test Switches 1,2 2
G SR 3.3.1.1.4 NA 5 (a) 2 H
SR 3.3.1.1.4 NA
- 13. Deleted (a)
With any control rod withdrawn from a core cell containing one or more fuel assemblies.
(d)
During Instrument calibrations, If the As Found channel setpolnt Is conservative with respect to the Allowable Value but outside Its acceptable As Found band as defined by Its associated Surveillance Requirement procedure, then there shall be an Initial determination to ensure confidence that the channel can perform as required before returning the channel to service In accordance with the Surveillance. If the As Found Instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.
Prior to returning a channel to service, the Instrument channel setpoint'shall be calibrated to a value that Is within the acceptable As Left tolerance of the setpoint; otherwise, the channel shall be declared Inoperable.
The nominal Trip Setpoint shall be specified on design output documentation which Is Incorporated by reference In the Updated Final Safety Analysis Report. The methodology used to determine the nominal Trip Selpoint, the predefined As Found Tolerance, and the As Left Tolerance band, and a listing of the setpoint design output documentation shall be specified In Chapter 7 of the Updated Final Safety Analysis Report.
I BFN-UNiT 3 3.3-9 Amendment No. 212 213 221 235 254
Feedwater and Main Turb1ine High.Water LevelTrip Instrumentation 3.3.2.2 3.3 INSTRUMENTATION 3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation LCO 3.3.2.2 Two channels 0f feedwater and main turbine high water level trip instrumenitation per triopsystem shall be OPERABLE.
,APPLICABILITY:
THERMAL POWER:>:.%
RP..
ACTIONS
-- NOTE Separate.Condition entry is allowed for each channel.
CONDITION.
REQUIRED ACTION*
COMPLETION TIME A. One or mote feedwater A.1 Place.channel(s) in-trip.
7 days and.main turbine high.
water level trip channels in'operable,.in onetrip system.
B.: One or more feedwater.
B.1 Restore feedwater and 2 houi; S
-and main turbine high main turbine high water waterjlevel trip channels level trip-capability.
inoperable in each trip system.
C.. Required Action and CA1 Reduce THERMAL 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated Completion POWERo< ýt
%RTP.
Time not met.
BF U I.
3*
BFN-UNiT 3 3.3;'22 Amendment No. 213 Septembet" 03, 1998
EOC-RPT Instrumentation 3.3.4.1 3.3 INSTRUMENTATION 3.3.4.1 End of Cycle Recirculation PumpTrip (EOC-RPT) Instrumentation LCO 3.3.4.1
- a. Two channels per trip'system for each EOC-RPT instrnJentatiin.Function listed beiow shall be OPERABLE:
- 1. Turbine Stop Vlve (TSV) Closure; and
- 2. Turbine Control Valve (TCV) Fast Closure, Trip Oil Pressure
- Low.
limits fOr inopeirable EOC-RPT ass sPecified in the COLR:are made applicable; and
limits for indperable EOC-RPT as specified in the COLR are
- made applicable..
APPLICABILITY:
THERMAL POWER ;2 3%
RTP.
BFN-UNIT 3 3.3-30 Amendment No. 24ýr245.
December 3D0,2003
EOC-RPT Instrumhehtatron 3.3.4.1 ACTIONS NOTE c
.Separate COnditidn entry iS a'llowed for each channel.
CONDITION REQUIRED ACTION COMPLETION TIME A. One Or more channels A.1 Restore channel to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> inoperable.
OPERABLE status.-
OR A.2 NOTE-Not applicable if inoperable'channel is the
- result of an inoperable breaker.:
1P1ace.channel in trip.
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> B. One or more Functions B.1 Restore EOC-RPT trip 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> with EOC-RPT trip ca6ability.
capability not maintained.
O.R ANDI B.2.
- Apply the MCPR and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> MCPR and LHGR:limit for LHGR limit for inoperable inoperabie.EOC-RPT not EOC-RPT as specified in made applicable:
the COLR.
C. Required Action* and associated Completion Time not met.
C.1
'Reduce THERMAL POWER to <
- WRTP. Verify atleast one of the 24 hoUrs following criteria (a, b, or c) is satisfied for each operating recirculation loop:
- a. Recirculation. pump flow to.speed ratio differs by < 5%from established patternms and'Jet pump loop flow to recirculation pump speed ratio differs by < 5% from established patterns,.
- b. Each jet pump diffuser to lower plenum differential pressUre differs by _ 20% :from established patterns.
c.. Each jet pump flow differs by < 10% from. established patterns, .BFN-UNIT.3 3.4-6 Ame'dment No. 212 RHRSW System...... 3.7.1 3.7 PLANT SYSTEMS 3.7.1 Residual Heat Removal Servie 'Water (RHRSW) Systeme n, Utim. .to 1-f-.t.*in LCO 3.71.... -NOE.. The number ofretquiredi RHRSW pumps may be reduced by one for each fueled unit that has:been in MODE 4:or 5 for.> 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Four RHRSW subsystems 4i4'J8S shall be OPERABLE with the number.of OPERABLE pumps aislisted below:
2' 2 units fueled - six OPERABLE RHRSW pumpis.
APPLICABILITY: bMODES 1,*2, and 3. 4W. Iýv BFN-UNIT 3 3.7-1 Amendment No.214
- September.08, 1998
RHRSW System.t4044 3.7.1 ACTIONS........ CONDITION REQUIRED ACTION COMPLETION TIME A. One required RHRSW A.1 NOTES pump inoperable. 1 Onlyapplicable for-the
- 2. uhIts.fueled condition.'.
shutdown board are required to be. OPERABLEif the -other fueled unit has been in MODE 4-or 5 for = 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Verify five RHRSW Immediately pumps0powered from separate 4 kV shutdown boards -are OPERABLE. OR
- A.2
'Restore required RHRSW 30 days .pump tb OPERABLE. cstatutS. .(continued) BFN-UNIT 3 3.7-2 Amendment No..214 September 08,.1998 II I III~ RHRSW System. 3.7.1 ACTIONS (continued) CONDITION REQUIRED ACTION COMPLETION TIME B. One RHRSW*subsystem B.13.1 NOTE inoperable. Enter appliCable Conditions ard Required Actions of LCO 3.4.7,
- Residual Heat Removal (RHR) Shutdown Cooling
- Hot Shutdown," for*RHR shutdown cooling made inoperble by the RHRSW isystem. Restore RHRSW 30 days sub system to OPERABLE status. C. Two required RHRSW C.1 Restore oneinoperable' 7 days pumps inoperable. RHRSW pump to OPERABLE status. D. Two RHRSW subsystems inoperable.* D.1 ..NOTE Enter applicable
- C0nditions andlRequired Actions of LCO 34.7, for' RHR'shutdown cooling made inoperable by the:
RHRSW System. Restoreone RHRSW subsystem t6oPERABLE status. 71days (continued) (..v'~ C..) I 3.7-3 BFN-UNIT 3 Amendment No. 214 September 08, 1.998 RHRSW System'."4 .S 3,7.1 ACTIONS (continued) CONDITION REQUIRED ACTION COMPLETION TIME E. Three or more required E.1 Restore one,HRSW 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> ' RHRSW pumps -pumpo0'.OPERABLE .inoperable, status. F. Three or more jRHRSW
- FA1
-NOTE subsystems'inoperable. Enter applicable Cdnditions and Required Actions of LCO 3.4.7. for RHR shdtdown cooling made inoperable by the RHRSW System. Restore one RHRSW 8 h*ours subsystem to OPERABLE status. G. Required Action and G.1 Be in MODE 3. 12.hours associated Completion Time not 6 et. AND. G.2 Be in -MODE 4-36 hours p.44, ~,v'-t. '~A BFN-.UNIT 3 3.7-4 Ae6ndmrent No. 214 September 08, 1998 i ".. "4-RHRSW System e40M 3.7.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7..1. Verify each RHRSW manual and power 31 days operated valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position. SR .7A~ ,'~ifr fi..... .....~urttu. .~ t .4... Ih4 o t4r
- BFN-UNIT 3 3.7-5 Amendment No.'214 September" 08, 1998
RHRSW System 0,44!HS 3.7.1 BFN-UNIT 3 3.7-6 Amendment No. 214 .September 8, 1998 EECW System and UHS 3.7.2 SURVEILLANCE FREQUENCY SR 3.7.2.1 Verify the average water temper0ature of UHS 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is - 95°F, SR 3.72.2. NOTE Isolation of flow to individual components does not render EECW System inoperable. Verify each EECW systern manual and power 31 days
- operated valve in the flow paths servicing safety ;related SYstems or components, that is not locked, sealed,. or otherwise'secured in pbsitioi; is in the iorrect position.
SR 3.7.2.3 Verify each required EEcW pump actuates 24 months on an actual or, simulated initiation signal. BFN-UNIT 3. 3.7-8 Amenidnment No. 215 S, 1998 Main Turbine.Bypass System 3.7.5 3.7 PLANT SYSTEMS 3.7.5 Main Turbine Bypass System LCO 3.7.5 The Maih Turbine Bypass System shall be OPERABLE. OR The following limits are made applicable:
- a. LCO3.2.1, "AVERAGE:PLANAR LINEAR HEAT.GENERATION RATE (APLHGR)," limits for an inoperable Main Turbine Bypass System, as specified in the COLR;*and
.1imits for an inoperable Main Turbine Bypass System, as specified in the COLR; and.
- c. LCO:3.2.3, "LINEAR HEAT"GENERATION RATE (LHGR),"
limits for an inopetable Main Turbine Bypass System, as specified in the COLR. APPLICABILITY: THERMAL POWER * * *% RTP, ACTIONS CONDITION REQUIRED ACTION COMPLET ION TIME A. Requirements, of the LCO A.1 Satisfy the rep.i irements 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> not met. of the LCO. B. Required Action and BAI Reduce THERMAL .4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />' associated compietlon POWER to <*% RTP. Time not met. BFN-UNIT 3 3.7-17 Amendment No. a44-,245 Dec.mber.30, 2003 Programs and Manuals 5.6 5.5 Programs and Manuals 5.5.12 Primary Containment Leakaga Rate Testina Program (continued) The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa., i . psig. The maximum allowable primary containment leakage rate, L., si abe 2% of primary containment air weight per day at Pa. Leakage Rate acceptance criteria are:
- a. The primary containment leakage rate acceptance criteria is < 1.0 L,.
During the first unit startup following the testing performed In accordance with this program, the leakage rate acceptance criteria are < 0.60 L4 for the Type B and Type C tests, and *; 0.75 L, for the Type A test; and
- b. Air lock testing acceptance criteria are:
- 1) Overall air lock leakage rate _0.05 L& when tested at k Pa.
- 2) Air lock door seals leakage rate Is _ 0.02 L, when the overall air lock is pressurized to ;- 2.5 psig for at least 15 minutes.
The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Primary Containment Leakage Rate Testing Program. The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program. BFN-UNIT 3 5.0-21 Amendment No. M 252 March 9, 2005 ENCLOSURE 6 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN) UNITS 1, 2, AND 3 TECHNICAL SPECIFICATIONS (TS) CHANGES TS-431 AND TS-418 - EXTENDED POWER UPRATE (EPU) RESPONSE TO ROUND 10 REQUEST FOR ADDITIONAL INFORMATION (RAI) (TAC NOS.
REGULATORY COMMITMENTS Comnmi tments An evaluation summary for Unit 1 piping systems (including main steam, feedwater, recirculation, residual heat removal (RHR), and torus attached piping) will be provided to the NRC staff by December 31, 2006. The information provided will include the calculated maximum stresses for piping systems similar to the information provided for the EPU application of Units 2 and 3. Because initial operation of Unit 1 Cycle 7 will be at 105% of OLTP, the core design and associated analyses are being reperformed consistent with an interim licensed power level of 3458 MWt. TVA will provide the revised Supplemental Reload Licensing Report to the NRC by January 31, 2007.