ML20198S843
| ML20198S843 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 11/05/1997 |
| From: | Donohew J NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20198S849 | List: |
| References | |
| NUDOCS 9711140143 | |
| Download: ML20198S843 (17) | |
Text
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UNITE) STATES g '-
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,j NUCLEAR REGULATORY COMMISSION l
WASHINGTON, D.C. 30eeH001
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ENTERGY OPERATIONS. INC.
SYSTEM ENERGY RESOURCES. INC.
SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION ENTERGY MISSISSIPPI. INC.
DOCKET NO. 50-416 GRAND GULF NUCLEAR STATION. UNIT 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 133 License No. NPF-29 1.
The Nuclear Regulatory Comission (the Comission) has found that:
A.
The application for amendment by Entergy Operations, Inc. (the licensee) dated May 7,1997, as supplemented by the letter of October 6,1997, comply with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.
The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the
-Commission; C.
There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D.
The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.
The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.
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9711140143 971105 PDR ADOCK 05000416 P
. 2.
Accordingly, the license is amended by changes to the Technical Specifications, as indicated in the attachment to this license amendment; and paragraph 2.C.(2) of Facility Operating License No, NPF-29 is hereby amended to read as follows:
(2) Technical Soecifications The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No.133, are hereby incorporated into this license.
Entergy Operations, Inc. shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
3.
This license amendment is effective as of its date of issuance.
FOR THE NUCLEAR REGULATORY COMMISSION D
.1 q
/ Jack N.
onohew hurProjectManager N
Project Directorate IV-1 Division of Reactor Projects lil/lV Office of Nuclear Reactor Regulation
Attachment:
Changes to the Technical fpecifications Date of Issuance: November 5, 1997
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ATTACHMENT TO LICENSE AMENDHENT NO. 1?3 FACILITY OPERATING LICENSE NO. NPF-29 DOCKET NO. 50-416 Replace the following pages of the Appendix A Technical Specifications and the Bases to the Technical Specifications with the attached pages.
The revised pages are identified by amendment number and contain vertical lines indicating the area of change.
REMOVE INSERT 3.3-5 3.3-5 3.3-53 3.3-53 3.5-5 3.5-5 3.5-9 3.5-9 B3.3-29 B3.3-29 B3.3-29a B3.3-30 83.3-30 B3.3-170 B3.3-170 B3.3-170a B3.3-171 B3.3-171 B3.5-13a B3.5-13a B3.5-14 B3.5-14 B3.5-19 B3.5-19 B3.5-20 B3.5-20 i
4 1
RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.3.1.1.11 Perform CHANNEL FUNCTIONAL TEST.
18 months SR 3.3.1.1.12
NOTES------------------
1.
Neutron detectors are excluded.
2.
For IRMs, 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 CAllBRATION.
18 months SR 3.3.1.1.13 Perform LOGIC SYSTEM FUNCTIONAL TEST.
18 months SR 3.3.1.1.14 Verify Turbine Stop Valve Closure, Trip 18 months Oil Pressure--Low and Turbine Control Valve Fast Closure Trip 011 Pressure--Low functions are not bypassed when THERMAL POWER is 2 40% RTP.
SR 3.3.1.1.15
NOTES------------------
1.
Neutron detectors are excluded.
2.
For Functions 3, 4, and 5 in Table 3.3.1.1-1, the channel sensors may be excluded, t
- l 3.
For Function 6, "n" equals 4 channels for the purpose of determining the STAGGERED TEST BASIS Frequency.
i.
Verify the RPS RESPONSE T!ME is within 18 months on a limits.
STAGGERED TEST BASIS
' GRAND GULF 3.3-5 Amendment No. 140,133
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Pricary Containment and Drywell Isolction Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS
NOTES-------------
1.
Refer to Table 3.3.6.1-1 to determine which SRs apply for each 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 Functica maintains isolation capability.
SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.3.6.1.2 Perform CHANNEL FUNCTIONAL TEST.
92 days SR 3.3.6.1.3 Calibrate the trip unit.
92 days SR 3.3.6.1.4 Perform CHANNEL CALIBRATION.
92 days SR 3.3.6.1.5 Perform CHANNEL CALIBRATION.
12 months SR 3.3.6.1.6 Perform CHANNEL CALIBRATION.
18 months SR 3.3.6.1.7 Perform LOGIC SYSTEM FUNCTIONAL TEST.
18 months SR 3.3.6.1.8
NOTE--------------------
Channel sensors may be excluded.
Verify the ISOLATION SYSTEM RESPONSE TIME 18 months on a for the Main Steam Isolation Valves is STAGGERED TEST within limits.
BASIS GRAND GULF 3.3-53 Amendment No. 128,133
ECCS--Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.5.1.5
NOTE--------------------
Vessel injection / spray may be excluded.
Vorify each ECCS injection / spray subsystem 18 months actuates on an actual or simulated automatic initiation signal.
NOTE--------------------
Valve actuation may be excluded.
Verify the ADS actuates on an actual or 18 months simulated automatic initiation signal.
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 reactor steam pressure and flow are adequate to perform the test.
Verify each ADS valve relief-mode actuator In accordanca strokes when manually actuated, with the Inservice Testing Program on a STAGGERED TEST BASIS for each valve solenoid SR 3.5.1.8
NOTE--------------------
ECCS actuation instrumentation is excluded.
Verify the ECCS RESPONSE TIME for the HPCS 18 months System is within limits.
GRAND GULF 3.5-5 Amendment No. 120,130,133
ECCS--Shutdown 3.5.2 SURVEILLANCE REQUIREMENTS (continued)
SURVEILLANCE FREQUENCY SR 3.5.2.5 Verify each required ECCS pump develops the In accordance specified flow rate with the specified with the total developed head.
Inservice Testing Program TOTAL 111118 FLOW RATE DEVELOPED HEAD LPCS 2 7115 gpm 2 290 psid i
LPCI 2 7450 gpm 2 125 psid HPCS 2 7115 gpm 2 445 psid t
.------------------NOTE--------------------
Vessel injection / spray may be excluded.
Verify each required ECCS injection / spray 18 months subsystem actuates on an actual or simulated automatic initiation signal.
i GRAND GULF
-3.5-9 Amendment No.-444,133 i
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RPS !astrumentation B 3.3.1.1 BASES 4
i SURVEILLANCE sn 3.3.1.1.15 REQUIREMENTS 4
(continued)
This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis.
The RPS RESPONSE TINE acceptance criteria are included in the applicable plant procedures.
As noted, neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation i
virtually ensure an instantaneous response time. Note 2 allows the channel sensors of Functions 3, 4, and 5 to be excluded from specific RPS RESPONSE TIME testing. This i
allowance to not perform specific response time testing of the sensors is applicable when the alternate testing requirements and restrictions of Reference 10 are performed.
As stated in Reference 10, analysis has demonstrated that other Technical Specification testing requirements (CHANNEL CELIBRATIONS, CHANNEL CHECKS, CHANNEL FUNCTIONAL TESTS, and LOGIC SYSTEN FUNCTIONAL TESTS) and actions taken in response to NRC Bulletin 90-01 Supplement 1 are sufficient to identify failure modes or degradation in instrument response times and assure operation of the analyzed instrument loops within acceptable limits.
Reference 10 also identifies that there are no known channel sensor failure modes '.oentified that can be detected by response time testing that cannot also be detected by other Technical Specification required surveillances.
Therefore, when the requirements, including sensor types, of Reference 10 are complied with, adequate assurance of the response time of the sensors is provided.
This assurance of the i
response time of the sensors when combined with the response time testing of the remainder of the channel ensures that I
the individual channel response times are less than or equ41 to the maximum values assumed in the accident analysis.
The L
calibretion shall be performed such that fast ramp or step
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change to system components during calibrations is performed to verify that the response af the transmitter to the input change is prompt.
Technicians shall monitor for response time degradation during the performance of calibrations.
Technicians shall be appropriately trained to ensure they are aware of the consequences of instrument response time degradation.
These items are commitments made per Reference 11.
If the alternate testing requirements of Reference 10 are not complisd with, then the entire channel will be l
response time tested including the sensors.
(continued) 4 1
GRAND GULF-B 3.3-29 LDC 97078 a
RPS Instrumentat Pm B 3.3.1 !
i BASES l
SURVEILLANCE
$8 3.3.1.1.15 (continued)
REQUIREMENTS RPS RESPONSE TIME tests are conducted on an 18 month STAGGERED TEST BAS!$. Note 3 requir1s STAGGERED TEST BASIS I Frequency to be determined based on 4 channels per trip system, in lieu of the 8 channels specified in Table 3.3.1.1-1 for the MSIV Closure Function. This Frequency is based on the logic interrelationships of the various channels required to produce an RPS scram signal.
Therefore, sta gered testing results in response time verification o these devices every 18 months.
This Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components causing serious time degradation, but not channel failure, are infrequent.
REFERENCES 1.
UFSAR, Figure 7.2-1.
2.
UFSAR, Section 5.2.2.
i 3.
UFSAR, Section 6.3.3.
4.
UFSAR, Chapter 15.
5.
UFSAR, Section 15.4.1.
6.
NE00 23842, " Continuous Control Rod Withdrawal in the Startup Range," April 18, 1978.
7.
UFSAR, Section 15.4.9.
(continued)
GRAND GULF B 3.3 29a LOC 97078
RPS Instrumentation B 3.3.1.1 BASES REFERENCES 8.
Letter. P. Check (NRC) to G. Lainas (NRC), "BWR (continued)
Scram Discharge System Safety Evaluation,"
December 1, 1980, as attached to NRC Generic Letter dated December 9,1980.
9.
NED0 30851-P-A, " Technical Specification Improvement Anrivses for BWR Reactor Protection System,"
March 1988.
10.
NE00 32291 A, " System Analyses for Elimination of Selected Response Time Testing Requirements," October 1095.
11.
GNRI 97/000 _, Amendment 133 to the Operating License.
GRAND GULF B 3.3-30 LDC 97078
i Primary Containment and Drywell Isolation Instrumentation 8 3.3.6.1
- BASES SURVEILLANCE SR 3.3.6.1.7 REQUIREMENTS (continued)
The LOGIC SYSTE:1 FUNCTIONAL TFST demonstrates the OPERA 81LITY of the required isolation logic for a specific channel. The system functional testing performed on 1
isolation valves in LC0 3.6.1.3 and LC0 3.6.5.3 overlaps i
this Surveillance to provide complete testing of the assumed safety function. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that i
apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.
Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency..
SR 3.3.6.1.8 This SR ensures that the individual char.nel response timas are less than or equal to the maximum values assumed in the accident analysis.
Testing is performed only on channels where the assumed response time does not corre nond to the diesel generator-(DG) start time.
For channels assumed to respond within the DG start time, sufficient margin exists in the 10 f.econd start time when compared to the typical channel response time (alll1 seconds) so as to assure adequate response without a specific measurement test.
Testing of the closure times of the NSIVs is not included in this Surveillance since the closure time of the MSIVs is tested by SR 3.6.1.3.6.
ISOLATION SYSTEM RESPONSE TIME acceptance criteria for this instrumentation is included in the applicable plant procedures.
As Noted, the channel sensor may be excluded from response time testin'g. This allowance to not perform specific response time testing of the sensors is applicable when the alternate testiii requirements and restrictions of Reference 7 are performed. As stated in Reference 7, analysis has demonstrated that other Technical Specification testing J
requirements (CHANNEL CALIBRATIONS, CHANNEL CHECKS, CHANNEL FUNCTIONAL TESTS, and LOGIC SYSTEM FUNCTIONAL TESTS and actions taken in response to NRC Bulletin 90 01 Supp are sufficient to identify failure modes or degradation in (continued)
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BASES SURVEILLANCE SR 3.3.6.1.8 (continued)
REQUIREMENTS instrument response times and assure operation of the analyzed instrument looos within acceptable Ifnits.
Reference 7 also identifies that there are no known channel sensor failure modes identified that can be detectsJ by response time testing that cannot also be detected by other Technical Specification required surveillances.
Therefore, wheh the requirements, including sensor types, of Reference 7 are coroiied with, adequate assurance of the response time of the sensors is provided. This assurance of the response time of the sensors when combined with the response time testing of the remainder of the channel ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis.
The calibration shall be performed such that fast ramp or step change to system components during calibrations is performed to verify that the response of the transmitter to tie input change is prompt. Technicians shall monitor for response time degradation during the performance of calibr6tions.
Technicians shall be appropriately trained to ensure they are aware of the consequences of instrument response time degradation. These items are coamitments made per Reference 8.
If the alternate testing requirements of Reference 7 are not complied with then the entire channel will be response time tested including the sensors.
ISOLATION SYSTEM RESPONSE TIME tests for this instrumentation are conducted on an 18 month STAGGERED TEST BASIS. This test Frequency is consistent with the typical t
industry refueling cycle and is based upon plant operating experience that shows that randon failures of instrumentation components causing serious response time degradation, t,ut not channel failure, are infrequent.
REFERENCES 1.
UFSAR, Chapter 6.
l 2.
UFSAR, Chapter 15.
(continued)
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B 3.3.6.1 BASE 5 REFERENCEC 3.
NED0-31466, " Technical Specification Screening (continued)
Criteria Application and Risk Assessment,"
November 1987.
a.
UFSAR, Section 9.3.5.
5.
NEDC 31677-P A, " Technical Specification Improvement Analysis for BWR ! solation Actuation Instrumentation,"
June 1989.
6.
NEDC-30851-P A, Supplement 2, " Technical Specifications !aprovement Analysis for BWR ! solation Instrumentation Cosmon to RPS and ECCS Instrumentation," March 1989.
7.
NED0 322912A, " System Analyses for Elimination of Selected Response Time Testing Requirements," October 1995.
8.
GNRI 97/000__, Amendment 133 to the Operating Licensea e
GRAND GULF B 3.3-171 LDC 97078 i
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I ECCS--Operating i
B 3.5.1 l
BASES' j
SURVEILLANCE SR 3.5.1.7 (continued) i REQUIREMENTS alternately tested. The Frequency of the required relief mode actuator testing was developed based on the i
tests required by the ASME Boiler and Pressure Vessel Code,
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Section XI as implemented by the Inservice Testing Program l
of Specification 5 5.6.
The testing Frequency required by the Inservice Testing Program is based on operating experience and valve performance.
Therefore, the frequency l
was concluded to be acceptable from a reliability standpoint.
1 SR 3.5.1.8 This SR ensures that the HPCS System response time is less than or equal to the maximum value assumed in the accident i
analysis.
Specific testing of the ECCS actuation instrumentation inputs into the HPCS System ECCS SYSTEM RESPONSE TIME is not required by this SR. Specific response I
time testing of this instrumentation is not required since these actuation channels are only assumed to respond within the diesel generator start time; therefore, sufficient margin exists in the diesel generator 10 second start time i
when compared to the typict.1 channel response time (milliseconds) so as to assure adequate response without a specific measurement test (Ref. 16).
The diesel generator I
starting and any sequence loading delays along with the Reactor-Vessel Water Level Low Low, Level 2 confirmation delay permissive must be added to the HPCS System equipment response times to obtain the HPCS System ECCS SYSTEM RESPONSE TIME.
The acceptance criterion for the HPCS System ECCS SYSTEM RESPONSE TIME is s 27 seconds.
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SURVEILLANCE SR 3.5.1.8 (continued)
REQUIREMENTS HPCS System ECCS SYSTEM RESPONSE TIME tests are conducted every 18 months. This frequency is consistent with the typical industry refueling cycle and is based on industry operating experience.
I REFERENCES 1.
UFSAR, Section 6.3.2.2.3.
2.
UFSt.R, Section 6.3.2.2.4.
3.
UFSAR, Section 6.3.2.2.1.
4.
UFSAR, Section 6.3.2.2.2.
5.
UFSAR, Section 15.6.6.
6.
UFSAR, Section 15.6.4.
7.
UFSAR, Section 15.6.5.
8.
9.
UFSAR, Section 6.3.3.
10.
11.
UFSAR, Section 6.3.3.3.
12.
Memorandum from R.L. Baer (NRC) to V. Stello, Jr.
(NRC), " Recommended Interim Revisions to LC0's for ECCS components," December 1, 1975.
13.
UFSAR, Section 6.3.3.7.8.
14.
UFSAR, Section 7.3.1.1.1.4.2.
15.
GNRI-96/00229, Amendment 130 to the Operating License.
16.
NEDO-32291-A " System Analyses for Elimiriation of Selected Response Time Testing Requirements," - October 1
1995.
17.
GNRI-97/000,_, Amendment 133.to the Operating License j
GRAND-GULF B 3.5-14 LDC 97078
ECCS--Shutdown i
B 3.5.2 i
BASES SURVEILLANCE SR 3.5.2.4 (continued)
REQUIREMENTS initiation signal is allowed to be in a nonaccident position provideo' the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification thtt those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.
The 31 day Frequency is appropriate because the valves are operated under procedural control and the probability of their being mispositioned during this time period is low.
In MODES 4 an6 s, the RHR System may operate in the shutdown cooling mode, or be aligned to allow alternate means to remove decay heat and sensible heat from the reactor.
Therefore, RHR valves that are required for LPCI subsystem operation may be aligned for decay heat removal. This SR is modified by a Note that allows one LPCI subsystem of the RHR System to be considered OPERABLE for the ECCS function if all the required valves in the LPCI flow path can be manually realigned (remote or local) to allow injection into the RPV and the system is not otherwise inoperable.
This will ensure adequate core cooling if an inadvertent vessel draindown should occur.
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-B 3.5.2 BASES (continued) i I
REFERENCES 1.
UFSAR, Section 6.3.3.4.
2.
GNRI-97/000,_, Amendment 133 to the Operating License.
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