ML20042C078
| ML20042C078 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 03/23/1982 |
| From: | Parker W DUKE POWER CO. |
| To: | Adensam E, Harold Denton Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 8203300161 | |
| Download: ML20042C078 (75) | |
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DIJKE POWEIh COMPANY Pownw Duit_cano
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March 23, 1982 373-4082 Mr. Ilarold R. Denton, Director N Office of Nuclear Reactor Regulation a k/
U. S. Nuclear Regulatory Commission Y c3 Washington, D. C. 20555 ff (5'-
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Docket Nos. 50-413 and 50-414 f' A'%yf<&
Dear Mr. Denton:
On February 2 and 3, 1982 representatives from Duke, Westinghouse, and the NRC/ Instrumentation and Control Systems Branch met at the Westinghouse Nuclear Center in Monroeville, Pennsylvania. The purpose of the meeting was to discuss the NSSS scope questions which were transmitted by Elinor G. Adensam's letter of December 21, 1981, January 12 and January 21, 1982. Attached are seven copics of the meeting summary which was prepared fol-lowing this meeting. Very truly yours,A ' l p .n a . < William O. Parker, Jr ROS/php Attachments cc: Mr. James P. O'Reilly, Regional Administrator Mr. Robert Guild, Esq. U. S. Nuclear Regulatory Commission Attorney-at-Law Region 11 314 Pall Mall 101 Marietta Street, Suite 3100 Columbia, S. C. 29201 Atlanta, Georgia 30303 Mr. '. K. Van Doorn Palmetto Alliance NRC Resident Inspector 2135 Devine Street Catawba Nuclear Station Columbia, S. C. 29205 I QO D J
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P e If . e' o NRC INSTRIM NTATION AND C0WTROL SYSTEMS BRANCH (ICSB) REVIEW MEETING ON CATAWBA FSAR February 2 - 3, 1982 at the Wr.stinghouse Nuclear Center, Monroeville, PA PEETING
SUMMARY
- 1. Attendees 1.ists attached.
- 2. Agenda - NSSS scope (list attached). Item identification is from the following hiRC letters:
Dec. 21, 1981 - Items 1 through 4 Jan. 21,1982 - Items 5 through 91 Jan.12,1982 - Items 92 through 97 Feb. 2,1982 handout - Items 98 through 116
- 3. Draf t summary - 22 pages
- 4. Attachments for the following listed items were passed out at the meeting and are attached here: 3, 6,17, 29, 54, 56, 68, 74, and 88.
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CATAWBA ICSB PITTSBURGH (NSSS) MEETING AGENDA ITEMS LIST OF CORRELATION OF ITEMS Catawba Byron /Braidwood Prime Item No. Item No. Responsibility 1 54 D 2 68 0 3 ? JCM 4 33 D 6 28 FWM 9 (50 WAT) JCM 10 14 JCM 12 FWM/D 13 15 FWM/D 14 13 FWM 15 30 ELC 17 27 ELC 18 29 ELC 19 D 20 D 21 D 22 JCM 23 D 24 D - 25 D 26 2 0 27 24, 25, 26 JCM 28 (20 WAT) (SNPIN Detail) FWM 29 32 JCM L
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CATAWBA ICSB PITTSBURGH (NSSS) MEETING AGENDA ITEMS (continued) Catawba Byron /Braidwood Prime Item No. Item No. Responsibility 3 30 FWM 31 8, 9, 19 0 FWM 35 f; 19 38 See 28 also 46 (Part II Duke) 0, ELC 39 8, 9, 18 FWM 40 8, 9, 18 FWM 41 8, 9, 18 FWM 46 None D/AS 48 8, 9, 18 FWM 50 21 FWM , 53 13 ELC 54 None ELC 56 None AS 58 23 ELC 59- None ELC 61 0/GH 64 40- ELC 66 66 JCM 68 (SNUPPS?) ELC 70 JCM 74 C/JCM 85 None AS 86 JCM 88 67 AS 89 None AS 91 JCM
ITEM 1 The staff requested a review of the adequacy of emergency operating procedures to be used by control room operators to obtain safe shutdown upon loss of any Class 1E or non-Class 1E bus supplying power to safety or non-safety related instruments and control s. This was addressed in a letter from R. Tedesco (NRC) to W. Parker (DPC) dated April 16,1981, a s Item 222.01. The response to question 222.01 (Volume 13 of the FSAR f ndicates that a review was made using the guidelines of IE Bulletin 79-27 and concluded that no design modifications are required. (1) Confirm that all a.c. and d.c. instrument buses that could affect the ability to achieve cold shutdown condition were reviewed and identify these buses. (2) Confirm that clear, simple, unambiguous annunciation of loss of power is provided in the control room for each bus addressed in item 1 above. Identify any exceptions. (3) Confinn that the effect of loss of power to each load on each bus identified in item 1 above, including ability to reach cold shutdown, was considered in the review.
RESPONSE
This item was resolved. J Ci-scussion centered around the issue of the impact the loss of an a.c.
' or d.c. instrument bus would have on the ability to achieve cold shut-down. In lieu of identifying these specific buses needed for cold shutdown, Duke agreed to analyze all a.c. and d.c. instrument buses.
(Re ference FSAR Fi gures 8.3.2-1 and 8.3.2-3. ) It was confirmed that the loss of any one of these buses would not preclude the ability to reach cold shutdown. Alarms identifying loss of power to these buses were discussed. ITEM 2 The staff requested the applicant to perform a review to determine what, if any, design changes or operator actions would be necessa ry to assure that high energy line break will not cause control system failures to complicate the e' vent beyond the FSAR analysi s. This issue was addressed in the letter from R. Tedesco (NRC) to W. Parker (DPC) dated April 16,1981, as Item 222.03. In the response to Question 222.03 (Volume 13 of FSAR) the applicant states that the required review is not completed and results will be documented in a later revision. This item will remain open until applicant has submitted the results and our review of those results is completed. l 1604Q:1 / { L: i
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RESPONSE
Carried over to B0P meeting. Duke will provide a discussion at the ICSB-80P meeting to cover the environmental effects of HELBs (excluding jet impingement and impacts from pipe whip). In particular, the specific control systems identified in Question 222.03 (4/16/81 letter from R. Tedesco to W. Parker) will be discussed. The remainder of the HELB analysis is scheduled for completion by 1/83. ITEM 3 The staff requested the applicant to provide information to assure that the design basis event analyses (Chapter 15 of FSAR) adequately bound other more fundamental credible failures. This issue was addressed in the letter from R. Tedesco (NRC) to W. Parker (DPC) dated April 16, 1981, as Item 222.04 (Volume 13 of FSAR). The applicant states than an analysis will be provided in the future. This item will remain open until the applicant has submitted the required information and our review of the information is completed.
RESPONSE
Confirmatory open item - formal submittal required. Duke Power provided a typed draf t of a response to previous ICSB Question 222.1.4 (now 420 series) for NRC review. ITEM 4 , Volune 13, page 220-7, Response to IEB 80-06. Provide a schedule for conducting the best to demonstrate that all equipment remains in its emergency mode upon removal of the actuating signal and/or manual resetting of the various isolating or actuation signals.
RESPONSE
Item resolved. Verification will be perfonned as part of ESFAS test (abstract FSAR Table 14.2.12-1, Page 31) . Test to be done prior to hot functional. ITEM 6 Indicate whether Catawba has the Westinghouse " General Warning Alarm System". If so, provide a list of conditions resulting in a general warning alarm and update the FSAR to include the input to the RTS from the general warning. 1604Q:1 ((_
RESPONSE
Confirmatory open ites .FSAR amendment to be submitted. Duke Power and Westinghouse agreed to an FSAR amendment to include a list of General Warning Alarm Reactor Trip conditions as was done on SNUPPS, Watts Bar, and Byron /Braidwood. The technical aspect of this ites, if any, was resolved by reference to previous reviews. The NRC advised they will carry this item as an open confimtory item until a draf t of Chapter 7.0 changes are received. A draf t FSAR amendment was Provided to Duke at the meeting. ITEM 9 For the RTS ar.d ESFAS, revise the FSAR Sections 7.2.2.1 and 7.3.2.1 to include the basis, assumptions, and results of the referenced FMEA. RESPONSE : Confirmatory open item - FSAR amendment required. The staff was referred to the Revision 1, February 1980 version of WCAP-8584 and the comitment that this Revision 1 will be referenced by amendment in the FSAR. 4 ITEM 10 Confirm that the FMEA, referenced in Section 7.3.2.1, for ESFAS includes (1) all BOP scope and (2) design changes subsequent to the design analyzed in the WCAP.
RESPONSE
Confirmatory open item - FSAR amendment required. p Duke provided verbal confimation that WCAPl interface criteria and assumptions have been met. Formal FMEAs for BOP systems have not been completed, but presented that single failure analysis on certain systems have been performed. On other systems, e.g., diesels, any single failure is assumed to fail one train and the other trair. eemains operable. ITEM 12 Identify all plant safety-related systems, or portions thereof, for which the design is incomplete.
RESPONSE
Resolved The changes required to Chapter 7.0 as a result of interlocking reactor ! trip on turbine trip with P-9 were comitted by Duke Power and Westing-l house as part of item 54. l l 1604Q:1 h e -
1 ITEM 13 Identify where microprocessors, telemetry systems, multiplexers, or computer systems are used in or interface with safety-related systems.
RESPONSE
Item resolved. This item was resolved for NSSS by reference to previous reviews on SNUPPS, Watts Bar, and Byron /Braidwood. In addition to the microprocessor / multiplier systems supplied by Westinghouse, Duke has supplied two systems of this type. These systems are described below: (1) ESF Bypass (Reg. Guide 1.47) Panel This system incorporates a Struthers-Dam VIP 512 Programmable Controller. (2) P1 ant Operator Aid Computer (0AC) This system incorporates a GE 4020 computer and peripherals. Both of the above systems are non-safety grade and receive input from safety-grade systems through qualified isolation devices. ITEM 14 Identify any sensors or circuits used to provide input signals to the protection system or perform a function required for safety which are located or routed through non-seismically qualified structures. This should include sensors or cirtuits providing input for reactor trip, emergency safeguards equipment such a: auxiliary feedwater system and safety-grade interlocks. Verificat'on should be provided that the sensors and circuits meet IEEE-279 and are seismically and environmen-tally qualified. Identify any testing or analyses perfonned which insure that failures of non-seismic structures, mountings, etc. will not cause failures which could interfere with the operation of any other portion of the protection system.
RESPONSE
Further discussion deferred to B0P meeting. Duke Power agreed to provide a brief discussion at the BOP meeting. Westinghouse input will support the Duke commitment. ITEM 15 Describe how the effects of high temperatures in reference legs of steam generator water level measuring instruments subsequent to high energy breaks are evaluated. Identify and describe any modifications planned 1604Q:1 e
or taken in response to IEB 79-21. Describe the level measurement errors due to environmental temperature effects on level instruments (excluding steam generator level) including reference legs.
RESPONSE
Deferred to B0P meeting. _
/
ITEM 17 Identify the lead-lag constants used in the RPS and ESFs.
RESPONSE
Confirmatory open item. A listing of lead and lag time constants was furnished to the NRC. Westinghouse will furnish for final Technical Specification. Reference will be added in FSAR section 7.2 to the Technical Specifications. ITEM 18 Provide and describe the following information for NSSS and B0P safety related setpoints: (a) Provide a reference for the methodology used. Discuss any differences between the referenced methodology and the methodology used for Catawba. (b) Verify that environmental error allowances are based on the highest value determined in qualification testing. (c) Identify protection channel where the Technical Speciff-cation setpoint, with allowance for channel statistical error, falls within 5 percent of the instrument range limit or within 5 percent of the range between level measurement taps. For those cases, specify the remaining margin to the end of the range. (d) Document the environ-mental error allowance that is used for each reactor trip and engineered safeguards setpoint. (e) Identify any time limits on environmental qualification of instruments used for trip, post-accident monitoring or engineered safety fe.J aes actuation. Where instruments are qualified for only a limited tine, specify the time and basis for the limited time. (f) Address the effect of test equipment accuracy on setpoint errors. (g) As an example, derive the setpoints for the low-low steam generator level trip.
RESPONSE
Confinnatory open item. r Westinghouse to perform a setpoint study similar to that performed for D. C. Cook for submittal to Duke Power prior to completion of the Technical Specification input. This study will be available for NRC audit. FSAR page '.2-26, item 15, will be revised appropriately. B0P f tems will be covered at the BOP meeting. 1604Q:1 ' t
7 q ITEM 19
^
The information provided in Section 2.2.1 (including Table 2.2-1) and Tables 3.3-1, 3.3-2, and 4.3-1 of the Tech. Specs. include a trip for Steam /Feedwater Flow Mismatch and Low Steam Generator Water Level. This trip is not discussed in Section 7.2.1.1.2. Clarify this apparent discrepancy. ITEM 20 Table 15.0.6-1 lists the following limiting trip points assumed in the accident analysis:
- a. Power range high neutron flux, high setting -- 118 percent.
- b. Low pressurizer pressure -- 1921 psig.
- c. Low-low steam generator level -- 25 percent of narrow range level span.
The trip setpoints shown in Table 2.2-1 of the Tech. Specs for items b. and c. above are >1865 psig (allowable values >1855 psig) and >10 per-cent (allowable vilue >9 percent) respectivelyT These values are con-siderably lower (less conservative) than those used for the accident analysis, rather than being more conservative to account for instrument errors. Also, replacing the 109 percent value used in Table 15.0.7-1 with the allowable value of 110 percent of Table 2.2-1, would result in a change in maximum overpower trip setting from 118 percent to 119 percent. Discuss how the results of the accident analysis would be affected if the allowable trip settings given in the Tech. Specs. would be used in lieu of the values shown in Table 15.0.6-1. Revise the allowable trip settings, if needed, to prevent the safe operating limits from being exceeded. ITEM 23 Tables 3.3-3, and 3.3-4, and 4.3-2 of the Tech. Specs. irclude the following parameters for ESFAS: 0 Differential Pressure Between Steam Lines 0 Steam Flow in Two Steam Lines -- High, Coincident with T avg
-- Low or Steam Line Pressure -- Low These parameters are not discussed in Section 7.3. Clarify this apparent discrepancy.
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ITEM 24 Tables 3.3-3 and 3.3-4, Engineered Safety Feature Actuation System Instrumentation of Technical Specifications do not include the loss of both Main Feedwater Pumps as a parameter to start the auxiliary feed-water pumps. We find, however, the less of both Main Feedwater pumps listed as a parameter to start the motor driven pumps in the description of the Auxiliary Feedwater System in Section 10.4.9, and also in Section 7.3.2.3. Clarify the apparent discrepancy. ITEM 25 Tables 3.3-9 and 4.3-6 in the Tech. Specs. specify the following readouts on the Auxiliary Shutdown Panel: 0 Reactor Coolant Temperature - W/R hot leg 0 Reactor Coolant Flow Rate Tables 7.4.7-1 through 7.4.7-2 do not show monitors for the reactor coolant flow rate and show monitors for the reactor coolant temperature W/R to cold leg vice hot leg. Clarify the app'arent discrepancies. RESPONSE: (Items 19, 20, 23, 24, 25) Confirmatory open items. These questions were based on a review of the Technical Specifications currently in the Catawba FSAR. These Tech. Specs are not up-to-date with other FSAR information. Duke proposed to delete the Tech. Specs. currently in the FSAR and committed to provide proposed Technical Specifications in accordance with NUREG-0452. ITEM 21 The trip setpoints specified in Section 7.2.1.1.2 for item 4b, Reactor Coolant Pump Undervoltage, is 70 per(ent of rated voltage and for item 4c, Reactor Coolant Pump Underfrequency, is 56 Hz. No values have been provided for these setpoints in Table 2.2-1 of the Tech. Specs. Specify the trip setpoints and the allowable values for the above parameters in Table 2.2-1. Describe also the equipment used for the
- monitoring, and discuss how the periodic tests on these monitors are perfonned.
RESPONSE
This item will be further discussed at the B0P meeting as a " walk th rough" . The RCP undervoltage and underfrequency monitoring equipment was dis-cussed. Design provisions for testing were outlined. This system will undergo a drawing review at the 80P meeting with emphasis on testability. 1604Q:1 7
ITEM 22 Page 7.3-7, provide a discussion of accuracy, or a reference to supple-ment the " typical" accuracy information given. Relate the accuracy requirements of the plant, such as for the safety analysis, to demon-strated equipment accuracy.
RESPONSE
Resolved by reference to Item 18. This item was resolution discussed, by the withofthe conclusions thestaff beingmethodology setpoint referred to its comp)lete (Item 18 . ITEM 26 In the Safety Evaluation Report (and supplements) issued for the Catawba construction permit, the following items required resolution during the operating licensee review: (1) Include activation of the RHR and safety injection pumps as an integral part of the ECCS periodic tests. (2) Include in the design the capability to test the reactor trip from a safety injection signal without being restricted or limited by power operation of the reactor. Discuss the status of the above items.
RESPONSE
Resolved. Part I to be done. Part 2 included in Protection System Design. ITEM 27 Identify where instrument sensors or transmitters supplying infonnation io both a protection channel and control channel or to uure than one cor. trol channel are located in a common instrument line or connected to a common instrument tap. The intent of this item is to verify that a single failure in a common instrument line or tap can neither defeat required separation between control and protection nor cause multiple l control system actions not bounded by analyses contained in Chapter 15 l of the FSAR. For control systens, the discussion can be limited to channels used for control of reactivity, reactor coolant pressure, reactor coolant temperature, reactor coolant flow, reactor coolant inventory, secondary system pressure, steam generator feedwater flow and steam generator steam flow. 1 l 1604Q:1 jf
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RESPONSE
Resol ved. The Staff was referred to the conclusion of the previous ICSB reviews on Byron /Braidwood and SNUPPS covering the same quer, tion or shared protec- i tion process taps, because the Catawba process connections on protection ! are the same as for those other plants. For the shared control system i process sensors, the staff was referred to the sensor table on the control system failure analysis submitted in draft form by Item 3. ITEM 28 and 38 Describe the scram response time testing. Describe compliance with R. G.1.118 and IEEE Std. 338-1975. Confirm
, that Tech. Specs. provide detailed instructions which insure that i
blocking of a selected protection function actuator circuit is returned to normal operation af ter testing. Confirm that Tech. Specs. include RTS and ESFAS response times for reactor trip functions. Confinn that tests include all components, from sensor to operation of final actua-tion device, and describe a typical response time test. Indicate any area of non-compliance with basis for each.
RESPONSE
Resolved for NSSS scope - additional information to be provided at B0P i meeting. Response time testing. The Westinghouse portion of this issue was resolve ' during the discussions with reference to previous ICSB
; reviews. Duke will provide addit.fonal information or sensor testing ! during B0P meetings.
ITEM 29 Portion of paragraph 7.3.1.2.6, subparagraph 1, appear not to apply to ESFAS response times. In particular, the discussion on reactor trip breakers, latching mechanisms, etc. should be replaced by a discussion of ESF pump and valve time responses. The applicant should provide a revised discussion for ESFAS (a) defining specific beginning and end points for which the quoted times apply and (b) relating these times to the total delay for all equipment and to the accident analysis requirements. j _RCSPONSE :, Confirmatory open item .- FSAR Section 7.3 and Tech. Specs. to be provided. l The staff was referred to the draft hand-out of an amended discussion i and clarification of ESF response times, which will be included in a forthcoming amendment. 1604Q:1
ITEM 30 The information provided in Section 7.2.2.2.3 on testing of the power range channels of the Nuclear Instrumentation System covers only the testing of the high neutron flux trips. Testing of the high neutron flux rate trips is not included. 1 Provide a description of how the flux rate circuitry is tested l periodically to verify its performance capability. RESPONSE : Confirmatory open item - NSSS revision to FSAR required, further discussion at B0P meeting. 1 Duke will describe its testing of the nuclear flux rate trips at the B0P meetings. Westinghouse agreed to revise the FSAR text to confirm the tert capabilities of the NIS flux rate trips. ITEM 31 In the discussion of the auxiliary shutdown control in Section 7.4.7.2 f t is stated that "The safety evaluation of achieving and maintaining hot shutdown with the controls available at the auxiliary shutdown panels includes consideration of transients whose consequences might jeopardize the safe shutdnwn conditions". Provide a detailed discussion on the type and severity of transients considered, and describe the effect these transients have on the auxiliary shutdown control.
RESPONSE
Confirmatory open item - FSAR amendment required to insert following into FSAR Section 7.4.7.2:
"The controls available on the ASPS give the capabilities of achieving and maintaining hot shutdown when the control room is inaccessible. The controls provide a means of sustaining the capabilities for boration, supplying steam aenerator feedwater and RHR and of continuing reactor coolant pump seal injection and/or thermal barrier cooling water flow."
This question was resolved by providing NRC with a copy of a proposed rewording of Section 7.4.2.2. ITEM 35 As discussed in Section 7.2.2.3, isolated output signals from protection system channels are utilized to generate a control signal to automatic control systems, such as rod drive system, pressurizer pressure and level control, and others. The control signal is derived by auction-eering the redundant protection system channels to select the high or low signal, whichever is chosen based on consideration of safety in case of a failure. 1604Q:1
Discuss what steps, if any, are taker to prevent unnecessary control actions, such as opening of pressurizer relief valves, during the testing of protection system channels with a signal from a test source.
- RESPONSE
Resolved. The questions on auctioneering and testing were resolved during the discussions by reference to previous presentations on SNUPPS and Watts Bar. No further action is required by Westinghouse or Duke Power. ITEM 39 Page 7.1-8 The statement is made, "The Westinghouse design of protec-tion systems incorporates overcurrent devices to prevent malfunctions in one circuit from causing unacceptable influences on the functioning of the protection system". Provide infonnation on the specific places where this is done and the basis that this design does not compromise protection channel independence. Discuss conformance with R.G.1.75 and IEEE 384-1974. ITEM 40 Describe the design criteria and tests performed on the isolation devices in the NSSS and B0P. Address results of analysis or tests performed to demonstrate proper isolation between separation groups. RESPONSE : (Items 39, 40, 41 and 48 for NSSS) Resolved for NSSS. The Westinghouse responsibility for NSSS protection systems was addressed and resolved. The justification for the B0P design and the Duke intention in the area of electrical independence was deferred to the 80P meeting. Duke committed to specifically address its confonnance to interface requirements identified in WCAP-8892 A. This action item was agreed to by Phil Marasco for Westinghouse. ITEM 41 The discussion in Section 7.1.2.2 states that Westinghouse tests on the Series 7300 PCS system covered in WCAP-8892 are considered applicable to Catawba. As' a result of these tests, Westinghouse has stated that the isolator output cables will be allowed to be routed with cables carrying voltages not exceeding 580 volts a.c. or 250 volts d.c. The discussion of isolation devices in Section 7.5.3.3.9 of the FSAR, however, con-sidered the maximum credible fault accidents of 118 volts a.c. or 140 volts d.c. only. Also, the statement in Section 7.7.2.1 implies that the isolation devices were tested with 118 volts a.c. and 140 volts d.c. only. Ir: order to clarify the apparent nonuniformity, provide the
- following:
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(a) Specify the type of isolation devices used for Catawba Process Instrumentation System. If they are not the same as the Series 7300 PCS tested by Westinghouse, specify the fault voltages for which they are rated and provide the supporting test data. (b) Provide information requested in (a) above for the isolation devices of the Nuclear Instrumentation System. As implied in WCAP-8892, the tests on Series 7300 PCS did not include the Nuclear Instrumentation System. (c) Describe what steps are taken to insure that the maximum credible fault voltages which could be postulated in Catawba, as a result cf B0P cable routing design, will not exceed those for which the isolation devices are qualifted. ITEM 48 . Describe how separation criteria for protection channel circuits, pro-tection logic circuits, and non-safety related circuits complies with R.G. 1.75. Indioate the separation method between these circuits. Discuss a typical example for each type circuit including an intra-panel wiring circuit. RESPONSE: (Items 41 and 48 for BOP) Further discussion deferred to B0P meeting. The NRC requested to review the Duke separation criteria at the BOP meeting. This is presented in FSAR Section 8.3.1.4. The No.C will review this section and any resulting questions will be addressed at the B0P meeting. ITEM 46 Page 7.1-16. Provide a schedule for developing IEEE-338 reliability goals and demonstrating the adequacy of test frequencies.
RESPONSE
Deferred to B0P meeting. ITEM 50 Discuss the diverse features of the undervoltage and shunt trips of the reactor trip breakers. Indicate if they can be tested independently.
RESPONSE
NRC and Westinghouse agreed to disagree. Duke will decide whether or not to commit to independent testing of the shunt coil circuits of the reactor trip breakers. Westinghouse did not change its position against these tests. Duke was in agreement with the Westinghouse position. The NRC made the decision to hold to its requirements for tests to be included in the Tech. Specs. 1604Q:1 AL
l l \ l i ITEM 53 1 Page 7.2-29 The fourth paragraph implies that a turbine trip may open the pressurizer code safety valves. Please discuss.
RESPONSE
Resol ved. Reference was made to turbine trip accident analysis (in Chapter 15) assumption, which is that the reactor remains at power. The Chapter 7 descriptions reflect this. ITEM 54 Provide analysis indicating whether the pressurizer PORY will be actu-ated following a turbine trip below the power setpoint of P-9. The analysis should cover core physics parameters bracketing those expected throughout the core lifetime.
RESPONSE
Confirmatory open item. The Westinghouse setpoint study will include results of an analysis performed with the P-9 definition as that setting at which the safety valves do not lif t. Logic change will be reflected in an FSAR amendment. ITEM 56 Section 7.7.1.7 and Figure 7.7.1-6 conflict concerning the basis for programming steam generator water level. Also there is no input label for the filter in Figure 7.7.1-6. Correct FSAR as appropriate.
RESPONSE
Confirmatory open item - FSAR amendment required. Section 7.7.1.7 (Page 7.7-11 of the SAR) states that the programmed water level is a function of neutron flux. Figure 7.7.1-6 shows the programmed water level to be a function of turbine impulse stage pres-sure. The figure is incorrect. The programmed water level is a functon of neutron flux as is stated in Section 7.7.1.7 and shown on Sheet 13 of Figure 7.2.1-1 (the functiona.1 diagrams). Aiso, the input labeled the filter on Figure 7.7.1-6 should read " Steam Generator Water Level Si gnal" . The two corrections should be made in a future amendment to the SAR. 1604Q:1 j f?>
ITEM 58 Provide an analysis indicating the time between reaching each high steam generator level alann setpoint and filling the steam generator with water assuming failure of the level channel used for control in the low directio n. Since only two out of three logic is used for high steam generator level, the remaining two channels do not meet the single failure criteria. Assume that the isolation function does not occur. The initial plant power level resulting in the most rapid steam gener-ator filling should be assumed. The applicant should be prepared to discuss the probable consequences of filling the steam generator and causing water to flow into the steam piping and the consequences of a steam generator level control channel failure.
RESPONSE
Open. Duke Power is reviewing vendor proposed hardware modification. ITEM 59 llsing detailed schematics describe the protection for locked rotor or sheared shaf t of the reactor coolant punps.
RESPONSE
Re solved. Reference to functional logic provided the satisfactory explana tion. ITEM 61 The discussion of the philosophy of protection for the reactor coolant pumps which is presented in FSAR Section 7.3.2.3 is inadequate. There fore: (a) Identify any situations in which a control room alann will not be actuated upon loss of component cooling flow to the reactor coolant pumps. (b) Quantify the time delay between a loss of component cooling to the mactor coolant pumps and the initiation of an alarm. (c) Describe how the operator corrects for a loss of component cooling water flow to the reactor coolant pumps during a seismic event or at any other time flow is lost. (d) Quantify the time it will take an operator (after an alarm is l mceived) to attempt to take the cormctive action which is identified in msponse to part (e) above and the time which is required to evaluate the results of this attempt. l (e) Describe the consequences of a failure to take effective corrective ' action (including reactor trip) within 10 minutes. 1604Q: 1
/f .l
e , RESPONSE : Open. Results of NRC auxiliary systems branch review of Question 410.17 is pending. ITEM 64 In the event of a boron dilution transient, describe the operation of the detection system and the interface arrangment with the protection system for valve actuation. Indicate if the neutron detector is quali-fled both environmentally and seismically. Confirm quality of detectors is Category I.
RESPONSE
Open. Resolution of reactor system break Questions 440.88 and 440.92 is pendi ng. ITEM 66 Using detailed schematics, verify that no single failue will preclude reactor coolant system letdown capability.
RESPONSE
Resol ved. In addition to nomal letdown means through the CVCS system (letdown or excess letdown) a diverse means of obtaining letdown exists through the safety related RV head vent system. Credit can be taken for this path in event of failure of nomal letdown path. ITEM 68 Confirm that Tech. Specs. will include surveillance requirements for the RTD bypass loop flow alarms. RESPONSE : Open. McGuire startup procedure will be provided at the 80P meeting to demonstrate the set-up method to be used at Catawba. A copy of a Jan. 6, '82 letter from Bechtel to SNUPPS was handed out. ITEM 70 Table 1.3.1-1 states that there are no significant differences between the ESFAS for Catawba and those of McGuire and Watts Bar. Our review shows that several paraneters associated with the safety injection and/or containment and steam line isolation for McGuire and Watts Bar are not provided for Ca tawba. These parameters are: 1604Q:1 L
/f
(1) High Di fferential Pressure Between Steam Lines (2) High Steam Flow (3) Pressurizer Water Level (Watts Bar only) Although the above parameters are not included in Table 7.3.1-1 and are not discussed in 7.3.1.2.6, credit appears to be taken for monitoring pressurizer water level in 7.3.2.4.1. Clarify the apparent discrepan-cies and amend Table 1.3.1-1 as necessary.
RESPONSE
Confinnatory open item. FSAR pg. 7.3-20 will be revi:ed to eliminate credit for low pressurizer level to close this item. ITEM 74 Describe automatic and manual design featum pennitting switchover from injection to mcin:ulation mode for emergency core cooling including protection logic, component bypasses and overrides, parameters monitored and controlled, and test capabilities. Discuss design features which insure that a single failure will neither cause premature switchover nor prevent switchover when required. Discuss the mset of Safety Injection actuation prior to automatic switchover from injection to recirculation and the potential for defeat of the automatic switchover functic'i. Confirm whether the low-low level refueling water storage tank alanns which detennine the time at which the containment spray is switched to recirculation mode are safety grade.
RESPONSE
Confirmatory open item. Westinghouse to submit revised logics to Duke Power prior to 80P meeting for an FSAR amendment. ITEM 85 Table 7.5.1-1 shows that the Post-Accident Monitoring System includes two Wide-Range Thot channels, and two Tcold channels. It is stated that "The T channels." hot channels are on separate power supply from the T c o' d From this statement we conclude that both Thot channe's are on one power supply, and both Tcold channels are also on one power supply . This would imply that a loss of a power supply would result in a loss of data from either both Thot or Tcold channels whichever is appl icable. Discuss what consideration was given to the loss of Thot or Tcold data.
RESPONSE
Deferred to B0P meeting. Determination of AT at hot shutdown panel to be discussed. 1604Q:1
e p ITEM 86 Using detailed schematics, describe the operation of the UHI system. From the description of upper head injection (UHI) interlocks in Section 7.6.3, it appears that the requirements of Branch Technical Position ICSB 4 in providing automatic opening of the valves whenever either primary coolant system pressure exceeds the preselected value, or a safety injection signal is present, are not followed. If so, justify the approach taken. Also confirm that the a.c. control power supply used for the valve position indicating lights is independent of the power supply used for the annunciators that alarm if the valve is not fully closed above a set pressure, as required by ICSB 4. RESPONSE : Part II deferred to B0P meeting. Part I resolved. Detailed review of schematics was deferred to the 80P meeting to deter-mine the means for system level manual actuation of the safety function for isolating the UHI from the head. Sequoyah was required to add manual switches to duplicate the function of the level switches. ITEM 88 Describe the design features used in the rod control system which (1) Limit reactivity insertion rates resulting from single failures within the system. (2) Limit incorrect sequencing or positioning of control rods. The discussion should cover the assumptions for detenntning the maximum control rod withdrawal speed used in the analyses of reactivity inser-tion transients. RESPONSE : Confirmatory open item - FSAR amendment required. Proposed FSAR amendment of Section 7.7.1.2.2 was passed out for NRC review. This item relates to rod control system features which limit reactivity insertions, maximum rod speeds and incorrect sequencing resulting from single failures within the system. The staff was referred to the generic presentation made at the SNUPPS review, and l referred to at other reviews. The Catawba rod control system is the same as the generic system previously reviewed. The generic evaluation of the rod control system should be added to the Catawba FSAR by future amendment.
- _ ITEM 89 List the basis, assumptions and results from the FMEA (WCAP-8976) for the rod control systems.
1604Q:1
/7
RESPONSE - Resolved. NRC to pursue WCAP-8976 review generically. ITEM 91 Using detailed schematics describe the design of boric acid addition control and the volume control tank level control . Discuss the recent Westinghouse generic deficiency regarding volume control tank level and its applicability to Catawba. RESPONSE : Confirmatory item for Duke Power - procedures should incorporate this. Reactor systems branch Question 440.40 considers this subject. Duke Power is reviewing a Westinghouse letter on this subject for incor-poration into operating procedures. Catawba has the same logic as the generic case reported in a potential deficiency and the Catawba plant specific evaluation indicated that, as in the generic case, there is adequate time for corrective action by the operator. ITEM 98 Table 7.2.2-1 is not correctly correlated to Chapter 15. RESPONSp Confirmatory open item. Westinghouse to correct as necessary. ITEM 99 Table 15.0.8-1 (page 1) - High steam generator level causes turbine trip which causes reactor trip. Section 7.2 only lists turbine trip and not high steam generator level trip.
RESPONSE
Confirmatory open item. Westinghouse to revise table. ITEM 100 Second paragraph on page 7.3-12 is not clear. Since SI does not cause steam line isolation, not all functions listed in 7.3.1.1.1 are ini-tiated by SI. Therefore, how many functions in 7.3.1.1.1 are initiated by SI, RESPONSE : Resolved. Main steam line isolation and containment spray are not actuated by the S signal. Reference was made to Figure 7.2-1 Sheet 8 and other FSAR sections to address that ESFAS does not always actuate SI. Containment air return fans and H2 recombiners were cited as not included in FSAR. 1604Q:1
ITEM 101 Table 15.0.8-1 (page 5) - Is SI initiated by a low pressurizer pressure for inadvertent opening of the pressurizer relief valve ? PESPONSE: Resolved. Answer was yes. ITEM 102 Page 7.1-11 refers to 10.2.2 for testing of reactor trip on turbine trip. Section 10.2.2 does not discuss testing of reactor trip circuit. Also discussion implies that the EH and stop valves are tested at power. Discuss testing of turbine trip of reactor during operation and include in FSAR.
RESPONSE
Deferred to B0P rtoting. Question was restated, i. e, some functions cannot be tested at power, e.g., turbine trip. ITEM 103 Page 7.1-11 states that manual switches cannot be tested at power because this would cause reactor trip. Please discuss. RESPONSE : Deferred to B0P meeting. Duke Power and Westinghouse to review prior to BOP meeting. Manual trip actuation on either train will cause a trip in any case and cannot be tested at power. ITEM 104 Third and fourth paragraphs on page 7.2-24 are unclear. Please explain.
RESPONSE
Resolved. I ! FSAR description was explained. Circuit continuity tested with pulses from semiautomatic relay tester. I 1604Q:1
ITEM 105 Figure 7.2.1-1 (Sheet 8) shows more variables (containment, pressure, etc. ) than listed under Section 7.3.1.2.2. If this section only covers SI, a new section should be developed for ESFAS. Also these variables should be included in 7.3.1.2.6 (See Item 23.)
RESPONSE
Resolved. A philosophical discussion about the definition of ESFAS occurred, and whether or not Section 7.3 covered all of ESFAS. ITEM 106 Tables 7.3.1-1 and 7.3.1-2 seem to have incorrect logic (e.g., SI manual is 1/1 for each train while pressurizer low pressure is 2/4 per train). RESPONSE : Further discussion at 80P me'eting. Duke Power apprised the NRC of their methodology for system level manual safety initiation. ITEM 107 Table 6.2.4-1 shows that containment spray lines are isolated by Phase B containment isolation. Page 7.3-3 discussion (above 7.3.1.1.2) disagrees. Please clarify. RESPONSE 1 Resolved. NRC was advised that the P signal opens containment spray lines. ITEM 108 On SI do the CCP miniflow valves close? See page 6.3-3.
RESPONSE
Deferred to B0P meeting. ITEM 109 Recent review of Waterford revealed heaters were used to control tem-perature and humidity within insulated cabinet housing electrical trans-mitters that provide input signals to the RPS. These heaters were l 1604Q:1
unqualified and concern was raised that heater failure could cause transmitter degradation. Please address. If heaters are used, describe design criteria.
RESPONSE
Deferred to B0P meeting. ITEM 110 Figure 2.2.1-1 (8 of 16) shows Deck Recirc. Fans. Does Catawba have these or should this be the Contain. Air Return and Hydrogen Skimmer. Also Interlock by Cont. High Pressure. Isn't this the low (0.25 psig) interlock? Also annulus ventilation shown activated by SIS. Section 7.6/5.1 says initiated by containment hi-hi pressure. Conflict?
RESPONSE
Further discussion at B0P meeting. May require FSAR revision (s). Terminology of " Deck Fans" versus Air Recirc. Fans to be corrected. ITEM 111 7.6.11.3.1 states hydrogen recombiner automatically initiated by signal from ESFAS yet other sections say local manual control. ITEM 112 7.6.11.3.19 states hydrogen recombiner has read-outs in control room. Other sections say no. Hydrogen sample is used to verify proper operation.
RESPONSE
Will be further discussed at the B0P meeting. FSAR to be amended to delete automatic start of electric hydrogen recombiners. ITEM 113 Page 7.4-7 under 7.4.2.1 the statement is made that "in the event control must be transferred the the Auxiliary Shutdown Complex, all automatic signals are defeated". Please explain. ITEM 115 Page 10.3-2 Discuss main steam isolation valves with solenoids, trains, etc.
RESPONSE
Deferred to B0P meeting. 1604Q:1 A/
- )
r ITEM 114 Table 7.3.1-3 (page 2) the discussion on P-11 does not seem to parallel that on page 1.
RESPONSE
Resolved. Table 7.3.1-3 page 2 explanation of P-11 is cormct. ITEM 116 i Page 7.3-4 paragraph 7.3.1.1.4 No. 7 what ventilation is thisp
RESPONSE
Resol ved. NRC accepted the definition of ventilation function as being containment ventilation isolation. i 1 1604Q:1 M
) NAFr dmynndment to Cehbg. Ch 7 in respowse to les B Mewda i+em G #4 ws CNS Each train contains a multiplexing test switch. At the start of a'
~
process or nuclear instrumentation system test, this switch (in either train) is placed in the A + 8 position. The A + 8 position alternately allows information to be transmitted from the two trains to the control board. A steady status lamp and annunciator indicates A flashing lamp input relays in both trains have been de-energized. means that the input relays in the two trains did not both de-erergize. Contact inputs to the logic protection system such as reactor coolant pump bus underfrequency relays operate input relays which are tested by operating the remote contacts as described above and using the same type of indications as those-provided for bistable input relays. Actuation of the input relays provides the overlap between the testing of the logic protection system and the testing of these systems sup-plying the inputs to the logic protection system. Test indications are status lamps and annunciators on the control board. Inputs to the logic protection system are checked one channel at a time, leaving the other channels in service. For example, a function that trips the reactor when two out of four channels trip becomes a one out of the a trip when one channel is placed in the trip mede. Both trains of the logic protection system remain in service during this portion of the test.
- b. Check of Logic Matrices Logic matrices are checked one' train at a time. Input relays are not operated during this portion of the test. Reactor trips from the train being tested are inhibited with the use of the input error inhibit switch on the semi-automatic test panel in the train. At the comple-tion of the logic matrix tests, one bistable in each channel of pro-cess instrumentation or nuclear instrumentation is tripped to check closure of the input error inhibit switch contacts.
The logic test scheme uses pulse techniques to check the coincidence logic. All possible trip and non-trip combinations are checked. Pulses from the tester are applied to the inputs of the universal logic card at the same terminals that connect to the input relay contacts. Thus there is an overlap between the input relay check and the logic matrix check. Pulses are fed back from the reactor trip breaker undervoltage coil to the tester. The pulses are of < such short duration that the reactor trip breaker undervoltage coil armature cannot respond mechanically. Test indie.ations that are provided are an annunciator in the control room indicating that reactor trips from the train have been blocked and that the train is being tested, and green and red lamps on the semi-automatic tester to indicate a good or bad logic matrix test. Protection capability provided during this portion of the test is from the train not being tested. IN$2MT B 7.2-24
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- 11. Channel Bypass or Removal from Operation The Protection System is designed to permit periodic testing of the analog channel portion of the Reactor Trip System during reactor power operation without initiating a protective action unless a trip condition actually exists. This is because of the coincidence logic required for reactor trip.
- 12. Operating Bypasses Where operating requirements necessitate automatic or manual bypass of a protective function, the design is such that the bypass is removed auto-matically whenever permissive conditior.s are not met. Devices used to achieve automatic removal of the bypass of a protective function are con-sidered part of the protective system and are designed in accordance with the criteria of this section. Indication is provided in the control room if some part of the system has been administratively bypassed or taken out of service.
- 13. Indication of Bypasses Bypass indication is discussed in Section 7.8.
- 14. Access to Means for Bypassing The design provides for administrative control of access to the means for manually bypassing channols or protective functions.
- 15. Multiple Setpoints l !. ! l i i }. i 1. i i .1 ; i ;
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- 16. Completion of Protective Action The protection s:< stem is so designed that, once initiated, a protective action goes to cc.npletion. Return to normal operation requires action by the operator.
- 17. Manual Initiation Switches are provided on the control board for manual initiation of pro-tective action. Failure in the automatic system does not prevent the manual actuation of the protective functions. Manual actuation relies on the operation of a minimum of equipment.
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7.3.1.2.4 Limits, Margins and Levels ' Prudent operational limits, available margins, and setpoints before onset of unsafe conditions requiring protective action are discussed in Chapters 15 and 16. 7.3.1.2.5 Abnormal Events Th2 malfunctions, accidents, or other unusual events which could physically dazage protection system components or could cause environmental changes are as follows:
- 1. Loss of coolant accident (See Chapter 15)
- 2. Steam breaks (See Chapter 15)
- 3. Earthquakes (See Chapters 2 and 3)
- 4. Fire (Section 9.5.1) '
- 5. Explosion (Hydrogen buildup inside containment) (See Section 15.4)
- 6. Missiles (See Section 3'.5)
- 7. Flood (See Chapters 2 and 3) 7.3.1.2.6 Minimum Performance Requirements Minimum performance requirements are as follows:
- 1. System Response Times -
- A as the (nth i D Ieered Safety required Features for the Actuatio'n.
Engi~netrfTd SafetySystem Features response sequ ce tima to is de 'ned # be initiated s uent to the point of time that the appro *
.evariable(s))
exceed setpoints. s onse time includes sensor Ta_nalog) and f logic (digital) delay p u t.itn_e dela a ith tripping open the reactor trip breakers and contr ing mechanisms, although the Engineered Safety Feature uati s 1 occurs before or simul-taneously with Engineere fet?' Te~atures seque
- itiation (See Figure 7.2.1-1, Sheet 8). efore, the response times to iating Engineered
[ Safety Featur resented herein are conservative. The va listed here-4 in are allowable times consistent with the safety analys d 2ra >
& ma cally verified durino olant pre operational start-up testsA maximum delay times thus include all compensati~on~an~d therefore require that any such network be aligned and operating during verification testing.
The Engineered Safety Features Actuation System is always capable of having response time tests performed using the same methods as those tests performed during the preoperational test program or following significant component changes. Typical maximum allowable time delays in generating the actuation signal for loss of coolant protection are: Pressurizer pressure 2.0 seconds Typical maximum allowable time delays in generating the actuation signal for steamline break protection are: 7.3-6
, 9 _.,_
1
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, The ESFAS respnse /tme is defmed as lhe mierval reywred for +he Es/= ,se7aence - Jo be inifiahed subsequent -lo Me -hme lhal lhe oppopnale ntnable(s) exceed : fhis selpom/Cs). 7Re Esf secuence is inihaled by the ou/put of -lhe Esfns - which is by -lhe ipem-lion of fhe dry confacts of #e slave relays (60066 i allK senes ielays.) m he ou/put cabmels of 4he ahd slale pelec+ ion ,syslem . The respmse hmes hsled below mc/ade Me inlerval of +1me a>M8i uiill elapse .be -
-la>een }he hme lhe parameler as sensed by +he , sensor exceeds lhe sofely
,se/pom/ and Jhe hme lhe schd sicle prokehon sys/em sisve relay dry conh2cis are goeraJed. These values (as hsled below) are maximum ollowable i
values costsislemt win +he safe}y analyses and he Tschmea/ Spadicahans and are i sysiemahca//y verifred donn preopenhonal s/arlup lala.g For +heplant averall ESQ. response hme ', refer k toble as-s' of +he Te:hniaa/ Specbcahoas. ,
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Rcd D 7,% SM Sea I TABLE 3.3-2 3/ ./, ,y REACTOR TRIP SYSTEM INSTRUMENTATION RESPONSE TIME FUNCTIONAL UNIT RESPONSE TIME
- 1. Manual reactor trip Not appifcable
# 2. Power range, neutron flux 50.5 seconds *
- 3. Power range, neutron flux, high positive rate Not applicable
- 4. Power range, neutron flux, high necative rate 50.5 seconds"
- 5. Intermediate range, neutron flux Not applicable
- 6. Source range, neutron flux Not applicable
//.0
- 7. Overtemperature ai 5@jfr) seconds *-
- 8. Overpower AT Not applicable f2*
- 9. Pressurizer pressure--low </p;.0
. 10 seconds
'- 10. Pressurizer pressure--high 7
.5f.0 seconds
- 11. Pressurizer water level--high Not applicable
- 12. a. Loss of flow - single loop '
(Above P-8) fi.0 seconds
- b. loss of flow - two loops (AboveP-7andyelowP-8) 51.0 seconds
- 13. Steam generator water level--low-low 52.0 seconds tTam ne pressure-low Later g/g
- 15. Undervoltage-reactor coolant pumps $1.5 seconds
- 16. Underfrequency-reac*or coolent pumps 50.6 seconds
- 17. Turbine trip
- a. Low fluid oil pressure Not applicable
- b. Turbine stop valve Not applicable Safety injection input from ESF Not applicable 18.
" Neutron cetectors are exempt from response time testing. Response time of i
the neutron flux signal portion of the channel shall be measured from
- l detector output or inout of first electronic component in channel. (This l
provision is not applicaole to cps docketed after January 1, 1978. See
- Regulatory Guide 1.118, November 1977.)
! 3/4 3-9 L
hy-( TABLE 3.3-2 (Continued) l REACTOR TRIP SYSTEM INSTRUMENTATION RESPONSE TIMES
- 19. Reactor trip system interlocks Not applicable
- 20. Reactor trip breakers Not applicable
- 21. Automatic trip logic Not applicable f
P l \ - l l l t 3/4.3-10
- $$$-h TABLE 3.3-5 ENGINEERED SAFETY FEATURES RESPONSE TIMES INITIATING SIGNAL AND FUNCTION RESPONSE TIME IN SECON05
- 1. Manual
- a. Safety Injection (ECCS) Not applicable Feedwater Isolation Not applicable Reactor Trip (SI) Not applicable Containment Isolation-Phase "A" Not applicable Cor.tainment Vent and Purge Isolation Not applicable ,
Auxiliary Feedwater Pumps Not applicable Essential Service Water System Not applicable Containment Air Recirculation Fan Not applicable
- b. Containment Spray Not applicable Containment Isolation-Phsse "B" Not applicable Containment Vent"and Purge '~rr5Tation ~ 'Not applicable
- c. Containment T::lation-Phase "A" Not applicable Containment Ven; and Purge Isolation Not applicable
- d. Steam Line Isolation Not applicable
- 2. Containment Pressure-High
- a. Safety Injection (ECCS) 527.0*
- b. Reactor Trip (from SI) 52.0
- c. Feedwater Isolation 57.0
- d. Containment Isolation-Phase "A" $17.0**/27.0 i
- e. Containment Vent and Purge Isolation Not applicable
- f. Auxiliary Feedwater Pumps Not applicable
- g. Essential Service Water System 537.0**/47.0 Y 3/4 3-23
u-g TABLE 3.3-5 (Continued) ENGINEERED S4FETY FEATURES RESPONSE TIMES RESPONSE TIME IN SECONOS INITIATING SIGNAL AND FUNCTION
- 3. Pressurizer Pressure-Low
- a. Safety Infection ~(ECCS) 527.0*/12.0**
- b. Reactor Trip (from SI) 52.0
- c. Feedwater Isolation 57.0
- d. Containment Isolation-Phase "A" -$17.0**
- e. Containment Vent and Purge Isolation Not applicable
- f. Auxiliary Feedwater Pumps Not applicable
- g. Essential Service Water System 547.0*/37.0**
- 4. Containment Pressure-High-High
- a. Steam line isolation 17.0
- 5. Negative Steam Line Pressure Rate-High
- a. Steam line isolation 59.,0
- 6. Steam Line Pressure-Low
- a. Safety Injection (ECCS) 512.0**/22.0 i
- b. Reactor Trip (from SI) 12:0
- c. Feedwater Isolation 57.0
- d. Containment Isolation-Phase "A" 517.0**/27.0 i
- e. Containment Vent and Purge Isolation Not applicable
- f. Auxiliary Feedwater Pumps Not applicable .
i
- g. Essential Service Water System 537.0*/47.0
- h. Steam Line Isolation 57.0
- 7. Containment Pressure--High-High-High
- a. Containment Spray 160.0
- b. Containment Isolation-Phase "B" Not applicable 3/ 3-24 .
i
$&O TABLE 3.3-5 (Continued)
ENGINEEREO SAFETY FEATURES RESPONSE TIMES INITIATING SIGNAL AND FUNCTION RESPONSE TIME IN SECON05
- 3. Steam Generator Water Level--High-$igh
- a. Turbine Trip 52.5
- b. Feedwater Isolation $11.0
- 9. Steam Generator Water Level - Low-Low
- a. Motor-driven Auxilia,ry Feedwater Pumps!1- s 560.0
- b. Turbine-driven Auxiliary Feedwater umps ttt 560.0 .
- 10. Station Blackout Motor-driven. Auxiliary Feedwater Pumps 5( ) " "4 a.
- 11. Trip of Main Feedwater Pumps
- a. Motor-driven Auxiliary Feedwater Pumps
~
5( ) e/"I
- 12. Loss of Power
- a. 4.16-kV Emergency Bus Undervoltage 5( ) ^' f (Loss of Voltage)
- b. 4.16-kV Emergency Bus Undervoltage 5( ) vs#
(Oegraded Voltage) Note: Response time for Motordriven Auxiliary 160.0 Feedwater Pumps on all S.I. signal starts I t
~
3/4 3-25
.. #M-1 TABLE 3.3-5 (Continued)
TABLE NOTATIONS
- Diesel generator st'rting a and sequence loading delays included.
Response time limit includes opening of valves to establish SI path and attainment of discharge pressure for centrifugal charging pumps, SI (4 loop only) and RHR pumps.
** Diesel generator starting and sequence loading delay not included.
Offsite power available. Response time includes opening of valves to establish SI path and attainment of discharge pressure for centrifugal charging pumps. i Diesel generator starting and sequence loading delays included. Response time limit includes opening of valves to establish SI path and attainment of discharge pressure for centrifugal charging pumps. IT On 2/3 any steam generator Ht Or s 2/3 in Zl4 sb C*n m dees e i 3/4 3-26 l l l t
r _ At
/ REM &
CNS O*' The reactor is manually tripped in the control room prior to evacuation; however, the reactor can also be manually tripped at the reactor trip switchgear. Instrumentation and controls for hot shutdown from outside the control room are located in the Auxiliary Building on the auxiliary shutdown panels and auxiliary feedwater pump turbine control panel (refer to Figure 1.2.2-2). The instrumenta-tion and controls provided on the auxiliary shutdown panels are iisted on Tables 7.4.7-1 and 7.4.7-2. The instrumentation and controls provided on the auxiliary feedwater pump turbine control panel are listed on Table 7.4.7-3. Selector switches on the auxiliary shutdown panels allow the operator to transfer control of the equipment required for shutdown from the control room to the shut-down panels. When equipment control is transferred to auxiliary shutdown panels, all control room controls and all interlocks that originate or pass through the control room and/or cable room are defeated. The auxiliary shutdown panels are physically and electrically separated from each other and from the control room and cable room. The electrical power that supplies all of the devices controlled from these panels is available following a loss of offsite power. Transfer of control to the shutdown panels is alarmed in the control room. Plant shutdown in the event of fire or sabotage is addressed in the Fire Plan or Security Plan. 7.4.7.2 Analysis Hot shutdown is a stable condition automatically reached following a unit shut-down. The hot shutdown condition can be safely maintained for an extended period of time. In the event the control room is not accessable, a unit can be kept in hot shutdown until control room access is restored. TEF safety evaluation of achieving and maintaining hot shutdown with the controls available at the auxiliary shutdown panels includes consideration of transients whose consequences might jeopardi7a the safe shutdown conditions. Transients that can affect the shutdown cono.'. ions are those that could degrade the capabil-
/j/f ities for boration, supplying steam generator feedwater, and residual heat remova{
or could interrupt reactor coolant pump seal injection and/or thermal barrier cooling water flow for more than ten minutes. The design of the auxiliary shutdown controls precludes any of the transients mentioned'above from jeopardizing the ability to achieve and maintain hot shut-I down. l l l 7.4-21
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$lt/$d/1 $4'A' TUR8!!NE IMPULSE STAGE PRESSURE V
PRO MER MU kehrhw/ sp( w STEAM FLOW FEE 0 WATER FILTER SI GN AL FLOW SIGNAL (+ ) (.) Pi CONTROLLER Pi CONTROLLER REMOTE MANUAL
,e r P0stT10hlNG
" V POWER RANGE (+ )
NEUTROM FLUX V 7 (+) Pi CONTROLLER GAIN e( y u FEE 0 WATER MAIN FEEDWATER BYPASS vatiE CONTROL VALVE DYNAMICS DYN AMI CS ( u V FEEDWATER BYP ASS MAIN FEE 0 WATER VALVE POSITION l CONTROL yALVE POSITION l l 1 STEAM GENERATOR WATER LEVEL i CONTROL SYSTEM BLOCK DIAGRAM CATAW8A NUCt. EAR STATION Figure 7.7.1-6 l
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INFO COP:~i TO:. -. Bechtel Power Corporation I Engineers-Constructors COMPLETE ACDON M a evl3d J - 3 sf - gyg gy g,, g REMARKS: . Gaithersburg, Maryland 20760 301-258 3000 r
~
f-UAls JAN 0 6 1982 m Mr. Nicholas A. Petrick Executive Director, SNUPPS U '
,. ) Jk 3 5 Choke Cherry Road Rockville, Maryland 20850 ; Q JANO 81982 -
[. lir BLSE-/M/8 File: 0278 Bechtel Job Number 10466 SNUPPS Project RTD Bypass Loop Flowrate Encl: A. SNP-4340, dated November 18, 1981
Dear Mr. Petrick:
Forwarded for your review in Encl'osure A is the Westin;; house response to the proposed NRC technical specification requirement to verify the magnitude of the RTD bypass loop flowrate at each refueling. The Instrumentation and Control Systems Branch discussed this concern during their FSAR review meet-ings and believed that flow dearadation could" adversely affect protection systems response time. Bechtel believes E~nclosure A adequately addresses the NRC concern in regard to flow degradation in the bypass piping due to crud deposition. However, the NRC was also concerned about limiting or totally blocking RTD loop flow due to an improper valve lineup. This'second NRC concern could be resolved by describing maintenance and valve lineup verification procedures which would be within utility scope. Combining Enclosure A and a description of valve. verification procedures may be sufficient to address the NRC concern and remove this is' sue from Section 16.0 of the Callaway SER. If you have any questions, please contact us. Very tru yo s, J . mith roject Engineering Manager CRK:psb cc: R. L. Stright, w/1 A. C. Passwater, w/1
- G. P. Rathbun.- 1 -
W. L. Luce,'w/1 D. W. Caponer;w/ 3 D. F. Schnell, w/l M. L. Johnson, w/3 J. L. Miller, w/l , N. Hill, w/1
pgg 7 ) b
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Westinghouse Water Reactor
- ca w * *
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! Electric Corporation D! visions som PittsbutgnPennsylvane152E
' November 18, 1981 SNP-4340 NS-LT-9594 Mr. Joseph H. Smith W S.O. SNP-4705 Project Engineering Manager l Bechtel Power Corporation 15740 Shady Grove Road Gaithersburg, Maryland 20760
Dear Mr. Smith:
SNUPPS PROJECTS ! RTD Bypass Loop Flowrate During the NRC~ Instrumentation and. Control Systems Branch review of the SNUPPS FSAR, the NRC (Mr. C. E. Rossi) ind.icated that they will require . that the magnitude of the RTD bypass loop flowrate be' verified to be within , required limits at each refueling. In the recently issued Callaway Safety Evaluation Report (NUREG-0830), the NRC reiterated this requirement and stated that it will be incorporated in the, plant Technical Specifications. Westinghouse has performed an evaluation of the SNUPPS RTD Bypass System, directed towards assessing the potential effect of increased fouling on the l RTD Bypass System delay times. As we understand it the NRC request is based on a concern that an increase in corrosion product deposition within the s Bypass System Piping will significantly increase the delay time, with a corresponding increase in the time required for gemration of the protection grade T H and TC signals. A qualitative assessment of this situation leads to the following key points: e A significant increase in transport time would be accompanied by a large decrease in bypass piping velocity. Assuming the relationship AH = KV2 holds true, and AH (driving head) is constant, then a large velocity decrease would result only from a very large increase in K value. , , In the usual practice, fouling irside pipes and tub'es is considered to
~
e have significant effect on the heat transfer mechanism but an insignifi-cant effect on hydraulic performance. Examination of the physical para-meters that detemine the friction factor "F", i.e., Reynolds Number and Relative Roughness, easily confirm that,only a gigantic increase in - absolute roughness (epsilon) could really increase the friction factor F and consequently the K value. Thus a meaningful increase in loss ! coefficient cannot be postulated on the,tasis of fouling. 4 e
./pp pp 5
( , i , .i s . Mr.. Joseph H. Smith November 18, 19,81 . SNP-4340 NS-LT-9594 Nevertheless a quantitative evaluation was perfonned which consisted of two parts: (1) Calculation of the current RTD Bypass System delay time with no fouling (base line resistance coefficients) and (2) calculation of the effect of increased fouling (increased resistance coefficients) on the system delay times. The results of part 1 are listed below along with the Bechtel Drawings used in the evaluation. Note that all of the delay times satisfy the 1.0 sec functional requirement for maximum allowable transport delay time. This is the time allotted for fluid entering the RTD scoops to reach the last temperature detector in the manifold. Bechtel Drawing # Delay Hot leg -(Sec)Times With No Fouling Cold Leo (Sec) Loop 1 M-03BB05(Q) Rev. 2 .71 .84 Loop 2 M-03BB06(Q) Rev. 2 - 70 ,
.75 Loop 3 M-03BB14(Q) Rev. 3 .70 ,
.98 Loop 4, M-03BB15(Q) Rev 2 . 79 - .82 In part 2 of the evaluation a parametric study was performed to determine the effect of increased fouling on the delay times. Figure 1 is a plot of the increase in the hot and cold leg transport delay time as a function of the percent increase in piping loss coefficient (due to fouling). Loop 1 was used as a representative loop to generate this plot but we can expect Loops 2, 3, and 4 to behave similarly. Sumarizing thi,s part of the study, the hot leg loss coefficients would have tu increase by the amounts listed below before the 1.0 second maximum delay time wou'd be reached.
Increase in H.L. Loss Coefficient Loop Necessary for 1.0 Sec. Delay Tine 1 100% 2 103% 3 106% 4 68% In sumary, changes in loss coefficients of this magnitude are simply , not credible. If increases in RTD system resistances of this magnitude were to occur de would expect to see similar, effects in the steam generator 4 1
{ {y Mr. Joseph H. Smith November 18, 1981 SNP-4340 NS-LT-9594 tubes. Fouling has never been a significant contributor to increases in systems resistance. Thus, Westinghouse does not feel it is necessary to verify the RTD Bypass Flow Rate periodically. Another consideration is that the Westinghouse safety analyses assume 2 seconds for manifold transport time and heating. The system is designed for a 1 second transport time. It is the opinion of Westinghouse.that~ the above evaluation results and the analytical assumptions provide the justification for not performing additional surveillance. If you have any questions concerning this material, please contact this office. Very truly yours, M W. L. Luce /bek W._R..Spezialetti
$NUPPS Licensing Manager Attachment cc: N.A.Petrick(SNUPPS),2L,2A F. D. Crawford (KCPAL), IL, lA D. W. Capone (UE), IL, l A P. A. Ward (Bechtel), IL, 2A J. A. Bailey (KG&E), IL, lA Joseph H. Smith (Bechtel), lL, lA -
R. L. Stright (SNUPPS), IL, l A . e 6
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RWST LEVEL CHAriflEL 81 STABLES
^ l fl0RMALLY DE-EflERGIZED ,
2 DE-ENERGIZED Oil LOSS OF POWER . 3 TRIP SIGilAL PROVIDED WHEll EflERGIZED
- 4) EtlERGIZED ON LO-L0 SETP0lflT s
k-v, PROCESS CONTROL LB I LB LB LB (*.) l l CABINETS
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- V LMT SW#1 LMT SW!l APPLICABLE VALVE R_ALVE HR INNER 870t6 8702B '
150. VALVE LMT SW#2 DESCRIPTION 412 LMT SW#1 m. RlIR OUTER 8701A 8702A - OPEN SUMP TO #1 RHR PUMP 8811A 150. VALVE LMT SWY1 LMT SW#2 VALVE SUMP TO #2 RHR PUMP 8811B TRAIN A B Limit switch 31 is . e e . al position signal and is used for position signals between valves assig rd to . e sa 2 train. Limit switch =2 is - e s . rnounted position switch and it is used for position signals
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Addition to Chapter 7 Sectiofr7.7./J.3 for Rod Control System Features (Agenda Item 99) Credible rod control equipment malfunctions which could potentially cause inadvertent positive reactivity insertions due to inadvertent rod withdrawal, incorrect overlap or ma1 positioning of the rods are the following:
- 1. Failures in the manual rod controls:
- a. Rod Motion Control Switch (In-Hold-Out)
- b. Bank Selector Switch
- 2. Failures in the overlap and bank sequence program control:
- a. Logic Cabinet Systems
- b. Power Supply Systems ,
- 1. Failures in the Manual Rod Controls The Rod Motion Control switch is a three position lever switch. The three positions are "In", " Hold" and "Out". These positions are ef fective when the bank selector switch is in manual . Failure of the rod motion control switch (contacts failing short or activated relay failures) would have the potential, in the worst case, to produce positive reactivity insertion by rod withdrawal when the bank selector switch is in the manual position or-in a position which selects one of the banks.
When the bank selector switch is in the automatic position, the rods would obey the automatic commands and failures in the rod motion control switch would have no effect on the rod motion regardless of whether the rod motion control switch is in "In", " Hold" or "Out". l l 07nRA l
.. 28 Ac s.-
In the case where the Bank Selector switch is sslecting h bank and a
^
failure occurs in the Rod Motion switch that would command the b,ank "out" even when the Rod Motion Control switch was in an "In" or
" Hold" position the selected bank could inadvertently withdraw.
This failure is bounded in the safety analysis (Chapter 15) by the uncontrolled bank withdrawal subcritica.1 and at power transients. A reactivity insertion of up to 75 pcm/sec is assumed in the analysis due to rod movement. This value of reactivity insertion rate is consistent with the withdrawal of two banks. Failure that can cause more than one group of four mechanisms to be moved at one time within a power cabinet is not a credible event
- because the circuit arrangement for the movable and lift coils would cause the current available to the mechanisms to divide equally between coils in the two groups (in a power supply). The drive mechanism is designed such that it will not operate on half current. A second feature in this scenario would be the multiplexing failure detection circuit included in each power cabinet. This circuit would stop rod withdrawal (or insertion).
The second case considered in the potential for inadvertent reactivity insertion due to possible f ailures is when the selector switch is in the manual position. Such a case could produce with a f ailure in the rod motion control switch a scenario where the rods could inadvertently withdraw in a programmed sequence. The overlap and bank sequence are programmed when the selection is in either automatic or manual . This scenario is also bounded by the reactivity values assumed in the SAR accident analysis. In this case, the operator can trip the reactor, or the protection system would trip the reactor via Power Range Neutron Flux-High, or overtemperature aT. Failure of the Bank Selector Switch A failure of the bank selector switch produces no consequences when the "in-hold-out" manual switch is in the " Hold" position. This is I due to the following design feature: . l l l 970SA
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The bank selector switch is series wired with the in-hold-out lever switch for manual and individual control rod bank operation. With the 'in-hold-out' lever switch in the ' hold' position, the bank selector switch can be positioned without rod movement.
- 2. Failures in the Overlap and Bank Sequence Program Control The Rod Control System design prevents the movement of the groups out of sequence as well as limiting the rate of reactivity ,
insertion. The main feature that perfoms the function of preventing mal positioning produced by groups out of sequence is included in the Block Supervisory Memory Suffer and Control. This circuitry accepts' and stores the externally generated command signal s . In the event of out of sequence input command to the rods while they are in movement, this circuit will inhibit the buffer memory from accepting the command. If a change of signal command appears, this circuit would stop the system after allowing the slave cyclers to finish their current sequencing. Failure of the components related to this system will produce also Rod deviation alam and insertion limit alarm'isee FSAR Section 7.7). Failures within the system such as failures of supervisory logic cards, pulser cards, etc., will also cause an urgent alam. An urgent alam will be followed by the following actions:
- Automatic de-energizing of the lift coil and reduced current energizing of the stationary gripper coils and movable gripper coil s.
- Activation of the alam light (urgent failure) on the power supply cabinet front panel .
Activation of rod control urgent failure annunciation window on the plant annunciator. 4705A
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- TVM y The urgent alarm is produced in general by:
Regulation failure detector Phase failure detector
- Logic error detector Multiplexing error detector Interlock failure detector.
- a. Logic Cabinet Failures The rod control system is designed to limit the rod speed control signal output to a value that causes the pulser (logic cabinet) to drive the control rod driving mechanism'at' 72 steps per minute. If a failure should occur in the pulses or the reactor control system, the highest stepping rate possible is 77 steps per minute, which cortvsponds to one step every 780 milliseconds. A comanded stepping ' rate higher than 77 steps per minute would result in 'GO' pulses entering a slave cycler while it is sequencing its mechanisms through a 780 millisecond step. This condition stops the control bank motion automatically and alarms are activated locally and in the control' room. It also causes the affected slave cycler to reflect further 'GO' pulses until it is reset.
Failures that cause the 780 millisecond step sequence time to shorten will not result in higher rod speeds since the stepping rate is proportional to the pulsing rate. Simultaneous failures in the pulser or rod control system and in the clock circuits that determine the 780 millisecond stepping sequence could result in higher. CRDM speed, however, in the unlikely event of these simultaneous multiple failures the maximum CRDM operation speed would be no more than approximately 100 steps per minute due to mechanical limitation. . This speed has been verified by tests conducted on the CRDM's. 9705A
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The positive reactivity insertion rates for these failure modes including the 100 steps per minute, are bounded by the Chapter 15 SAR analysis assumptions.
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Failures causing movement of the rods out of sequence No single failure was discovered (WCAP 8976) that would cause a rapid uncontrolled' withdrawal of Control Bank 0 (taken as worst case) when operating in the automatic bank overlap control mode with the reactor at near full power output. The analysis revealed that many of the failures postulated were in a safe
! direction and that rod movement is blocked by the rod Urgent Al a m,
- b. Power Supply System Failures Analysis of the power cabinet disclosed no single component, failures that would cause the uncontrolled withdrawal of a group
.of rods serviced by the power cabinet. The analysis substantiates that the design-of a power cabinet is
" fail-preferred" in regards to a rod withdrawal accident if a component fails. The end results of the failure is either that of blocking red movement or that of dropping an individual rod or rods or a group of rods. No failure, within the power
, cabinet, which could cause erroneous drive mechanism operation will remain undetect'ed. Sufficient alam monitoring (including
' urgent' alam) is provided in the design of the power cabinet for fault detection of those failures which could cause erroneous operation of a group of mechanisms. As noted in the i foregoing, diverse monitoring systems are available for i
detection of failures that cause the erroneous operation of an individual control rod drive mechanism. r l 9705A
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. Conclusion In sumary, no single failure within the rod control system can cause either reactivity insertions or mal-positioning of the control rods resulting in core thennal conditions not bounded by analyses contained in Chapter 15.
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C' /d S B //cou #3 M lb CNS 222.0 INSTRUMENTATION AND CONTROL SYSTEMS BRANCH 222.1 See Question 420.1 222.2 See Question 420.2 222.3 See Question 420.3 222.4 See Question 420.4 1A c.4.f4D ED Id h - 220-13 Rev. 4}}