ML20098H185
| ML20098H185 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 09/05/1984 |
| From: | GEORGIA POWER CO. |
| To: | |
| Shared Package | |
| ML20098H184 | List: |
| References | |
| TAC-54168, TAC-55695, NUDOCS 8409120096 | |
| Download: ML20098H185 (163) | |
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, _s TABLE OF CONTENTS i )
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I. Introduction II. References III. Analog Transmitter Trip System (ATTS) Installation 3A. ATTS Detailed Design Information 3B. Bases for Technical Specifications Revisions for ATTS Equipment 3C. Summary IV. Proposed Plant Modifications to be Incorporated into the ATTS Design 4A. Introduction
- 48. Safety Evaluation Report 4B.1 Low Low Set Logic Design Modification 48.2 Lowered Main Steam Isolation Valve (MSIV) Water Level Trip Setpoint Modification 48.3 Reactor Vessel Water Level - Low Low (Level 2) Trip Setpoint Modification 48.4 Reactor Vessel Water Level - High (Level 8) Trip Instruman-tation Modifications 48.5 RCIC/ Reactor Vessel Water Level 8 Trip Clarification 4B.6 Lowered Water Level Trip Setpoint for Isolation of Reactor Water Cleanup (RWCU) and Secondary Containment, and Starting
/N of Standby Gas Treatment System (SGTS)
\J- 48.7 Deletion of High Drywell Pressure Signal for Residual Heat Removal (RHR) (Shutdown Cooling Mode) and RPV Head Spray Valve 48.8 Safety / Relief Valve Position Indicator Modifications 48.9 Residual Heat Removal Shutdown Cooling Mode Safety Limit Modification -
4B.10 Elimination of MSIV Closure Scram in Startup Mode 48.11 T-ip Function Identification Modifications 48.12 Miscellaneous Trip Setpoint/ Allowable Value Modification V. Summary VI. Proposed Technical Specifications Revisions Appendix 1 Significant Hazards Review
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(g I. INTRODUCTION
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- The Edwin I Hatch Nuclear Plant-Unit 1 (HNP-1) safety-related sy' stem instru-
- mentation upgrade program, which includes incorporation of the analog transmitter
_ trip system (ATTS), comprises many equipment modifications and installations to afeet many of the requirements and criteria of:
e IE Bulletin 79-018, Environmental Qualification of Class 1E Equipment *
. e NUREG-0737, TMI Lessons Learned
- I 'e NUREG-0696, Safety Parameters Display System Interfaces *'
i e NUREG-0661, Low Low Set Trip Logic *.
l This submittal covers information on ATTS (Section III) and the proposed plant design modifications-(Section IV) being performed at Plant Hatch through the installation of ATTS during the 1984 refueling outage. This report will be updated for -the 1985 refueling outage to include the remaining modifications s
~ being performed through the installation of ATTS.
The purpose of this submittal is to provide the bases for the proposed modi-fications and to provide Georgia Power Company's (GPC) proposed revisions to the Techical Specifications.
]v ATTS and the associated plant modifications will be incorporated into the HNP-1 system logic prior to and during the next two refueling outages. The installation is scheduled to be completed by the startup of Cycle 10.
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- Subject shown is not necessarily title of document.
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II. REFERENCES
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- 1. Edwin I. Hatch Nuclear Plant Unit 2, Docket No. 50-366, Proposed Plant Modification-Low Low Set Logic and Lowered MSIV Water Level, GPC Letter NED-83-108, Proposal for Technical Specifications Changes Which Support Cycle 4 Startup, February 23, 1983.
- 2. IE Bulletin 79-01B, Environmental Qualification of Class 1E Equipment.
- 3. IEEE 323-74, IEEE Standard for Qualifying Class 1E Equipment for Nuclear Power Generating Stations.
- 4. IEEE 344-75, IEEE Recommended Practices for Seismic Qualification of IE Equipment for Nuclear Power Generating Stations.
- 5. NEDC-24346, Evaluation of Mark I S/RV Load Cases C3.2 and C3.3 for Edwin I. Hatch Nuclear Plant - Units 1 and 2.
- 6. NEDO-21617-A, General Electric Licensing Topical Report, Analog Trans-mitter/ Trip Unit System for Engineered Safeguard Sensor Trip Inputs.
- 7. NUREG-0588, Revision 1, Interim Staff Position on Environmental Qualifi-cation of Safety-Related Electrical Equipment.
- 8. NUREG-0661, Mark I Containment Long Term Program.
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C 9. NUREG-0626, GE Evaluation of Feedwater Transients and Small Break LOCA in GE-Designed Operating Plants.
- 10. NUREG-0696, Functional Criteria for Emergency Response Facilities.
- 11. NUREG-0737, Clarification of TMI Action Plan Requirements.
- 12. Regulatory Guide 1.105, Instrument Setpoints.
- 13. Draft Standard Technical Specifications for General Electric Boiling Water Reactor (GE-STS) - BWR/4.
- 14. WASH-1400, An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants.
- 15. Edwin I. Hatch Nuclear Plant Unit 2', Docket No. 50-366, Proposed Plant Modifications to be Incorporated Into ATTS Design, GPC Letter, NED-84-017, Request for Technical Specification Changes to Support Analog Transmitter Trip System Installation, January 23, 1984.
- 16. GPC Letter, NED-84-281, Response to NRC Staff Questions on Proposed ATTS Technical Specifications Changes, June 7,1984.
- 17. GPC Letter, NED-84-321, Revised Responses to NRC Staff Questions on q Proposed ATTS Technical Specifications Changes, June 14, 1984.
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() III. ANALOG TRANSMITTER TRIP SYSTEM (ATTS) INSTALLATION LJ .
- } A safety evaluation report was prepared to evaluate the licensing requirements of ATTS. Frem that evaluation, it was concluded that the incorporation of ATTS constitutes neither an unreviewed safety question, nor a significant hazards consideration. To keep the Nuclear Regulatory Commission (NRC) apprised of major Plant Hatch design modifications, Georgia Power Company (GPC) prepared a detailed description of the system to be installed. This detailed description provides all of the instrumentation to be incorporated into ATTS during the next two refueling outages. The general description of the proposed ATTS is provided in NEDE-22154-1 General Electric (GE) Licensing Topical Report (contained in Reference 15). NEDE-22154-1 is a plant-specific revision to the NED0-21617-A document (Reference 6), which was approved by the
-NRC to use as a reference to license the ATTS design. NEDE-22154-1 contains the system / component design changes and additional qualification test data.
Because no approved Arrhenius accelerated aging techniques were available when the-original NEDO-21617-A document was issued, the equipment referencing the original NE00-21617-A report is only partially qualified to IEEE 323-1974 requirements. To meet the IEEE 323-1974 and NUREG-0588 criteria, the ATTS to -
be installed at Plant Hatch-Unit 1 was requalified. A description of qualification testing is documented in Chapter 4 of NEDE-22154-1, and in addition identifies Plant Hatch testing criteria. Actual qualification reports will be provided to the NRC upon request.
Since the equipment comprising the ATTS was demonstrated to be superior to the O
V mechanical switches currently used at Plant Hatch, certain tschnical speci-fications surveillance requirements may be revised. These revisions take advantage of the sensor improvements.Section III discusses the proposed sur-veillance revisions for the complete ATTS installation. The proposed plant modifications a'ssociated with ATTS and their justifications are discussed in Section IV.
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-3A. ATTS DETAILED DESIGN INFORMATION p
\h. ;3A.1 In_NE00-21617-A, dated December 1973, the NRC identified specific detailed information that each applicant (who uses that topical as a licensing basis) must provide relative to the specific application of the ATTS hardware into his plant. Since NEDE-22154-1 (contained in Reference 15) describes the same conceptual system as NED0-21617-A but with different hardware, GPC is supplying the NRC with the same information (requested of those who use NE00-21617-A as a licensing ;
basis) regarding the Plant Hatch installation. Therefore, this section provides specific design criteria for the ATTS installation to be completed during the 1984 and 1985 refueling outages for Plant Hatch-Unit 1.
As identified in the NRC request section of NED0-21617-A, GPC offers the information listed below. ,
3A.1.a The following information for each instrument loop that will be converted to the ATTS is provided in table 3.1:
o Variable name e MPL number e Enginee ed safeguards division e Model number and vendor of the transmitter or RTD.
e Device's associated rack.
- ~ 3A.I.b The layout of each card file in each trip unit cabinet, showing the trip variable for each card file slot, is provided in figures 3.1 through 3.8. These figures were developed to illustrate the 12
. card slots per card file and the three card files per cabinet arrange-ment.
3A.1.c The environmental service conditions for Plant Hatch are presented in tables 4-1 through 4-3 of NEDE-22154-1. The seismic curves identified in these tables are the Unit 2 floor response spectra curves gener-ated for the various mounting locations of the ATTS hardware. These Unit'2 curves envelop the corresponding Unit 1 curves and consequently may be used to define the seismic conditions for both units. Figures 3.9 through 3.21 correspond to or envelop tne Plant Hatch safe shutdown earthquake curves. Table 4-5 and figures 4-5 through 4-12 of NEDE-22154-1 define the seismic levels to which the ATTS hardware was qualified.
Comparison of the curves presented in figures 3.9 through 3.21 with the corresponding curves presented in figures 4-5 through 4-12 of NEDE-22154-1 shows that the ATTS' hardware was seismically qualified to levels which exceed the Hatch requirements. Table 3.2 presents a
- summary of the various ATTS hardware along with the corresponding mounting locations and references to the applicable Plant Hatch seismic curves.
'D/] 3A.1.d An interconnection diagram, showing the basic interconnections between the existing logic cabinets and the instrument cabinets and the new trip unit cabinets, is shown in figure 3.22. This interconnection diagram also presents the divisional separation of the cabinets. -
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3A.1.e~ The qualification program to the requirements of IEEE 323-74 and IEEE c- 344-75 was completed in December of -1983 with GE's issuance of the final qualification report (NEDC-30039). The details of the qualification program are presented in NEDE-22154-1. GPC will submit
. the final- qualification reports (proprietary to GE) to the NRC upon request. .
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O 3.A.2 In a telecon with GPC, the NRC identified several questions regarding D) the Unit 2 ATTS licensing submittal. GPC's response to those questions was submitted to the NRC by GPC letters NED-84-281 dated June 7, 1984, and NED-84-321 dated June 14, 1984. GPC has also answered the same questions concerning ATTS design for Unit 1, below.
3.A.2.a QUESTION 1-1:
Please supply information relating to the power supply arrangement for the ATTS units within the RPS on both the primary and backup power systems. Also, please supply information with regard to the RPS and ECCS on how GPC ensures that an undervoltage condition could not exist which would incapacitate the trip functions for those systems.
RESPONSE
The RPS portion of the ATTS is supplied, as is the remainder of the RPS, from the RPS MG set which has a class 1E undervoltage trip that initiates a scram on undervoltage. The system itself is a fail-safe system; therefore, with a loss of power, all instruments go to their safety positions. This arrangement is consistent with the original design bases of the plant.
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'V class 1E batteries are divisionalized and supplied by chargers that are powered off the emergency diesels. The batteries are sized per FSAR Section 8.5.3 for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> continuous duty without the charger.
The power supply for the ECCS portion of ATTS is consistent with the original design bases of the plant.
The installation of the ATTS system has not affected the design of -
the Plant Hatch ECCS and RPS power supplies. Undervoltage protection for the ECCS portion of the system is provided by the Class 1E batteries which are supplied by chargers that are powered from the emergency diesel generators. The RPS portion of the ATTS is protected by redundant C1 ass IE output breakers which will deenergize the RPS bus on an undervoltage condition. The minimum voltage that the batteries would ever show based on the FSAR requirement is 105 Vdc. The ATTS has voltage converters which work from 105 to 140 Vdc on the input-output to give a nominal output of 25 Vdc and a full-load voltage of 23.5 Vdc. The ATTS is designed to operate with a minimum voltage of 23.5 Vdc; therefore, the ATTS function is assured.
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m 3.A.2 b.-QUESTION 1-2:
Does the MG set on the RPS also supply some non-Class IE loads, and if so, what type of isolation devices separate the class IE and non-Class IE systems? Also, what type of surveillance is performed on-those isolation devices?
RESPONSE
The RPS MG sets supply a 120 V-ac power to the below listed loads.
The design of these systems, including the additional hardware for the RPS' portion of the ATTS is consistent with the design criteria established in the FSAR. It is also noted that all safety actuations associated with the listed systems, as well as the RPS portion of the ATTS goes to their safety position on a loss of RPS power. The
. additional hardware associated with the RPS portion of the ATTS is no more susceptible.to failures than the hardware which it replaces.
The systems powered from the RPS are as follows:
e RPS MG SET A Neutron Monitoring System Reactor Protection System Nuclear Steam Supply Shut Off System Primary Containment Isolation System Process Radiation Monitoring System O.
Neutron Monitoring System Reactor Protection System Nuclear Steam Supply Shut Off System Primary Containment Isolation System Process Radiation Monitoring System Offgas Radiation Monitoring System The ECCS de distribution panels which supply essential dc power to the ECCS ATTS cabinets also supply some non-Class 1E loads. These distribution panels are supplied from the plant Class IE batteries which are backed up by chargers fed by the emergency buses. Breakers are used to separate the non-Class 1E and the Class 1E systems. This is also consistent with the original design bases of the plant The addition of ATTS into the plant design does not modify the original licensing bases of the plant with respect to the application of breakers.in the RPS. The breakers used for undervoltage protection are Class 1E. Surveillance testing is required for these breakers per Unit-1 Technical Specifications Section 4.9.0.1. There is.no commitment to perform surveillance testing on other breakers within the system. This is consistent with the original design basis of the plant in that Plant Hatch, Unit 1 is not required to meet q Regulatory Guide 1.75.
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3.A.2.c -QUESTION 1-3:
Please provide the setpoints for the gross failure alarm.
RESPONSEi The high/ low gross failure setpoints are to be set at values of 35 +
0.5 and 0.5 + 0.5 mA., respectively. The alarms are provided to
- indicate a short-circuit and open-circuit. Therefore, the setpoint values can be varied significantly outside the saturation range of the transmitter and still provide adequate protection.
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(T- - 3.A.2.d QUESTION 1-4:
LJ In the AC NE00 document topical report on ATTS, there is a table that talks so. c the maximum lead length that can be installed in the plant using the wire length and power supply voltage. What are we doing with regard to that table at Plant Hatch?
RESPONSE
The table in question is presented in the Rosemount, Inc.,
" Operations Manual-Trip / Calibration System - Model 5100U," 1976.
This manual is referenced in NE00-21617-A. The Plant Hatch design, presented in NEDE-22154-1, does not use Rosemount trip units; GE trip units are used. However, the two trip unit designs are very similar. ,
The purpose of the maximum lead length requirement is to assure sufficient voltage out of the trip unit to drive the transn.'tter. .
Calculations by GE indicate that lead lengths as long as 3820 ft are acceptable using 16 gauge wire. The maximum length of cable used in the Plant Hatch ATTS design is 1800 ft, utilizing 16 gauge wire.
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I N._/ [] 3.A.2.e QUESTION 1-6:
Please provide the applicability of Regulatory Guide 1.75 and IEEE 279-1971 with regard to the Plant Hatch ATTS installation.
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RESPONSE: ,
The ATTS design and installation meet the standards of IEEE l 279-1971.
GPC is not committed to meet the requirements of Regulatory Guide 1.75 in the original licensing bases. However, with regard to ATTS, GPC attempted to meet Regulatory Guide 1.75 to the maximum practical extent.
.However, the ATTS installation does not completely meet Regulatory l
Guide 1.75 criteria. For example, as discussed in the Response to
, Question 1-2, there are.non-Class 1E loads being powered from Class 1E buses with a circuit breaker as the separation device. As stated i' earlier, this is consistent with the original design bases for Plant i Hatch, inasmuch as Plant Hatch is not a Regulatory Guide 1.75 plant.
- Divisional separation is maintained within the cabinet. Class 1E/non-Class 1E separation is carried through up to the trip relay.
The annunciator trip relays are the separation point between IE and non-1E; that separation is via the contact to coil separation within the relay.
Within the cabinets, the minimum separation distance is 6 in. up to the relay. Within the relay, one is limited to the distance from the contact to the coil.
The ATTS has been installed consistent with the requirements of Chapter 8 of the FSAR and 10 CFR 50, Appendix R.
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TABLE 3.1 (SHEET 10F 8)
INSTRisENT LOOP I F ORMATION Primary Sensor Engineering Existing Device New Device Trip Unit Old New Safeguard c V'riable Name(a) leL No. MPL No. MPL No. Division Manufacturer Model No. Generic Name Manufacturer Model No(. ) Associated Rack (b)
- 1) Reactor Steam Dome 821-N620 NA B21-N120 ECCS NA NA Pressure Rosemount (d) A,C-H21-P404A/B Pressure High A,8,C,0 A,8,C,0 Transmitter B.D-H21-P405A/B (ll S Aming Logic Permissive)
- 2) Low Low Set Control 821-N621* NA B21-N120 ECCS NA NA Slave NA NA NA Permissive A,B.C.D A.B.C.D
- 3) Low Low Set Control B21-N622 NA B21-N122 [0CS NA NA Pressure Rosemount (d) A,C-H21-P404A/B Pemissive A,B,C,D A,8,C,D Transmitter B.D-H21-P405A/B
- 4) Steam Tunnel B21-N623 B21-N010 821-N123 RPS Fenwall 17002-40 RTD Weed 1A00 Local Temperature High A,B C D A,B,C,D A,8,C.D Y
- 5) Steam Tunnel 821-N624 B21-N011 821-N124 RPS Fenwall 17002-40 RTD Weed 1AOD Local Temperature High A,B,C,D A,B,C,D A,B,C,D
- 6) Steam Tunnel B21-N625 821-N012 821-N125 RPS Fenwall 17002-40 RTD Need 1AOD Local Temperature High A,8,C,D A,B,C,D 1..B.C.D
- 7) Steam Tunnel 821-N626 B21-N013 821-N126 RPS Fenwall 17002-40 RTD Weed 1A00 Local Temperature High A,B C.D A,8,C D A,B,C,D
- 8) Reactor Vessel B21-N641* B21-N021 821-N090 ECCS Barton 288 Slave NA NA NA Pressure Low B,C 8,C, B,C
- 9) Reactor Vessel Steam 821-N678 B21-N023 821-N078 RPS Bartsdale B2T-M12SS Pressure Rosemount (d) A,B-H21-P404C/D Dome Pressure High A,B,C,D A,B,C D A,B,C,D Transmitter ,C D-H21-P405C/D of
- Slive trip unit.
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- a. Transmitters having the same MPL No, are the same equipment providing several trip functions.
- b. Separated for divisional conside ations.
- d. Pressure transmitter model number 1153GB8 PAN 0019.
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TABLE 3.1 (SEET 2 0F 8) '
INSTRUENT LOOP IEORMATION Primary Sensor Engineering Existing Davice New Device Trip Unit Old New Safeguard V riable Namela) WL No. WL No. WL No. Division Manufacturer Model No. Generic Name Manufacturer Model No(c) Associated Rack (b)
- 10) Reactor Vessel Steam 831-N679 831-N018 831-N079 RPS Barksdale 82T-M1255 Differential Barton 764 Local Dome Pressure Low A A A Pressure Transmitter B31-N679 B31-N018 B31-N079 RPS Static-0-R!ng SN-A33- Differential Barton 764 Local D B D (X9)STT Pressure Transmitter II) Reactor Vessel Nater 821-N680 821-N017 821-N000 RPS Barton 288A Differential Barton 764 A,8-H21-P404C/D Level Low (Level 3) A,8,C.D A,B,C,0 A,8,C,D Pressure C D-H21-P405C/D Transmitter
- 12) Reactor Vessel Water B21-N681 B21-N024** 821-N081 RPS Yamay 4418C Differential Barton 764 A,B-H21-P404C/D Level Low Low Low A,B A,8 A,8 Pressure (Level 1) Transmitter w
1 821-N681 821-N025** B21-N081 RPS Yamay 4418C Differential Barton 764 C.D-H21-P405C/D C) C,0 A,8 C,0 Pressure Transmitter
- 13) Reactor Yessel Water 821-N682* B21-N024** B21-N081 RPS Yarway 4418C Slave NA NA NA Level Low Low A,8 A,8 A,8 .
(Level 2) 821-N682* B21-N025** 821-N081 RPS Yarway 4418C Slave NA NA NA C,D A,8 C,D
, 14) Reactor Shroud B21-N685# B21-NO36 821-N085 ECCS Yarway 4418CE Differential Barton 764 A-H21-P409 Nater Level Low A,B B21-NO37 A,8 Pressure B-H21-P410 (Level 0) Transmitter
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- 15) Main Steam Line A 821-N686 B21-N006 B21-N006 RPS Barton 288 Differential Barton 764 A,B-H21-P415A/B Flow High A,8,C,D A,B,C,0 A,B.C.D Pressure C,0-H21-P425A/B Transmitter
- Slave trip unit.
- Not being deleted; only the safety function is being replaced by ATTS. Performs recirculation pump trip only.
- Provide analog output for reactor water level indication and recording.
- a. Transmitters having the same MPL No, are the same equipment providing several trip functions.
- b. Separated for divisional considerations.
TABLE 3.1 (SHEET 3 0F 8)
INSTRt#ENT LOOP IFORMATION Primary Sensor Engineering Existing Device New Device Trip Unit Old New Safeguard Yrriable Name(a) WL No. WL No. E L No. Division Manufacturer Model No. Generic Name Manufacturer Model No(c) Associated Rac
- 16) Main Steam Line B B21-N687 B21-N007 B21-N087 RPS Barton 288 Differential Barton 764 A,B-H21-P415A/B Flow High A B.C,0 A.B.C,D A,B,C,D Pressure C.D-H21-P425A/B Transmitter
- 17) Main Steam Line C B21-N688 B21-N006 821-N088 RPS Barton 288 Differential Barton 764 A,B-H21-P415A/B Flow High A B.C.D A.B.C,0 A,B,C D Pressure C,D-H21-P425A/B Transmitter *
- 18) Main Steam Line D B21-N689 B21-N009 821-N089 RPS Barton 288 Differential Barton 764 A,B-H21-P415A/B Flow High A,B,C,D A,B.C.D A,B,C,0 Pressure C D-H21-P425A/B Transmitter
- 19) Reactor Vessel B21-N690ff B21-N021 821-N090 ECCS Ba'rksdale B2T-M12SS Pressure Barton 763 A,E-H21-P404A Pressure Low A.D.E.F A D.E.F A.D.E.F Transmitter D,F-H21-P405A w
B21-N690 B21-N021 821-N090 ECCS Barton 288 Pressure Rosemount 1153GB9RJ B-H21-P410 C B,C B,C B,C Transmitter C-H21-P409
- 20) Reactor Vessel Water 821-N691f B21-NO31 821-N091 ECCS Yarway 4418C Differential Barton 764 A,C-H21-P404A Level Low Low Low A,B,C D A,B C.D A.B.C,D Pressure 8,0-H21-P405A (8.evel 1) Transmitter
- 21) Reactor Vessel Water B21-N692* B21-NO31 B21-N091 ECCS Yarway 4418C Slave NA NA NA Leval Low Low A,B,C,D A,B,C.D A,B,C D (Level 2)
- 22) Reactor Vessel Water 821-N693 B21-N017 B21-N093 ECCS Barton 288A Differential Rosemount (d) Local Level High (Level 8) A,B A,8 A,B Pressure Transmitter 821-N693* B21-N017 B21-N095 ECCS Barton 288A Slave NA NA NA C,D C,0 A,B 5' slave trip unit.
- B21-N691A,B will provide analog output for reactor water level indication and replace B21-N026A.B. B21-N691C.D will provide analog reaction water level recorder inputs and replace B21-N626C.D.
if B21-N6904,0 will provide analog input for reactor pressure recorder inputs and replace B21-N051A,B.
- a. Transmitters having the same MPL No. are the same equipment providing several trip functions.
- b. Separated for divisional considerations.
- d. Pressure transmitter model number 1153DB4PA
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INSTRUENT LOOP INFORMATION Primary Sensor Engineering Existing Device New Device Trip Unit Old New Safeguard Variable Name(a) WL No. MPL No. WL No. Ofvision Manufacturer Model No. Generic Name Manufacturer Model No(c) Associated Rac
- 23) Reactor Vessel Nater 821-N695 821-N042 B21-N095 ECCS Yarway 4418C Differential Barton 764 A-H21-P4048 Level Low (Level 3) A,8 A,8 A,8 Pressure 8-H21-P4058 Transmitter
- 24) Drywell Pressure C71-N650 C71-N002 C71-N050 RPS Static-0-Ring 12N-884-NX Differential Barton 764 Local High A,8,C D A,8,C D A,8,C,0 Pressure Transmitter
- 25) RHR Pump Discharge E11-N655 E11-N016 E11-N055 ECCS Ba.-ksdale 82T-M12SS Pressure Barton 763 Local Pressure High A,C A,C A,C Transmitter E11-N655 E11-N016 E11-N055 ECCS Static-0-Ring SN-AA3- Pressure Barton 763 Local 8,D 8,D 8,0 (X10)SITT Transmitter y 26) RHR Pump Discharge E11-N656 E11-N020 E11-N056 ECCS Barksdale 82T-M12SS Pressure Barton 763 Local Pressure High AC A,C A,C .
Transmitter to E11-N656 E11-N020 E11-N056 ECCS Static-0-Ring SN-AA3- Pressure Barton 763 Local 8,0 8,0 8,0 (X10)SITT Transmitter
- 27) RHR Pump Flow E11-N682 E11-N021 E11-N082 ECCS Barton 289 Differential Barton 764 Local Low A,8 A,8 A,8 Pressure Transattter
- 28) Drywell Pressure E11-N694 E11-N010 E11-N094 ECCS Static-0-Ring 12N-AAS- Differential Barton 764 Local High A,8,C,0 A,8,C,0 A,8,C,0 (X9)TT Pressure Transsitter E11-N011f A,8,C,D
- 29) Core Spray Pump E21-N651 E21-N006 E21-N051 ECCS Barton 289 Differential Barton 764 Local Discharge Flow Low A,8 A,8 A,8 Pressure Transmitter
- Deleted from plant. Functions of E11-N011 A,8,C,D assigned to E11-N010A,8,C.D.
- a. Transmitters having the same W L No are the same equipment providing several trip functions.
- b. Separated for divisional considerations,
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d TABLE 3.1 (SHEET 5 0F 8)
INSTRUMENT LOOP INFORMATION ,
Primary Sensor Engineering Existing Device New Device Trip Unit Old New Safegdard Variable Name(a) et go, yL No. WL No. Division Manufacturer Model No. Generic Name Manufacturer Model No(C) Associated Rack
- 30) Core Spray Pump E21-N652 E21-N009 E21-N052 ECCS Barksdale B2T-M12SS Pressure Barton 763 Local Discharge Pressure A,8 A,8 A,8 Transmitter High *
- 31) Core Spray Pump E21-N655 E21-N008 E21-N055 ECCS Static-0-Ring SM-AA3- Pressure Barton 763 Local Discharge Pressure A,5 A,B A,8 (X10)SITT Transmitter High
- 32) HPCI Pump E41-N650 E41-N027 E41-N050 ECCS Barksdale B2T-M12SS Pressure Barton 763 H21-P414B Pressure High Transmitter
- 33) HPCI Pisup E41-N651 E41-N006 E41-N051 ECCS Barton 288 Differential Barton 764 H21-P414A Discharge Flow Pressure High Transmitter Y 34) HPCI Pump E41-N6538 E41-N010 E41-N053 ECCS Static-0-Ring 6N-AA21- Differential Barton 764 H21-P414B C Suction E41-N654* E41-N010 E41-N053 ECCS (X9)VSTT Pressure Pressure Low Transmitter Static-0-Ring 6N-AA21- Slave NA + NA (X9)VSTT
- 35) HPCI Turbine Exhaust E41-N655 E41-N012 E41-N055 ECCS Static-0-Ring 6N-AA2- Differential Barton 764 A C-H21-P434 Diaphragm Pressure A.B.C.D A.B.C.D A,B,C.D (X10)-SITT Pressure B,D-H21-P414A High Transmitter -
- 36) HPCI Turbine Exhaust E41-N656 E41-N017 E41-N056 ECCS Static-0-Ring SN-AA3- Pressure Barton 763 H21-P4148 Pressure High B,D A,B, B,0 (X10)SITT Transmitter
Differential Barton 764 A-H21-P016 Differential Pressure A,8 E41-N005, A,8 Pressure B-H21-P036 High (+) Transmitter .
- Slave trip unit.
- E41-N654 is a slave trip unit from E41-N653 and provides an alarm function.
- a. Transmitters having the same N L No. are the same equipment providing several trip functions,
- b. Separated for divisional considerations.
i O O O TABLE 3.1 (SHEET 6 0F 8) ,
INSTRUIENT LOOP INFORMATION -
t Primary Sensor Engineering Existing Device New Device
- ~
Trip Unit Old New Safeguard Variable Name(a) WL No. MPL No. WL No. Division Manufacturer Model No. Generic Name Manufacturer Model No(c) Associated Rack
- 38) HPCI Steam Supply E41-N658 E41-N001 E41-N058 ECCS Bartsdale 82T-M12SS Pressure Barton 763 A.C-H21-P016 Pressure Low A,B,C.D A.B.C,0 A,B,C.D Transmitter B,D-H21-P036
- 39) HPCI Steam Line E41-N660* E41-N004 E41-N057 ECCS Barton 288 Slave NA NA NA Differential A,8 E41-N005 A,8 .
Pressure High (-)
- 40) HPCI Torus , Water E41-N662 E41-N015 E41-N062 ECCS Robertshaw 83842-A2 Capillary Barton 764 with Local Level High BD A,B B,D Differential Model 352 Pressure Capillary Transmitter Sensors
- 41) HPCI Equipment , E41-N670 E41-NO30** E41-N070 ECCS Pyco N145C3224P1 RTD Weed 1AOD Local w Ambient Temperature A,B A,8 A,8 Type T
.' High
- 42) HPCI Pipe Room E41-N671 E41-N046** E41-N071 ECCS Pyco N145C3224P1 RTD ' Weed 1A00, Local Ambient Temperature A,8 A,8 A,8 Type T High
- 43) RCIC Pump Discharge E51-N650 E51-N020 E51-N050 ECCS Bartsdale B2T-M12SS Pressure Barton 763 H21-P417B Pressure High -
Transmitter
- 44) RCIC Pump Flow E51-N651 E51-N002 E51-N051 ECCS Barton 289 Differential Barton 764 H21-P417A High Pressure Transmitter
- 45) RCIC Turbine Exhaust E51-N656 E51-N009 E51-N056 ECCS Bartsdale D2H-190SS Pressure Barton 763 H21-P417B Pressure High A,C A,B A,C Transmitter .
- 46) RCIC Steam Line E51-N657 E51-N017 E51-N057 ECCS Barton 288 Differential Barton 764 A-H21-P035 AP High (+) A,8 E51-N018 A,8 Pressure B-H21-P038 T.ansritter
- Slave trip unit.
- N6t being deleted; the safety function is being replaced by ATTS, only the alarm function will be retained.
- a. Transmitters having the same IPL No. are the same equipment provi[fing several trip functions.
- b. Separated for divisional considerations.
f
. I
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& i -
TABLE 3.1 (SHEET 7 0F 8)
INSTRUMENT LOOP INFORMATION 3
Primary' Sensor Engineering Existing Device New Device Trip Unit Old New Safeguard c Variable Name(a) WL No._ MPL No. ML No. Division Manufacturer _Model No. Generic Name Manufacturer Model No(. ) Associated Rack (b
- P High (-) A,8 E51-N018 A,8
Ambient Temperature A,8 A,B A,8 Type T High j 50) Torus Ambient . E51-N663 E51-N026** E51-N063 ECCS Pyco N145C3224P1 RTD Weed 1A00 Local j Temperature (no trip) A,B C.D A,B,C,D A,B,C,D Type T
~
i E51-N664 E51-N027** E51-N064 ECCS Pyco W145C3224P1 RTD Weed 1AOD Local l A.B.C.D A,B,C,0 A,B,C.D Type T i
- 51) Jorus Ambient E51-N666 E51-N025** E51-N066 ECCS Pyco N145C3224P1 RTD Weed 1AOD Local Temperature High A.B.C.D A,B,C.D A,B,C,D Type T Y 52) Torus Differential E51-N665 E51-N604** NA ECCS Transmation 630A RTD NA NA NA g Temperature High A,B.C.D A,B.C.D , t
- 53) RCIC Pimp Suction E51-N683 E51-N006 E51-N083 ECCS Static-0-Ring 6N-AA21- Differential Barton 764 H"I-P8'78 Pressure Low (X9)VSTT Pressure Transmitter
! E51-N684* E51-N006 E51-N083 ECCS Static-0-Ring 6N-AA21- Slave NA NA NA I (X9)VSTT
! 54) RCIC Turbine Exhaust E51-N685 E51-N012 E51-N085 ECCS Static-0-Ring 12NN-AAS-M4 Differential Barton 764 A,C-H21-P417A
- Diaphragm Pressure A.B.C.D A.B.C.D A,B,C D Pressure B,D-H21-P437 High Transmitter
, Inlet (no trip) A.E.D,H, A,B,C.D, A.E.D.H. Type T
. J,M J,M 3 . G31-N022 RPS Pyco N145C3224P1 RTD Weed IA00 Local l E,F Type T l
- Slave trip unit.
- Not being deleted; only the safety function being replaced by ATTS. Alarm function only,
- s. Transmitters having the same NL No. are the same equipment providing several trip functions.
l b. Separated for divisional considerations,
- c. The complete RTD model number for all present RTD applications is I A00/611 1B-C-6-C-2-A2-0.
g .
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TABLE 3.1 (SHEET 8 0F 8)
INSTRUMENT LOOP INFORMATION Primary Sensor Engineering Existing Device New Device Trip Unft Old New Safeguard c V~ariable Name(a) WL No. WL No. WL No. Division Manufacturer Model No. Generic Name Manufacturer Model No(. ) Associated Rack
- 56) RWCU Area Ventilation G31-N663 G31-N602** NA RPS Transmation 630A NA NA NA NA Di fferential A.E.D,H, B,C,0,E, Temperature High J,M A,F
. Ambient Temperature A.E.D,H, A,B.C.D. A.E.D H. Type T High J.M G31-N023 J,M ,
E.F G31-N016**
8,C.D.E.
A,F
- 58) Low Low Set Aming NA NA B21-N302A ECCS NA NA Pressure PCI A17-IP Local Logic Pennissive B21-N302B Switch
~821-N302C B21-N3020 w B21-N302E 821-N302F 5 B21-N302G B21-N302H B21-N302J B21-N302K B21-N302L
- 59) Low Low Set Aming NA B21-N301A B21-N301A ECCS PCI A17-IP Pressure PCI A17-IP Local Logic Pemissive B21-N301B B21-N301B Switch B21-N301C B21-N301C B21-N3010 B21-N301D B21-N301E B21-N301E B21-N301F B21-N301F B21-N301G B21-N301G B21-N301H B21-N301H B21-N301J B21-N301J B21-N301K B21-N301K B21-N301L B21-N301L Not being deleted; only the safety function is being replaced by ATTS. Alam fur.ction only,
- a. Transmitters having the same MPL No. are the same equipment having several trip settings.
b.. Separate 1 for divisional considerations,
t i TABLE 3.2 w/
CORRELATION BETWEEN EQUIPMENT AND MOUNTING LOCATIONS (For Use With Seismic Figures 3.9 through 3.21)
Description Location Figure
- 1) Cabinets H11-P921 Main Control Room - el 164 ft-3.18, 3.19 to H11-P928
- 2) Racks MPL No.
a) H21-P402 Reactor Building - el 158 ft 3.15, 3.16, 3.17 ,
b) H21-P404 A-D Reactor Building - el 158 ft 3.15, 3.16, 3.17 c) H21-P405 A-D Reactor Building - el 158 ft 3.15, 3.16, 3.17 d) H21-P409 Reactor Building el 130 ft 3.12, 3.13, 3.14 e) H21-P410 Reactor Building - el 130 ft 3.12, 3.13, 3.14 f) H21-P414 A/B Reactor Building - el 87 ft 3.9, 3.10, 3.11 (HPCI Room) -
b V g) H21-P415 A/B Reactor Building - el 130 ft 3.12, 3.13, 3.14 h) H21-P016 (Wall) Reactor Building - el 130 ft 3.15*, 3.16*, 3.17*
- 1) H21-P417 A/B Reactor Building - el 87 ft 3.9, 3.10, 3.11 (RCIC Corner Room) j) H21-P425 A/B Reactor Building - el 130 ft 3.12, 3.13, 3.14 k) H21-P434(Wall) Reactor Building - el 87 ft 3.12*, 3.13*, 3.14*
(HPCI Room)
- 1) H21-P035 (Wall) Reactor Building - el 130 ft 3.15*, 3.16*, 3.17*
m) H21-P036 (Wall) Reactor Building - el 130 ft 3.15*, 3.16*, 3.17*
n) H21-P437 (Wall) Reactor Building - el 87 ft 3.12*, 3.13*, 3.14*
(RCIC Corner Room) o) H21-P038(Wall) Reactor Building - el 130 ft 3.15*, 3.18*, 3.17*
- 3) Pressure Switches, Use Multiple Locations-Plant 3.20, 3.21 RTDs Hatch Spectrum Peak Envelope Curves
- 4) Locally Mounted Use Multiple Locations - Plant 3.20, 3.21
\- - Transmitters Hatch Spectrum Paak Envelope Curves
~
- The next higher elevation seismic curves should be used for the wall racks.
3-17
A O u O-FIGURE 3.1 ASSIGNED TRIP UNIT LOCATIONS IN ECCS CARD FILES FOR CABINET H11-P925(d) 1 2 3 4 5 6 7 8 9 10 11 12 E51-N658A(a) E51-N658C E51-N657A E51-N660A E51-N685A E51-N685C E51-N656A E51-N656C E51-N651 E51-N684 E51-N683 E51-N650 E51-N058A(b) E51-N058C E51-N057A SLAVE E51-M085A E51-NOBSC E51-N056A E51-N056C E51-N051 SLAVE E51-N083 E51-N050 RCIC STM LNIC) RCIC STM LN RCIC STM LN RCIC STM LN RCIC TB EX RCIC TB EX RCIC TB EX RCIC TB EX RCIC PtSF RCIC PtBF RCIC PU W RCIC PUW LO PR LO PR HI AP(+) HI AP(-) DIA HI PR DIA HI PR HI PR HI PR HI FLOW LO Pk ALARM SUC LOW PR HI PR E41-N658A(a) E41-N658C E41-N657A E41-N660A E41-N655A E41-N655C B21-N620A B21-N621A B21-N622A E41-N058A(b) E41-N058C E41-N057A SLAVE E41-N055A E41-N055C B21-N120A SLAVE B21-N1224 HPCI STM LNI C) WCI STM LN HPCI STM LN HPCI STM LN HPCI TB EX HPCI TB EX LLS AMING LLS LLS LO PR LO PR HI A P(+) HI A P(-) DIA HI PR DIA HI PR LOGIC PERM CONTROL CONTROL PERM PERN B21-N691A(a) 521-N692A B21-N693A B21-N691C B21-N692C B21-N693C B21-N695A B21-N685A E11-N682A B21-N620C B21-N621C '82T-N622C B21-N091A(b) SLAVE B21-N093A B21-N091C- SLAVE SLAVE B21-N095A B21-N005A E11-N062A B21-N120C SLAVE B21-N122C WTR LYL llc) WTR LYL 2 WTR LVL 8 WTR LVL 1 WTR LVL 2 WTR LVL 8 WTR LVL 3 WTR LVL 0 RNR PU W A/C LLS AMING LLS LLS '
CS/A05/RHR HPCI/RCIC RCIC CS/ ADS /RNR HPCI/RCIC RCIC ADS RHR LO FLOW LOGIC PERM CONTROL CONTROL DIESEL DIESEL
- PEM PEM Y -
5 a. Trip unit pW'l No. *
- b. Sensor MPL No.
- c. Loop function.
- d. Blank spaces denote empty file slots.
e
1 p 7"N U V -
U .
FIGURE 3.2(a)
ASSIGNED TRIP UNIT LOCA,TIONS IN ECCS CARD FILES FOR CABINET H11-P926(b) 1- 2 3 4 5 6 7 8 9 10 11
'1 12 E51-N6588 E51-N6580 E51-N6578 E51-N6608 E51-N6858 E51-N6850 E41-N6568 E41-N6560 E41-N651 E41-M654 E41-N653 E41-N650 I E51-N058B E51-N058D E51-M0578 SLAVE E51-N0858 E51-N0850 E41-N0568 E41-NC560 E41-N051 SLAVE E41-N053 E41-N050 RCIC STM LN RCIC STM LN RCIC STM LN RCIC STM LN RCIC TB EX RCIC TB EX HPCI TB EX IFCI T3 EX HPCI PI W HPCI Pt9F HPCI Ptw HPCI PUW LO PR L0 PR HI AP(+) HI A P(-) DIA HI PR DIA HI PR HI PR HI PR HI FLOW L0 PR ALARM SUC PR SUC PR l
l E41-N6588 E41-N6580 E41-M6578 E41-N6608 E41-N6558 E41-N6550 E41-N6628 E41-N6620 B21-N620B N21-N6218 B21-N6628 E41-N0588 E41-N058D E41-N0573 SLAVE E41-N055B E41-N0550 E41-N0628 E41-N062D B21-N1208 SLAVE B21-N1228 j HPCI STM LN HPCI STM LN HPCI STM LN HPCI STM LN HPCI TB EX HPCI TB EX HPCI TORUS HPCI TORUS LLS ARMING LLS LLS l LO PR LO PR HI A P(+) HIAP(-) DIA HI PR DIA HI PR HI WTR LVL HI WTR LVL LOCIC PERM CONTROL CONTROL i PERM PERM 1
B21-N6918 B21-N692B B21-M6938 821-N691D B21-N6920 821-N693D B21-N6958 B21-N6858 E11-N682B B21-N620D l B21-N621D B21-N622D B21-N0918 SLAVE B21-N0938 821-N091D SLAVE SLAVE B21-N0958 B21-N0858 E11-N0828 821-N120D SLAVE B21-N1220 WTR LVL 1 WTR LYL 2 WTR LVL 8 WTR LYL 1 WTR LVL 2 WTR LM. 8 WTR LVL 3 WTR LYL 0 RHR PUMP 8/D LLS ARMING LLS LLE
- CS/ ADS /RHR WCI/RCIC HPCI CS/ ADS /RHR HPCI/RCIC HPCI ADS RHR LO FLOW LOGIC PERM CONTROL CONTROL DIESEL DIESEL PERM PERM I
W 7 b a. See figure 3.1 for description of nomenclature.
j
- b. Blank spaces denote empty flie slots.
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,a
\
FIGURE 3.3(a)
ASSIGNED TRIP UNIT LOCATIONS IN ECCS CARO FILES FOR CABINET' H11-P927(b) 1 .2 3 4 5 6 7 8 9 10 11 12 E11-N655A E11-N655C E11-N656A E11-N656C E11-N694A E11-N694C B21-N690A
- 821-N690C B21-N641C B21-N690E E11-N055A E11-N055C E11-N056A E11-M056C E11-N094A E11-N094C 521-N0904 B21-N090C SLA E 821-N090E RHR PtMP A RHR PtMP C RHR PUMP A RHR PUMP C OR M LL DR M LL E SSEL ESSEL E SSEL ESSEL HI PR HI PR HI PR HI PR HI PR HI PR LO PR L0 PR L0 PR LO PR l E21-N651A E21-N655A E21-N652A E51-N663A E51-N664A E51-N665A E51-N663C E51-N664C E51-N665C l E21-N051A E21-N05fA E21-N052A E51-N063A E51-N064A NA E51-N063C E51-N064C NA i CS PtMP A CS PUNP A CS PUW A RCIC TORUS RCIC TORUS HPCI TORUS LO FLON HI PR HI PR M LO(NT)fCI M LO(NT)(c) RCIC HI AT TORUS HPCI TORUS M LO(NT) HPCI M LO(NT)(c)
TORUS HI (C)AT E41-N670A E41-N671A E51-N661A E51-N666A E51-N666C E41-M070A E41-N071A E51-N061A E51-N066A E51-N066C j HPCI EQUIP HPCI PIPE RM RCIC EQUIP RCIC TORUS NPCI TORUS M HI TW M HI T W M HITW M HI TW M HI TW *
- a. See figure 3.1 for description of nemenclature. .
o b. Blank spaces denote empty file slots.
- c. (NT) denotes instrument with no trip function.
(
[
O O O FIGURE 3.4(a) ,
ASSIGNED TRIP Uu!T LOCATIONS IN ECCS CARD FILES FOR CABluET N11-P92B(b)
~
1 2 3 4 5 6 7 3 9 10 11 12 E11-M 558 E11-u6550 E11-W568 E11-le6560 E11-uS948 E11-u6940 821-186908 321-u6415 521-uG900 821-II690F E11-u0555 E11-u0550 E11-uG568 E11-uG560 E11-u0948 E11-u0940 821-u0908 SLAK B21-u0900 821-N090F RNR Pter 5 RHR PtMP D RHR Pier B RNR Pt9F 0 OR M LL DRMLL W SSEL E SSEL E SSEL M 5SEL HI PR HI PR HI PR HI PR HI PR HI PR LO PR LO PR LO PR L0 PR E21-56515 E21-II6558 E21-II6523 E51-II6638 E51-u664B E51-u6658 E51-u6630 E51-N6640 E51-u6650 E21-uD513 E21-uG558 E21-u0523 E51-uG63B E51-uG648 18A E51-uG630 E51-uG640 NA C5 Pier B C5 PtBF 3 C5 Pter B K IC T0ANS KIC 70AUS RCIC TORUS HPCI T0AUS HPCI TORUS LO FL(nr NI PR HI PR ApS LO(UT)(CI M HI(UT)(c) HI AT HPCI AfS TORUS LO(UT) (c) Af8 HI(NT)(C)
HI AT E41-uS708 E41-u6715 E51-u661B E51-Il6665 E51-u6660 E41-uG708 E41-uG713 E51-u0618 E51-IID665 E51-u0660 IFCI EQUIP IFCI PIPE RM RCIC EQUIP RCIC TORUS HPCI T0AUS JWS HI TIF Age HI TIF ApS HI Tpr AIS HI TIF ApS HI TIF
- c. See rigure 3.1 for description of nomenclature.
~ b. Blanit spaces denote empty file slots.
c- (MT) denotes f astrument with no trip function.
6
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's. . (_)
FIGURE 3.5(a)
ASSIGNED TRIP Wu!T LOCATIONS IN WS CAAD FILES FOR CASINET N11-P921(LI 1 2 3 4 5 6 7 8 9 10 11 12 521-u606A B21-3687A B21-M68AA b21-II68 % B21-u6004 B21-RESIA B21-u682A B21-le67 M B31-Is57 M C71-N6504 B21-N0064 521-aOSIA B21-uGA M B21-300M B21-u0004 521-N001A SLAVE B21-u0784 B31-N07M C71-50504 888 ST LE A set ST LN B NI ST LN C fel ST LN 0 WTR LVL 3 WTR L E 1 WTR LE 2' WSSEL ESSEL BRVELL RI FLOW HI FLOW NI FLOW NI FLOW RPS IISIV ISOL HI PR L0 PR MI PR 321-uS23A B21-II624A B21-II625A B21-se626A B21-51234 521-N124A B21-5125A 521-N126A STN TINIII STN Tigel STN Tisal STN TUIIN NI Tar NI TIF NI TIF HI Tpr G31-II661 A G31-II662A G31-II6634 G31-le661E G31-le662E G31-II663E G31-le661J G31-le662J G31-le663J G31-IID61A G31-IIO62A 10 4 G31-IID61E G31-IIO62E IIA G31-IIO61J G31-u062J lea RWCU RN I RWCU NI OUT RWCU 4AEA RMCU Nt Ig RMCU NI OUT RMCU AAEA RWCU NI 15 RWCU 158 OUT RWCU AREA 19FluT)(C Ape NI TIF HI AT TIF(NTIICI AIS NI TIF NI AT TIr[NT)(C) afb HI'Tpr NI AT Y
m o. See figure 3.1 for descriptise of somenclature.
" b. Blank spaces denote enyty file slots-c- (NT) denotes lastrument with no trip functice.
S G
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Y O O O FIG N 3.6I4)
. ASSIGIED TRIP UNIT LOCATICES IN M CAaB FILES FOR CABIET nil-P922(b) 1 2 3 4 5 6 7 8 9 10 11 12 321-a686B B21-u6373 B21-56a03 321-56893 B21-56003 B21-5681B B21-uGB2B B21-5670B C71-uG50B B21-30368 B21-a0875 521 4 :? B21-50393 321-30B05 321-30818 SLAN 821-5878B C71-505W pel ST LE A lel ST Lu 8 pel ST La C let ST LN 3 WRLE3 Et LE 1 WE LE 2
- K 55EL BETELL MI FLOW NI FLOW NI FLOW NI FLOW BPS 8tSIV ISOL NI PR NI PR 321-5623B 321-3624B 321-m6258 B21-116268 321-5123B B21-5124B B21-51258 321-N126B 5118 Tuus $191 T1558 5191 TIABI STN TuuN WI W NI W NI W NI W f
l
- c. See figure 3.1 for descriptfee of esmeeciatore,
- b. Blank speces denote empty flie sists.
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, , FIGURE 3.7(a)
ASSIGNED TRIP UNIT LOCATIDNS IN RPS CARD FILES FOR CABINET H11-P923(b) 1 2 3 4 5 6 7 8 9 10 11 12 B21-N686C B21-N687C B21-N688C B21-N689C B21-N680C B21-N681C B21-N682C B21-N678C C71-N650C B21-N086C B21-N087C B21-N08SC B21-N089C B21-N000C B21-NOBlC SLAVE B21-N078C C71-N050C
HI FLOW HI FLOW HI FLOW HI FLOW RPS MSIV ISOL HI PR HI PR l
h
' _, B21-N623C B21-N624C B21-N625C B21-N626C
/- B21-N123C 821-N124C B21-N125C B21-N126C 0 STM TUNN- STM TUNN 3 ,
,e -
,/ r x
- a. See figure 3.1 for description of nomencthture.
i y b. Blank spaces denote empty file slots.
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FIGURE 3.8(a)
ASSIGNED TRIP UNIT LOCATIONS IN RPS CARD FILES FOR CABINET H11-P924(b) 1 2 3 4 5 6 7 8 9 'O 11 12 B21-N686D B21-N687D B21-N6880 821-N6890 B21-N6800 821-N681D B21-N682D B21-N678D B31-N679D C71-N650D
- B21-N0060 821-N087D B21-N0880 B21-N0890 B21-N0800 B21-N081D SLAYE B21-N0780 B31-N0790 C71-N050D
^
MN ST LN A MN ST LN 8 MN ST LN C MN ST LN D WTR LVL 3 WTR LYL 1 WTR LYL 2 VESSEL VESSEL DRYWELL HI FLOW HI FLOW HI FLOW HI FLOW RPS MSIV iSOL HI PR LO PR HI PR B21-N6230 B21-N624D 821-N625D B21-N6260 B21-N123D B21-N1240 B21-N125D B21-N126D STM TUNN STM TUNN STM TUNN STM TUNN HI TMP HI TW HI TMP HI TMP G31-N661D G31-N662D G31-N6630 G31-N661H G31-N662H G31-N663H G31-N661M G31-N662M G31-N663M G31-N061D G31-N062D NA G31-N061H G31-N062H NA G31-N061M G31-N062M NA RWCU RM IN RWCU RM OUT RWCU AREA RWCU RM OUT RWCU AREA RWCU RM IW RWCU RM OUT RWCU AREA i
TMP(NT)(c) AMB HI TMP HI AT RWCU TW(NT) RM(c)IW ape HI TW HI AT TW(NT)ICI AMB HI TW HI AT 1
Y y a. See figure 3.1 for description of nomenclature.
- b. Blank spaces denotes empty file slots.
3
- c. (NT) denotes instrument with no trip function.
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t i V V V FIGURE 3.25 BASIC CABLE ARRANGEMENT & SEPARATION LAYOUT FOR PLANT HATCH ATTS CONTROL ROOM ECCS ECCS RPS RPS DIV I DIV II 1 A ( A), 18 (8),
SATTERY BATTERY 2A (C) 28 (D)
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_ _ __ __ _ -- l
I i 38. BASES FOR TECHNICAL SPECIFICATIONS REVISIONS FOR ATTS EQUIPMENT (a)
G '
With the incorporation of ATTS into the HNP-1 design, two types of Technical Specifications revisions are desirable:
e Nomenclature changes e Modifications to the surveillance frequency of ATTS equipment.
The bases for the Technical Specifications changes over and above these ATTS changes are included in Section IV.
38.1 The bases for these changes are as follows:
38.1.a Nomenclature Changes to the Technical Specifications The installation of ATTS replaces mechanical switches with trans-mitters. In the past, the Technical Specifications identified the
. switches as such under the instrument description. Therefore, the Technical Specifications require a revision to reflect this change.
Additional changes which are purely administrative in nature have been made to correct minor errors and to improve the readability of the .
Technical Specifications.
38.1.b Modifications of the Surveillance Frequency U As evidenced by NED0-21617-A, the NRC previously approved the following surveillance frequencies for ATTS equipment:
e Once per shift for channel check e Once per month for channel functional test -
e Once per operating cycle for channel calibration.
The revisions contained in the enclosed proposed changes to the Technical Specifications reflect the above surveillance frequencies.
Additional bases for the surveillance frequency revisions are con-tained within Chapter 6 of NEDE-22154-1 (contained in Reference 15).
38.2 The proposed . Technical Specifications revisions illustrated in this submittal are the revisions that will be incorporated into the Plant Hatch-Unit 1 system through the next refueling outage. GPC will apprise the NRC of the expected work scope to be completed and the desired implementation of the proposed Technical Specifications changes.
(x a. See Appendix 1 (page Al-2) for an 10 CFR 50.92 evaluation of the proposed changes to the Technical Specifications Surveillance requirements.
~
3-40 _
3C.
SUMMARY
From the preceding discussions, it may be concluded that the proposed
- incorporation of_the ATTS equipment into the Plant Hatch design and the proposed nomenclature and surveillance requirement changes to the.
Technical Specifications do not introduce an unreviewed safety ques-tion or a significant hazards consideration. These proposed changes take advantage of the sensor improvements for this new equipment.
O O
3-41
/~~ IV. ' PROPOSED PLANT MODIFICATIONS TO BE INCORPORATED INTO THE ATTS DESIGN
(_N) 4A. INTRODUCTION Section IV provides the bases for the proposed Technical Specifica-tions. revisions, in addition to an overview of the evaluation per-formed to conclude that the proposed modifications constitute neither an unreviewed safety question, nor a significant hazards consideration. This section covers the Hatch 1 ATTS equipment items which are scheduled for installation during the 1984 refueling outage.
Within this section three values are discussed: the analytical limit, the trip setpoint/ allowable value, and the trip setpoint.
A discussion on these values and their determination is presented below.
4A.1 Setpoint Methodolgy The methodology which was used to generate the setpoints is detailed in Attachment 3 of Reference 16.
~
4A.1.a Analytical Limits The analytical limits are the values used as inputs to the safety analysis in the FSAR. For Plant Hatch, the analytical limits were
(~N selected to prevent violation of the applicable safety limits. For
\ml example, the analytical limit for the level I reactor water level trip -
was selected to prevent fuel cladding temperatures in excess of the peak value (2200 F) used in the Plant Hatch Appendix K LOCA analyses.
In some cases values were not used directly in the FSAR analysis. In those cases where an analytical limit was not available, engineering judgement or historical data was justified and used.
Unless otherwise noted, the analytical limits used in the setpoint calculations for this submittal were the original analytical limits used in the HNP Safety Analysis. For those that were changed, a safety evaluation is provided that justifies the change to that analytical limit. In no case with these new limits do the FSAR analyzed transients or accidents exceed the safety limits which are specified in the Plant Hatch Technical Specifications.-
The conservatisms in the Plant Hatch design basis computer codes were not used in place of the analytical limit for the starting value of the calculations.
4A.1.b Allowable Value and Trip Setpoint Determinations The allowable value was obtainined by either adding or subtracting (whichever was conservative) the Igop accuracy from the analytical limit. The loop accuracy was obtained by taking the square
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root-of-the-sum-of-the squares of the transmitter accuracy, the trip unit accuracy, and the calibration accuracy. The trip setpoint was O
. 4-1 -
a_--_-____-_-_-_____-____
w (7 calculated by adding or subtracting (whichever was used to obtain the C) allowable value) the loop drift and the leave-alone range from the allowable value.
Each of these terms is a function of other parameters; for instance, the transmitter accuracy reflects transmitter performance with regard to the transmitter temperature specifications, power supply specifications, and static pressure specifications. Trip unit accuracy is basic reference accuracy. Calibration accuracy consists of the accuracy of applying pressure to the transmitter and measuring its electrical output error band. Thus, trip unit calibration accuracy is a function of the ATTS calibration units and the readout used to adjust the trip setpoints. What we refer to as loop accuracy is developed by taking the square root-of-the-sum-of-the squares of all the terms. These parameters envelope the Plant Hatch, Unit 1 ,
requirements.
The transmitter, trip unit, and calibration accuracies are all treated as independent variables between the analytical limit and allowable value. The transmitter and trip unit drifts were treated as independent variables between the allowable value and trip setpoint.
The total loop accuracies and the total loop drifts were directly added to obtain the trip setpoint and were, therefore, treated as-dependent variables.
An additional variable called the leave-alone band was added (treated -
I as a dependent variable) between the allowable value and trip G setpoint. This band is set at 3 0.25 percent of the trip unit range and allows a range of values that the trip unit may vary. A setpoint adjustment is not required when the trip unit setting is within this t 0.25 percent range. If the trip unit is out of the leave-alone band on a monthly calibration functional test, the operator resets the trip unit trip setpoint within the 0.25 percent range. Currently, if the trip unit setting is more than 1 0.60 percent (sum of leave-alone range + trip unit drift) from the specified setpoint, a deficiency report will be generated internally at GPC Plant Hatch.
The only value extrapolated was setpoint drift. In many cases the transmitter manufacturer's specifications only provided drift values for 6- or 12-month intervals. These values were extrapolated linearly to provide 18- and 24-month drift values for use in the Plant Hatch setpoint calculations. Ongoing vendor test programs demonstrate that linear extrapolation is a conservative approach.
Drift of the trip units will be monitored on a monthly basis, and drift of the transmitters will be monitored on an operating cycle basis using plant procedures. After two operating cycles, GPC will evaluate the performance of these trip units and transmitters against the manufacturer's published specifications. At that time, if necessary, GPC will propose modifications to the surveillance frequencies specified in the Unit 1 Technical Specifications based upon this performance.
V(3 4-2
7 e
j-'3 4A.1.c Harsh Environment Considerations U The temperature effects for a harsh environment were explicitly used as one of the variables to determine transmitter accuracy for each loop. The data used were obtained directly from the transmitter performance specifications. No extrapolations were required. The manufacturer's performance specifications envelope the Plant Hatch calculated harsh environment profiles.
The two areas explicitly considered in the harsh environment effects were radiation and temperature compensation. These were considered as independent effects. The reasoning that they are independent effects is that temperature peaks relatively early in a LOCA event while significant radiation integrated doses occur later. As a result of a GE evaluation for Barton transmitters, it was determined that radiation effects were not significant in the setpoint calculations.
Therefore, the setpoint calculations did not explicitly consider radiation as a parameter. SCS performed an evaluation which allowed exclusion of the radiation effect also for those functions where Rosemount transmitters are to be installed.
Humidity was not an explicit parameter in the setpoint calculations.
The testing program for the transmitters included exposure to a steam environment during the DBE/ post-DBE testing phases. Therefore, the effects of humidity are accounted for in the temperature compensation factor. -
p i,,)'
s 4A.1.d Human Factors Consideratons No component of error for the man-to-machine interface was included in the setpoint calculations; however, there is a requirement that calibration be performed with instruments of 1/4 percent or better accuracy. This value was assumed in the setpoint calculations.
During monthly channel functionaT tests, the trip setpoint milliampere value is read directly from the calibration unit. The calibration unit locks in the trip setpoint value and presents a digital display.
During channel calibration, the readings are taken with a digital voltmeter. At the calibration checkpoints, sufficient stability of the digital readout is achieved to assure that the human ability to read the display presents insigificant errors in the overall results of the setpoints calculations.
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4-3 L
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g.- 4B. . SAFETY EVALUATION REPORT h -
48.1 ' Low Low Set logic Design Modification (821-N620A,B,C,0; B21-N621A,B,C,D; B21-N622A,B,C,0)
The concept and justification for the low low set (LLS) logic to be *
, incorporated _into the HNP-1 design are detailed in NEDE-22223 and NEDE-22224.which are contained within Appendices 1 and 2 of Reference
- 1. Reference 1, the Hatch Nuclear Plant-Unit 2 (HNP-2) low low set submittal, was approved by the NRC on June 29, 1983.
The purpose of the LLS relief logic is to mitigate the induced loads of subsequent safety / relief valve (S/RV) actuations as identified in NUREG-0661. The LLS relief logic automatically arms the designated
_LLS S/RVs at their LLS setpoints when any S/RV opens initially and when, concurrently, the. reactor. vessel steam dome pressure exceeds the scram setpoint. After arming, the reactor vessel steam dome pressure instrumentation controls the solenoid valves so that the LLS S/RVs open and close at their assigned setpoints. Technical Speci-fications revisions are required to accurately reflect the newly designated safety function of the selected S/RVs. _However, as justi-fied in Appendices 1 and 2 of reference 1, this modification consti-tutes neither an unreviewed safety question, nor a significant haz-ards consideration. Appendix 1 (page Al-3) of this document provides the-results of the significant hazards review.
' S The proposed limiting condition for operation (LCO) requirements were developed taking into consideration _ reference 13 which is currently under NRC review. The proposed surveillance requirements were devel-oped from the ATTS requirements since the LLS instrumentation is being incorporated into the plant design as part of this system. The proposed surveillance requirements for ATTS are justified in Section III of this document.
The proposed LCO requirements are less restrictive than the LCO requirements specified in Reference 13, which assume the presence of one tailpipe pressure switch per S/RV. The new HNP-1 design incor-porates two independent tailpipe pressure switches (designed to meet single-failure criteria) per S/RV. Should one ta11 pipe pressure switch become inoperable on a low setpoint (1080 psig) S/RV, there is a second switch to support the arming of the LLS. logic should that S/RV open. If the redundant tailpipe pressure switch also fails, there are three additional S/RVs with 1080 psig setpoints, at least one of which is assumed to open with the opening of the S/RV with the failed tailpipe pressure switches. Should any one (or more) S/RV open and should any one tailpipe pressure switch sense the opening of the S/RV, the tailpipe pressure switches would have served their function in regard to the LLS logic operation. Should an S/RV with two failed switches open and no other S/RV opens concurrently, the LLS relief logic can be defeated. Figures 4.1 through 4.10 provide the engineering documents which are relevant to understanding the proposed LLS logic design modification for Unit 1..
O 4-4
e A reliability analysis was performed to predict the probability of a 1
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defeat of LLS logic to mitigate the load cases C3.2 and C3.3 (NEDC-24346). This analysis assumed that one of the two pressure
- switches of each S/RV failed and only one S/RV responded to mitigate these load cases. (There are only a small number of events under load cases C3.2 and C3.3 where the potential ' exists for only one S/RV opening. However, to be conservative it was assumed that the pro-bability of this occurrence was 1. If more than one S/RV did open, additional pressure switches would be available to arm the LLS logic.) Using WASH-1400 failure rates, it was predicted that the probability of LLS logic being defeated upon demand would be 1.97 x 10" assuming all pressure switches are operable at startup after refueling. Therefore, the proposed LCO requirements with one operable tailpipe pressure switch per S/RV are justified.
The proposed setpoints/ allowable values were developed using the criteria of Regulatory Guide 1.105, taking into considerat. ion the design basis of the system.
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ATTS ELEMENTARY DIAGRAM FIGURE 4.10 4 4.is 8409120096-O(o
t Lowered Main Steam Isolation Valve (MSIV) Water Level Trip Setpoint
~~
; 48.2
) Modification (B21-N681A,B,C,0)
The justification for the lowering of the MSIV water level trip setpoint from level 2 to level 1 is detailed in the NEDE-22223 and NEDE-22224 (Appendices 1 and 2 of Reference 1, the HNP-2 MSIV Lowered Water Level submittal approved by the NRC on June 29, 1983). The lowering of the MSIV water level trip setpoint is an additional means of mitigating the induced loads of subsequent S/RV actuations. A delayed MSIV isolation allows more steam to be released from the reactor prior to an S/RV actuation. The subsequent pressurization rate after MSIV isolation is also reduced because of the lower decay heat rate at this later time. This modification is also being implemented in response to the generic NRC evaluation of boiling water reactor (BWR) responses to feedwater transients and small-break loss-of-coolant accidents (LOCAs) documented in NUREG-0626 which concludes that the number of S/RV challenges should be reduced. For the anticipated operational transients, a lower MSIV water level trip setpoint reduces the number of S/RV challenges. This is true not only because of the extra heat removal by the main condenser but also because of the operation of high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems that may significantly lower the reactor pressure during operational transients prior to isblation. This modification lowers the isolation level of the following groups of valves from reactor vessel water level 2 to level 1: Functional Type MPL No. Main Steam Isolation Valves 821-F022A, B, C, O B21-F028A, B, C, O Main Steam Drain Isolation 821-F016 Valves 821-F019 Reactor Water Sample Line B31-F019 Isolation Valves B31-F020 The proposed Technical Specifications revisions reflect this change. However, as justified in Appendices 1 and 2 of Reference 1, this modification constitutes neither an unreviewed safety question, nor a significant hazards consideration. No surveillance frequencies are affected by this modification; and with the exception of the setpoint modification itself, the LCO remains unchanged. Appendix 1 (page Al-4) of this document provides the results of the significant hazards review. k,
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4-16
t O 48.3 Reactor Vessel Water Level - Low Low (Level 2) Trip Setpoint g b! Modification (821-N682A,B,C,0, 821-N692A,8,C,0) i The proposed Technical Specifications trip setpoint/ allowable value for the reactor vessel water level 2 signal is 2 -55 in. Reactor vessel water level 2 is for the initiation of HPCI and RCIC (821-N692A,B,C,0). With the approval of section 48.6 level 2 will also isolate reactor water cleanup and secondary containment and initiate the standby gas treatment system (821-N682A,B,C,0). Using Appendix K models, the Final Safety Analysis Report (FSAR) emer-gency core cooling system (ECCS) analysis was performed using a nominal analytical limit of -38 in, for level 2 HPCI actuation. However, the level 2 analytical limit is not a significant parameter in the Appen-dix K calculations. Therefore, as explained below, the ECCS calculations
~
are insensitive to the variation in HPCI actuation water level so that a lower level 2 has no significant effect on the ECCS performance. Sensitivity studies of the effect the level 2 analytical limit has on the ECCS analysis show that level 2 can be lowered all the way to the
- level 1 analytical limit (-152.5 in.) without affecting the results of that analysis. However, it has not been recommended that the level 2 analytical limit be lowered to -152.5 in. The proposed analytical limit of -58 in, was selected to provide the best flexibility and protective margin for the plant.
(~^ For small breaks, the limiting single failure is the HPCI failure. Even C) if HPCI is assumed operable, delaying the HPCI actuation has an insignifi-cant effect on core heatup. For the proposed change in the level 2 analytical limit to -58 in., the MAPLHGRea' limit will not be changed. The requirements of 10 CFR 100 will still be met because: e Reactor power level or inventory is not changed. e Engineering standards are not changed. e The probability of radioactive release will not be increased. The trip setpoint/ allowable value of 2 -55 in, was developed from the newly established analytical limit using the criteria of Regulatory Guide 1.105. The designated trip setpoint for the plant will take into consideration instrument drift. Therefore, this modification constitutes neither an unreviewed safety question, nor a significant hazards consideration. No surveillance frequencies are changed by this modification; and with the exception of the setpoint modification itself, the LCO remains unchanged. Appendix 1 (page Al-5) provides the results of the signift-cant hazards review. p) ( a. Maximum average planar linear heat generation rate. 4-17
3 48.4 Reactor Vessel Water Level - High (Level 8) Trip Instrumentation (V Modifications (821-N693A,B,C,0) After HPCI and RCIC have activated, this trip function prevents the water level in the reactor vessel from reaching the height of the main steam outlet. Its intended protective function is accomplished by tripping the HPCI steam turbine and the RCIC steam supply valves when the water level in the reactor vessel reaches the level 8 setting. The trip function is to protect the HPCI and RCIC steam turbine systems from potential damage. This trip function is currently assigned to instruments B21-N017A,B,C,0 which control the reactor protection system (RPS) reactor vessel water level 3 instrumentation. To separate the RPS and the ECCS functions, the ATTS design assigned the reactor vessel water level 8 trip function to the ECCS instrumentation. Since the functions of the level 8 trip remain the same, this modification constitutes neither an unreviewed safety question, nor a significant hazards consideration. Appendix 1 (page Al-6) provides the results o,f the significant hazards review. The analytical limit for this function is 59.5 in. The trip setpoint/ allowable value of s 56.5 in. was developed using the criteria of Regulatory Guide 1.105. The designated trip setpoint for the plant will take into consideration setpoint drift. O O t 4-18
)
v-48.5 RC?C/ Reactor Vessel Water Level 8 Trip Clarification The present HNP-1 Technical Specifications state that when the reactor vessel water level - high (level 8) setpoint is reached, the RCIC turbine is tripped. Design Change Request 81-158 modified the RCIC system so that a level 8 trip does not electrically trip the turbine, but closes the steam supply valves. This allows the system to automatically reset when the water level-drops below level 8, eliminating the need for manual reset of the system before the operator can take manual control over the system and avoid a fluctuating water level. The as-built notice for this change was issued on July 6, 1981. This design change did not require a revision to the Technical Spect-fications. However, to avoid misinterpretation it is proposed that the Technical Specifications be revised. The proposed modification consists of adding a note to table 3.2-3 and the Bases, for the level 8 trip, stating that the system is capable of automatic reset after a level 8 trip. Since there is no change to the RCIC system or to the level 8 trip function, this modification constitutes neither an unreviewed safety question, nor a significant hazards considera-tion. Appendix 1 (page Al-7) provides the results of the significant hazards review. m e 4 0 U 4 ~
p 48.6 Lower Water Level Trip Setpoint for Isolation of Reactor Water Cleanup V (RWCU) and Secondary Containment, and Starting of Standby Gas Treatment System (SGTS) (821-N682A,B,C,0) - Reactor scram from normal power levels (above SQ percent of rated) usually results in a reactor vessel water lwel transient due to void collapse that causes isolation of the RWCU system at reactor water level 3. The result is typically the dropping of the cleanup filter cake, added radwaste processing, loss of ability to remove water from the reactor vessel immediately after scram, and other undesirable operational problems. These results adversely affect plant availability and operability. By Icwering the isolation setpoint to reactor water level 2, these problems can be resolved without any adverse safety impact. The lowering of the level trip for isolation of RWCU from reactor water level 3 to reactor water level 2 will not have any adverse effect on plant transient and accident analysis. For any reactor pressure coolant boundary line breaks inside the primary containment, the LOCA design basis accident (OBA) analysis has shown that ECCS is capable of mitigating all break sizes up to and including the recircula-tion line break. For a RWCU line break outside the primary containment, the break detection is provided by the high differential flow, area high temperature, or area high ventilation differential temperature rather than by water level variation. By lowering the SGTS actuation and secondary containment isolation from reactor water level 3 to reactor water level 2, the potential for spurious trips is reduced. The ECCS analysis design basis assumes n) ( that SGTS will initiate at the same time as the ECCS which initiates at reactor water level 2. The secondary containment, in conjunction with the SGTS, is designed to minimize any ground level release of radio-active material which may result from an accident; therefore, secondary containment should isolate at the same level at which the SGTS is actuated. , This modification'has been implemented on other BWR/4s. The requirements of 10 CFR 100 are stil' net. These changes to the plant constitute neither an unreviewed sa .y question, nor a significant hazards consideration. Appendix 1 (page Al-8) provides the results of the significant hazards review. . I e i o i 4-20 ( -
l l 48.7 Deletion of High Drywell Pressure Signal for Residual Heat Removal (RHR) (]
'v (Shutdown Cooling Mode) and RPV Head Spray Valve High drywell pressure has been used as a signal to isolate the shutdown cooling made of RHR. Small steam leaks in the drywell may cause a high drywell pressure signal which prohibits an acceptable normal shutdown procedure by preventing operation of the RHR system during the shut-down cooling mWe. To resolve this operational and safety concern, the high drywell pressure signal would be deleted from the isolation logic for the RHR shutdown cooling suction valves and the reactor pressure vessel (RPV) head spray isolation valves.
The use of high drywell pressure as an isolation signsi has little effect in preventing coolant losses due to an RHR pipe break inside the drywell since the inboard isolation valves are located as close as possible to the drywell wall. Such pipe breaks do not present a site boundary dose problem since the leaked fluid and associated radioactivity are completely retained within the primary containment boundary. The high drywell pressure signal for the RPV head spray valves will also be deleted. Since the RPV head spray valves are used as part of the shutdown cooling procedures, this change is con-sistent with the above proposed RHR (shutdown cooling mode) system modification. This change does not affect the Appendix K calculation results presented in the FSAR. The requirements of 10 CFR 100 will still be met. This (7 modification, therefore, constitutes neither an unreviewed safety V question, nor a significant hazards consideration. Appendix 1 (page Al-9) provides the results of the significant hazards review. A new valve group (6) must be assigned to Technical Specifications table 3.7-1 since the RHR reactor shutdown cooling suction supply valves (E11-F008, E11-F009) and the RHR reactor head spray isolation
- valves (E11-F022 and E11-F023) are now unique and isolate on reactor vessel water level - low (levei 3) and reactor vessel steam dome pressure - low permissive. The reactor vessel steam dome pressure
-low permissive trip was not included in the original Technical Specifications table 3.7-1, but was added to correct and clarify the Technical Specifications.
This modification has been implemented on other BWR/4s.
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l 4-21 _____________f1_
~; 48.8 Safety / Relief Valve Position Indicator Modifications It was shown during qualification testing that the variable setting of the S/RV pressure switches could not hold their setpoints. To eliminate this problem, new switches were desig'ned which do not have' a variable setpoint capability. These switches are set at the factory at 85 psig. One of the two pressure switches on each S/RV has an indicating light associated with it. This light serves as primary indication of the position of the S/RV. Since table 3.2-11, Instrumen-tation Which Provides Surveillance Information, provides the type and range description of the S/RV primary indicator, it needs to be revised to reflect an indicating light at 85 psig. Also listed in table 3.2-11 is the S/RV secondary indicator. The type and range are currently given as a temperature element with a 0-600 F range. The instrument that provides surveillance is actually a recorder with a range of 0-600*F which receives input from the temperature element.
Therefore, this table also needs to be revised to show a recorder rather than the temperature element. Since these changes only clarify the Technical Specifications and do not revise any setpoints, this modificiation does not introduce an unreviewed safety question or a significant hazards consideration. Appendix 1 (page Al-10) provides the results of the significant hazards review. f"
- x-O 0
, / 4-22
p- - (j 48.9 Residual Heat Removal Shutdown Cooling Mode Safety Limi_t
. Modification The present HNP-1 Technical Specifications list a safety limit of 135 psig for the reactor vessel steam dome pressure whenever operat-ing the RHR system in the shutdown cooling mode. This value is incorrect. When the Technical Specifications were first written, the trip setpoint was accidentally listed in the safety limit section.
As a result, a calculation was performed to determine the actual safety limit. From this calculation it was determined that a safety limit of 162 psig will prevent overpressurization of the RHR heat exchanger due to reactor pressure and RHR pump head. In addition, it was noticed that the bases statements for the safety limit and the limiting safety system are reversed. This modification proposes to correct this error by changing the Technical Specifications safety limit from 135 psig to 162 psig. In addition, the bases for the safety limit and the limiting safety system settings will be corrected. Since these changes serve only to correct Technical Specifications errors, this modification consti-tutes neither an unreviewed safety question, nor a significant hazards consideration. Appendix 1 (page Al-11) provides the results
- of the significant hazards review.
q .- s b s 4-23
48.10 Elimination of MSIV Closure Scram in Startup Mode v() The current Technical Specification: require a reactor scram on MSIV 3 closure with the reactor in the startup/ hot standby made above 1045 psig vessel pressure. Since 1045 psig is the maximum allowable setpoint for the reactor trip on high pressure, the reactor will scram at 1045'psig in the startup/ hot standby mode irregardless of MSIV position. This modification proposes to disable the scram function on MSIV closure in the startup/ hot standby mode and delete the requirement from the Technical Specifications. This modifica-tion constitutes neither an unreviewed safety question, nor a signi-ficant hazards consideration. Appendix 1 (page Al-12) provides the results of tne significant hazards review. O i i N 4-24 .
j ~' . 48.11 Trip Function Identification Modifications Several of the trip function descriptions were revised to correspond ): .with the HNP-2 Technical Specifications and in some cases to the , Standard Technical Specifications. Since these modifications are . editorial in nature, an unreviewed safety question is not introduced, j nor is a significant hazards consideration. Appendix 1 (page Al-13) provides the results of the significant hazards review. 4 1 l i I I l ) i i i . i LO a . i I f ) i
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. 4-25 -
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/T 4.B.12 Miscellaneous Trip Setpoint/ Allowable Value Modifications V
4.8.12.a. New calculations were performed to determine the new setpoint value for each ATTS instrument. The setpoint calculations were made using the criteria of Regulatory Guide 1.105. The Plant Hatch analytical limits were used (where applicable) to develop the allowable values and trip setpoints. Unless identified in the text, the analytical limits used to develop these setpoints are the values used in the design basis of Plant Hatch. The values that are proposed to be i inserted into the Technical Specifications are the calculated allow-able values. The setpoints used at Plant Hatch will take into consideration instrument drift and will be developed from the allow-able values. The proposed Technical Soecifications revisions include modifications of the trip setpoints/ allowable values for the follow-ing instruments: , l RPS Trip Function Trip Unit MPL No.
- 1. Reactor vessel steam dome B21-N678A,B,C,0 pressure - high
- 2. Reactor vessel water level - B21-N680A,B,C,0 Level 3
- 3. Reactor vessel water level - B21-N681A,B,C,0 Level 1 .
(A)
- m. ECCS Trip Function Trip Unit MPL No.
- 1. Reactor vessel water level - 821-N691 ,B,C,0 Level 1
- 3. Reactor vessel steam dome B21-N690A,B,C,0 pressura - low .
- 4. Reactor vessel steam dome B21-N690E,F j presssure - low B21-N6418,C
- 5. Reactor vessel water 821-N695A,B level - Level 3 sY
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4-26
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48.12.b The bases for these proposed changes are as follows: 48.12.b.1 Setpoint Bases for Trip Functions Assigned to Reactor Protection System (RPS) Cabinets
- 1. Reactor vessel steam dome pressure - high (B21-N678A,B,C,D)
The analytical limit of 1071 psig is the value used in the plant transient analysis. The intent of this reactor scram function is to provide the nuclear system process barrier overpressure protection, because a rupture to the process barrier may result in the release of fission products. A pressure increase while operating also tends to increase-tha power of the reactor by collapsing voids, thus adding reactivity. A reactor scram quickly re, duces the neutron flux, counteracting the pressure increase. The trip setpoint/ allowable value of s1054 psig was developed using the criteria of Regulatory Guide 1.105. The designated trip setpoint for the plant will take into consideration instrument drift.
- 2. Reactor vessel water level - Level 3 (B21-N680A,B,C,0)
I Reactor vessel water level 3 is for isolation of primary con-taiment, initiation of reactor scram, and for closure of RHR shutdown cooling isolation valves. The analytical limit of 7.5 in. was used to determine the trip setpoint and allowable
,'^' value. A trip setpoint/ allowable value of 2 8.5 in was developed using the criteria of Regulatory Guide 1.105. The designated trip setpoint for the plant will take into considera-tion instrument drift.
- 3. Reactor vessel water level - Level 1 (821-N681A,B,C,0)
The analytical limit for this application is -152.5 in. The trip setpoint/ allowable'value of 2 -121.5 in was developed using the criteria of Regulatory Guide 1.105. The designated trip setpoint for the plant will take into consideration instrument drift. 48.12.b.2 Setpoint Basis for Trip Functions Assigned to ECCS Cabinets
- 1. Reactor vessel water level - Level 1 (B31-N691A,B,C,D)
The analytical limit of -152.5 in. is the value in the FSAR ECCS analysis for A05, low pressure coolant injection (LPCI), and containment spray initiation. The trip setpoint/ allowable value of 2 -121.5 in, was developed using the criteria of Regulatory Guide 1.105. The designated trip setpoint for the plant will take into consideration instrument drif t.
- 2. Reactor vessel steam dome pressure - low (B21-N690A,B,C,0,E,F)
'~'; These instrument channels monitor the reactor vessel pressure to
! provide the permissive signal for core spray and the injection 4-27 o-
)
t f~ N permissive signal for RHR (LPCI). The analytical limit for this j pressure permissive function has a range from 400 to 500 psig. l The criterion for this setpoint is that it should be low enough to ensure that no overpressurization of the low pressure ECCS occurs and high enough not to unnecessarily delay the flow injection of the low pressure system. The trip setpoint/allowabl'e value of 2 422 psig was developed using the lower analytical limit and the criteria of Regulatory Guide 1.105. The lower analytical limit was used because the important parameter is to ensure that RHR and core spray are operating as the pressure drops; therefore, a sign change of 2 is required. Although the lower analytical limit was used to determine the new Technical Specifications value, the original Technical Specifications value of s 500 psig is maintained. The designated trip setpoint for the plant will take into consideration instrument drift.
- 3. Reactor vessel steam dome pressure - low (B21-N690E,F; B21-N6418,C)
An analytical limit of 300 psig is used in the Appendix K ECCS calculations. The intent of this trip function is to provide a permissive for closure of the recirculation dis-charge valves. The present Hatch setpoints of 310 psig, 318 psig, and 324 psig are above the analytical limit of 300 psig. Plant Hatch, therefore, has operated within its design basis. However, the current Technical Specifications value of s335 psig was set
- to ensure that the recirculation discharge valves would operate during accident conditions. An analytical limit of 2300 psig
(]/ and a nominal trip setpoint of 360 psig (determined using the criteria of Regulatory Guide 1.105) will meet the intent of the
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Technical Specifications value; therefore, a sign change is proposed. The trip setpoint/ allowable value of 2 325 psig was developed using the criteria of Regulatory Guide 1.105.
- 4. Reactor vessel water level - Level 3 (821-N695A,B)
Reactor vessel level 3 provides an ADS permissive. The analytical limit of 7.5 in. was used in the FSAR ECCS analysis. The trip setpoint/ allowable value of 2 8.5 in was developed from the analytical limit using the criteria of Regulatory Guide 1.105. The designated trip setpoint for the plant will take into con-sideration instrument drift. [ \ 4-28 l t
[] 48.12.c Conclusion (m / - For the trip functions identified in this section, the analytical limits presented are such that neither transient nor safety analysis . results documented in the FSAR are adversely affected. The uncer-tainities associated with instrument accuracy, calibration, and drift are considered in the setpoint determination. Therefore, it is con-cluded that the proposed instrumentation setpoint changes do not reduce the margin of safety of the current Technical Specifications, or chcnge the FSAR setpoint bases and, therefore, constitute neither an unreviewed safety question as defined in 10 CFR_50.59, nor a signifi-cant hazards consideration as described in 10 CFR C0.92. Appendix 1 (page Al-14) provides the results of the significant hazards review. U r 4-29
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, V.
SUMMARY
V It can be concluded from the discussions of the preceding sections that the modifications do not introduce an unreviewed safety question, nor a signift-cant hazards consideration. The upgrade program is designed to: e Improve plant safety e Reduce instrument drift LERs e Increase plant reliability and availability e Aid in meeting the requirements of IE Bulletin 79-018, NUREG-0737, NUREG-0696, and NUREG-0661. This submittal provides an overview of the evaluation and the justification l for the proposed ATTS and the associated plant modifications to be incorporated into the Plant Hatch design during the 1984 refueling outage. The proposed Technical Specifications revisions are included in Section VI of this document. GPC will submit the proposed Technical Specification revisions for the remainder of the Hatch 1 ATTS modifications prior to the beginning of the 1985 refueling outage for that unit. O i l l !O 5-1
i Ov VI. . PROPOSED TECHNICAL SPECIFICATIONS REVISIONS
'l
. The Technical Specifications for HNP-1 (Appendix A to Operating License DPR-57) are proposed for revision as presented in this section. The revisions are for the ATTS equipment which is scheduled for installation during the 1984 refuglitig outage. Table 6.1 provides the instructions for incorporating the re' vision (s).
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l-TABLE 6.1 INSTRUCTIONS FOR INCORPORATING TECHNICAL SPECIFICATIONS REVISIONS If the Technical Specifications revisions are accepted as proposed, the HNP-1 Technical Specifications (Appendix A to Operating License DPR-57) should be incorporated as follows: Deletions Insertions Applicable SER.<an . Item _(Page) (Page) Section(s) 1 1.0-6 1.0-6 4.B.10 2 1.1-3 1.1-3 4.B.11, 4.B.12 3 1.1-4 1.1-4 4.B.10 4 1.1-5 1.1-5 4.8.3, 4.B.11, 4.B.12 5 1.1-13 1.1-13 4.B.11, 4.8.12 6 1.1-14 1.1-14 4.B.10 7 Fig. 2.1-1 Fig. 2.1-1 4.B.2, 4.8.3, 4.8.4, 4.B.11, 4.B.12 8 1.2-1 1.2-1 4.8.12 9 1.2-2 1.2-2 4.8.9 10 1.2-4 1.2-4 4.B.9 11 1.2-6 1.2-6, 6a 4.B.9 12 3.1-3 3.1-3 4.B.11, 4.B.12 13 3.1-4 3.1-4 4 B.11, 4.B.12 CG 14 3.1-5 3.1-5 4.B.10 15 3.1-7 3.1-7 ATTS, 4.8.11 16 3.1-8 3.1-8 ATTS 17 3.1-11 3.1-11 4.B.11 18 3.1-12 3.1-12 4.B.11, 4.B.12 19 3.1-14 3.1-14 ATTS 20 3.1-15 3.1-15 ATTS 21 3.1-17 3.1-17 ATTS 22 3.1-18 3.1-18 ATTS 23 3.2-1 3.2-1 4.8.1 24 3.2-2 3.2-2 4.8.2, 4.B.3, 4.B.6, 4.B.11,
- 4. B .12-25 3.2-5 3.2-5 4.B.3, 4.8.4, 4.B.11, 4.B.12 26 3.2-8 3.2-8 4.B.3, 4.B.4, 4,8.5, 4.B.11, 4.B.12 27 3.2-10 3.2-10 4.B.11, 4.0.12 28 3.2-11 3.2-11 4.B.11, 4.B.12 29 3.2-14 3.2-14 4.8.11, 4.B.12 30 3.2-20 3.2-20 4.B.3 31 3.2-22 3.2-22 4.0.8 32 3.2-23c 4.B.1 33 3.2-24 3.2-24 ATTS, 4.B.11 34 3.2-27 3.2-27 ATTS, 4.B.11 35 3.2-30 3.2-30 ATTS, 4.0.11 36 3.2-33 3.2-33 ATTS, 4.8.11 t'. 37 3.2-35 3.2-35 ATTS, 4.B.11
( 38 3.2-38 3.2-38 ATTS, 4.B.11 6-2
- r. -
..< ,u-(~'T ' Deletions Insertions Applicable SER*ca>
l/s Item (Page) (Page) Section(s) 39 3;. 2-45 . 3.2-45 ' 4.B.11 40 c -
.3 ;2-49c 4.B.1 41 3.2-50 ' 3.2-50, 50a 4.B.2, 4.B.3, 4.B.6, s - 4.B.9, 4.B.11, 4.B.12 42 3.2-52 3.2-52 Editorial, 4.B.3, 4.B.11,
.s "'
_ 4.B.12 43 ~?3.2-53 3.2-53 ATTS, 4.B.4, 4.B.11, 4.B.12 44 3.2-55 *- - 3.2-55, ~~ Editorial, ATTS, 4.B.3, 4 4.B.11 45 3.2 3.2-56 ^ ATTS, 4.B.4, 4.B.5, 4.B.11, 46 3.2-58 3.2-58 . 4.8.11, 4.B.12 47 3.2-59 3.2-59 4.B.12 , 48 3.2-60 3.2-60 4.B.12 49 .3.2 3.2-62 4.B.11, 4.B.12 50 0-3.2-68a 3.2-68a 4.B.1 51 3.2-69 3.2-69 ATTS 52 3.6-9 3.6-9 4.B.1 53 3.6-9a 3.6-9a, 9b 4.B.1 54 3.6-21 3.6-21 4.B.1 55 3.6-22 3.6-22 4.B.1
.56 3.7-17 '
3.7-17 4.B.7 57 3.7218 ^ ' 3.7-18 4.B.7
.. 58 -3.7 3.7-19 4.B.7, 4.B.11, 4.B.6, 4.B.2 -
59 3.7-35 .3.7-35 4.B.2, 4.B.6, 4.B.7, 4.B.11 [ s
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- SER-Safeti Evaluation Report
- a. 1. ATTS refers to proposed revisions justified in Section III of this submittal.
- 2. ~48.1 through 48.12 refer to justifications presented in Section IV of-this submittal.
. 3. Editorial refers to the correction of a typographical error.
^
) '
6-3
r - _ _ ..
@ GG. Simulated Automatic Actuation - Simulated automatic actuation means applying a simulated signal to the sensor to actuate the circuit in question.
HH. Start & Hot Standby Mode - The reactor is in the Start & Hot Standby Mode when the Mode Switch is in the START & HOT STANDBY position. In l this mode the reactor protection system is energized with IRM and APRM (Start & Hot Standby Mode) neutron monitoring system trips and control rod withdrawal inter-locks in service. II. SJrveillance Frequency - Periodic surveillance tests, checks, calibrations, - and examinations shall be performed within the specified surveillance intervals. These intervals may be adjusted plus or minus 25%. The operating cycle interval as pertaining to instrument and electrical surveillance shall never exceed 15 months. In the case where the elapsed interval has exceeded 100% of the specified interval, the next surveillance interval shall commence at the end of the original specified interval. JJ. Surveillance Requirements - The surveillance requirements are requirements established to ensure that the Limiting Conditions for Operation as stated in Section 3 of these Technical Specifications are met. Surveil-lance requirements are not required on systems or parts of systems that are not required to be operable or are tripped. If tests are missed on parts not required to be operable or are tripped, then they shall be
- s performed prior to returning the system to an operable status.
( ; i Q m.) KK. Total Peaking Factor (TPF) - The total peaking factor is the highest product of radial, axial, and local peaking factors simultaneously operative at any segment of fuel rod. LL. Transition Boiling - Transition boiling is the boiling that occurs between nucleate and film boiling. Transition boiling is manifested by an unstable fuel cladding surface temperature, rising suddenly as steam blanketing of the heat transfer surface occurs, then dropping as the steam blanket is swept away by the coolant flow, then rising again. e.-
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(_) SAFETY LIMITS LIMITING SAFETY SYSTEM SETTINGS 2.1.A.I.d. APRM Rod Block Trip Setting The APRM rod block trip setting , shall be: S RB s 0.66 W + 42% where: S RB = Rod block setting in percent of rated thermal
~
power (2436 MWt) W = Loop recirculation flow rate in percent of rated (rated loop recirculation flow rate equals 34.2 x 10' lb/hr) ~ In the event of operation with a core maximum fraction of limiting power density (CMFLPD) greater than the fraction of rated core thermal pg,,7 (Core MW Thermal), the ARPM (g 2436 gain shall be adjusted up to 95% of rated thermal power as follows: APRM Reading 2 100% x CMFLPD Provided that the adjusted APRM reading does not exceed 100% of rated thermal power and the required gain adjustment incre-ment does not exceed 10% of rated thermal power.
- 2. Reactor Vessel Water Low Level Scram Trip Setting (Level 3)
Reactor vessel water low level scram trip setting (Level 3) shall be 2 8.5 inches (narrow range scale).
- 3. Turbine Stop Valve Closure Scram Turbine stop valve closure scram trip setting shall be s 10 percent valve closure from full open. This
,- m scram is only effective when tur-(j- bine steam flow is above 30% of rated, as measured by turbine first stage pressure.
1.1-3
l "(_) SAFETY LIMITS LIMITING SAFETY SYSTEM SETTINGS I 2.1.A.4. Turbine Control Valve Fast Closure Scram Trip Setting Turbine control valve fast closure scram trip shall initiate within 30 milliseconds of start of control valve fast closure. Fast closure is sensed by measuring electro-hydraulic control oil line pressure which decreases rapidly upon generator load rejection and just prior to fast closure of the control
. valves. This scram is only effective when turbine steam flow is above 30% of rated, as measured by turbine first stage pressure.
- 5. Main Steam Line Isolation Valve Closure Scram Trip Set-ting
/
\_ / Scram trip setting from main steam line isolation valve closure shall be s 10 percent valve closure from full open. This scram is effective in the Run Mode.
- 6. Main Steam Line Isolation Valve Closure on Low Pressure Main steam line isolation valve closure on low pressure at inlet to turbine valves shall occur _at 2 825 psig, while in the Run Mode.
- 7. Main Steam Line Isolation Valve Closure on Low Con-denser Vacuum Main steam line isolation valve closure on low condenser va-cuum shall occur at 2 7 inches Hg vacuum.
f% - 1.1-4
f- - A/ -- SAFETY LIMITS LIMITING SAFETY SYSTEM SETTINGS 2.1.B. Reactor-VesselWaterLevelTripSettingsl Which Initiate Core Standby Cool-ing Systems (CSCS) Reactorvesselwaterleveltripsettingsl which initiate core standby cool-ing systems shall be as shown in Tables 3.2-2 thru 3.2-6 at normal operating conditions.
- 1. HPCI Actuation (Level 2)
HPCI actuation (Level 2) shall occur at a water level 2 -55 inches. ,
- 2. Core Spray and LPCI Actuation (Level 1) l Core Spray and LPCI actuation (Level 1) shall occur at a water level 2 -121.5 inches.
O O 1.1-5
. _ ~ . -
~2.1. A.-l .c - APRM- Flux Scram Trip Settings (Run Mode) (Continued)
The APRM flow referenced scram trip setting at full recirculation flow
;( l ;is adjustable up to 120% of. rated power. This reduced flow referenced U trip setpoint will result in an earlier scram during slow thermal
; transients, .such~ as the loss of 80*F feedwater . heating event, than would result with the 120% fixed high neutron flux scram trip. The lower flow referenced scram setpoint therefore decreases the severity
.(ACPR):of.a slow. thermal transient and allows lower Operating Limits if_ such.a transient is the. limiting abnormal operational transient during a:certain exposure interval in the cycle.
The APRM fixed high neutron flux signal does not incorporate the timeLconstant, but responds directly to instantaneous neutron flux. This scram setpoint scrams the reactor during fast power increase transients if credit is not taken for a direct (position) scram, and
-also serves to scram the reactor if credit is not taken for the flow referenced scram.
The APRM' reading must be adjusted to ensure that the LHGR transient-
. peak is not increased for any combination of CMFLPD and reactor core thermal power. The APRM reading is adjusted in accordance with the
-formula _in Specification 2.1.A.1.c., when the CMFLPD is greater than the fraction of rated core thermal power.
Analyses of the limiting tran'sients show that no scram adjustment is-
. required to assure MCPR > 1.07 when the transient is inif.iated from the operating MCPR-limit.
-d. ApRM Rod Block Trip Setting
~
Reactor power level may be varied by moving control rods or by varying the recirculation flow rate. The APRM system provides a control rod block
-to prevent rod withdrawal beyond-a given point at constant recirculation-
~
flow rate, and thus' to protect against the condition'of a MCPR l_ess than , 1.07. This rod block trip setting, which.is automatically varied with recirculation loop flow rate, prevents an increase in the reactor -power
-level to excessive values due to control rod withdrawal. The flow variable trip ~ setting-provides. substantial margin from fuel damage, assuming a steady-state operation at the trip setting, over the entire recirculation flow range. The margin to the Safety Limit increases as the flow decreases for the specified trip setting versus flow relation-ship; therefore, the worst case MCPR which would occur during a steady-state operation-is at 108% of rated thermal power because of the APRM rod block trip ~ setting. The actual power distribution in the core is estab-lished by.specified control rod sequences and is monitored continuously by the in-core LPRM system. The APRM reading is adjusted to compensate for a CMFLPD greater than the fraction of rated core thermal ~ power.
- 2. ' Reactor Vessel Water Low Level Scram Trip Setting (Level 3) l The trip setting for low level scram is above the bottom of the separator
~
skirt. This level is > 14 feet above the top of the active fuel. This level has been used in transient analyses dealing with coolant inventory decrease. The results reported in FSAR Section 14.3 show that a scram at
- -. this level adequately protects the fuel and the pressure barrier. The 7 -
designated scram trip setting is at least 22 inches below the bottom of the normal operating range and is thus adequate to avoid spurious scrams. 1.1-13 . L
._ , < r m.
- N
(_) BASES FOR LIMITING SAFETY SYSTEM SETTINGS 2.1.A.3. Turbine Stop Valve Closure Scram Trip Settings The turbine stop valve closure scram trip anticipates the pressure, neutron flux and heat flux increase that could result from rapid closure of the turbine stop valves. With a scram trip setting of s 10 percent of valve closure from full open, the resultant increase in surface heat flux is limited such that MCPR remains above 1.07 during the worst case transient that assumes the turbine bypass is closed. This scram is bypassed when turbine steam flow is below 30% of rated, as measured by turbine first stage pressure.
- 4. Turbine Control Valve Fast Closure Scram Trip Setting This turbine control valve fast closure scram anticipates the pressure, neutron flux, and heat flux increase that could result from fast closure of the turbine control valves due to load rejection exceeding the capability of the turbine bypass. The Reactor Protection System initiates a scram when fast closure of the control valves is initiated by the fast acting solenoid valves. This is achieved by the action of the fast acting solenoid valves in rapidly reducing hydraulic control oil pressure at the main turbine
- control valve actuator disc dump valves. This loss of pres-sure is sensed by pressure switches whose contacts form the one-out-of-
; two-twice logic input to the reactor protection system. This trip setting,
) a nominally 50% greater closure time and a different valve characteristic
(_/
\~ from that of the turbine stop valve, combine to produce transients very similar and no more severe than for the stop valve. This scram is bypassed when turbine steam flow is below 30% of rated, as measured by turbine first stage pressure.
- 5. Main Steam Line Isolation Valve Closure Scram Trip Setting The main steam line isolation valve closure scram occurs within 10% of valve movement from the fully open position and thus anticipates the neutron flux and pressure scrams which remain as available backup pro-tection. This scram function is bypassed automatically when the Mode Switch is not in the RUN position.
- 6. Main Steam Line Isolation Valve Closure on Low Pressure The low pressure isolation of the main steam lines at 825 psig was provided to protect against rapid reactor depressurization and the resulting rapid cooldown of the vessel, which might result from a pressure regulator failure causing inadvertent opening of the control and/or bypass valves.
\
' ~ 1.1-14 i
7, - - v . .m .. 900 7 NOTE: SCALE IN INCHES ABOVE VESSEL ZERO e rh WATER LEVEL P.'OMENCLATURE ( HEIGHT ABOVE 800 - - VESSEL ZERO NO. (INCHES) READING INSTRUMENT
* (8) 573.5 +56.5 BARTON/ROSEMOUNT l 750 -- (7) 559 +42 GE/MAC VESSE L (4) 549 +32 GE/MAC
' ~ BARTON FLANGE] (3) 5255 + 8.5 (2) 462 -55 BARTON 700 -- 395.5 -121.5 BARTON (1)
(0) 3135 -2035 BARTON 650 - - MAIN STE AM
<- 640 - LINE F
600 -- 577
.- 573.5 (8) +60 - - +60 - +60 - -
+f 3 - -
9 - 559 (7) (3)- 56.5 (7) 42 HI ALARM 550 -e 54 914) HPCI& (4) '32 LO ALARM
- 5255 (3) RCIC TRIPS (3) -85 LOW (LEVEL 3 BOTTOM OF STEAM ~
-ORYER SKIRT 517 INSTHUMENT 0-0 O-- 0 -- REACTOR CONTRIBUTE TO ADS SCRAM FEED 500 --
17 - - -55 LOW LOW (LEVEL 2) WATER CORE
- 2( SPRAY g INITI ATE HPCI, RCIC, 450 --
400 -- 395.5 (1) - -1215 LOW LOW LOW (LEVEL 1) INITI ATE RHR.C.S.,
- 367 -150 --
U f 350 - ' 352.56 START DIESE* AND
" CONTRIBUTE TO A.D.S.
CLOSE MSIV*S 2/3 COR E
-2035 HEIGHT 3135 (0)
PERMISSIVE 300 -- ACTIVE FUEL 250 -- 200 = 208.56 317 - - REClRC j RECinC -um miSmgE ) NOZZLE SUCTION - 161.5 NOZZLE 150 -- 100 -- a 50 -- 0-- 9380 2 (~'s FIGURE 2.1-1 REACTOR VESSEL WATER LEVEL
(#N g SAFETY LIMITS LIMITING SAFETY SYSTEM SETTINGS 2.2 REACTOR COOLANT SYSTEM INTEGRITY 2.2 REACTOR COOLANT SYSTEM INTEGRITY Applicability Applicability The Safety Limit, established to pre- The Limiting Safety System Settings apply serve the reactor coolant system to trip settings of the instruments and integrity, applies to the limit on the devices which are provided to prevent the reactor vessel steam dome pressure, reactor vessel steam dome pressure Safety Limit from being exceeded. Objective Objective The objective of the Safety Limit (asso- The objective of the Limiting Safety Sys-ciated with preserving the reactor cool- tem Settings is to define the level of ant system integrity) is to establish a the process variables at which automatic pressure limit below which the integrity protective action is initiated to prevent of the reactor coolant system is not the reactor vessel steam dome pressure threatened due to any overpressure con- Safety Limit from being exceeded. dition. Specifications Specifications A. Reactor Vessel Steam Dome Pressure A. Nuclear System pressure i 5 (/ 1. When Irradiated Fuel is in the 1. When Irradiated Fuel is in the Reactor Reactor The reactor vessel steam dome pres . When irradiated fuel is present in sure shall not exceed 132.5 psig at the reactor vessel, and the head any time when irradiated fuel is is bolted to the vessel, the present in the reactor vessel. limiting safety system settings shall be as specified below: Limiting Safety Protective System Settings Action (psig)
- a. Scram on high s 1054 l reactor pres-sure (reactor vessel steam dome pressure)
- b. Nuclear system 4 valves at relief valves 1080 open on 4 valves at nuclear system 1090 pressure 3 valves at 1100 n
1.2-1
SAFETY LIMITS LIMITING SAFETY SYSTEM SETTINGS 2.2.A Nuclear System Pressure (cont.) The allowable setpoint relief error for each valve shall be + 1%. In the event that an instalIed safety-relief valve requires replacement, a spare valve whose setpoint is lower than that of the failed valve - - may be substituted for the failed valve until the first refueling outage following such substitution. No more than two valves with lower setpoints may be substituted in place of valves with higher setpoints. Spare valves which are used as sub-stitutes under the abovementioned provisions shall have a setpoint equal to 1080 psig +1% or 1090 psig
+1%.
1.2.A.2 When Operating The RHR Sys- 2.1.A.2. When Operating The RHR System tem in the Shutdown Cooling in the Shutdown Cooling Mode Mode
~j The reactor pressure trip set-The reactor vessel steam dome ting which closes (on increas-pressure shall not exceed 162 l ing pressure) or permits open-psig at any time when operat- ing (on decreasing pressure) of ing the RHR system in the Shut- the shutdown cooling isola- -
down Cooling Mode. tion valves shall be s 135 psig. _) 1.2-2
4s 4 1. BASES FOR SAFETY LI-MITS 1.2.A.2.~-When Operating the RHR System in the Shutdown Cooling Mode , i .- The design pressure of the. shutdown cooling piping of the Residual . Heat Removal System is not exceeded with the reactor vessel steam dome
- pressure less than-162 psig.
I-4 4 4 t i i l-( i
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I l l r i 1 s - t r e ) I 1.2-4 ! i : I- !
8ASES FOR LIMITING SAFETY SYSTEM SETTINGS D 2.2 REACTOR COOLANT SYSTEM INTEGRITY U .- Nuclear System Pressure A. 1.' When Irradiated Fue'l is in the Reactor The 11 relief / safety valves are sized and set point pressures.are estab-
.lished.in accordance with the following requirements of Section III of
'the ASME Code:
- a. -The lowest relief / safety valve must be set to open at or'below vessel design pressure.and the-highest relief / safety valve must be set to open at or below 105% of design pressure.
- b. The valves must limit the reactor pressure to no more than 110% of design pressure.
The primary system relief / safety valves are sized to limit the primary system pressure, including transients, to the limits expressed in the ASME Boiler and Pressure Vessel Code, Section III, Nuclear Vessels. No credit is taken from a scram initiated directly from the isolation
' event, or for power operated relief / safety valves, sprays, or other
- power operated pressure relieving devices. Thus, the probability of failure of'the turbine generator trip SCRAM or main steam isolation valve closure SCRAM is conservatively assumed to be unity. Credit is
' taken for. subsequent indirect protection system action such as neutron
,e flux SCRAM and reactor high pre'sure s SCRAM, as allowed by the ASME Code. Credit is also taken for the dual relief / safety valves in their ASME Code qualified mode of safety operation. Sizing on this basis is applied to.the most severe pressurization transient, which is the main steam isolation valves closure, starting from operation at 105 percent of the reactor warranted steamflow condition. Reference 2, Figure 4 shows peak,-vessel bottom pressures attained when the main steam isolation valve closure transients _are terminated by various modes of reactor scram', other than that which would be initiated directly from the isolation event (trip scram). Relief / safety valve capacities for this analysis are 84.0 percent, represen-tative of the 11 relief / safety valves. The relief / safety valve . settings' satisfy' the Code requirements for.
~
relief / safety valves that the lowest valve set point be at or below the vessel design pressure of 1250 p'sig. These settings are also sufficiently above the normal operating pressure range to prevent unnecessary cycling caused by minor transients. The results of postu-lated transients where inherent relief / safety valve actuation is required are given in Section 14.3 of the FSAR.
- 2. When Operating the RHR System in the Shutdown Cooling Mode An interlock exists in.the logic for the RHR shutdown cooling valves, which are normally closed during power operation, to prevent opening of the valves above a preset pressure setpoint of 135 psig. This setpoint
's - is selected to assure that pressure integrity of the RHR system is main-tained. Administrative operating procedures require the operator to 1.2-6
m - - . . . _
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L/ BASES FOR LIMITING SAFETY SYSTEM SETTINGS , ,_ _ close these shutdown cooling valves prior to pressure operation. How-ever, as a backup, 'the interlock will automatically close these vcives when the pressure setpoint is reached.' Double indicating lights will ' be provided in the control room for valve position indication. 1. 5, J LO
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1.2-6a - 4 v-,--,,,-,,-----,. , , - , . . - , - . - . . , - , , , , , , - - , _ . , - , , _ , . , - , . , . , , . . , - _ . , . . . -n. . . - - - - - - , . . . - <
.. J Table 3.1-l' REACTOR PROTECTION SYSTEM (RPS) INSTRUMENTATION REQUIREMENTS When the reactor is subcritical and the reactor water temperature is less than 212 F, only the following sources of scram trip signals need to be operable:
Mode Switch in SHUTDOWN ' Manual Scram 5 3 IRM High High Flux
- Scram Discharge Volume High High Level
( . Scram Operable Number Source of Scram Trip Signal Channels Scram Trip Setting Source of Scram Signal is (a) Required Per Required to be Operable
, Trip System Except as Indicated Below g
(b) _ { O 1 Mode Switch in SHUTDOWN 1 Mode Switch in Automatically bypassed two
- SHUTDOWN seconds after the Mode
) Switch is placed in the *
; SHUTDOWN position.
1
! 2 Manual Scram 1 Depression of l Manual Scram Button
- 3 IRM High liigh Flux 3 5120/125 of full IRMs are aute.atically bypassed scale Tech Spec when APRMs are on scale and the 2.1.A.1.a Mode Switch is in the Run y position.
Inoperative 3 Not Applicable IRMs are automatically bypassed f when APRMs are on scale and the Mode Switch is in the RUN 1 position. 4 Reactor Vessel Steam Dome 2 51054 psig Not required when reactor head
) , Pressure - High Tech Spec 2.2.A.1 is not bolted to the vessel.
1 I i
O . O O 1 Table 3.1-1 (Cont'd) Scram Operable Number Source of Scram Trip Signal Channels Scram Trip Setting Source of Scram Signal is (a) Required Per Required to be Operable Trip System Except.as Indicated Below (b) 5 High Drywell Pressure 2 ~< 2 psig Not required to be operable when ' primary containment integrity is not required. May be bypassed when necessary during purging for containment inerting or deinerting. w
- 6 Reactor Vessel Water Level - 2 -> 8.5 inches
'g Low (Level 3) 7 Scram Discharge Volume High Permissible to bypass (initiates High Level control rod block) in order to { reset RPS when the Mode Switch is
- a. Float Switches 171. gallons (
- b. Thermal Level Sensors 171 gallons 8 APRM Flow Referenced 2 S < 0.66W+54%
Neutron Flux (Not to exceed 117%) Tech Spec 2.1.A.1.c Fixed High Neutron 2 S < 120% Power Flux Tech Spec 2.1.A.1.c Inoperative 2 Not Applicable An APRM is inoperable if there are less than two LPRM inputs per level or there are less than 11 LPRM inputs to the APRM channel. i
~$
q O, ~J G Table 3.1-1 (Cont'd) Scram Operable Number Source of Scram Trip Signal Channels Scram Trip Setting Source of Scram Signal is (a) Required Per Required to be Operable Trip System Except as Indicated Below (b) 8 APRM Downscale 2 > 3/125 of full scale The APRM downscale trip is active only when the Mode Switch is in RUN. The APRM downscale trip is automati-cally bypassed when the IRM instrumentation is operable and not tripped. w 15% Flux 2 < 15/125 of full The APRM 15% Scram is auto-scale Tech Spec matically bypassed when the 7 2.1.A.1.b Mode Switch is in the RUN position. , 9 Main Steam Line Radiation 2 < 3 times normal Not required if all steam lackground at rated lines are isolated. thermal power. 10 Main Steam Line Isolation 4 < 10% valve closure Automatically bypassed when Valve Closure from full open the Mode Switch is not in Tech Spec 2.1.A.5 the RUN position. The design permits closure of any two lines without a scram being initiated., g 11 Turbine C6ntrol Valve 2 Within 30 milli- Automatically bypassed when Fast Closure seconds of the start turbine steam flow is below of control valve 30% of rated as ineasured by ( fast closure turbine first stage pressure. Tech Spec 2.1.A.4.
O O O
. Table 4.1 Reactor Protection System (RPS) Instrumentation Functional Test, Functional Test Minimum Frequency, and Calibration Minimum Frequency Scram Instrument functional Test Instrument Calibration )
Number Source of Scram Trip Signal Group Minimum Frequency- Minimum Frequency (a) (b) (c) 1 Mode Switch in SHUTDOWN A Once/ Operating Cycle: Not Applicable 2 Manual Scram A Every 3 months Not Ap'plicable 3 IRM High High Flux C Once/ Week during refueling Once/ Week and within 24 hours of Startup (e) Inoperative C Once/ week during refueling Once/ Week and within 24 hours of Startup (e) ." 4 Reactor Vessel Steam Dome D Once/ Month Once/ operating cycle 7 Pressure - High 4 - 5 High Drywell Pressure A Once/ Month (f) Every 3 months I ' 6 Reactor Vessel. Water Level - D Once/ Month (g) Once/ Operating Cycle Low (Level 3) l 7 Scram Discharge Volume High High Level
- a. Float Switches A Once/ Month (f) (h) ,
- b. Thennal Level Sensors B Once/ Month (f) Once/ operating cycle 8 APRM Fixed High Flux B Once/ Week (e) Twice/ Week Inoperable B Once/ Week (e) Twice/ Week Downscale B Once/ Week (e) Twice/ Week Flow Reference B Once/ Week (f)- Once/ Operating Cycle 15% Flux C Within 24 Hours of Startup (e) Once/ Week
-- - - t
r .- _. .__ .,__ . _ _ _ - . _ -___ ._ _ O - O O Table 4.1-1 (Cont.)- 9 Main Steam Line High Radiation B Once/ Week (e)_ Every 3 months (i) 10 Main Steam Line Isolation Valve A Once/ Month (f) (h) Closure 11 Turbine Control Valve Fast A Once/ Month (f) (j) Once/ Operating Closure Cycle (k) 12 Turbine Stop Valve Closure A Once/ Month-(f) (h). RPS Channel Switch A Once/ Operating Cycle Not Applicable Turbine First Stage Pressure A Every 3 months Every 6 months Permissive Reactor Pressure Permissive A Every 3 months Every 6 months-LPRM Signal B Every 1000 Effective Full Power Hours
']
r 7
- 1. The column entitled " Scram Number" is for convenience so that a one-to-one relationship can be established between items in Table 4.1-1 and items in Table 3.1-1.
- b. The definition for each of the four groups is as follows: l Group A. On-off sensors that provide a scram trip signal.
Group B. Analog devices coupled with bi-stable trips that provide a scram trip signal. Group C. Devices which only serve a useful function during some restricted mode of operation, such as startup or shutdown, or for which the only practical test is one that can be
. performed at shutdown.
Group D. Analog transmitters and trip units that provide a scram trip function. l
- c. Functional tests are not required when the systems are not required to be operable or are tripped.
However, if functional tests are missed, they shall be performed prior to returning the systems to an operable status. . s
~ .- -
BASES FOR LIMITING CONDITIONS FOR OPERATION
N 3.1.A.2. Manual Scram O
- The manual scram function is active in all modes, thus providing for a manual means of rapidly inserting control rods during all modes of reactor operation. .
- 3. IRM The bases for the IRM High High Flux Scram Trip Setting are discussed in the bases for Specification 2.1.A.1.a. Each protection trip system has one more IRM channel than is necessary to meet the minimum number re-quired. This allows the bypassing of one IRM channel per protection trip system for maintenance, testing or calibration.
- a. High High Flux The IRM system provides protection against excessive power levels and short reactor periods in the source and intermediate power ranges. The requirement that the IRM's be inserted in the core until the APRM's read 3/125 of full scale or greater assures that there is proper overlap in the neutron monitoring systems and thus, that adequate coverage is pro-vided for all ranges of reactor operation.
A source range monitor (SRM) system is also provided to supply addi-tional neutron level information during start-up but has no scram func-tion (Section 7.5.4 FSAR). Thus, the IRM and APRM systems are required in the Refuel and Start & Hot Standby modes. In the power range, the
.O APRM system provides the required protection (Section 7.5.7 FSAR).
V Thus, the IRM System is not required when the APRM's are on scale and the Mode Switch is in the RUN position,
- b. Inoperative When an IRM channel becomes unat'e to perform its normal monitoring function, the. condition is recognized and an inopertive trip results.
This trip is given the same logic significance as the upscale trip; thus the faulty channel immediately fails safe by contributing to a potential scram condition.
- 4. Reactor Vessel Steam Dome Pressure - High <
High pressure within the nuclear system poses a direct threat of rupture to the nuclear system process barrier. A nuclear system pressure increase while the reactor is operating compresses the steam voids and results in a positive reactivity insertion causing increased core heat generation that could lead to fuel failure and system over pressurization. A scram counter-acts a pressure increase by quickly reducing the core fission heat l generation. l The nuclear system high pressure scram setting is chosen slightly 'above the
- reactor vessel maximum normal operation pressure to permit normal operation i without spurious scrams yet provide a wide margin to the maximum allowable
, nuclear system pressure. The location of the pressure measurement, as com-l pared to the location of highest nuclear system pressure during transients, l VQ was also considered in the selection of the high pressure scram setting. The nuclear system high pressure scram works in conjunction with the pres-sure relief system in preventing nuclear system pressure from exceeding the maximum allowable pressure. This same nuclear system high pressure scram j 3.1-11
r
-.s e
13.1.A.4. ~ Reactor Vessel Steam 0:mo Prassure - High (Continued)'- setting also protects the core from exceeding thermal hydraulic limits as
.f; a result of pressure increases from some events that occur when the reactor
\- 'is operating at. less :than rated power and flow.
~
-5. High Orywell Pressure Pressure switch instrumentation for-the drywell is provided to-detect a loss of coolant accident and initiate the core standby cooling equipment. A high drywell. pressure scram is provided at.the same setting (s2 psig) as the core standby cooling systems initiation to minimize the energy which must be
~
accommodated during a loss of coolant accident. The instrumentation is a backup to th'e reactor vessel water-level instrumentation.
- 6. Reactor Vessel Water Level - Low (Level 3)
' The bases for the Reactor Vessel Water Level-Low Scram Trip Setting (Level.
- 3) are discussed in the bases -for Specification 2.1.A.2.
- 7. Scram Discharge Volume High High Level The control rod drive scram system is designed so that all of the water
.which is discharged from the reactor by a scram can be accommodated in the discharge piping. A part of'this piping is an instrument volume which is the low point in the piping. No credit was taken for this f volume in the design of the discharge piping as concerns the amount of F water which must be accommodated during a scram. During normal operation the discharge volume is empty; however, should the discharge volume fill 4 with water, the water discharged to the piping from the reactor could not
+ - be accommodated which woul_d result in a slow scram time or partial. or no control rod insertion. To preclude this occurrence, level switches have
- ' -been provided in the instrument volume which scram the reactor when the volume of water reaches'71 gallons. As indicated above, there is suffi-
- cient volume in the piping to accommodate the scram without impairment of.the
] scram times or amount of insertion of the control rods. This function shuts the reactor down while sufficient volume remains to accommodate the dis-charged water and precludes the situation in which a scra'm would be required . but not able to perform its function adequately.
- 8. APRM e Three APRM instrument channels are provided for each protection trip sys-tem. APRM's A and E' operate contacts in one trip logic and APRM's C and E operate contacts in the other trip logic. APRM's B, 0 and F are arranged similarly in the other protection trip system. Each protection trip sys-l~ tem has one more APRM than is necessary to meet the minimum number re-i quired per channel. This allows the bypassing of one APRM per protection
- trip system for maintenance, testing or calibration. t- ' Flow Referenced and Fixed High Neutron Flux a. ! The bases for the APRM Flow Referenced and Fixed High Neutron Flux Scram i Trip Settings are discussed in the bases for Specification 2.1.A.I.c. [O 3.1-12
- p. , ..
.2 BASES FOR LIMITING CONDITIONS FOR OPERATION
() 3.1.B. RPS Response Time Component electrical characteristics are selected so that the system response time, from the opening of a sensor contact up to and including the opening. of the trip actuator contacts, is less than 50 milliseconds. A 50 millisecond time delay plus control rod movement and sensor delay time is used in the various transient analyses. For the analog transmitter trip system (ATTS) instrumentation, the sensor consists of a transmitter and the associated trip unit. C. References
- 1. FSAR Section 7.2, Reactor Protection System
- 2. FSAR Section 7.5.4, Source Range Monitor Subsystem
- 3. FSAR Section 7.5.7, Average Power Range Monitor Subsystem
~
- 4. IEEE Standard 279-1971 Criteria for Protection Systems for Nuclear Power Generating Stations V
O V 3.1-14 a...
BASES FOR LIMITING CONDITIONS FOR OPERATION 4.1 REACTOR PROTECTION SYSTEM (RPS) A. Test and Calibration Requirements for the RPS The minimum functional testing frequency used in this specification is based on a reliability analysis using the concepts developed in Reference 1 and the surveillance frequencies for ATTS equipment approved by the NRC in Reference
- 2. These concepts were specifically adapted to the one out of two taken twice logic of the reactor protection system. The analysis shows that the sensors are primarily responsible for the reliability of the reactor protec-tion system. This analysis makes use of unsafe failure rate experience at conventional and nuclear power plants in a reliability model for the system.
An unsafe failure is defined as one which negates channel operability and which, due to its nature, is revealed only when the channel is functionally tested or attempts to respond to a real signal. Failures such es blown fuses, ruptured bourdon tubes, faulted amplifiers, faulted cables, etc., which result in upscale or downscale _ readings on the reactor instrumentation are safe and will be easily recognized by the operators during operation be-cause they are revealed by an alarm or a scram. The channels listed in Table 4.1-1 are divided into four groups for l . functional testing. These are: Group A. Ori-Off Sensors that provide a scram trip function. Group B. Analog devices coupled with bi-stable trips that provide a scram function. -( Group C. Devices which only serve a useful function during some ( restricted mode of operatien, such as startup or shutdown, or for which the only practical test is one that can be performed at shutdown. Group D. Analog transmitters and trip units that provide a scram trip function. The sensors that make up Group A are specifically selected from among the whole family of industrial on-off sensors that have earned an excellent reputation for reliable operation. During design, a goal of 0.99999 probability of success at the 50% confidence level was adopted to assure that a balanced and adequate design is achieved. The pec5 ability of success is primarily a function of the sensor failure rate and the test interval. A three-month test interval was planned for Group A sensors. This is in keeping with good operating practices, and satisfies the design goal for the logic configuration utilized in the Reactor Protection System. To satisfy the long-term objective of maintaining an adequate level of safe-ty throughout the plant lifetime, a minimum goal of 0.9999 at the 95% confi-dence level is proposed. With the one out of two taken twice logic, this requires that each sensor have an availability of 0.993 at the 95% confidence level. This level of availability may be maintained by adjusting the test interval as a function of the observed failure history (Ref.1). To facili-tate the implementation of this technique, Figure 4.1-1 is provided to indi-cate an appropriate trend in. test interval. The procedure is as follows:
/ 1. Like sensors are pooled into one group for the purpose of data
( acquisition.
' 2. The factor M is the exposure hours and is equal to the number of sensors 3.1-15
r BASES FOR LIMITING CONDITIONS FOR OPERATION p) t 4.1.A. Test and Calibration Requirements for the RPS (Continued) Group C devices are active only during a given portion of the operational cycle. For example, the IRM is active during startup and inactive during full power operation. Thus, the only test that is meaningful is the one performed just prior to shutdown or startup; i.e., the tests that are per-formed just prior to use of the instrument. Calibration frequency of the instrument channel is divided into two cate-gories: They are as follows:
- 1. Passive type indicating devices that can be compared with like units on a continuous reference.
- 11. Vacuum tube or semiconductor devices and detectors that drift .
or lose sensitivity. Experience with passive type instruments in generating stations and substa-tions indicates that the specified calibrations are adequate. For those devices which employ amplifiers, etc., drift specifications call for drift to be less than 0.4%/ month; i.e., in the period of a month a drift of
.4% could occur and still provide for adequate margin. For the APRM system, drift of electronic apparatus is not the only consideration in determining a calibration frequency. Change in power distribution and loss of chamber sensitivity dictate a calibration every seven (7) days. Calibration on this frequency assures plant operation at or below thermal limits. -
,m C The sensitivity of LPRM detectors decreases with exposure to neutron flux at a slow and approximately constant rate. This is compensated for in the APRM system by calibrating twice a week using heat balance data and by calibrating individual LPRM's every 1000 effective full power hours using TIP traverse data.
Group D devices consist of analog transmitters, master trip units, slave trip units, and other accessories. The general description of the ATTS devices is provided in Reference 3. As evidenced by NED0-21617-A, the NRC has approved the following surveillance frequencies for ATTS equipment:
- 1. Once per shift for channel check
- 2. Once per month for channel functional test
- 3. Once per operating cycle for channel calibration B. Maximum Fraction of Limiting power Density (MFLPD)
Since changes due to burnup are slow, and only a few control rods are moved daily, a daily check of the MFLPD is adequate. The determination of the MFLPD would establish whether or not adjustment of the APRM reading is required. G(3 3.1-17
e BASES FOR LIMITING CONDITIONS FOR OPERATION 4.1.C. References I. M. Jacobs, " Reliability of Engineered Safety Features as a Function of 1. Testing Frequency," Nuclear Safety, Volume 9, No. 4, July-August, 1968, pp 303-312. ,
- 2. NE00-21617-A, " Analog Transmitter / Trip Unit System for Engineered Safe-guard Sensor Trip Inputs."
- 3. NEDE-22154-1,." Analog Trip System for Engineered Safeguard Sensor Trip Inputs - Edwin I. Hatch Nuclear Plant Units 1-and 2."
D O O 3.1-18
e w ,/ LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.2 PROTECTIVE INSTRUMENTATION 4.2 PROTECTIVE INSTRUMENTATION Applicability Applicability The Limiting Conditions for Operation The Surveillance Requirements apply to the plant instrumentation apply to the instrumentation which performs a protective function. which performs a protective function. Objective Objective
. The objective of the Limiting Condi- The objective of the Surveillance
-tions for Operation is to assure the Requirements is to specify the type operability of protective instrumen- and frequency of surveillance to tation, be applied to protective instru-mentation.
Specifications Specifications The Limiting Conditions for Operation The check, functional test, and of the protective instrumentation af- calibration minimum frequency for fecting each of the following protec- protective instrumentation affect-tive actions shall be as indicated in ing each of the following protec-("') the corresponding LC0 table. tive actions shall be as indicated
\s / in the corresponding SR table.
Protective Action LCO Table SR Table _ A. Initiates Reactor Vessel 3.2-1 4.2-1 and Containment Isolation B. Initiates or Controls HPCI 3.2-2 4.2-2 C. Initiates or Controls RCIC 3.2-3 4.2-3 *
- 0. Initiates or Controls ADS 3.2-4 4.2-4 E. Initiates or Controls the 3.2-5 4.2-5 LPCI Mode of RHR F. Initiates or Controls Core 3.2-6 4.2-6 Spray G. Initiates Control Rod Blocks 3.2-7 4.2-7 H. Limits Radioactivity Release 3.2-8 4.2-8 I. Initiates Recirculation Pump 3.2-9 4.2-9 Trip J. Monitors Leakage Into the 3.2-10 4.2-10 Drywell K. Provides Surveillance 3.2-11 4.2-11 Information L. Initiates Disconnection of 3.2-12 4.2-12 Offsite Power Sources M. Initiates Energization by 3.2-13 4.2-13 Onsite Power Sources
(~'N N. Arms the Low Low Set S/RV 3.2-14 4.2-14 (s-) System 3.2-1
(S V 'V. Table 3.2-1 . INSTRUMENTATION WHICH INITIATES REACTOR VESSEL AND PRIMARY CONTAINMENT ISOLATION Required Ref. Trip Operable Action to be taken if No. Instrument Condition Channels Trip Setting number of channels is-(c) Nomenclature per Trip not met for both trip Remarks (d) , System (b) systems (c) : 1 Reactor Vessel Low (Level 3) 2 1 8.5 inches Initiate an orderly Initiates Group 2 & 6 f Water Level Narrow Range shutdown and achieve isolation. , the Cold Shutdown Condition within 24 l hours or isolate the j shutdown cooling system. J Low Low 2 1-55 inches Initiate an orderly Starts the SGTS, w (Level 2) shutdown and achieve initiates Group 5 w the Cold Shutdown isolation, and i Condition within 24 initiates i hours. secondary containment isolation. Low Low Low 2 ->-121.5 inches Initiate an orderly Initiates Group 1 , (Level 1) shutdown and achieve isolation. the Cold Shutdown Con-dition within 24 hours. 2 Reactor Pressure High 1 1135 psig Isolate shutdown Isolates the shutdown (Shutdown Cooling cooling. cooling suction valves Mode) of the RHR system. 3 Drywell Pressure High 2 12 psig Initiate an orderly Starts the standby shutdown and achieve gas treatment system, the Cold Shutdown initiates Group 2 Condition within 24 isolation and second-hours ary containment isolation. 4 Main Steam Line High 2 < 3 times normal Initiate an orderly load InitiatesGroup 1 Radiation Tull-power reduction and close MSIVs isolation-background within 8 hours
v (y
)
~
03 -L) i ( 1 Table 3.2-2 ! L
\ '\i INSTRUMENTATION WHICH INITIATES OR CONTROLS HPCI 1
N N .. - -
' Instruknt Ref.\ . Trip Re'q uired ' Trip Setting. Remarks j C No. .
?
Condition Operable
, \(c) .
Nomenclatur( Ch mnels , S.1 per Trip x f Syst.es (b) i ,; 3
~
q +. '}
- 1. Reactor Vessel Water Level Low Low 2' > -55 inches Initiatec\ tHPCI; AlsoN initiates j (Level 2) s
' RCIC', s i 4
- 2. Drywell Pressure High 3
2 s 5 2 psig InitidesHPCI;Aso' initiates '
' \. I
_g % LPCI and Core Spray and pro- ( 3 vides a permissive signal to,, ,7 ' ss l s s A ADS. s N .s T , .
- 3. HPCI Turbine Overspeed Mechanical li l' 5000 rpm Trips HPCI turbine
' I w . -
1 4. HPCI Turbine Exhaust Pressure High - l' i 150 psig Trips HPCI turbine 1 r
- s , m . -
- s. s
- 5. HPCI Pump suction 4ressuse' .\ Low' 1 < 15' inches Trips HPCI turbine s Hg vacuum 5
- 6. Reactor Vessel Water level High 2 $ +56.5 inches Trips HPCI turbine (Level 8) 7.* HPCI System Flow High ~
1 > 800 gpm Closes HPCI minimum flow bypass (Flow Switch) line to suppression chamber. Low 1 1 500 gpm Opens HPCI minimum flow bypass line if pressure permissive is present.
- 8. HPCI Equipment Room High 1 1 175*F Closes isolation valves in HPCI system, trips HPCI turbine.
y O O O 9 e f Table 3.2-3 l. I INSTRUMENTATION WHICH INITIATES OR CONTROLS RCIC ; Raf. Instrument Trip Required Trip Setting Remarks No. Condition Operable (a) Nomenclature Channels per Trip System (b)
- 1. Reactor Vessel Water Level Low Low 2 >-55 inches Initiates RCIC; also initiates ;
(Lesel 2) HPCI.
- 2. RCIC Turbine Overspeed Electrical 1 1110% rated Trips RCIC turbine. l Mechanical 1 1125% rated Trips RCIC turbine.
- 3. RCIC Turbine Exhaust High 1 s+25 psig Trips RCIC turbine. *
,, Pressure j' 4. RCIC Pump Suction Pressure Low 1 5 15 inches Trips RCIC turbine.
oo Hg Vacuum
- 5. Reactor Vessel Water Level High 2 5+56.5 inches Trips RCIC; automatically recets (Level 8) when water drops below level 8, system automatically restarts at level 2.
- 6. RCIC System Flow High 1 >80 gpm ClosesRCICminimumflow (Flow Switch) hypass line to suppression cnamber.
Low 1 140 gpm Opens RCIC minimum flow . bypass line if pressure permissive is present.
- 7. RCIC Equipment Room High 1 5175 F Closes-isolation valves in RCIC system, trips RCIC turbine.
C-
,m ~s 7
i Table 3.2-4 ! INSTRUMENTATION WHICH INITIATES OR CONTROLS ADS I
- Rsf. Instrument Trip 3 Required Trip Setting Remarks No. , , Condition Operable (a) Nomenclature ' Channels per Trip Systein (b) -
'I
, .1. Reactor Vessel Water Level Low (Level 3) 1 18.5 inches Confirms low level, ADS permissive f y , Reactor. Vessel Water Level Low Low Low 2 - 1-121.5 inches Permissive signal to ADS timer- ' (Level 1) ,
- 2. Drywell P'ressure High 2 52 psig Permissive signal to ADS timer l 7 3. RHR Pump Discharge High 2 1100 psig Permissive signal to ADS timer - '
- y Pressure '
- 4. CS Pump Discharge High 2 1100 psig Permissive signal to ADS timer
- Pressure '
i j 5. Auto Depressurization 1 120 1 12 seconds With Level 3 and Level 1 and high { Timer - drywell pressure and CS or RHR pump j at pressure, timing sequence begins. 4 If the ADS timer is not reset it will initiate ADS. i . 4
- 6. Automatic Blowdown Control 1 Not applicable Monitors availability of power to
, Power Failure Monitor logic system
- a. The column entitled "Ref. . No." is only for convenience so that a one-to-one relationship can be established between items in Table 3.2-4 and items in Table 4.2-4.
i
- b. Whenever any CCCS subsystem is required to be operable by Section 3.5, there sh.all be two operable trip systems. If the required number of operable channels cannot be met for one of the trip systems,
~ ; that system shall be repaired or the reactor shall be placed in the Cold Shutdown Condition within l 24 hours after this trip systems is made or found to be inoperable.
3 . '
+
Table 3.2-5 INSTRUMENTATION WHICH INITIATES OR CONTROLS THE LPCI MODE OF RHR Raf. Instrument Trip Required Trip Setting Remarks No. Condition Operable (a) Nomenclature Channels per Trip System (b)
- 1. Reactor Vessel Water Level Low Low Low 2 1 -121.5 inches Initiates LPCI mode of RHR (Level 1) f
- 2. Drywell Pressure High 2 52 psig Initiates LPCI mode of RHR i
l w 3. Reactor Vessel Steam High (Shutdown 1 1 135 psig With primary containment isola- ; - Dome Pressure Cooling Mode) . tion signal, closes RHR (LPCI) 7 inboard motor operated injection ( p valves i Low 2 1 325 psig Permissive to close Recirculation l Discharge Valve and Bypass Valve Low 2 1422 psig
- Permissive to open LPCI injection l l valves
- 4. Reactor Water Level 1 1-203.5 inches Acts as permissive to divert (Shroud Level Indicator) some LPCI flow to containment spray
- 5. LPCI Cross Connect N/A 1 Valve not Initiates annunciator when valve Valve Open Annunciator ' closed is not closed -
*This trip function shall be 5500 psig. l i
Table 3.2-6 INSTRUMENTATION WHICH INITIATES OR CONTROLS CORE SPRAY Raf. Instrument Trip Required Trip Setting Remarks Ns. Condition Operable (a) Nomenclature Channels per Trip System (b)
- 1. Reactor Vessel Water Level Low Low Low 1-121.5 inches Initiates CS.
(Level 1) 2 j
- 2. Drywell Pressure ,
High 2 5 2 psig Initiates CS,
, l
- 3. Reactor Vessel Steam Dome Low 2 3 422 psig* Permissive to open CS l Pressure injection valves. 4 w 4. Core Spray Sparger 1 To be determined Monitors integrity of CS
. Differential Pressure during startup piping inside vessel and core < 7 testing shroud. ( S. CS Pump Discharge Flow Low 1 2475 gpm Minimum flow bypass.line is ! (Flow Switch) closed when low flow signal i is not present. 5
- 6. Core Spray Pump Discharge 2 2100 psig Defers ADS actuation until ,
Pressure Interlock LPCI or CS pump is confirmed to be running
- 7. Core Spray Logic Power 1 Not Applicable Monitors availability of l Failure Monitor power to logic system.
*This trip function shall be s500 psig. l c
- a. The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in Table 3.2-6 and items in Table 4.2-6.
- b. Whenever any CCCS subsystem is required to be operable by Section 3.5, there shall be two operable trip systems. If the required number of operable channels cannot be met for one of the trip systems, that ;-
system shall be repaired or the reactor shall be placed in the Cold Shutdown Condition within 24 hours after this trip system is made or found to be inoperable.
-I
${'
a) '
./
)
Table 3.2-9 INSTRUMENTATION WHICH INITIATES RECIRCULATION PUMP TRIP R:f. Instrument Trip Required Trip Setting Remarks No. Condition Operable (a) Nomenclature Channels per Trip System .
- 1. ReactorVesselgterLevel Low 1(b) > -38 inches Power must be reduced and the (ATWS RPT) mode switch placed in a mode other than the RUN Mode.
- 2. Reactor Pressure High 1(b) 11120 psig Power must be reduced and the (ATWS RPT) mode switch placed in a mode other than the RUN Mode.
- 3. E0C - RPT(d) 1. Turbine Stop 2(*)(#) 1. Stop Valve Trips recirculation pumps on Valve Closure 190% Open turbine control valve fast
- 2. Turbine Control 2. Control Valve closure or stop valve g sure Valve Fast Hydraulic when reactor is > 30%.
Closure Press Trip w Point w 4 (a) The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established o between items in Table 3.2-9 and items in Table 4.2-9. (b) Whenever the reactor is in the RUN Mode, there shall be one operable trip system for each parameter for each operating recirculation pump, except that one trip system may remain inoperable for up to 14 days. If this cannot be met, the indicated action shall be taken. (c) Anticipated Transients Without Scram - Recirculation Pump Trip (d) End of Cycle - Recirculation Pump Trip (e) Either of these two E0C - RPT systems can trip both recirculation pumps. Each E0C - RPT system will trip if 2-out-of-2 fast closure signals or 2-out of-2 stop valve signals are received. (f) The requirement for these channels applies from EOC-2000 MWD /t to E0C. The RPT system may be placed in an inoperable status for up to 2 hours to provide the required anonthly surveillance. If one E0C-RPT system is inoperable for longer than 72 hours or if both E0C-RPT systems are simultaneously inoperable, an orderly power reduction will be immediately initiated and reactor power will be <30% within the next 6 hours.
,I
L O O O Table 3.2-11 INSTRUMENTATION WHICH PROVIDES SURVEILLANCE INFORMATION Required Rgf. Operable No. Instrument Instrument- Type and (a) (b) Channels Range Action Remarks 1 Reactor Vessel Water Level 1 Recorder (c) (d) 2 Indicator 0 to 60" (c) (d) 2 Shroud Water Level 1 Recorder (c)- (d)' 1 Indicator -317" to -17" (c) (d) 3 - Reactor Pressure 1 Recorder 0 to 1500 psig (c) (d) 2 Indicator 0 to 1200 psig (c) (d) 4 Drywell Pressure 2 Recorder -5 to +80 psig (c) (d)' 5 Drywell Teaperature 2 Recorder 0 to 500 F (c) (d) . 6- Suppression Chamber Air Temperature 2 Recorder 0 to 500 F (c) (d) , h7 Suppression Chamber Water Temperature 2 Recorder 0 to 250*F (c) (d) 8 Suppression Chamber Water Level 2 Indicator 0 to 300" (c) (d) 2 Recorder 0 to 30" (c)(e) (d) 9 Suppression Chamber Pressure 2 Recorder -5 to +80 psig (c) (d) 10 Rod Position Information System (RPIS) 1 28 Volt Indicating Lights (c) (d) 11 Hydrogen and Oxygen Analyzer 1 Recorder 0 to 52 (c) (d) 12 Post LOCA Radiation Monitoring System 1 Recorder (c) (d) i Indicator 1 to 108 R/hr (c) (d) l 13 a) Safety / Relief Valve Position Primary 1/SRV Indicating Light at 85 psig (f) l Indicator b) Safety / Relief Valve Position Secondary 1 Recorder 0 to 600 F (f) l Indicator
t 'r )- qj u Table 3.2-14 INSTRUMENTATION WHICH ARMS LOW LOW SET S/RV SYSTEM Required Operable Trip Channels R2f Conditi^n per Trip No.I") Instrument Nomenclature System Trip Setting Remarks
- 1. Reactor Vessel Steam Dome High 2(b) 5 1054 psig Pressure
- 2. Relief / Safety Valve High 2/ valve 85, +15, -5 The limiting condition Tailpipe Pressure psig of operation of these switches is provided in Specification 3.6.H.I w
e w I E$ a
- a. The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in table 3.2-14 and items in table 4.2-14.
- b. With the reauirements for the minimum number of OPERABLE channels not satisfied for one trip system, place the inoperable channel in the tripped condition or declare the associated system inoperable within one hour. With therequirementsfortheminimumnumberofOPERABLEchannelsnotsatisfiedforbothtripfsystems,declarethe associated system inoperable within one hour.
t) w/ V. Tcble 4.2-1 Check, Functional Test, and Calibration Minimum Frequency for Instrumentation Which Initiates Reactor Vessel and Primary Containment Isolation Ref. Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimum Frequency Minimum Frequency Minimum Frequency 4 (a) (b) (c) 1 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Levels 1, 2, and 3) 2 Reactor Pressure None (d) Every 3 months (Shutdown Cooling Mode) i 3 Drywell Pressure None (d) , Every 3 months 4 Main Steam Line None Once/ week (e) Every 3 months (f)
- Radiation i ."
y 5 Main Steam Line None (d) Every 3 months y Pressure , 6 Main Steam Line Flow None (d) Every 3 months ! 7 Main Steam Line Tunnel None Once/ operating cycle Once/ operating cycle Temperature i 8 Reactor Water Cleanup None (d) Every 3 months
- System Differential Flow -
j 9 Reactor Water Cleanup None (d) Every 3 months 3 Equipment Room , i Tempera ture i 1 I i
(" . {
-Table 4.2-2 Check, Functional Test, and Calibration Minimum Frequency for Instrumentation Which Initiates or Controls HPCI-Ref. Instrument Check Instrument functional Test Instrument Calibration No. Instrument Minimum Frequency Minimus Frequency. Minimum Frequency (a) (b) (c) l' Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Level 2) 2 Drywell Pressure None (d) Every 3 months 3 HFCI Turbine Overspeed None N/A Once/ operating cycle w 4 HPCI Turbine Exhaust None (d) Every 3 months g Pressure h5 HPCI Pump Suction Pressure None (d) Every 3 months i 6 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (
(Level 8) 7 HPCI System Flow None (d) Every 3 months (Flow Switch) 8 HPCI Equipment Room None (d) Every 3 months 9 deleted 10 HPCI Steam Line Pressure None (d) Every 3 months
O O O Table 4.2-3 I Check, Functional Test, and Calibration Minimum Frequency for Instrumentation Which Initiates or Controls RCIC Raf. Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimum Frequency Minimum Frequency Minimum Frequency (a) (b) (c) 1 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Level 2) 2 RCIC Turbine Overspeed Electrical / None N/A Once/ operating cycle Mechanical None N/A Once/ operating cycle m 3 RCIC Turbine Exhaust None (d) Every 3 months - Pressure I w 4 RCIC Pump Suction Every 3 months None (d) Pressure 5 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Level 8) 6 None (d) Every 3 months RCIC SgstegFlow 7 RCIC Equipment Room None (d) Every 3 months 8 deleted 9 RCIC Steam Line Pressure None (d) Every 3 months I
2 Table 4.2-4 Check, Functional Test, and Calibration Minimum Frequency for Instrumentation Which Initiates or Controls ADS Ref. Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimum Frequency Minimus Frequency Minimum Frequency ? (a) (b) . (c) > ] l 1 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle i (Level 3) i > l Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle i (Level 1) 1 2 Drywell Pressure None -(d) Every 3 months 3 RHR Pump Discharge (d) Every 3 months j .[i Pressure None
- O j 4 CS Pump Discharge None (d) Every 3 months Pressure l (
) 5 Auto Depressurization None N/A Once/ operating cycle Timer l l 6 Automatic Blowdown None Once/ operating cycle None 1 4 Control Power Failure *
; Monitor i
I Notes for Table 4.2-4 2 The column entitled "Ref. No." is only for convenience so that a one-to-one. relationship can be ) a. established between items in Table 4.2-4 and items in Table 3.2-4. i i
! k
O O O l Table 4.2-5 Check, Functional Test, and Calibration Minimum Frequency for Instrumentation Which Initiates or Controls the LPCI Mode of RHR ; Raf. Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimum Frequency Minimum Frequency Minimum
- Frequency (a) (b) (c) 1 Reactor Vessel Water Level Once/ shift Once/ month Once/ operating cycle (Level 1) 2 Drywell Pressure None (d) Every 3 months 3 Reactor Vessel Steam Once/ shift Once/ month Once/ operating cycle Dome Pressure 4 Reactor Water Level Once/ day (d) Every 3 months
, (Shroud Level Indicator) < ';) 5 LPCI Cross Connect Valve None Once/ Operating cycle None w Open Annunciator 6 RHR (LPCI) Pump Discharge None (d) Every 3 months , Pressure Interlock . 7 RHR (LPCI) Pum . None (d) Every 3 months (Flow Switch) p Flow 8 RHR (LPCI) Pump . None N/A Once/ operating cycle Start Timers . 9 Valve Selection Timers None N/A Once/ operating cycle 10 RHR Relay Logic Power None Once/ operating cycle None Failure Monitor (
fy
. V/ m n)
(_. U-Table 4.2-6 Check, Functional Test, and Calibration Minimum Frequency for Instrumentation Which Initiates or Controls Core Spray 1 Raf. . Instrument Check Instrument Functional Test Instrument Calibration No. Instrument Minimum Frequency Minimum Frequency Minimum Frequency-(a) - (b) (c) 1 Reactor Vessel Water Level Once/shif t Once/ month Once/ operating cycle (Level 1) 2 Drywell Pressure None (d) Every 3 months 3 Reactor Vessel Steam Dome Once/ shift Once/ month Once/ operating cycle Pressure w
- , 4 Core Spray Sparger Once/ day N/A Once/ operating cycle i Differential Pressure 5 CS Pump Discharge Flow None (d) Every 3 months (Flow Switch) 6 Core Spray Pump Discharge None (d) Every 3 months Pressure Interlock 7 Core Spray Logic Power None Once/ operating cycle None Failure Monitor Notes for Table 4.2-6
- a. The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in Table 4.2-6 and items in Table 3.2-6. >
Table 4.2-9 CHECK AND CALIBRATION MINIMUM FREQUENCY FOR INSTRUMENTATION WHICH INITIATES RECIRCULATION PUMP TRIP Raf. Instrument Check Instrument functional Test Instrument Calibration No. Instrument Minimum Frequency Minimum Frequency Minimum Frequency (a) 1 ReactorVessel(gterLevel Once/ day. Once/ operating cycle Once/ operating cycle l (ATWS RPT). 2 Reactor Pressure None Once/ operating cycle Once/ operating cycle (ATWS RPT) 3 E0C - RPT Trip a) Initiating Logic None Once/ month None ." b) Breakers None Once/ operating cycle None y c) Response Time -None None Once/ operating cycle g RPT logics + Breakers Notes for Table 4.2-9 (a) The column. entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in Table 3.2-9 and items in Table 4.2-9. (b) An ATWS recirculation pump trip logic system functional test shall be performed once per operating cycle. O
i O O O Table 4.2-14 CHECK, FUNCTIONAL TEST, AND CALIBRATION MINIMUM FREQUENCY FOR INSTRUMENTATION WHICH ARMS THE. LOW LOW SET.S/RV SYSTEM Raf Instrument Check No.g ,) InstrumentFunctional(fgst InstrumentCalibratgg Instrument Minimum Frequency Minimum Frequency Minimum Frequency ) 1 Reactor Vessel Steam Dome Once/ shift Once/ month Once/ operating cycle Pressure 2 Relief / Safety Valve Tailpipe N/A Once/ month (d) O xe/ operating cycle (e) h Pressure 7 0 o
- a. The column entitled "Ref. No." is only for convenience so that a one-to-one relationship can be established between items in table 4.2-14 and items in table 3.2-14.
- b. Instrument functional tests are not required when the instruments are not required to be operable or are tripped. s However, if functional tests are missed, they shall be performed prior to returning the instrument to an operable status.
- c. Calibrations are not required when the instruments are not required to be operable. However, if calibrations are missed, they shall be performed prior to returning the instrument to an operable status. ,
?
- d. See section 4.6.H.1.e.1 for exceptions to this pressure switch functional test frequency.
- e. See section 4.6.H.1.e.2.
BASES FOR LIMITING CONDITIONS FOR OPERATION O 3.2 PROTECTIVE INSTRUMENTATION kJ In addition to the Reactor Protection System (RPS) instrumentation which in-itiates a reactor scram, protective instrumentation has been provided which initiates action to mitigate the consequences of accidents which are beyond the operators ability to control, or terminates operator errors before they result in serious consequences. This set of Specifications provides the lim-iting conditions for operation of the instrumentation: (a) which initiates reactor vessel and primary containment isolation, (b) which initiates or controls the core and containment cooling systems, (c) which initiates control rod blocks, (d) which initiates protective action, (e) which monitors leakage into the drywell and (f) which provides surveil-lance information. The objectives of these specifications are (i) to assure the effectiveness of the protective instrumentation when required by preserv-ing its capability to tolerate a single failure of any component of such sys-tems even during periods when portions of such systems are out of service for maintenance, and (ii) to prescribe the trip settings required to assure ade-quate performance. When necessary, one channel may be made inoperable for brief intervals to conduct required functional tests and calibrations. A. Instrumentation Which Initiates Reactor Vessel and Primary Containment Isolation (Table 3.2-1) Isolation valves are installed in those lines which penetrate the primary con-tainment and must be isolated during a lo'ss of coolant accident so that the radiation dose limits are not exceeded during an accident condition. Actua-O tion of these valves is initiated by protective instrumentation shown in Table V 3.2-1 which senses the conditions for which isolation is required. Such in-strumentation must be available whenever primary containment integrity is re-quired. The objective is to isolate the primary containment so that the guidelines of 10 CFR 100 are not exceeded during an accident. The events when isolation is required are discussed in Appendix G of the FSAR. The instrumentation which initiates primary system isolation is connected in a dual bus arrangement.
- 1. Reactor Vessel Water Level
- a. Reactor Vessel Water Level Low (Level 3) (Narrow Range)
The reactor water level instrumentation is set to trip when reactor water level is approximately 14 feet above the top of the active fuel. This level is referred to as Level 3 in the Technical S'pect-fications and corresponds to a reading of 8.5 inches on the Narrow Range Scale. This trip initiates Group 2 and 6 isolation but does not trip the recirculation pumps.
- b. Reactor Vessel Water Level Low Low (Level 2) g The reactor water level instrumentation is set to trip when reactor water level is approximately 8 feet above the top of the active fuel. This level is referred to.as Level 2 in the Technical Speci-fications and corresponds to a reading of -55 inches.
f) This trip initiates Group 5 isolation, starts the standby gas U treatment system, and initiates secondary containment isolation. 3.2-50
- . _ , _ . - . __ ._= - . - _ . -. .-. . -,- . . - . .. . -
BASES FOR LIMITING CONDITIONS FOR OPERATION ! 3.2.A.1.c. Reactor Vessel Water Level Low Low Low (Level 1) The reactor water level instrumentation is set to trip when the reactor water leve,l is approximately 43, inches above the top of , the active fuel. This level is referred to as Level 1 in the Technical Specifications and corresponds to a reading
- of -121.5 inches. This trip initiates Group 1 isolation.
O-i l 1 1 i t 3.2-50a
, , - - ,--,._,e ,;m.- ,m- ,,n-, , . , - , , , . , , ._y,..,,,m,v,w,ng.. ,,w.m ,...yw--. yww.-v-.,
e BASES FOR LIMITING CONDITIONS FOR OPERATION
^
3.2.A.7 Main Steam Line Tunnel Temperature High (Continued)
~
with the resultant small release of radioactivity, gives isolation before the guidelines of 10 CFR 100 are exceeded.
- 8. Reactor Water Cleanuo System Differential Flow High Gross leakage (pipe break) from the reactor water cleanup system is detected by measuring the difference of flow entering and leaving the system. The set point is low enough to ensure prompt isolation of the cleanup system in the event of such a break but, not so low that spurious isolation can occur due to normal system flow fluctuations and instrument noise. Time delay relays are used to prevent the isola-tion signal which might be generated from the initial flow surge when the cleanup system is started or when operational system adjustments are made which produce short term transients.
- 9. Reactor Water Cleanup Equipment Room Temperature High and
- 10. Reactor Water Cleanup Equipment Room Differential Temperature Hfgh Leakage in the high temperature process flow of the reactor water cleanup system external to the primary containment will be detected by temperature sensing elements. Temperature sensors are located in the inlet and outlet ventilation ducts to measure the temperature difference. Local ambient temperature sensors are located in the compartment containing equipment and Q piping for this system. An alarm in the main contrul room vill be set to i ' annunciate a temperature rise corresponding to a leakage.within the identi-fled limit. In addition to annunciation, a high cleanup room temperature will actuate automatic isolation of the cleanup system.
- 11. Condenser Vacuum Low The Bases for Condenser Vacuum Low are discussed in The Bases for Specifica-tion 2.1.A.7.
B. Instrumentation Which Initiates or Controls HPCI (Table 3.2-2)
- 1. Reactor Vessel Water Level Low Low (Level 2)
The reactor vessel water level instrumentation setpoint which initiates HPCI is 2 -55 inches. This level is approximately 8 feet above the top of the active fuel and in the Technical Specifications is refer-red to as Level 2. The reactor vessel low water level setting for HPCI system l initiation is selected high enough above the active fuel to start the HPCI system in time both to prevent excessive fuel clad temperatures and to pre-vent more than a small fraction of the core from reaching the temperature at which gross fuel failure occurs. The water level setting is far enough below normal levels that spurious HPCI system startups are avoided.
- 2. Drywell Pressure High O The d twell pressure instrumentation setpoint with initiates HPCI is s 2 l
psig. High drywell pressure is indicative of a failure of the nuclear system process barrier. This pressure is selected to De as low as possible without inducing spurious HPCI system startups. This instrumentation ser-
~
ves as a backup to the water level instrumentation described above. 3.2-52
~
E BASES FOR LIMITING CONDITIONS FOR OPERATION O 3.2.B.3 HPCI Turbine Overspeed LJ The HPCI turbine is automatically shut down by tripping the HPCI turbine stop valve closed when the 5000 rpm setpoint on the mechanical governor is reached. A turbine overspeed trip is required to protect the physi-cal integrity of the turbine.
- 4. HPCI Turbine Exhaust Pressure High When HPCI turbine exhaust pressure reaches the setpoint (s 150 psig) the HPCI turbine is automatically shut down by tripping the HPCI stop valve closed.
HPCI turbine exhaust high pressure is indicative of a condition which threat-ens the physical integrity r.f the exhaust line.
- 5. HPCI Pump Suction Pressure Lq A pressure switch is used to detect HPCI system pump suction pressure and is set to trip the HPCI turbine at 15 inches of mercury vacuum.
This setpoint is chosen to prevent pump damage by cavitation.
- 6. Reactor Vessel Water Level High (Level 8) i A reactor water level of +56.5 inches is indicative that the HPCI system has performed satisfactorily-in providing makeup water to the reactor vessel. The reactor vessel high water level setting which trips the HPCI turbine is near the top of the steam separators and is sufficient to A prevent gross moisture carryover to the HPCI turbine. Two analog dif-(.) ferential pressure transmitters trip to initiate a HPCI turbine shutdown.
- 7. HPCI System Flow To prevent damage by overheating at reduced HPCI system pump flow, a pump discharge minimum flow bypass is provided. The bypass is controlled by an automatic, D. C. motor-operated valve. A high flow signal from a flow meter downstream of the pump on the main HPCI line will cause the bypass valve to close. Two signals are required to open the valve: A HPCI pump discharge pressure switch high pressure signal must be received to act as a permissive to open the bypass valve in the presence of a low flow signal from the flow switch.
NOTE: Because the steam supply line to the HPCI turbine is part of the nuclear system process barrier, the following con-ditions (8-13) automatically isolate this line, causing shutdown of the HPCI system turbine.
- 8. HPCI Equipment Room Temperature High High ambient temperature in the HPCI equipment rum near the emergency area cooler could indicate a break in the HPCI sys em turbine steam line.
The automatic closure of the HPCI steam line valves prevents the ex-r cessive loss of reactor coolant and the release of significant amounts of l (]) radioactive material from the nuclear system process barrier. The high i l 3.2-53
BASES FOR LIMITING CONDITIONS FOR OPERATION 3.2.B.13 Suppression Chamber Area Differential Air Temperature High As for the HPCI equipment room differential temperature, and for the same reason, a differential air temperature greater than the trip setting of s 42 F between the inlet and outlet ducts which ventilate the suppression chamber area will initiate a timer to isolate the HPCI turbine steam line. ..
- 14. Condensate Storage Tank Level Low The CST is the preferred source of suction for HPCI. In order to provide an adequate water supply, an indication of low level in the CST automat-ically switches the suction to the suppression chamber. A trip setting of 0 inches corresponds to 10,000 gallons of water remaining in the tank.
- 15. Suppression Chamber Water Level High A high water level in the suppression chamber automatically switches HPCI suction to the suppression chamber from the CST.
- 16. HPCI Logic Power Failure Monitor The HPCI Logic Power Failure Monitor monitors the availability of power to the logic system. In the event of loss of availability of power to the logic system, an alarm is annunciated in the control room.
C. Instrumentation Which Initiates or Controls RCIC (Table 3.2-3)
- 1. Reactor Vessel Water Level Low Low (Level 2) l The reactor water level instrumentation setpoint which initiates RCIC is 2
-55 inches. This level is approximately 8 feet above the top of the active fuel and is referred to as Level 2. This setpoint insures that RCIC is started in time to preclude conditions which lead to inade-quate core cooling.
- 2. RCIC Turbine Overspeed The RCIC turbine is automatically shutdown by tripping the RCIC turbine stop valve closed when the 125% speed at rated flow setpoint on the mech-anical governor is reached. Turbine overspeed is indicative of a condi-tion which threatens the physical integrity of the system. An electrical tachometer trip setpoint of 110'.' also will trip the RCIC turbine stop valve closed.
- 3. RCIC Turbine Exhaust Pressure High When RCIC turbine exhaust pressure reaches the setpoint (s 25 psig), the RCIC turbine is automatically shut down by tripping the RCIC turbine stop valve closed. RCIC turbine exhaust high pressure is indicative of a con-dition which threatens the physical integrity of the exhaust line.
- 4. RCIC Pump Suction Pressure Low
) One pressure switch is used to detect low RCIC system pump suction pressure and is set to trip the RCIC turbine at s 15 inches of mercury vacuum. This setpoint is choosen to prevent pump damage by cavitation. 3.2-55
BASES FOR LIMITING CONDITIONS FOR OPERATION
-3.2.C.5 Reactor Vessel Water Level High (Level 8)
-{
- A high reactor water level trip is indicative that the RCIC system has performed satisfactorily in providing makeup water to the reactor vessel.
The reactor vessel high water level setting which trips the RCIC turbine is near the top of the steam separators gnd sufficiently low to prevent gross
- moisture carryover to the RCIC turbine. Two differential pressure trans-mitters trip to initiate a RCIC turbine shutdown. Once tripped the system is capable of automatic reset after the water level drops below Level 8.
This automatic reset eliminates the need for manual reset of the system before the operator can take manual control to avoid fluctuating water levels.
- 6. RCIC System Flow To prevent damage by overheating at reduced RCIC system pump flow, a pump discharge minimum flow bypass is provided. The bypass is controlled by a.n automatic, D. C. motor-operated valve. A high flow signal from a flow meter downstream of the pump on the main RCIC line will cause the bypass valve to close. Two signals are required to open the valve: A RCIC pump discharge pressure switch high pressure signal ist be received to act as a permissive to open the bypass valve in the prc ice of a low flow signal from the flow switch.
Note:
,A Because the steam supply line to the RCIC turbine is part of i
d the nuclear system process barrier, the following conditions (7 - 13) automatically isolate this line, causing shutdown of the RCIC system turbine.
- 7. RCIC Equipment Room Temperature High l High ambient temperature in the RCIC equipment room near the emergency area cooler could indicate a break in the RCIC system turbine steam line.
The automatic closure of the RCIC steam line valves prevents the exces-sive loss of reactor coolant and the release of significant amounts of radioactive material from the nuclear system process barrier. The high temperature setting of 90 F + ambient was selected to be far enough above anticipated normal RCIC system operational levels to avoid spurious isolation but' low enough to provide timely detection of a RCIC turbine steam line l break. The high temperature trip initiates a timer which isolates the RCIC l turbine steam line if the temperature is not reduced below the setpoint.
- 8. RCIC Steam Line Pressure Low Low pressure in the RCIC steam supply could indicate a break in the RCIC l steam line. Therefore, the RCIC steam line isolation valves are auto-matically closed. The steam line low pressure function is provided so that in the event a gross rupture of the RCIC steam line occurred up-stream from the high flow sensing location, thus negating the high flow indicating function, isolation would be effected on low pressure. The iso-
, 'v 3.2-56 i
BASES FOR LIMITING CONDITIONS FOR OPERATION (T 0. Instrumentation Which Initiates or Controls ADS (Table 3.2-4) l C/ The ADS is a backup system to HPCI. In the event of its failure
- to maintain reactor water level, ADS will initiate depressurization of the reactor in time for LPCI and CS to adequately cool the core. Four
, signals are required to initiate ADS: tow water level, confirmed low water level, high drywell pressure, and either a RHR or Core Spray
. pump available. The simultaneous presence of these four signals will initiate a 120 second timer which will depressurize the reactor if not reset.
- 1. Reactor Vessel Water Level
- a. Reactor Vessel Water Level Low (Level 3)
The second reactor vessel low water level initiation setting (+8.5 inches) is selected to confirm that water level in the l vessel is in fact low, thus providing protection against inadvertent depressurization in the event of an instrument line (water level) failure. Such a failure could produce a simultaneous high drywell pressure. *A confirmed low level is one of four signals required to initiate ADS.
- b. Reactor Vessel Water Level Low Low Low (Level 1)
The reactor vessel low water level setting of -121.5 inches is selected to provide a permissive signal to open the relief valve {T x_ ,/ and depressurize the reactor vessel in time to allow adequate cooling of the fuel by the core spray and LPCI systems following a LOCA in which the other make up systems (RCIC and HPCI) fail to maintain vessel water level. This signal is one of four required to initiate ADS.
- 2. Drywell Pressure High A primary containment high pressure of 2 2 psig indicates that a breach of the nuclear system process barrier has occurred inside the drywell. The signal is one of four required to initiate the ADS. .
e 9 U 3.2-58 l
BASES FOR LIMITING CONDITIONS FOR OPERATION ('~) 3.2.0. 3. RHR Pump Discharge Pressure High G An RHR pump discharge pressure of 2 100 psig indicates that LPCI flow is available when the reactor is depressurized. The presence of this signal means low pressure core standby cooling is available. Low pressure core standby cooling available is one of the four signals required to initiate ADS.
- 4. Core Spray Pump Discharge Pressure High A core spray pump discharge pressure of 2 100 psig indicates that Core Spray flow is available when the reactor is depressurized.
The presence of this signal means low pressure core standby cooling is available. Low pressure core standby cooling available is one of the four signals required to initiate ADS.
- 5. Auto Depressurization Timer The 120-second delay time setting is chosen to be long enough so that the HPCI system has time to start, yet not so long that the core spray system and LPCI are unable to adequately cool the core if HPCI fails to start. An alarm in the main control room is annunciated each time either of the timers is timing. Resetting the automatic depressurization system logic in the presence of tripped initiating signals recycles the timers.
r N 6. Automatic Blowdown Control Power Failure Monitor
'D The Automatic Blowdown Control Power Failure Monitor monitors the availability of power to the logic system. In the event of loss of
-availability of power to the logic. system, an alarm is annunciated in the control room.
E. Instrumentation Which Initiates or Controls.the LPCI Mode of RHR l (Table 3.2-5)
- 1. Reactor Vessel Water Level Low Low Low (Level 1)
Reactor vessel low water level (Level 1) initiates LPCI and indi-cates that the core is in danger'of being overheated because of ' an insufficient coolant inventory. This level is sufficient to allow the timed initiation of the various valve closure and loop selection routines to go to completion and still successfully perform its design function. l a 3.2-59
.w w - . , ,
i l l BASES FOR LIMITING CONDITIONS FOR OPERATION
- 2. Drywell Pressure High I ()T l- Primary containment high pressure is indicative of a break in the I
nuclear system process barrier inside the drywell. The high drywell pressure setpoint of s 2 psig is selected to be high enougi; to avoid spurious starts but low enough to allow timely system initiation.
- 3. Reactor Vessel Steam Dome Pressure Low l
The Bases for Reactor Pressure (Shutdown Cooling Mode) are discussed in the Bases for Specification 3.2.A.2. With an analytical limit of 2 300 psig and a nominal trip setpoint of 360 psig, the recirculation discharge valve will close successfully during a LOCA condition. Once the LPCI system is initiated, a reactor low pressure setpoint of 422 psig produces a signal which is used as a permissive to open the LPCI in-l l O i lO 3.2-60* i l
~_ _ _
BASES FOR LIMITING CONDITIONS FOR OPERATION 'y'~') 3.2.E.9 Valve Selection Timers v After 10 minutes, a timer cancels the LPCI signals to the injection valves. The cancellation of the signals allows the operator to divert the water for other post-accident purposes. Cancellation of the signals does not cause t.ie injection valves to move.
- 10. RHR Relay Logic Power Failure Monitor The RHR Relay Logic Power Failure Monitor monitors the availability of power to the logic system. In the event of loss of availability of power to the logic system, an alarm is annunciated in the control room.
F. Instrumentation Which Initiates or Controls Core Spray (Table 3.2-6)
- 1. Reactor Vessel Water Level Low Low Low (Level 1)
A reactor low water level of -121.5 inches (Level 1) initiates Core Spray. This level is indicative that the core is in danger of being overheated because of an insufficient coolant inventory.
- 2. Drywell Pressure High Primary containment high pressure is indicative of a break in the nuclear system process barrier inside the drywell. The high drywell pressure set-point of s 2 psig is selected to be high enough to avoid spurious system
/~'} initiation but low enough to allow timely system initiation, v
- 3. Reactor Vessel Steam Dome Pressure Low Once the core spray system is initiated, a reactor low pressure setpoint of 422 psig produces a signal which is used as a permissive to open the core l
. spray injection valves. The valves do not open,.however, until reactor pres-sure falls below the, discharge head of the core spray system.
-4. Core Spray Sparger Differential Pressure A detection system is provided to continuously confirm the integrity of the core spray piping between the inside of the reactor vessel and t.he core shroud. A differential pressure switch measures the pressure difference be-tween the top of the core support plate and the inside of the core spray sparger pipe just outside the reactor vessel. If the core spray sparger pip-ing is sound, this pressure difference will be the pressure drop across the core resulting from inter-channel leakage. If integrity is lost, this pres-sure drop will include the steam separator pressure drop. An increase in the normal pressure drop initiates an alarm in the main control room.
l l / , i (- } j . 3.2-62 l
BASES FOR LIMITING CONDITIONS FOR OPERATION M. Instrumentation Which Initiates Energization by Onsite Power Sources (Table (N_ x_,) 3.2-13) . The undervoltage relays shall automatically trip the loss of offsite power (LOSP) Jockout relays if voltage is lost on the emergency buses and low voltage is sensed on start-up transformer 1C (SVT IC). This lockout will, if a loss of coolant accident (LOCA) has previously occurred, cause energization of the emergency 4160 volt buses by the Diesel Generators (D/Gs). If the LOSP and LOCA occur simultaneously, the lockout relay will provide a permissive allowing D/G output breaker closure when the D/G voltage is up to normal. The undervoltage relays will have no time delay. The absence of time delay provides a faster response time if the diesel generator has been previously initiated and prevents an additional time delay if it has not. This scheme prevents the connection of the 0/G to the offsite power source. N. Instrumentation Which Arms Low Low Set System (Table 3.2-14) The bases for these trip functions are found in the bases for Section 3.6.H, page 3.6-21. 3.2.1 References
- 1. FSAR Appendix G, Plant Nuclear Safety Operational Analysis
- 2. FSAR Section 7.3, Primary Containment and Reactor Vessel Isolation
("'S Control System V
- 3. FSAR Section 14, Plant Safety Analysis
- 4. FSAR Section 6, Core Standby Cooling Systems
- 5. FSAR Section 14.4.4, Refueling Accident
- 6. FSAR Section 6.5.3, Integrated Operation of the Core Standby Cooling Systems
- 7. FSAR Section 6.5.3.1, Liquid Line Breaks
- 8. 10 CFR 100 i
3.2-68a l
BASES FOR LIMITING CONDITIONS FOR OPERATION A 4.2 PROTECTIVE INSTRUMENTATION U The instrumentation listed in Tables 4.2-1 thru 4.2-13 will be functionally tested and calibrated at regularly scheduled intervals. .The same design re- . liability goal'as the Reactor Protection System of 0.99999 is generally applied for all applications of one-out-of-two-taken-twice logic. Therefore, on-off sensors are tested once every three months, and bi-stable trips associated with analog sensors and amplifiers are tested once per week. The ATTS instruments are tested once per month per NE00-21617-A. Those instruments which, when tripped, result in a rod block have their contacts arranged in a one-out-of-n logic, and all are capable of being bypassed. For such a tripping arrangement with bypass capability provided, there is an optimum test interval that should be maintained in order to maximize the reliability of a given channel (Reference 1). This takes account of the fact that testing degrades re-liability and the optimum interval between tests is approximately given by: 1= b r Where: 1 = the optimum interval between tests. t = the time the trip contacts are disabled from performing their function while the test is in progress.
, r = the expected failure rate of the relays.
O v To test the trip relays requires that the channel be bypassed, the test made, and the system returned to its initial state. It is assumed this task requires an es-timated 30 minutes to complete in a thorough.and workmanlike manner and that the relays have a failure rate of 10
- failures per hour,. Using this data and the above operation, the optimum test interval is:
i= 2(0.5) = 108 hours 10-'
= 42 days A test interval of once per-month will be used initially.
The sensors and electronic apparatus have not been included here as these are ana-log devises with readouts in the control room and the sensors and electronic ap-paratus can be checked by comparison with other like instruments. The checks which are made on a daily or once per shift basis are adequate to assure oper-ability of the sensors and electronic apparatus, and the test interval given l above provides for optimum testing of the relay circuits. The above calculated test interval optimizes each individual channel, considering it to be independent of all others. As an example, assume that there are two channels with an individual technician assigned to each. Each technician tests his channel at the optimum frequency, but the two technicians are not allowed to communicate so that one can advise the other that his channel is under test. Un-der these conditions, it is possbile for Loth channels to be under test simultane-ously. Now, assume that the technicians are required to communicate and that two 3.2-69
LIMITING CONDITIONS FOR OPERATION __ SURVEILLANCE REQUIREMENTS ( 3 3.6.H.1. Relief / Safety Valves f l 4.6.N.1. Relief / Safety Valves ! v a. When one or more relic'f/ safety I a. End of Operating Cycle l valve (s) is known to be failed an orderly shutdown shall be initiated Approximately one-half of all and the reactor depressurized to relief / safety valves shall be less than 113 psig within 24 hours, benchchecked or replaced with Prior to reactor stbrtup from a a benchchecked valve each re-cold condition all relief / safety fueling outtge. All 11 valves valves shall be operable, will have toen checked or re-placed upon the completion of every second operating cycle.
- b. With one or more relief / safety l b. Each Operating Cycle valve (s) stuck open, place the reactor mode switch in the shutdown position. Once during each operating cycle, at a reactor pressure
> 100 psig each relief valve shall be manually opened until thermocouples downstream of the valve indicate steam is flow-ing from the valve.
- c. With one*or more safety /*elief valve c. Integrity of Relief Valve tailpipe pressure switches of a Bellows" safety / relief valve declared inoperaale and the associated The integrity of the relief m safety / relief valve (s) otherwise bellows shall be continuously indicated to be open, place the monitored and the pressure (d
)
reactor mode switch in the Shut- switch calibrated once per down position, operating cycle and the accu-
' mulators and air piping shall be inspected for leakage once per operating cycle.
- d. With one safety / relief valve tailpipe d. Relief Valve Maintenance l pressure switch of a safety / relief valve declared inoperable and the asso- At lease one relief valve shall ciated safety / relief valve (s) otherwise be dissassembled and inspected indicated to be closed, plant operation each operating cycle.
may continue. Remove the function of that pressure switch fron the low low e. Operability of Tail pipe l set logic circuitry until the next COLD Pressure Switches i SHUTOOWN. Upon COLD SHUTDOWN, restore the pressure switch (es) to OPERABLE The tail pipe pressure switch status before STARTUP. of each relief / safety valve shall be demonstrated operabis
- e. With both safety / relief valve tailpipe by performance of a:
pressure switches of a safety / relief valve declared inoperable and *he asso- 1. Functional Test: ciated safety / relief valve (s) etherwise indicated to be closed, restore at least a. At least once per 31 one inoperable switch to OPERABLE status days, except that all within 14 days or be in at least HOT portions of instrumen-r~N SHUTOOWN within the next 12 hours tation inside the pri-() ~ and in COLO CHUTDOWN within the following 24 hours. mary containment may be excluded from the functional text, and "D;es not apply to t4o-,tago Target Rock $RVs - 3.6-9
LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 4.6.H.1 Relief / Safety Valves (Continued) {
- e. Operability of Tail Pipe l Pressure Switches
- 1. Functional Test: I
- b. At each scheduled out- I age greater than 72 hours during which en-try is made into the primary containment, if not performed with-in the previous 31 days.
- 2. Calibration and verifying l the setpoint to be 85, +15,
-5 psig at least once per 13 months.
3.6.H.2 Relief / Safety Valves Low Low 4.6.H.2 Relief / Safety Valves low Low Set Function Set Function During power operation startup, The low low set relief valve func-and hot standby, the relief tion and the low low set function valve function and the low low pressure actuation instrumenta-(o
) set function of the following reactor coolant system safety /
tion shall be demonstrated OPERABLE by performance of a: relief valves shall be OPERABLE with the following low low set a. CHANNEL FUNCTIONAL TEST, function lift settings: including calibration of the trip unit and the dedicated Low Low Set Allowable Value (psig)* high steam doma pressure Valve Function Open Close channels **, at least once per month. Low s 1005 s 857 Medium s 1020 s 872 b. CHANNEL CALIBRATION, Logic Medium High s 1035 s 887 System Functional Test, and High s 1045 s 897 simulated automatic operation of the entire system at least
- a. With the relief valve function and/or once per 18 months, the low low set function of one of the above required reactor coolant system safety / relief valves inoper-able, restore the relief valve func-tion and the low low set function to OPERABLE status witnin 14 days or be in at least HOT SHUTDOWN within the next 12 hours and COLD SHUT 00WN within the following 24 hours.
a The lift setting pressure shall correspond to ambient conditions of the valves (O) at nominal operating temperatures and pressures. Co The setpoint for dedicated high steam dome pressure changels is s 1054 psig. 3.6-9a
F-t LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENiS - ( ' b. With the relief valve function ~( and/or the low low set function of more than onesof the above required reactor coolant system relief / safety valves inoperable, be in at least HOT SHUTDOWN with-in 12 hours and in COLD SHUTDOWN within the next 24 hours. 3.6.I Jet Pumps 'e. , I. Jet Pumps Whenever the reactor'is in:the Whenever both recirculating pumps Start & Hot Standby or Run Mode are operating with the reactor in with both recirculating pumps the Start & Hot Standby or Run operating, all. jet pLmps shall be Mode, jet pump operability shall operable. Ifsit is determined that - be checked daily by verifying that a jet pump is\ inoperable, an orderly , the following conditions do not shutdown shall be initiated and the occur simultaneously. reactor shall be in the Cold Shut-down Condition with in 24' hours. 1. The two recirculation loops
- have a flow imbalance of 15%
s< or more when the pumps are operated at the same speed. -G . f
-,- 3.6-9b
i V BASES FOR LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 3.6.H. Relief / Safety Valves (Continued) Experience in relief / safety valve operation shows that a testing of 50 per-cent of the valves per year is adequate to detect failure or deteriorations. The relief / safety valves are benchtested every second operating cycle to ensure that their set points are within the tolerance given in Specification 2.2.A. The relief / safety valves are tested in place at low reactor pressure once per operating cycle to establish that they will open and pass steam. The requirements established above a~p ply when the nuclear system can be pres-surized above ambient conditions. These requirements are applicrble at nu-clear. system pressures below normal operating pressures because abnormal operational transients could possibly start at these conditions such that eventual overpressure relief would be needed. However, these transients are much less severe in terms of pressure, than those starting att rated condi-tions. The valves need not be functional when the vessel head is removed, since the nuclear system cannot be pressurized. The low low set (LLS) system lowers the opening and closing setpoints on four preselected relief / safety valves. The LLS system lowers the setpoints after any relief / safety valve has opened at its normal steam pilot setpoint when a concurrent high reactor vessel steam dome pressure scram signal is present. The purpose of the LLS is to mitigate the induced high frequency loads on r the containment and thrust loads on the SRV discharge line. The LLS system (]/ increases the amount of reactor depressurization during a relief / safety valve blowdown because the lowered LLS setpoints keep the four selected LLS relief / safety valves open for a longer time. The high reactor vessel steam dome pressure signal for the LLS logic is provided by the exclusive analog trip channels. The purpose of installing special dedicated steam dome pres-sure channels is to maintain separation from the RPS high pressure scram fun.ctions. I. Jet pumps Failure of a jet pump nozzle assembly hold down mechanism, nozzle assembly and/or riser, would increase the cross-sectional flow area for blowdown fol-lowing the design basis double ended line break. Therefore, if a failure occurred, repairs must be made. The detection technique is as follows. With the two recirculation pumps balanced in speed to within + 5%, the flow rates in both recirculation loops will be verified by control room monitoring instruments. If the two flow rate values do not differ by more than 10%, riser and nozzle assembly integrity has been verified. If they do differ by 10% or more, the core flow rate measured by the jet pump diffuser differential pressure system must be checked against the core flow rate derived from the measured values of loop flow to core flow correlation. If the difference between measured and derived core flow rate is 10% or more (with the derived value higher) diffuser measurements will be tale 'o define the location within the vessel O of failed jet pump nozzle (or riser.i and the plant shut down for repairs. b 3.6-21
(/ BASES FOR LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 3.6.I. Jet Pumps (Continued) If the potential blowdown flow area is increa' sed, the system resistance to the recirculation pump is also reduced; hence, the affected drive pump will "run out" to a substantitally higher flow rate (approximately 115% to 120% for a single nozzle failure). If the two loops are balanced in flow at the same speed, the resistance characteristics cannot have changed. Any im-balance between drive loop flow rates would be indicated by the plant proc-ess instrumentation. In addition, the affected jet pump would provide a leakage path past the core thus reducing the core flow rate. The reverse flow through the inactive jet pump would still be indicated by a positive differential pressure but the net effect would be a light decrease (3% to 6%) in the total core flow measured. This decrease, together with the loop flow increase would result in a lack of correlation between measured and derived core flow rate. Finally, the affected jet pump diffuser differen-tial pressure signal would be reduced because the backflow would be less than the normal forward flow. A nozzle-riser system failure could also generate the coincident failure of a jet pump body; however, the converse is not true. The lack of any substantial stress in the jet pump body makes failure impossible without an initial nozzle riser system failure. p 3.6.J Recirculation Pump Speeds Q An evaluation was not provided for ECCS performance during reactor operation with one recirculation loop out-of-service. Therefore, continuous reactor operation under such conditions should not be permitted until the necessary analyses have been performed, evaluated and determined acceptable. The reactor may, however, operate for periods up to 24 hours with one recirculation loop out-of-service. This short time period permits corrective action to be taken and minimizes unnecessary shutdowns which is consistent with other Technical Specificati'ons. During this period of time the reactor will be operated within the restrictions of the thermal analysis and will be protected from fuel damage resulting from anticipated transients. b 3.6-22 e _ _ - _ _ _ _ _ _ _ _ - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ - . _ _ - - - _ _ - _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ -
O O O TABLE 3.7-1 PRIMARY CONTAINMENT ISOLATION VALVES Isolation Number of Power Maximum Normal ' Action on Group Operated Valves Operating Position Initiating (b) Valve Identification (d) Inside Outside Time (sec) (a) Signal (a) 2 Suppression chamber exhau'st valve 2 5 C SC bypass to standby gas treatment (T48-F339,T48-F338) 2 Suppression chamber nitrogen 1 5 0 GC make-up line (normal operation) (T48-F1188) 2 Drywe11 and suppression chamber 1 5 C SC nitrogen supply line (inerting) (T48-F103)- w y 2 Drywell and suppression chamber 1 5 C SC 1 nitrogen make-up line (normal N operation) (T48-F104) 2 Drywell equipment drain sump 2 15 C SC discharge (G11-F019,G11-F020) 2 Drywell floor drain sump discharge 2 15 C SC (G11-F003, G11-F004) 2 TIP Guide Tube 1 each NA C SC (C51-J004) line, (c) Drywell pneumatic system 2 5 0 GC (P70-F002, P70-F003) 6 RHR reactor shutdown cooling 1 1 24 C SC l suction (supply) (E11-F008, E11-F009)
O O O > . . TABLE 3.7-1 (Cont'd) PRIMARY CONTAINMENT ISOLATION VALVES Isolation Number of Power Maximus Normal Action on Group Operated Valves Operating Position Initiating (b) Valve Identification (d) Inside Outside Time (sec) (a) Signal (a) 6 RHR reactor head spray 1- 1 20 C SC l (Ell-F022, E11-F023) 3 HPCI - turbine steam 1 1 50 0 GC (E41-F002, E41-F003) 4 RCIC - turbine steam 1 1 20 0 GC (E51-F007, E51-F008) 4 5 Reactor water cleanup from 1 1 30 0 GC recirculation loop w (G31-F001, G31-F004) l' Number of Valves Normal (e) Check Valve Identification Inside Outside (e) Position (e) 4 Feedwater 2 2 0
- (B21-F010 A,B; B21-F032A,B)
Control Rod Hydraulic Return 1 1 0' l (C11-F083, Cll-F086) Standby Liquid Control System 1 1 C (C41-F007, C41-F006) , Reactor water cleanup return line 1 0 j (G31-F039) i RHR injection testable check 2 C i (E11-F050 A,B)
Table 3.7-1 (Concluded) Primary Containment Isolation Valves bq ;These notes refer to the lower case letters in parentheses on the previous page. NOTES:
- a. Key: 0 = Open SC = Stays closed C = Closed GC = Goes closed
- b. Isolation Groupings are as follows:
GROUF 1: The valves in Group 1 are actuated by any one of the following conditions:
- 1. Reactor vessel water level Low Low Low (Level 1) !
- 2. Main steam.line radiation high
- 3. Main steam line flow high
- 4. Main steam line tunnel temperature high
- 5. Main steam line pressure low
- 6. Condenser vacuum low GROUP 2: The valves in Group 2 are actuated by one one of the following conditions:
- 1. Reactor vessel water level low (Level 3)
- 2. Drywell pressure high GROUP 3: Isolation valves in the high pressure coolant injection (HPCI) system are actuated by any one of the following conditions:
- 1. HPCI steam line flow high .
- 2. High temperature in the vicinity cf the HPCI steam line
- 3. HPCI steam line pressure low
- 4. HPCI turbine exhaust diaphragm pressure
( ) GROUP 4: Primary Containment Isolation valves in the reactor core isolation cooling (RCIC) system are actuated by any one of the following conditions:
- 1. RCIC steam l' . ilow high
- 2. High temperature in the vicinity of the RCIC steam line
- 3. RCIC steam line pressure low GROUP 5: The valves in Group 5 aie actuated by any one of the following conditions:
- 1. Reactor vessel water level Low Low (Level 2) !
- 2. Reactor water cleanup equipment room temperature high
- 3. Reactor water cleanup equipment room ventilation differential temperature high
- 4. Reactor water cleanup system differential flow high
- 5. Actuation of Standby Liquid Control System - closes outside valve only
- 6. High temperature following non-regenerative heat exchanger - closes outside valve only GROUP 6: The valves in Group 6 are actuated by the following conditions:
- 1. Reactor vessel water level low (Level 3)
- 2. Reactor vessel steam dome pressure high (shutdown cooling mode)
- c. Requires a Group 2 signal or a Reactor Building ventilation high radiation isolation signal.
- d. For redundant lines, only one set of valves is listed. Other sets are identical except for valve numbers, which are included. Valve numbers are listed in order from within primary containment outward for each line.
- e. Not applicable to check valves.
~
3.7-19
m. q V BASES FOR LIMITING CONDITIONS FOR OPERATION 3.7,0. primary Containment Isolation Valves Double isolation valves are provided on lines penetrating the primary con-tainment and open to the free space of the containment. Closure of one of the valves in each line would be sufficient to maintain the integrity of the system. Automatic initiation is required to minimize the potential leakage paths from the containment in the event of a loss-of-coolant accident. Table 3.7-1 contains primary containment isolation valves that auto-matically actuate on a primary containment isolation signal. The primary containment isolation signals are grouped as described below. Group 1 process lines are isolated by reactor vessel water level low low low (Level 1) in order for removal of decay heat subsequent to a scram, yet isolate in time for proper operation of the core standby cooling systems. Group 2 isolation valves are not normally in use and are closed by reactor vessel water level low (Level 3) or drywell pressure high. It is not desirable to actuate the Group 2 isolation signal by a transient or spurious signal. Group 3 and 4 process lines are designed to remain operable and mitigate fN the consequences of an accident which results in the isolation of other V process lines. The signals which initiate isolation of Group 3 and 4 process lines are therefore indicative of a condition which would render these other lines inoperable. Group ~5 process lines are normally in use and it is therefore not desirable to cause spurious isolation due to high drywell pressure resulting from non-safety related causes. To protect the reactor from a possible pipe break'in the system, isolation is provided by hign temperature in the clean-up system area or high flow difference through the cleanup system. A'so
-since the vessel could potentially be drained through the cleanup system, a low level isolation is provided.
Group 6 isolation valves are not normally in use and are closed by reactor vessel water level low (Level 3) and reactor steam dome pressure low per-missive. The primary containment is penetrated by several small diameter instrument lines connected to the reactor coolant system. Each instrument line con-
.tains a 0.25 inch restricting orifice inside the primary containment, a manually operated root valve outside the primary containment, and an excess flow check valve outside the primary containment.
p d ' 3.7-35 y w -- - mw e -,-- ,w- - .- ,,y y - v-- - ,
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i 1 f, F l i ! 4 ; t P 4 i I a o i APPENDIX 1 1~ SIGNIFICANT HAZARDS REVIEW l t i 6 I 1 . j . i t r- - - - ~ ~ , . _ ,. . . . . - - , - . . . - ~ ~ . - - - _ . - _ . - - - -__ ---
1 e Overview of the -Individual 10 CFR 50.92 Evaluations of the Proposed ATTS- {)r-s_ Related Technical Specifications Changes for the Edwin I. Hatch Nuclear Plant-Unit-1 The proposed Technical Specifications changes, which Georgia Power Company (GPC) is proposing-for use with the new analog. transmitter trip system (ATTS)
-to be installed at Hatch 1, include new instrument trip setpoints/ allowable values and surveillance intervals which take credit for the advantages that the new devices have over those currently installed at the plant, in terms of
.setpoint drift and instrument accuracy. In addition to these types of.
revisions,'this submittal also proposes a number of other types of Technical Specifications changes including the following:
~
o Changes which account for inodifications to instrument loops or trip logic resulting from the new ATTS design. . e Changes which correct minor typographical or descriptive errors found in the Hatch 1 Technical Specifications during the safety review process for ATTS. (The errors found do not necessarily affect sections covering requirements for ATTS components.) e Changes to the Technical Specifications Bases sections which correct existing errors and update them with respect to the other proposed ATTS changes. All.of these proposed modifications were based on Nuclear Regulatory Commission (NRC) and industry standards listed in Table Al-1 of this d . appendix, to the extent practicable. It should be noted that use of several documents in Table Al-1 goes beyond the extent of commitments made by GPC, including those made in the Hatch 1 FSAR, and that their use in the design and implementation of ATTS does not represent an extension by GPC of these commitments to other plant systems' designed to other criteria. If conflicts arose between the requirements of the FSAR and those contained in the listed standards, the requirements of Hatch 1 FSAR section 7.1 and Appendix F were followed by.GPC. The individual 10 CFR 50.92 evaluations contained in the following pages,
--when-taken collectively, provide a complete evaluation for significant hazards resulting.from the proposed ATTS-related license changes. Based on the conclusion of each of the i_ndividual reviews, which was that each type or group of changes did not result in a significant hazard as defined in 10 CFR 50.92, GPC'has determined that the same conclusion is valid for this
' entire license change proposal.
O Al-1
)
2 f~s TABLE Al-1 Q ANALOG TRANSMITTER TRIP SYSTEM CONFORMANCE CRITERIA (SHEET 1 0F 3) I.
- IEEE Standards ,
g IEEE-279-1971: Criteria for Protection System for Nuclear Power Generating Station IEEE-323-1974: Qualifying Class 1E Equipment for Nuclear-Power Generating Stations IEEE-336-1977: Installation, Inspection and Testing Requirements for Instrumentation and Electrical Equipment During the Construction of Nuclear Power Generating Stations IEEE-338-1977: Criteria for , Periodic Testing of Nuclear Power Generating Station Safety Systems IEEE-344-1975: Recommended Practices for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations IEEE-397-1977: Application of the Single-Failure Criterion to Nuclear Power Generating Station Class IE. Systems
/m IEEE-420-1973: Trial-Use Guide for Class 1E Control Switchboards for Nuclear
- d.
-Power Generating Stations IEEE-494-1974: Method for Identification of Documents Related to Class 1E Equipment and Systems for Nuclear Power Generating Stations NRC Regulatory Guides Regulatory Guide 1.22: Periodic Testing of Protection System Actuation
. Functions Regulatory Guide 1.28: Quality Assurance Program Requirements
.. Regulatory Guide 1.29: Seismic Design Classification Regulatory Guide 1.30: Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electrical Equipment Regulatoiy Guide 1.38:. Quality Assurance Requirements for Packing, Shipping, Receiving, Storage, and Handling of Items for Water-Cooled Nuclear Power Plants Regulatory Guide 1.47: Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems O
G
r~w TABLE Al-1 (SHEET 2 0F 3) NRC Regulatory Guides (continued) Regulatory Guide 1.53; Application of the Single-Failure Crite'rion to Nuclear Power Plant Protection Systems Regulatory Guide 1.61: Damping Value for Seismic Design of Nuclear Power Plants Regulatory Guide 1.62: Manual Initiation of Protective Actions Regulatory Guide 1.64: Quality Assurance Requirements for the Design of Nuclear Power Plants Regulatory Guide 1.68: Initial Test Program for Water-Cooled Reactor Power. Plants Regulatory Guide 1.75: Physical Independence of Electrical Systems , Regulatory Guide 1.89: Qualification of Class IE Equipment for Nuclear Power Plants Regulatory Guide 1.92: Combining Modal Responses and Spatial Components in Seismic Response Analysis (q,/ Regulatory Guide 1.97: Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident Regulatory Guide 1.100: Seismic Qualification of Electric Equipment for Nuclear Power Plants Regulatory Guide 1.131: Qualification Tests of Electric Cables, Field Splices, and Connections for Light-Water-Cooled Nuclear Power Plants NRC Regulations Regulation 10 CFR 21: Reporting of Defects and Noncompliance Regulation 10 CFR 50.49: Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants Regulation 10 CFR 50.55a: Issuance, Limitation and Conditions of Licenses and Construction Permits (CP) - Codes and Standards Regulation 10 CFR 50, Appendix A: General Design Criteria (GDC) f,or Nuclear Power Plants r, d I
- ,,- , ..,_--..-_.._7 __ .,, _ , - - -- - - - _. ,
TABLE Al-1 (SHEET 3 0F 3) General Design Criteria GDC 1: ' Quality-Sta'ndards and Records GDC 2: Design Basis for Protection Against Natural Phenomena GDC 5: Sharing of Structures, Systems, and Components GDC 10: Reactor Design
-GDC 13: Instrumentation and Control GDC 20: Protection System Functions GDC 21: Protection System Reliability and Testability GDC 22: Protection System Independence GDC 23: Protection System Failure Mode GDC 24: Separation of. Protection and Control Systems GDC-29: Protection Against Anticipated' Operational Occurrences 9
6 e 1
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l _ _ , . ..-.._,..___.__..._.__._..m_._. . ~ . . - . , _ . . - . .---..._.m._,_
i r 10 CFR 50.92 Evaluation for the Proposed Changes to the Technical Specifica- , (m) tions Surveillance Intervals as a Result of the Installation of Transmitter Trip System for Edwin I. Hatch Nuclear Plant-Unit 1(th)ea Analog j Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed Technical Specification changes due to the installation of the analog transmitter trip system (ATTS). ATTS replaces the pressure, level, and temperature switches in the reactor protection system and the emergency core cooling system (ECCS) with analog sensor / trip unit combinations. The system is designed to improve sensor intelligence and reliability, while still providing continued monitoring of critical parameters and performing the intended basic logic function. Since the ATTS instrumentation is superior in design to the mechanical switches currently used at Plant Hatch, certain surveillance intervals may be extended without any significant effect on the expected magnitude of sensor drift or frequency of instrument malfunction. GPC proposes to change the surveillance requirements for the ATTS instrumentation to once per shift for channel checks, once per month for channel functional tests, and once per operating cycle for channel calibrations. These proposed surveillance requirements were previously approved on a generic bases for ATTS equipment by the Nuclear Regulatory Commission (NRC) review of the General Electric Company topical report NEDO 21617-A. Additional changes to the nomenclature used in the Technical Specifications are included for clarification and consistency with this proposed change. p GPC reviewed the proposed changes and considers them not to involve a Q significant hazards consideration for the following reasons:
- 1. They would not significantly increase the probability or consequences of an accident previously evaluated, because the new ATTS instruments have been demonstrated to be superior in design to the existing devices in terms of instrument accuracy and drift characteristics. In addition, the new setpoints have been rigorously calculated, assuming the proposed surveillanc.e frequencies.
- 2. They would not create the possibility of a new or different accident from any accident previously evaluated, because the new surveillance intervals for ATTS were developed to be consistent with the Plant Hatch-Unit 1 Final Safety Analysis Report (FSAR) descriptions.
- 3. They would not involve a significant reduction in a margin of safety, because the new surveillance requirements are tailored to the ATTS instruments, using the methodology of Regulatory Guide 1.105. In addition, the bases for the margins of safety, as described in the FSAR, have been maintained.
- a. See section 38 (page 3-40) for discussion of proposed revisions.
f} v Al-2
; 10 CFR 50.92 Evaluation for the Proposed Changes to the Technical Specifica-t/ tions as a Result of the Incorporation of the Low Low Set Relief Design Modification for Edwin I. Hatch Nuclear Plant-Unit 1ca>
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed addition of the low low set (LLS) relief logic technical specifications. The purpose of the LLS design modification is to mitigate the induced loads of subsequent safety / relief valve (S/RV) actuations as identified in NUREG-0661. The load reduction is accomplished by lowering the opening and closing setpoints of four non-automatic depressurization system (ADS) S/RVs after initial S/RV opening. Technical Specifications revisions are required to accurately reflect the newly designated safety function of the selected S/RVs. The proposed limiting conditions of operation requirements were developed taking into consideration the General Electric BWR/4 Standard Technical Specifications, while the surveillance requirements were developed from the ATTS requirements. This modification is required by the Nuclear Regulatory Commission (NRC) order requiring that reassessment of the containment design for suppression pool hydrodynamic loading conditions be promptly instituted and that any plant modifications needed to conform to the NRC staff's acceptance criteria, contained in Appendix A to NUREG-0661, be performed. GPC reviewed the proposed changes and considers them not to involve a significant hazards consideration for the following reasons: (3 1. They would not significantly increase the probability or () consequences of an accident or equipment failure previously evaluated, because this new system was designed to reduce the consequences of certain plant transients without any significant effect on other accident scenarios.
- 2. They would not create the possibility of a new or different accident from any accident previously evaluated, because the potential accident scenarios following implementation of these changes are bounded by those in the FSAR analysis.
- 3. They would not involve a significant reduction in a margin of safety, because the bases for the proposed operability limits and surveillance requirements for this new system are consistent with the bases for current Technical Specifications requirements.
~
- a. See subsection 48.1 (page 4-4) for discussion of proposed revisions.
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O' 10 CFR 50.92 Evaluation for the Proposed Changes to the Technical Specifica-V tions due to the Lowering of the Main Steam Isolation Valve Water Level for Edwin I. Hatch Nuclear Plant-Unit Ica> Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed Technical Specifications revisions due to the lowering of the main steam isolation valve (MSIV) water level trip setpoint. The proposed modification lowers the isolation level of the MSIVs, the main steam drain isolation valve, and the reactor water sample line isolation valves from reactor vessel water level 2 to level 1. The purpose of lowering the MSIV water level trip setpoint, as detailed in NEDE-22223 and NEDE-22224, is to provide an additional means to mitigate the induced loads of subsequent safety / relief valve (S/RV) actuations. Lowering the setpoint delays the MSIV closure allowing more steam to be released from the reactor prior to an S/RV actuation. Subsequently, the pressurization rate after isolation is reduced, and the time period between S/RV actuations is increased. This change also reduces the probability of spurious MSIV trips and scrams, prevent unnecessary use of the suppression pool as the alternate heat sink, and improve the life expectancy of the feedwater sparger. This modification is required by the Nuclear Regulatory Commission (NRC) order requiring that reassessment of the containment design for suppression pool hydrodynamic loading conditions be promptly instituted that and any plant modifications needed to conform to the NRC staff's acceptance criteria, contained in Appendix A to NUREG-0661, be performed.
/ %
U GPC reviewed the proposed changes and considers them not to involve a significant hazards consideration for the following reasons:
- 1. They would not significantly increase the probability or consequences of an accident or equipment failure previously evaluated, because this new system was designed to reduce the consequences of certain plant transients without any significant effect on other accident scenarios.
- 2. They would not create the possibility of a new or different accident from any accident previously evaluated, because the potential accident scenarios following implementation of these changes are bounded by those in the FSAR analysis.
- 3. They would not involve a significant reduction in a margin of safety, because the bases for the proposed operability limits and surveillance requirements for this new system are consistent with the bases for current Technical Specifications requirements.
- a. See subsection 4B.2 (page 4-16) for discussion of proposed revisions.
(v) Al-4
~ ._ -(~) 10 CFR 50.92 Evaluation for the Proposed Changes to the Technical Specifica- 's.J tions Reactor Vessel Water Level - Low Low (Level 2) Trip.Setpoint for Edwin I. Hatch Nuclear Plant-Unit 1ca>
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed reactor vessel water level 2 trip setpoint Technical Specifications change. This proposed change lowers the level 2 trip setpoint/ allowable value from -38 in. to -55 in., thus, potentially decreasing the number of plant transients by decreasing the number of HPCI/RCIC actuations due to normal operational perturbations in water level. GPC reviewed the proposed change and considers it not to involve a significant hazards consideration for the following reasons:
- 1. It will not significantly increase the probability or consequences of an accident previously evaluated, because a reevaluation of the FSAR analysis showed that the new setpoint, in conjunction with the new analog transmitter trip system (ATTS) instrumentation, would still provide the same degree of plant protection as described in the Final Safety Analysis Report (FSAR).
- 2. It will not create the pos'sibili+.y of a new or different accident from any accident previously evaluated, because the lowered setpoint is still within the bounds of the olant safety analysis and should decrease the number of unnecessary emergency core cooling system actuations.
- 3. It will not involve a significant reduction in a margin of safety, because the setpoint still performs its intended safety function, as describcd in the FSAR. In addition, the calculations which determined the new setpoint took credit for the improved drift characteristics of the ATTS instruments and the criteria of Regulatory Guide 1.105.
- a. See subsection 48.3 (page 4-17) for discussion of proposed revisions.
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.- - ~__ _- . _ , _ - - _ _ - - - - . .
,- m o - -m _ . , _ I) 10 CFR 50.92 Evaluation for the Proposed Changes to the Technical Specifica-
\- / tions due to the Reactor Vessel Water Level - High (Level 8) Trip Instrumentation Modification for Edwin I. Hatch Nuclear Plant-Unit lea >
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed changes to tha Technical Specifications due to the reactor vessel water level - high (level 8) trip instrumentation. This change proposes to replace the current instruments with new ATTS units. Since the ATTS instruments are superior in design to the mechanical switches currently used at Plant Hatch, using the criteria of Regulatory Guide 1.105, the setpoint/ allowable value will be lowered from 58 in. to 56.5 in. GPC reviewed the proposed change and considers it not to involve a significant hazards consideration, because it represents a more conservative and restrictive Technical Specifications requirement than that which is currently in place. Consequently, this change is consistent with Item (ii) of the " Examples of Amendments that are Considered Not Likely to Involve Significant Hazards Considerations" listed on page 14,870 of the April 6, 1983, issue of the Federal Register and will not result in a significant hazards consideration.
. ,-~
- a. See subsection 48.4 (page 4-18)' for discussion of proposed revisions.
Al-6 -
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f /T 10 CFR 50.92 Evaluation of the Proposed Change to the Technical Specifica-k-l tions Reactor Core Isolation Cooling Reactor Vessel Water Level 8 Trip for Edwin I. Hatch Nuclear Plant-Unit 1<a Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed change to the reactor core isolation cooling (RCIC) reactor vessel water level 8 Technical Specifications. This change proposes to clarify the Technical Specifications by adding a note to table 3.2-3 and the Bases stating that the RCIC system is capable of automatic reset after a level 8 trip. Since there is no physical change to the RCIC system level 8 trip, GPC considers this change to be purely administrative in nature. As discussed above, the proposed change is submitted in an effort to update informational sections of the Technical Specifications and is administrative in nature. Therefore, GPC has determined that the proposed change is . consistent with Item (i) of the " Examples of Amendments that are Considered Not Likely to Involve Significant Hazards Considerations" listed on page 14,870 of the April 6, 1983, Federal Register and will not involve a significant hazards consideration. (U) . a. See subsection 4B.5 (page 4-19) for discussion of proposed revisions. A
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Al-7
10 CFR 50.92 Evaluation for the Proposed Changes to the Technical Specifica-( tions due to the Lowered Water Level Trip Setpoint for Isclation of Reactor V) Water Cleanup and Secondary Containment, and Starting of Standby Gas Treatment j System for Edwin I. Hatch Nuclear Plant-Unit 1<a>
. Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed changes to the Technical Specifications due to the lowered water level trip setpoint for the isolation of reactor water cleanup (RWCU) and secondary containment, and the starting of the standby gas treatment system (SGTS). This change preooses to lower the water level trip setpoint for the isolation of RWCU and secondary containment and startup of SGTS from level 3 to level 2. A reactor scram from normal power
(<50 percent rated) usually results in a reactor vessel water level transient due to a void collapse that causes RWCU isolation at level 3. This usually results in the dropping of the cleanup filter cake, and added radwaste processing. These problems can be avoided by lowering RWCU isolation to level 2. Lowering the SGTS actuation and secondary containment isolation from level 3 to level 2 reduces the probability of spurious isolations. GPC reviewed the proposed changes and considers them not to involve a significant hazards consideration for the following reasons: ,
- 1. They will not significantly increase the probability or consequences of an accident from any accident previously evaluated, because the Final Safety Analysis Report (FSAR) emergency core cooling system O
( analysis system already assumes SGTS initiation at level 2. Secondary containment requires a functioning train of the SGTS for full effectiveness, and isolation of the containment building is assumed to be simultaneous with SGTS initiation in the FSAR analysis. In addition, the changes will reduce operability problems associated with unnecessary RWCU and secondary containment isolations.
- 2. They will not create the possibility of a new or different kind of accident from any accident previously evaluated, because the lowered setpoint is still within the bounds of the FSAR analysis and will not change the basic functions of these trips.
- 3. They will not involve a significant reduction in a margin of safety, because these trips still perform their intended safety functions, as described in the FSAR.
p a. See subsection 48.6 (page 4-20) for discussion of proposed revisions. b Al-8
10 CFR 50.92 Evaluation for the Proposed Changes to the Technical Specifica-I,,\ tions due to the Deletion of the High Drywell Pressure Signal for Residual \d Heat Removal (Shutdown Cooling Mode) and RPV Head Spray Valve for Edwin I. Hatch Nuclear Plant-Unit 1 ca Georgia Power Company (GPC) reviewed the requirements of 10 CfR 50.92 as they relate to the proposed changes to the Technical Specifications due to the deletion of the high drywell pressure signal for residual hea't removal (RHR) (shutdown cooling mode) and the reactor pressure vessel head spray valve. The purpose of this change is to stop small steam leaks in the drywell from preventing operation of the RHR system during the shutdown cooling mode, thereby prohibiting an acceptable normal shutdown procedure. GPC reviewed the proposed changes and considers them not to involve a significant hazards consideration for the following reasons:
- 1. They will not significantly increase the probability or consequences of an accident previously evaluated; because the requirements of 10 CFR 100 are still met, and the Appendix K calculations are not affected.
- 2. They will not create the possibility of a new or different kind of accident from any accident previously evaluated, oecause the deletion of the drywell pressure isolation is only being made on closed-loop systems. In addition, General Electric has shown that Q the reactor vessel low water level trip function, which isolates the V shutdown cooling mode of RHR, is adequate for reactor protection.
Furthermore, this change does eliminate the possibility for isolation of the shutdown cooling system due to high drywell pressure during periods when its function is essential for adequate decay heat removal.
- 3. They will not involve a significant reduction in a margin of safety, because the high drywell pressure isolation has little effect in preventing coolant losses or radioactive substance releases, and presently hinders the operability of the RHR shutdown cooling systems during certain plant scenarios.
p a. See subsection 48.7 (page 4-21) for discussion of proposed revisions. b Al-9
,S 10 CFR 50.92 Evaluation for the Proposed Change to the Safety / Relief Valve ij Position Indicator Technical Specifications for Edwin I. Hatch Nuclear Plant-Unit Ica> ,
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the pro;fosed safety / relief valve (S/RV) position indicator Technical Specifications. This change proposes to correct the S/RV primary position indicator range from 0-400 psig to 85 psig, because the new qualified S/RV pressure switches do not have a variable-range indication capability. However, the setpoint would not change since it is presently 85 psig. Since an indicating light at the setpoint is turned on and off by pressure switches, the Technical Specifications would also be revised to reflect the S/RV primary position indicator as an indicating light. This change also proposes to correct the S/RV secondary position indicator type from a temperature element to a recorder, since the recorder is the instrument that actually provides surveillance. GPC considers these changes to be administrative in nature because no plant modifications are required. As discussed above, these proposed changes clarify and correct the Technical Specifications. GPC determined that the proposed changes are administrative in nature and are consistent with Item (i) of the " Examples of Amendments that are Considered Not Likely to Involve Significant Hazards Considerations" listed on page 14,870 of the April 6,1983, issue of the Federal Register. Thus, the proposed changes will not involve a significant hazards consideration. l
- a. See subsection 48.8 (page 4-22) for discussion of proposed revisions.
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fs 10 CFR 50.92 Evaluation for the Proposed Change to the Residual Heat Removal (RHR) ('~' ) Shutdown Cooling Mode Safet Limit Technical Specifications for Edwin I. HatchNuclearPlant-Unitl'g* Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed residual heat removal (RHR) shutdown cooling mode safety limit Technical Specifications change. The purpose of this change is to clarify and correct the HNP-1 Technical Specifications. The Technical Specifications currently list a safety limit of 135 psig for the reactor vessel steam dome pressure. This value is also listed as a trip setpoint. The actual safety limit is and has always been 162 psig. In addition, the bases for the safety limit and the limiting safety system settings are reversed. Therefore, this change proposes to revise the safety limit from 135 psig to 162 psig and switch the bases for the safety limit and the limiting safety system settings. Since this change only corrects an error, GPC considers this change to be purely administrative in nature. As discussed above, this proposed change clarifies and corrects the Technical Specifications. GpC determined that the proposed change is administrative in nature and is consistent with Itsm (i) of the " Examples of Amendments that are Considered Not Likely to Involve Significant Hazards Considerations" listed on page 14,870 of the April 6,1983, of the Federal Register. Thus, the proposed change will not involve a significant hazards consideration. (D v 4
- a. See subsection 48.9 (page 4-23) for discussion of proposed revisions.
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,. 10 CFR 50.92 Evaluation for the Proposed Elimination of the MSIV Closure Scram in the Startup/ Hot Standby Mode for Edwin I. Hatch Nuclear Plant-Unit 1<a> (/) s_ j 1 Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed Technical Specifications revision due to the elimination of the main steam isolation valve (MSIV) closure scram in the startup/ hot standby mode. This change proposes to disable the reactor scram on MSIV closure with the vessel pressure exceeding the scram pressure in the startup/ hot standby mode. Since normal operating pressures in the startup/ hot standby mode are significantly less than 1045 psig (scram pressure), and since the reactor will scram on high pressure should the reactor steam dome pressure exceed 1045 psig regardless of MSIV position, this scram is essentially bypassed. Therefore, this change will not affect plant safety. GPC reviewed the proposed change and considers it not to involve a significant hazards consideration for the following reasons:
- 1. It will not significantly increase the probability or consequences of an accident previously evaluated, because the trip is already essentially bypassed and provides no safety function.
- 2. It will not create the possibility of a new or different kind of accident from any accident previously evaluated, because this trip is already essentially bypassed and provides no safety function.
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- 3. It will not involve a significant reduction in a margin of safety, because this trip is already essentially bypassed and provides no safety function.
7- g a. See subsection 4B.10 (page 4-24) for discussion of proposed revisions. (_-)- Al-12
10 CFR 50.92. Evaluation for the Proposed Trip Function Identification (~'} Changes to the Technical Specifications for Edwin I. Hatch Nuclear
's # Plant-Unit 1<a>
Georgia' Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed trip function identification changes to the Technical Specifications. Since the proposed changes only involve revisions in nomenclature, GPC considers them to be purely administrative in nature. As discussed above, the proposed changes only involve changes in nomenclature. Therefore, GPC determined that these proposed changes are consistent.with Item (i) of the " Examples of Amendments that are Considered Not Likely to Involve Significant Hazards Considerations" listed on page 14,870 of the April 6, 1983, issue of the Federal Register and will not involve a significant hazards consideration. O V r
-~ . a. See subsection 48.9 (page 4-25) for discussion of proposed revisions.
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, 10 CFR 50.92 Evaluation for the Proposed Miscellaneous Trip Setpoint/ Allow- ') able Value Modifications to the Technical Specifications for Edwin I. Hatch V Nuclear Plant-Unit Ica>
Georgia Power Company (GPC) reviewed the requirements of 10 CFR 50.92 as they relate to the proposed miscellaneous trip setpoint/ allowable value modifications to the Technical Specifications. The purpose of this change is to update the Technical Specifications trip setpoints being replaced by the analog transmitter trip system (ATTS). Since the time that original setpoints were determined, a better calculational method has been developed. This proposed change uses the Regulatory Guide 1.105 methodology in updating the setpoints for the instruments being replaced with the ATTS units, and takes credit for the improved error and drift characteristics of the new system. This change replaces the trip setpoints listed in the Technical Specifications which are the original analytical limits with the newly evaluated allowable values determined through Regulatory Guide 1.105 methodology. GPC reviewed the proposed changes and considers them not to involve a significant hazards consideration for the following reasons:
- 1. They will not significantly increase the probability or consequences of an accident previously evaluated, because the new ATTS instruments are of a superior design as compared to the current instruments. In addition, the setpoints were determined using the Q criteria of Regulatory Guide 1.105, and therefore, still meet the V Final Safety Analysis Report (FSAR) criteria.
- 2. They will not create the possibility of a new or different kind of accident from any accident previously evaluated, because the basic trip functions, as described in the FSAR, are unchanged.
- 3. They will not involve a significant reduction in a margin of safety, because for most trips, the original design basis was maintained.
Any new design bases were fully addressed with regard to FSAR requirements. In addition, Regulatory Guide 1.105 criteria were used in the calculation of the new setpoints. O a. See subsection 4B.10 (page 4-26) for discussion of proposed revisions. V Al-14
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