ML20083N418
| ML20083N418 | |
| Person / Time | |
|---|---|
| Site: | 05000447 |
| Issue date: | 01/28/1983 |
| From: | Sherwood G GENERAL ELECTRIC CO. |
| To: | Eisenhut D Office of Nuclear Reactor Regulation |
| References | |
| JNF-004-83, JNF-4-83, MFN-014-83, MFN-14-83, NUDOCS 8302010644 | |
| Download: ML20083N418 (148) | |
Text
{{#Wiki_filter:_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NUCLEAR POWER GENERAL h ELECTRIC SYSTEMS DIVISION GENERAL ELECTRIC COMPANY,175 CURTNER AVE.. SAN JOSE, CALIFORNIA 95125 MFN 014-83 MC 682, (408) 925-5040 JNF 004-83 January 28, 1983 U.S. Nuclear Regulatory Commission _' Office of Nuclear Reactor Regulation Washington, D.C. 20555 Attention: Mr. D.G. Eisenhut, Director Division of Licensing
SUBJECT:
IN THE MATTER OF 238 NUCLEAR ISLAND GENERAL ELECTRIC STANDARD SAFETY ANALYSIS REPORT (GESSAR II) DOCKET N0. STN 50-447 j Attached please find the remaining final draft responses to the Instrumentation and Control Systems Branch (ICSB) questions in the Commission's October 5,1982 request for edditional information. These responses reflect the NRC/GE information ex-hange meetings held in Bethesda October 14 & 15, 1982; San Jose December 7-9, 182; and again in Bethesda January 11-13, 1983. This transmittal contains the last ten responses for the 421-series as promised ig our previous submittal dated January 21, 1983. They are 421.02, 04,13,16,18,22732740,44and50. Also included is Attachments 1 and 2 (referenced in Response 421.04d) and Attachment 3 (referenced in Response 421.23 submitted January 21). Four extra copies of these attachments are F included for reference purposes in conjunction with the amendment scheduled for February 1983. Sincerely, 0)7 Glenn G. Sherwood, Manager phdJ D%d Nuclear Safety & Licensing Operation Attachments cc: M.J. Virgilio, NRC D.C. Scaletti, NRC L.S. Gifford, GE-Bethesda (Without Attachments) F.J. Miraglia (Without Attachments) C.0. Thomas (Without Attachments) R.M. Ketchel (Without Attachments)
*To be provided under separate cover.-
8302010644 830128 PDR ADOCK 05000447 A PDR
421.02 QUESTION
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QRBFT In Section 7.1 of your FSAR, you do not address the Branch Technical Positions (BTP) relatine to the instrumentation and control systems listed in Table 7-1 of the SRP and provided in Appendix A to Chapter 7 of the SRP. Provide a detailed discussion using drawings, schematics and P&ID's to demonstrate that your proposed design conforms to the guidance provided in the applicable BTP's, including Branch Technical Position ICSB 18 (PSB) contained in Appendix 8-A of the SRP. 421.02 RESPONSE The following Table provides GE's assessments for all BTP's shown in Table 7-1 of the SRP and BTP ICSB 18 (PSB): (Next 6 Pages 6;Ayr,ckwe,T) I i l
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SRP ASSESSMENT l l RESPONSE TO QUESTION 421.02 PAGE 1 OF 6 SRP ACCEPTANCE JUSTIFICATION DEVIATION l (a) BTP ICSB 3: Isolation of low pressure Diversity exception is taken See response to question 421.40. j systems from the High Pressure Reactor for RHR suction lines which ! Coolant System. incorporate two motor - operated valves as the LP/ HP interface. Otherwise, no deviations. (b) BTP ICSB 4: Requirements of MOVs in Not applicable to BWR BTP ICSB 4: BWRs do not employ safety ' the ECCS accumulator lines (PWR plants) plants. injection tanks with MONS, (c) BTP ICSB 12: Protection System trip Not applicable to BWR BTP ICSB 12: BWRs do not employ reactor l point changes for operation with Pl ants coolant pumps and safety setpoints are l reactor coolant pumps out of service, fixed. (d) BTP ICSB 13: Des'ign criteria for Not applicable to BWR BTP ICSB 13: BWRs.do not employ steam I auxiliary feedwater systems. plants. generators nor auxiliary feedwater systems. (e) BTP ICSB 14: Spurious withdrawals of Not applicable to BWR BTP ICSB 14: SRP identified single-failure single control rods in PWRs. plants, rod withdrawal problem unique to PWRs only, (f) BTP ICSB 16: Control Element Not applicable to GE BWRs. BTP ICSB 16: SRP identifies requirement Assembly (CEA) interlocks in Combus- unique to Combustion Engineering Vendor. tion Engineering reactors. (fg) BTP ICSB 18 (PSB): Application of No deviation BTP ICSB 18: Valve operations have been' the single-failure criterion to evaluated in the design. If inadvertent manually-controlled electrically- open operation has adverse safety conse-operated valves. quences, two valves are placed in series
*Unless otherwise indicated, all references are in GESSAR II.
SRP ASSESSMENT RESPONSE TO QUESTION 421.02 PAGE 2 op 6 1 DEVIATION JUSTIFICATION CH TERIA (fg) BTP ICSB 18 (PSB): Continued on the pipe with logic segregation such l that no single electrical failure can open i
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both valves (e.g., see valves F007 and F008 on Figure 6.7-la). Likewise, if inadverteni close operation has adverse safety conse-quences, two valves are placed in parallel ; on the pipe with logic segregation such that no single electric failure can close both valves (e.g., see valves F001A and F001B on Figure 9.3-5) . The power disconnect option is therefore unnecessary and i; not used except for valve FF038 on Figure 9.5-18. See Section 9.5.9.3 for its Safety evaluation and Section 9.5.9.5 for its instrumentation requirements, which includes the BTP discussio4 Also see Response 430.39. $tteoud)J 4 l l -- -- ---
L ,' GESF7,R II U FINAL DRAFT 22A700 i 238 NUCLEAR ISLAND R;v. ATTACHMENT OTf-IcSB-I? ( (- 9.5.9.1.1 Safety Design Bases (Continued) G~ Code Section III, Class 2, Quality Group B and Quality Assurance B requirements, vy cenfiameaY fensin.1E*na,isNla$ leu Ms/vts, astlf/Inj up to tiua v=NaJ (2) M / designed to Seismic Category I, ASME Code Section III, Class 3, Quality Group C and Quality Assurance B requirements. (k ' (3) The deep-bed demineralizer is designed and fabricated in accordance with ASME Boiler and Pressure Vessel Code, Section VIII, Division 1. (4) The two horizontal, centrifugal SPCU pumps are designed and fabricated in accordance with API 610. (5) The remainder of the system is designed t6 the ANSI B31.1 j Power Piping Code and Quality Group D requirements.
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9.5.9.1.2 Power Generation Design Bases (1) During norm l plant operation, the SPCU System is designed to recirculate approximately 1,100 gpm of suppression pool water. e (2) In circumstances of high suppression pool activity or V conductivity, such as following a blowdown transient, the system is capable of providing cleanup of the suppression pool water at the rate of 2,200 gpm. (3) The system is designed to maintain the suppression pool 1:ater quality at or better than the following conditions: k h hfo"r1 f0 pm 9.5-39
GESSAR II A
- 238 NUCLEAR ISLAND Rsv.
ATTACHMENT GTf-gss-18 9.5.9.2 Systems Description (Continued) (- -
.~ - In the event of a LOCA, the SPCU System function is automatically terminated to acconolish containment isolation. Power for the Camd via/vu/
SPCU System pumpU ls supplied only from the preferred power buses. Containment isolation valves are provided with Class lE preferred and standby power. The SPCU System, consisting of piping, valves and instrumentation, is shown in Figure 9.5-18 (K-172). The system has no unique major components. 9.5.9.3 Safetv Evaluation . The system has no safety-related function as previously defined. Failure of.the system does not compromise any safety-related
... system or component and does not prevent safe reactor shutdown.
k . However, the system does incorporate some' features that assure reliable operations over the full range of normal plant operations. These features consist primarily of instrumentation that monitors and/or controls SPCU operation and performance. l j Portions of the SPCU System that penetrate the containment are previded with isolation valves which are automatically c1csed by an isolation signal. l l The containment isolation signal logic receives reactor low-wr.ter-level signals and drywell high-pressure signals. These inputs
, isolate the SPCU System to prevent containment bypass leakage.
kinmeah Emergency power is supplied by Class lE buses to isolation valves t and leak de tion instrumentation for the DBA and for LOPP events. o.,s n . - - < y -1?-. s \
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. 238 NUCLEAR' ISLAND R v. (1P ATTACHtENT
( 9.5.9.5 Instrumentation Requirements (Continued) q' . turn it off using a hand selector switch located in the control room. $ .q !3 E tSt!! A @ ] ] The containment isolation valves are supplied with position indica-tion in the control room and remote-manual as well as automatic operation. (See Subsection 7.3.1 for details.) ^ Q f#n Jfs.lel suffas. 9.5".1.5 c.nfikuYioQ
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9.5.10 Nuclear Island - BOP Interface 9 . 5. l'0 .1 Nuclear Island Fire Pro'tection System - BOP Interface The Applicant shall provide the water and CO2 supplies for the Nuclear Island Fire Suppression. System. - 9.5.10.1.1 Design criteria Fire water supply for the Nuclear Island shall be provided by the BOP Fire Water System, Essential Service Water System and Conden-sate Transfer System. The Essential Service Water System provides a backup Seismic Category I source of water for hose reels for essential equipment. Condensate is the preferred source of water for the Wet Standpipe System inside the containment. The ESW and condensate connections and actuation and isolation provisions are ([ within the scope of the Nuclear Island design. CO 2 shall be supplied to the Nuclear Island at a sufficient rate and duration for the Diesel Generator Building CO2 Fire Suppression System. The classification of the BOP Fire Water and CO2 Supply System for I the Nuclear Island may be Quality Group D and nonseismic Category I. v I 9.5-44
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FINAL DRAFT SRP ASSESSMENT RESPONSE TO QUESTION 421.02 PAGE 3 op (i
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DEVIATION JUSTIFICATION CRITERI (g) BTP ICSB 20: Design of instrumentation No Deviation BTP ICSB 20: It is not within the BWR and controls provided to accomplish operating design base, to transfer from changeover from injection to injection to recirculation mode. The BTP recirculation mode. is primarily a PWR concern. However, HPCS suction automatically transfers from its preferred source (condensate storage tank) to the suppression pool on receipt of low condensate water level or high suppression . pool water level signals. See 7.3.1.1.1.1. C.1 and 6.3.2.2.1. Likewise, RCIC has similar transfer (automatically), as . described in 7.4.1.1.D.6 and 5.4.6.1. (h) BTP ICSB 21: Guidelines for applica- No deviation BTP ICSB 21: See analysis sections for tion of Regulatory Guide 1.47. each system for application of Regulatory
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Guide 1.47. For example , 7.3.2.1.2. A.7 for ECCS. Also see Response 421.04.
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B.1 & B.2 Individual system components meeting guide-lines B.1, 2 & 3 of Regulatory Guide 1.47 are annunciated at a single " system out of service" window for each division. In addition, status lights identify which com-ponent causes the out-of-service condition. Manual switches are provided to compliment administrative procedures which cover func-tions not automatically annunciated. Both annunciators and status lights are located in the Control Room immediately accessible to the operator. JNN
f FINAL DRAFT SRP ASSESSMENT RESPONSE TO QUESTION 421.02 PAGE 4 OF b ' SRP ACCEPTANCE DEVIATION JUSTIFICATION B.3 (h) BTP ICSB 21: (continued) The operator cannot cancel erroneous indi-cations. He can silence the horn, but i cannot clear the wir'7w or status lights ( until the problem is cleared. B.4 The annunciators and status lights are not safety related. However, no safety action is required by the operator based solely on annunciator indication. B.5 Interfaces between annunciators and safety-related logic are optically isolated such that no annunciator failures could cause failures of essential safety functions. Status lights are retained in the divisiona I circuits and are qualified with the panels l housing them. Compliance with Regulatory l Guide 1.75 assures redundant safety system independence is not compromised. B.6 A1T indicating and annunciating functions can be tested during normal plant operation . (This should be confirmed by applicant). No Deviation BTP ICSB 22: RPS conformance to Regulatory (i) BTP ICSB 22: Guidance for application Guide 1.22 is addressed in Subsection of Regulatory Guide 1.22. 7.2.2.2.A.1. RPS conformance to IEEE-279 is addressed in Subsection 7.2.2.2.C.1. Corresponding conformance sections for ECCS are 7.3.2.1.2. A.3 and 7.3.2.1.2.C.1 respectively. _ _ _ _ _ _ _ *Unless otherwise indicated, all references are in GESSAR II.
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SRP ASSESSMENT RESPONSE TO QUESTION 421.02 5 g g ,,,,f,,_ PAGE SRP ACCEPTANCE DEVIATION JUSTIFICATION (j) BTP ICSB 26: Requirements for Some RPS inputs come from See Subsection 7.2.3; the analysis on the Reactor Protection System anticipatory devices mounted on non- use of RPS inputs from devices mounted on trips. seismically qualifled equip- nonseismically qualifled equipment and/or ment and/or located in non- located in nonseismically qualified seismically qualified enclosures has been accepted per three enclosures. safety evaluation reports: (1) NUREG-0124 (supplement to NUREG 75/110) " Safety Evaluation Report, GESSAR 238 Nuclear Island Standard Design Supplement 1", September 1976, pp. 7-78, 15-3,4. (2) NUREG-0151, "SER, GESSAR 251, Nuclear Steam Supply System Standard Design", March 1977. (3) NUREG-0124 Supplement 2, January 1977, pp. 15-1, 2. The above reports include data for generic 238 and 251 BWR/6 designs. This analysis considers turbine trip, generator load rejection trip and recirculation pump trip (RPT). Generally, GE requires all hardware con-tributing to scram be qualifled per IEEE-279 (7.2.2.2.C.1). This means that such equipment located in the turbine building is required to be qualified to all class 1E requirements (except seismic in some cases). Interconnecting cables are treated as class 1E cables and are run in separate conduit for each division in
*Unless otherwise indicated, all references are in GESSAR II.
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SRP ASSESSMENT RESPONSE TO QUESTION 421.02 PAGE 6 op 6 SRP ACCEPTANCE DE VI ATION JUSTIFICATlON 4 (j) BTP ICSB 26: (continued) accordance with Regulatory Guide 1.75 as , required by GE specifications. As indicated - in the response to question 421.38, single ' failures associated with ca' ole or sensors in the non-seismic area will not jeopardize the integrity of the RPS. Where exceptions are taken by customer /AE (i.e., applicants turbine control valve fast closure and turbine stop valve closure sensors), isolation is provided to protect the integrity of the RPS. i l l l l l l
*Unless otherwise indicated, all references are in GESSAR II .
F/WA L DRAF7^ 6 421.04 QUESTION Discuss in detail, your design of the bypassed and inoperable status indication system using detailed schematics. Provide the following additional information in your discussion:
- a. Your conformance with the recommendations of Regulatory Guides 1.47 and 1.22 (Positions D.3a and 30). -
421.04 a RESPONSE Conformance with Regulatory Guides 1.22 and 1.47 is discussed in GESSAR II, Sections 7 1.2.10 5 and 7 1.2.10.10 respectively; and , in the analysis sections for the various systems. The GESSAR II design is in full compliance with Regulatory Guide 1.47 and with positions D.3a and 3b of Regulatory Guide 1.22. Refer to Question 421.42 and its associated response for bypass and inoperable conditions of the HPCS.
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421.04 (b) @ ESTION F/NAL PRM T Provide the design philosophy used in c61ecting whi:h equipsent and systems to monitor, incisding auxiliary and support systems. (* 42l.04 (b) RESFONSE In general, the following design philosophy can be inferred and is a summary of the designers interpretation of the content of Reg' Guide 1.47. a) Automatic Indication at the system Level on ions of the System
- Loss of a train is annunciated
- Motor operated valves in test are indicated by lights
- System isolation (valve closure) is indicated by lights b) Automatic Indication at the System Level When Auxiliary Systems are Lost
- Loss of auxiliary temperature control, level control, cooling water and pump turbine drivers are inntncierted c) Automatic Indication for a Train or Component
- Loss of motor operated valves or pumps that can cause loss of a train are annunciated
- Loss of power, logic power, equipment in test or calibration is indicated by lights
- All RPS out-of-service status is annunciated d) Manual Initiation of Bypass Indication
- Bypass of any channel or train is indicated by lights These guidelines havs been applied to those safety-related systems that are discussed in FSAR Sections 7 2. 7 3, 7.4 and 7.6. The specific safety-related systems is given choicg#p' in the f 'g,oggghts i
Issentially for lights are provided for component status. Annunciat&rs are provided for auxiliary systems and ma,jor components whose failure could render a primary system inoperative. If any component or aus-iliary system does cause loss of a train or the pystan, then this condition is annunciated at the system level. These indications serve to provide the operators with a convient *==av status so that actions can follow to observe the individual status indicators and return the affected component or system to service. Design of the system allows testing during nozinal operation and precludes the possibility of adverse effects on safety systems. Itose portions of the bypassed / inoperative indication system which, when faulted, could reduce independence between redimdant safety systems are electrically isolated frcan the protection circuits. RECEIVD ( JAN 271g3 Rw. snm I
k 421.04 e QUESTION Provide a discussion of how your design of the bypass and inoperable status indication system comply with positions B.1 ( through B.6 of Branch Technical Position ICSB 21. 421.04 c RESPONSE The design of the bypass and inoperable status indication system complies with positions B.1 through B.6 of the BTP ICSB 21 as follows: B.1 The bypass /inop. indicators and annunciators are located on control room panels convenient to the operator. They provide necessary information to the operator concerning status of each safety system. B.2 There are no safety systems shared between one unitiand another in the GESSAR II design. Therefore, position B.2 does not apply. B.3 Eo~~means are provided to cancel erroneous bypass /inop. indications. Therefore, position B.3 does not apply. B4g The annunciators and status lights are not safety related. However, no safety action is required by the operator based solely on 'a annunciator indication. ( Administrative procedures by tilityk pplicant) ( na Interfaces between annunciators and safety-related logic are optically isolated such that no annunciator failures could cause failures of essential safety functions. Status lights are retnined in the divisional circuits and are qualified with the panels housing them. Compliance with Regulatory Guide 1 75 mesured redundant safety system independence is not compromised. B.6 The design of the system allows testing during normal operntion. in addition, indicator and annunciator lamps are testable by means of test switches on the control room panels.
i fWh NY 421.04 d QUESTION
. Provide the list of system automatic and manual bypasses in
( light of the recommendations of Regulatory Guide 1.47 421.04 d PESPONSE (letter datedk3L
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The requested lists are tabularized and ,tt: 2:d = 1ppert :- 3 A ttacM*cW1 (NSSS list for the Nuclear Island. Approx.19 pages) and as AttecAarent-M ::di 2 (Non-NSSS l list for the Nuclear Island. Approx. 51 pages). Yhe = M . /Est icant sleall fronde the list of aurowarie sud eaawel heresses for a t least flee folleviq stp te ns : Esse *rf't'nl/Ntes Zenvece Ve ter sys tem, piesel Contfos.1 geneest.or feiers **/ aqi T'**esened syste are
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Attendiu '7A. Any s tae> &QR Jgste.;ne ye a vivi.* bg indientan $o ,coe,,0 /# v rT4 _421.04 e QUESTION Reyntmy se; I.ysj ska he /s Si esTVfoid kg tse ^ tappf g Provide a discussion of the hardware features employed to provide a consolidated display, including human factors consider-ations, of the bypassed and inoperable status of engineered safety systems (ESF) equipment. (Refer to Regulatory Guide 1.47.) 421.0$ e RESPONSE The displays of the bypassed and inoperable status of ESF systems / equipments are grouped together by systems at the respective control panels. The bypass end inoperable conditions are indicated at the system level (e.g. LPCS system "out of service") as well as at the component level (e.g. " injection valve in manual override). In addition, such inputs are fed to the Emergency Response Information System (ERIS) to provide a consolidated display of systems status. The ERIS is described in Appendix 18B of GESSAR II. I Audible alarm (annunciators) are included to attract the operator's attention when the status of the safety system changes to/from the out-of-service condition. Switches at the control panels provide manual capability to activate the indicators and audible alarms. 421.04 f QUESTION Provide a discussion of the rationale for your statement on page 7 5-42 of your FSAR that Regulatory Guide 1.47 which requires an automatically operated indication of the bypassed and inoperable status, is not applicable. 421.0% f RESPONSE ~ The safety-related display instrumentation (SRDI) itself does not perform any automatic safety function. It is designed to operate continuously and there is no provision for automatic or operating bypasses. Its redundant channels meet the single failure criterion. Removal of instrumente. tion of a single channel for servicing during plant operation is administratively controlled. Therefore, automatically operated indication of the inoperable status of the SRDI is not applicable.
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FINAL DRAFT 421.13 QUESTION In Table 7-2 of Section 7.1 of the SRP, we provide an applicability matrix for various sections of Chapter 7, including references to the appropriate NUREG documents. We note that you provide general information on this matter in Appendix A of your FSAR. You should be prepared to provide at a forthcoming meeting, more detailed information, using drawings as appropriate, indicating how your proposed design satisfies the following Tfil action items:
- a. II.D.3, Relief and safety valve position indication.
- b. II.E.4.2, Containment isolation dependability, Positions (4), (6) and (7).
- c. II.F.1, Accident monitoring instrumentation, Positions (4),
(5) and (6),
- d. II.F.3, Instrumentation for monitoring accident conditions (Regulatory Guide 1.97, Revision 2).
- e. II.K.1.23, Reactor vessel level indication.
- f. II.K.3.13, HPCS and RCIC initiation levels.
- g. II.K.3.15, Isolation of HPCS and RCIC.
- h. II.K.3.18, ADS actuation.
- i. II.K.3.21, Restart of LPCS and LPCI.
- j. II.K.3.22, RCIC automatic switchover.
l Discuss the applicability of the resolution achieved by the BWR Owners Group for the items listed above, to your proposed design. t 421.13 RESPONSE The meeting requested in the question was held December 7-9, 1982. It was agreed between GE and the NRC that information contained in Appendix 1A sufficiently describes items b e.g,1 and J. The following is provided to supp11 ment appendix 1A for the remaining items:
- a. (See following page)
421.13 a. (RESPONSE CONTINUED) y[ SAFETY RELIEF VALVE POSITION INDICATION Three pressure switches are installed in each SRV (including ADS) discharge line to monitor line pressure and give a positive indication of valve position. The switches are arranged in a two-out-of-three logic and actuate a common control room annunciator on high discharge line pressure. The annunciator is continuously on when pressure is above the pressure switch set point for any logic group. The pressure switch set point is high enough to avoid spurious alarms (e.g. leakage around the valve) yet low enough to give a positive indication of an open valve. Each SRV valve is provided with open-closed lights on the front panel in the main control rrem near the SRV manual switches. The lights are connected to the SRV discharge line pressure switches. These pressure switches are also connected to the process computer via isolators in order to provide a permanent record of the history of each SRV actuation. The pressure switch power supply is class IE. A power system monitor (sensor and/or associated power supply failure) annunciator providesindication of power supply failure. All pressure switches and related components are qualified to seismic category 1 requirements and qualified to operate in their respective environments. In addition, a diverse monitoring raethod is available. A temperature element is installed on the safety / relief valve discharge piping several feet fro..i the valve body. The temperature element is connected to a multipoint recorder in the control room to provide a means of detecting safety / relief valve leakage during plant operation. Ilhen the temperature in any safety / relief valve discharge pipeline exceeds a preset value, an alarm is sounded in the main control room. The alarm setting is enough above normal rated power drywell ambient temperatures to avoid spurious alarms, yet low enough to give early indication of safety / relief valve leakage. Non essential power is used for this monitoring system. 421.13 c. Information is provided in Appendix ID as indicated in the response to question 421.06 concerning Regulatory Guide 1.97. 321.13 d. Information is provided in Appendix ID as indicated in the response to question 421.06 concerning Regulatory Guide 1.97. l l 421.13 f. l HPCS is presently designed to " restart" (injection valve reopens) following a level 8 trip as described in Subsection 7.3.1.1.1.1.C.4 of GESSAR II . The comitment to modify RCIC with the auto-restart feature is found in Appendix 1A, Section IA.58. A copy of the section (marked up with minor corrections) is attached along with the referenced section 15D.2.1.4.1 which details the modification in conjunction with NUREG-0737. i
431,13 ,, F /N4 MFT The BWR Owners' Group submitted a letter to tiie NRC (BWROG-8260, T.J. Dente to ' D.G. Eisenhut, October 28,1982) which identified 8 options for resolution. The NRC has judged option 2 (ELIMINATE HIGH DRYWELL PRESSURE TRIP AND ADD MANUAL INHIBIT SWITCH) and option 4 (BYPASS HIGH DRYWELL PRESSURE TRIP AND ADD MANUAL INHIBIT SWITCH) to be acceptable. Thereforethe applicant will commit to one of the following: e Impliment Option 2 or e Impliment Option 4 or e Renegotiate NRC approval for another option
l
// V RE GESSAR II 22A7007 238 NUCLEAR ISLAND d2 I95 REV. 4 P. . ST E 1A.58 SEPARATION OF HIGH-PRESSURE COOLANT INJECT.>h AND REACTOR CORE ISOLATION COOLING SYSTEM INITIATION LEVELS -- ANALYSIS AND IMPLEMENTATION (NUREG-0737 Item II.K.3.13)
NRC Position Currently, the reactor core isolation cooling (RCIC) system and the high-pressure cooisnt injection (HPCI) system both initiate on the same low-water-level signal and both isolate on the same high-water-level signal. The HPCI system will restart on low water level but the RCIC system will not. The RCIC system is a low-flow system when compared to the HPCI system. The initiation levels of the HPCI and RCIC system should be separated so that the RCIC system initiates at a higher water level than the HPCI system. Further, the initiation logic of the RCIC system should be modified so that the i RCIC system will restart on low water level. These l l changes have the potential to reduce the number of l challenges to the HPCI system and could result in less
- stress on the vesssl from cold water injection. Analyses should be performed to evaluate these changes. The analyses should be submitted to the NRC staff and changas should be implemented if justified by the analysis.
Response
The response to this task will be divided into two parts: the first response will address the need to separate the RCIC and HPCS initiation level, and the second response will address the need to provide an l , auto-restart feature for the RCIC system. { 1A.58-1 l 132A28 - _ _ . _ _ _ _ . _-
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h lA.58 SEPARATION OF HIGH-PRESSURE COOLANT INJECTION AND REACTOR CORE ISOLATION COOLING SYSTEM INITIATION LEVELS -- ANALYSIS AND IMPLEMENTATION (NUREG-0737 Item II.K.3.13) (Cont'd) Response (Cont'd) Evaluation of HPCS and RCIC Initiation Level The BWR Owners' Group sponsored a program to evaluate this concern. The results of this program were submitted to the NRC via a letter from R. H. Buchholz, General l Electric Company, to D. G. Eisenhut, Director of NRC, dated October 1, 1980. I The conclusion drawn from this analysis is that the separation of HPCS and RCIC initiation setpoints is ( unnecessary for safety considerations. The basis for l this conclusion, as described in the above referenced letter, is that for rapid level changes associated with accifient scenarios and severe transients, their initiation would be essentially simultaneous in that possible separation distances could not preclude HPCS challenges; likewise, for slow level changes due to small leaks or slow transients, adequate time exists for manual initiation of RCIC by the reactor operator, prior to HPCS auto-initiation. As a result of the above challenges, thermal stresses will occur in the reactor vessel and its internals. The most. severe thermal cycle due to RCIC and HPCS p initiation at the current low water level was assessed l and compared to the thermal cycle analysis for the limiting reactor components. Furthermore, operating 1A.58-2 132A29 _ _ _
/ R .tiVE GESSAR II D C2 IS P'. 22A7007 238 NUCLEAR ISLAND REV. 4
. s1 ,, 0 1A.58 SEPARATION OF HIGH-PRESSURE COOLANT INJECTION AND REACTOR CORE ISOLATION COOLING SYSTEM INITIATION LEVELS -- ANALYSIS AND IMPLEMENTATION (NUREG-0737 Item II.K.3.13) (Cont-d)
Response (Cont'd) plant experience was evaluated to estimate the frequency of occurrence of HPCS* and RCIC initiations. Based on this evaluation, it was concluded that the current design is satisfactory, and a significant reduction in thermal cycles is not achievable or necessary. Evaluation of Proposed Auto-Restart of RCIC The BWR Owners' Group sponsored a program to evaluate this concern and develop an appropriate modification. (- The results of this program were submitted to the NRC via a letter from D. B. Waters, Chairman of BWR Owners' Group, to D. G. Eisenhut, Director of NRC, dated December 29, 1980 (Reference 20).
.e :en uati n of audifienti...
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automatic restart 4:n__;;J;e th;t ;.t would contri-bute to improved system reliability and that it could be accomplished without adverse effects on system function and plant safety. Therefore, the 238 Nuclear Island design will be modified to allow automatic restart of the RCIC system following its trip on high RPV water level.
*The HPCS system replaces the HPCI system in the 238 Nuclear Island. The above referenced BWR Owners' Group analysis
( addresses the use of both systems. lA.58-3 . 132A30
R tiVE GESSAR II g g9" ]q* 22A7007 238 NUCLEAR ISLAND REV. 4 RW U 3 ( - 1A.58 SEPARATION OF HIGH-PRESEURE COOLANT INJECTION AND REACTOR CORE ISOLATION COOLING SYSTEM INITIATION LEVELS -- ANALYSIS AND IMPLEMENTATION (NUREG-0737 Item II.K.3.13) (Cont'd) Response (Cont'd) The plant modifications to allow automatic restart of the RCIC system following its trip on high RPV water level will be reflected in Subsection 5.4.6 following n staff approval of this response. A technical desc of this modification is included in Section 15D.2. . . . ( 1A.58-4 5UW.\%R
I GESSAR II R sEl D 22A7007 238 NUCLEAR ISLAND **"' 4 DC 1N P3.M A3 1 ( 15D.2.1.3 Decay Heat Removal (Continued) a stuck open relief valve or a loss-of-coolant accident inside primary containment provide a direct pathway for energy to reach the suppression pool. If available for these events, a flow path to the main condenser limits the amount of energy delivered to the suppression pool. Thus, if RHR system suppression pool or containment cooling mode is unavailable for any reason, this path to the main condenser and then to the ultimate heat sink serves as a backup to the RHR system. Because of the substantial capacity of the suppression pool to absorb the decay heat following a transient or loss-of-coolant accident, the time made available by this capacity allows time for the operator to concentrate on establishing and maintaining adequate core cooling systems as his first ( priority and the establishment of a containment cooling function is of secondary importance. No oparator actions are needed to initiate most of the high pressure and low pressure water delivery systems. This fundamental feature of the BWR design ensures a highly reliable design to prevent core damage. 15D.2.1.4 Plant Improvements Plant improvements for the 238 Nuclear Island are described in Appendix 1A which addresses post-Three Mile Island require-ments. This section describes those specific modifications which are significant in reducing the calculated plant risk (Section 15D.3)'following severe transients or accidents. 15D.2.1.4.1 Automatic RCIC Restart ( This change is made in response to NUREG-0737, item II.K.3.13 (Reference 1). The change increases the 230-A10 15D.2-10
sEl c0 GESSAR II 22A7007 238 NUCLEAR ISLAND DC 1 1 ,2 REV. 7 W. 33 ( 15D.2.1.4.1 Automatic RCIC Restart (Continued) availability of the RCIC system during transients and accidents by allowing the system to automatically restart following high vessel water level shutoff. Existing Systen Operation The RCIC system is described in Subsection 5.4.6. During normal plant operation the steam supply valve to the turbine is closed. Upon receipt of a vessel low water level signal, the RCIC system starts automatically. The following automatic actions occur:
- 1. The steam supply valve to the turbine opens to supply steam to the turbine. Steam line drain isolation valves then close, which isolates the RCIC steam supply from the main condenser.
( ( Once the steam supply valve leaves the fully l n 2. closed position the ramp generator " ramp" function is initiated. This ramp generator controls the acceleration of the turbine via the turbine control valve.
- 3. The gland seal system automatically starts.
~
- 4. Condensate suction valve remeins open or is auto-matically opened to supply water to the RCIC pump. .
- 5. 'The pump discharge valve opens to supply the water .
l to the reactor vessel.
- 6. The cooling water supply valve opens automatically and coolant is supplied to the turbine lube oil
( cooler. 1 15D.2-11 230-C6
R . IVE GESSAR II / 22A7007 238 NUCLEAR ISLAND D C 2 .198 agy, 4 F. ' 1TRO ;
- k. 15D.2.1.4.1 Automatic RCIC Restart (Continued)
- 7. The test bypass valve to the condensate storage tank closes, if initially open.
The RCIC system will automatically shut down upon receipt of any of the following signals:
- 1. Reactor high water level (see modification below)
- 2. RCIC pump low suction pressure
- 3. Turbine high exhaust pressure
- 4. Turbine overspeed
- 5. Auto-isolation signal
- 6. Manual turbine trip pushbutton The shutdown is affected by releasing the spring-loaded turbine trip valve. In order to reset the system it is
. necessary to first close the steam supply valve, then ' drive the motor operator of the turbine trip valve in the close direction until the spring-loaded closing latch mechanism is reset. Finally, the turbine trip valve is driven to the full open position. Closure o'f the steam supply valve also resets the ramp generator, closes the vessel injection valve, closes the minimum flow valve and opens the appro-pria'.e drain valves.
Automatic Reset Modification The planned change (Figure 15D.2-5) utilizes the steam supply valve to shut off steam to the turbine following reactor high water level, rather than using the turbine trip valve. Closure of the steam supply valve puts the system in a partial standby configuration because of the existing interlocks associated with closure of this valve. This I plant change will be reflected in Subsection 5.4.6 following staff approval. 230-A12 15D.2-12
RE JVf ' cESSAR II - 22A7007 238 NUCLEAR ISLAND D C2 19 9 : REV. 7 P. . UR ij ( 15D.2.1.4.1 Automatic RCIC Restart (Continued) Effect of the Planned Changes The planned change will utilize the RCIC steam supply valve (E51-F045) to shut off the steam to the turbine on high vessel level rather than the turbine trip valve. The steam supply valve will now be used to both initiate system opera-tion at low reactor vessel water level and terminate system operation at high water level. 4 The time taken to shut off steam flow will be longer due to _ the nominally longer travel time of the steam supply valve compared to the trip valve. The spring-loaded turbine trip valve closes essentially instantaneously. The steam supply valve closes in fifteen seconds or less. Conservatively assuming full rated flow throughout this extended shutoff ( period and a maximum rated RCIC flow of 800 gpm, an addit.ional 200 gallons will be added to the rear:ar vessel following the high vessel water level trip. This volurr.e addition has an insignificant effect on high vessel level transients including those involving high-flow rate systems (e.g., HPCS) (Subsection 15.5.1). Additional logic circuitry is added as shown in Figures 15D.2-6 and 15D.2-7. Also, an additional annunciator is added (Figure 15D.2-8) because the existing turbine trip alarm is . produced by a limit switch on the turbine trip valve. The total effect on the 238 Nuclear Island design is to improve safety. The operator is no longer required to manually reset the system following a high vessel water level trip to permit later operation if needed. He will no longer be distracted by the reset action and the possibility ( of inadvertent failure to reset is eliminated. The change 15D.2-13 230-C7 -
I ~' RECWELV GESSAR II g"o 22A7007 238 NUCLEAR ISLAND - REV. 4 P ... $1 4 k 15D.2.1.4.1 Automatic RCIC Restart (Continued) utilizes the steam supply valve to terminate steam flow on high water level only. The other five RCIC trip parameters will still close the turbine trip valve requiring manual reset of the system. 15D.2.1.4.2 RCIC Break Detection Logic Modification This change is made in response to NUREG-0737 (Reference 1), Item II.K.3.15. The change increases the starting reliability of the RCIC system by reducing the likelihood of an inadvertent trip during system startup. Existing System Operation
, Each RCIC steam supply line is provided with two normally k open isolation valves (E51-F063 and E51-F064). These valves close autcmatically upon receipt of an isolation signal.
Each line contains a flow metering device located downstream of the isolation valves. The flow sensing system will initiate closure of the isolation valves when the flow in that line exceeds 300% of rated. A pipe rupture can procace up to ten times rated flow. The issue raised by NUREG-0737, Item II.K.3.15 (Reference 1), is that the 300% setpoint may be momentarily exceeded during the RCIC start sequences causing unnecessary trip of the RCIC system and thus less than optimum reliability. Changing the setpoint would require extensive accident analyses involving the 1cak detection systems as well as'the RCIC system. Addition of a time delay to the break detection circuitry directly addresses the problem and can be designed to have no impact on the currently documented accident
! analyses of RCIC steam supply line breaks (Subsection 15.6.4).
230-A14 15D.2-14
f (\ f&'A l WW 421.18 Provide a detailed discussion of your methodo' logy to establish the (7.1) trip setpoint and allowable value for each RPS and ESF channel, i (7.3) including the following additional information: -
- a. The trip value assumed in your analyses in Chapter 15 of your FSAR.
- b. The margin between the combined channel error allowance and the
(~ - total channel error allowance assumed in the accident' analyses.
- c. The values assigned to each conponent of the coinbined channel error allowance (e.g., process measurement accuracy, sensor calibration accuracy, sensor drift, sensor environmental allowances and instrument rack drift), the basis for these values and your methodology to sum these errors.
- d. The degree of your conformance with the guidance provided in Positions C.1 through C.6 of Regulatory Guide 1.105. ,
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- l The method employed to establish adequate margins for instrument setpoint drift, inaccuracy and calibration uncertainty as discussed in NRC Regulatory Guide 1.105 is' explained by i reference to Figure 1. Because of the generic nature of this I figure it is not drawn to any scale and is used solely to illustratewith Starting the aqualitative Safety Limit relationships of the various margins.
as indicated at the extreme right l hand of the figure, the first margin extends to the point marked Analytic Limit. This margin is there to account fo r uncertainties in the calculational model used but excludes allowances for instrumentation. Thus the calculational model can assume ideal or perfect instruments. The next margin is i between the Analytical Limit and the Allowable Value of the parametric setpoint, and accounts for instrument errors and l calibration capability for the specific instrumentation. The ' remaining margin which is of interest from a safety standpoint is that shown between the Allowable Value and the Instrument Setpoint. This margin is that which is deemed adequate to cover instrument drift which might occur during the established surveillance period. It follows that if during the surveillance ' period'an instrument has drifted from its setpoint in a non-( conservative direction but not beyond the allowable value, then the instrument performance is still within the requirements of l the plant safety analysis. In this case, a Licensing Event l t Report (LER) would not be required. , ! For completeness Figure 1 shows further margin between the Instrument Setpoint and the Maximum (Licensed) Operatir.g Point for the plant. During plant operation transient overshoots may occur for certain parameters and instrument" noise" may be present. The instrument setpoint may also drift in a conservative manner. There must be sufficient margin between the instrument setpoint and the maximum operating point to avoid spurious reactor scrams or unwarranted system initiations. Not all parameters (functional units) have ad associated analytical limit, and a Design Basis (DB) limit is indicated. In general, the analytic limit is employed in those cases where a functional unit setpoint is directly associated with an analyzed abnormal plant transient or accident as described in the FSAR, Section 15. Where a design basis limit is used it is not always possible to provide simple quantification of the limit, e.g., IRMs , are only required to overlap in range with portions of the SRM and APRM ranges. A similiar situation occurs with the main steam line radiation sensors which have a setpoint based essentially j on previous operating experience. l' I l
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WW Ev.tluations performed to date indicate that there S considerable conservatism in the design analy' sis to accommodate the ef f ects of harsh environments. Instrument performance under harsh environmental k w conditions program. can be evaluated based on results of the applicant's equipment environmental qualification
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LU-question 421.18- Additional Informaticn F/M L Pmr [ Establishment of Protective Instrument Setpoints (BWR)
! The otdective is to ensure that all protective instruments will perform their safety trip functions at values of the measured parameter which do not violate the plant safety analysis or design basis. Regulatory guide 1.105 supports this objective by requiring that each setpoint shall include an allowance for the accuracy limit of the instrument, the cal-ibration capability, and the potential drift of the setpoint between calibration checks. -
Instrument accuracy can be specified, and qualified to meet the specification. A calibration margin can be allocated based on generally available " state of
= art" equipment to be used by the operator. The determination of an adequate , allowance for instrument setpoint arift is more canplex, and is &?
t function of many factors. Methods of establishing an adequate k drift margin may vary significantly; being largely dependent on g the specific application. However, regardless of the tasis for the setpoint 7 drift allowance, its adequacy must be demonstrated empirically and consistently y [ in the field. It follows tha.t this essential criterion will be met when successive calibrations show that the setpoint remains within the allowable t value. It is clear that with this condition satisfied, the precise contributions from individual factors to the overall drift are only of academic interest. c d n { Another hoint to be considered relatiye to establishing adequate protective instrumentation setpoints is the danger of believing that a common methodology h( p can be applied. A good example is afforded by.the BWR Reactor Protection System, which, depending on the product line, has some ten or eleven instrumented functions which may cause reactor scram. An examination of these functions with an emphasis on instrement drift, demonstrates the individual nature of the issue.
- b ^
The IRM scram function is a backup to the APRM scram outside the "RUN" i mode, ie in the less than 15% power range. The design basis is essentially to provide a monitoring facility which overlaps with the SRM and APRM systems. This overlap is checked (tech specs) during plant startup and shutdown. A J nominal scram setpoint of 120/125 is used and applies to all ranges of the. instrument as pover is increased. An instrument drift (electronics only) i of 2/125 is used to monitor electronic performance betweensuccessive surveillance 3 - checks. (Instrument full scale is 125 divisions). No attempt is made to e calibrate the IRMs in terms of a power measurement, due to the larga variations which result whenever a control rod is moved near to the sensor. It follows J that the setpoint drift from this sourcefar outveinhs any other drift con-A siderations. As stated, alectronic drift is checia , and clearly sensor i drif t is of 'ittle concern in this application. x 8
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The APRMs use the LPRMs as the source sensors. F WA L MAfr It is well known that the LPRM sensitivity varies with exposure and that these sensors are
/ affected by changing control rod pattern. To offset these effects the APRMs are caltbrated at least weekly against a heat balance. Thus, these b major drift effects are satisfactorily accounted for without the requirement for evaluation of LPRM sensor drift. As in the case of the IRMs. the APRM electronics are allocated a drift allowance, in this case 2%. The high frequency of calibration of the overall measurement removes any significant concern for drift. .
In the case of Main ~ Steam Line Isolation Valve Closure, a mechanically attached position switch must function within the first- 10% of main valve movement towards closure. Examination of the mechanical design shows that drift is virtually impossible. Howe'ver, a 1% drift allowance is made, which is in reality an allowance for measurement differences when successive surveillance checks are made. No electronics are involved. For the Main Steam Line Radiation High Scram it should be noted th'at no credit is taken for this scram function in the plant safety analysis. The setpoint for this function is more correctly related to the detection of a rapid and significant fission product release from the fuel to the coolant, such as might result from the postulated and highly improbable rod drop accident. For thisa ccident condition, the safety analysis assumes a scram frcra the APRM. 'The design drift allowance for the Main Steam Line Radiation monitors was chosen to ensure that the trip setpoint would remain within the allowable value over the period between surveillance tests. This allowance is ba applicat3cnovermanyyears.sedonfie)dexperiencewiththesamemeasurement j k The Turbine Stop Valve Closure scram is derived in most cases frcm position switches, which are mecnanically coupled to follow main stop valve movement. Because of'the mechanical nature of the measurement, drift is not expected, although an allowance is provided. No electronics are invol,ved. The' Turbine Control Valve Fast Closure scram is obtained from pressure switches which measure the loss of oil pressure at the main turbirie control valve actuator disc dump valves. The design basis (Safety analysis) requirement is the scram shall be initiated within 20 or 30 milliseconds after main control valve initial movement, depending upon product line. As a matter of fact, the scram obtained in this way results in scram initiation in advance of train control valve initial movement. Furthermore, a wide range of the pressure switt.h setpoint is available from which the scram is initiated. Consequently, drift in this setpoint is of little concern because excessive drift would still allow the scram to occur before it is actually required. The Scram Discharge Volume- Water Level High scram is based on measuring water level in the scram discharge volume by means of float switches or analog pressure transmitters. For float switches, drift is not applicable due to the mechanical nature of the measurement. The analog transmitterrare treated in the same way as other water level measurements mentioned below. Two' points relative to this measurement may be noted. Firstly, considerable margin exists in the setpoints to be used on account of the excess discharge volume available, thus drift is not a significant concern. Secondly, earlier indications are given at lower levels (alarm, followed by rod block) which alert the operator, and this scram function does not have a setpoint which is used in the transient analysis.
~ FWM PKAFT~
For Reactor Vessel Steam Dome Pressure-High, Reactor Water level and Dryw311 Pressure drift. similar considerations are made with regard to instrument setpoint Many reactor years of operational experience exist for each application in identical situations and environments. This cumulative experience is used ( to establish overall' drift allowances which in conjunction with appropriate i surveillance (calibration) intervals, ensure,that allowable setpoint values are not violated. The reactor protection systen; is a major safety system which involves protective instrumentation setpoints, and is called upon to operate not infrequently. General Electric believes that basing drift allowances largely.on operating experience has been amply validated. Also, that each application should be examineef on its merits when considering the significance of setpoint drift. All other retpoints for BWR safety systems are based on these principles. ' f
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TABLE 1 REACIUt SCRAM INSTRUIGt'fT SE170IN13 Techniest Amstytie or Design Item Nominst Spoolflestion Design Basis Ca11bre- Drift Number Trip Fasetion Trip setpoint Limit Limit Aeonraey ties Allowenee Resctor Protection Systes 0.2%I *I 1.0lI*I 1 Soares Range 5 5 2 x 10 :ps 4 x 10 eps D.siga 2.0%
- Noaitor Neutros basis Flux - Upscale 2 Intermediate 120 Divisions 122 Divisions Design 4.0 1.0 3,i Range Monitor basis Divistees Divisiese Divleless Neutron Finz -
Upscale e 3 Average Power 15 20% Destas 0.2% 1.05 2.05 Range Nonitor baals Neutros Flux - 1*pscale (Not. Run Mode) ( - l 4 Average Fovs. Range Monitor Simulated normal - Pcwor - Upscale ,
- e. Flow refer- 0.66W + 48% 0.66W + 51% 0.66f + SM S.05 2.05 2.05 ,
enced -
- b. Hist flow 111% 113% 114% 0.2% 1.05 2.05 clasped 5 Average Power 118% 120n 122% 0.2% 1.95 2.06 Rangt Wenitor -
Upscale (Rua Mode) See Footnotes at end of Table. l l
TABLE 1 (Coattamed) Teenaloal Analytte or Desigs Item Nominal Spootfication Destga Basis Calibre- Drift Number Trip Fanotion Trip Setpoint Limit Llett Aeearney tion Alloveneo l l Reactor Protection System (Contissed) l-6 Rosetor Vessel 1064.7 pels 1079.7 psig 1095 pets 15 ps! 9 ps! 15 po!
- . Steam Dome Pressure - High 7 Reactor Vossal 11.4 is. 10.3 in. 10.2 la. 0.6 in. 0.12 la. 0.6..la.
Water Level - Low, Level 3 3 Main Steam Line 94% Opea 93% Opes 905 Open 25 2% 11 Isoletion Valve - Closure (Run Mode Daly) 9 Nain Stese Line 2.5 x full 3 x is11 Desiga 205 205 205 Radiation - High power beek- cpower beek- basis grosad gronad 10 Drywell 1.73 peig 1.93 pois 2.00 peig 0.05 pet 0.04 pet 0.1 pet Pressare - Eigh 11 Scram Discharge (b) (b) (b) 1.5 la. 0.3 is. 1.5 la. Volnse Water
. Level - High 12 Tarbine Stop (e) (e) (e) - - -
Valve - Closure 13 Tarbine Control (e) (e) (e) - - - Valve - Fast closure, Trip 011 Pressure - Low l , See Footnotes at and of Table.
l t t l ( TAB 12 1 (Contissed) l l Maalasse ' Technical Analytte or Design 1 ten Nominal Specification Nanber Trip Fanetion Design Basis Calltre- Drift Trip Setpolat Limit Limit Acearney tien A11ovanee-Reactor Protection System (Coattamed) 14 Tarbine Control 27% of spea IdI 28.5% of f 305 of 1,gg of 0.6% of 1.95 poi of C or / rhine span spaa #' spas ' span spaa ' Stop Ysive - Closure (TCYFC/ TSVC) Trip Seren Bypass 15 Reactor Yessel 33.2 is. es.s in. 34.4 in. 0.6 la. . 0.12 la. 0.6 la. Water Level - High, Level 8 , (Ron Mode Only) ,' Footnotes for Table 1 (a) Eqr.av lent linear full scale. t ' (b) his value is based om data to be deteralmed daring lasta11ation. . (e) To be supplied by Castomer. . (d) he span of the transmitter and trip units shall be 0 to 100 percent of the valse of the turbine first stage pressere in psia at turbine valves wide opea (VWO) steamflow. His valse is to be supplied by A/E. . (e) All resetor vessel water levels are reforeseed to lastrument sore whleh is .529.75 Amehoe above seet more.
i i l .I i 71B12 2 ISS.ATION ACTUATION INSTRUMENT SEIPUINIS { Ensinom j feehalent Analytte or Design Item Naminal Speelfication Detiga Basis Calibre- Drift Number Trip Famotion Trir Setpoint Limit Limit Asearney tion A11ovence Reactor Core Isolation Coo 11ag (RCIC) I i RCIC Steam Line (3005) 330.13 Flow - Bish 318 la. N20 314 !a.'E20 in. 5 20 6 la. N 20 1. 2 !a. 52 0 6 !a. 5 20 l 2 RCIC Steam 60 peig $3 pois Destga basis 2 ps! 0.4 pet 2 psi. j; Supply Pressure - Imv 3 RCIC Turbine 10 psig 20 psig Destga basis ,0 . 3 poi 0.06 pet 0.30 ps! Exhaust Diaphragm . Pressars - Eigh l 4 4 Nain Steam Line (a) (3) (a) (*F 2*F 6*F ] (NSL) Tunnet j Ambient Tempers- . tore - High l 5 MSL Tannel (a) (a) (a) 4*F 1*F SeF Differential - Temperature - ! High , i I 6 NSL Tussel (a) (a) (a) - - - Temperatare
'alaer 7 RCIC F4alpment (a) (a) (s) 4 'F 2*F 6eF
.a.r ca Ai.bi ent Temperstar9 -
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TABIE 2 (Contissed' Nerious Technical Aanlytte or .Bestga Ites Nominal Speelfication Design Basis Cet thre- ' Ctift Number Trip Fusotion Trip Setpoint Lielt Limit Aeosraey tion Allowenee - Reactor Core Isolation Cocilag (Contiused) 8 RCIC F4 sipment (a) (a) (a) 6*F l'F 3*F Area Differen-tist Temp. - High . 9 Residssi Heat (a) (a) (e) 4 eF 3*F 6*F Removal (RHR) Equipment Area Ambient Temp. - Hist 10 ERR F4sireent (a) (a) (a) gey 1*F 3*F Area Differen-tial Temp. - High - Shutdora Coo 11ag Isolation 11 Reactor Yessel 11.4 is. 10.8 in. 10.2 la. 0.6 (s. 0.11 is. 0.6 13 Yster Level 3 - Low 11 Shutdows Cut- 135 psig 150 pels 165 pelg 15 pel 3 ps! 15 pet un Pressare Permissive -
- High See Footnotes at end of Table.
I i k TABLE 2 (Comtlaned) ? 4 l l l. Technical Analytte er Maalaus Iten Destga j Nontmal Spootfication Design Basis , Naaber Trly Fasetion Trip Setpoint Calibre- Drift e I Limit Limit AsearseF tion Allowaseo 3 Statdora Coo 11ag Isolation (Contissed) $ 13 RER Egalpment (a) (a) (a) j Area Ambient 4*F 2*F 6*F ] Temperstare - High i 14 RER Equipment (a) (a) (a) 6*F Area Differen- l'F 3'F ~ tial Temperstare - High i Resideal Beat Removal (tER) (Steen Condessing Nede) i 15 RRR/RCIC Steam 144.4 in. E20 150.8 la. Eg0 Design basta Line Flow - High 6 La. 0.12ia. 6 la. 16 RER Ersipment (a) i (a) (a) Area Ambient 4'F 2*F 6*F Temperatarv - j Bigh 1 17 RER Equipment (a) ' (a) (a) ! , Area Differential 6*F 1*F- 3*F { Teorerature - j Uigh I Centaissent Isoletter. 1 18 ' Fleet Enhaast i 305 i SOE Pleans (a) 205 205 smalytte smalytte 264 l ___ Radletion - Nigh limit s limite 1 See Footnotes at end of Table. -__ i
TABIR 2 (Continued) Eastaus Technical Analytte er Desiga 7 ten Nominal Specifiestloc Design Bests Calibre- Drift . N.s.ber Trip Pesetton Trip Setpoint Lisitt Lksit Aeceracy taea A11evance Main Steam Line Isolation . 19 Rosetor Vessel -se.s in. -se.7 is. - 40.9 19. 2.2 ha. 0.44 la. 2.2 !a. Yater Level - Low Level 2 20 Dryve11 1.88 peig 1.93 psig 2.00 peig 0.06 pel 0.02 pet 0.0$ pel Pressure - High - 21 Nais Steam Line 2.5 x full 3 x full power Desism basis 2M 2M 2M ! Radiation - High power boek- backgroned groned t 22 Nain Steam Line 849 psig 837 psig 825 pelg 12 ps! 2.4 pei 12 pel Pressure - Lov 23 Nela Steam Line 169 paid 176.5 psid 178.99 ps! 1.5 pel 1.2 pel 7.42 pel Flow - Bigh (14M) 24 Main Steam Line (3) (a) (a) 4'F 2eF s'F Tunnel Ambient Temperature - Bigh 2$ Main Steam Line (a) (a) (a) 6'F 1e7 SeF Tunnel Diffe?sa-t ui Temperature - l Eigh 26 Condenser 9 in. Hg 8.7/9.3 is. Eg 8.1/10.0 0.6 1s. 53 0.2 la. Eg 0.3 la. Eg Vacuum - Low la. Eg See Footnotes at end of Table.
TABt2 2 (Centiated) Maximum Technical Analytte or Destge Item Noainst Spelfication Design Basis Calibre- Drift Number Trip Peneties Trip Setpolat I,im it Limit Aeestasy tica Allownsee Reactor Vater Cleesup System 27 Reactor Vessel -149.a in. -152.0 14. -154.2 !a. 2.2 in. 0.44 is. "; l a. Water Level - Low, Level 1 28 Differential 79 gym 88 spe 95.6 spe 4.3 spa 4.3 spe 9.6 gym Flow - Eigh 29 Differential 45 see. 57.5 see. 60 see. 2 see. 1 see. 2 s'oe. Flow Timer (Seconds) 30 Rosator Water (a) (a) (a) 4'F 2*F 6*F Cleanup Unit Equipment Area Ambient Temperature - High 31 Reactor Water (a) (a) (e) 6*? 1e7 SeF i Cleanup Unit l Equipment Area Differential Temperature - Rish 32 Reactor Yessel -36.5 la. -stt.7 is. -40.9is. 2.1 in. 0.44 la. 2.2 !a. Water Level - Low. I.evel 2 See Footectes at end of Table , i l t
I TP212 2 (Castissed) . Nazisme ! Teehnical Analytte or Destsa Ites Nominal Spelfication Design Basie Calibre- Drift Number Trip Posettoa Trip Setpoint Limit Limit Assuracy ties A11ewesee Resotor Water Cleanup System (Continued) ! 33 Main Steam Line (a) (a) (a) 4*F 2 *F 6'F - - Tammet Ambient
- Temperature - High 34 Nain Stese (a) (a) (a) 6*F l'F S'F Line Tsanel ~
Differential , Teeparature - High h tsates for Table._2. (a) h be sappiled by Cuetamer. (b) All vetor levels are referenced to instrument sere ohish ic S29.75 isokee ateve vesset sees. I
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TABLE 3 EIERGENCY CORE COOLING SYSTMt3 ACTUATION INS 1RUNENT SEFFOINIS i Naalaus Techstest Analytte or Design Ites Nominal BroolfJcation Design Basis Ca11 bra- Drift Number Trip Panetton Trip Setpoint Limit Limit Aseursey tios. A11ovameo Righ Pressure Core Spray (EPCS) 1 Reactor Water -se.s in. -se. 7 f a. *40.9 la. 2.2 in. 0.44 la. 2.2 is. Level - Im , Lovei 2 2 Drywell 1.C3 peig 1.94 psig 2.00 pois 0.06 pst 0.02 poi 0.05 pet Pressure - High
~
3 CorAeneste C + 3.5 la. C + 0.5 is.( C is. O.2 la. 0.2 la. 0.2 1a. Storage Tank Level - Low 4 Suppression P - 1.1 la.( ' F - 0.5 is.IEI . P la.ISI O.2 in. h 1 la. 0.2 is. Pool Water Level - High 5 Reactor Vesset 51.2 is. as.e is. 64.4 is. 0.6 is. 0.12 is. 0.6 is. Water Level - - High, Level 8 - (Shutoff) See Footnotes at end of Table.
TABLE 3 (Contisse4) Matiassa
, Teobatcel Analytte er Destga Ites Noelsel Spagitieation Design Basis Calibra ~ Drift Number Trip Panetton Trip Setpoint Limit Limit Aseursey ties Allowsoes -
Automatie Depressurization System (ADS) l 6 Drywell 1.88 psig 1.94 ps a g 2.00 psig 0.06 poi 0.02 pet 0.05 pet Pressure - High 7 Reactor Vessel -14s.a is. -152.0 in. -154.5 to. 2.2 la. 0.44 la. 2.2 !a. Water Level - Lov. Level 1 - 8 ADS Timer 115 sec. 117 see. 120 see. 2 see. 1 see. 2 see. (Seconds) 9 Low Pressere 145 psig 140/150 pois Dest'ga basis 3 ps! 0.5 pet 2.5 pel
- Core Spesy i Pump Discharge Pressure ~
Pe rmis sive l 10 Residual Best 125 psig 122 psig Destga basis 3 ps! 1 Pet 3 pet l Removal (Low I Pressure Coolant Inj ectica Mode) -- Pamp Dis.-harge . . Pressure - Permissive 11 Reactor Vessel 11.4 13. 10.8 in. 10.2 !a. 0.6 is. 9.11 is. 0.6 is. Water Level - Low, Level 3 9 See Footnotes at end of Table.
TABt2 3 (Coattamed) i , Nazimaa j Taehntent Analytte or Destsa Ites helmel Spoolfication Design Basis Calibre- Drift Number Trip Fr.aotles Trip setpotat Limit Limit Aeonesey ties A11ovasoo Lara Pressure Core Spray saa Low Pressure Coolant Injection - Loop A l ] 12 Reactor Yessel -14e.e is. -152.0 la. -154.2 is. 2.2 la. 0.44 in. 2.2 la
- Water Level -
l Lov. Level 1 ,_ 15 Dr5ve11 1.88 pair, 1.94 peig 2.00 peig 0.06 pai 0.02 poi 0.05 ps! 4 l Pressure - liigh - 14 Not Appliesble 15 Pump Start (b) (b) (b) - - Time Detey I Low Pressure Ccolant Injection - Imore B and C 16 Reactor Yessel -14a.e la. -152.0 in. ~154.2 !a. 2.2 !a. 0.44 in. 2.2 la. Water Level - Low. Level 1 - 17 Drywell 1.88 pois 1.94 peig 2.00 peig 0.06 po! 0.02 poi 0.05 poi Pressure - High See Footnotes at end of Table.
)
l 4 i TABLE 3 (Coattamed) i Naainu.a .
! Techaloal Analytte or Desiga
- i Itse Nominst Specification Design Baele Calibra- Drift i
Number Trip Peaction Trip Setpoint Limit Limit Aeeareer tion Allowanee , Low Pressure Coolant Injection - Loops B and C (Continase) I 18 Not App 11ceble
. a 1
! 19 Paup Start Tine (b) (b) (b) - - - l Delay - ) f Footnotes for Table 3 1 ) (a) C = Condensate volume which wilt allow time to evitch to pool suotion without Savitellag the M puny. , (b) To be supplied by Customer 1 j (c) All water levels are referenced to imetrament sero wkleh le 529.75 lashoe aheve vessel sere. (d) Pool high level l i
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GENERAL @ ELECTRIC i { * '"*" 249A1238
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EMI SUSCEPTIBILITY TEST GUIDE f muutmu
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249A1238 m .o. 2 GENER At h ELECTRIC NUCLEAR INERGY DIVISION ntv. $
- 1. SCOPE 1.1 This test guide describes procedures for conductive and radiated Electro-magnetic Interference (EMI) tests.
- 2. APPLICABLE DOCUMENTS - None !
- 3. DISCUSSION f I
3.1 EMI is generally propagated to tr.strumentation primarily by conduction and/or rartiation. Inductive- or capacitive-coupled EMI from radiated electromagnetic ) fields are limited to "near-fields" conditinns because the distance from the inter- ' fering source is usually less than A/2n where A is the wavelength of the inter-ference signal. EMI may also be conducted via a comon impedance path such as a gruund loop or mutual conductance circuit. The following types of EMI Susceptibility test procedures are outlined in this test guide:
- a. Conducted EMI transients .
< b. Conducted rf EMI i( c. Radiated transient EMI fttids
- d. Radiated rf EMI fields
( l 3.2 Ik'fi ni ti nns. The EMI susceptibility tests for instrumentation were established , ! as a result of worst-case transient and radio frequency conditions measured in actual fielsi tests. These EMI measurements were conducted in and around nuclear reactor control rooms when various EMI generating sources were operating. Typical items associated with a nucicar power station which generate EMI when energized or decaergized include many inductive components as well as industrial electronic and electrical devices.
- a. THI Transients - EMI transients typically impressed on 110 volt ac power lines by deenergizing an inductive load (eg, relay, solenoid, or electric motor) are generally a 100 to 500 kHz damed oscillatory wave of .iix to seven cycles with a 200 volt maximum peak-to-peak amplitur'a and a characteristic impedance of -
150 ohms.
- b. Radio Freonency EMI - Radio frequency EMI produced by arcinq contacts.
Iltwrescent lic,hting, SCR-controlled circuits, etc. is usually a 0.5 to 100 MHz sine wave that is continuous, anplitude- or frequency-modulated or combination thercM . These sine wave signals can nroduca a maximt:n peak-to-peak (p-p) amplit :ie of 5 V and currents up to 10t, mA.
.n o
4 _ ... . . . . . . m _. . k i 4 249A1238 m wo.2 GEN ER AL h ELECTRIC NUCLEAR Et4ERGY OtVeslON nev. 5
- 1. SCOPE 1.1 This test guide describes procedures for conductive and radiated Electro-magnetic Interference (EMI) tests.
- 2. APPLICA0LE DOCUMENTS - none f f
- 3. DISCUSSION l 3.1 EMI is generally propagated to 9.strumentation primarily by conduction and/or l radiation. Inductive- or capacit4 coupled EMI from radiated electromagietic .
fields are limited to "near-fkiV conditions because the distance from the inter- ' fering source is usually less than A/2n where A is the wavelength of the inter-ference signal. EMI may also be conducted via a cocinon impedance path such as a gruund loop or mutual conductance circuit. The following types of EMI Susceptibility test procedures are outlined in this test guide: , ,
- a. Conducted EMI transients
- b. Conducted rf EMI
- c. Radiated transient EMI fisids
- d. Radiated rf EMI fields 3.2 Definitions. The EMI susceptibility tests for instrumentation were established ,
as a result of v:orst-case transient and radio frequency condition) measured in actual field tests. These EMI measurements were conducted in and around nuclear reactor control rooms when various EMI generating sources were operating. Typical items associated with a nucicer power station which generate EMI when energized or deenergized include many inductive components as well as industrial electronic and electrical devices.
- a. THI Transients - EMI transients typically impressed on 110 volt ac power lines by deenergizing an inductive load (eg, rt: lay, solenoid, or electric motor) are generally a 100 to 500 kHz damed oscillatory wave of six to seven cycles with -
a 300 volt maximum peak-to-peak amplitur'a and a characteristic impedance of 150 ohms,
- b. Radio Freonency EMI - Radio f requency EMI produced by arcinq contacts, Iluorescent lic;nting, SCR-controlled circuits, etc. is usually a 0.5 to 100 fMz sine wave that is continuous, anplitude- or fraque' icy-modulated or t.ombination therret. These sine wave signals can nroduca a maximttn peak-to-peak (p-p) amplit eJ of 5 V and currents up to 10t, mA.
+
-7
' l
(' ! 249Al238 mm 3 GEN ER AL h ELECTRIC l-NUCLEAR ENEhGY DIVis10N 5 !. I
- 4. PROCEDUPE 4.1 -General. The following is a general procedure for perfoming the four EMI tests Identified in Paragraph 3.1 Details v3ry depending upon the equipment under e test ar.d the particular EMI excitatien technique employed. , /
4.1.1 Connect the instrenent to be tested and the test ee.uipment per the appro-priate figure (Figures 1 through 6). The signal lead from the transient generator (Figure 7, and the pwer input lead from the isolation trant former should be 3 feet or less in length. The de resistante to external earth ground for all instruments should not exceed 20 ohms. A satisfactory grcund may be obtained by connection to two cr more 20-foot copper rods driven into the ground (approximate diameter: 1 inch; distance between rods: 20 feet). Ground connections should be made of short wide conductors which have a maximum cractica's cross section (flat straps versus , l . roundconductors). These conductors should he of corrosion-proof high-conductivity
- material (copper not alunintri) to ensure the lowest inductive retetance (which varies directly with frequency) and, consequently, the niinimuni impedance to ground. An
( ideal ground lead would have a length no greater than five times its width. l 4.1.2 After energizing the equipment and applying a 5%-of-full-scale input signal to the instrument under test, verify that the selected type of EMI excitation signal meets the frequency and amplituJ2 specifications of the .ppropriate figree and make adjus'umnic, as required. 4.1.3 Connect both input leads of the oscilloscope to point "A" of the connection figures using a standard (3.5 ft long, x 10) test probe. The observed EMI signal should be small compared 'o the amplitude of Paragraph 4.1.2 (<10%). If greater
- than 10%, there is a conrion-mode problem which might be caused by ground loops which i
should be corrected before preceeding. 4.1.4 Observe the response of the instrument under test while applying the EMI signal; if it is susceptible to the EMI, record the frequency and type of EMI excitation, and detemine the susceptibility threshold level that just initiates the out-of-specification response. The EMI signal should be applied long enough to allos for the respanse time of the instrument under test. 4.1.5 Repeat the steps of Paragraphs 4.1.2, 4.1.3, and 4.1.4 over the frequency range of t'.. particular EMI excitation signal being empicyed. 4.1.6 For considerations in performing the foregoing tests unique to each of the four excitation techniques, see Paragraphs 4.2 through 4.5.2 , l l ( o
. .. s 4
1 1 sr.wo. 4 GENER AL h ELECTRIC 249A1238 j NUCLEAR ENERGY DIVislON 5 . 4.2 Conducted EMI Transients. This test is conducted to verify that the instru- ' ment is not susceptible to conducted electromagnetic transients injected on power input leads. 4.2.1 Reoui rements. No malfunction, undesired response, degradatir.n of perfomance or permanent damage to the instrinent shall occur when one or more dam;,ed oscilla-tory waves (100 to 500 kHz, six to seven cycles, 300 volts peak-to-peak amplitude *, from a bipolar wave transient generator with a 150-ohm output impedance) is applied to each angrounded power input lead. ' 4.2.2 Test Setup. See Figures 1 and 2. l 4.3 -Cnnducted RF EMI. This test is conducted to verify that the instrument is not suscep"Eib'le to conducted rf EMI (continuous wave, frequency- or amplitude-modulated) injected on power input leads. ; 4.3.1 Reaut rements . No malfunction, undesired response, dog.adation of perfomance, ! or pemanent damage shall occur when a sine wave from a signal generator having a j 47-ohm output im?edance is applied to each ungrounded power input lead. The sine . wave shall be a 0.5 to 100 MHz continuous wave (5 V p-p)**, amplitude modulated . (0 to 5 V), or frequency modulated (220 kHz). ( , d . 3. 2 Test Sctr. Ste figui es 3 and 4. 4.4 Radiated Transient Electranagnetic Fields. This test is conducted to verify that the instr'.nent is not susceptible to radiated transient electromagnetic fields via input and output wires and cables. 4,4.1 Requirements. No malfunction, undesired response, degradation of perfomance, or permanent damage shall occur when one or more damped oscillatory waves from a bipolar wave transient generator having an output imperiance of 150 ohms is introduced on conductors wnich are parallel and in intimate physimi contact with each input end output wire or cable. The waves shall be 100 to 500 kHz, six to seven cycles, 300 V - p-p amplitude. 4.4.2 Test Setup. See Figure 5.
- For 110 Vac only. See Figure 2 for de power bus transients.
** For 110 Vac end 24 Vdc pwer lines only; see Figure 4 for other de power bus ampli tudes .
- 1
\
I i
w
. . . _ . . _ - . - . - . . . . - . .. - 0
(. ' 249A1238 G EN ER ALM ELECTRIC sa %o. 5 NUCLE AR ENERGY DIVislON , 4.5 Radiated RF Electromagnetic Fields. This test is conducted to verify that the \.. instrument is not susceptible to radiated rf electromagnetic fields (continuous s, wave, frequency- or amplitude-modulated) via input and output wires and cables. 4.5.1 Requirements. No malfunctions, undesired response, degradation of performance, or pemancrit 6amage shall occur when a sine wave from a signal generator having a 47-ohm output impedance is introduced on conductors which are parallel and in intimate physical contact with each inpet and output wire or cable. The sine wave shall be a 0.5 to 100 MHz continuous wave (5 V p-p), amplitude modulated (0 to 5 V). or frequency modalated (220 kHz), .- 4.5.2 Test Setup. See Figure 6. m O S (
s a (. . ~. u , s : z w itaa . GENER AL h ELECTRIC ' NUCLEAR EMRGY DIVISION , g y, g
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TRANSIENT GENERATOR
=
1AMPED O*,0!LLATURY 150 OHM E TO 7 CYCLES 100 OUTPUT' e TO 500 kHz - O TO 30N 0-p o " :.- 110VAC . I %
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UNDER TEST SCOPE (. --
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NOTES: . l A. The EMI transient should be conducted over a period long enouah the ensure that an EFI *eansient occurs at enuugh points throughout the 360" of the , power frequer.c) to ensure worst case coditions. B. Damped oscillatory EMI transients shall have a repetition rate from 1/2 to i 1 Hz and shall be conducted at 100, 200. 300, 400, and 500 kHz. t FIGURE 1 TEST SETUP FOR COND'JCTED EMI TRANSIENT (110 Vac P0h'ER LINE TEST) (
- e .
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TRANSIENT GENERATOR 150-0HM ~ OUTPUT [ (" i)110VAC DA" PED OSCILLATORY 6 TO 7 C(Cl.ES __ 100 TO 500kHz _- k3WIRETO 2 WIRE WIRE ADAPTER
+5 Y BUS LillE, +0.25 V P-P
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T15 V BUS LINE,'+3.00 V P-P T20 V DUS s LINE, 74.00 V P-P T24 V BUS LINE, T5.00 V P-P I MICR0 FARAD
-w 600V T25 V BUS LINE, - 300 V P-P _g
_ s 1 MICROFARAD [ 600V (- e DC POWER .
+C [ 3+ DC POWER -
INPUT I a SUPPLY _ c . I.- SCOPE 1 INSTP.U!!ENT UNDER TEST NOTES: A. The Eli! transient should be conducted over a period long enough to ensure that an EMI transient occ;rs at enough points throughout the 360* of the power frequency to ensure worst case conditions. D. Dampad oscillatory FMI transients shall have a repetition rate from 1/2 to I Hz and shall bf conducted at 100, 200, 300, 400, and 500 kHz. I I FIGU3E 2 TEST SETUP FOR CONDUCTED EH1 TRANSIENT (CC POLLER LINE TEST) (
( ' 20Al238 sw. no. 8 GEllER AL h ELECTRIC NUCLF.AR ENERGY DIVislON nev.'5 e RF GEhERATOR 3 WIRE TO 47 OHM _ [% e - 0 TO SV P-P t
~
b 500 LHz TO 100 MHz -- _ i + ISOLATION TR%NSf0RP.ER T* 1 0FD THREE FARADAY SHIELDS [00 7 UTC HIT-3 OR E00AL (Z) --1 I r --
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1 II 0 110VAC 110VAC Q l l g 3 -- _ INPUT / i J g_ _ g , T
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T SCOPE UNDER TEST i *. l iiOTE5: A. Scan the full frequency range of the rf generator from 0.5 to 100 MHz by tuning the oscillator through the required frequency range at e rate of 1 to 5 Ituz per second. B. The type of rf EMI susceptibility signals (i.e., continuous wave, frequency-or anplitude-modulated or cemoination thereof) and sweep rate shall be selected for the maximita anticipated effects on the instrument under test. FIGUf:E3 TEST SETUP FOR COND'JCTED RF EMI (110 Vac POWER'LINE TEST) (
(. 249A1238 sw. mo. 9 i GENER ALh ELECTRIC ' NUCLEAR ENERGY DIVISION nav. 5 - RF GENERATOR 4/ OHM - OUTPUT $ I 7 ) 110VAC o ,, t 0.5 TO 100 MHz __
\3WIRETO2 WIRE
! SV BUS LINE,10.25 V P-P ADAFTER
+15 V BUS LINE, +3.00 V P-P T20 V BUS 1.INE, 74.00 V P-P -~'
T24 V BUS LINE, 75.00 V P-P ( - d T25YBUSLINE,[5.00VP-P 1 MICROFARAD / -- 1 MICROFARAD 7 00 VOLT 2 ~# 100 VOLT , ( m
#+
DC POWEi< UC E0k'CR A Ih?UT - o-- --- o- SUPPLY A l INSTRUMENT l SCOPE UNDER TEST NOTES: A. Scan the foil frequency range of the rf generator from 0.5 to 103 MHz by tur.1ng the oscillater through the required frequency range at a rate of , 1 to 5 MHz per second. B. The type of rf EMI susceptiollity signals (i.t:., continuous wave, frequer.cy-or amplitude-modulated or co". bin 6 tion the-cof) and sweep rate shall be selected for the maximum anticipated ef fects of the instrtrien* under test. FIGURE 4 TEST SETOP FOR CONDUCTED RF EMI (DC POWER LINE TEST)
.. :._ o-
. .. . . _ . _ . _ - _. ._ 2 . l C. : 249A1238 sw.wa 10 I j GENER AL h ELECTRIC . NUCLEAR ENERGY DIVISION REV. 5 0 FOUR PARALLEL CONDUCTORS (NOT TWISTED) IN PLASTIC , TUBINGI CONDUCTOR 5 MUST BE IN STRAIGHT LINE (AVOID PfT - CIRCLEORUSHAPEDPOSITIO@ gg E - 11oyA: _ j 150 OHM . 10W .
._- . DAM ...tSCILLATORY l 3 6 10 7 CYCLES :
100 TO S00 kHz ; f _ _ .__ _ . _ __ _____--_ ___ __ ___ _ __ g O TO ,300 V P-P
; -- _ __ _ . _ . _ _ . _ _ _ _ - - p n n, ir 50 FT vvv h I ISOLATION TRANSFORMER
*R oo THREE FARADAY SHIELDS INPflT OR OUTPUT UTC HIT-3 OR EOUAL .
'N r RESISTANCE CIRCUIT UNDER :
VALUE OF A.CTUAL TEST l,--
---] l REMOTE INPUT OR l OUlFUT IMPEDt.NCE VAC A[ ,I l, j:: '
(' ' / U , _ _a i te _. T-110VAC
/ INSTRUMEhT I J !
l'NDER TEST _ SCOPE NOTE.c: A. EMI tr?nsients with a retition rate frcm 1/2 to 1 Hz shall be conducted at ' 100, 2U0, 330, ano 50r kHz. B. A purely rest ive 15c uh- ioad is connected across the two paralle: conductors in the plastic tubing connected to the transient generator (i.e., five 750-ohm, 2-watt carben-composition resistors connected in parallel). C. Input or output circuits which nomally require a shielded cable will be tasted by connecting a 50 foot length of the appropriate shielded cable to the input or output circuit in lieu of connecting the two wires inside the plcstic tubing. The shielded cable shall be taped or tied in intimate physical contact with the entire 5') foot length of the plastic tubing. D. T e plastic tubing containing the four parallel conductors must be kept as straight as possible and any surplus length will not be folded, coiled or placed in a "U"-shaped position, e FIGURE 5 TEST SETUP FOR RADIATED TRANSIENT ELECTROMAGNETIC FIELDS
m=m . . = . . _ . . . --- - . . . . _ C i 249A1238 sw.wo. 11 GENERAL h ELECTRIC ! NUCLEAR ENERGY DIVISION nev. 5 l FOUR PARALLEL CONDUCTORS RF GENERATOR . (NOT TWISTED) IN PLASTIC ; TUBING: CONDUCTORS MUST BE IN STRAIGHT LINE (AVOID . 3 W!RE TO 2 WIRE CIRCLE OR "U" SHAPED 47 OHM ^ ( ADAPTER _ POSITION) OUTPUT i 1 ' . Ill,VAC 47 OHM T 5W - N 0 TO 5 V P-P F 0.5 TO 100 MHz
-4 T=
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-I i ISOLATION TRANSFORMER
*R THREE FARADAY SHIELDS I
INPUT OR OUTPUT UTC HIT-3 OR EOUAL
*R = RESISTANCE CIRCUIT UNDER - - -) --
i VALUE OF ACMAL TEST l l p g REMOTE INPUT OR 110 VAC A5 8 I 8 I I h 110 VAC OUTPUT IMPEDANC[ INPUT t "
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I N ST R v. .m.. . r - ! ' L_% 3 , UNDER TE.iT hC0FE -- NOTES: A. The plastic tubing containing the four parallel conductors must be kept as straight as possible and any surplus length will not be folded, coiled, or placed in a "U"-shaped position. S. Input or output circuits which nomally require a shielded cable wi'. be tested by connecting a 50 foot length c' the aporopriate shielded ca21e to , the input or output circuit in lieu of connecting the two wires inside the l plastic tubing. The shielded cable shall be taped or tied in inticate l physical contact with the entire 50 foot length of the plastic tubing. C. Standing waves should be expected to develop on the 50 foot length of parallel conductors above 3 MHz because of the mismatch conditions which prevail for frequer.cies where 1/5 of the wavelength is shorter than 50 feet. D. A purely resistive 4) ohm load is connected across the two parallcl conductors , in the plastic tubing connected to the rf generator (i.e., ten 470-oh:n, 2-watt, carbon-composition resistors cornected in parallel). E. Scan the full frequency range of the rf generator frnm 0.5 to 100 MHz iiy
- tuning the c:cillator through the required frequency range at a rate of .
I to 5 MHz per second.
# i. The type of rf EMI susceptibility signals (continuous wave, icecuency- or amplitude-modulated, or combins, tion thereof) and sweep rate shall be selected for the ruximu'n inticipated eff ects on the instrtment under test.
FIGURE 6 TEST SETUP FOR RADIATED RF ELECTROMAGNETIC FIELD
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F/NAL DRA Fl~ 421.40 QJESTION Provide a discussion on high pressure / low pressure interfaces and the associated interlocks in Section 7.6 of your FSAR. Discuss how each of the high pressure / low pressure interfaces in your design conforms to our positions in Branch Technical Position ICSB 3. Discuss how the associated interlock circuitry confoms to the requirements of IEEE Std. 279. Your discussion should include illustrations from applicable drawings; e.g., th reactor heat removal (RHR) system. 421.40 RESPONSE Appendix IE contains a full discussion of HP/LP interlocks with specific reference to the series M0V's of RHR under Diversity of Interlocks. Additionally, use of the self-test subsystem increases the reliability of the interlock circuitry beyond the high degree present in testability)(non-NSPS) nud designs. trip vuin nVe folly qualtfth/ 74e 15 ns class iniceI*e N3 Ame/ vere (fremsaitrev comeponents-c.u p& N gn- &f a ma n n sr u e r s ~ < & muJn .i., d4%J ( n ga w + %p m W h * " # g u-a, im : e d ves ttb *1 Describe what annunciation is provided for tite low pressure permissive for the RHR Shutdown Cooling Mode.
*Anwen OE55AR H The current design as shown on the 4 elementary diagrams does not include annunciation for the low pressure pomissive to open RHR valves 7008 and F009.
e Guestion Describe the auto-reclose of RHR valves F008 and F009 (isola whlves in the let-down line from the Recire System) on increasing pressure, e A n swer-Division 3 logic centrols valve 7009 and identical legic in Division 4 controls valve F008. For each valve, either of two channels can cause automatic re-close of the valves. Each channel consists of one reactor pressure sensor and one reactor water level sensor. If reactor pressure exceeds the set-point or reactor water level remains below level 3,the valves re-close. Conysrsely, the valves will open automatically if pressure is below the set-point and level is above level 3.
GESSAR II 22A7007 L('? ( < U
, f rGa #'~ ( 238 NUCLEAR ISLAPD .
Rev. 12 1E.38 REDUNDANCY AND DIVERSITY OF HIGH/ LOW PRESSURE SYSTEM INTERLOCKS (2-ICSB) (Continued) LRG-II Plants include interlocks which prevent the operator from opening these valves when reactor pressure is high. The trip unit setpoints are set at 135 psig as compared to a pressure rating of 500 psig for the piping. The two isolation valves in the suction line have divisionally separated controls. These valves are manually controlled pressure-interlocked valves. Each valve control circuit has two pressure interlocks either of which will prevent he^yalve from being open. It would require a failure of a{l[$/ ransmitter trip unit channels to permit opera-t tion of both valves when the reactor pressure is high. The interlocks are controlled by analog pressure transmitters which :neasure reactor coolant pressure and transmit a signal proportional to the pressure to a solid state trip unit and a visual indicator. This design permits on-line monitoring of the transmitter outputs on analog indicators in the control room so that cross comparison of the output values can be made between channels and other control room pressure indicators. Technical Specifications require a channel check of these systems to be made each 12 hours. The trip units are located in the control room for ease of calibration and testing. i In addition to these automatic protection featuces, administrative controls do not permit placing the RHR system in the shutdown cooling mode until the reactor pressure has been reduced to less ( than 135 psig. The pressure indications used for determining reactor. pressure when placing the system in shutdown cooling are located on the main control panel and are different from those used in the overpressure protection trip system. GESSAR II Position: Same as LRG-II Position (solid state design). W- ['o n solo d - s ta te desips, ir voeld vegon c. p fnilum of /~*b2 .twuSitterl pyip vss i t c h = n n els is coc.k of 2 divisions to p e,-s.u t operst roer of both valves w he" the ec4crer p eesJd* ele'.'38-3 ~
4 GESSAR II 22A7007 238 NUCLEAR ISLAND Rsv. O 7.6.1.5 High Pressure / Low Pressure Systems Interlock (Continued) B. Power Sources The power for the interlocks is provided from the essen-tial power supplies for the associated systems (RHR for the RHR valves and LPCS for the LPCS valves). C. Equipment Design The following is a list of high pressure / low pressure interfaces and rationale for valve interlock equipment: Interlocked Parameter . Process Line Type Valve Sensed Purpose coctin RHRshutdown}f MO E12-F009 Reactor Prevents valve opening supply MO E12-F008 pressure until reactor pressure c.cchny is low, f RHRshutdhCheckE12-F050 N/A N/A return MO E12-F053 Reactor Prevents valve open-pressure ing until reactor pressure is low, f RHR head Check E51-F066 N/A N/A spray MO E12-F023 Reactor Prevents valve opening pressure until reqctor pressure islow,p , RHR Steam MO E12-F087 Steam line Prevents valve opening l t condensing mode AO E12-F051 pressure untilpressureislow,[ LPCS Check E21-F006 of[A ' ressure be- /A system MO E21-F005 tween injec- aintains valve close,d tion valve,'& until differentielC ch'eck valv,e pre'ssure is low A 4
-47C5' system Reactor Maintains valve closed
. spray - CheckE21-F00%
s -MO -E21-F005 vessel until pressure is low
~, .s_yprggr --
^
pressure (Exc EPT FM VALVE FIANVAl~ d tt S- CON T AC Peedwater P61-FF010A&B Reactor-to- Prevents seal ai)r iso-l containment P61-FF0llA&B seal air lation valve openi g isolation differential until differer.tial valve leak- pressure pressure is low age control 1 7.6-33
$ gEcteSES VALVE If p,g g S $ ugg lS IM H 4 , p g p NvAL-AliS'UNTN l
QNL1)
- GESSAR II 22A7007 238 NUCLEAR ISLAND Rev. 0 7.6.1.5.C High Pressure / Low Pressure Systems Interlock (Continued) )
Interlocked Parameter Process Line Type Valve Sensed Purpose MS positive MO E32-F007 Reactor Prevents isolation leakage MO E32-F008 pressure valve opening until control MO E32-F027 pressure is low. Re-MO E32-F028 closes valves if pressure is high. RHR A./B_T nope c//EC/r E12-F041 N/A N/A
-hpef /fd E12-F042 Reactor Prevents valve opening pressure until pressure is low beept fc valve >+t an N/-A M} ~
Cdn rRf D. Circuit Descriptio fre
- S "?f . -
he <e <d6 F d/ve #/Phe v t"" u,,r; i p>e >Su y e ;> /sg.f oe t" ety '!*J 4""N
,R'fe '
At least two valves are provided in C.nh seriese mina w /-A tt> each of -ceurn./ enty these lines syW die-steam condensing, node ~1ine which -has%3 pressure ucing_s.tatus_3stithY relie lye-on_the_. low-pressure ~ Rtt ,.5/10 TOC W N C001.-/,N 6 E off
, The c"lation euctiopalves have[E/Z indepe ~ Frs $ t di" : interlocks to prevent the valves from being opened when the primary system pressure is above the subsystem design pressure. }
These valves also receive a signal to close when reactor pressure is above system pressure.
/
The RHR System head spray motor-operated valve CEl2-FDP3 a is inter h locked to prevent valve opening whenever the primary pressure is above the subsystem de.7ign pressure, and automatically closes whenever the primary system pressure exceeds the subsystem design pressure. SA' O TD GM/ 400uA/6 ftruMN l The RHR System-recirculation dischargg valve E12-F053 is {interlockedtopreventvalveopeningwhenevertheprimaryp is above the subsystem design pressure, and automatically closes
, whenever the primary system pressure exceeds the' subsystem design pressure. This valve must operate for 1cng-term cooling, and has a remote testable check valve E12-F050 downstream. The check valve position can be confirmed at any time. Relief valve E12-F025 J ill handle the leakage of the closed check valve. ;
7.6-34
- GESSAR II 22A7007 238 NUCLEAR ISLAND Rev. 0 7.6.1.5.D em ssure/ Low Pressure Systems Interlock (Continued)
High u em The RHR system vessel injection valve, E12-F042, must operate for short-term cooling. This valve opens upon receipt of an accident signal when the low pressure permissive is reached. This' valve is the fastest opening valve available and it has a re note testable check valve downstream. IN J E C T!!!/ The LPCS system eperger valve E21-F005 must operate for core flooding / spray. This valve opens upon receipt of an accident signal when the low pressure permissive is reached. This valve is the fastest opening valve available and it has a remote testable check valve downstream. The feedwater containment isolation valve leakage control system valves are interlocked to close or to not open whenever the h reactor-to-seal air differential pressure is high. The seal air line isolation valves are also interlocked to close when the seal air line pressure falls below the setpoint. ' T valve leakage control system (E U he main
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valvespare interlocked to close to not open whenever the reactor-to-seal air differential pressure is high. E. Logic and Sequencing The logic for the pressure sensor inputs is one-out-of-two high pressure signals for valve closure. ! F. Bypasses and Interlocks There are no bypasses or interlocks in the high pressure / low pressure interlocks. l l p ! 7.6-35 l ' l . _
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- 22A7007 238 NUCLEAR ISLAND R v. 0 7.6.1.5 High Pressure / Low Pressure Systems Interlock (Continued)
G. Redundancy and Diversity Each process line has two valves in series which are redundan.t in assuring the interlock. The shutdown cooling and h w ffLy & R &TVg/V discharge--suotionp valves have independent r4 di y..rsc interlocks to prevent the valves from being opened when the primary system pressure is above the subsyctem design pressure. i H. Actuated Devices The motor-operater' valves and air-operated valve listed in Subsection 7.6.1.5.C are the actuated devices. I. Separation Separation is maintained in the instrumentation portion of the high pressure / low pressure interlocks by assigning the signals for the electrically controlled valves to ESF separation divisions. The sensors and cabling are in separate ESF divisions. J. Testability The actuated devices can (except those valves kept closed by reactor pressure interlocks) be tested during reactor operation. The sensors can be tested during reactor operation in the same manner that the RPS sensors are tested. Refer to Subsec-tion 7.2.1.1.D.8 for a discussion of typical RPS testing. K. Environmental Considerations The instrumentation and controls for the high pressure / low pressure interlocks are qualified as Class lE equipment. The sensors are mounted on local instrument panels and the control circuitry is housed in control panels in the control room. 7.6-36
F/NA L DNAFF 421.44 @ESTION g In Section 7.4.1.1 of your FSAR, you identify conditions which are non-
- s. itored and which can trip the RCIC turbine stop valve and isolate the system if their setpoints are exceeded. Discuss the details of this design.
s4'21.44 RESPONSE The RCIC turbine trip logic is designed to provide equipment (RCIC turbine and turbine pasp) p a tection for the system If a trip occurs, the operater has an opportunity to correct the situation and restart the system manually. Without the trip protection, the equipment could be seriously damaged re-sulting in loss of its functional capability. The tri) function, while potentially causing short tem loss of system operability, does provide for long tern availability. The RCIC turbine will automatically trip for the following conditions:
- a. High RCIC turbine exhaust pressure (one out of two)
- b. Inw RCIC oump suction pressure (one out of one)
- c. RCIC turbine overspeed (one out of one)
(_ d. RCIC isolation (one out of two) The RCIC isolation logics (A orb), which monitor for pipe breaks in the system, will cause automatic RCIC turbine trips for the following con-ditions:
- a. High RCIC tusine exhaust diaphram pressure (two out of two)
- b. High area ambient temperature (one out of seven from LDS)
- c. High steam line differential pressure (one out of two)
- d. Low RCIC steam supply pressure To maintain system availability, trip sotpcints are selected far enough away from normal operating ranges to prevent spurious trips yet well within necessary ranges to protect the environs and equipment. Selection of reliable, safety related (where required)instamentation and controls provides additional assurance of system availability.
Recent changes, as a result of TMI, also improve system availability. A time delay has been added to the high steam line differential pressure isolation function to alleviate potential inadvertent $ golation and hence RCIC turbine trips, during system startup. Vessel high water level no longer trips the RCIC turbine but instead closes the tusina steam supply valve. This allows for autamatic RCIC system restart subsenuent to a high wntar lavel rignal ie vessel level returns to the low level trin tmint. (
F f NdL MAF7~ Tha R"IC syste is not required nor designed based to meet single failure at the system level. Loss.of its function because of a tuttine trip (authentic cr nise) ( will not impede core cooling since HPCS provides redundancy to RCIC for all present
\ design base requirements.
The 'IMI upgrades discussed in this response are presently not included in Chapter 7 t.!: GESSAR or GESSAR drawings. Modifications will be dono at a later time. Safety-related components and sensors used for the RCIC, including interlocks, are qualified consistant associated with thewith the requirements turbine trip circuitryofare a Class the FIENqstem. The interlocks 6/trip unit type. The transmitter trip units are nuclear sa(oty related Class IE and fully testable. They are equipped with meter and trip point calibration so that their proper operation can be part of the checked by the station plant Technical operators. Equipent test frequencies are supplied as Specificat$ons. , y,+ 's p f M 2T47 h w ende e*<h & de & Ciy 5 4-el M /*1 W sf*4 h 5+5 (le
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' ' In Section 7.4.1.4 of your FSAR, you provide information on the remote shutdown system (RSS). Attachment 2 provides the Instrumentation and Control Systems Branch guidance for remote shutdown capability (i.e., guidance for meeting the requirements of GDC 19). Indicate the extent to which your proposed design of the RSS conforms to the guidance provided in Attachment 2. 421.50 RESPONSE (See Attached) ( O
a m , FlMA L WW ICSB POSITION GESSAR II RSS DESIGN
-10CFR50 Appendix A, GDC 19 (As interpreted in S.R.P. Section 7.4) , o Provide redundant safety grade capability o The RSS is not considered a for remote shutdown assuming no fire damage safety system and is therefore or accident has occured not completely redundant nor safety grade of itself.
Pawever, portions which interface with safety-related systems meet the design criteria for those systems (See GESSAR II, Section. 7.4.2.4.1). Some redundancy is provided through operator action at local panels. o RSS equipment should be seismic.' ally o The RSS panel itself and the quali fied. transfer switches are seismicall) quali fied . The control switches and display instrumentation can be seismically qualified. o Provide redundant instrumentation o See Figure 7.4-3 (RSS-IED) (indicatorij for verification of and 7A.4-3 (RSS-Elementary). safe shutdown conditions. Sufficient instrumentation is provided to verify safe shutdown condition. However, such instruments' are single channel and are not redundant. o Loss of offsite power should not negate o See Figure 7A.4-3 (RSS shutdown capability from RSS Elementary). RSS derives its power from essential busses and is therefore functional during loss of offsite power. o Transfer of control to RSS should not o Only LPCI in one RHR loop and disable any automatic actuation of ESF RCIC are disabled in transfer functions unless such systems can be to RSS panel. However, these manually placed in service from the RSS. equipments can be manually placed in service from the RSS panel. All other automatic actuations of ESF functions operate normally. Therefore, the GESSAR I RSS design satisfies Appendix K. l 0 RSS access via keys or keylock switches o See Figure 7A.4-3b. Keylock shall be administratively controlled and switches are not used on the shall not be precluded by the event RSS panel. Administrative necessitating evacuation of the control controls are the responsibility room. of the applicant (See Response . 421.50e). l
FWM NW ICSB POSITION (continuri) GESSAR II RSS DESIGN (continued) o The design should comply with the requirements o GESSAR II control room design of Appendix R to 10CFR50. includes necessary separation and fire protection. However, the RSS is not considered a scfety system and fire damage
's not within the existing RSS design base. Barriers inside the RSS panel will prevent the propagation of fire from one division to another. It is the applicant's responsibility to locate panel and provide fire protection.
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F iNA L PR/lF T~ 421.50 a QUESTION ( Provide the following additional information in your discussion using drawings as appropriate:
- a. Desigr. Criteria for the remete control station equipment including the transfer switches and separation requirements for redundant functicns.
421.50 a RESPONSE The Remote Shutdown System (RSS) provides remote manual control of normal and nuclear safety-related systems necessary for prompt shutdown and subse outside the control room.quent cooldown of the reactor from The remote shutdown capability in itself does not perform any safety related function. Those RSS components that interface with safety related systems maintain the integrity and channel separation of those systems. (also see part d) ( l l (
p(NAL OR A F I~ 421.50b QUESTION ( Discuss the separation arrangement between safety-related and non-safety-related instrumentation and controls on the auxiliary shutdown panel. 421.50b RESPONSE Inside the remote shutdown panel physical barriers between redundant divisions, and between safety related and non-safety related equipments prevents the propagation of fire or effects of electrical faults from one division to another. ( (
FINA L DRA F T 421.50 c QUESTION ( Discuss the location of the transfer switches and the remote control stations. 421.50 c RESPONSE The transfer switches are located at the Remote Shutdown panel. The RS panel shall be located by thee"et ., ,;d;' j$phcant* 4so that access to and function of the panel will not be affected by the event causing the control room evacuation. It is suggested that the panel be located near a local RHR system control board where convenient communication can be maintained with the RHR switch gear and where failure of any other equipment will not damage the equipment on the remote shutdown panel. The panel shall be located in a controlled environment similar to that of the control room.
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F f MA L DRAF T 421.50 d QUESTION (' Provide a description of your isolation, separation and transfer override provisions. This should include the provisions for preventing electrical interaction between the control room and the remote shutdown equipment. 421.50 d RESPONSE The functions needed for the remote shutdown control are provided with manual transfer switches located at the remote shutdown panel, which defeat the controls from the control room and transfer the controls to the remote shutdown control. Remote shutdown is not possible without actuation of the transfer switches. 1 ( _ _ . , _ _ . - . - P - ' " - - ' ' ' "
Pr 421.50 e QUESTION 2 (~' Provide a description of the administrative and procedural control features to restrict and to assure access, when necessary, to the displays and controls located outside the control room. 421.50 e RESPONSE ' It is the ett'f t; plicant's responsibility to describe administrative and procedural control on access to remote shutdown panel. (
F (MA L PRA F T 421.50 f QUESTION i ('~ Provide a description of any communication systems required to co-ordinate operator actions, including redundancy and separation. 421.50 f RESPONSE It is the utility, plicant's responsibility to describe communication systems. i 1 9 6 l l l l l I l t {
F(WL DRA F V 421.50 a QUESTION ( Discuss the means for ensuring that cold shutdown can be accomplished. 421.50 g RESPONSE The RSS design includes a panel and associated controls, indicators, .t and monitors for interfacing with the RHR, RCIC, Main Steam, and Condensate and Feedwater Systems. In the event the reactor vessel is isolated, the feedwater supply is unavailable, the normal:. beat sinks (turbine and condenser are lost, and evacuation of the control room is necessary, re) mote manual control of normal rea cold shutdown sytems is taken as follows: Reactor pressure will be controlled and core decay and sensible heat will be rejected to the suppression pool by releasing steam through the safety relief valves. Reactor water inventory will be maintained by the RCIC system. The suppression pool will be cooled as required by operating the RHR system in the suppression pool cooling mode. This procedure will cool the reactor and reduce its pressure at a controlled rate. The RHR system will than be operated in the shutdown cooling mode to bring and maintain the reactor to the cold shutdown condition. ( l l l l l
FIHA L DAA FT 421.50 h QUESTION ( Provide a description of the control room annunciation of the status of remote control or override status of devices under local control. 421.50 h RESPONSE Operation of any of the transfer switches causes an annunciator alarm in the control room. ( (
F(NA L PRAfr 421.50 i OVESTION ( Discuss your proposed startup test program to demonstrate remote shutdown capability in accordance with the guidance provided in Regulatory Guide 1.68, Revision 2. 421.50 i RESPONSE The startup test program for the RSS shall be performed after the completion of the preoperational testing of the RSS, and the establishmen' of remot; shutdown operating procedures and test procedures, ano the commu*i1 cations between the control room and remote shutdown locations. The reactor shall be scrammed and the MSIV's closed from outside the control room while the 5,: actor is in a normal steady state condition. Reactor water level and pressure shall b controlled from outside the main control room. Data shall be obtained and recorded at locations outside the control oom to verify that the plant has achieved hot shutdown conditions and can be maintained at stable hot shutdown for at least 30 minutes. Manual operation of the safety relief valve (s) and the suppression pool cooling mode of the RHR system. from outside the control room (- shall be demonstrated. From outside the control room, water level shall be controlled in the normal range and reactor gressure shall be lowered at a rate not to exceed the technical specification limits. The reactor coolant temperature shall be reduced 50'F by controlling the shutdown cooling mode of the RHR and/or the Reactor Core Isolation Cooling Sy::tems from outside the control room at a rate not to exceed l technical specification limits. A test report shall document the results of all tests performed and a summary of any significant deviations from the required system performance. i s a
{~ f MA L ORA F r 421.50 3 00ESTION (' Discuss the testing to be performed during plant operation to verify the capability of maintaining the plant in a safe shutdown condition from outside the control room. 421.50 j RESPONSE It is the et"f ty,kplicant's responsibility to discuss testing performed during plant operation in accordance with their plant technical specifications. I I l ( l ,}}