ML18022A606
| ML18022A606 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 01/11/1988 |
| From: | Zimmerman S CAROLINA POWER & LIGHT CO. |
| To: | NRC OFFICE OF ADMINISTRATION & RESOURCES MANAGEMENT (ARM) |
| References | |
| NLS-87-258, NUDOCS 8801200120 | |
| Download: ML18022A606 (532) | |
Text
REQULA' INFORMATION DISTR IBUTI YSTEM (RIDS) lr
/ <<0 ACCESSION NBR: 8801200120 DOC. DATE: 88/01/11 NOTARIZED: NO DOCKET FACIL: 50-400 Shearon Harv is Nuclear Power Planti Unit ii Carolina 05000400 AUTH. NAME AUTHOR AFFILIATION ZIMMERMAN S. R. Carolina Power h Light'o.
RECIP. NAME RECIPIENT AFFILIATION Document Contvol Bvanch (Document Control Desk)
SRK 39poWp) $
SUBJECT:
Forwards response to plant-specific v equiv ements of ATWS mitigating sos actuation circuitrg SER. Requests NRC reviee design 5 provide initial Feedback to acceptability bg 880215 to minimize design reUjork 5 implementation schedule.
DISTRIBUTION CODE: A055D COPIES RECEIVED: LTR ~ ENCL ~ SIZE:
TITLE: OR/Licensing Submittal: Salem ATNS Events QL-83-28 NOTES: App)ication fov permit v eneeal filed. 05000400 RECIPIENT COPIES REC IP IENT COP I ES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL PD2-1 LA 0 PD2-1 PD 3 3 BUCKLEY'S B 1 INTERNAL: ARM/DAF/LFMB 1 0 NRR LASHER' 1 NRR/DEST/ESB 1 1 NRR/DEST/ICSB 1 NRR/DEST/PSB 0 NRR/DEST/RSB 1 1 NRR/DLPG/GAB 1 0 NRR/DOEA/QCB 1 0 R ILRB 0 OQC/HDS1 1 0 REQ FILE 01 1 1 RES/DE/EI 8 1 1 EXTERNAL: LPDR 1 1 NRC PDR 1 1 NSIC 1 1 TOTAL NUMBER OF COP.IES REQUIRED: LTTR 20 ENCL 13
aS SR%
Carolina Power & Light Company SERIAL: NLS-87-258 United States Nuclear Regulatory Commission ATTENTION: Document Control Desk Washington, DC 20555 JAN i 1 1988 F'DR 880i200120 PDR ADQCK 880iiiQ 05000400 SHEARON HARRIS NUCLEAR POWER PLANT DOCKET NO. 50-400/LICENSE NO. NPF-63 PLANT-SPECIFIC AMSAC SUBMITTAL
REFERENCE:
CP&L letter to NRC dated October 14, 1985 NLS"85-370 Gentlemen:
In accordance with 10CFR50.62, the reference letter submitted a proposed schedule for implementing ATWS Mitigating System Actuation Circuitry (AMSAC) at the Shearon Harris Nuclear Power Plant (SHNPP). That submittal was based on a preliminary evaluation of the material presented in WCAP-10858 "AMSAC Generic Design Package". Carolina Power & Light Company (CP&L) proposed to install AMSAC during the first Refueling Outage (RFO) with acceptance testing and training to be completed within three months after the outage. As stated in the October letter, CP&L's schedule was based on 1) NRC approving the WCAP 18 months prior to the RFO to allow sufficient time for design and procurement, and 2) that the 18-month period assumed that the staff would not require plant-specific reviews prior to implementation.
Since the October 1985 submittal:
The SER accepting WCAP-10858 was issued in July 1987. The SER detailed 14 key plant-specific elements that the NRC would concentrate on regarding implementation of AMSAC at each facility.
In addition, the SER also identified plant-specific questions concerning isolation of AMSAC.from existing'afety-related equipment.
Westinghouse issued Revision 1 to WCAP-10858 in July 1987. The revised WCAP contained significant updates to Logic,2 and 3 with regard to the AMSAC enable setpoint.
Carolina Power & Light Company determined that the optimum logic for implementation at SHNPP is Logic l. In the October 1985 submittal, CP&L tentatively chose Logic 3, pump and valve status monitoring, as the preferred logic for installation at SHNPP. This was based on the assumption that there would be no significant changes to the WCAP.
Based on subsequent detailed analysis of the 3 AMSAC logics, CP&L will implement Logic 1, monitoring steam generator water level, instead of Logic 3.
As stated above, the NRC's Safety Evaluation Report (SER) accepting the generic Westinghouse design for the AMSAC identified a number of aspects of the design which would require more detailed, site-specific information in order to conduct .an appropriate review. That site-specific information, relevant to SHNPP, is provided in Attachment 1 to this letter.
411 Fayetteville Street o P. O. Box 1551 o Raleigh, N. C. 27602
SBB ~ E net.
gf
Document Control Desk NLS-87-258 / Page 2 Carolina Power & Light Company's SHNPP and H. B. Robinson facilities are utilizing virtually identical AMSAC systems. As a result, Attachment 1 to this letter is very similar to CP&L's submittal for H. B. Robinson on October 30, 1987, the differences being attributable to AMSAC's interfacing with differing plant designs, and incorporation of changes or additional information to address the staff's comments on the Robinson submittal. At this stage of the project, most of the capabilities, features, and design parameters of the proposed AMSAC have been finalized. A vendor has been selected and final, detailed design is underway to incorporate the selected system into the SHNPP facility. However, the AMSAC design is not yet finalized. As a result, some information specified in the SER's plant-specific items or from staff review of the H. B. Robinson submittal cannot be provided at this time. These include the Appendix A information for the AMSAC output isolation relays, system test frequencies, as well as a simplified logic diagram for the AMSAC 'black box'. This additional information will be forwarded after it becomes available.
Even though the SER was issued in July of 1987, leaving only 13 months before the first RFO, and the SER required the submittal of considerable plant-specific information, it is CP&L's intent to maintain the original schedule of installing AMSAC during the first RFO (i.e., August 1988) if final NRC acceptance of the SHNPP AMSAC package is received by June 1, 1988.
Carolina Power & Light Company has determined that approval of the SHNPP AMSAC design is required by June 1, 1988 to provide sufficient time to finalize modification packages to be implemented during the first RFO. If final NRC approval of the SHNPP AMSAC package cannot be provided by June 1, 1988, CP&L hereby requests NRC concurrence with delaying the implementati,on of AMSAC at SHNPP until the second RFO.
Given the schedule restrictions necessary to ensure that the system can be installed in the first RFO, CP&L must proceed with the detailed design phase of the project prior to obtaining NRC approval of the plant-specific application. Therefore, CP&L requests that the NRC review this design and provide initial feedback as to its acceptability by February 15, 1988 to minimize possible design rework and any potential impact upon the implementation schedule.
If you have any questions concerning this matter, please contact Steven D.
Chaplin at (919) 836-6623.
Yours very truly, Manager Nuclear Licensing Section SDC/crs (5339SDC)
Enclosures cc: Mr. B. C. Buckley Dr. J. Nelson Grace Mr. G. F. Maxwell
Attachment I to NLS-87-258 SHNPP RESPONSE TO PLANT-SPECIFIC REQUIREMENTS OF ATWS/AMSAC SAFETY EVALUATIONREPORT 88p)2ppi2p (5340SDC/bmc )
Attachment 1 to NLS-87-258 Page 1 of 29 RESPONSE TO PLANT-SPECIFIC REQUIREMENTS OF ATWS SAFETY EVALUATIONREPORT On 3uiy 7, 1987, the NRC issued their Safety Evaluation Report (SER) approving the Westinghouse Owners'roup (WOG) prepared Topical Report WCAP 10858A "AMSAC Generic Design Package." That SER granted generic approval of three plant monitoring options which Westinghouse plants could use to fulfillthe requirements of 10CFR50.62, "Requirements for Reduction of Risks from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants." Individual plant approvals were withheld contingent upon receipt and approval of more detailed information concerning the site-specific implementation of one of the approved generic approaches. The WOG has since issued Revision 1 to WCAP-10858 to incorporate various refinements to Logics 1, 2 and 3.
Each of the plant-specific information requests specified by the SER is restated below along with the response applicable to the SHNPP. To facilitate review, the discussion of specific aspects of the design has been prefaced with a general description of the system and equipment selected for the SHNPP application. Since the final design is not complete, the information included in this text is intended to convey the philosophy and design objectives. Significant deviations from this information that may evolve during final design will be conveyed to the NRC.
GENERAL SYSTEM DESCRIPTION The ATWS Mitigation System Actuation Circuitry (AMSAC) system will provide a means to automatically trip the turbine and actuate auxiliary feedwater flow in the event of a complete loss of feedwater transient. Westinghouse analysis, documented in WCAP 8330, has demonstrated that this is the only ATWS event for which Westinghouse plants with motor driven main feedwater pumps would require AMSAC mitigating action in order to prevent RCS overpressurization or exceeding DNB limits. The AMSAC system is independent of, and isolated from, the existing Reactor Protection System (RPS) from sensor to output actuation device. The AMSAC setpoints and timer delayed actuation will ensure that the RPS has had time to perform its function before any AMSAC initiated action. Therefore, the AMSAC signal will be of no consequence unless the RPS has failed.
The Harris Plant AMSAC system will utilize the steam generator level monitoring option as defined by Logic 1 of WCAP 10858A, Revision 1. This is a change from the use of Logic 3, as originally anticipated in early design evaluations. The. system will use the outputs from existing steam generator narrow-range level sensors fed into a microprocessor-based AMSAC controller. The AMSAC controller will also monitor turbine first-stage pressure to identify the 0096 nominal turbine load above which the AMSAC must be armed. Class lE qualified isolators will protect the safety-related circuits currently associated with both of these sets of sensors from any perturbations that could be introduced by malfunctions of the nonsafety related AMSAC circuitry. A timer associated with the AMSAC arming logic will maintain the AMSAC in an armed condition for 180 to 020 seconds after turbine pressure drops below the 0096 power level. This will ensure that a turbine trip will not disarm AMSAC before it has had time to initiate auxiliary feedwater flow if the steam generator level criteria are met. During operation, the controller will continuously scan the sensor inputs. The AMSAC system will be armed when the turbine pressure indicates that the plant is above 0096 power. If AMSAC is armed and the controller identifies a coincident low level in two out of three (5340SDClbmc )
Attachment I to NLS-87-258 Page 2 of 29 steam generators, the controller will actuate a turbine trip and initiate auxiliary feedwater flow after appropriate timer delay to ensure that it does not preempt the RPS Trip functions. The AMSAC outputs will tie in to the existing safety-related actuation circuits using isolation relays to protect the existing systems from problems induced by AMSAC malfunctions.
The AMSAC controller itself consists of two parallel, redundant, commercial programmable controller units. Either unit will be fully capable of independently performing the AMSAC functions. This programmable controller features an Erasable Programmable Read Only Memory (EPROM) which provides non-volatile memory for the controller's program logic. This feature enables the controller to maintain the program in memory following a loss of power to the unit without reliance upon a battery back-up. Alterations of the program in EPROM would require use of a separate programming device. This feature greatly reduces any possibility of unauthorized program changes in the installed controllers.
The AMSAC Controllers will be housed in a cabinet located adjacent to the Control Room. Local displays and controls at the cabinet will provide necessary capabilities for testing, calibration, and trouble diagnosis.
An AMSAC bypass switch is provided in the Control Room. AMSAC status indication will be provided in the Control Room to inform the operator of AMSAC trip status, arming status, and bypass status. In addition, an "AMSAC Trouble" lamp in the Control Room will alert the operator to anomalies in the AMSAC readings. A simple diagnostic process at the AMSAC controller panel would then be initiated to determine the actual nature of the problem. The local panel provides built-in features to facilitate testing and trouble shooting of the system.
PLANT-SPECIFIC INFORMATIONSPECIFIED BY SER 1.0 DIVERSITY The plant-specific submittal should indicate the degree of diversity that exists between the AMSAC equipment and the existing Reactor Protection System.
Equipment diversity to the extent reasonable and practicable to minimize the potential for common-cause failures is required from the sensors'utput to, but not including, the final actuation device; e.g., existing circuit breakers may be used for the auxiliary feedwater initiation. The sensors need not be of a diverse design or manufacture. Existing protection system instrument-sensing lines, sensors, and sensor power supplies may be used. Sensor and instrument-sensing lines should be selected such that adverse interactions with existing control systems are avoided.
RESPONSE
The proposed SHNPP AMSAC system will be diverse from the existing Reactor Protection System from sensor output to the final actuation devices. Steam generator level signals are taken from the steam generator level narrow-range channels at the Process Instrumentation Cabinets (PIC) (signal processing cabinets) via safety-related isolators. The signals are taken at sensor output before processing (see attached Sketches SK-H86-032M-Z-7002, SK-H86-032M-Z-7003, and SK-H86-032M-Z-7000). Turbine first stage pressure is picked up at the sensor and isolated for AMSAC input (see attached Sketches SK-H86-032M-Z-7005 and SK-H86-032M-Z-7006). The AMSAC logic is (5340soc/bmc )
Attachment 1 to NLS-87-258 Page 3 of 29 performed separately and independently from the existing Reactor Protection System. AMSAC outputs actuate existing devices via isolation relay contacts (see attached Sketch SK-H86-032M-Z-7000 for safety/nonsafety output relay interfaces). The proposed AMSAC controller will be a digital microprocessor-based system, thereby contributing to diversity. from the analog logic of the existing Reactor Protection System.
2.0 LOGIC POWER SUPPLY The plant-specific submittal should discuss the logic power supply design.
According to the rule, the AMSAC logic power supply is not required to be safety related (Class 1E). However, logic power should be from an instrument power supply that is independent from the Reactor Protection System power supplies. Our review of additional information submitted by Westinghouse Owners'roup (WOG) indicated that power to the logic circuits will utilize RPS batteries and inverters. The staff finds this portion of the design unacceptable; therefore, independent power supplies should be provided.
RESPONSE
The proposed AMSAC logic cabinet will be powered from a battery-backed power supply. This power supply is fed from a bus which is independent of the existing Reactor Protection System (see attached SK-H86-032M-E-3013).
3.0 SAFETY-RELATED INTERFACE The plant-specific submittal should show that the implementation is such that the existing protection system continues to meet all applicable safety criteria.
RESPONSE
The proposed AMSAC will be electrically isolated at the safety-related sensor inputs and the safety-related outputs. Safety-related isolators will be used on AMSAC inputs. Isolation relays with physical separation of safety/
nonsafety-related wiring will be provided on AMSAC outputs (see attached Sketches SK-H86-032M-Z-7000 and B-001-1936). This will allow the existing Reactor Protection System to remain unaffected by faults from within the AMSAC System, as well as to continue to meet applicable safety criteria as described in the Final Safety Analysis Report, Section 7.1.2.
0,0 QUALITYASSURANCE The plant-specific submittal should provide information regarding compliance with Generic Letter 85-06, "Quality Assurance Guidance for ATWS Equipment that is not Safety-Related."'ESPONSE A. Nonsafet Related QA guidance for nonsafety-related AMSAC equipment has been provided by the NRC through Generic Letter 85-06. CPRL has reviewed the Generic Letter and has determined that the requirements for radioactive waste management systems provided in Section 19 of the CPRL Corporate (5340SDC/bmc )
0 Attachment 1 to NLS-87-258 Page 0 of 29 Quality Assurance Program (CQAP) meet or exceed the guidance provided in Generic Letter 85-06 with the exception of Sections IX and XVIII.
Therefore, activities related to design, procurement, installation, and testing of nonsafety-related AMSAC equipment except Sections IX and XVIIIwill be controlled in accordance with Section 19 of the CQAP.
Existing engineering and plant modification control procedures provide for controls over Special Processes (Section IX).
In order to ensure that the guidance concerning Audits (Section XVIII)is met, plant modifications that involve AMSAC will be included in the
~
. population of modifications from which QA audit samples are selected.
This measure will be taken in addition to the normal reviews by line
'anagement provided for in procedures for engineering and plant modif ications.
Record keeping for design control and modification of existing plant systems will comply with the requirements of 10CFR50.59.
d~fR f d Activities related to the design, procurement, installation, and testing of equipment which interfaces directly with existing safety-related systems, will comply with the requirements of Sections 1 through 17 of the CQAP and the applicable procedures in Sections 3.0 (Engineering Procedures) and 0.0 (Procurement of Engineering Items) of the Nuclear Engineering Department Procedures Manual. Reference 10CFR50, Appendix B.
AMSAC is not required to be safety related nor to meet IEEE-279.
However, the implementation will incorporate good engineering practice and will be such that the existing protection system continues to meet applicable safety-related criteria. Devices isolating AMSAC from the Reactor Protection System will meet the isolation device requirements of IEEE 279-1971.
5.0 MAINTENANCEBYPASS The plant-specific submittal should discuss how maintenance at power is accomplished and how good human factors engineering practice is incorporated into the continuous indication of bypass status in the Control Room.
RESPONSE
Maintenance bypass will be accomplished by disabling the output of the AMSAC controller units with a permanently installed hard-wired switch in series with the nonsafety-related AMSAC processor output relay contacts. Bypass indication will be displayed in the Control Room and on the AMSAC panel. In addition, either programmable controller could be unplugged and removed from the AMSAC controller cabinet or replaced while the other AMSAC controller maintains full AMSAC capability. Maintenance bypass at power will not involve lifting leads, pulling fuses, tripping breakers, or physically blocking relays.
Control room modifications associated with AMSAC will be consistent with existing Control Room design philosophy. Human factors review will be (5340SDC/bmc )
Attachment 1 to NLS-87-258 Page 5 of 29 conducted as a normal part of the plant modification process in accordance with the provisions specified within the SHNPP Detailed Control Room Design Review Summary Report.
6.0 . OPERATING BYPASS The plant-specific submittal should state that operating bypasses are continuously indicated in the Control Room; provide the basis for the 7096 or plant-specific operating bypass level; discuss the human factors design aspects of the continuous indication; and discuss the diversity and independence of the C-20 permissive signal (Defeats the block of AMSAC).
RESPONSE
The AMSAC controller will monitor the C-20 permissive signal in order to identify the 00% nominal turbine load below which AMSAC functions would be blocked (i.e., the Operational Bypass). Operational bypass indication will be continuously indicated in the Control Room. The C-20 permissive signal will be taken from first-stage turbine pressure through safety-related isolators thereby maintaining separation from existing Reactor Protection System circuitry (see attached Sketches SK-H86-032M-Z-7005, SK-H86-032M-Z-7006, and B-001-1936). Two turbine pressure inputs will be required to enable AMSAC.
The power level for enabling of AMSAC will be 00% as outlined in WOG Letter WOG-87-086 dated April 10, 1987 and WCAP-10858, Revision 1. Human factors review will be conducted as a normal part of the plant modification process in accordance with the provisions specified within the SHNPP Detailed Control Room Design Review Summary Report.
MEANS FOR BYPASSING The plant-specific submittal should state that the means for bypassing is accomplished with a permanently installed, human-factored bypass switch or similar device and verify that disallowed methods mentioned in the guidance are not utilized.
RESPONSE
The means for manually bypassing ATWS will be a permanently installed, human-factored bypass switch located in the Control Room. Bypass indication will be at the local panel and in the Control Room. Bypassing will not involve pulling fuses or lifting internal wiring. Switches and indication installed in the Control Room will be of the same design philosophy as equipment presently in service. Human factors review will be conducted as a normal part of the plant modification process in accordance with the provisions specified within the SHNPP Detailed Control Room Design Review Summary Repor t.
8.0 MANUALINITIATION The plant-specific submittal should discuss how a manual turbine trip and auxiliary feedwater actuation are accomplished by the operator.
(5340soc/bmc )
Attachment 1 to NLS-87-258 Page 6 of 29
RESPONSE
Manual initiation of a turbine trip at SHNPP is accomplished by rotating a single switch on the main control board.
Initiation of auxiliary feedwater is accomplished from the Control Room as follows:
~ For Motor-Driven Auxiliary Feedwater Pumps I) Start selected pump(s)
- 2) Verify appropriate auxiliary feedwater header valve alignment for feedwater flow.
~ For Steam-Driven Auxiliary Feedwater Pump I) Start pump by placing steam shut-off valve in OPEN position.
- 2) Verify appropriate valve alignments for steam flow and auxiliary feedwater flow.
9.0 ELECTRICAL INDEPENDENCE FROM EXISTING REACTOR PROTECTION SYSTEM The plant-specific submittal should show that electrical independence is achieved. This is required from the sensor output to the final actuation device at which point nonsafety-related circuits must be isolated from safety-related circuits by qualified Class lE isolators. Use of existing isolators is acceptable.
However, each plant-specific submittal should provide an analysis and tests which demonstrate that the existing isolator will function under the maximum worst-case fault conditions. The required method for qualifying either the existing or diverse isolators is presented in Appendix A.
RESPONSE
Isolation relays will be used for the nonsafety to safety-related interface on AMSAC outputs. Nonsafety AMSAC outputs will energize the coils of the isolation relays with the relay contacts initiating ATWS mitigation in safety-related circuits. Safety and nonsafety relay panel wiring will be physically separated. These relays will be seismically and environmentally qualified.
Safety-related signals for ATWS input will be taken from existing sensors with safety-related isolators. Cabling and conduits to the AMSAC controller will be separated from existing Reactor Protection System equipment. Specific responses to the Appendix A information requests are provided below for the signal input isolation devices.
RESPONSE TO APPENDIX A ISOLATION DEVICES Signal isolators for inputs to the proposed AMSAC system are presently planned to be Class IE qualified units supplied by Westinghouse. These 7300 series (5340SDC/bmc )
Attachment 1 to NLS-87-258 Page 7 of 29 Process Control System, Class lE isolators are similar to units that have been used in other safety-related applications at SHNPP and are understood to be accepted as qualified isolators by NRC (see Attachment 2, NRC letter to Westinghouse dated April 20, 1977). The Appendix A information requests are restated below followed by the response pertaining to these input isolation devices. The responses reference the appropriate sections of the test report, WCAP-8892A, which are also enclosed as Attachment 3 to this submittal.
INFORMATION REQUEST A For the type of device used to accomplish electrical isolation, describe the specific testing performed to demonstrate that the device is acceptable for its application(s). This description should include elementary diagrams when necessary to indicate the test configuration and how the maximum credible faults were applied to the devices.
RESPONSE
The following tests have been performed on the Westinghouse 7300 Series Process Control System.
A. Test Performed as Outlined in WCAP-8892-A (see Attachment 3)
- l. 118/060/550 volts AC to output of isolator Fig. D-2
- 2. 115/250 volts DC to output of isolator Fig. D-2
- 3. 5 kv antenna (noise source, crosstalk) Fig. D-l
- 0. 1 amp current test AC Fig. D-2
- 5. Random noise test Fig. D-1
- 6. MIL-N-19900B Noise Tests, 2 sources Fig. D-1
- 7. DC relay (noise test) Fig. D-2 INFORMATION REQUEST B Data to verify that the maximum credible faults applied during the test were the maximum voltage/current to which the device could be exposed, and define how the maximum voltage/current was determined.
RESPONSE
Steam generator level and turbine pressure signals are 0-10 volt loops. The isolator takes its input signals from the signal loop and converts the 0-10 volt input to a 0-20 mA output. The maximum credible fault condition postulated for this application would involve some low probability undetermined mechanism which would short the 120 volts AC power supply for the isolator or the AMSAC cabinet across the output circuit from the isolator. The capability of the isolator to withstand such a fault is demonstrated in WCAP-8892A.
(5340SDC/bmc )
Attachment l to NLS-87-258 Page 8 of 29 INFORMATION REQUEST C Data to verify that the maximum credible fault was applied to the output of the device in the transverse mode (between signal and return) and other faults were considered (i.e., open and short circuits).
RESPONSE
Testing verified that 1 l8 VAC applied on the control side wiring did not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to this wiring being in close proximity to each other. (See WCAP-8892A, Appendix G.) Appendices 3 and H reached the same conclusion for 060 and 550 VAC tests. See page D2 for configuration.
INFORMATION REQUEST D Define the pass/fail acceptance criteria for each type of device.
RESPONSE
Phase I tests of WCAP-8892A were performed to demonstrate that a credible perturbation in the control wiring (isolator output) would not degrade protective action, nor be reflected back into the protection wiring (isolator input).
INFORMATION REQUEST E Provide a commitment that the isolation devices comply with the environmental qualifications (IOCFR50.09) and with the seismic qualifications which were the basis for plant licensing.
RESPONSE
The Westinghouse isolator equipment specified in the preliminary ATWS design is the same as part of the original plant process instrumentation and meets the seismic and environmental qualifications which were the basis for plant licensing.
INFORMATION REQUEST F Provide a description of the measures taken to protect the safety systems from electrical interference (i.e., Electrostatic Coupling, EMI, Common Mode and Cross Talk) that may be generated by the ATWS circuits.
RESPONSE
Westinghouse process instrumentation, 7300 series, has been tested for expected credible voltages and noise levels:
5 kv antenna (noise, cross talk)
Random noise test MIL-N-19900B (noise test 2 sources)
DC Relay (noise test)
(5340SDC/bmc )
V C
Attachment 1 to NLS-87-258 Page 9 of 29 ~
\
It is not anticipated that ATWS could or would produce noise or interference outside of the scope of these tests, if ATWS circuitry produces noise at all.
INFORMATION REQUEST G Provide information to verify that the Class 1E isolator is powered from a Class 1E source.
RESPONSE
The ATWS isolator cards will fit into existing Westinghouse Process Instrument Cabinets (PIC) and utilize class lE power supplies as provided in the PIC.
10.0 PHYSICAL SEPARATION FROM EXISTING REACTOR PROTECTION SYSTEM Physical separation from existing Reactor Protection System is not required unless redundant divisions and channels in the existing reactor trip system are not physically separated. The implementation must be such that separation criteria applied to the existing protection system are not violated. The plant-specific submittal should respond to this concern.
RESPONSE
The SHNPP project, including the existing reactor protection system, meets the intent of Regulatory Guide 1.75 "Physical Separation of Elective Systems" as described in FSAR, Section 1.8. AMSAC will be physically separated from existing Reactor Protection System hardware in accordance with CPRL's commitment to Regulatory Guide 1.75, such that existing Reactor Protection System separation will be maintained. The AMSAC controller will be located in a separate cabinet where there will be no interaction with existing Reactor Protection System equipment.
11.0 ENVIRONMENTALQUALIFICATION The plant-specific submittal should address the environmental qualification of ATWS equipment for anticipated operational occurrences only, not for accidents.
RESPONSE
The AMSAC controller, cables, and instrumentation will be installed in locations that are controlled, mild environments under anticipated operational occurrences.
12.0 TESTABILITYAT POWER Measures are to be established to test, as appropriate, nonsafety-related ATWS equipment prior to installation and periodically. Testing of AMSAC may be performed with AMSAC in bypass. Testing of AMSAC outputs through the final (5340SDC/bmc )
Attachment l to NLS-87-258 Page 10 of 29 actuation devices will be performed with the plant shut down. The plant-specific submittals should present the test program and state that the output signal is indicated in the Control Room in a manner consistent with plant practices including human factors.
RESPONSE
Present plans for the Control Room indication include "AMSAC Armed,"
"AMSAC Bypassed," "AMSAC Initiated," and "AMSAC Trouble." In addition, the AMSAC Bypass Switch will be located in the Control Room. Human factors review will be conducted as a normal part of the plant modification process in accordance with the provisions specified within the SHNPP Detailed Control Room Design Review Summary Report.
The proposed AMSAC system will offer extensive self-testing and diagnostics as well as built-in capabilities to facilitate operator testing.
Controller Pro ram Checks (Automatic)
Each programmable controller will perform self-diagnostics to ensure proper operation. Immediately upon power-up, it will perform a cyclic redundancy check on the read only memory (EPROM) containing the microprogram which directs the programmable controller operation. The self-diagnostics will test the random access memory (RAM) to ensure it can be written to, and read from, and verify proper operation of the arithmetic and logic functions.
A parity check on the program memory is performed each time an instruction is executed. This involves encoding a specific "parity bit" tracer at predetermined locations in the program data in memory. The controller verifies the authenticity of the command by verifying the existence and location of the parity bit. A watchdog timer will check that each scan is executed normally.
These checks will ensure that the hardware functions properly and the software is not corrupted.
Sensor In ut ualit Checks (Automatic)
The AMSAC controller program will perform a "spread check" on AMSAC input signals every scan cycle and light the "AMSAC Trouble" lamp in the Control Room and on the local AMSAC panel if a large difference exists among the level signal inputs from the three steam generators or the two pressure signal inputs from the turbine. The plant personnel will then use the AMSAC local panel's diagnostic features to investigate the nature of the problem. Figure B shows the controls and displays currently planned for this local AMSAC panel.
Although the design is still preliminary, this figure is illustrative of the system's capabilities for testing and troubleshooting. The precise manner in which these capabilities are incorporated into the final design may change.
Status lights for each input to each controller unit will indicate which of the inputs was exhibiting the excessive "spread" that initiated the "AMSAC Trouble" lamp. Simple deductive reasoning will enable plant personnel to quickly ascertain the probable source of the problem. For example, a large signal spread for the same steam generator level exhibited on both of the AMSAC microprocessors would suggest a defective analog input signal while a large signal spread indicated by only one of the microprocessors would suggest a (5340SDC/bmc )
l I Attachment l to NLS-87-258 Page l l of 29 defective microprocessor. This diagnostic capability also applies to the C-20 permissive signal.
These status lamps will also indicate any inputs which are in a "tripped" status for having exceeded their setpoint values. A separate."variable tripped" lamp indication will allow plant personnel to distinguish indication of an input exceeding its setpoint from that of the input exhibiting an excessive spread from the other corresponding inputs.
Pro ram Lo ic Verification (Manual)
I The application program logic will be tested manually by switches located on this local AMSAC panel. The operator will select the desired microprocessor using the "TEST" switch to take that unit off-line while the other AMSAC microprocessor remains on-line to provide full AMSAC'capability. Using the hard wired switches associated with the input status light, the operator can then simulate various combinations of inputs to the unit in test. Here again, the status light will indicate which input signals have been bypassed with simulated inputs and verify that appropriate output signals are generated by the program.
Out ut Contact Verification (Automatic)
To enhance reliability and testability, each AMSAC controller unit will drive three relays wired in a configuration shown in the attached Figure A.
Continuity is required across these contacts in order to supply power to the isolation relays which initiate mitigating actions. One of the relays from each controller unit (labelled A3 and B3) will be normally closed during operation and opened only when the associated controller unit is in a test mode. The other two relays from each unit are redundant modules which are normally open and close only upon an AMSAC actuation signal from the associated controller. This configuration of redundant output relays from independent controller units contributes significantly to the reliability of the system. This configuration also allows each individual controller, to automatically open its associated test relay and verify operation of its output relays without applying power to the final actuation relays or inhibiting the ability of the other controller unit to initiate an AMSAC actuation signal.
Tri -Set oint Accurac Test (Manual)
Periodic analog signal accuracy tests will be performed manually by injecting a signal into the controller unit in the test mode at an external terminal connector and verifying the value displayed on the digital readout. The trip setpoint for each input signal is similarly compared using a variable input current source and checking display value when the corresponding lamp actuates. The test frequency for accuracy and trip setting are anticipated to be comparable to the existing Reactor Protection System periodic checks.
Safet /Non-Safet Interface Isolation Test (Manual)
Input isolation devices and the output relays which interface with the safety-related actuation circuits will be periodically tested and calibrated much the same as existing Reactor Protection System circuitry.
(5340SDC/bmc )
Attachment 1 to MLS-87-258 Page 12 of 29 13.0 g,
COMPLETION OF MITIGATIVEACTION AMSAC shall be desi ned so that once a ctuated, the completion of mitigating action shall be consistent with the plant turbine trip and auxiliary feedwater circuitry. Plant-specific submittals should verify <hat the protective action, once initiated, goes to completion and that the subsequent return to operation requires deliberate operator action.
RESPONSE
The AMSAC controller, upon plant conditions indicative of an ATWS event, will trip the turbine and start auxiliary feedwater via contacts added into existing plant circuitry (see sketches SK-H86-032M-Z-7007 through 7013). The ATWS event signal will allow existing "seal in" circuits to complete mitigating action. Deliberate operator action will be requirea to restore reactor protection circuits to manual operation.
10.0 TECHNICAL SPECIFICATIONS Technical Specification requirements related to AMSAC will have to be addressed by plant-specific submittals.
RESPONSE
Carolina Power R Light Company concurs with the position of the Westinghouse Owners'roup (WOG) that technical specifications for AMSAC are unnecessary and inconsistent with the goals and criteria of the TS Improvement Program.
The justification for this position was presented to the NRC by WOG Letter OG-171, dated February 10, 1986.
(5340SDC/bmc )
Attachment 1 to NLS-87-258 Page 13 of 29 I
CON7ROLLE/2 A Co<T ~o~~zz 23 I
I ~-. ~~~< A, B$ 78$ T PELA P I I I
I I I
OuTpc/T I 007 PELRY Z AZ par'CLAY 2
I I
I I
QQ< pur QOTTu7 Rc& i'. I RGcHV 4 I I
I I
7mez Td ECkzcize AcruAnou/ssoc~rioa RzC.cf Ya Notes: 1) All contacts open when de-energized.
- 2) Contacts labeled A are driven by Processor A; those labeled B are driven by Processor B. Either processor is capable of independently generating the AMSAC initiating signal.
- 3) Contacts A3 and B3 are held closed when the AMSAC is running. A3
,opens when Processor A is under test; Contact B3 opens when B is under test.
- 0) Contacts numbered 1 and 2 are from redundant output modules on each controller. Both close upon a signal from the controller to initiate AMSAC mitigating action.
FIGURE A - ARRANGEMENT OF SIGNAL OUTPUTS (5340SDC/bee )
Attachment l to NLS-87-258 Page l0 of 29 LEVEL 1 Q Q AMSAC TRIPPED LEVEL 2 (RED) aSYSTEM RESET TEST LEVEL 3 POWER POWER 2 OPP 1
TEST Q 2 TROUBLE (ORANGE)
SYSTEM BYPASSED (ORANGE)
DIGITAL TEST DIGITAL READOUT READOUT Q TIMER TRIGGERED Q Q VARIABLETRIPPED Q VARIABLE VARIABLE SELECT SELECT FlGURE B AMSAC PANEL (5340SOC/bmc )
I
~j468&EAf g 7,0 pcs -gg- gQ
'CH I 9E6I I CO~
hlOH-SAF": I Y R":CATT.O I pS- X~oF aV I
r
I lr SAFF><ARo TEss CAB I I ARP 19A I SI4T 1353 I I .
I l. I I I
TB-813 Ta-91+ SI4T 1113 SI4T 1975 rI4CB- I 81 I
I I
I I
I I
I I
ER IS II4ULT IPL~m C 8 I,I I
I I
I I
I ANNUNC.
CAB-2 AL~17 I
I I
I r
I I
I I
I QLATION CAa 2A I2A2> !7Ztt'I s w 34 33 111 112 I I I I I I . C11975>>
I I
I I
I' I
I I
I I
I I
J I l~
I 1353 IR w 0 I I i I --- r I EX I ST INS I
I C11113>>
I I - -- C I I l I I )G',}-- ] w TBI~I I C
I I
I I
="==,--:-. "==El .-==-=- 1113 ' I I
I I I J
la iW A la lw /8 )w- lR )9 8
- ."..I ~c~T I O.J -TBS:
P O I CAG 25 (252)
I 14
~ 6: I I
I Ic~~l 'I 111=-'9,
~2 Ir" I
I 34 325.
I, I I SHT 1974 I AMSAC PANEL I 11974 ~
+w 27 I
I I I I I 5 C 11974 >>
I I i I I I ~ I I I I I TG;B13 SAFESUARO ITB (p I 2 TE=I CAG "8" I --I--. = I 3
ia lw Js Ia w Is J B lw I 5 c( (e Jw (5 I I SHT 1353 1
I I 8 /w /5 J I I I 2 I I TB-914 1
ITB ITB ITB I I
I I I I' }
,I I 5 C-113 3>>
I PIC I I PIC4 I PIC I I PIC C 8 Co CAB I I
1 2 I
3 I I I
P1ITATI~'~ C~-~ ~-~-:~~ I sar-aF.-" i;-.
I I I I I I I I SAF= I Y RELA I~ RC/ I Ca TE I
~r Q~~llsTICH
)8 I
I PPQ c~l CslsL EHC I ~ REIsi I
I TI RELATED ISO'AFElY UPP-18 I INO I CATES CABLL;TAG IOENT IF I CAT I QN US%) FOR THESE ~CA8"~. I APERTURE CAROLINA PONE? 4, L(GHT C04l.
120V-VITAL SC~ESII EHCIHEEIIIHC I I.ICEHSIHC CEPAllTSlEHT IIALEI I I I
CAR9 SHARON HARRIS NUCLEAR P P AC PANEL I I TITLEs A INS I I I
Also Av~le Oa COhlIROL NIP.ING OIAGPAR I Apery e Card e-<01-1935 I
I
'I I
1 k
S i
r ie' c
/tI/CI/AEAJj J go 1/4-g7- @san C.C I pj'-4 uFgf G,QCY ESIERe EM SA~ 6 SKY ~, GUS SG~ 6egKY AUXe EUS 'IE OTAe 481 OTAe SSII
'.... 'T.
TIlral, ~ ~ 544YICL 0 1 tsa. 4'. I. ~ ~ ~" STAe 461
'I 4 I ~
460V ~Me EUS SA4 SA I 484V c~~ E~ tee~~
.) 480V AUXe AGCY AUXe 484 'rCER KK lett ciUS I ~
484V ENEII A21~~ 484Y ESIER 484V
~
ESCHAR 480V BIER tel
),)
SIC 1 5825 484Y 54 t 824 480V NC KK SMS 480V SC 1ESS
.)
IAZI I~
ILOCYAI ccr
~ -- ) ,)
I4OCYLI ILOCYAI
~),) ) )
ILSCYLI
.-I )=- -."-). -. I
)Cu. F CL~ " CA~
PPSAZS t~
1 ZO/ZOGY 1 P. IA35 t~
ZO/ZOGY 124/ZOGV PPSOZS S~ tZO/ZOGY PPS o~l 1 CLIYISII 14
~ ~
~.
CCCACRGI t~ DC I ESIERe bM t~c ESER. GUS DC I DP I c8
) N DPS I)
~L I?5 OLT ~ I IL 141
~
llATIIc45 I'L 541.
I T OCYL IP5 IILTIIcll Ii IIISTP~ 7 I tmCXX 1tGY INSi 7'58V 1 18V INS i ~
Ph 1Am PA 14 SNSi t ic= T ACYL reecCSP e I
)a-.. 4
)aT. 4 4 I
)CXe )aT. 4 I I l PICKS
~
CAY%'
LQI eL 5 ~ PcC cC 4
~
Q CEVC.
elec
~.
~
Otic I cYC ANNA.
PTccTP PIC~c 11&55M i~ ~ ~
INTCcCOa I C-TSII ccet44 ZHSkcTA PT Cere PCeQSc CXTe 14 ICAY PCYSII r PrrcTL. CPP IO
'Y I TAI COO I C I CCCt I CCLCC i n C CCC
~COCCI OiA I ICXR ICS NS I NDN==APEml TL
~
51 514 CAROLINA POY/ER PLANT ENGINE=RING
'HEARON HARRIS I
Q LIQQI CQQpANY DEPAR~
UNIT
~I tt GN N C Also AVL~~> 0+ AMSAC POSER SUPPLY
'gpertuee ~~ cc SIICCl CLC I CLOI ILLCTI
~. 5K-H el6-0>2.rl-==3O13 ' IiLY cCI ~
9 10 I
eI I
ky
i ~
~wc,HWr~fd I ~>
p&-gF-8,58
~~Dc! OQOL:"PlZH-9Eil-'AQ ~. J70FBV 5= ~i- IS
~ ~
PULI IPI.~
Cx~,
~ ~
CONTROL .
.. NOH-cMFci Y R:-M> cD Pod< cAc~t Y REL47co-S/C Ki'SHLD
.. ~ ~ ~
..:. .ZIC I45 r ~ ~
QN-~~-: tf RBÃ~B": --";-.- WIN p, P2JC Ig i--';/- I~ .-"
PC AMcAC HQ}4-=AF=i f RPMi=D IBOLATICN 5 FBGUQD
~ CHAWWP I CI=M 'A'L=V" CAB I
9-2o cia CABINET . QQ g ~P CAB ZA
-(~A ~) ~ ". CAB'A'URB!M=TiclP
~ ~
PIC CHAMNci 7 CAB . ARP BTART MOTOR DRIVc.l "
SM G=!4 'O'cVci 2 I9A AFWP X 5 TURB!NB LT-435 ORIVEM PUMP i
1 ~
.STM GW'C L=V=' .l=OLATION gAIN Bt
-' 'CA525
'I Ms=') . . c~"-=GUARD CHAMuc' J URBIMB TRIP TUR- IE'IAGc~/cc5c F I Ckfs P!C CHAMNc .CAB .~iARi MOTOR DRN=Q AFWP 'c' iURBIMB Ages TURB. Is ~iAG" FR:"= . d.
.... PT-4-".l U DRIVm PUMP 1ZOVAC 8'SDlP bO ac sac-a -'
I28'.l>hi//IA-wc iicv I sate i DCSc/iitciois
~ eO/CSSiOiiM CiiCIICC/i SCC. iiO YI.. -. . SAFETY RELATED KE@;fQRK. CAROLINA POY/ER 8 LIGHT COMPANY NUCLEAR PLANT ENGINEERING DEPARTMBii RAJJGN, N.C.
~ . CA.RB HEAR N HARRIS NUCLEAR P P iifLCi
~Age Available On AiWS BLOCK DIAGRAM
~ -I
'Aperture Card CCCCC
/ ~SK-HSG-032M-Z-7000 ~; "0"""P 10 I
a(
1 P
I
ADO II TOPAMC c-=
I I 5~IOWE
~
I .
A HB6 c
~d RTKD Mt F'11I ~aveefsP T
cHT 1%~6 0=-2M L1~C g LY-474@
~
~0~2
~ 45 0 ZHSH)2 24&20@)C zd 1w.ir. J 0~0~1 2HSZ< 1 2&02(Xl5 ZTt ~
121 +.1ZS
~tt 1
> $ 0tIP POVER
~dL T IAIA7 AA 55 I 032I ~ 5ov 10 OMOI ZT 0&000-27 LOT 4 f+
ZSL
<oP A04 0 Ao bv Qr 0&01 ZS 0&40&20 a. CIIANIIEL I Izt TEST ZTL 1 tZZ 2YL1 los 0828 LS/4744 II ORPARAYOR NA 'I v,C 0aZZ '
4744, SAGc DRAWlMG 2445D+I SHT.9 R'EV. 2 ChROLJhlh POWER 6 LTCriT CQ.
,;SHEARON HARRIS NUCLEAR P I'NON
-. SAFETY. RELATED IMTERCON NECTIM6 WIR tMG DIAGlZAM GTM. GEW. l LVL (MARROW RANGE) 0 'H 9.034+ Vr j'4 PROT. CHAl tMEL I C=:-". i.=TI>CV 0~8. 244504I SHT 9
)
IL =: < c~ No. SK-H86-032M-Z-7002
~. Jg or AP AOD
+ lNN TO AM~WC -- - ~-
S== DWG
- S~I SHT.
S h l'M .. '
A T,5 HB5 ZITI alll- C U~~C Qotkl IJ+C4 I.Y-48SA a~a~a 2HS2db 24 02~
IIY 0~0~7 24052<7 2&020+7 2TI ~ )4 l l21 I Y
'Y 12'lII
$ 0)IO IOOYER 0 I
LL/405A ~5 I N P OZZIE ~ tie la 0&01 1$ OIHOS IS I OT kb5 2 Mete J04000Y bt 0~0 I le CIVIC Ie CK. I N I?I 2 CNONNOC I TEST NCI~
2~0 I ~i22 I 0829 IOO I.S/485A c'WP lllATCII NA I 0327 L.S~+55A SASe ORAV/ING
'445D42 SHT. IO REV. I GARQLIhlA POWER 4, LIGHT GQ.
SHEARON HARRIS NUCLEAR P P NON- SAFETY. RELATED
-iWTmCOWWECTlWC WiaiuG DlAGRAM STM. t;aW. Z LVL (WA~ROW RANCH PROT. CHAwklFL 2
~e I ~-"=. 0>G. 2445042 SHT lo C
C
=~~-c~ ~o. SK-H86-032M-Z-7003.
pg QO u/cRP ADO TO AMSAC SSK DWG A :5-4QI SHT.~ 'i Otgd 886 &So t.~TED ~
032M u~PuI ~uvccf'cc MWc4 Y.//96A 4 O'Hot 1< 2H)22 14 V.It v f 0&01 24402 12 1' ~e ti QOg PO'If 2 IIL f)SOl ATP/
03Z9 )I 1 CY 424 I20 iY11MP 0330 tY 4%4 0336 I.C/4't 4 IUC/74QE)
BASE DRAWING 2445043 SHT. Il RFY. l CAROLINA POW:"8 5 LIGHT CO.
SHGARQhl HARRIS hlUCLEAR P P MON-SAFETY RELATED IWTERCONhJECTlklCI WIRlNCI DlAGRAM STM. CIEH.3 LVL (NAIZROW RANGE) 5 QQ/,-n-3 PROT. CHANNEL XK 1-~=c jt= t roe
~w. gus. 2445043 SHT. Il eg=TC+ NO. SK" HGG-OGHAM-Z-7004
I Ofl.
rrrr00 I
rrrri4L lr,st ~tvwr~ i I
t r It II 0&05 tf 4&00 tC 0~00 tk 0~00 t6
~ or ~)5 IV I
PICA 14
.Oa t
I
~
gS N P atlCNaNNCI. NI'? 0~~03
~ IC55 0801 I f05 ~ga lt PC/lid 1NoUtl 0336 IIO/444 lli0/tCCK)
Ta AMe~C r .SE:" GWG B-40I BHT. ) 'I35 c~l A
~PVf Cnv~~18C. HS6 .
LJ~C. ~ 032M PY-446 ADD
'BASE DRAWIMG 2445043 SHT.l2 REV.3 CAROLINA POWER 6 LIGHT CO.
SHEAROM HARRIS NUCLEAR P P MOM- SAFETY RELATED IMTERCOMMECTIMG WIRIMG DIAGRAM FIRST STAGE TURBINE PRESSURE
<HPc PROT. CHAMMEL 'KE G=-HCRIFTIGN,
<"-.=. Gws. 2445D43 SHT. IZ a/ fl'C'.-1 gQ . S K- HGCo 032M - Z - 70 0 5
', ~ /
1, l v.~f~
071.'
0S1 h
I
~tent 0
I 0&005 0~05 lf 20 0~02 0~02 tf 20 2'l >
)Pg Nd1(
POSER jSOt3 N P
.he OZSL OZ36 T'ROS@-gt. POT~hh7 PO/hh7 o TSST H T1 <UO/74h01 OBZ7 PS/hh7
~ h h TO AMSAC
-" DWQ
~ J'( .
Stol 5% &35 I
eu]-JEST'UVgR,~
Q/c< ..
K PY-4J I AOO A
HB6 032M BASE DRAWlklG 2445044 SHT. ll REV. 3 CAROLINA POMD'R 6 LIGHT CO.
SHEARQN HARRlS hlUCLEAR P P MON-SAFETY RELATED INTERCOWMECTIMG WIRIWG DIAGRAM I=INST STAG'E TURBINE PRESSURE KTU.IS i 'Pg H Pg D.P~)~ PROT. CHANhlEI ZZ z
Z 1U D C OESCR IFT 1 GiV
~~~. owe. 2445P44 SHY.II U D PT 0
SKETCH Na. SK-H8ID-032M-Z-7006
~ ~
~N7 ~
NOTES-'ffwc//n ze -8'-
pg, g3 0/
dS'<
gi S.9 KY BUS IB-SB CUB. Q (IS4 4- t~C ea, I. CR-(~) LOCATEO IW ISOLATION CABIWE>
15&49 +Z+8+I 28;,,SEE OWG 5 4OI SHT. 3Q'35 4Z<SQ) SH.I73Z. 2.CONTACTS CLOSE ON ~i GEbl. LO-I 0
. LEYKL.
86UVX SB Bl 7 XO5 XD&
ute-l~a(
!{I'G4-691&)
g p./ Co32"9 K(o41 2 iNOiEH) l 432 ".,
l c-SB
>~is ~is g~z SSP(S) OuYPuw->
~~CR fA9 l97+
TDPU',2t
'97+ (H@~-277@, SH.ZZ RI
'U
-,Dp)I.'2.2liI 4 (W 1~74j TOPU iC< - I 4955, I 4m S z, +Z3 "~.
<<Z35& ) SH.I731 C3 /D IJ Wl l(
5A Fi'LO 5 7 YMr P-SA I
los ioo KCu4l
~51~5 2 (NOT" I)
~o~iZ I/l915 ~~~r2-I9 iN>T CR- 5-GA l
'.:-F(A) QVTPuT-I (P~-r'7~~,Saq2)
TOF'U f.r i 10
~ 1 NOTES l09 ArcP-I~i A(5A) R 2
- C'R-(~)
I. LOCA i KO IN IBQLATIOkl CABIN~i '2A. Sc== DWG $ .401 SH'0 1 .Z6.
Z.COI4TACi5 CLC5"" ON ~iKG=N. LO LO f(l":6-".-<~47~) L>>t/L1 NOT A 1
tt QBZI4 ADD BASE DRAWING 5-401 SHT. I9'75 REV. 8 CAROLINA POMER 4 LIGHT CO.
SHEAROM HARRIS MUCLEAR P P SAFETY RELATED i; '
~
CONTROL WIRING DIAGRAM Pr Aux. FEEOWATER TURB. IX-SB STEAM B
'est PZ " 8 N- h= a H. ISOL. VALVE '2MS-V8SA-I 1ij i
C GHCR ii=iIOhl
? owe. B-40l SH u ge
=<<Tc< No. SK- H86-032M-Z-7008
jI KGZO I
10 ll l2
<<"-C wg I
STC-0) PAL-I (I369.56759, SH. IB, I7)
XII cc gr 4 z ~.8~~
zeal=.Io IT pl (
NOTES ADD 1. CR-(~a) LOCATED IN ISOLATION
~aWET 2A. SEE DWC S-40I (HI-1~v<
A 2. CONTAG75 OPED OM 5 i HAI4 GEOL LO-LO HG6 LEYEL.
052M SASc DRAWlMG 6-40 l SHT. 1353 REV. 6 ChROL1HA POWFR 6 LJGriT CO SHEARON HARR15 NUCLEAR P P SAFETY RE,l ATE,D .
CQhlTROL 0/lRlhlCI DlAGRAM TUR81MF AUTO TRlP AND
'FF c, HPi"-c'~')w OVERSPEED OKSCRIFTIPN
~v. owe. B-401 SHT. 1353 c:ya TcH NP, SK HS& 032M Z"7009
0 815cknsW J'o A As- P'-@P SSP '6) OUTPUT-1 l,
(1W,4-Z776 SH.Z4) iC~o20 K&ZO Fp:-<8), PN1--1 03t'o4-36759'H.
13,19)
~
813
~
) 4 l PiiV>> ~ P'vs-se NOTES
~ADD
- f. CR-(~) 1 OCAi"-3 IM 16QL.47IQM .
- CABl'QET 25. Sc" DWG. S-Wl SH ~ )~-6 A ~COMTAC iS OPEN Ohl QTM. GcM. LO-LO H86
..LEVEL.
oszw BAS'E OQAWNG 1-401 SHT.1953 RPl 6 CAROLINA POWER 4 LIGHT CO.
SHEARQN HARRlS NUCLEAR P P SAFE'TY RELATED CONTROL WIR1MG DlAGRAM TURBlNE AUTO TRlP AND XPG" HP4 0 ~ALE OVERGPEED tU C O~~CRiFTiON
.=.==. owe. 6"401 SHT. I~55 u
cgi=Tcq go. SK H86-052M" 2-70 lO
O q4 <<E15 )
(g9 A
@32M i'll ADD I (.-g
~~4
.BA5K DRAWlh1G 1-40l SHT. Illa'EV. l0 CAROLINA POWER 4 LIGHT CO.
GHEAROhl HARRlS klUCLEAR P P SAFETY @EL.ATED.
Q
~
~ C CONTROL WlRlMG DlAGRAM EQF RGEMCY LOAO SEQlJF}JCER 6S 0 R4-092M ESS CAB lA-SA OKSCR I FY ION C~ Q p-"-". gwg. 6-40l SHY. Il)3 crycH go. SK- H8~o-05'ZM- Z" 701 l
~~
0 U
C 0
t I
'I
~ ~
A Pop 0""ZM I 5R) ~, ~, 'I AOD
( l~g4 pl~ ~
-,4":4'-"')
I, ~
~ )' ~
. ~ .".
BASE DRAWlMG 8-401 SHT.1156 REV.8 ChROLINA POMe~ 6 LECHT CO.
'.SHEARON HARRlS WCl EAR P. P.
. SAFETY RELATED CONTROL V/1RlhlG DlAGRAM EMERGENCY LOAD SEQUENCER PB.S f404-n t"t~s E55 CAB. 11-SB
>> 'hl p~~. owe. 1~1 SHT. 1158 O
P==PR I.=T I pi%
cgpycg Np, SK"HSG-032M Z" 701~
xV
~tU
+
O~
5 aU'O
~0 Q~
UJ QoS 227 z
QC C4
.IQ ..... m I I W I CSTC I OSSCS>rTIOss
'rl
- SAFETY RELATED.
Pveanble On CAROLlNA PO'/I/ER 8 LIGHT COMPANY-NII~~R PLANT ENGINEERING DEPARTMENT RALEIGH, N.
Aperture Cal ~ ~" SHARON HARRI5 MUCLEAR P P
""'.STARTlHCI CONTROL ClRCUlT FOR MOTOR DRNEN AUX. FE.t=DWAieR ISTIC I NUC I 4CCN I 222 PUMPS A< 5 CS I gyC I
IQ ~I/ , "-K-HBG-0"2vil.'z-7013
1.
6
Attachment 2 to NLS-87-258 APRIL 20, 1977 NRC LETTER ACCEPTING "WESTINGHOUSE 7300 SERIES PROCESS CONTROL SYSTEM NOISE TEST" (5340SDC/bmc )
ggS IIE0I c> UNITED STATES
~4 ~o 4f i~
NUCLEAR REGULATORY CPMMISSlPN g> 0 l WASHINGTON, D. C. 20555 pa
%y*y4 Mr. C. Eicheldinger, Manager Nuclear Safety Department P. 0. Box 355 Westinghouse Electric Corporation Pittsburg, Pennsylvania 15230
Dear Mr. Eicheldinger:
We have reviewed your revision 2 to the Westinghouse 7300 series Process Control Systems (PCS) noise test report. From our evaluation of this revision we have determined that our concerns, expressed in our evaluation of this report, have been adequately resolved.
This letter, in conjunction with my letter to you dated January 19, 1977, expresses our acceptance of the noise report. The staff considers that this noise report (now identified as WCAP 8892) provides justification that the objectives of IEEE Standard 279-197 1 8 Regulatory Guide 1.75 will be satisfied for, the 7300 PCS.
Sincerely,
-Pcs~.-S4 Robert LZ'Tedesco Assi stant Director for Plant Systems Divis'ion of Systems Safety, NRR
I Attachment 3 to NLS-87-258 EXCERPTS FROM: WCAP-8892A "WESTINGHOUSE 7300 SERIES PROCESS CONTROL SYSTEM NOISE TEST" DATED JUNE 1977 (5340SOC/bmc )
~
APPENDIX D TEST ARRANGEMENTS - BLOCK DIAGRAMS
c N>(ST hod4cc Avv~N<+
+c g~iaPAt
(. C oapT'Roe GiI Si<$ ) COaSa)m C. fiOC$ g R Kc og.OPRa Pg.o'tB c.'T I aid
< +s~s L~)
tJLIC,at-gg PL-RUT ~] QVvg1 pk Q P 1 & L6 ~AD PLJTSQ Tc=07 PP I Hy QAgi~g PC g CP hid2u'I Caela) I-RoH RtpQY OF'ARDS
~~~q +4<iu-O CcOPc 4 PBCOkbcg, ALL X5pL-A~sc.1 HOAJ I'foLI~cj VIA KgA Liig~tc.
C.oaSAlCCT< b,
(<) Mk)T ksJAL CAiLIQBAJr TFm,zg~iou pR ~ C r R~iu4~ C Cases Z~czs)
(6) C go I.~5 Yo Yc,Res> A.iS 4 CrtRL< 3 pCgg PRoYi CV i oa) 0 CuwVQo 4 CA@I-~4 iS >>>I-~4 3 4$ 87 <eZ FoK g PPRP K] ~Q~~ I 6f'Pkoal HAT'~i- C 2n 4w.
9J PR A Se=
Mxa.-d - RAMbcg: 5 KV
go~yA)gs $ ~dkkC a)T4 P pp<<~ TO V~s Y TC&.<<Q C
~~gW saP AL
( Q'ygy~I C,ASH@) CO@)a B 4'Tioal i R Kc.uk,b~R5, Pkorc C:rI o0 C +B~S Waged,<BAg. PL-ALlT'I~LI~A~o+
Q W I W a.h, ~M Mi Sg PC g CA i3I4~<'I Tc $T Po I <'Y CA@a.Fg CCeaI;) FIZog FltpalY Op'PLCP5 5UH~ CIA<II-I-OCmPc= 4 E~<OEOCg
~S tA A< ~Inc~ HOW) I YPR.I~Cg VIA KIKIII AVoR.
5Iac.OVuM reA Pkc W EbgE CohtoCil PA. Z,m CARd W IE (I) Muv~~pu*c can <u~wT 7 ~~~Mwmsoa +R<+ C~~<~i~4~ ~ <<+<< >>+<sf
(~) Cgp~es Wo ~c=a~,~~~5 4 C~aL~ 3-Ack-s
}- Ru<C CVI e& f CuRIVRa I CAR I ~5 G O~bL~4 W~OCl &ma FOII'4 API'Rc XI~AVeI-8>>++.
PPao<(Havetx 2o 4t=.
pgAbc X
] I K VA4, 9 C o VA C, 5 > P 0A.C-> lb <6 C- '4 'jb ~c iA+P +C, >C. g~I +y cN
C APPENDIX G p~ for aO Phase I- 118 VAC This test was performed by imposing 118 VAC on the isolator output wiring in channel 422. (Specifically TY-422B, the overpower AT setpoint isolator.)
The isolator output wiring was disconnected and the fault applied to con-ductors 85 and 86 in cable f/4 which was approximately 40 feet long. All other wiring was exactly in place. With the 118 VAC present on the con-trol cable (isolator output), the Pre-.test was repeated, taking all recordings and monitoring all points on the oscilloscope and noting all comparator trip points.
The test voltage was also randomly switched on and off and 'all Pre-Test steps repeated.
This test" verified that 118 VAC applied on the control side wiring did not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to this wiring being
.,in close proximity to each other.
6-1
jj77/cj/rnE&7 3+~
P+- gg-AS+
APPENDIX H
]~ SoFM Phase I- 460 VAC This test was performed by imposing 460 VAC on the isolatoz output wiring in channel 422. (Specifically TY-4223, the overpower 4T setpoint isolator.)
The isolator output wiring was disconnected and the fault applied to con-ductors 85 and 86 in cable 84 which was approximately 40 feet long. All other wiring was exactly in place. Pith the 460 VAC present on the con-tzol cable (isolator output), the Pre-Test was repeated, takin'g all recordings and monitoring all points on the oscar.loscope and noting all comparatoz trip points.
The test voltage was also randomly switched on and off and all Pre-Test st'ep's repeated.
This test verified that 460 VAC applied on the control side wizing did not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to'his wiring being in close proximity to each other.
gQgcP~z+ g 1>
PV- b7-K8 APPENDIX J
~r" &
Phase I- 550 VAC This test was performed by imposing 550 VAC on the isolator output wiring in channel 422. (Specifically TY-422B, the overpower AT setpoint isolator).,
The isolator output wiring was disconnected and the fault applied to con-dGctors 85 and 86 in cable 84 which was approximately 40 feet long. All other wiring was exactly in place. With the 550 VAC present on the con-trol cable (isolator output), the Pre-Test was repeated, taking all recordings and monitoring all points on the oscilloscope and noting all comparator trip points.
The test voltage was also randomly switched on and off and all Pre-Test steps repeated.
This test verified that 550 VAC applied on the control side wiring did not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to this wiring being in close proximity to each other.
J
APPENDIX K 7o5 80 I- 115 VDC
'hase This test was performed by imposing 115 VDC on the isolator output wiring
.in channel 422. (Specifically TY"422B, the overpower dT setpoint isolator).
The isolator output wiring was disconnected and the fault applied to con-ductors 85 and 86 in cable 84 which was approximately 40 feet long. All other wiring was exactly in place. With the 115 VDC present on the con-trol cable (isolator output), the Pre>>Test was repeated, taking all recordings and monitoring all points on the oscilloscope and noting all comparator trip points.
The test voltage was also randomly switched on and off and all Pre-Test steps repeated.
This test verified that 115 VDC applied on the control side wiring did not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to this wiring being in close proximity to each other.
A'WecAn ~~~f ~ +
/l~- 0+-Pgg APPENDIX L 8 ()r a)0 Phase I- 250 VDC This test was performed by imposing 250 VDC on the isolator output wiring in channel 422. (Specifically TY&22B, the overpower AT setpoint isolator).
The isolator output wiring was disconnected and the fault applied to con-ductors 85 and 86 in cable 84 which was approximately 40 feet long. All other wiring was exactly in place. With the 250 VDC present on the con-trol cable (isolator output), the Pre<<Test was repeated, taking all recordings and monitoring all points on the oscilloscope and noting all comparator trip points.
The test voltage was also randomly switched on and off and all Pre-Test steps repeated.
This test verified that 250 VDC applied on the control side wiring did not cause any degiadation of protection action as a result of wire to wire cross. talk from control to protection wiring due to this wiring being in close proximity to each other.
g11i c//r~f'/~i 3 ~.
pu- >7-Psg APPENDIX N pr g a/~
Phase I 5 KV Antenna
- nis test was performed using a 5 KV noise source whose characteristics are as follows:
Peak Valve:
1/2 Peak Valve: 'u8 KV SEC Frequency: 10 HERTZ Repetion Rate: 100 HERTZ The output wiring from isolator TY-422B was reconnected and all other wiring was exactly in place. An antenna from the 5 KV source was strapped adjacent to the control cables (isolator output) for distance of 40 feet.
Since the protection and control wiring was bundled together for approxi-
~tely 20 feet, the antenna was ad)acent to the protection wiring for 20 feet of its total length of 40 feet which extended into the cabinet.
.4'ith the 5 KV source energized, the Pre-Test was repeated taking all recordings and monitoring all points on the oscilloscope and noting all comparator trip points, This test was repeated with the antenna ad)acent to the control cabling only (isolator output) and all Pre-Test steps repeated.
This test verified. that a 5 KV noise source as previously described, ad)acent to control side wiring (in addition'to being adjacent to Pro-tection wiring) did not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to this wiring being in close proximity to each other.
pg Jd ~F~
APPE.'H)IX N Phase I- 1 A.'2 AC
- This test was performed by imposing 1 A~P on the isolator output wiring in channel 422. (Specifically TY-4223, the overpower hT setpoint isolator.)
The isolator output wiring was disconnected and the fault applied to con-ductors 45 and 86 in cable N which was approximately 40 feet long. All other wiring was exactly in place. Nith the 1 AMP present on the con-trol cable (isolator output), the Pre-Test was repeated, taking all recordings and monitoring all points on the oscilloscope and noting all conparator trip points.
The test current was also randomly switched on and off and all Pre-Test steps repeated.
This test verifie'd that 1 AMP applied on the control side wiring did not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to this wiring being in close proximity to each other.
- The current flow of 1 AMP was established using a 100 OHM resistor
. and 118 UAC.
gpggr j/mrn7j 3 5o pa-87-sSF Jg. Jg .FP~
APPmnrX P Phase I<< Random Noise This test vas performed using a random noise generator whose a c er-characte-isti cs are created via a RC netvork producing a ringing type of noise.
The output wiring from isolator TY-422B was reconnected and all other viring was exactly in place, An antenna from the random noise source was strapped adjacent to the control cables (isolator output) for a stance of 40 feet. Since the protection and control viring was bundled dista together for approximately 20 feet, the antenna vas adjacent to the pro-tection wiring for 20 feet of its total length of 40 fee t whic h extende d into the cabinet.
With the random noise generator energized, the Pre-Test was repeated taking all recordings and 'monitoring all points on the oscilloscope and noting all comparator trip points.
This test was repeated with the antenna adjacent to the control cabling only and all Pre-Test steps repeated.
This test verified that the random noise source as previous1y described, adjacent to control side wiring (in addition to being adjacent to Pro-tection wiring) did not cause any degradation of protection action as a result of wire to vire cross talk from control to protection wiring due to this wiring being in close proximity to each other.
Phase I- MIL-K-19900B These tests were run in accordance with the edited version of MIL-N-19900B-Pazagraph 4.6.11. With all viring in place and all isolators connected, these tests vere run with a 40 foot antenna cable in contact with iso1ated output cable (control cable) of channel 422. As specified- in the MIL-N Test, tvo noise sources were used. One vas a 3 henry, 500 ohm inductance sw'tched on and off of a 115 VDC rectified power supply and the other vas a 10 millihenry, 2 ohm inductance svitched on and off of a 115 VAC supply. Both noise sources used the same VAC supply that supplies the protection instrumentation inside the cab&et.
With. the fizst noise source energized, the Pre-Test was repeated taking all recordings and monitoring all points on tha oscilloscape and noting all comparatoz trip points.
The same procedure was followed using the second MIL-N noise source.
This test verified that the MIL-H-199008 noise sources as previously described, contacting control side vizing (in addition to contacting thePzotection wiring) did not cause any degradation of protection action as a result of wire to wire cross talk from contxol to protection wiring due to this wiring being in close proxim5.ty to each other.
APPENDIX R Phase I- DC Rela This test was performed by disconnecti TY-422B and connecting into this w g o relay coil. All other y coil as connected t r coil being switched on f an d off takin ak a 11 ay di d i or ing all p ointstheon the oscilloscope and notin g all comparator trip points.
This test verified thathat any noise generatede b y the switching on and n o ff did i
of a 120 VDC relay directly n th e control si a on o protection ac output re cross talk from ontrol to r to wir s w ring 1 imi y to each other.
AriwcPms~< 8 r' p~- 87-858 APPENDIX 5 Phase I- '.!isc. Tests A series of tests vere conducted on some of the spare conductors in the control pre-fab cables. A test fault of 580 VAC was used, first constantly applied and then randomly switched on and off. The Pre-Test "as repeated, taking all recordings and monitoring all points. A total c' spare wire combinations vas tested (18 test runs).
In addition, a 118 VAC relay coil was used as described in .-pendix R.
These tests verified that, faults applied to spare control cable conduc-tors nor the noise generated by a 118 VAC relay coil directly in the control wiring (isolator output) did not cause any degradation of pro-tection action as a result of wire to wire cross talk from control to protection wiring due to this viring being in close proximity to each other.
gffirjlp&J7 3 76 P8- gi- ~~8'g=
APPENDIX U Js vt M Phase II - Triac Out ut of Co arator A series of tests were performed on the printed circuit board card con-taining the triac stage used for certain control output applications of the 7300 series comparator housed in the protection cabinet. With the device connected in the circuit, all wiring exactly in place, the fol-lowing test faults were individually applied (See Appendix D for applica-tion of test faults):
118 VAC>> 208 VAC>> 460 VAC>> 125 VDC>> 250 VDC>>
580 VAC, SHORT With each test fault applied to the control cable (isolator output),
the Pre-Test was repeated, taking all recordings and monitoring all points on the oscilloscope and noting all comparator trip points.
These tests verified that the identified fault voltages applied to the control side wiring (isolator output) did not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to this wiring being in close proximity to each other. These tests also verified that the sub5ect device prevented any protection system degradation by preventing the fault from propagating through the electronics or to any adjacent circuitry.
~ ~
APPEhDIX V Phase II Rela Out ut of Co arator A series of tests were performed on the printed circuit board card con-taining the relay stage used for certain control output applications of the 7300 series comparator housed in the protection cabinet. With the device connected in the circuit, all wiring exactly in place, the fol-lowing test faults were individually applied (See Appendix D for applica-tion of test faults):
118 VAC, 125 VDC, 250 VDC, 580 VAC, SHORT With each test fault applied to the control cable (isolator output),
the Pre-Test was repeated, taking all. recordings and monitoring all points on the oscilloscope and noting all comparator trip points.
These tests verified that the identified fault voltages applied to the control side wiring (isolator output) did not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to this wiring being in close proximity to each other. These tests also verified that the subject device prevented any protection system degradation by preventing the fault from>propagating through the electronics.
These tests did however surface a problem due to solder splatter from the faulted device onto ad)acent printed circuit cards when 125 VDC and 580 VAC faults were applied. To rectify this situation a circuit modi-fication was made (a fuse was added to the control side circuit ~ see Section D ) and the resulting circuit configuration bench tested at all-fault voltages (see Section.D) ~ These bench tests Verified that the modification prevents the fault from propogating via solder splatter onto any adjacent circuitry thus degradation of'protectian action does not occuro
pygmy yFAO APPE:iDIX !i Phase II - Power Sup lv i.'ith Isolated Out ut A series of tests were performed on the sub)ect isolator with the isola-cr connected in the circuit and all other wiring exactly in place.
Tte output stage of this isolator is identical to the Voltage to Voltage isolator, the tests of which are documented in Appendix Y. The follow-
'ng test faults were individually applied (See Appendix D for application of test faults):
118VAC, 208VAC, 460VAC, 125VDC, 250VDC, 580VAC, SHORT Vith each test fault applied to the control cables (isolator output),
the Pre-Test was repeated, taking all recordings'nd monitoring all points on the oscilloscope and noting all comparator trip points.
These tests verified that the identified fault voltages applied to the control side wiring (isolator output) de not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to this wiring being in close proximity to each other. These tests also verifi6d that the sub)ect device prevented any protection system degradation by preventing the fault from propagat-ing through the electronics or to any adjacent circuitry,
t APPEaDLX Z Phase II - Volta e to Current Isolator A series of tests were performed on the subject isolator with the isola-tor connected in the circuit and all other wiring exactly in place.
The following test faults were individually applied (See Appendix D for app'ication of test faults):
118VAC, 208VAC, 460VAC, 125VDC, 250%)C, 580VAC, SHORT With each test fault applied to the control cables (isolator output),
the Pre-Test was repeated, taking all recordings and monitoring all .
points on the oscilloscope, and noting all comparator trip points.
These tests verified that the identified fault voltages applied to the control side wiring (isolator output) did not cause any degradation of protection .system action as a result of wire to wire cross ta1k from control to protection wiring due to this wiring being in close proxi-mity to each other. The tests also verified that the subject device prevented any protection system degradation by preventing the fault from propagating through the electronics, These tests did however surface a problem due to solder splatter from the faulted device onto adjacent printed circuit cards when 118VAC, 208VAC, and 580VAC faults were applied. To rectify this situation a circuit modification was made (change one diode to a resister - See Section 0 ) and the resulting circuit configuration bench tested at all fault voltages (See Section D). These bench tests verified that the modification prevents the fault from propagating via solder splatter onto any adjacent circuitry thus degradation of protective action does not occur.
R C(618~~ go APPE!iDIX 'K Phase 'II - Volta e to Voltage Isolator A series of tests were performed on the sub)ect isolator with the isola-tor connected in the circuit and all other wiring exactly in place.
The output stage of this isolator is identical to the Power Supply Mith Isolated Output Isolator, the tests of which are documented in Appendix V. The following test faults vere individually applied (See Appendix D for application of test faults):
1 18UAC ~ 208VAC ~ 460VAC ~ 125VDC ~ 250VDC ~ 580VAC ~ SHORT Wi.th each test fault applied to the control cables (isolator output),
the Pre-Test was repeated, taking all recordings and monitoring all points on the oscilloscope and noting all comparator trip points.
These tests verified that the identified fault voltages applied to the control side wiring (isolator output) did not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to this wiring being in close proximity to each other. These tests also verified that the sub)ect device prevented any protection system degradation by preventing the fault from propagat-ing through the electronics or to any ad)acent circuitry.
APPRJDIZ Z Phase II - Ca"inet Power Su clv Failure Detection Circuit A series of tests were performed on the printed circuit board card con-taing the relay stage used for the sub'ect function and housed in the protect'on cabinets. Vith all wiring exactly in place, the device connected in the circuit, the following test faults were individually applied (See Appendix D for application of test faults):
250VDC, 580VAC, SHORT Lith each test fault applied to the control cables (isolator output),
the Pre-Test was repeated, taking all recordings and monitoring all points on the oscilloscope and noting all comparator trip points, These tests verified that the identified fault voltages applied to the control side wiring '(isolator output) did not cause any degradation of protection action as a result of wire to wire cross talk from control to protection wiring due to this wiring being in close proximity to each other.. These tests also verified that the subject device pre-vented any protection system degradation by preventing the fault from propagating through the electronics or to any ad)acent circuitry,
C~
pQ
15.3 CONDITION III - INFREQUENT FAULTS By definition, Condition III occurrences are faults which may occur very infrequently during the life of the plant. They will be accommodated with the failure of only a small fraction of the fuel rods although sufficient fuel damage. might occur to preclude resumption of the operation for a considerable outage time. The release of radioactivity will not be sufficient to interrupt or restrict public use of those areas beyond the exclusion radius. A Condition III fault will not, by itself, generate a Condition IV faul.t or result in a consequential loss of function of the reactor coolant system or containment barriers'. For the purpose of this report the following faults have been grouped into this category:
- 1. Loss of reactor coolant, from small ruptured pipes or from cracks in large pipes, which actuates the emergency core cooling system.
- 2. Complete loss of forced reactor coolant flow.
- 3. Single rod cluster control assembly withdrawal at full power.
Each of these infrequent faults are analyzed in this section. In general, each analysis includes an identification of causes and description of the accident, an analysis of effects and consequences, a presentation of results, and relevant conclusions.
The time sequence of events during applicable Condition III faults 1 and 2 above is shown in Table 15.3-1.
1 579 v:1D/110208 15.3-1
Us
'jg
~
Yf a+
'L'
~
>>I
15.3.2 Com lete Loss of Forced Reactor Coolant Flow 15.3.2. 1 Identification of Causes and Accident Oescri tion A complete loss of forced reactor coolant flow may result from a simultaneous loss of electrical supplies to all reactor coolant pumps. If the reactor is at power at the time of the accident, the immediate effect of a loss of forced coolant flow is a rapid increase in the coolant temperature. This increase could result in departure from nucleate boiling (ONB) with subsequent fuel damage if the reactor were not tripped promptly. The following provide necessary protection against a loss of coolant flow accident:
(1) Undervoltage or underfrequency on reactor coolant pump power supply buses; (2) Low reactor coolant loop flow.
The reactor trip on reactor coolant pump bus undervoltage is provided .to protect against conditions that can cause a loss of voltage to all reactor coolant pumps, i.e., station blackout. The reactor trip on reactor coolant pump underfrequency is. provided to open the reactor coolant pump breakers and trip the reactor for an underfrequency condition, resulting from frequency disturbances on the major power grid. The trip disengages the reactor coolant pumps from the power grid so that the pumps'lywheel kinetic energy is available for full coastdown. Both trips are'blocked below Permissive 7.
The reactor trip on low primary coolant loop flow is provided to protect against loss-of-flow conditions that affect only one reactor coolant loop. It also serves as a backup to the undervoltage and underfrequency trips. This function is generated by two-out-of-three low-flow signals per reactor coolant loop. Above Permissive 8, low flow in any loop will actuate a reactor trip.
Between Permissive 7 and Permissive 8, low-flow in any two loops will actuate a reactor trip.
4579v:1D/110208 '5.3-2
~ C ~
"t 1
~ \
(a 0
Normal power for each pump is supplied through individual busses connected to the isolated phase bus. duct between the generator circuit breaker and the main transformer. Faults in the substation may cause a trip'f the main transformer high side circuit breaker leaving .the generator to supply power to the reactor coolant pumps. When a generator circuit breaker trip occurs because of electrical faults, the pumps are automatically transferred to an alternate power supply and the pumps will continue to supply coolant flow to the core. Following any turbine trip where there are no. electrical faults, the generator circuit breaker is tripped and the reactor coolant pumps remain connected to the network through the transformer high side breaker.
Continuity of power to the pump buses is achieved without motoring the generator since means are provided to isolate the generator without isolating the pump buses from the external power lines (e.g., a generator output breaker is provided as well as a station output breaker).
15.3.2.2 Anal sis of Effects and Conse uences This transient is analyzed by three digital computer codes. First, the LOFTRAN code (1) is used to calculate the loop and core flow during the
~
transient. The LOFTRAN code is also used to calculate the time of reactor trip based on the calculated flows and the nuclear power transient following reactor trip. The FACTRAN code is then used to calculate the heat flux THING code (3,6) 's transient based on the nuclear power and flow from LOFTRAN.. Finally, the used to calculate the minimum DNBR during the transient based on the heat flux from FACTRAN and flow from LOFTRAN. The transients presented represent the minimum of the typical and thimble cells for Standard and VANTAGE 5 fuel.
The following case has been analyzed:
All loops operating, all loops coasting down.
The method of analysis and the assumptions made regarding initial operating conditions and reactivity coefficients are identical to those discussed in Section 15.2.5, except that following the loss of supply to all pumps at power, a reactor trip is actuated by either bus undervoltage or bus underfrequency.
1579v:1D/110208 15.3-3
15.3.2.3 Results The calculated sequence of events is shown in Table 15.3-1. Figures 15.3.2-1 and 15.3.2-2 show the flow coastdown, nuclear power and heat flux transients and minimum DNBR for the limiting complete loss of flow event. The reactor is assumed to trip on the undervoltage signal. The ONBR versus time plot represents the limiting cell for the three-loop coastdown.
15.3.2.4 Conclusions The analysis performed has demonstrated that for the complete loss of forced reactor coolant flow, the ONBR does not decrease below the safety analysis limit values during the transient, and thus, no core safety limit is violated.
1579v:1D/110208 15.3-4
}
g'ip
'4
- 9
15.3.3 Sin le Rod Cluster Control Assembl Withdrawal at Full Power 15.3.3. 1 Identification of Causes and Accident Oescri tion No single electrical or mechanical failure in the rod control system could cause the accidental withdrawal of a single RCCA from the inserted bank at full power operation. .The operator could deliberately withdraw a single RCCA in the control bank; this feature is necessary in order to retrieve an assembly should one be accidentally dropped. In the extremely unlikely event of simultaneous electrical failures that could result in single RCCA withdrawal, rod deviation and rod control urgent failure would both be displayed on the plant annunciator, and the rod position indicators would indicate the relative positions of the assemblies in the bank. The urgent failure alarm also inhibits automatic rod motion in the group in which it occurs. Withdrawal of a single RCCA by operator action, whether deliberate or by a combination of errors, would result in activation of the same alarm and the same visual indications.
Each bank of RCCAs in the system is divided into two groups of four mechanisms each. 'he rods comprising a group operate in parallel through multiplexing thyristors. The two groups in a bank move sequentially such that the first group is always within one step of the second group in the bank. A definite schedule of actuation and deactuation of the stationary gripper, movable gripper, and lift coils of a mechanism is required to withdraw .the RCCA attached to the mechanism. Since the four stationary grippers, movable grippers, and lift coils associated with the four RCCAs of a rod group are driven in parallel, any single failure that would cause rod withdrawal would affect a minimum of one group, or four RCCAs. Mechanical failures are either in the direction of insertion or immobility.
In the unlikely event of multiple failures that result in continuous withdrawal of a single RCCA, it is not possible, in all cases, to provide assurance of automatic reactor trip so that core safety limits are not violated. Withdrawal of a single RCCA results in both positive reactivity insertion tending to increase core power, and an increase in local power density in the core area covered by the RCCA.
1579v:1D/110208 15.3-5
0 15.3.3.2 Anal sis of Effects and Conse uences Power distributions within the core are calculated by the TURTLE code based on a macroscopic cross section generated by LEOPARD. The peaking factors calculated by TURTLE are then used by THINC to calculate the minimum DNH for the event. The plant was analyzed for the case of the worst rod withdrawn from Hank D inserted at the insertion limit, with the reactor'nitially at full power, 15.3.3.3 Results Two cases have been considered as follows:
(1) If the reactor is in the automatic control mode, withdrawal of a single RCCA will result in the immobility of the other RCCAs in the controlling bank. The transient will then proceed in the same manner as Case 2 described below. For such cases as above, a trip will ultimately ensue, although not sufficiently fast in all cases to prevent a minimum DNHR in the core of less than the safety limit.
(2) If the reactor is in the manual control mode, continuous wi.thdrawal of a single RCCA results in both an increase in core power and coolant temperature, and an increase in the local hot channel factor in the area of the failed RCCA. In terms of the overall system response, this case is similar to those presented in .Section 15.2; however, the increased local power peaking in the area of the withdrawn RCCA results in lower minimum DNHR than for the withdrawn bank cases. Depending on initial bank insertion and location of the withdrawn RCCA, automatic reactor trip may not occur sufficiently fast to prevent the minimum core DNHR from falling below the safety limit value. Evaluation of this case at the power and coolant condition at which overtemperature LT trip would be expected to trip the plant shows that an upper limit for the number of rods with a DNHR less than the safety limit value is 5%.
1579v:1D/11020B 15.3-6
15.3.3.4 Conclusions For the case of one RCCA fully withdrawn, with the reactor in'ither the automatic or manual control mode and initially operating at full power with Hank D at the insertion limit, an upper bound of the number of fuel rods experiencing DNBR less than the design limit is 5% or less of the total fuel rods in the core.
For both cases discussed, the indicators and alarms mentioned would function to alert the operator to the malfunction before ONS could occur. For Case 2 discussed above, the insertion limit alarms ( low and low-low alarms) would also serve in this regard.
1579v:1D/110208 15.3-7
t
~%
15.3.4
~ ~ References
- 1. T. M. T. Burnett, et. al., LOFTRAN Code Descri tion, WCAP-7907-P-A (Proprietary), WCAP-7907-A (Non-Proprietary), April 1984.
- 2. H. G. Hargrove, FACTRAN-A Fortran-IV Code for Thermal Transients in a U02 Fuel Rod, WCAP-7908, June 1972.
- 3. Hochreiter, L. E., Chelemer, H. and Chu, P. T., "THING-IV An Improved Program for Thermal-Hydraulic Analysis of Rod Bundle Cores," WCAP-7956, June, 1973.
- 4. R. F. Barry and S. Altomare, The TURTLE 24.0 Diffusion De letion Code, MCAP-7213-P-A (Proprietary), WCAP-7758-A (Non-Proprietary), January 1975.
- 5. R. F. Barry, LEOPARD-A S ectrum De endent Non-S atial De letion Code for the IBM-7904, MCAP-3269-26, September 1963.
- 6. Hochrieter, L. E., and Chelemer, H., "Application of the THINC IV Program to PMR Design," WCAP-8054 (Proprietary), October, 1973, and WCAP-8195 (Non-Proprietary), September, 1973.
1579 v:1D/110208 15.3-8
TABLE 15. 3" 1 TIME SEQUENCE OF EVENTS FOR CONDITION III EVENTS Accident Event Time sec Complete Loss of Forced Reactor Coolant Flow: All All loops operating, all pumps coasting down Coastdown begins 0.0 Rod .motion begins 1.5 Minimum DNBR occurs 3.4 1579v:10/110208 15.3-9
C)
.4
~ 2 8.
- 8. 1 ~ 2. 3. 4 ~ 5. 6 ~ 7. 8. 'l. 18 ~
1.2 5R I.
ID
~ B
.6
.4
~ 2
- 8. 1. 2. 3 4. 5. 6. 7. B.
~
R. 18.
TINE { SEC)
Shearon Harris Figure 15.3.2-1 All Loops Operating All Loops .Coasting Down Vessel F'low and Heat Flux vs. Time
CL le C) cC ~ 4
.2 8 ~ 1. 2. 5. 4 ~ 5. 6. 7. B. 1. 18
'A t7
-0 2 3 TlHE (SEC)
Shearon Harris Figure 15.3.2-2 All Loops Operating All Loops Coasting Down Nuclear Power and DNBR vs. Time
2683.
2588.
2488.
2388.
2288.
218~.
2888.
- l. 2. 3. 4. S. 6. 7. e. 9. 18.
Time (sec).
Shearon Harris Figure 15.3.2-3 All Loops Operating All Loops Coasting Down Pressurizer Pressure vs. Time
4~
~1 t
4 P~
15.4 CONDITION IV - LIMITING FAULTS Condition IY occurrences are faults that are not expected to take place, but are postulated because the'ir consequences would include the potential for the release of significant amounts of radioactive material. These are the most drastic occurrences 'that must be designed against and represent limiting design cases. Condition IV faults shall not cause a fission product release to the environment resulting in an undue risk to public health and safety in excess of guideline values of 10 CFR 100. A single Condition IY fault shall not cause a consequential loss of required functions of systems needed to cope with the fault including those of the emergency core cooling system (ECCS) and the containment. For the purposes of this report the following faults have been classified in this categor'y:
(1) Major rupture of pipes containing reactor coolant up to and including double-ended rupture of the largest pipe in the reactor coolant system (RCS), i.e., loss-of-coolant accident (LOCA);
(2) Major secondary system pipe ruptures (3) Steam generator tube rupture; (4) Single reactor coolant pump (RCP) locked rotor; (5) Rupture of a control rod mechanism housing (rod cluster control assembly [RCCAj ejection).
Each of these five 1'imiting faults is analyzed in Section 15.4. In general, each analysis includes an identification of causes and description of the accident, an analysis'f effects and consequences, a presentation of results, and relevant conclusions.
1576v:1D/110788
lg El l ~ )' P I I I
15.4.2 Ma or Secondar S stem Pi e Ru ture Two major secondary system pipe ruptures are analyzed in this section: rupture of a main steam line and rupture of a main feedwater pipe. The time sequence of events for each of these events is provided in Table 15.4-8.
15.4.2. 1 Ru ture of a Main Steam Line 15.4.2.1. 1 Identification of Causes and Accident'escri tion The steam release arising from a rupture of a main steam pipe would result in an initial increase in steam flow that decreases during the accident as the steam pressure falls. The energy removal from the RCS causes a reduction of coolant temperature and pressure. In the presence of a negative moderator temperature coefficient, the cooldown results in a reduction of core shutdown margin. If the most reactive RCCA is assumed stuck in its fully withdrawn position after reactor trip, there is an increased possib'i lity that the core will become critical and return to power. A return to power following a steam
,pipe rupture is a potential problem mainly because of the high power peaking factors that exist assuming the most reactive RCCA to be stuck in its fully withdrawn position. The core is ultimately shut down by the boric acid injection delivered by the SIS.
The'nalysis of a main steam pipe rupture is performed to demonstrate that the following criteria are satisfied:
( 1) Assuming a stuck RCCA, with or without offsite power, and assuming a single failure in the engineered safety features (ESF), the core remains in place and intact. Radiation doses do not exceed the guidelines of .10CFR100.
'2)
Energy release to containment from the worst steam pipe break does not cause failure 'of the containment structure.
Although ONH and possible cladding perforation following a steam pipe rupture are not necessarily unacceptable, the following analysis, in fact, shows that no ONH occurs for any rupture assuming the most reactive assembly stuck in its fully withdrawn position.
1576v:1D/110788 15.4-2
- ~
sr
The following functions provide the necessary protection against a steam pipe rupture:
(1) SIS actuation from any of the following:
(a) Two-out-of-three low pressurizer pressure signals',
(b) Two-out-of-three low steam line pressure signals in any one main steam line; (c) Two-out-of-three high-1 containment pressure signals.
(2) The overpower reactor trips (neutron flux and LT), low pressurizer reactor trip, and the reactor trip occurring in conjunction'ressure with receipt of the safety injection signal.
(3) Redundant isolation of the main feedwater lines: sustained high feedwater flow would cause additional cooldown. Therefore, in addition to the normal control action which will close the main feedwater valves following reactor trip, a safety injection signal will rapidly close all feedwater control valves and back up feedwater isolation valves, trip the main feedwater pumps, and close the feedwater pump discharge valves, (4) Trip of the fast-acting main steam line isolation valves (designed to close in less than 5 seconds) on:
(a) High-2 containment pressure.
(b) Safety injection system actuation derived from two-out-of-three low steam line pressure signals in any one main. steam line (above Permissive P-11).
(c) High negative steam pressure rate indication from two out of three signals in any one main steam line (below Permissive P-ll).
1576v:1D/110788 15.4-3
,P i l5
For breaks downstream of the isolation valves, closure of all valves would completely terminate the blowdown. For any break, in any location, no more than one steam generator would blow down even if one of the isolation valves fails to close. A description of steam line isolation is included in Chapter 10 of the FSAR.
Flow restrictors are installed in the steam generator outlet nozzle and are an integral part of the steam generator. The effective throat area of the nozzles is 1.4 square ft., which is considerably less than the main steam pipe area; thus, the nozzles also serve to limit the maximum steam flow for a break at any location.
15.4.2. 1.2 Anal sis of Effects and Conse uences The analysis of the steam pipe rupture has been'erformed to determine:
(1) The core heat flux and RCS temperature and pressure resulting from the cooldown following the steam line break. The LOFTRAN code has been used.
(2) The thermal and hydraulic behavior of the core following a steam line break. A detailed thermal and hydraulic digital-computer code, THINC (3,' has been used to determine if DNB occurs for the core 17) condit'ions computed in (1) above.
The following conditions were assumed to exist at the t.ime of a main steam line break accident.
(1) End of life (EOL) shutdown margin at no-load, equilibrium xenon conditions, and the most reactive assembly stuck, in its ful'ly withdrawn position. Operation of the control rod banks during core burnup is restricted in such a way that addition of positive reactivity in a steam line break accident will not lead to a more adverse condition than the case analyzed.
1576v:1O/110788 15. 4-4
4%)
I 4.
~
-0 Q
(2) The negative moderator coefficient corresponding to the EOL rodded I
core with the most reacti've rod in the Fully withdrawn position. The variation of the coefficient with temperature and pressure has been 1ncluded. The k e ff versus temperature at 1150 psia corresponding to the negative moderator temperature coefficient plus the Doppler temperature effect used is shown on Figure 15.2.13-1. The effect of power generation in the core on overall reactivity is shown on Figure 15.4.2-1.
The core properties associated with the sector nearest the affected steam generator and those associated with the remaining sector were conservatively combined to obtain average core properties for reactivity feedback calculations. Further, it was conservatively assumed that the core power distribution was uniform. These two conditions cause underprediction of the reactivity feedback in the high-power region near the stuck rod. To verify the conservatism of this method, the reactivity as well as the power distribution was checked. These core analyses considered the Doppler reactivity from the high fuel temperature near the stuck RCCA, moderator feedback from the high water enthalpy near the stuck RCCA, power r'edistribution and nonuniform core inlet temperature effects. For cases in which steam generation occurs in the high flux regions of the core; the effect of void formation was also included. It was determined that the reactivity employed in the kinetics analysis was always larger than the true reactivity verifying conservatism; i.e.', underprediction of negative reactivity feedback from power generation.
(3) Hinimum capability for injection of high concentration boric acid (2000 ppm) solution corresponding to the most restrictive single failure in the SIS. The characteristics of the injection unit used are shown on Figure 15.2.13-2. This corresponds to the flow delivered by one charging pump delivering its full flow to the cold leg header.
No credit has been taken for the low concentration of boric acid that 1576v:10/110788 15.4-5
must be swept from the safety injection lines downstream of the refueling water storage tank (Rh'ST) isolation valves prior to the delivery of highly concentrated, boric acid to the reactor coolant loops. This effect has been-allowed for in the analysis. The modeling of the SIS in LOFTRAN is described in Reference 2.
For the case where offsite power is assumed, the sequence of events in the SIS is the following: After the generation of the safety injection signal (appropriate delays for instrumentation, logic, and signal transport included), the appropriate valves begin to operate and the high-head injection pump starts. In 27 seconds, the valves are assumed to be in their final position and the pump is assumed to be at full speed. The volume containing the low concentration borated water is swept before the 2000 ppm boron reaches the core. This delay is inherently included in the modeling. In cases where offsite power is not available, an additional 10-second delay is assumed to be required to start the diesels and .to load the necessary safety injection equipment onto them. That is, after a total of 37 seconds following an SIS signal, the SIS is assumed to be capable of delivering flow to the RCS.
(4) Two cases have been considered in determining the core, power and RCS transients:
(a) Complete severance of a pipe with the plant initially at no-load conditions, full reactor coolant flow with offsite power available, (b) Complete severance of a pipe with the plant initially at no-load conditions with offsite power unavailable.
(5) Power peaking factors corresponding to one stuck.RCCA and nonuniform core inlet coolant temperatures are determined at EOL. The coldest core inlet temperatures are assumed to occur in the sector with the stuck rod. The power peaking factors account for the effect of the local void in the region of- the stuck control assembly during the 1576v:1D/110788 15.4-6
'1
~ e
%+I
~ a3
return to power phase following the steam line break. This void in conjunction with the large negative moderator coefficient partially offsets the effect of the stuck assembly. The power peaking factors depend on the core power, operating history, temperature, pressure, and flow, and thus are different for each case studied.
8oth cases assume initial hot shutdown conditions at time zero since this represents the most pessimistic initial condition. Should the reactor be just critical or operating at power at the time of a steam line break, the reactor will be tripped by the normal overpower protection system when power level reaches a trip point. Following a trip at power the RCS contains. more stored energy than at no-load, the average coolant temperature is higher than at no-load, and there is appreciable energy stored in the fuel. Thus, the additional stored energy is removed via the cooldown caused by the steam line break before the no-load conditions of RCS temperature and shutdown margin assumed in the analyses are reached. After the additional stored energy has been removed, the cooldown and reactivity insertions proceed in the same manner as in the analysis which assumes no-load condition at time zero.
However, since the initial steam generator water inventory is greates't at no-load, the magnitude and duration of the RCS cooldown are less for steam line breaks occurring at power.
(6) In computing the steam flow during a steam line break, the Moody Curve (4) for fL/D = 0 is used. The Moody Multiplier is 1 with a discharge at dry saturated steam conditions.
(7) Perfect moisture separation in the steam generator is assumed. The assumption leads to conservative results since, in fact, considerable water would be discharged. Hater carryover would reduce the magnitude of the temperature decrease in the core and the pressure increase in the containment.
15 76v:1D/110788 15.4-7
4
'e4 >
&P
15.4.2.'1.3 Results The results presented are a conservative indication of the events that would occur assuming a steam line rupture since it is postulated that all of the conditions described above, occur simultaneously.
Figures 15.4.2-2 and 15.4.2-3 show the response of pertinent system parameters following a main steam pipe rupture. Offsite power is assumed to be available such that full reactor coolant flow exists. The transient shown assumes an uncontrolled steam release from only one steam generator.
As can be seen, the core attains criticality with RCCAs inserted (with the design shutdown assuming one stuck RCCA) before boric acid solution at 2000 ppm enters the RCS from the SIS which is drawing from the RWST. The delay time consists of the time to receive and actuate the safety injection signal and the time to completely open valve trains in the safety injection lines.
The safety injection pumps are then ready to deliver flow. At this stage, a further delay is incurred before 2000 ppm boron solution can be injected to the RCS due to the low concentration solution being swept from the safety injection lines; Should a partial loss of offsite power occur such that power is lost to the ESF functions while the reactor coolant pumps remain in operation, an additional safety injection delay of 10 seconds would occur while the diesel generators startup and the necessary safety injection equipment is loaded onto them. A peak core power well below the nominal full power value is attained.
The calculation assumes the boric acid is mixed with and diluted by the water flowing in the RCS prior to entering the reactor core. The concentration after mixing depends on the relative flowrates in the RCS and the SIS. The variation of mass flowrate in the RCS due to water'ensity changes is incl.uded in the calculation as is the variation of flowrate from the SIS and the accumulator due to changes in the RCS pressure. The SIS flow calculation includes the line losses in the system as well as the pump head curve. The accumulators provide an additional source of borated water after the RCS pressure has decreased to below 600 psia.
1576v:1D/120688 15.4-8
J A
~ C
Should the core be critical at near zero power when the rupture occurs, the initiation of safety injection by low steam line pressure will trip the reactor. Steam release from more than one steam generator wi 11 be prevented by automatic trip of the isolation valves in the steam lines by high
. containment pressure signals, by low steam line pressure signals, or by high negative steam pressurization rate signals. The steam line isolation valves are designed to be fully closed in less than 5 seconds after receipt of closure signal.
Figures 15.4.2-4 and 15.4.2-5 show the responses of the salient parameters for the ease discussed'above with a total loss of offsite power at the time of the rupture. This results in a coastdown of the reactor coolant pumps. In this case, the core power increases at a slower rate. The ability of the emptying steam generator to extract heat from the RCS is reduced by the decreased flow in the RCS.
It should be noted that following a steam line break. only one steam generator blows down. completely. Thus, the remaining steam generators are still available for dissipation of decay heat after the initial transient is over.
In case of a loss of offsite power, this heat is removed to the atmosphere via the steam line safety valves, 15.4.2. 1.4 Conclusion A DNB analysis was performed for the above cases. It was found that the DNB design basis's(I6 met.
1576v:1D/120688 15.4-9
gp 4g
15.4.2.2 Ma 'or Ru ture of a Main Feedwater Pi e 15.4.2.2. 1 Identification of Causes and Accident Descri tion A major feedwater line rupture is defined as a break in a feedwater pipe large.
enough to prevent the addition of sufficient feedwater to the steam generators to maintain shell-side fluid inventory in the steam generators. If the break is postulated in a feedline between the check valve, the forward flush valve, or the reverse flush valve and the steam generator, fluid from the steam generator may also be discharged through the break. (A break upstream of the feedline check valve, or downstream of the forward or reverse flush valves would affect the nuclear steam supply system [NSSS] only as a loss of feedwater. This case is covered by the evaluation in Section 15.2.8.)
Depending on the size of the break and the plant operating conditions at the time of the break, the break could cause either an RCS cooldown (by excessive energy discharge through the break), or an RCS heatup. The potential RCS cooldown resulting from a secondary pipe rupture is evaluated in Section 15.4.2. 1, Rupture of a Main Steam Pipe. Therefore, only the RCS heatup effects are evaluated for.a feedline rupture.
A feedline rupture reduces the ability to remove 'heat generated by the core from the RCS for the following reasons:
(1) Feedwater to the steam generators is reduced. Since feedwater is subcooled, its loss may cause reactor coolant temperatures to increase prior to reactor trip; (2) Liquid in the steam generator may be discharged through the break, and, would then not be available for decay heat removal after trip; (3) The break may be large enough to prevent the addition of any main feedwater after trip.
1576v:1D/110788 15.4-10
/pe 0 'll I
An Auxiliary Feedwater (AFW) system is provided to assure that adequate feedwater will be available such that:
(1) No substantial overpressurization of the reactor coolant system shall occur; and (2) Liquid in the reactor coolant system shall be sufficient to cover the reactor core at all times.
P The following provide the necessary protection against a main feedwater line rupture:
(1) A reactor trip on any of the following conditions:
(a) High pressurizer pressure; (b) Overtemperature. hT; (c) Low-low steam generator water level in any steam generator.;
(d) Low steam generator level plus steam/feedwater flow mismatch in any steam generator; (e) Safety injection signals from any of the following:
- 1. Low steam line pressure,
- 2. High containment pressure (Hi-l),
- 3. High steamline differential pressure.
(Refer to Chapter 7 for a description of the actuation system.)
I 1576v:10/110 78S 15. 4-11
V I a
P, 1 g S'
(2) An AFH system to provide an assured source of feedwater to the steam generators for decay heat removal. (Refer to FSAR Section 10.4.9 for a description of the AFM system.)
15.4.2.2.2 Anal sis of Effects and Conse uences A detailed analysis using the LOFTRAN code is performed in order to determine the plant transient following a feedline ruptur'e. The code describes the plant thermal kinetics, RCS including natural circulation, pressurizer, steam generators, and feedwater system, and computes pertinent variables, including the pressurizer pressure, pressurizer water level, and reactor coolant average temperature.
Major assumptions are:
(1) The plant is initially operating at 102% of the ESF design rating.
(2) Initial reactor coolant average temperature is 5.3'F above the nominal value, and the initial pressurizer pressure is 38 psi above its nominal value.
(3) A conservatively high initial pressurizer level is assumed; initial steam generator water level is at the nominal value plus 10% in the faulted steam generator, and at the nominal value minus 10% in the intact steam generators.
(4) No credit is taken for the pressur'izer power-operated relief valves or pressurizer spray.
(5) No credi't is taken for the high pressurizer pressure reactor trip.
Note': This assumption is made for calculational convenience.
Pressurizer power-operated relief valves and spray could act to delay the high pressure trip. Assumptions 3 and 4 permit evaluation of one hypothetical, limiting case rather than two 1576v:1D/110788 15.4-12
1'fl
<<g4
possible cases: one with a high pressure trip and no pressure control; and one with pressure control but no high pressure trip.
(6) Main feed to all steam generators is assumed to stop at the time the break occurs. (All main feedwater spills out through the break.)
(7) A conservative feedline break discharge quality is assumed prior to the time 'the reactor trip occurs, thereby maximizing the time the trip setpoint is reached. After the trip occurs, a saturated liquid discharge is assumed until all water inventory is discharged from the affected steam generator. This minimize the heat removal capability of the affected steam generator.
(8) Reactor trip is assumed to be initiated when the low-low level trip setpoint in the ruptured steam generator is reached. A low-low level setpoint of 19% narrow range span is assumed.
(9) The worst possible break area which minimizes the steam generator fluid inventory at the time of trip and is assumed maximizes the blowdown discharge rate following the time of trip, and thereby maximizes the resultant heatup of the reactor coolant.
(10) No credit. is taken for heat energy deposited in RCS metal during the RCS heatup.
(ll) No credit is taken for charging or letdown.
(12) Steam generator heat transfer- area is assumed to decrease as the shell-side liquid .inventory decreases.
(13) Conservative core residual heat generation based on long-term operation at the initial power level preceding the trip is assumed. The 1979 ANS 5.1((5)'ecay heat standard plus uncertainty was used for calculation of residual decay heat levels.
1576v:1D/110788 15.4-13
gi
",jg 4 c I 4P Qltt Wg
~ 'r y,l lb
(14) The AFW system is actuated by the low-low steam generator water level signal. For the case with offsite power available, one motor-driven AFW pump is. assumed to deliver 286 gpm to the two intact steam generators before automatic AFW isolation, and 430 gpm the intact steam generators after automatic AFW isolation.
For the case without offsite power available, one motor driven AFH pump is assumed to deliver 215 gpm to one intact steam generator before AFW isolation, and 430 gpm after automatic AFW isolation.
A 61.5 second delay following reactor trip is assumed to allow time for startup of the emergency diesel generators and the AFW pumps. Before the relatively cold (91'F) AFW enters the unaffectd steam generators, additional time is modeled to allow for the purging of 28 cubic feet of hot water contained in the AFW system lines.
15.4.2.2.3 Results Results for two'feedline break cases are presented. Results for a case in which offsite power is assumed to-be available are presented in Section 15.4.2.2.3.1. Results for a case .in which offsite power is assumed, to be lost following reactor trip are presented in Section 15.4.2.2.3.2. The calculated sequence of events for both cases is list'ed in Table 15.4-8.
15.4.2.2.3.1 Feedline Ru ture with Offsite Power Available The system response following a feedwater line rupture, assuming offsite power is available, is presented in Figures 15.4.2-7 through 15.4.2-10. Results presented in Figures 15.4.2-8 and 15.4.2-10 show that pressures in the RCS and main steam system remain below 110% of the respective design pressures.
Pressurizer pressure decreases after reactor trip on low-low steam generator water level due to the reduction of heat input. Following this initial decrease, pressurizer pressure increases to the pressurizer safety valve setpoint. This increase in pressure is the result of coolant expansion caused by the reduction in heat transfer capability in the steam generators. Figure 15.4.2-8 shows that the water volume in the pressurizer increases in response to the heatup, pressurizer water relief begins at 1512 seconds. At approximately 2200 seconds, decay heat generation decreases to a level such 1576v:1 0/110788 15.4-14
1+
4(
II\
i+i t
I y4 L
that the total RCS heat generation (decay heat plus pump heat) is less than AFW heat removal capabi lity, and RCS pressure and temperatur'e begin to decrease.
The results show that the core remains covered at all times and that no boiling occurs in the reactor coolant loops.
15.4.2.2.3.2 Feedline Ru ture Without Offsite Power Available The system response following a feedwater line rupture without offsite power available is similar to the case with,offsite power available. However, as a result of the loss of offsite power (assumed to occur at reactor trip), the reactor coolant pumps coast down. This results in a reduction in total RCS heat generation by the amount produced by pump operation.
The reduction in total RCS heat generation produces a milder transient than in the case where offsite power is available. Results presented in Figures 15.4.2-12 and 15.4.2-14 show that pressure in the RCS and main steam system remain below 110% of the respective design pressures. Pressurizer pressure decreases after reactor trip on low-low steam generator water level due to the reduction of heat input. Following this initial decrease, pressurizer pressure increases to a peak pressure of 2505 psia at 1028 seconds. This increase in pressure is the result of coolant expansion caused by the reduction in heat transfer capability in the steam generators. Figure 15.4.2-12 shows that the water volume in the pressurizer increases in response to the heatup and pressurizer water relief begins at 1024 seconds. At approximately 1400 seconds, decay heat generation decreases to a level less than the AFW heat removal capability, and RCS temperatures begin to decrease.
The results show that the core remains covered at all times, and that no boiling occurs in the Reactor Coolant loops.
15.4.2.2.4 Conclusion Results of the analysis show'hat for the postulated feedline rupture, the assumed AFW system capacity is adequate to remove decay heat, to prevent overpressurizing the RCS, and to prevent uncovering the reactor core.
1576v:10/110788 15.4-15
'l r'X
15.4.4 Sin le Reactor Coolant Pum Locked Rotor 15.4.4. 1 Identification of Causes and Accident Descri tion The accident postulated is an instantaneous seizure of an RCP rotor. Flow through the affected reactor coolant loop is rapidly reduced, leading to an initiation of a reactor trip on a low flow signal.
Following initiation of ihe reactor trip, heat stored in the fuel rods continues to be transferred to the coblant causing the coolant to expand. At the same time, heat transfer to the shell-side of the steam generators is reduced, first because the reduced flow results in a decreased tube-side film coefficient and then because the reactor coolant in the tubes cools down while the shell-side temperature increases (turbine steam flow is reduced to zero I
upon plant trip). The rapid expansion of the coolant in the reactor core, combined with reduced heat transfer in the steam generators causes an insurge into the pressurizer and a pressure increase throughout the RCS. The insurge into the pressurizer compresses the steam volume, actuates the automatic spray system, opens the power-operated relief valves, and opens the pressurizer safety valves in that sequence. The three power-operated relief valves are designed for reliable operation and would be expected to function proper ly during the accident. However, for conservatism, their pressure-reducing effect as well as the pressure-reducing effect of the spray'is.not included in the analysis.
15.4.4.2 Anal sis of Effects and Conse uences Two digital computer codes are used to analyze this transient. The LOFTRAN (2) code is used to calculate the resulting loop and core coolant flow following the pump seizure. The LOFTRAN code is also used to calculate the time of reactor trip, based on the calculated flow, the nuclear power following reactor trip, and to determine the peak pressure. The thermal behavior of the fuel located in the hot channel and at'he core hot spot is investigated using the FACTRAN (6) code, using the core flow and the nuclear power calculated by LOFTRAN. The FACTRAN code includes the use of a film boiling heat transfer coefficient.
1576v:1D/120188 15.4-16
4p
-4 Ip'f t<'l<< ir
'J
The following case is analyzed:
All loops operating, one locked rotor.
At the beginning of the postulated locked rotor accident, i.e., at the time the shaft in one of the RCPs is assumed to seize, the plant is assumed to be operating under the most adverse steady state operating conditions, i.e.,
maximum steady state power level, maximum steady state pressure, minimum (thermal design) flow rate, and maximum steady state coolant average temperature.
Hhen the peak pressure is evaluated, the initial pressure is conservatively estimated as 38 psi above the nominal pressure of 2250 psia, to allow for errors in the pressurizer pressure measurement and control channels. This is done to obtain the highest possible rise in the coolant pressure during the transient. To obtain the maximum pressure in the primary side, conservatively high loop pressure drops are added to the calculated pressurizer pressure.
The pressure response is shown on Figure 15.4.4-1.
The analysis of the Locked Rotor event has considered the effect of a coincident loss of offsite power (see FSAR Section 15.3.3). In addition, the effects of the Reactor Coolant Pump Shaft B'reak event (see 'FSAR Section 15.3.4) have been considered. A single analysis which bounds both the Locked Rotor and the Shaft Break incidents has been performed.
15.4.4.2.1 Evaluation of the P'ressure Transient After pump seizure and reactor trip, the, neutron flux is rapidly reduced by control rod insertion effect. Rod motion is assumed to begin 1 second after the flow in the affected loop reaches 87% of nominal flow. No credit is taken for the pressure-reducing effect of the pressurizer relief valves (PORVs),
pressurizer sp'ray, steam dump, or controlled feedwater flow after plant trip.
Although these operations are expected to occur and would result in a lower peak pressure, an additional degree of conservatism is provided by ignoring their effect.
1576v:1D/120188 15.4-17
U P
The pressurizer safety valves are assumed to initially open at 2500 psia and achieve rated flow at 2575 psia (3% accumulation).
15.4.4.2.2 Evaluation of the Effects of DNB in the Core Durin the Accident For this accident, ONB is assumed to occur in the core and, therefore, an evaluation of the consequences with respect to fue'I rod thermal transients is performed. Results obtained from analysis of this hot spot condition represent the upper limit with respect to cladding temperature and zirconium-water reaction.
In the evaluation, the rod power at the hot spot is conservatively assumed to be 3.0 times the average rod power at the initial core power level.
15.4.4.2.3 Film Boilin Coefficient The film boiling coefficient is calculated in the FACTRAN code using the Bishop-Sandberg-Tong film boiling "correlation. The fluid properties are evaluated at film temperature (average between wall and bulk temperatures).
The program calculates the film coefficient at every time step based on the actual heat transfer conditions at the time. The neutron flux,'ystem pressure, bulk density, and mass flowrate as a function of time are used as program input.
For this analysis, the initial values of the pressure and the bulk density are used throughout the transient since they are the most conservative with respect to cladding temperature response. For conservatism, ONB was assumed to start at the b'eginning of the accident.
15.4.4.2.4 Fuel Claddin Ga Coefficient'he magnitude .and time dependence of the heat transfer coefficient between
,fuel and cladding (gap coefficient) has a pronounced influence on the thermal results. The larger the value of the gap coefficient, the more heat is transferred between pellet and cladding. Based on investigations on the effect of the gap coefficient upon the maximum cladding temperature during the transient, the gap coefficient was assumed to increase from a steady state value consistent with the initial fuel temperature to 10,000 BTU/hr-ft2 -'F 0 1576 v:1D/120188 15.4-18
11
'ip
~ Il
at the initiation of the transient. This assumption causes energy stored in the fuel to be released to the cladding at the initiation of the transient and maximizes the cladding temperature during the transient.
15.4.4.2.5 Zirconium-steam Reaction The zirconium-steam reaction can become significant above 1800'F (cladding temperature). The Baker-Just parabolic rate equation shown below is used to define the rate of the zirconium-steam reaction.
d w t
2 = 33.3 x 10 6
exp [~~]
- 45,500 (15.4-1) where:
w = amount reacted, mg/cm t = time, sec T = temperature, 'K The reaction heat is 1510 cal/gm.
15.4.4.3 Results The results for the loss of offsite power case are as limiting, or more limiting than the case with offsite power available. Therefore, the loss of offsite power results are presented here.
Transient values of RCS pressure, RCS flow, faulted loop flow, nuclear power
'I hot channel heat flux, and clad temperature are shown in Figure 15.4.4-1 through Figure 15.4.4-6.
\
Maximum RCS pressure, maximum cladding temperature, maximum zirconium-water reaction are contained in Table 15.4-9.
15.4.4.4 Conclusions (1) Since the peak RCS pressure reached during any of the transients is less than that which would cause stresses to exceed the faulted condition stress limits, the integrity of the primary coolant system is not endangered.
1576v:1D/120188 15.4"19
(2) Since the peak cladding surface temperature calculated for the hot spot during the worst transient remains considerably less than 2700'F and the amount of zirconium-water reaction is small, the core will remain in place and intact with no consequential loss of core cooling capability.
(3) The results of the transient analysis show that 'less than 30% of the fuel. rods will have DNHRs below the safety analysis limit values.
The radiological doses have been calculated based on 30% failed fuel, and have been found to be within the guidelines of 10CFR100.
1576v:1D/120188 15.4"20
7 ~
f 'Q
".I A 0
S~
15.4.6 Ru ture of a Control Rod Drive Mechanism Housin Rod Cluster Control Assembl E'ection) 15.4.6. 1 Identification of Causes and Accident Descri tion This accident is defined as the mechanical fai lure of a control rod mechanism pressure housing resulting in the ejection of a rod cluster control assembly (RCCA) and drive shaft. The consequence of this mechanical failure is a rapid positive reactivity insertion and system depress'urization together with an adverse core power distribution, possibly leading to localized fuel rod damage.
15.4.6. 1. 1 Desi n Precautions and Protection Certain features" of the Shearon Harris Nuclear Plant are intended to preclude the possibility of a rod ejection accident, or to limit the consequences if the accident were to occur, These include a sound, conservative mechanical design of the rod housings, together with a thorough quality control (testing) program during assembly, and a nuclear design that lessens the potential ejection worth of RCCAs, and minimizes the number of assemblies inserted at high power levels.
15.4.6. 1.2 Mechanical Desi n The mechanical design is discussed in FSAR Section 4.2. Mechanical design and quality control procedures intended to preclude the possibility of an RCCA drive mechanism housing fai lure are listed below:
(1) Each full length control rod drive mechanism housing is completely assembled and shop tested at 4100 psi.
(2) The mechanism housings are individually hydrotested after they are attached to the head adapters in the reactor vessel head, and checked during the hydrotest of the completed reactor coolant system.
(3) Stress levels in the mechanism are not affected by anticipated system transients at power, or by the thermal movement of the coolant loops. Moments induced by the design-basis earthquake can be accepted within the allowable primary working stress range specified by the ASME Code,Section III, for Class I components.
1576v:1D/l 1 0788 15.4-21
L 4
~ 'I k'
l(
ge
(4) The latch mechanism housing and rod travel housing are each a single length of forged Type-304 stainless steel. This material exhibits excellent notch toughness at all temperatures .that will be encountered.
A significant margin of strength in the elastic range together with the large energy absorption capability in the plastic range gives additional assura'nce that gross fai lure of the housing will not occur. The joints between the latch mechanism housing apd head adapter, and between the latch mechanism housing and rod travel housing, are threaded joints reinforced b> canopy-type rod welds which are subject to periodic inspections, 15.4.6.1.3 Nuclear Desi n Even if a rupture of an RCCA drive mechanism housing is postulated, the operation of a plant utilizing chemical shim is such that the severity of an ejected RCCA is inherently limited. In general, the reactor is operated with the RCCAs inserted only far enough to permit load follow. Reactivity changes caused by core depletion and xenon transients are compensated by boron changes. Further, the location and grouping of control RCCA banks are selected during the nuclear design to lessen the severity of an RCCA ejection accident. Therefore, should a RCCA be ejected from its normal position during full-power operation, only a minor reactivity excursion, at worst, could be expected to occur.
However, it may be occasionally desirable to operate with larger than normal insertions. For this reason, a rod insertion limit is defined as a function of power level. Operation with the RCCAs above this limit guarantees adequate shutdown capability and acceptable power di stribution. The position of all RCCAs is continuously indicated in the control room. An alarm will occur if a bank of RCCAs approaches its insertion limit or if one RCCA deviates from its bank. There are low and low-low level insertion monitors with visual and audio signals. Operating instructions require boration at low-level alarm and emergency boration at the low-low alarm.
1576v:10/110788 15.4-22
I' IVV
~ V"
~L VV+
V VL
15.4.6.1.4 Reactor Protection The reactor protection in the event of a rod ejection accident has been described in Reference 7. The protection for this accident is provided by the power range high neutron flux trip (high and low setting) and high rate of neutron flux increase trip. These protection functions are described in detail in FSAR Section 7.2.
15.4.6. 1.5 Effects on Ad acent Housin s Disregarding the remote possibility of the occurrence of an RCCA mechanism housing failure, investigations have shown that failure of a housing due to either longitudinal or circumferential cracking is not expected to cause damage to adjacent housings leading to increased severity of the initial accident.
15.4.6. 1.6 Limitin Criteria Due to the extremely low probability of an RCCA ejection accident, limited fuel damage is considered an acceptable consequence.
Comprehensive studies of the threshold of fuel fai lure and of the threshold of
'significant conversion of the fuel thermal energy to mechanical energy have been carried out as part of the SPERT project by the Idaho Nuclear Corporation (8) . Extensive. tests of zirconium-clad UO fuel'ods
~
2 representative of those in PWR-type cores have demonstrated failure thresholds in the range of 240 to 257 cal/gm, However, other rods of a slightly different design have exhibited failures as low as 225 cal/gm. These results significantly from the TREAT (g) results, which indicated a fai lure 'iffer threshold of 280 cal/gm. Limited results have indicated that this threshold
'decreases by about 10% with fuel burnup. The cladding failure mechanism appears to be melting for zero burnup rods and brittle fracture for irradiated rods. Also important is the conversion ratio of thermal to mechanical energy. This ratio becomes marginally detectable above 300 cal/gm for unirradiated rods and 200 cal/gm for irradiated rods; catastrophic fai lure, (large fuel dispersal, large pressure rise) even for irradiated rods, did not occur below 300 cal/gm.
1576v:1D/110788 15.4"23
C t,
In view of the above exp'erimental results, conservative criteria are applied to ensure that there is I
little or no possibility of fuel dispersal in the coolant, gross latt'ice distortion, or severe shock waves. These criteria are:
(1) Average fuel pellet enthalpy at the hot spot below 225 cal/gm for unirradiated fuel and 200 cal/gm for irradiated fuel; (2)'Average cladding temperature at the hot spot below the temperature at which cladding embrittlement may be expected (2700'F);
(3) Peak reactor coolant pressure less than that which would cause stresses to exceed the faulted condition stress limits; (4) Fuel melting will be limited to less than 10% of the fuel volume at the hot spot even if the average fuel pellet enthalpy is below the limits of Criterion (1) above.
15.4.6.2 Anal sis of Effects and Conse uences The analysis of the RCCA ejection accident is performed in two stages: 'a) an average core nuclear power transient calculation and (b) a hot spot heat transfer calculation. The average core calculation is performed using spatial neutron kinetics methods to determine the average power generation with time including the various total core feedback effects, i.e., Doppler reactivity and moderator reactivity. Enthalpy and temperature transients in the hot spot are then determined by multiplying the average core energy, generation by the hot channel factor and performing a fuel rod transient heat transfer calculation. The power distribution calculated without feedback is pessimistically assumed to persist throughout the transient.
A detailed discussion. of the method on analysis can be found in Reference 10.
15.4.6.2. 1 Avera e Core Anal sis The spatial kinetics computer code, TWINKLE', (11) is used for the average core transient analysis. This code solves the two group neutron diffusion theory kinetic equations in one, two, or three spatial dimensions (rectangular 1576v:1D/110788 15.4-24
coordinates) for six delayed neutron groups and up to 2000 spatial points.
The computer code includes a detai'led multiregion, transient fuel-clad-coolant heat transfer model for calculating poi'ntwise Doppler, and moderator feedback effects.
In this analytis, the code is used as a one-dimensional axial kinetics code since it allows a more realistic representation of the spatial effects of axial moderator feedback and RCCA movement and the elimination of axial feedback weighting factors. However, since the radial dimension is missing, it is still necessary to employ very conservative methods (described below) of calculating the ejected rod worth and hot channel factor. A further description of TWINKLE appears in Section 15.1.8.
15.4.6.2.2 Hot S ot Anal sis The average core energy addition, calculated as described above, is multiplied by the appropriate hot channel factors, and the hot spot analysis is performed using the detailed fuel and cladding transient heat transfer computer code, FACTRAN (6) . This computer code calculates the transient temperature distribution in a cross section of a metal clad U02 fuel rod, and the heat flux at the surface of the rod, using as input the nuclear power versus time and the local coolant conditions. The zirconium-water reaction is explicitly represented, and all material properties are represented as'functions of temperature. A parabolic radial power generation is used within the fuel rod.
FACTRAN uses the Dittus-Boelter((12)'r Jens-Lottes( (13)'orrelation to determine the film heat transfer before DNB, and the Bishop-Sandberg-Tong correlation (14) to determine the film boiling coefficient after DNB. The
~
DNB heat flux is not calculated; instead the code is forced into DNB by specifying a conservative DNB heat flux. The gap heat transfe'r coefficient can be calculated by the code; however, it is adjusted in order to force the full power steady state pellet temperature distribution to agree with'that p'redicted by design fuel heat transfer. codes.
1 576 v:1D/110788 15.4-25
t lg g k
4 $ ~ 4 8
it~
Var
~ 4~
For full power cases, the design initial hot channel factor (F<) is input to
. the code. The hot channel factor during the transient is assumed to increase from the steady state design value to the maximum transient value in 0.1 seconds, and remain at the maximum for the duration of the transient. This is conservative, since detailed spatial kinetics models show that the hot channel factor decreases shortly after the nuclear power peak due to power flattening caused by preferential feedback in the hot channel. Further description of FACTRAN appears in Section 15. 1.8.
15.4.6.2.3 S stem Over ressure Anal sis Because safety limits for fuel damage specified earlier are not exceeded, there is little likelihood of fuel dispersal into the coolant. The pressure surge may therefore be calculated on the basis of conventional heat transfer from the fuel and prompt heat generation in the coolant.
The pressure surge is calculated by first performing the fuel heat transfer calculation to determine the average and hot spot heat flux versus time.
Using this heat flux data, a TMINC calculation is conducted to determine the volume surge. Finally, the volume surge is simulated in a plant transient computer code. This code calculates the pressure transient taking into account fluid transport in the system, heat transfer to the steam generators, and'he action of the pressurizer spray and pressure relief valves. No credit is taken for the possible pressure reduction caused by the assumed failure of the control rod pressure housing 15.4.6.2.4 Calculation of Basic Parameters Input parameters for the analysis are conservatively selected on the basis of calculated values for this type of core. The more important parameters are discussed below. Table 15.4-10 presents the parameters used in this analysis.
15.4.6.2.5 E'ected Rod Morths and Mot Channel. Factors The values for ejected rod worths and hot channel factors are calculated using three dimensional calculations. Standard nuclear design codes are used in the analysis. No credit is taken for the flux-flattening effects of reactivity feedback. The calculation is performed for the maximum allowed bank insertion 1576v:1D/110788 15.4-26
~ t I
~
E J'
l>>
at a given power level as determined by the rod insertion limits. Adverse xenon distributions are considered in the calculations.
Appropriate margins are added to the results to allow for calculational uncertainties, including an allowance for nuclear power peaking due to densification.
15.4.6.2.6 Reactivit Feedback Hei htin Factors The largest temperature rises, and hence the largest reactivity feedbacks, occur in channels where the power is higher than average. Since the weight of regions is dependent on flux, these regions have high weights. This means that the reactivity feedback is larger than that indicated by a simple single channel analysis. Physics calculations were carried out for temperature changes with a flat temperature distribution, and with a large number of axial and radial temperature distributions. Reactivity changes were compared and effective weighting factors determined. These weighting factors take the form of multipliers that, when applied to single channel feedbacks, correct them to effective whole core feedbacks for the appropriate flux shape. In this analysis, since a one-dimensional (axial) spatial kinetics method is employed, axial weighting is not used. In addition,.no weighting is applied to the moderator feedback. A conservative radial weighting factor is applied to the transient fuel temperature to obtain an effective fuel temperature as a function of time accounting for the missing spatial dimension. These weighting. factors were shown to be conservative compared to three-dimensional analysis.
15.4.6.2.7 Moderator and Do ler Coefficient The critical boron concentrations't the beginning-of-life (BOL) and end-of-life (EOL) are adjusted in the nuclear code in order to obtain moderator density coefficient curves which are conservative compared to actual design conditions for the plant. As discussed above, no weighting factor is applied to these results.
1576v:1D/110788 15.4-27
L 4 1 fe
The Doppler reactivity defect is determined as a function of power level using the one-dimensional steady state computer code with a Doppler weighting factor of 1. The resulting curve is conservative compared to design predictions for this plant. The Doppler weighting factor should be larger than 1 (approximately 1.2) just to make the present calculation agree with design predictions before ejection. This weighting factor will increase under accident conditions, as discussed above. The Doppler defect used as an initial condition is 900 pcm at BOL and 840 pcm at EOL.
15.4.6.2.8 Dela ed Neutron Fraction Calculations of the effective delayed neutron fraction (9 ff) typically yield values of 0.70% at BOL and 0.50% at EOL for the first cycle. The accident is sensitive to 5 if the ejected rod worth is nearly equal to or greater than 8 as in zero power transients. In order to allow for future fuel cycles, pessimistic estimates of 5 of 0.54% at beginning of cycle and 0.44% at end of cycle were used in the analysis.
15.4.6.2. 9 Tri React i vi t Inserti on The trip reactivity insertion assumed is given in Table 15.4-10 and includes the effect of one stuck rod. These values are reduced by the ejected rod reactivity. The shutdown reactivity was simulated by dropping a 'rgd of the required worth into the core. The start of rod motion occurred 0.5 seconds after the high neutron flux trip point was reached. This delay is assumed to consist of 0.2 seconds for the instrument channel to produce a signal, 0. 15 se'conds for the trip breaker to open, and 0. 15 seconds for the coil to release the rods. The analyses presented are applicable for a rod insertion time of 2.7 seconds from coil release to entrance to the dashpot. The choice of such a conservative insertion rate means that there is over 1 second after the trip point is reached before Significant shutdown reactivity is inserted into the core. This is a particularly important conservatism for ho't full power accidents.
The rod insertion versus time is described in Section 15.1.4.
1576v:1D/110788 15.4-28
~ j i%/
~i%
el 0
\De ip
15.4.6. 3 Resul ts The values of the parameters used in the analysis, as well as the results of the analysis, are presented in Table 15.4-10 and discussed below.
15.4.6.3.1 Be innin of C cle, Full Power Control Bank D was assumed to be inserted to its insertion limit. The worst ejected rod worth and hot channel factor were conservatively assumed to be 0.21% aK and 6.5, respectively. The peak hot spot clad average temperature was 2424'F. The peak hot spot fuel center temperature exceeded the BOL melting temperature of 4900'F. However, melting was restricted to less than 10% of the pellet.
15.4.6.3.2 Be innin of C cle, Zero Power
.For this condition, control Bank D was assumed to be fully inserted and C was at its insertion limit. The worst ejected rod is located in control Bank D and was conservatively assumed to have a worth of 0.840% aK and a hot channel factor of 12.5 The peak hot spot cia'd average temperature reached 2677'F. The peak. hot spot fuel center temperature reached 4435'F.
15,4.6.3.3 End-of-C cle, Full Power Control Bank D was assumed to be inserted to its insertion limit. The ejected rod worth and hot channel factors were conservatively assumed to be 0.23% aK and 7.0, respectively. This resulted in a peak hot spot clad average temperature of 2344'F. The peak hot spot fuel center temperature exceeded the EOL melting temperature 'of 4800'F. However, melting was restricted to less than 10% of the pellet.
15.4.6.3.4 End of C cle, Zero Power The ejected'od worth and hot channel factor for this case were obtained assuming control Bank D to be fully inserted and Bank C at its insertion limit. The results were 0.90% hK and 23.0, respectively. The peak clad average and fuel center temperatures were 2640 and 4159'F, respectively.
1576v:10/110788 15.4-29
"0 L,
A summary of the cases presented is g',ven in Table 15.4-10. The nuclear power and hot spot fuel clad temperature transients for the worst cases (BOL full power and zero power) are presented on Figures 15.4.6-1 through 15.4.6-2.
15.4.6.3.5 Fission Product Release It is assumed that fission products are released from the gaps of all rods P
entering DNB. In all cases considered, less than 10% of the rods entered DNB based on a detailed three-dimensional THINC analysis. Although limited fuel melting at the hot spot was predicted for the full power cases, in practice melting is not expected since the analysis conservatively assumed that the hot spots before and after ejection were coincident.
15.4.6.3.6 Pressure Sur e A detailed calculation of the pressure surge for an ejection worth of one dollar at BOL, hot full power, indicates that the peak pressure does not exceed that which would cause stress to exceed the faulted condition stress limits. Since the severity of the present analysis does not exceed this worst case analysis, the accident for this plant will not result in an excessive pressure rise or further damage to the RCS.
15.4.6.3.7 Lattice Deformations A large temperature gradient will exist in the region of the hot spot. Since the fuel rods are free to move in the vertical direction, differential expansion between separate rods cannot produce distortion. However, the temperature gradients across individual rods may produce a force tending to bow the midpoint of the rods toward the hot spot. Physics calculations indicate that the net result of this would be a negative reactivity insertion. In practice, no significant bowing is anticipated, since the structural rigidity of the core is more than sufficient to withstand the forces produced. Boiling in the hot spot region would produce a net flow away from that region. However, the heat from fuel is released to the water relatively slowly, and it is considered inconceivable that cross flow will be sufficient to produce significant lattice forces. Even if massive and rapid boi ling, sufficient to distort the lattice, is hypothetically postulated, the large void fraction in the hot spot region would produce a reduction in the 7576v:1D/110788 15.4-30
NI total core moderator to fuel ratio, and a large reduction in this ratio at the hot spot. The net effect would therefore be a negative feedback. It can be concluded that no conceivable mechanism exists for a net positive feedback resulting from lattice deformation. In fact, a small negative feedback may result. The effect is conservatively ignored in the analyses.
j 15.4.6.4 Conclusions Even on a conservative basis, the analyses indicate that the described fuel and cladding limits are not exceeded. It is concluded that there is no danger of sudden fuel dispersal into the coolant. Since the peak pressure does not exceed that which would cause stresses to exceed the faulted condition stress limits, it is concluded that there is no danger of further consequential damage to the reactor coolant system. The analyses have demonstrated that the upper limit in fission product release as a result of a number of fuel rods entering DNB amounts to 10%
1576v:1D/110788 15. 4-31
4 r
tP
%g P
15.4.7 References
- 1. Technical S ecifications, Shearon Harris Nuclear Power Plant Unit One Technical Specifications through Amendment 7, August 22, 1988.
- 2. T. W. T. Burnett; et a1., LOFTRAN Code Oescri tion, WCAP-7907-P-A (Proprietary), MCAP-7907-A (Non-Proprietary), April 1984.
- 3. Hochreiter, L. E., Chelemer, H. and Chu, P. T., "THINC-IV an Improved Program for Thermal-Hydraulic Analysis of Rod Bundle Cores," WCAP-7956, June, 1973.
- 4. F. S. Moody, "Transactions of the ASME," Journal of Heat Transfer, February 1965, Figure 3, page 134.
- 5. ANSI/ANS-5. 1-1979, American National Standard for Decay Heat Power in Light Water Reactors, 1979.
- 6. H. G. Hargrove, FACTRAN-A Fortran IV Code for Thermal Transients in a U02 Fuel Rod, MCAP-7908, June 1972.
- 7. 'T. W. T. Burnett, Reactor Protection S stem Diversit in"Westin house Pressurized Water Reactor, WCAP-7306, April 1969.
- 8. T. G. Taxelius, ed. "Annual Report - Spert Project, October 1968 September 1969", Idaho Nuclear Cor oration IN-1370, June 1970.
- 9. R. C. Liimatainen and F. J. Testa, Studies in TREAT of Zircal'o Clad, U02-Core Simulated Fuel Elements, ANL-7225, January - June 1966, p. 177, November 1966.
- 10. D. H. Risher, Jr., An Evaluation of the Rod E'ection Accident in Westin house Pressurized Mater Reactors Usin Spatial Kinetics Methods, MCAP-7588, Revision 1, December 1971.
1576v:1o/122288 15.4-32
I yA h
- 11. D. H. Risher, Jr. and R. F. Barry, TWINKLE - A Multi-Dimensional Neutron Kinetics Com uter Code, WCAP-7979-P-A (Proprietary), WCAP-8028-A (Non-Proprietary), January 1975..
- 12. F. W. Dittus and L. M.. K. Boelter, University of California (Berkeley),
Pubis. Eng., 2,433, 1930.
- 13. W. H. Jens and P. A. Lottes, Anal sis of Heat Transfer, Burnout, Pressure Dro , and Densit Data for Hi h Pressure Water, USAEC Report ANL-4627, 1951.
- 14. A. A. Bishop, et al., "Forced Convection Heat Transfer at High Pressure After the Critical Heat Flux," ASME 65-HT-31, August 1965.
- 15. Risher, D. H., Jr., "An Evaluation of the Rod Ejection Accident in Westinghouse Pressurized Water Reactors Using Spatial Kinectics Methods,"
WCAP-7588,'Revision 1-A, January 1975.
- 16. Westinghouse letter dated March-25, 1986, NS-NRC-86-3116, "Westinghouse Response to Additional Request on WCAP-9226-P/WCAP-9227-N-P, Reactor Core Response to Excessive Secondary Steam Release," (Non-Proprietary).
- 17. Hochrieter, L. E., and Chelemer, H., "Application of the THINC-IV Program.
to PWR Design," WCAP-8054 (Proprietary), October, 1973, and WCAP-8195 (Non-Proprietary), September, )973.
1576v:1D/110788 15.4-33
A, 4
TABLE 15.4-8 Sheet 1 of 3 TIME SEQUENCE OF EVENTS FOR MAJOR SECONDARY SYSTEM PIPE RUPTURES Accident Event Time sec Major Steam Line Rupture A. Offsite power Steam line ruptures 0 available Criticality attained 25 Boron from RWST reaches core 35 Accumulators actuate 76 Peak heat flux attained 78 Core becomes subcritical -345 B. Without offsite Steam line ruptures 0 power Criticality attained 30 Boron from RWST reaches core 48 Peak heat flux attained -320 Core becomes subcritical -350 1576v:10/110788 I
TABLE 15.4-8 Sheet 2 of 3 Accident Event Time, sec Rupture of Main Feedline rupture occurs 10 Feedwater Pipe (Mith Offsite Power)
Low-low steam generator level reactor trip setpoint reached in affected steam generator 32.6 Rod begins to drop 36.1 Emergency Feedwater is started 94.1 Feedwater lines are purged and AFH is'elivered to two of three intact steam generators 181.8 Low steamline pressure setpoint reached 201 Steaml inc isolation occurs 208 AFh'solation occurs 264 Steam generator safety valves lift in intact loops 547 Pressurizer water relief begins 1512 Total RCS heat generation (decay heat + pump heat) decreases. to emergency feedwater heat removal capability -2200 1576v:1O/110788
1~
TABLE 15.4-8 Sheet 3 of 3 Accident Event Time, sec Rupture of Main Feedline rupture occurs 10 Feedwater Pipe (Without Offsite Power)
Low-low steam generator level reactor trip setpoint reached in affected steam generator 32.6 Rod begins to drop 36.1 Reactor coolant pump coastdown 38.1 Emergency feedwater is started'4.1 Feedwater lines are purged and AFW is delivered to one intact steam generator 152 Low steamline pressure setpoint reached 232 Steamline isolation occurs 239 AFW isolation occurs 290 Steam generator safety valves lift in intact loop Pressurizer water relief. begins 1024 Total RCS heat generation decreases to AFW heat removal capability -1400 1576v:1D/020389
TAOLE 15.4-9 TIME SEQUENCE OF EVENTS AND
SUMMARY
OF RESULTS FOR THE LOCKED ROTOR TRANSIENT Event Time (Seconds)
Rotor on one pump locks 0.0 Low flow trip point reached 0.05 Rod begin to drop 1.05 Maximum RCS pressure occurs 2.7 Remaining pumps begin to coast down 3.05 Maximum clad temperature occurs at core hot spot 4.2 Maximum RCS pressure, psia 2649 Maximum clad temperature at core hot spot, 'F 2254 Maximum Zr-H 0 at core hot spot, X by weight 1.4 1576 v:1D/120188
TABLE 15.4-10 PARAMETERS USED IN THE ANALYSIS OF THE ROD CLUSTER CONTROL ASSEMBLY EJECTION ACCIDENT Time in Life ~eqeinnin ~Be innin End End Power level, /. 102 0.0 102 0.0 Ejected rod worth; %hk 0.21 0.84 0.23 0.90 Delayed neutron fraction, / 0.54 0.54 0.44 0.44 Feedback reactivity weighting 1.30 2.07 1.30 3.55 Trip reactivity, %hk FO before rod ejection 2.60 2.60 F< after rod ejection 6.5 12.5 7.0 23.0 Number of operating pumps 3 Maximum fuel pellet average temperature, 'F 4136 3786 4027 3615 Maximum fuel center temperature, 'F 4435 4159 Maximum clad average .temperature, 'F 2677 2344 '2640 2424'82 Maximum fuel stored energy, cal/gm 163 176 154
- Less than 10% fuel melt-1576v:10/1 10788
~"
I
~ I Y5
TABLE 15.4-11 TIME SEQUENCE OF EVENTS FOR ROD CLUSTER CONTROL ASSEMBLY EJECTION ACCIDENT Accident Event Time sec Beginning-of-Life, Initiation of rod ejection 0.0 Full Power Power range high neutron 0.046 flux setpoint reached Peak nuclear power occurs 0.126 Rods begin to fall into core 0.546 Peak fuel average 2.297 temperature occurs ,
Peak clad temperature occurs 2.375 Peafc heat flux occurs 2.390 End-of-Life, Ini ti ation of rod ejection 0.0 Zero Power Power range high neutron 0.175 flux setpoint reached Peak nuclear power occurs 0.208 Rods begin to fall into core 0.675 Peak clad temperature occurs 1.245 Peak heat flux occurs 1.309 Peak fuel average temperature 1.693 occurs 1576v:1D/020389
2IN D
"L -~II0 I.
X
- -$ N0 D
h.
g -140 0
0 c -42M bl D -10M L
D -N J
~ -soo 0
hl
.I.
-4N 0 L02 1.04 N5 OAN 0.$ Lf2 0.$ 4 0.1i 0.18 02 WV (e,no< 0F mIe.}
Shearon Harris Figure l5.4.2-1 Variation of Reactivity with Power at Constant Core Average Temperature
gpss
,4i Ae
'P 4." ~ i 41i t
lE
o I
.25
>C
.2
.15 z
.1 P ..85 1GO. 288. KQO. 488. SBB. 688. 788.
T I HE ( SEC )
~ 25QB.
2888.
QP P) )588.
IQGB.
V)
- o. SQB.
8.
- 8. 188. 288. 588. 488. 580. 688. 788.
7 IHE (SEC) 60Q.
C)
~ SBB.
I 488.
CC m 588.
C)
- 8. 188. 288. 588. 488. 588. '88. 788.
TI)RE 15EC)
Shearon Harris Figure 15.4.2-2 Transient'esponse To A Line Break Double 'team Ended Rupture With .
Offsite Power Available (Case A)
Cg CL Q.
.8
.6 Ci
,4 CE
~ 2 I
U)
- 8. 188. 208 388 488 S88 688 788 T INE )SEC )
580.
480.
380.
Qt Pg 286.
c C) 180.
G.
188. 288. 308. 488. SQQ. 668. 788.
T INE (SEC) 3QQQ.
2608.
1008,
-1808.
Qz
-2908.
-3888.
8 188. 288. 388. 488. 588. 688. 788.
TINE )SEC )
Shearon Harris Figure 15.4.2-3 Transient Response To A Steam Line Break Double Ended Rupture With Offsite Power Available (Case A)
~ ~
V
.3 Ct$
S r .25 3 E 0'R
.2 CL S
6$
O .15 4l C 0 ~r0 .I CJ Ct5
.05 S-LL G.
- 8. 188. 288. 388. 488. 588. 603 '88.
CL E 508.
I-4GG.
BOOED 308.
208
'08.
o
- 8. 188. 288. 308. 480. 580. 600
~ Pl SOBER 6QQ.
O S
Ol 4CG.
M
~ I 5-Vl 200.
Eh Ol S
O
- 8. 188. 288. 380. 400. 608 '08.
1203.
BQG.
600.
200.
G. IGQ. 288 '88. 488. SGG. 688. 788.
Time (sec) Shearon Harris Figure 15.4.2-3A Transient Response To A Steam Line Brea'k Oouble Ended Rupture With Offsite Power Available (Case A)
h p~
H W~l VI
Z I
.25
>C I
.2
<z .15 LJ LJ
.1 Q .85 8.
- 8. 188. 288. 389. 488: 580. 680. 788.
TIME ) SEC )
~ 2508; CL 2888.
LLI Qt g 15GG.
~~ )GGG.
Ch
- p. 508.
- 8. 188. 200. 388. 408. 588. 68G. 780.
TIME . (SEC)
~ 688.
CI
~ 588.
K LJ I
) 488.
~
CK 0 388.
a:
- 8. 188. 288. 388. 468. 588. 688. 708.
TIME, (SEC)
Shearon Harris Figure 15.4.2-4 Transient Response To A Steam Line Break Double Ended Rupture With No Offsite Power Available (Case B)
f Pl LJ, 2 th
- 8. 188. 288. 388. 488. 588. 688. 788.
T I HE . (SEC )
588.
488.
388.
288.
C) 188.
8.
-188, 8 188. 288. 388. 488. S88. 688. 78Q.
T I HE ( SEC )
80Q 2SQQ.
)888.
8.
cr.
4J
-188Q.
-28QQ.
-3GN.
8 188 .. 2QG. 388. 488. 688. 688. 788.
7 I )1E l EEC )
Shearon Harris Figure 15.4.2-5 Transient Response To A Steam Line Break Double Ended Rupture With No Offsite Power Available (Case,B)
~uk 1
,4
o5 Ctf 5 r ~ 25 07 E OZQ .2 S-lO 0 .15 8
r O 0 r ~ 1 CJ ltl .85 S
0.
G. 100 200. 300 ~ 4CO. c00. 6CG. 788 6QD.
500.
400.
5CO.
2CO 0 ~ 180. 200. KCG ~ 400 ~ 588. 600. 788.
4 i ~
6CC ~
O S- ~ t f%
<I ~
N S
2A 7 4)
S O
G. 100. 208. EQO. 408. 588, 608. 708.
120C.
18"C.
880.
400.
2"C.
Q. 188. 208 '80. 488. 580 '80. 700 Harris
'ime (sec) Shearon Figure 15.4.2-5A Transient Response To A Steam Line Break Double
~
Ended Rupture With No Offsite Power Available (Case B)
ie4 le~ Ie" ie4 TINE (SEC)
Shearon Harris Figure 15.4.2-6 Hain Feedline Rupture With Offsite Power Nuclear Power and Core Heat Flux vs. Time
2.00 t;
Cfi 2 'C0. lI (l) \
~ 22CO.
f4'h u 2000.
i&CO.
1680
'80 162 18"- 184 2CL 0 I
1":C0.
1 <<GiJ 1200.
= icon.
&00.
D c'08.
408.
288 '
81 182 TINE ISEC) 18'04 Shearon Harris Figure 15.4.2-7 Hain Feedline Rupture With Offsite Power Pressurizer Pressure and Water Volume vs. Time
SAT C
C: 64Q.
CL HOT LEG I
r C' CJ I
hl 9 C a.J ~
CD CD 0
LJ COLD LEG D
c4Q 520 I88 IQI I 82 18D I84 LJ SAT G.
I 0; HOT LEG LJ O.
620.
LJ I
C 5QQ.
CD CD
~ I COLD LEG CT. CQQ I
R 546.
528.
588, I8'Q2 'QD T I HE ( SEC I I84 Shearon Harris Figure 15.4.2-8 Main Feedline Rupture With Offsite Power Faulted and Intact Loop Coolant Temperatures vs. Time
YW INTACT Cf)
Cf) 1880.
0'88.
6K.
CO FAULTED 181 !02 184
.12 C) cf2 . 10c. ~
6 5
I
.68E ~
5 C
w 6QE INTACT w .48c 5 I
Cf)
FAULTED
.28E ~ 5 18'82 T I HE ( SEC 1 184 Shearon Harris Figure 15.4.2-9 Hain Feedline Rupture With Offsite Power Steam Generator Pressure and Water Hass vs. Time
r n
~ I f 0 l
I ~
L Ci I.
L LJ SD G:
I C'
~ 2 I8I I84 I
~
K
>C 4J a4 G')
I8I l8~ I84 T jIIE I SEC I Shearon Harris Figure 15.4.2-10 Hain Feedline Rupture Nithout Offsite Power Nuclear Power and Core Heat Flux vs. Time
2 Oi ~
i V.
~
Q.
Q.
22CC.
1600 188 182 18" Ioc
<<CCO.
Ieco.
1 6 CO.
I -'CO.
)
a, 1280.
I CCO.
COG.
0'
&UU ~
488.
288.
181 182 18" I84 T ICE I SEC I Shearon Harris Figure 15.4.2-11 Hain Feedline Rupture Without Offsite Power Pressurizer Pressure and Water Volume vs. Time
~ I4
)o, P
3 cc
= 548.
c HOT LEG R 520.
I
- c. 5C3.
C C
cp 0 COLD LEG
. 553.
5le.
523.
5CC.
Ie I 82 f85 >84 SAT HOT LEG 4d 4
COLD LEG c'C 52C.
U 533.
ic> ie2 )85 let I
I SAT L ~ ccrc HOT LEG I
a iJ
- c. 533.
c
~
C 58C.
I COLD LEG c58.
54C.
528.
IBB 182 le>>
T I tK l SCC I ie'hearon Harris Figure 15.4.2-12 Hain Feedline Rupture Without Offsite Power Faulted/Isolated/Intact Loop Temperatures vs. Time
< 184
.14E ~ 6 2 .12E~6 ID 18E~6 EZ X
o .BBE~S EX
~~ .68E 5 K'
.48E 5 IA ISOLATE9
.28E ~ 5 FAULTED 188 181 182 18> is4 T ICE 15EC 1 Shearon Harris Figure l5.4.2-I3 Hain Feedline Rupture Without Offsite Power Steam Generator Pressure and Water Hass vs. Time
~ 2CBB.
Vl CL 2783.
Qi u) 2"=83 ~
lrJ QI Q
z 2583.
Ld I
V) v) 2483.
I
~~ 2388.
C)
O
~ 2283.
C)
I Q 2188.
2333,
- 0. l8. .'5.:8.
T I HE ( SEC )
Shearon Harris Figure 15.4.4-1 All Loops Operating One Locked Rotor RCS Pressure vs. Time
1.2
.8 C3
.6 Shearon Harris Figure 15.4.4-2 All Loops Operating One Locked Rotor Total RCS Flow vs. Time
4 eal Jbl r I-
Shearon Harris Figure 15.4.4-3 All Loops Operating One Locked Rotor Faulted Loop Flow vs. Time
QI 4J o
Q Ql CZ
~ 4
.2
)~. 28.
TINE'SEC)
Shearon Harris Figure 15.4.4-4 All Loops Operating One Locked Rotor Nuclear Power vs. Time
2SCB ~
o 22SB.
2888.
1758.
P 1SBB.
)2SB.
1688, 7SB.
8 ~ 2: 4, o. Fs, 13, l2, 14> lo, )8, "8, TINE (SEC>
Shearon Harris Figure 15.4.4-5 A11 Loops Operating One Locked Rotor Maximum Clad Temperature vs. Time
E 1:2 O
.6 Ol 51
~ 2 Q
8 ~ 1 ~ 2 ~ 3. 4. 5, 6. 7.
Time (sec)
Shearon Harris Figure 15.4.4-6 A11 Loops Operating One Locked Rotor Hot Channel Heat Flux vs. Time
i C
2.5 C
f C 0
C lkl C
% l 5 II L
4 l.
G, I G ~ l 2. 3~ 4. 5. 6. 7. 6. R. le TINE (secs) 6GGG ~
FUEL CENTER TENPERATURE g
4000.
3GGG ~
FUEL AVERAGE TENPERATURE ~
Laf 5I 2008.
CLAD OUTER TENPERATURE~
1GGG.
- l. 2 ~ 3. 4. 5. 6. 7. 8 ~
TINE (secs)
Shearon Harris Figure 15.4.6-1 Rod Ejection Accident BOL HFP Nuclear Power, Hot Spot Fuel and Clad Temperature vs. Time
18 1 18 2
- 8. .5 1. 1.5 2. 2.5 3. 3.5 4.
TINE (secs)
Ooo.
FUEL AVERAGE~
38O8 TENPERATURE 2C08.
CLAD OUTER TENPERATURE 8.
- 8. l. 2 ~ 3. 4. 5. 6. 7. 8, 9. 18.
TINE (secs)
Shearon Harris Figure 15.4.6-2 Rod Ejection Accident BOL HZP Nuclear Power, Hot Spot Fuel and Clad Temperature vs. Time
ATTACHMENT 4 LOCA ACCIDENT ANALYSIS FOR THE SHEARON HARRIS NUCLEAR POWER PLANT TRANSITION TO 17 x 17 VANTAGE 5 FUEL (277CRS/lah)
TABLE 15.0.3-2 (Cont1nued)
SUMMARY
OF INITIAL CONDITIONS AND COMPUTER CODES USED In1t1al NSSS Thermal Power Moderator Moderator Out Assumed Computer Temperature Dens1ty (2)
Faults - Codes Utilized hk/~F ~(hk/ /cc) (Mwt)
Loss of coolant acc1dents SATAN-VI, See Section See Sect1on 2775 result1ng from the spectrum WREFLOOD. 15.6.5. 15.6.5, of postulated pip1ng breaks COCO, BASH, References References within the reactor coolant LOCBART, pressure boundary. NOTRUMP 1582vr 10/100788-14
1 J b~
II
,r~
- ~
'6~
L' 4.y P
6.2.1.5 sis for Performance
~ ~
~ ~ ~ Minimum Containment Pressure Anal Ca abi1 it Studies of Emer enc Core Cool in S stem The containment backpressure used for the limiting case CD = 0.4, DECLG break for the ECCS analysis presented in Section 15.6.5 is presented in Figure
~
6.2.1-302. The containment backpressure is calculated using the methods and assumptions described in "Westinghouse Emergency Core Cooling System Evaluation Model - Summary," MCAP-8339, Appendix A. Input parameters including the containment initial conditions, net free containment volume, passive heat sink materials, thicknesses, surface areas, starting time, and number of containment heat removal systems used in tlie analysis are described below.
The analysis was performed assuming the loss of offsite power as the most limiting condition. As indicated in MCAP-8471, the three loop plant limiting case break (CD = 0.4 DECLG) yields lower calculated PCT values with offsite power available (reactor coolant pumps run case) than if offsite power is lost (reactor coolant pumps trip case). This results from core thermal hydraulics during blowdown and is true even though calculated containment pressure may be lower in the offsite power available case due to faster actuation of the engineered safguards. The applicability of the generic conclusion regarding offsite power status to the Shearon Harris ECCS analysis is presented in detail below.
A review of the original three-loop plant generic sensitivity runs demonstrated the large benefit in calculated clad temperature which exists at end of.blowdown in the offsite power available case. Calculated clad temperature at end of blowdown at the limiting fuel rod elevation (7.25 ft) is 1528'F with offiste power lost; with offsite power available, the calculated clad temperature at the equivalent location is only 1453'F at end of blowdown. Hence, the blowdown performance calculated with offsite power available produces a clad temperature result at end of blowdown which is 75'F better than with loss of offsite power assumed. This benefit will remain in effect throughout the core reflood transient, during which time the PCT is 1582v:1D/100788-16
J qQ calculated. During the core ref lood transient the reactor coolant pumps are assumed to be in the locked-rotor configuration independent of the availability of offsite power.
The impact of containment pressure on ECCS performance is important only during the core reflood transient. If offsite power is presumed available, the start times of the containment fan'oolers and sprays at Shearon Harris will be reduced by ten seconds. The ten seconds of additional heat removal by these systems will reduce calculated containment pressure during reflood by less 'than 0.4 psi; the impact of this pressure reduction on calculated PCT is less than 25 F.
Overall, then, the total effect of'ssuming offsite power to be available
. during a large break LOCA event at Shearon Harris is to obtain a more favorable result. The Westinghouse ECCS performance analysis generic assumption of loss of offsite power is limiting for Shearon Harris, and the results presented in the FSAR demonstrate compliance with 10 CFR50.46 for this limiting case.
6.2.1.5.1 Mass and Energy Release Data The mass/energy releases to the Containment during the blowdown and reflood portions of the limiting break transient are presented in Tables 6.2.1-59 through 6.2.1-61.
The mathematical models which calculate the mass and energy releases to the Containment are described in Section 15.6.5. Since the requirments of Appendix K of 10CFR50 are very specific in regard to the modeling of the RCS during blowdown and the models used are in conformance with Appendix K, no alterations to those models have been made in regard to the mass and energy releases. A break spectrum analysis is performed (see references in Section 15.6.5) that analyzes various break sizes, break locations, and Moody discharge coefficients for the double ended cold leg guillotine which do affect the mass and energy releases to the Containment. This effect is considered for each case analyzed. During refill, the mass and energy 1582v:1D/100788-17
releases to the Containment is assumed to be zero, which minimizes the containme'nt pressure. Ouring reflood, the effect of steam-water mixing .
between the safety injection water and the steam flowing through the RCS intact loops reduces the available energy released to the containment vapor.
space and therefore tends to minimize containment pressure.
6.2.1.5.2 Initial Containment Internal Conditions The following initial values were used in the analysis:
Containment pressure 14.7 psia Containment temperature 90 F RWST temperature 40 F Service water temperature 33 F Outside temperature -2 F Initial Relative Humidity 100 %
The initial temperature condition that may be encountered under limiting normal operating conditions used in the ECCS performance analysis was assumed to be 90'F. An evaluation determined that the containment temperature cannot fall below 80'F, and the normal expected average containment temperature is estimated at 100'F. The 90'F value was chosen because it was.shown to be a conservatively low v'slue consistent with representative normal full power operation of other nuclear plants. The normal operating range for containment pressure is expected to be between negative 1 inch wg to positive 4 inch wg with the nominal pressure expected to be slightly positive. The value of 14.7 psia was assumed for the ECCS performance analysis. The containment is the atmospheric type per Item d of SRP 3.8. The normal containment purge and makeup systems along with the containment cooling system will maintain the conta'inment within the normal operating range. The Normal Containment Purge Exhaust is first adjusted to allow the system to draw down the containment atmosphere to a slight negative pressure (to prevent outleakage). When the containment pressure is reduced to -0.25 in. wg. one of the two 100 percent capacity makeup fans will automatically start. The static pressure controller will regulate the respective supply fan inlet damper to modulate and maintain 1582v:1D/100788-18
q I 4
~p $
4I a.i P
'I >
the containment pressure setpoint. The pressure transmitter for controlling this lower value has a range of 0 to negative 1.0 in. wg. Safety grade pressure transmitters with a range of -5 to 0 to +5 in. wg provide coverage of the normal expected containment pressure range to include the negative pressure transient requiring initiation of the containment vacuum relief system.
6.2.1.5.3 Containment Volume The volume used in the analysis is 2.344 x 10 ft. .
6.2.1.5.4 Active Heat Sinks The Containment Spray System and the containment fan coolers operate to remove heat from the Containment.
Pertinent data for these systems which were used in the analysis are presented in Table 6.2. 1-62. The heat removal capability of each fan cooler is presented in Figure 6.2.1-303.
The containment sump temperature was not used in the analysis because the maximum peak cladding temperature occurs prior to initiation of the recirculation mode for Containment Spray System. In addition, heat transfer between the sump water and the containment vapor space was not considered in the analysis.
6.2.1.5.5 Steam-Water Hixing Water spillage rates from the broken loop accumulator are determined as part of the core reflooding calculation and are included in the containment (CO'0) code calculation model.
6.2.1.5.6 Passive Heat Sinks The passive heat sinks used in the analysis, with their thermophysical properties, are given in Table 6.2,1-63.
isezv:ionoo7ee-is
f* '4
. ><4 (ICQ
Concrete themophysical properties utilized were taken directly from BTP CSB 6-1. A carbon steel thermal conductivity value of 26 Btu/hr-ft-F is specified for the temperature range of interest for Shea'ron Harris from Reference 6.2.5-5; likewise, a volumetric heat capacity value is obtained from that The values shown in Table 6.2.1-63 were used in the analysis. 'eference.
6.2.1.5.7 Heat Transfer to Passive Heat Sinks The condensing heat transfer coefficiens used for heat transfer to the steel containment structures is given in Figure 6.2.1-304 for the limiting break.
The containment temperature transient for the limiting break is shown in Figure 6.2.1-305.
6.2.1.5.8 Containment Purging During a LOCA An analysis was performed to determine the reduction in containment pressure resulting from containment purging during a LOCA for ECCS backpressure determination. This analysis was based upon the containment conditions defined using the 1978 Westinghouse Evaluation Hodel. A containment isolation signal is received in that analysis at 1.03 seconds'fter inception of the LOCA. Adding 1.5 seconds for signal delay, a calculation is performed for a containment purge system consisting of two 8-inch diameter lines and the following conservative assumptions:
a) A 3.5 second isolation valve closure time is assumed. During the 6.03 second period immediately following the LOCA, no credit is taken for the reduction in effective flow area which occurs while the valve is in the process of closing.
b) The frictional resistance associated with duct entrance and exit losses, filters, ductwork bends and skin friction has not been considered.
c) No fan coastdown effects are considered.
i d) No inertia is considered. Steady state flow out the purge system ducts is established immediately at the time of the LOCA'.
1 582 v:1D/10078B-20
k
>Sr "y
~ d
A mixture of steam and air will be exhausted from the containment through the purge lines during the 6.03 seconds that the isolation valves are assumed to remain open. The effect of the composition of the gas being exhausted on containment pressure has been bounded by investigating the two extreme cases, air alone and steam alone. Mithin several seconds of the inception of the LOCA, containment pressure will have increased to the point that critical flow will occur in the purge lines. To bound the calculated gas mixture exhausted through the purge lines, the critical flow rates of steam and air were calculated during the first 6.03 seconds of the transient. Using these flow rates, critical flow was then conservatively assumed to be in effect from time zero. Equation 4.18 in Reference 6.2.1-13 was employed to calculate the critical flow rate of air through the purge lines. Figure 14 of Reference 6.2.1-14 was applied to compute the critical flow rate of steam through the purge lines. The total mass released during the 6.03 seconds that the valves are presumed open is calculated as 331 ibm air or 239 ibm steam. The impact on containment pressure at 6.03 seconds resulting from this loss of air or seam is less than 0.05 psi. in either case. The effect of a containment pressure reduction of this magnitude on the calculated peak clad temperature (PCT) is less than 1 deg.-F. Therefore, there is no'g penalty and margin with respect to 10CFR50.46 PCT requirements would remain.
6.2.1.5.9 Other Parameters No other parameters have a substantial effect on the minimum containment pressure analysis.
1582v:1D/10078S-21
~,i TABLE 6.2.1-59 BLOWDOWN MASS/ENERGY RELEASES DECLG CD = 0.4 Time (Sec.) Mass Flow lb/sec. Energy Flow Btu/sec.
0 0.0 0.0
.05 5.406 x 10 2.984 x 10 2.0 4.358 x 10 2.453 x 10 4.0 2.796 x 10 1.617 x 10 6.0 2.136 x 10 1.283 x 10 8.0 1.744 x 10 1.119 x 10 10.0 1.391 x 10 9.289 x 10 12.0 1.171 x 10 7.864 x 10 14.0 9.215 x 10 6.524 x 10 16.0 6.667 x 10 5.161 x 10 18.0 4.136 x 10 3.638 x 10 20.0 3.813 x 10 2.740 x 10 22.0 4.654 x 10 2.356 x 10 24.0 4.509 x 10 1.756 x 10 26.0 3.370 x 10 1.167 x 10 28.0 3.606 x 10 8,785 x 10 29.25 5.135 x 10 8.784 x 10 1582v:1D/100788"22
ie A
TABLE 6.2.1-60 REFLOOD MASS/ENERGY RELEASES" CD TOTAL MASS FLOWRATE TOTAL ENERGY FLOWRATE TIME SEC LBM/SEC 10 BTU/SEC 42.372 0.0 0.0 43.622 5.14 .067 51.89 70,63 .890 68.44 169.57 1.067 88.59 311.78 1.444 111.09 319.68 1.400 135.19 325.63 1.352 163.79 362.23 1.369
- Accumulator nitrogen was released between 50.0 and 70.0 seconds at a mass flow rate of 192.27 ibm/sec.
1582v:1D/10078S"23
'I v am 7Q y~l J~
t k
t4
TABLE 6.2.1-61 BROKEN LOOP INJECTION SPILL TO CONTAINMENT FOR LIMITING CASE DECLG CD 0'4 TIME SEC ENTHALPY BTU MASS FLOWRATE~ LBM/SEC ENERGY 0.0 59.62 4675.1 278910.8 3.01 59.62 3464.1 206529.9 4.01 59.62 3232.5 192723.0 5.01 59.62 3042.0 181366.6 8.01 59.62 2619.6 156181.4 11.01 59.62 2326.8 138726.4 16.01 59.62 1990.4 118668.7 21.01 59.62 1764.3 105188.1 24.01 59.62 1662.7 99132.5 27.01 59.62 1578.9 94134.5 28.01 8.027 194.0 1557.6 29.01 8.027 194.2 1559.3 1582v:1D/100788-24
TABLE 6.2.1-62 ACTIVE HEAT SINK DATA FOR MINIMUM POST-LOCA CONTAINMENT PRESSURE I. Containment .Spray System Parameters A. Maximum spray system flow, total 4450 B. Fastest post LOCA initiation of Containment Spray System 32.35
.II. Fan Coolers A. Maximum number of fan coolers operating B. Fastest post LOCA initiation of fan coolers 22.7 C. Performance data See Figure 6.2.1-303 for fan cooler atmosphere heat removal rate.
1582v:1o/100788-25
'b fiI
TABLE 6.2.1-63 PASSIVE HEAT SINK DATA FOR MINIMUM POST-LOCA CONTAINMENT PRESSURE Heat Sink Description Sl ab Slab* Material Number Descri tion Material Thickness in. Area, ft Surf ac~
Containment Carbon Steel .50 26546 Dome Concrete 30
- 2. External Cylinder Carbon Steel .375 63065 Hall Concrete 54
- 3. 1" Steel Liner Carbon Steel 1.0 2280 Concrete Concrete 54
- 4. Concrete Concrete 45 82525 Stainless Steel Liner Stainless Steel .1872 6756 Concrete Concrete .60 Sump Concrete 45 29320
- 7. Piping Carbon Steel .19656 5703
- 10. Electrical Carbon Steel .17448 33066 Embedded Stainless Stainless Steel .39024 1030 Concrete 3.2244
- 12. Not Embedded Stainless Steel .40068 3242 Stainless 1582v:1D/1001'88-26
54 TABLE 6.2.1-63 (Continued)
PASSIVE HEAT SINK DATA, FOR MINIMUM POST-LOCA CONTAINMENT PRESSURE Heat Sink Description Slab Slab" Material Surf ac~
Number Descri tion Material . Thickness in. Area, ft
- 13. Structural Heat Sinks Carbon Steel 1.0 '0300
- 14. Not Embedded Carbon Steel ..17375 119467 Structural
- 15. Structural Heat Carbon Steel .5004 66753 Sinks.
- 16. Embedded Structural Carbon Steel .3405 3472 Concrete
- 17. Embedded Structural Carbon Steel 1.444 13899 Concrete 3.2244
- 18. Ductwork Carbon Stel .1248 5430
- 19. Ductwork Galvanized .029028 39672 Carbon Steel
- 20. Seismic Hangers Carbon .Steel .18756 84386 Metal Coatings for individual slabs are defined via superscripts (2), (3), (4), (5).
Properties of the coatings are provided in 'the thermophysical property listing by number.
1582v:1D/100788-27
1 J C
~l(
Thermophysical Properties (1) Metal Thermal Conductivity:
Carbon Steel: 26 Btu/hr.-ft.-F Stainless Steel 9.2 Btu/hr.-ft.-F Thermal Capacity: 53.9 Btu/cu.ft. F)
(2) Paint is applied to outer and inner surfaces of the bare carbon steel plate casing.
Thickness Range: 5 mi ls Thermal Capacity: 42.6 Btu/cu.ft - F Therm'al Conductivity (Paint System): .23 Btu/hr-ft-F (3) Paint is applied only to outer surface of carbon steel., uninsulated pipe Paint Thickness Range: 5 mi ls Thermal Capacity: 147 Btu/cu.ft - F.
Thermal Conductivity: .23 Btu/hr-ft-F (4) Paint is applied to outer only of bare carbon steel sheet metal, Thickness Range: 8 mi ls Thermal Capacity: 42,6 Btu/cu.ft-F Thermal Conductivity (Paint System): .23 Btu/hr-ft-F 1582v:1D/100788-28
le l4
(5) Galvanizing: Zinc is applied according to ASTH A 525 coating designation 90 (commercial) coating thickness is approximately 0.90 oz./ft galvanized on both sides.
Thickness Range: 1.513 mils Thermal Capacity: 40.6 Btu/cu.ft-F Thermal Conductivity: 64 Btu/hr.-ft-F (6) Concrete Thermal Conductivity: .92 Btu/hr-ft"F Thermal Capacity: 22.62 Btu/cu.ft-F 1582v:1D/100788-29
25 20 f 15'0 40 R) 120 1i0 200 24) 2eo 520 75K (SEC)
SHEARON HARRIS NUCLEAR POWER PLANT CONTAINNENT PRESSURE FIGURE Caro1ina (DECLG CD 0.4)
Power I Light Co. 6.2. 1-302
'FINAL SAFETY ANALYSIS REPORT
I V ZERO FOULINO 33 F WATER TEMPERATURE R' %+50 CFM AIR FLOW 1500 GPM WATER FLOW SN f00 PERCENT SATURATION y tN 8
TS ZO ZS & 35 4) 45 $0 55 00 85 70 75 8) e5 SO 'K T00 %5 110 HEAT REMOVAL RATE PER FAN tSTUNR X % I SHEARON HARRIS NUCLEAR POMER PLANT HEAT REMOVAL RATE OF ENERGENCY FIGURE Carolina COOLER UNIT Power 3 Light Co. 6.2.1-303 FINAL SAFETY ANALYSIS REPORT
~ ~ ~t, e )dill ' &
~ 4
- I J%
I O
700 5
400
.ae 200 120 $ M 200 240
%WE (SEC)
SHEARON HARRIS NUCLEAR POMER PLANT CONTAINMENT MALL HEAT TRANSFER FIGURE Carolina COEFFICIENT Power K Light Co. 6.2.1-304 FINAL SAFETY ANALYSIS REPORT
!p V ~ ~0>O<<g' a
210 200 190 g
O 1N 170 160 iaO 140 130 120
.1 10
'120 160
%WE (SEC)
SHEARON HARRIS NUCLEAR POWER PLANT CONTAINMENT TEMPERATURE FIGURE Carolina ~ (DECLG CD~0.4)
Power 5 Light Co. 6.2.1-305 FINAL SAFETY ANALYSIS REPORT
fg
>l$
SHNPP FSAR 15.6.3 STEAM GENERATOR TUBE RUPTURE (SGTR) 15.6.3. 1 Identification of Cause and Accident Oescri tion The accident examined is the complete severance of a single steam generator tube. The accident is assumed to take place at power with the reactor coolant contaminated with fission products corresponding to continuous operation with a limited number of defective fuel rods. The ace~dent leads to an increase in contamination of the secondary system due to leakage of radioactive coolant from the reactor coolant system (RCS). In the event of a coincident loss of offsite power, or failure of the Condenser Steam Oump System, discharge of radioactivity to the atmosphere takes place via the steam generator power-operated relief valves (and safety valves if their setpoint is reached).
In view of the fact that the steam generator tube material is Inconel-600 and is a highly ductile material, it is considered that the assumption of a complete severance is somewhat conservative. The more probable mode'f tube failure would be one or more minor leaks of undetermined origin. Activity in the steam and power conversion system is subject to continual surveillance and an accumulation of minor leaks which exceeds the limits established in the Technical Specifications is not permitted during the Unit operation.
Oue to the series of alarms as described below, the operator will readily determine that a steam generator tube rupture has occurred, identify and isolate the faulty steam generator, and complete the required recovery actions to stabilize the plant and terminate the primary to secondary break flow. The recovery procedure can be completed on a time scale which ensures that break flow to the, secondary system is terminated before water level in the affected
,steam generator rises into the main steam pipe; Sufficient indications and .
controls are provided to enable the operator to carry out these functions satisfactorily.
Assuming normal operation of the various plant control systems, the following sequence of events is initiated by a tube rupture:
1266v:1D/020689
SHNPP FSAR a) Pressurizer low pressure and low level alarms are actuated and charging pump flow increases in an attempt to maintain pressurizer level. On the secondary side there is a steam flow/feedwater flow mismatch before trip as feedwater flow to the affected steam generator is reduced due to the break flow .which is now being supplied to that Unit.
b) The condenser vacuum pump effluent radiation monitor, steam generator blowdown line radiation monitor, and/or main steamline radiation monitor will alarm, indicating a sharp increase in radioactivity in the secondary system.
c) Continued loss of reactor coolant inventory leads to a reactor trip signal generated by low pressurizer pressure or by overtemperature hT.
Resultant plant cooldown following reactor trip leads to a rapid decrease in RCS pressure .and pressurizer level, and a safety injection (SI) signal, initiated by low pressurizer pressure, follows soon after the reactor trip. The SI signal automatically terminates normal feedwater supply and initiates auxiliary feedwater (AFH) addition.
d) The reactor trip automatically trips the turbine and if offsite power is available, the steam dump valves open permitting steam dump to the condenser. In the event of a coincident loss of offsite power, the steam dump valves would automatically close to protect the condenser. The steam generator pressure would rapidly increase resulting in steam discharge to the atmosphere through the steam generator power-operated relief valves (and safety valves if their setpoint is reached).
e) Following reactor trip and SI actuation, the continued action of the AFN supply and borated SI flow (supplied from the refueling water storage tank) provide a heat sink which absorbs some of the decay heat. This reduces the amount of steam bypass to the condenser, or in the case of loss of offsite power, steam relief to the atmosphere.
1266v:1D/020689
d
";5 v~
as~ g 9 I
SHNPP FSAR f) SI flow results in stabilization of the RCS pressure and pressurizer water level, and the RCS pressure trends toward an equilibrium value where the SI flow rate equals the break flow rate.
In the event of an SGTR, the plant operators must diagnose the SGTR and perform the required recovery actions to stabilize the plant and terminate the primary to secondary leakage. The operator actions for SGTR recovery are provided in the plant Emergency Operating Procedures. The major operator actions include identification and isolation of the ruptured steam generator, cooldown and depressurization of the RCS to restore inventory, and termination of SI to stop primary to secondary leakage. These operator actions are described below.
- 1. Identify the ruptured steam generator.
High secondary side activity, as indicated by the condenser vacuum pump effluent radiation monitor, steam generator blowdown line radiation monitor, or main steamline radiation monitor, typically will provide the first indication of an SGTR event. The ruptured steam generator can be identified by an unexpected increase in steam generator level, high activity in a steam generator water sample, or a high radiation indication on the corresponding main steam]inc radiation monitor. For an SGTR that results in a reactor trip at high power, the steam generator water level will decrease to near the bottom of the narrow range scale for all of the steam 'generators. The AFM flow will begin to refill the steam generators, distributing approximately equal flow to each of the steam generators.
Since primary to secondary leakage adds additional liquid inventory to the ruptured steam generator, the water level will increase more rapidly in that steam generator. This response, as displayed by the steam generator water level instrumentation, provides confirmation of an SGTR event and also identifies the ruptured steam generator.
- 2. Isolate the ruptured steam generator from the intact steam generators and isolate feedwater to the ruptured steam generator.
1266v:1D/020689
~t SHNPP FSAR Once a tube rupture has been identified, recovery actions begin by isolating steam flow from and stopping feedwater flow to the ruptured
'steam generator. In addition to minimizing radiological releases, this also reduces the possibility of overfilling the ruptured steam generator with water by I) minimizing the accumulation of feedwater flow and 2) enabling the operator to establish a pressure differential between the ruptured and intact steam generators as a necessary step toward terminating primary to secondary leakage.
- 3. Cool down the RCS using the intact steam generators.
After isolation of the ruptured steam generator, the RCS is cooled as r'apidly a's possible to less than the saturation temperature corresponding to the ruptured steam generator pressure by dumping steam from only the intact steam generators. This ensures adequate subcooling in the RCS after depressurization to the ruptured steam generator pressure in subsequent actions. If offsite power is available, the normal steam dump system to the condenser can be used to perform this cooldown. However, if offsite power is lost, the RCS is cooled using the power-operated relief valves (PORVs) on the intact steam generators.
- 4. Depressurize the RCS to restore reactor coolant inventory.
Mhen the cooldown is completed, SI flow will increase RCS pressure until break flow matches SI flow. Consequently, SI flow must be terminated to stop primary to secondary leakage. However, adequate reactor coolant inventory must first be assured. This includes both sufficient reactor coolant subcooling and pressurizer inventory to maintain a reliable pressurizer level indication after SI flow is stopped. Since leakage from the primary side will continue after SI flow is stopped until RCS and ruptured steam generator pressures equalize, an "excess" amount of inventory is needed to ensure pressurizer level remains on span. The "excess" amount required depends on RCS pressure and reduces to zero when RCS pressure equals the pressure in the ruptured steam generator.
1266v:1D/020689 4
i.
SHNPP FSAR The RCS depressurization is performed using normal pressurizer spray if the reactor coolant pumps (RCPs) are running. However, if offsite power is lost or the RCPs are not running for some other reason, normal pressurizer spray is not available. In this event, RCS depressurization can be performed using the pressurizer PORVs or auxiliary pressurizer spray. In the event that these systems are unavailable for the RCS depressurization, a contingency procedure provides the operator actions for terminating primary to secondary leakage without pressurizer-pressure control. Thus, in lieu of performing the RCS depressurization, the operator can use the contingency procedure to terminate SI in order to stop the primary to secondary leakage if other means of pressurizer pressure control are unavailable.
- 5. Terminate SI to stop primary to secondary leakage.
The previous actions will have established adequate RCS subcooling and secondary side heat sink, and sufficient reactor coolant inventory to ensure that SI flow is no longer needed. When these actions have been completed, SI flow must be stopped to terminate primary to secondary leakage. Primary to secondary leakage wi 11 continue after SI flow is stopped until RCS and ruptured steam generator pressures equalize.
Charging flow, letdown, and pressurizer heaters will then be controlled to prevent repressurization of the RCS and reinitiation of leakage into the ruptured steam generator.
Following SI termination, the plant conditions will be stabilized, the primary to secondary break flow will be terminated, and all immediate safety concerns will have been addressed. At this time a series of operator actions are performed to prepare the plant for cooldown to cold shutdown conditions.
Subsequently, actions are performed to cool down and depressurize the RCS to cold shutdown conditions and to depressurize the ruptured steam generator.
1 266 v:10/020689
50 8
SHNPP FSAR 15.6.3.2 Anal sis of Effects and Conse uences An SGTR results in the leakage of contaminated reactor coolant into the secondary system and subsequent release of a portion of the activity to the atmosphere. Therefore, an analysis must be performed to. assure that the offsite radiological consequences resulting from an SGTR are within the allowable guidelines. One of the major concern's for an SGTR is the possibility of steam generator overfill since this could potentially result in
.a significant increase in the offsite radiological consequences. Therefore, an analysis was performed to demonstrate margin to steam generator overfill, assuming the limiting single failure relative to overfill. The results of this, analysis demonstrated that there is margin to steam generator overfill for SHNPP. An analysis was also performed to determine the offsite radiological consequences, assuming the limiting single failure relative to offsite doses without steam generator overfill. Since steam generator overfill does not occur, the results of this analysis represent the limiting consequences for an SGTR for SHNPP. The analyses to demonstrate margin to overfill and to determine the offsite radiological consequences for a design basis SGTR for SHNPP are presented in Reference 1, and the results of the offsite radiological consequences analysis are discussed below.
A thermal and hydraulic analysis was performed to determine the plant response for a design basis SGTR, and to determine. the integrated primary to secondary break flow and the mass releases from the ruptured and intact steam generators to the condenser and to the atmosphere. This information was then used to calculate the quantity of radioactivity released to the 'environment and the resulting radiological consequences.
15.6.3.3 Thermal and H draulic Anal sis The plant response following an SGTR was analyzed with 'the LOFTTR2 program until the primary to secondary break flow is terminated. The reactor protection system and the automatic actuation of the engineered safeguards systems were modeled in the analysis. The major operator actions which are required to terminate the break flow for an SGTR were also simulated in the analysis.
1266v:10/020689
SHNPP FSAR Anal sis Assum tions The accident modeled is a double-ended break of one steam generator tube located at the top of the tube sheet on the outlet (cold leg) side of the steam generator. It was assumed that the reactor is operating at full power at the time of the accident and the secondary mass was assumed to correspond to operation at the bottom of the steam generator level control band with an allowance for uncertainties. It was also assumed that a loss of offsite power occurs at the time of reactor trip and the highest worth control assembly was assumed to be stuck in its fully withdrawn position at reactor trip.
The limiting singl,e failure was assumed to be the failure of the PORV on the ruptured steam generator. Failure of this 'PORV in the open position will cause an uncontrolled depressurization of the ruptured steam generator which will increase prim'ary to secondary leakage and the mass release to the atmosphere. It was assumed that the ruptured steam generator PORV fails open when the ruptured steam generator is isolated, and that the PORV was isolated by locally closing the associated block valve.
The major operator actions required for the recovery from an'GTR are discussed in Section 15.6.3. 1 and these operator actions were simulated in the analysis. Since a loss of offsite power was assumed for the analysis, normal pressurizer spray was not available to perform the RCS depressurization.
8ecause the pressurizer PORVs and auxiliary pressurizer spray are designed as non-safety related for SHNPP, it was assumed that they were also unavailable for the RCS depressurization. Thus, it was assumed that the contingency
. procedure would be used to terminate SI without pressurizer pressure control.
The operator action times which were used for the analysis are presented in Table 15.6.3-1. It is noted that the PORV on the ruptured steam generator was assumed to fail open at the time the ruptured steam generator was isolated.
8efore proceeding with the recovery operations, the failed open PORV on the ruptured steam generator was assumed to be isolated by locally closing the associated block valve. It was assumed that the ruptured steam generator PORV 1266v:10(0206&9
)
<<i 4
I <5 pe~ .
SHNPP FSAR is isolated at 20 minutes after the valve was assumed to fail open. After the ruptured steam generator PORV was isolated, the additional delay time of 5 minutes (Table 15.6.3-1) was assumed for the operator action time to initiate the RCS cooldown.
Transient Descri tion The LOFTTR2 analysis results are described below. The sequence of events for this transient is presented in Table 15.6.3-2.
Following the tube rupture, reactor coolant flows from the primary into the secondary side of the ruptured steam generator since the primary pressure is greater than the steam generator pressure. In'response to this loss of reactor coolant, pressurizer level decreases as shown in Figure 15.6.3-1. The RCS pressure also decreases as shown in Figure 15.6.3-2 as the steam bubble in the pressurizer expands. As the RCS pressure decreases due to the continued primary to secondary leakage, automatic reactor trip occurs on an overtemperature hT trip signal.
After reactor trip, core power rapidly decreases to decay heat levels. The turbine stop valves close and steam flow to the turbine is terminated. The steam dump system is designed to actuate following reactor trip to limit the increase in secondary pressure, but the steam dump valves r'emain closed due to the loss of condenser vacuum resulting from the assumed loss of offsite power at the time of reactor trip. Thus, the energy transfer from the primary system causes the secondary side pressure to increase rapidly after reactor trip unti'I the steam generator PORVs (and safety valves if their setpoints are reached) lift to dissipate the energy, as shown in Figure 15.6.3-3. The main feedwater flow will be terminated and AFW flow will be automatically initiated following reactor trip and the loss of offsite power.
The RCS pressure decreases more rapidly after reactor trip as energy transfer to the secondary shrinks the reactor coolant and the leak flow continues to deplete primary inventory. Pressurizer level also decreases more rapidly following reactor trip. The decrease in RCS inventory results in a low 1266v:1D/020689
4 0
IJ 4 I
4 I .~
J'K
't
\p
SHNPP FSAR pressurizer pressure SI signal. After SI actuation, the RCS pressure and pressurizer tend to stabilize until the ruptured steam generator PORV is assumed to fail open.
Since offsite power is assumed lost at reactor trip, the RCPs trip and a gradual transition to natural circulation flow occurs. Immediately following reactor trip the temperature differential across the core decreases as core power decays (see Figures 15.6.3-4 and 15.6.3-5), however, the temperature differential subsequently increases as natural circulation flow develops. The cold leg temperatures trend toward the steam generator temperature as the fluid residence time in the tube region increases. The intact steam generator loop temperatures continue to slowly decrease due to the continued AFW flow until operator actions are taken to control the AFW flow to maintain th' specified level in the intact steam generators. The ruptured steam generator loop temperatures also continue to slowly decrease until the ruptured steam generator was isolated and the PORV was assumed to fail open, Na'or 0 erator Actions
- 1. Identify and Isolate the Ruptured Steam Generator The ruptured steam generator was assumed to be identified and isolated at 10 minutes after the initiation of the SGTR or when the'arrow range level reaches 30%, whichever time is greater. Since the time to reach 30%
narrow range level is less than 10 minutes, it was assumed that the ruptured steam generator is isolated at 10 minutes. The ruptured steam generator PORV was also assumed to fail open at this time, and the failure was simulated at 604 seconds. The failure causes the ruptured steam generator to rapidly depressurize as shown in Figure 15.6.3-3, which results in an increase in primary to secondary leakage. The depressurization of the ruptured steam generator increases the break flow and energy transfer from primary to secondary which results in a decrease in the ruptured loop temperatures as shown in Figure 15.6.3-5. As noted previously, the intact steam generator loop temperatures also decrease, as shown in Figure 15.6.3-4, until the AFW flow to the intact steam generators is throttled. After this time, the heat transfer to the intact 1266v:1D/020689
p pl
SHNPP FSAR steam generators decreases and the temperature differential across the intact steam generators decreases. As the intact steam generator hot leg temperatures decrease below the steam generator water temperature, reverse d
heat transfer takes place for a short time period as shown in Figure 15.6.3-4. It was assumed that the time required for the operator to identify that the ruptured steam generator PORV is open and to locally close the associated block valve is 20 .minutes. Thus, at 1806 seconds the depressurization of ruptured steam generator was terminated.
- 2. Cool Down the RCS to establish Subcool.ing Margin After the ruptured steam generator PORV block valve was closed, there is a 5 minute operator action time imposed prior to initiation of cooldown.
The depressurization of the ruptured steam generator affects the RCS cooldown target temperature since the temperature is dependent upon the pressure in the ruptured steam generator. Since offsite power was lost, the RCS was cooled by dumping steam to the atmosphere using the intact steam generator PORVs. The cooldown was continued unti 1 RCS subcooling at the ruptured steam generator pressure is 20'F plus an allowance of 20'F for instrument uncertainty. Because of the lower pressure in the ruptured steam generator the associated temperature the RCS must be cooled to is also lower, which has the net effect of extending the time for cooldown, The cooldown was initiated at 2108 seconds and was completed at seconds.
'168 The reduction in the intact steam generator pressures required to accomplish the cooldown'is shown in Figure 15.6.3-3, and the effect of the cooldown on the RCS temperature is shown in Figure 15.6.3-.4, The pressurizer level and RCS pressure also decrease during this cooldown process due to shrinkage of the reactor coolant, as shown in Figures 15.6.3-1 and 15.6.3-2.
- 3. Terminate SI to Stop Primary to Secondary Leakage .
At this time, actions have established adequate RCS subcooling and verified a secondary side heat sink to ensure that SI flow is no longer 1266v:1D/020689 10
'I ~
h
~pa
SHNPP FSAR needed. When these actions have been completed, the SI flow must be stopped to prevent repressurization of the RCS and to terminate primary to secondary leakage. An operator action time of 5.5 minutes was assumed following completion of the RCS coo'ldown until SI termination. The differential pressure between the RGS and the ruptured steam generator is shown in Figure 15.6.3-6. Figure 15.6.3-7 shows that the primary to secondary leakage continues after the SI flow is stopped until the RCS and ruptured steam generator pressures equalize.
The ruptured steam generator water volume is shown in Figure 15.6.3-8. The water volume in the ruptured steam generator is significantly less than the total steam generator volume. of 5949 ft3 when the break flow is terminated.
The mass of water in the ruptured steam generator is also shown as a function of time in Figure 15.6.3-9.
Mass Releases The mass releases were determined for use in evaluating the exclusion area boundary and low population zone radiation exposure. The steam releases from the ruptured and intact steam generators, the feedwater flows to the ruptured and intact steam generators, and primary to secondary break flow into the ruptured steam generator were determined for the period from accident initiation until 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after the accident and from 2 to 8'ours after the accident. The releases for 0-2 hours were used to calculate the radiation doses at the exclusion area boundary for a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> exposure, and the releases for 0-8 hours were used to calculate the radiation doses at the low population zone for the duration of the accident.
The operator actions for the SGTR recovery up to the termination of primary to secondary leakage were simulated in the LOFTTR2 analysis. Thus, the steam releases from the ruptured and intact steam generators, the feedwater flows to the ruptured and intact steam gen'erators, and the primary to secondary leakage into the ruptured steam generator were determined from the LOFTTR2 results for the period from the initiation, of the accident until the leakage is terminated.
1266v:10/020689
C I 4 'k Ap vt,
'1 4
~ gr P t
l k~
'll i.W
~&
SHNPP FSAR Following the termination of leakage, it was assumed that the actions are taken to cool down the plant to cold shutdown conditions. The PORYs for the intact steam generators were assumed to be used to cool down the RCS to the RHR system operating temperature of 350'F, at the maximum allowable cooldown rate of 100'F/hr. The steam releases and the feedwater flows for the intact steam generators for the period from leakage termination until 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> were determined from a mass and energy balance using the calculated RCS and intact steam generator conditions at the time of leakage termination and at 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
The RCS cooldown was assumed to be contiaued after 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> until the RHR system in-service temperature of 350'F is reached. Depressurization of the ruptured steam 'generator was then assumed to be performed to the RHR ,
in-service pressure of 375 psia via steam release from the ruptured steam generator PORV. The RCS pressure was also assumed to be reduced concurrently as the ruptured steam generator is depressurized. It was assumed that the continuation of the RCS cooldown and depressurization to RHR operating conditions are completed within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after the accident since there is ample time to complete the operations during this time period. The steam releases and feedwater flows from 2 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> were determined for the intact and ruptured steam generators from a mass and energy balance using the conditions at 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and at the RHR system in-service conditions.
After 8 hours, it was assumed that further plant cooldown to cold shutdown as well as long-term cooling is provided by the RHR system. Therefore, the steam releases to the atmosphere were terminated after RHR in-service conditions were assumed to be reached at 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
For the time period from initiation of the accident'until leakage termination, the releases were determined from the LOFTTR2 results for the time prior to reactor trip and following reactor trip. Since the condenser is in service until reactor trip, any radioactivity released to the atmosphere prior to reactor trip would be through the condenser vacuum pump exhaust. After reactor trip, the releases to the atmosphere were assumed to be via the steam generator PORVs. The mass release rates to the atmosphere from .the LOFTTR2 analysis are presented in Figures 15.6.3-10 and 15.6.3-11 for the ruptured and intact steam generators, respectively, for the time period until leakage 1266 v:1D/020689 .12
Rlg Y~
YR
\ R
SHNPP FSAR termination. The mass releases calculated from the time of leakage termination unti 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and from 2-8 hours were also assumed to be released 1
to the atmosphere via the steam generator PORVs. The mass releases for the SGTR event for the 0-2 hour and 2-8 hour time intervals considered are presented in Table 15.6.3-3.
15.6.3.4 Offsite Radiation Dose Anal sis The evaluation of the radiological cons'equences of a steam generator tube rupture", assumes that the reactor has been operating at the Technical Specification limit for primary coolant activity and primary to secondary leakage for sufficient time to establish equi librium concentrations of radionuclides in the reactor coolant and in the secondary coolant.
Radionuclides from the primary coolant enter 'the steam generator, via the ruptured tube, and are released to the atmosphere through the steam generator PORVs (and safety valves) and via the condenser vacuum pump exhaust.
The quantity of radioactivity released to the environment, due to a SGTR, depends upon primary and secondary coolant activity, iodine spiking effects, primary to secondary break flow, break flow flashing fractions, attenuation of iodine. carried by the flashed portion of the break flow, partitioning of iodine between the liquid and steam phases, the mass of fluid released from the generator, and liquid-vapor partitioning in the turbine condenser hot well. All of these parameters were conservatively evaluated in a manner consistent with the recommendations in Standard Review Plan 15.6.3.
- l. Desi n Basis Anal tical Assum tions The major assumptions and parameters used in the analysis are itemized in Table 15.6.3-4.
- 2. Source Term Calculations The radionuclide concentrations in the SHNPP primary and secondary system, prior to and following the SGTR were determined as follows:
1266v:1D/020689 13
lt f1
SHNPP FSAR
- a. The iodine concentrations in the reactor coolant will be based upon preaccident -and accident initiated iodine spikes.
- i. Accident Initiated Spike - The initial primary coolant iodine concentration is 1 pCi/gm of Dose Equivalent (D.E.) I-131.
Following the primary system depressurization associated with the SGTR, an iodine spike is initiated in the primary system which increases the iodine release rate from the fuel to the coolant to
, a value 500 times greater than the release rate corresponding to the initial primary system iodine concentration.
ii. Preaccident Spike - A reactor transient has occurred prior to the SGTR and has raised the primary coolant iodine concentration from 1 to 60 pCi/gram of D.E. I-131.
- c. The chemical form of iodine in the primary and. secondary coolant is assumed to be eleme'ntal.
- d. The initial noble gas concentration in the reactor coolant are based upon 1% fuel defects.
- 3. Dose Calculations The iodine transport model utilized in this analysis was proposed by Postma and Tam (Reference 2). The model considers break flow flashing, droplet size, bubble scrubbing, steaming, and partitioning. The model assumes that a fraction of the iodine carried by the break flow becomes airborne immediately due to flashing and atomization. Removal credit is taken for scrubbing of iodine contained in the atomized coolant droplets when the rupture site is below the secondary water level. The fraction of primary coolant iodine which is not assumed to become airborne immediately mixes with the secondary water and is assumed to become'irborne at a rate 1266v:1D/020689 14
l0 SHNPP FSAR proportional to the steaming rate and the iodine partition coefficient.
This analysis conservatively assumes an iodine partition coefficient of, 100 between the steam generator liquid and steam phases when the rupture site is covered. The model takes no scrubbing or mixing credit when the rupture site is above the secondary water level. Oroplet removal by the dryers is conservatively assumed to be negligible. The iodine transport model is illustrated in Figure 15.6.3-12.
The following assumptions and parameters were used to calculate the activity released to the atmosphere and the offsite doses following a SCTR.
- a. The mass of reactor coolant discharged into the secondary system through the rupture and the mass of steam released from the ruptured and intact steam generators to the atmosphere are presented in Table 15.6.3-3.
- b. The time dependent fraction of rupture flow that flashes to steam and is immediately released to the environment is presented in Figure 15;6.3-13. The break flow flashing fraction was conservatively calculated assuming that 100 percent of the break flow comes from the hot leg side of the steam generator, whereas the break flow actually comes from both the hot leg and cold leg sides of the steam generator.
- c. In the iodine transport model, the time dependent iodine removal efficiency for scrubbing of steam bubbles as they rise from the rupture site to the water surface conservatively assumes tnat the rupture is located at the intersection of the outer tube row and the upper anti-vibration bar. However, the tube rupture break flow was conservatively calculated assuming that the break is at the top of the
. tube sheet. The water level relative to the top of the tubes in the ruptured and intact steam generators is shown in Figure 15.6.3-14.
The iodine scrubbing efficiency is determined by the method suggested by Postma and Tam (Ref. 2). The iodine scrubbing efficiencies are shown in Figure 15.6.3-15.
1266v:1D/020689 15
I r
~ l 0 ~%i
>~
F~
SHNPP FSAR
- d. The rupture site is considered to be uncovered when the secondary water level is less than approximately 12 inches over the rupture site, which, as stated above, is assumed to be at the intersection of the outer tube row and the upper anti-vibration bar (approximately 3 inches below the apex of tube bundle). During the time that the rupture site is uncovered (from approximately 75 to 150 seconds), all of the activity carried by the break flow is assumed to be directly released to the environment, i.e., the activity carried by the break flow will neither mix with the secondary water nor partition.
- e. The total primary to secondary leak rate is assumed to be 1.0 gpm as allowed by the SHNPP Technical Specifications. The leak rate is assumed to be 0.35 gpm for each of the intact steam generators and 0.30 gpm for the ruptured steam generator.
- f. The iodine partition coefficient between the liquid and steam of the ruptured and intact steam generators is assumed to be 100 during the time that, the rupture (or leakage) site is covered.
- g. No credit was taken for radioactive decay during release and transport, or for cloud depletion by ground deposition during transport to the site boundary or outer boundary of the low population zone.
- h. Short-term atmospheric dispersion factors (x/Qs) for accident analysis and breathing rates are provided in Table 15.6.3-8. The breathing rates were obtained from NRC Regulatory Guide 1.4, (Ref. 3).
4.'ffsite Th roid Dose Calculation Hodel Offsite thyroid doses are calculated using the equation:
Th DCF. (IAR).. (BR} (x/Q}
1 J 1266v:10I020689
I Q
~
'~$ l~
SHNPP FSAR where:
(IAR) . ,
= integrated activity of isotope i'eleased during the time interval j in Ci*
(BR) . breathing rate during time interval j in meter 3 /second (Table 15.6.3-8)
(x/Q) ~
atmospheric dispersion factor during time interval j
'n second/meter 3 (Table 15.6.3-8)
DCF- thyroid dose conversion factor via inhalation for isotope i in rem/Ci (Table 15.6.3-9)
Th thyroid dose via inhalation in rem Offsite whole-body gamma doses are calculated using the equation:
= 0.25 IAR i . (x/Q).
D EFi 1
where:
(IAR) integrated activity of noble gas nuclide i released.
during time interval j in Ci "
(x/Q) . atmospheric dispersion factor during time interval j in seconds/m
- No credit is taken for cloud depletion by ground deposition or by radioactive decay during transport to the exclusion area boundary or to the outer boundary of the low-population zone.
1266v:10/020689 17
I 4
SHNPP FSAR average gamma energy for noble gas nuclide i in Mev/dis (Table 15.6.3-10) whole-body gamma dose due to immersion in rem Offsite beta-skin doses are calculated using the equation:
0>
= 0.23 E>i (IAR)1. (x/Q).
1 J where:
(IAR)i . integrated activity of noble gas nuclide i released during time interval j in Ci "
(x/Q)~ atmospheric dispersion factor during time interval -
j in seconds/m average beta energy for noble gas nuclide i'n Mev/dis (Table 15.6.3-10) 0( beta-skin dose due to immersion in rem
- No credit is taken for cloud depletion by ground deposition or by radioactive decay during transport to the exclusion area boundary or to the outer boundary of the low-population zone.
1266v:10/020689 18
I SHNPP FSAR
- 5. Results Thyroid, whole-body gamma, and.beta-skin doses at the Exclusion Area 8oundary and Low Population Zone are presented in Table 15.6.3-11.
All doses are well within the allowable guidelines as specified by Standard Review Plan 15.6.3 and 10CFR100.
1266v:1D/020689
,pr
SHNPP FSAR 15.6.3.5 References
- 1) Holderbaum, D. F., Lewis, R. N., and Rubin, K., "LOFTTR2 Analysis for A Steam Generator Tube Rupture - Shearon Harris Nuclear Power Plant",
MCAP-11703 (Proprietary)/MCAP-11704 (Non-Proprietary), January 1988.
- 2) Postma, A. K., Tam, P. S., "Iodine Behavior in a PMR Cooling System Following a Postulated Steam Generator Tube Rupture", NUREG-0409.
- 3) NRC Regulatory Guide 1.4, Rev. 2, ".Assumptions Used for Evaluating the Potential Radiological Consequences of a LOCA for Pressurized Mater Reactors", June 1974.
- 4) NRC Regulatory Guide 1. 109, Rev. 1, "Calculation of Annual Doses to Man From Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50 Appendix I", October 1977.
- 5) Bell, M. J., "ORIGEN - The ORNL Isotope Generation and Depletion Code",
ORNL-4628, 1973.
1266v:1O/020669 20
IW
~%
4 0
SHNPP FSAR TABLE 15.6.3-1 OPERATOR ACTION TIMES FOR DESIGN BASIS SGTR ANALYSIS Action Time min Identify and isolate ruptured SG 10 min or LOFTTR2 calculated time to reach 30% narrow range level in the ruptured SG., whichever is longer Operator action time to initiate cooldown Cooldown Calculated by LOFTTR2 Operator action time to initiate 5.5 SI termination without having pressurizer pressure control SI termination and pressure Calculated by LOFTTR2 equalization 1 266 v:10/020689 21
SHNPP FSAR
'ABLE 15.6.3-2 SEQUENCE OF EVENTS EVENT TIME sec SG Tube Rupture Reactor Trip 38.6 Safety Injection 228.4 Ruptured SG Isolated 602.0 Ruptured SG PORV Fails Open 604 Ruptured SG PORV Block Valve Closed 1806 RCS Cooldown Initiated 2108 RCS Cooldown Terminated 3168 SI Terminated 3504 Break Flow Terminated 4406 1266v:1D/020689 22
SHNPP FSAR TABLE 15.6.3-3 MASS RELEASE RESULTS TOTAL MASS FLOW (POUNDS) 0 - 2 HRS 2 - SHRS Ruptured SG Condenser 45,500 Atmosphere 107,300 37,100 Fee'dwater 90,500 Intact SGs Condenser 90,300 Atmosphere 387,000 766,200 Feedwater 573,600 772,400 Break Flow 200,700 1 266 v:1D/020689 23
SHNPP FSAR TABLE 15.6.3-4 PARAMETERS USED IN EVALUATING RADIOLOGICAL CONSEQUENCES I. Source Data A. 'Core power level, MHt 2785 B. Total steam generator tube 1.0 leakage, prior to accident, gpm C. Reactor coolant iodine activity:
- 1. Accident Initiated Spike The initial RC iodine activities based on 1 pCi/gram of D.E. I-131 are presented in Table 15.6.3-5. The iodine appearance rates assumed for the accident initiated spike are presented in Table 15.6,3"6.
- 2. Pre-Accident Spike Primary coolant iodine activities based on 60 uCi/gram of D.E. I-131 are presented in Table 15.6.3-5
- 3. Noble Gas Activity The initial RC noble gas activities based on 1%
fuel detects are presented in Table 15.6.3-7 1 266 v:1D/020689 24
p:
~~ t
SHNPP FSAR TABLE 15.6.3-4 (Sheet 2)
.D. Secondary system initial activity Dose equivalent of 0.1 yCi/gm of I-131, presented in Table 15.6.3-5 E. Reactor coolant mass, grams 1.8 x 10 I
F. Initial steam generator water mass 3.64 x 10 (each), grams G. Offsite power Lost at time of reactor trip H. Primary-to-secondary leakage duration for intact SG, hrs.
I. Species of iodine 100 percent elemental II. Activity Release Data A. Ruptured steam generator
- 1. Rupture flow See Table 15.6.3-3 1
- 2. Rupture flow flashing fraction See Figure 15.6.3-13
- 3. Iodine scrubbing efficiency See Figure 15.6.3-15
- 4. Total steam release, lbs See Table 15.6.3-3
- 5. Iodine partition factor 100 when rupture site is covered
- 6. Location of tube rupture Intersection of outer tube row and upper anti-vibration bar 1266v:1D/020889 25
SHNPP FSAR TABLE 15.6.3-4 (Sheet 3)
B. Intact steam generators
- 1. Total primary-to-secondary 0,7 leakage, gpm
- 2. Total steam release, lbs See Table 15.6.3-3
- 3. Iodine partition factor 100 when leakage site is covered C. Condenser
- 1. Iodine partition factor 100 D. Atmospheric Dispersion Factors See Table 15,6.3-8 1266v:1D/020689 26
SHNPP FSAR TABLE 15.6.3-5 IODINE. SPECIFIC ACTIVITIES IN THE PRIMARY AND SECONDARY COOLANT BASED ON 1, 60 AND 0. 1 uCi/ ram OF D.E. I-131 S ecific Activit uCi/ m .
~Pi C Secondar Coolant Nucl ide ~lwC i/ m 60 wCi/c0m ~0.1 uCi/ m 0.77 45.9 0.077 0.79 47.5 0.079 1.14 68.1 0.114 I-134 9.5 0.016 I-135 36.4 0.061 1266v:1D/020689
SHNPP FSAR TABLE 15.6.3-6 IODINE SPIKE APPEARANCE RATES (CURIES/SECOND)
I-131 I-132 I-133 1.36 7.35 2.87 3.39 1266v:10/020689 28
SHNPP FSAR TABLE 15.6.3-7 NOBLE GAS SPECIFIC ACTIVITIES IN THE REACTOR COOLANT BASED ON 1% FUEL DEFECTS Nuclide S ecific Activit gCil m Xe-131m 2.3 Xe-133m 18.0 Xe-133 280.0 Xe-135m '0.5 Xe-135 7.7 Xe-138 .
0.67 Kr-85m 2.1 Kr-85 7.7 Kr-87 1.3 Kr-88 3.8 1266v:1D/020689 29
SHNPP FSAR TABLE 15.6.3-8 ATMOSPHERIC DISPERSION FACTORS AND BREATHING RATES Time Exclusion Area Boundary Low Population Breathing Rate 3
(hours) x/Q (Sec/m ) Zone x/Q (Sec/m ) (m /Sec) [Ref. 3]
0-2 6.17 x 10 l.'4 x 10 3.47 x 10 2-8 1.4 x 10 3.47 x 10 1 266 v:1D/020689 30
SHNPP FSAR TABLE 15.6,3-9 THYROID DOSE CONVERSION FACTORS (Rem/Curie) tRef. 4]
Nuclide I-131 1.49 x 10 I-132 1.43 x 10 I-133 2.69 x 10 I-134 3.73 x 10 I-135 5.60 x 10 1266v:10/020689 31
4 OW SHNPP FSAR TABLE 15.6.3-10 AVERAGE GAMMA AND BETA ENERGY FOR NOBLE GASES (Mev/dis} [Ref. 5]
Nuclide Xe-131m 0.0029 0.165 Xe-133m 0.02 0.212 Xe-133 0.03 0.153 Xe-135m 0.43 0.099 Xe-135 0.246 0.325 Xe-138 1.2 0.66 Kr-85m 0.156 0.253 Kr-85 0.0023 0.251 Kr-87 0.?93 1.33 Kr-88 2.21 0.248 1266v:10/020689 ~
32
+1 4
SHNPP FSAR TABLE 15.6.3-11 OFFSITE RADIATION DOSES Doses Rem Calculated Allowable Value Guideline Yalue
- 1. Accident Initiated Iodine S ike Exclusion Area Boundary (0-2 hr.)
Thyroid Dose 20. 2" 30 Low Population Zone (0-8 hr.)
Thyroid Dose 4. 8 30 2, Pre-Accident Iodine S ike Exclusion Area Boundary (0-2 hr.)
Thyroid Dose 98,9 300 Low Population Zone (0-8 hr.)
Thyroid Dose 22,6 300
- 3. Whole-Bod Gamma and Beta-Skin Dose Exclusion Area Boundary (0-2 hr.)
Whole-Body Gamma Dose 0.2 2 5k Beta-Skin Dose 0.6 5*
Low Population Tone (0-8 hr.)
Whole-Body Gamma Dose 0.1 2 5*
Beta-Skin Dose 0.1 2.5+
"Assumed to apply to the sum of the whole-body gamma and beta-skin doses.
1266 v:1D/020669 33
/r>
P S SHEARON HARRlS STEAf1 GENERATOR TUBE RUPTURE 70.
60
'0.
W FV 40 '
C 30.
N
~ 20.
10
- 0. 1000. 2000. 3000. 4000.
TIME (SEC)
Figure 15.6.3-1 Pressure.zer Level
SHEARON HARRIS STEAM GENERATOR TUBE RUPTURE 2300
'100
'900
'4 N
R 1700.
F4 Qc N
O 1500.
C4 1300 ~
1100.
0~ 1000 2000. 3000. 4000.
TIME (SEC)
Figure 15.6.3-2 RCS Pressure 35
4 oar SHEARON HARR1S STEAl1 GENERATOR TUBE RUPTURE 1400.
1200 ~
RUPTURED SG 1000.
800.
600.
A O
O 400. INTACT SG 200.
0.
- 0. 1000. 2000. 3000. 4000.
TIME (SEC)
Figure 15.6.3-3 Secondary Pressure 36
h>
t
SHEARON HARRIS STEAI1 GENERATOR TUBE RUPTURE 650-600.
Thot O 550.
3 Tcold O
< 500.
M
~ 450.
> 400.
0 0
350.
300 '. 1000. 2000. 3000 4000.
TIME (SEC)
Figure 15.6.3-4 Intact Loop Hot and Cold Leg RCS Temperatures 37
SHEARON 'HARRIS STEAI1 GENERATOR TUBE RUPTURE 650.
t 600.
O 3 550. Thot A
g 500. Tcold o+ 450.
pt Q 400.
00 350.
300.
- 0. 1000. 2000. 3000. 4000.
TIME (SEC)
Figure 15.6.3-5 Ruptured Loop Hot and Cold Leg RCS Temperatures 38
SHEARON HARRIS STEAf1 GENERATOR'TUBE RUPTURE 1400.
1200.
1000.
H TQ 800.
U R
600.
,O 4pp 200.
0.
-200
- 0. 1000. 2000. 3000. 4000.
TIME (SEC)
Pigure 15.6.3-6 Differential Pressure Betveen RCS and Ruptured SG 39
f ~
b, 4q
SHEARON HARRIS STEAI1 GENERATOP. TUBE RUPTURE 70.
60.
o 50.
N U) 40.
3 30.
20 ~
10-0
-10 ~
- 0. 1000. 2000. 3000. 4000.
TIME (SEC)
Figure I 15.6.3-7, Primary to Secondary Break Flov Rate 40
~ ~
P' '
SHEARON HARRIS STEAM GENERATOR TUBE RUPTURE 5000.
4500.
5 4000.
0 ra 3500.
g 3000 ~
+ 2500 ~
R 2000.
1500 '
~ 1000. 2000 3000. 4000.
TIME (SEC)
Figure 15.6.3-8 Rupture6 SG Mater Valume
I C' SHEARON HARRIS STEAt1 GENERATOR TUBE RUPTURE 220000.
180000.
140000.
100000.
60000.
0~ 1000. 2000. 3000 4000.
TIME (SEC)
Figure 15.6.3-9 Ruptured SG Water Mass 42
e ~
~ III
SHEARON HARRlS STEAl1 GENERATOR. TUBE RUPTURE o 700 W
(0 A 600.
pg 500.
g 400.
o
~
IX 300.
o .200.
U 100.
g)
R 0 0 1000. 2000. 3000. 4000 TIME (SEC)
Figure 15.6.3-10 Ruptured SG Mass Release Rate to the Atmosphere 43
SHEARON HARR1S STEATO GENERATOR TUBE RUPTURE 1400.
o N
~ 1200.
à Q 1000.
fV 800.
o 600.
C 400>>
0 200.
R H 0.
0 1000. 2000. 3000. 4000.
TIME (SEC)
Figure 15.6.3-11 Intact SGs Mass Release Rate to the Atmosphere 44
SHHPP FSAR DROPLETS NOT SCRUBBED FLASH SCRUBBING INTO VAPOR 4 PRIMARY IS DROPLETS S BREAK SCRUBBED T COVERED DROPS E
'WATER A A M T SECONDARY M
WATER S 0 P S NO A P C H E E FLASH R INTO -E VAPOR 4 DROPLETS SPRAY BREAKUP INTO DROPS
- PARTITION Figure '15.6.3-12 @dine Transport Model
SHEARON HARRIS STEAM GENERATOR TUBE RUPTURE
..18 0 16 N ~
.14 g
U .12 H
.10
~
~
3
~ .06 m .04
.02 0~
0~ 1000. 2000 '000 '000.
TIME (SEC)
Figure 15.6.3-13 Break Flov Flashing Fraction 46
P
SHEARON HARR 1 S S7EAl1 GENERATOR TUBE RUPTURE 250.
RUPTUEKD SG 200.
0 Ov 0
150.
0 XHTACT SG g 100.
C 50 0 ~
0 1000. 2000. 3000. 4000.
TIME (SEC)
Figure 15.6.3-14 SG Water Level Above Top of Tubes
VQ
'V
SHHPP FSAR
.05 SHEARON HARRIS STEAt1 GENERATOR TUBE RUPTURE
.04 0
.03 0
M P4 Q
fA IXI O
N
~ 01 0
- 0. 500 '000. 1500. 2000. 2500. 3000.
TXME (SEC)
Figure 15.6.3-15 Iodine Scruhhing Efficiency 48
H P f"
P
~15
~,
t,<
4
~J ry.
s ff
15.6.5
~ ~ MAJOR REACTOR COOLANT SYSTEM PIPE RUPTURES (LOSS OF COOLANT ACCIDENT) 15.6.5.1 Identification of Causes and Fre uenc Classification A loss-of-coolant accident (LOCA) is the result of a pipe rupture of the RCS pressure boundary. For the analyses reported here, a major pipe break (large break) is defined as a rupture with a total cross-sectional area equal to or greater than 1.0 ft . This event is considered an ANS Condition IV event, a limiting fault,'n that it is not expected to occur during the lifetime of Shearon Harris, but is postulated as a conservative design basis. A minor pipe break (small break) is defined as a rupture of the reactor coolant pressure boundary with a total cross-sectional area less than 1.0 ft. in which the normally operating charging system flow is not sufficient to sustain pressurizer level and pressure. This is considered a ANS Condition III event in that it is an infrequent fault that may occur during the'ife of the plant.
The Acceptance Criteria for the LOCA are described in 10 CFR 50.46 (10 CFR 50.46 and Appendix K of 10 CFR 50 1974) as follows:
- 1. The calculated peak fuel element clad temperature is below the requirement of 2,200'F.
- 2. The amount of fuel element cladding that reacts chemically with water or steam does not exceed 1 percent of the total amount of Zircaloy in the reactor.
- 3. The clad temperature transient is terminated at a time when the core geometry is still amenable to cooling. The localized cladding oxidation limit of 17 percent is not exceeded, during or after quenching.
- 4. The core remains amenable to cooling during and after the break.
- 5. The core temperature is reduced and decay heat is removed for an extended period of time, as required by the long-lived radioactivity remaining in the core.
1582v:10/100788-30
,~
>'i<
tT 7
These criteria were established to provide significant margin in emergency core cooling system (ECCS) performance following a LOCA. MASH-1400 (USNRC 1975) (10) presents a recent study in regards to the probability of occurrenceof RCS pipe ruptures.
In all cases, small breaks (less than 1.0 ft. ) yield results with more margin to the acceptance criteria limits than large break.
15.6.5.2 Se uence of Events and S stems erations Should a major break occur, depressurization of the RCS results in a pressure decrease in the pressurizer. The reactor trip signal subsequently occurs when the pressurizer low pressure trip setpoint is reached. A safety injection signal is generated when the appropriate setpoint is reached. These countermeasures will limit the consequences of the accident in two ways:
- 1. Reactor trip and borated water injection supplement void formation in causing rapid reduction of power to a residual level corresponding to fission product decay heat. However, no .credit is taken in the LOCA analysis for the boron content of the inject>on water. In addition, the insertion of control rods to shut down the reactor is neglected in the large break analysis.
- 2. Injection of borated water provides for heat transfer from the core and prevents excessive clad temperatures.
In both large and small break LOCA analyses loss-of-offsite power coincident with the accident is assumed. The single failure in defining SI flow rates subsequently considered is the loss of an RHR pump for the large break and the loss of a diesel generator for the small break; thus, only a portion of the ECCS flow actually present is considered to be available. Therefore, for both large and small break LOCAs, ECCS flow to the core is at a conservatively low value following its automatic actuation, especially since all water delivered to the broken loop is considered to spill directly to the containment sump.
Notwithstanding these conservatisms, conformance with the 10CFR50.46
~I 1582v:10/100788-31
\
(
t~
)Q' I
acceptance criteria is demonstrated in the large and small break LOCA analyses. No other postulated single failure would have as great an effect on ECCS flow delivery.
Single failures do not have a significant effect on final containment water levels following a postulated LOCA.
The ECCS termination and reinitiation criteria provided in the Harris Plant Emergency Operating Procedures (EOP's) are designed to minimize any possibility of an operator error to 'improperly or prematurely shut off safety injection from challenging core cooling. Termination criteria for high pressure safety injection flow (HPI) following a LOCA event call for a shutoff of all HPI when the RCS pressure is stable or increasing and subcooling exists, .the pressurizer level is on span plus errors and steam generators are being fed auxiliary feedwater or have indicated level above the U-tubes. For a break as small as a 0.5" equivalent diameter hole, as soon as the HPI is terminated, a rapid depressurization of the system occurs. EOPs will direct the operator to immediately reinitiate safety injection and to perform a controlled cooldown with SI flow, thereby ensuring that the core wi 11 remain covered and adequately cooled.
Any break postulated to occur in the ECCS line is bounded by the spectrum of breaks presented in the FSAR. Standard assumptions used in defining safety include:
- 1) The spilling of the the broken loop accumulator directly to containment.
. 2) -
The spilling of the safety injection line attached to the broken cold leg.
- 3) A single failure condition such that only one train of safety injection pumps operates for Small Break, only one RHR pump for Large Break.
1582v:1D/100788-32
a
~,1t
~ I, e,
iJ 4
'4
Each of the three RCS cold legs has an injection line attached. Flow delivered into the RCS is computer based on the following logic:
The limiting combination of ECCS pumps for each accident as described above is modelled to start and deliver flow into the reactor coolant system through two branch injection lines.
One branch injection line spills to containment backpressure. - The branch injection line with minimum system resistance is selected to spill to minimize delivery to the core.
The flow delivered into the reactor through the reactor coolant pump seals is assumed to be lost and, therefore, seal injection is not included in the total core delivery.
Safety injection flows computed via this methodology are conservatively low for any postulated break location.
Descri tion of Lar e Break Loss-of-Coolant Accident Transient The sequence of events following a large break LOCA is presented in Table 15.6.5-1; Before the break occurs, the unit is in an equilibrium condition; that is, the heat generated in the core is being removed via the secondary system. During blowdown, heat from fission product decay, hot internals and the vessel, continues to be transferred to the reactor coolant. At the beginning of the blowdown phase, the entire RCS contains subcooled liquid which transfers heat from the core by forced convection with some fully developed nucleate boiling. After the break develops, the time to departure from nucleate boiling is calculated, consistent with Appendix K of 10 CFR 50.
Thereafter the core heat transfer is unstable, with both nucleate boiling and film boiling occurring. As the core becomes uncovered, both turbulent and laminar forced convection and radiation are considered as core heat transfer mechanisms.
1582v:1D/100788-33
g I
4M J I I" 4 p Ni I-
'N gA) w,4
'b 4b
The heat 'transfer between the RCS and the secondary system may be in either direction, depending on the relative temperatures. In the case of continued heat addition to the secondary, the secondary system pressure increases and the main steam safety valves may actuate to limit the pressure. Hakeup water to the secondary side is automatically provided by the auxiliary feedwater system. The safety injection signal actuates a feedwater isolation signal which isolates normal feedwater flow by closing the main feedwater isolation valves, and also initiates emergency feedwater flow by starting the auxiliary feedwater pumps. The secondary flow aids in the reduction of RCS pressure.
When the RCS depressurizes to 600 psia, the accumulators begin to inject borated water into the reactor coolant loops. The conservative assumption is made that accumulator water injected bypasses the core and goes out through
'he break until the termination of bypass. This conservatism is again consistent with Appendix K of 10CFR50. Since loss of offsite power (LOOP) is assumed, the RCPs are assumed to trip at the inception of the accident.
Previous sensitivity studies have demonstrated the conservatism of this assumption for the large break LOCA analyses. The effects of pump coastdown are included in the blowdown analysis.
The blowdown phase of'he transient ends when the RCS pressure (initially assumed at 2280 psia) falls to a value approaching that of the containment atmosphere. Prior to or at the end of the blowdown, the mechanisms that are responsible for the emergency core cooling water injected into the RCS bypassing the core are calculated not to be effective. At this time (called end-of-bypass) refill of the reactor vessel lower plenum begins. Refi.ll is completed when emergency core cooling water has filled the lower plenum of the reactor vessel, which is bounded by the bottom of the fuel rods (called bottom of core recovery time).
The reflood phase of the transient is defined as the time period lasting from the end-of-refill until the reactor vessel has been filled with water to the extent that the core temperature rise has been terminated. From the latter stage of. blowdown and then the beginning of reflood, the safety injection 1582v:1D/100788-34
+t
\
"4
accumulator tanks rapidly discharge borated cooling water into the RCS, contributing to the filling of the reactor vessel downcomer. The downcomer water elevation head provides the driving force required for the ref looding of the reactor core. The RHR (low head) and charging (high head) pumps aid in the filling of the downcomer and subsequently supply water to maintain a full downcomer and complete the reflooding process.
Continued operation of the ECCS pumps supplies water during longterm cooling.
Core temperatures have been reduced to longterm steady state levels associated with dissipation of residual heat generation. After the water level of the residual water storage tank (RHST) reaches a minimum allowable value, coolant for long-term cooling of the core is obtained by'switching to the cold leg recirculation phase of operation, in which spilled borated water is drawn from the engineered safety features (ESF) containment sumps by the low head safety injection (residual heat removal) pumps and returned to the RCS cold legs.
The Containment Spray System continues to operate to further reduce containment pressure.
Approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after initiation of the LOCA, the ECCS is realigned to supply water to the RCS hot legs in order to control the boric acid concentration in the reactor vessel.
Descri tion of Small Break LOCA Transient Ruptures of very small cross. section will cause expulsion of the coolant at a rate which can be accommodated by the charging pumps which would maintain an operational water level in the pressurizer, permitting the operator to execute an orderly shutdown. The coolant which would be released to the containment contains the fission products existing in it.
The maximum break size for which the normal makeup system can maintain the pressurizer level is obtained by comparing the calculated flow from the reactor coolant system through the postulated break against the charging pump makeup flow at normal reactor coolant system pressure, i.e., 2250 psia. A 1582v:10/100788-35
'tW
,4 ( ~
I l
~1 ftv
makeup flow rate from one centrifugal charging pump is adequate to sustain pressurizer level at 2250 for a break through an approximately 3/8 inch diameter hole. This break results in a loss of approximately 17.5 lb//sec..
Should a larger break occur, depressurization of the reactor coolant system causes fluid to flow to the reactor coolant system from the pressurizer, resulting in a pressure and level decrease in the pressurizer. Reactor trip occurs when the pressurizer low pressure trip setpoint is reached. The safety injection system is actuated when the appropriate setpoint is reached.
As contrasted with the large break, the blowdown phase of the small br'eak occurs over a longer time period. Thus, for the small break LOCA there are only three characteristic stages, i.e,, a gradual blowdown in which the decrease in water level is checked, core recovery, and long-term recirculation.
15.6.5.3 Core and S stem Performance
~
15.6.5.3.1
~ ~
~I
~
~
Mathematical Model: I1 The requirements of an acceptable ECCS evaluation model arh presented in Appendix K of 10 CFR 50 (Federal Register 1974).
Lar e Break LOCA Evaluation Model The analysis of a large break LOCA transient is divided into three phases:
(1) blowdown, '(2) refill, and (3) reflood. There are three distinct transients analyzed in each phase, including the thermal-hydraulic transient in the RCS, the pressure and temperature transient within the containment, and the fuel and clad temperature transient of the hottest fuel rod in the core.
Based on these considerations, a system of interrelated computer codes has been developed for the analysis of the LOCA.
A description of the various aspects of the LOCA analysis methodology is given by Bordelon, Massie, and Zordon (1974). (6) This document describes the major phenomena modeled, the interfaces among the com'uter codes, and the 1582v:1D/100788-36
P.I
~W
features of the codes which ensure compliance with the Acceptance Criteria.
The SATAN-VI, NREFLOOD, BASH, LOCBART, and COCO codes, which are used in the LOCA analysis, are described in detail by Bordelon et al. (1974) ; Kelly et al. (1974); (9). Young et al. (1987)( '; Bordelon and Murphy (1974) (3) . Code modifications are specified in References 2, 7 and 14.
These codes assess the core heat transfer geometry and determine if the core remains amenable to cooling throughout and subsequent to the blowdown, refill, and reflood phases of the LOCA. The SATAN-VI computer code analyses the thermal-hydraulic transient in the RCS during blowdown and the WREFLOOD computer code calculates this transient during the refill phase of the accident. The BASH code is used to determine the system response during the reflood phase of the transient. The COCO code is used for the complete containment pressure history during all three phases. The LOCBART computer code calculates the thermal transient of the hottest fuel rod during the three phases. The Revised Pad Fuel Thermal Safety Model, described in Reference the initial fuel rod conditions input to LOCBART. 14,'enerates SATAN-VI calculates the RCS pressure, enthalpy, density, and the mass and energy flow rates in the RCS, as well as steam generator energy transfer between the primary and secondary systems as a function of time during the blowdown phase of the LOCA. SATAN-VI also calculates the accumulator water mass and internal pressure and the pipe break mass and energy.-flow rates that are assumed to be vented to the containment during blowdown. At the end of the blowdown, information on the state of the system is transferred to the NREFLOOD code which performs the calculation of the refill period to bottom of core (BOC) recovery time. Once the vessel has refilled to the bottom of the core, the reflood portion of the transient begins. The BASH code is used to calculate the thermal-hydraulic simulation of the RCS for the reflood phase.
Information concerning the core boundary conditions is taken from all of the above codes and input to the LOCBART code for the purpose of calculating the core fuel rod thermal response for the entire transient. From the boundary conditions, LOCBART computes the fluid conditions and heat transfer 1582v:1D/100788-37
'4 II
~
i-l 7j, 4
'\-
p.l
coefficient for the full length of the fuel rod by employing mechanistic models appropriate to the actual flow and heat transfer regimes. Conservative assumptions ensure that the fuel rods modeled in the calculation represent the hottest rods in the entire core.
The containment pressure analysis is performed with the COCO code , which is interactive with the WREFLOOD code. The transient pressure computed by the COCO code is then input to the BASH code for the purpose of supplying a backpressure at the break plane while computing the reflood transient.
The large break analysis was performed with the December 1981 version of the Evaluation Model modified to incorporate the BASH computer code.
Small Break LOCA Evaluation Model The NOTRUMP computer code is used in the analysis of loss-of-coolant accidents due to small breaks in the Reactor Coolant System. The NOTRUMP computer code is a state-,of-the-art one-dimensional general network code consisting of a number of advanced features. Among these features are the calculation of thermal non-equi librium in all fluid volumes, flow regime-dependent drift flux calculations with counter-current flooding limitations, mixture level tracking logic in multiple-stacked fluid nodes, and regime-dependent heat transfer correlations, The NOTRUMP small break LOCA emergency core cooling'system (ECCS) evaluation model was developed to determine the RCS response to design basis small break LOCAs and to address the NRC concerns expressed in NUREG-0611, "Generic Evaluation of Feedwater Transients and Small Break Loss-of-Coolant Accidents in Westinghouse Designed Operating Plants."
In NOTRUMP, the RCS is nodalized into volumes interconnected by flowpaths.
The broken loop is modeled explicitly with the intact loops lumped into a second loop. The transient behavior of the system is determined from the governing conservation equations of mass, energy and momentum applied throughout the system. A detailed description of NOTRUMP is given in References 20 and 21.
1582v:1D/100788"38
Pr, f
k H
The use of NOTRUMP in the analysis involves, among other things, the representation of the reactor core as heated control volumes with an associated bubble rise model to permit a transient mixture height calculation. The multinode capability of the program enables an explicit and detailed spatial representation of various system components. In particular, it enables a proper calculation of the behavior of the loop seal during a loss-of-coolant transient.
Cladding thermal analyses are performed with the LOCTA-IV code which uses the RCS pressure, fuel rod power history, steam flow past the uncovered part of the core, and mixture height history from the NOTRUMP hydraulic calculations, as input.
The small break analysis was performed with the approved Westinghouse ECCS Small Break Evaluation Hodel 15.6.5.3.2 Input Parameters and Initial Conditions:
Table 15.6.5-2 lists important input parameters and initial conditions used in the analysis. The analysis presented in this section was performed with a reactor vessel upper head temperature equal to the RCS cold leg temperature.
The bases used to select the numerical values that are input parameters to the analysis have been conservatively determined from extensive sensitivity studies (Westinghouse 1974((12). '; Salvatori 1974( '; Julian 1976 ).
In addition, the requirements of Appendix K regarding specific model features were met by selecting models which provide a significant overall conservatism in the analysis. The assumptions which were made pertain to the conditions of the reactor and associated safety system equipment at the time that the LOCA occurs, and include such items as the core peaking factors, the containment pressure, and the performance of the ECCS. Decay heat generated throughout the transient is also conservatively calculated.
1582v:1D/101088-39
e Q
yV si'1 5
15.6.5.3.3
~ ~ ~ ~ Results Lar e Break Results Based on the results of the LOCA sensitivity studies (Westinghouse 1974 Salvatori 1974 (11) ) the l,imiting large break was found to be the double ended cold leg guillotine (DECLG). Therefore, only the DECLG break is considered in the large break ECCS performance analysis. Calculations were performed for a range of Hoody break discharge coefficients. The results of these calc'ulations are summarized in Tables 15.6.5-1 and 15.6.5-3. The hot spot is defined to be the location of the maximum peak clad temperature. This location is given in Table 15.6.5-3 for each break size analyzed.
The mass and energy release data for the break resulting in the highest peak clad temperature are presented in Tables 6.2.1-59 and 6.2.1-60.
t Figures 15.6.5-4 through 15.6.5-30 present the parameters of principal interest from the large break ECCS analyses. For all cases analyzed transients of the following parameters are presented:
a) Hot spot clad temperature.
b) Coolant pressure in the reactor core.
c) Water level in the core and downcomer during reflood.
d) Core reflooding rate.
e) Thermal power during blowdown.
f) Containment pressure.
1582v:10/101088-40
L ip
()
For the limiting break analyzed, the following additional transient parameters
~ ~
are presented:
a) Core flow during blowdown (inlet and outlet).
b) Core heat Wansfar coefficients.
c) Hot spot fluid temperature.
d) Hass released to Containment during blowdown.
e) Energy released to Containment during blowdown.
f) Fluid quality in the hot assemhP~y during blowdown.
g) Hass velocity during blowdown.
h) Accumulator water flow rate during blowdown and reflood.
i) Pumped safety injection water flow rate during reflood.
The maximum clad temperature calculated for a large break is 2106'F which is less than the Acceptance Criteria limit of 2200'F. The maximum local metal-water reaction is 8.025 percent, which is well below the embrittlement limit of 17 percent as required hy 10 CFR 50.46. The total core metal-water reaction is less than 0.3 percent for all breaks, as compared with the 1 percent criterion of 10 CFR 50.46. The clad temperature transient is terminated at a time when the core geometry is stil'I amenable to cooling. As a result, the core temperature will continue to drop and the ability to remove decay heat generated in Qm fuel for an extended period of time will be provided.
1582v:1o/lOD7BBW1
l lb 9 II
'I~.-
'I I
I Small Break Results As noted previously, the calculated peak clad temperature resulting from a small break LOCA is less than that calculated for a large break. Based on the results of the LOCA sensitivity studies , the limiting small break was found to be less than a 10 in. diameter rupture of the RCS cold leg. In addition, sensitivity studies have indicated little or no uncovering will occur for break sizes that are 2 in. or less. A range of small break analyses are presented which establishes the limiting small break. The results of these analyses are summarized in Tables 15.6.5-4 and 15.6.5-5.
Figures 15.6.5-31 through 15.6.5-57 present the principal parameters of interest for the small break ECCS analyses. For all cases. analyzed the following transient parameters are presented:
a) Core pressure (psia) b) Core mixture (feet) c) Core Steam Flow (ibm/sec) d) Break Steam Flow (ibm/sec) e) Total System Mass (ibm) f) Hot Spot Vapor Temperature (F) g) Fuel Rod Heat Transfer Coefficient (Btu/ft hi) h) Hot Spot Clad Temperature (F)
Figure 15.6.5-56 gives the safety injection flowrate for the small, break analysis.
1582v:1D/100788-42
+AI 'e'
>e 4 '
rgb I
Figure 15.6.5-57 presents the hot rod power shape utilized to perform the" small break analysis presented here. This power shape was chosen because it provides an appropriate distribution of power versus core height and also local power is maximized in the 'upper regions of the reactor core (10 ft. to 12 ft.). This power shape is skewed to the top of the core with the peak local power occurring at the 10.0 ft. core elevation.
This is limiting for the small break analysis because of the core uncovery process for small breaks. As the core uncovers, the cladding in the upper elevation of the core heats up and is sensitive to the local power at that elevation. The cladding temperatures in the lower elevation of the core, below the two phase mixture height, remains low.'he peak clad temperature occurs above 10 ft; Schematic representations of the computer code interfaces are given in Figures.
15.6.5-2 and 15.6.5-3.
The maximum calculated peak clad temperature for all small breaks analyzed is 1780'F. These results are well below all acceptance criteria limits of 10 CFR 50.46 and in all cases are not limiting when compared to the results presented for large breaks.
'I A complete spectrum of Small Break Loss of Coolant Accidents were examined in Refer'ence 24. The studies in that report indicated the maximum PCT occurred for the 3" break, thus the PCT does increase as break size decreases for the FSAR cases, but then decreases as break sizes decrease below 3".
1582v:1D/100788-43
A
, r~L I
vi ~
T 7
t'I Q
pat jt 4
-N
REFERENCES FOR SECTION 15.6.5
- l. "Acceptance Criteria for Emergency Core Cooling System for Light Water Cooled Nuclear Power Reactors," 10 CFR 50.46 and Appendix K of 10 CFR 50, Federal Re ister 1974, Volume 39, Number 3.
- 2. Rahe, E. P. (Westinghouse), letter to J. R. Miller (USNRC), Letter No.
NS-EPRS-2679, November 1982.
- 3. Bordelon, F. M., and Murphy, E. T., "Containment 'Pressure Analysis Code (COCO)," WCAP-8327 (Proprietary), WCAP-8326 (Non-Proprietary), June, 1974.
- 4. Young, M. Y. et al, "The 1981 Version of the Westinghouse ECCS Evaluation Model Using the BASH Code," WCAP-10266-P.-A Rev. 2 (Proprietary), 1987.
- 5. Bordelon, F. M. et al., "SATAN-VI Program: Comprehensive Space, Time Dependent Analysis of Loss-of-Coolant," WCAP-8302 (Proprietary) and WCAP-8306 (Non-Proprietary), 1974.
- 6. Bordelon, F. M.; Massie, H. W.; and Zordon, T. A., "Westinghouse ECCS Evaluation Model - Summary," WCAP-8339, 1974.
7, Rahe, E. P., "Westinghouse ECCS Evaluation Model, 1981 Version,"
WCAP-9220-P-A (Proprietary Version), WCAP-9221-P-A (Non-Proprietary Version), Revision 1, 1981.
- 9. Kelly, R. D. et al., "Calculational Model for Core Reflooding After a Loss-of-Coolant Accident (WREFLOOD Code," WCAP-8170 (Proprietary) and WCAP-8171 (Non-Proprietary), 1974.
1582v:1D/100788-44
F'.
C$
~ip >" 'o dQ
- 10. U. S. Nuclear Regulatory Commission 1975, "Reactor Safety Study - An Assessment of Accident Risks in U. S. Commercial Nuclear Power Plant,"
MASH-1400, NUREG-75/014.
- 11. Salvatori, R., "Westinghouse ECCS - Plant Sensitivity Studies," WCAP-8340 (Proprietary)'nd MCAP-8356 (Non-Proprietary), 1974.
- 12. "Westinghouse ECCS Evaluation Model Sensitivity Studies," MCAP-8341 (Proprietary) and MCAP-8342 (Non-Proprietary), 1974.
- 13. "Bordelon, F. M., et al., "Westinghouse ECCS Evaluation Model-Supplementary Information," WCAP-8471 (Proprietary) and MCAP-8472 (Non-Proprietary), 1975.
- 14. Letter from J. F. Stoltz (NRC) to T. M. Anderson (Westinghouse),
Subject:
Review of WCAP-8720, Improved Analytical Models used in Westinghouse Fuel Rod Design Computations.
- 15. Julian, H. V., Tubone, C. J., Thompson, C. H. "Mestinghouse ECCS Three Loop Plant (17 x 17) Sensitivity Studies," WCAP-8853, September, 1976 (Non-Proprietary).
- 16. Salvatori, R., "Westinghouse ECCs Plant Sensitivity Studies," MCAP-8340 (Proprietary) and MCAP-8356 (Non-Proprietary), July, 1974.
- 17. "Report on Small Break Accidents for Westinghouse NSSS System, "MCAP-9600 (Proprietary) and WCAP-9601 (Non-Proprietary), June, 1979.
- 18. "Clarification of TMI Action Plan Requirements", NUREG-0737, November, 1980.
- 19. NRC Generic Letter 83-85 from D. G. Eisenhut, "Clarification of TMI Action Plan Item II.K.3.31", November 2, 1983.
1582v:1D/100788"45
'l f I
- 20. Meyer, P.~ E., "NOTRUMP - A Nodal Transient Small Break and General Network
~ ~
Code", WCAP-10079-P-A, August 1985.
- 21. Lee, N. et al., "Westinghouse Small Break ECCS Evaluation Model Using 'the NOTRUMP Code", WCAP-10054-P-A, August 1985.
- 22. Rupprecht, S. D., et al., "Westinghouse Small Break LOCA ECCS Evaluation Model Generic Study With the NOTRUMP Code"; WCAP-11145.
- 23. Bordelon, F. M., et. al. "LOCA-IV Program: Loss of Coolant Transient Analysis,",WCAP-8301, dune, 1974.
- 24. Lee, N., Tauche, W. D., Schwarz, W. R., "Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code," WCAP-10082-A, August 1985.
1582v:10/100788-46
TABLE 15.6.5-1 LARGE BREAK TIME SEQUENCE OF EVENTS DECLG CD 0 8 DECLG CD 0 6 DECLG (CD 0 ')
(Sec) (Sec) (Sec)
START 0.0 0.-0 0.0 Reactor Trip Signal .423 .428 .437 S. I., Signal .74 .84 1.03 Acc. Injection 8.99 11.30 15.40 End of Blowdown 19.93 22.54 29.46 End of Bypass 19.93 22.54 29.46 Pump Injection 27.74 27.84 28.03 Bottom of Core Recovery 32.358 34,853 42.37 Acc. Empty 43.100 45.823 50.897 1582v:1D/100788-47
o+
7A k PY
>>P Cg
'pg I
Cg
TABLE 15.6.5-2 INPUT PARAMETERS USED IN THE ECCS ANALYSIS Core Power~ 2775 Mwt Peak Linear Power (Includes 102% factor) 13.607 kM/ft. (Large Break) 13.263 kW/ft. (Small Break)
Total Peaking Factor, F~ 2.45 (Large Break) 2-,50 (Small Break)
Axial Peaking Factor, FZ 1.4848 (Large Break) 1.5152 (Small Break)
Power Shape Large break - chopped cosine Small Break - See Figure 15.6.5-57 Full Assembly Array 17 x 17 Vantage 5 Accumulator Mater Volume (nominal) 1050 ft. /accumulator Accumulator Tank Volume (nominal) 1450 ft, /accumulator .
Accumulator Gas Pressure (minimum) 600 psia Safety Injection Pumped Flow See Figures 15.6.5-18 and 15.6.5-56
.Containment Parameters See Tables 6.2.1-62, 6.2.1-63, and Figures 6.2.1-303 and 6.2.1-304 Initial Loop Flow 10037 lb./sec.
Vessel Inlet Temperature 557.1 F Vessel Outlet Temperature 623.8 F Reactor Coolant Pressure 2280 psia Steam Pressure 964.0 psia Steam Generator Tube Plugging Level
- 2%%d is added to this power level to account for. calorimetric error.
1582v:1O/020389-48
I tA
TABLE 15.6.5-3 LARGE BREAK DECLG (CD 0 8) DECLG (CD 0 6) DECLG (CD (Sec) (Sec) (Sec)
Results Peak Clad Temp. 'F 1699.8 1867.6 2105.2 Peak Clad Location Ft. 6.25 8.0 6.0 Local Zr/H20 Reaction 1.348 3.57 8.03 (max) %
Local Zr/H20 Location Ft. 7.00 6.25 6.0 Total Zr/H20 Reaction % <0.3 <0.3 <0.3 Hot Rod Burst Time sec 38.18 36.24 32.68 Hot Rod Burst Location Ft. 6.00 6.25 6.0 Calculation NSSS Power Mwt 102% of 2775 Peak Linear Power kw/ft 102% of 13.340 Peaking Factor (At License Rating) 2.45
'ccumulator Mater Volume (ft ) 1050 Fuel region + cycle analyzed Cycle Region UNIT 1 ALL ALL 6/ Steam Generator Tube Plugging in each steam generator is assumed.
1582v:1D/100788-49
TABLE 15.6.5-4 SMALL BREAK LOCA TIME SEQUENCE OF EVENTS FOR CONDITION III EVENTS Event Time s Break Size: 2-Inch 3-Inch 4-Inch .
Break occurs 0 '
Reactor trip signal (Setpoint + delay) 38.76 17.76 9.353 Core power shutdown (setpoint + delay + rod drop) 41.46 19. 46 12.053 Safety injection signal 51.03 24.97 .17. 81 Safety injection begins 78,03 51.97 44.81 Top of core uncovered (deepest uncovery, not always first,uncovery) 2080 778 455 Accumulator injection begins N/A 1263 641 Peak clad temperature time 3051. 1377 758 Core recovered 4850 3755 2257 1 582 v:1D/100788-50
l C
l I
TABLE 15.6.5-5 SMALL-BREAK LOSS OF COOLANT ACCIDENT CALCULATION RESULTS PARAMETER VALUE Break Size: 2-Inch 3-Inch 4-Inch Peak clad temperature ('F) 1045 1780 1510 Elevation (ft) 11.50 11.75 11.50 Zr/H20 cumulative reaction Maximum local (%) 0.0566 2.2577 0.3804 Elevation (ft) 11.50 11.75 11.50 Total core (%) < 0.3 < 0.3 < 0.3 Rod Burst None None None SIGNIFICANT INPUT PARAMETERS Licensed core power 2775 MW Peak linear heat generation rate 13.003 kW/ft Accumulator Tank water volume 1050 ft Pressure . 600 psi 1582v:1D/100788-51
,\ ~ t 4~A 1 gJ i'4 "F
lfj
-fl
,$ 4 ta
BREAK OCCURS B REACTOR TRIP (COMPENSATED PRESSURIZER PRESSUREI L I'UMPED SAFETY INJECTION SIGNAI. (HI I CONT. PRESS. OR LO PRESSURIZER PRESS.I 0 PUMPED SAFETY INJECTION BEGINS (ASSUMING OFFSITE POWER AVAILABLE)
W D ACCUMULATOR INJECTION 0 CONTAINMENT HEAT REMOVAL SYSTEM INITIATION(ASSUMING OFFSITE POWER AVAILABLE)
W N END OF BYPASS END OF SLOWDOWN PUMPED SAFETY INJECTION BEGINS (ASSUMING LOSS OF OFFSITE POWER)
BOTTOM OF CORE RECOVERY R CONTAINMENT HEAT REMOVAL SYSTEM INITIATION(ASSUMING LOSS OF OFFSITE POWERI
'E F ACCUMULATORS EMPTY L
0 0
D CORE QUENCHED L
0 N SWITCH TO COLD LEG RECIRCULATION ON RWST LOW LEVEL ALARM (MANUALACTIONI G
T E'
SWITCH TO LONG TERM RECIRCULATION (MANUAL ACTIONI M
C 0
0 L
I N
G SHEARON HARRIS NUCLEAR POWER PLANT SE(UENCE OF EVENTS FOR LARGE BREAK FIGURE Carolina LOSS-OF-COOLANT ANALYSIS Power 8 Light Co. 15.6.5-1 FINAL SAFETY ANALYSIS REPORT
q% l 1
V, 4
1
llew gg 'tl&
ILOMOOMII 1EFlLL IEFL000 Rr- Ã bOCREC I
CALCULATES HOT RODo AMACKNT RODe l CALCULATES HOT NSe AMACEIIT ROOe ANO AIO HOT ASSKIOLY ROD TKS'KRATURK~ bLOCKAGK, h.t.c, HOT ASM%LY ROD TO%'KRATURE ~ bLOCKAGE, CAO A ALSO CALCULATES CORK TENPERATURK tLOCTA ONLY) I AND h.t ce 0 I g
IIT ASSEII.Y, CNE ITS YELOClTYI QUALlTYg PRESQNE CORK FL009l% RATEo lNLET CORE ENTINLPY CONDlTlONS AT BOCRKC CALCULATES CORK FLOOOlNG SOCRECe RATK, RCS CONDlTlONS QURlII CALCULATES KSe COREe RCS CONOlTlONS RKFLOOD HOT ASSEII.Y AT bOCRKC FN10 CONDlTlN6 n
C) w M
r C7 mW w ED NSS, EIIERGY RELEASE 1NTO. CONTAlll%NT RCS CONOlTlONS AT KOB ACeuea.ATDA, Sl FLOu, CONTAlItIIKNT PRESSURE CALCULATES REFlLL, FL0001NG RATE AND ASS, ENERGY RELEASE RATE FRON RCS DURING REFLOOD.
{MREFLOOD)~ CALCULATKS CONTAlNHKNT PRESSURE (COCO)
IREFLOOOICOCO CJl Ch CD CALILATES CONTAlNIIKIIT EJl PRESSURE {COCO ONLY) l m
V>>
1
)
rt"
'4'e d
4$ ~ r.~
N CORE PRESSURE, CORE L 0 FLOW, MIXTURE LEVEL, 0 T AND FUEL ROD POWER C R HISTORY T U A M
0 TIME'CORE COVERED P
SHEARON HARRIS NUCLEAR POWER PLANT CODE INTERFACE DESCRIPTION FOR FIGURE Carolina SMALL BREAK HODEL Power 8 Light Co. 15.6.5-3 FINAL SAFETY ANALYSIS REPORT
gE T.
.25E 84
.225E 84 h
LIJ
.2E.84
~ O
.175E 84
. 15E 84 C) o
. 125E+84 I
o
.1E'84 758.
I 588.
C) 258.
CZ C3
- 58. 188. 158. 288. 258. 388.
TINE (SEC. )
SHEARON HARRIS NUCLEAR POWER PLANT PEAK CLAD TENPERATURE FIGURE Carolina DECLG (CD~0.4)
Power 5 Light Co. 15.6.5-4 FINAL SAFETY ANALYSIS REPORT
la 4'
CORE BOTTOM (~ .TOP, ( + )
Q 1688 d 2.S S 7.S ld 12.$ lS 1T.S 28 22.$ 2S 2>.$ SB 1)IK (SEC1 SHEARON HARRIS NUCLEAR POWER PLANT CORE PRESSURE FIGURE Carolina DECLG (CD%0.4)
Power l Light Co.
FINAL SAFETY ANALYSIS REPORT 15.6.5-5
4 I'k
~ 'e>>-1
22.
ON MR 28.
18.
OP OF CORE i RE UN L 8.
CORE SAT RATION LEVE 6.
4.
- 58. 188.
TINE (SEC) 158. 288. '58 (AFTER BOC)
'HEARON HARRIS NUCLEAR REFLOOD TRANSIENT POMER PLANT CORE AND DOMNCONER MATER LEVELS FIGURE Carolina. DECLG (CD~0.4)
Power L Light Co. 15.6.5-6 FINAL SAFETY ANALYSIS REPORT
~ 'C1~
~l ll'
18.
9.
8.
o '7.
LJ V)
Z I
o 2.
'8. 25. 58. 75. 188. 125. 158. 175. 288. 225. 258.
TIME (SEC)
(AFTER BOC)
SHEARON HARRIS NUCLEAR REFLOOD TRANSIENT POWER PLANT CORE INLET VELOCITY FIGURE Carolina DECLG (CD~0.4)
Power 8 Light Co. 15.6.5-7 FINAL SAFETY ANALYSIS REPORT
,~ ~ ( p'gg 1
k f
l.2
~ 6 O
~ 6
~ 2 I 2.S S 1.$ 18 l2.$ lS 17.$ 28 22.S 2S 2>.$ 58 Tits (SEC)
SHEARON HARRIS NUCLEAR POWER PLANT CORE POWER TRANSIENT FIGURE Carolina DECLG (CD%0.4)
Power K Light Co. 15.6.5-8 FINAL SAFETY ANALYSIS REPORT
S 20 15 10 0 40 Io 120 '140 200 240 280 420
~
~
(SEC)
SHEARON HARRIS NUCLEAR POWER PLANT CONTAINMENT PRESSURE FIGURE Caro1ina DECLG (CD~0.4)
Power I Light Co. 15.6.5-9 FINAL SAFETY ANALYSIS REPORT
I'y
~ A
BOTTOM ( ) TOP , (')
CJ LJ 6888 07 F 888 a
2888 H
2888
-F888
-6888 8 'S S >~S lB l2~S Ills lS l
lt~S 28 22~S 2S ÃoS dB SEC)'HEARON HARRIS NUCLEAR POWER PLANT CORE FLOW (TOP AND BOTTON) FIGURE Carolina OECLG (CD~0.4)
Power 5 Light Co. 15.6.5-10 FINAL SAFETY ANALYSIS REPORT
-t \ ~ I 4 C K 4 LW ~ %l ~ s,.j
~4 P
~ kE 0' ~
m 58.
45.
w 48.
+~ 35.
~ 38.
25.
~ 28, 15.
V) 18.
I 5.
CE z 8 '8 188. 158. 288. 258.
TINE (SEC.) .
SHEARON HARRIS NUCLEAR POMER PLANT HEAT TRANSFER COEFFICIENT FIGURE Carolina DECLG (CD~0.4)
Power L Light Co. 15.6.5-11 FINAL SAFETY ANALYSIS REPORT
.y<
A' II gyt 1
jp
~'Jp'
.25E 84
.225E.84 5
LJ
.2E.84 O
.175E 84 F
w .15E 84.
l 5 . 125E 84
.1E 84 758.
588.
258.
188. 158. 288. 258. 388.,
TIME (SEC.)
SHEARON HARRIS NUCLEAR POMER PLANT FLUID TEMPERATURE FIGURE Carolina DECLG (CD~0.4)
Power t Light Co. 15.6.5-12 FINAL SAFETY ANALYSIS REPORT
Jh 0888E+S
$ 88 SEES 4888E+S 5888E+S 2888EiS I888EeS
- I888E+6 8 2 AS S 1. S lb 12.S IS IT.S 28 22.S 2S 27. S 88 Tlirt (SEC)
SHEARON HARRIS NUCLEAR POWER PLANT BREAK FLOW RATE FIGURE Carolina DECLG (CO%0.4)
Power I Light Co. 15.6.5-13 FINAL SAFETY ANALYSIS REPORT
c "4's-0
l Q)
~
588BE+8
.2658E+8
~ 2588EW
, 1 SBBE+8
~ lBBBEid
~ SBBBE+2 SBBBE+i 5 2.6 6 7.6 ld l2 S lS lT.S 25 22 6 2S 2>,S 58 TlllE lSEC)
SHEARON HARRIS NUCLEAR POMER PLANT BREAK ENERGY RELEASED TO CONTAINMENT FIGURE Carolina DECLG (CDi0.4)
Power I Light Co. 15.6.5-14 FINAL SAFETY ANALYSIS REPORT
' & ~ 'I % e
' ~'+" ~
- I
>.S 58 TI& ISECI SHEARON HARRIS NUCLEAR POMER PLANT ACCUMULATOR FLOW (DURING BLONOMN) FIGURE Carolina DECLG (CD~0.4)
Power t Light Co. 15.6.5-16 FINAL SAFETY ANALYSIS REPORT
I a'eLe L a ~ >> ~ 4 w+ wroAe g v c4
.4E+84
~ .35E 84
.3E 84
~ .25E'84 o 2E.84
~ .15E'84 O
I
.1E 84 588.
- 58. 188. 158. "288. 258.
TINE (SEC)
(AFTER BOC)
SHEARON HARRIS NUCLEAR POWER PLANT ACCUMULATOR FLOW (DURING REFLOOD) FIGURE Carolina DECLG (CD~0.4)
Power I Light Co. 15.6.5-17 FINAL SAFETY ANALYSIS REPORT
482.
488.
m 398.
K 396.
I cC o 394 ~
392.
398. ]58. 288. 258.
- 58. 188.
TINE ( SEC )
{AFTER BOC)
SHEARON HARRIS NUCLEAR POMER PLANT SAFETY INJECTION FLOM (DURING REFLOOD) FIGURE Caro1ina DECLG (CDi0.4)
Power 8 Light Co. 15.6.5-18 FINAL SAFETY ANALYSIS REPORT
'w ~ ~
l 4
r) a%
E 4 A CI
PEAK NODE (-) BURST NODE (X)
.25E 84 w~ .225E 84 5
w
.2E 84 O
.175E 84
.15E'84
. 125E+84 xC) .1E-84 ei Q
~w 758 588.
258.
- 58. 188. 158. 288. 258. 388.
TIME (SEC.)
SHEARON HARRIS NUCLEAR POMER PLANT PEAK CLAD TENPERATURE FIGURE Carolina DECLG (CD%0.6)
Power 5 Light Co. 15.6.5-19 FINAL SAFETY ANALYSIS REPORT
A l @ 4 f II Ablraa 4
e ~ ~ ~ ~
' ~ ~
I ~ ~
I I ~ ~ ~
~ ~
I ~
.k'4, ~ & Ji 4 ~kyj(j, 7
C)[
5
22.
NCOMER 28.
18.
TOP OF ORE CORE Q ENCH LEVE 8.
CORE SAT URAT I 0 LEVEL 6.
4.'OTTOM 188.
F CORE 158. 288. 258. 388.
TIME ( SEC )
(AFTER BOC)
SHEARON HARRIS NUCLEAR REFLOOD TRANSIENT POWER PLANT CORE AND DOWNCOMER WATER LEVELS FIGURE Carolina DECLG (CD~0.6)
Power 5 Light Co. 15.6.5-21 FINAL SAFETY ANALYSIS REPORT
t~ ka e, l44+,
aQ I.
~ ~ a ~
4 lH.
il I - t 'h ~ ~ I'. i ~
P II I
k~
i~
, ~
18.
9.
8.
o 7.
Ll (fl z
I o
Ffl 2.
- 8. 25. 58. 75. 188. 125. 158. 175. 288. 225. 258.
TINE (SEC)
(AFTER BOC)
SHEARON HARRIS NUCLEAR REFLOOD TRANSIENT POltER PLANT INLET VELOCITY'ORE FIGURE Carolina DECLG (CDi0.6).
Power K Light Co. 15.6.5-22 FINAL SAFETY ANALYSIS REPORT
F.4,s w ~ = s ~ v 'r *.&r cia.~ -"*>~
b,
,0 f Jl
~ ~
~
I ~ ~ ~ ~
I ~ ~
I I ~
~
~
~ ~
I ~
%~w4 *c 0
A4
2$
m 40 W 120 100 200 240 2bO 520 1NE (SKC)
SHEARON HARRIS NUCLEAR PORE R PLANT CONTAIHMEHT PRESSURE FIGURE Carolina DECLG (CD%0.6)
Power K Light Co. 15.6.5-24 FINAL SAFETY ANALYSIS REPORT
PEAK NODE ( ) BURST NODE(X)
.25E 84
.225E 84 5 .2E+84 O.
.175E 84 O .15E 84 O
, 125E 84 l
O
.1E 84 w 758 I
588.
C) 258.
CL
- 58. 188. 158. 288. 258. 388.
TINE ( SEC. )
SHEARON HARRIS NUCLEAR POXER PLANT PEAK CLAD TENPERATURE FIGURE Carolina DECLG (CD~0.8)
Power k Light Co. 15.6.5-25 FINAL SAFETY ANALYSIS REPORT
44&> C i ~
44
-0 4 W
%44
~ ~
~
I ~ ~ ~ ~ ~
I
~
~
~ ~
I ~
I % 5 -"*'4 r
C$
-0
. ~
22.
00 NCOMER 28.
18.
TOP 0 CORE 8.
l gg@g'<'lgg]i(ii 6.
BOTTO OF CORE 4.
188. ]68. 288. 258.
TINE (SEC)
(AFTER BOC)
SHEARON HARRIS NUCLEAR REFLOOD TRANSIENT POWER PLANT CORE AND DOWNCOHER WATER LEVELS Carolina DECLG (CD~0.8)
Power 3 Light Co.
FINAL SAFETY ANALYSIS REPORT
<'4O ~ 'Vw l 4Ak
~ ~ *~ <o g, v WI il Fill' i~
>lk 0
18.
9.
8.
o 7.
Ll M
6.
2.
'8. 25. 58. 75. 188. 125. 158. 175. 288. 225. 258.
TIME (SEC)
(AFTER BOG)
SHEARON HARRIS NUCLEAR REFLOOD TRANSIENT POMER PLANT Carolina DECL6 (CDND.B)'IGURE CORE INLET VELOCITY Power 5 Light'Co. I5.6.5-28 FINAL SAFETY NlALYSIS REPDRT
- t- W "~ ~
I h * ~ 8, H AN l I~ ...A, C
vs+
8 e 4 6 4 $ 4 12 l4 l6 IS Tf& %KC)
SHEARON HARRIS NUCLEAR POWER PLANT CORE PDWER TRANSIENT FIGURE Carolina GKCLG (CD~0..8)
Power t Light Co. 15.6.5-29 FINAL SAFETY ANALYSIS REPORT
I I"
- ~
20 15 10 120 160 200 240 280 XS MME (SEO)
SHEARON HARRIS NUCLEAR POMER PLANT CONTAINMENT PRESSURE FIGURE Caro1ina DECLG (CD~0.S)
Power k Light Co. 15.6.5-30 FINAL SAFETY ANALYSIS REPORT
C a'lb~
I I
'g Wy1'
mes.
2288.
iees.
cC
~~ iees.
~ La>
g I488.
C/l Lal l288 ~
~ UJ o
CC iess.
ees.
ces.
488 ses. >888. >see. 2eee. 2ses. sees. sses. ises. 4ses.
TltC (SEC l SHEARON HARRIS NUCLEAR POMER PLANT CORE PRESSURE FIGURE Carolina (3 INCH BREAK)
Power 5 Light Co. 15.6.5-31 FINAL SAFETY ANALYSIS REPORT
la " J ~ ~ '+$ -
4 0
54.
SB.
25 e LJ 5
Pc 2< ~
R W
U 22.
TOP OF CORE 18.
16
- b. $ 88. 1088. !588. 2888. 2588. 5888. 5588. 1888. 4588.
Tlat% 1SEC)
SHEARON HARRIS NUCLEAR POWER PLANT. CORE HIXTURE LEVEL FIGURE Carolina (3 INCH BREAK)
Power I Light Co. 15.6.5-32 FINAL SAFETY ANALYSIS REPORT
%t P O' I \P IXI 4 p I'g g4 1 '
'a} '
~
=
~
225.
2ee.
~ l75.
Z CD lse.
CD cc'25.
Cf
~ l88 ~
IJ cD 75.
CJ 58.
- 1. SM. IBM. lSM. 2888. 2588. 58M. 5588. 4888. 1588.
T1 tK l SEC l SHEARON HARRIS NUCLEAR POHER PLANT CORE STEAN FLOW FIGURE Carolina (3 INCH BREAK)
Power K Light Co. 15.6.5-33 FINAL SAFETY ANALYSIS REPORT
4 P ~
))
i,<, "r c
120 see. iaee. tsoe. wee. me. sooe. sseo. wee. csee.
T II% t SEC I SHEARON HARRIS NUCLEAR POMER PLANT BREAK STEAN FLOM FIGURE Carolina (3 INCH BREAK)
Power 8 Light Co. 15;6.5-34 FINAL SAFETY ANALYSIS REPORT
I; tll' 0 L1
SWM i IMO. l SOS. 2MO ISA. 5080 55M (SIC I
~ 4OQQ, i55Q SHEARON HARRIS NUCLEAR POWER PLANT TOTAL SYSTEM NSS FIGURE Carolina (3 INCH BREAK)
Power K Light Co. 15.6.5-35 FINAL SAFETY ANALYSIS REPORT
t jt
BURST ~ 9 00 FT
~ ( ) PEAK ~ 1 1 75 FT (+ )
~ 2588.
2888.
1588.
I a.
X l888.
W I
O 588.
588. 1888. l588. 2888. 2588. 3888. 3588. 4888. 4588.
'lll1E lSEC)
SHEARON HARRIS NUCLEAR POWER PLANT CORE VAPOR TEMPERATURE FI6URE Caro1ina (3 INCH BREAK)
Power h Light Co. 15.6.5-36 FINAL SAFETY ANALYSIS REPORT
l,,d ~ Pk P
BURST. 9. 00 FT ( ) PEAK 11. 75 FT-(+
o )
]B3 CV I
I cD ]B2 Vl CZ I
x CD 4
CI ui ]B]
CZ QC I
5BB. ]BBB. 15BB. 2BBB. 25BB. 3BBB. 35BB. " 4BBB. 45BB.
TINE {SEC]
SHEARON HARRIS NUCLEAR POWER PLANT FUEL ROD HEAT TRANSFER COEFFICIENT FIGURE Caro1ina (3 INCH BREAK)
Power t Light Co. 15.6.5-37 FINAL SAFETY ANALYSIS REPORT
'>> -v Ski 4 4 ~ '. w >a= ~ a.
I+
i equi
,fi h
~
BURSTS 9.00 FT ( ) PEAKED 11.75 FT (+)
~ 2588.
CI 2888.
C)
CI l588.
CI X
~ 1888.
O 5 588.
CJ 588. l888. l588. 2888. 2588. 3888. 3588. 4888. 4588.
T ltlE l SEC)
SHEARON HARRIS NUCLEAR POWER PLANT HOT SPOT CLAD TENPERATURE FIGURE CaT olina (3 INCH BREAK)
Power 5 Light 'Co. 15.6.5-38 FINAL SAFETY ANALYSIS REPORT
'LQI44 4848 I ~
2188.
2288.
2888.
lBBB.
lees ~
CL
~ l1es.
l288.
888.
188.
S. See. less. lSBS. 2888 '588. 5888. 5588.
TIE (SECI SHEARON HARRIS NUCLEAR POWER PLANT CORE PRESSURE FIGURE Carolina (4 INCH BREAK)
Power 5 Light Co. 15.6.5-39 FINAL SAFETY ANALYSIS REPORT
, ts ri
"~ W 4- 4J,I ~ '
'I~4 9
38.
26.
I w 26 '
24 ~
< 22.
EJ
.TOP OF CORE 26.
16.
16.
ses. ress. >see. 2ess. 2666. sess. 66ee.
TIHE (SECI SHEARON HARRIS NUCLEAR POMER PLANT CORE NIXTURE LEVEL FIGURE Carolina (4 INCH BREAK)
Power 5 Light Co. 'IS.6.S-4O FINAL SAFETY ANALYSIS REPORT
J%g,+
S- IE 4 0 tA Ay I
'I
use.
9 sse.
X 588.
~ 2se.
~ 288.
LJ g 158.
lee.
B. 588. 1888. 1588. 2888 ~ 2588. 5888. 5588.
7115: l SEC I SHEARON HARRIS NUCLEAR POWER PLANT CORE STEAN FLOW FIGURE Carolina (4 INCH BREAK)
Power 3 Light Co. 15.6.5-41 FINAL SAFETY ANALYSIS REPORT
(
1
~ a
225.
SN. INo 1SN. BIO 2SN. QNo SKI.
TIE: 1 SEC I SHEARON HARRIS NUCLEAR POWER PLANT BREAK STEAM FLOW FIGURE Carolina Power i Light Co.
FINAL SAFETY ANALYSIS REPORT (4 INCH BREAK) 15.6.5-42
I
SHEARON HARRIS NUCLEAR POWER PLANT TOTAL SYSTEN NASS FIGURE Carolina (4 INCH BREAK)
Power 5 Light Co. 15.6.5-43 FINAL SAFETY ANALYSIS REPORT
ag 0 l
~ I Jp if'P ad II
-0
+E
~ ~
~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~
~
~ ~ ~
4 y
- 0
BURST. 9.50 FT( ) PEAK ~ 11.50 FT(+)
186 CU 4.
cD 182 Ch 4.
CD LJ m 181 I
188 288. 488. 688. 888. 1888. '288. 1488. 1688. 1880, 2880. 2288 ~ 2488.
TIHE (SEC)
SHEARON HARRIS NUCLEAR POWER PLANT FUEL ROD HEAT TRANSFER COEFFICIENT FIGURE Carolina (4 INCH BREAK)
Power I Light Co. 15.6.5-45 FINAL SAFETY ANALYSIS REPORT
ju 1 M
BURSTS 9.50 FT( ) PEAKED 11.50 FT(+)
~ 2588.
C) 2888.
C)
O 1588.
o
~ l888.
Ct 5 588.
U 288. 488. 688. 888. I888. I288. I488. 1688. l888. 2888. 2288. 2488.
TIVE ISECI SHEARON HARRIS NUCLEAR
=
POWER PLANT HOT SPOT CLAD TEMPERATURE FIGURE Carolina (4 INCH BREAK)
Power I Light Co. 15.6.5-46 FINAL SAFETY ANALYSIS REPORT
%I Ak 1 S AW* 4
'4 4
1$ 0
2488.
2288.
~ 2888.
less.
CX au leee.
CX CL
'488.
1288.
1888.
ess
- 1. 588. 1888. 1588. 2888. 2588. 5888. 5588 4888. 4588. 5888.
F TltlE lSEC)
SHEARON HARRIS NUCLEAR POWER PLANT CORE PRESSURE FIGURE Carolina (2 INCH BREAK)
Power L Light Co. 15.6.5-47 FINAL SAFETY ANALYSIS REPORT
"i ~ > ICE g4
'lE* e si i.
~ <l wAs Ray 0 I
'e fg sg e
34.
32.
28.
~ 26>>
K w 24.
TO P OF CORE lB SBB. l888. l588. 2888. 25M. 3888. 3588. 4888. 4588. 5888 Tlat% (SEC)
SHEARON HARRIS NUClEAR POWER PLANT CORE MIXTURE LEVEL FIGURE Carolina (2 INCH BREAK)
Power 3 Light Co. 15.6.5-48 FINAL SAFETY ANALYSIS REPORT
~ Djti .A L N II kylh %
1 88.'68.
148.
CJ w 128.
3 18B.
5 88.
I i w 68 48.
- 1. ses. 1see. 1ses. mes. esse. sese. ssee. csee. ~see. sess.
T1tK 1 SEC)
SHEARON HARRIS NUCLEAR POWER PLANT CORE STEAN FLOW FIGURE Carolina (2 Power i Light Co.
FINAL SAFETY ANALYSIS REPORT INCH BREAK) 15.6.5-49
- 4 ~e '
f A Vvl
see. >me. csee. ~. me.tQXI 1 IW seas. ssee. aeee. isae. seee.
SHEARON HARRIS NUCLEAR POMER PLANT BREAK STEAM FLOM FIGURE Carolina (2 INCH BREAK)
Power t Light Co. 15.6.5-50 FINAL SAFETY ANALYSIS REPORT
N 1mt44W'F t~
4E 08 gg ~ IE i 06
~ .2%-08 z
o -8E'08 i
.)K 08
.lEig I 008. 8080. 5008 ~ 4000+ S008.
ill8: IKC I SHEARON HARRIS NUCLEAR POMER PLANT TOTAL SYSTEM NSS FIGURE Caro1ina (2 INCH BREAK)
Power 8 Light Co. 15.6.5-'51 FINAL SAFETY ANALYSIS REPORT
- ~ 0 M f 4 ~pQeg iq
, (I,Q
BURSTS 10.50 FT( ) PEAKED 11.50 FT(+)
~ 2588.
2888.
l588.
a- l888.
O 588.
8.
2h88. 2258. 2588 '758. 3888. 3258. 3588. 3758. 4888. 4258. 4588. 4758. 5888.
TjNE (SEC I SHEARON HARRIS NUCLEAR POWER PLANT CORE VAPOR TEMPERATURE FIGURE Carolina (2 INCH BREAK)
Power 3 Light Co. 15.6.5-52 FINAL SAFETY ANALYSIS REPORT
~ i+4c gt) e Ct igh ib7t' t
BURST ~ 10. SO FT ( ) PEAK ~ 11. 50 FT (+ )
OC I
CV 4
c) ]82 Ch I
CI CI CJ i I is>
2888. 2258 '588. 2758.. Mas. 3258. 3588: 3758. 4888. 4258. 4588. 4758. S888 ~
T]ME (SECI SHEARON HARRIS NUCLEAR POMER PLANT FUEL ROD SEAT TRANSFER COEFFICIENT FIGURE Carolina (2 INCH BREAK)
Power I Light Co. 15.6.5-53 FINAL SAFETY ANALYSIS REPORT
~ ~v sew'i
'1 A1 N -r ~
4 4
P
.BURST. 10. 50 FT ( ) PEAKED 11.50 FT (+)
~ 2588.
W 4J 2888.
CD CD 1588.
CD Z
i 1888.
CD 5 588.
2888. 2258. 2588. 2758. 3888. 3258. 3588. 3758. 4888. 4258. 4588. 4758. 5888.
TIVE (SEC)
SHEARON HARRIS NUCLEAR POMER PLANT HOT SPOT CLAD TEMPERATURE FIGURE Carolina (2 INCH BREAK) 15.6.5-54 Power h Light Co.
FINAL SAFETY ANALYSIS REPORT
e '+5~
Pg 1
10o TOTAL RESIDUAL HEAT IWITH 4% SHUTDOWN)
Fu 101 g e 6
I 4
I I
10'i s
10'3 10'I 2 5 104 2 5 101 2 103' 5 10 2 5 5 10 TIME AFTER SHUTDOWN ISECONDS)
SHEARON HARRIS NUCLEAR POWER PLANT CORE POWER AFTER REACTOR TRIP FIGURE Caro1ina Power 3 Light Co. 15.6.5-55 FINAL SAFETY ANALYSIS REPORT
~bL ~ \ 4 ~ lh ~ I 2A 22 2
t8 1.6 SHEARON HARRIS NUCLEAR POMER PLANT SMALL BREAK SAFETY INJECTION FLOlfRATE FIGURE Carolina Power L Light Co. 15.6.5-56 FINAL SAFETY ANALYSIS REPORT
l I
IIEET~
"4 4 0 +'I "-
p I gya
.'e
2A 1.6 1A
~ 12 OA 10 12 SHEARON HARRIS NUCLEAR POWER PLANT SNLL BREAK LOCA POWER SHAPE FIGURE Ca1olina Power K Light Co. 15.6.5-57 FINAL SAFETY ANALYSIS REPORT
0 ATTACHMENT C LOCA RELATED TECHNICAL SPECIFICATION INFORMATION PLANT NAME: Shearon Harris (CgL)
TYPE/DATE OF LOCA ANALYSIS: Large Break:
Cn 0.4, 0.6, 0.8 1981 EM with BASH 10/88 Small Break:
2 inch, 3 inch, 4 inch NOTRUMP 10/88 TOTAL PEAKING FACTOR: 2.45 HOT ASSEMBLY ENTHALPY RISE FACTOR: 1.65 COLD LEG ACCUMULATOR NOMINAL WATER VOLUME'050 ft /accumulator COLD LEG ACCUMULATOR GAS PRESSURE: 600 psia (minimum)
K(Z) CURVE: Figure 1 (attached)
l
+b k~ ~~"
CQL VANTAGE 5 RTSR ANALYSIS K(Z) CuRVE 0.9 0.8 0.7 0.6 Elevation Norma11zed Peakfn Factor 0.5 0.0 1.0 6.0 1.0 OA 12.0 0.925 0.5 0.2 0.1 0
0 10 CORE ELEVATION (FEH)
ATTACHMENT 5 SAMPLE CORE OPERATING LIMITS REPORT (277CRS/lych)
SHEARON HARRIS UNIT 1 CYCLE 2 CORE OPERATING LIMITS REPORT REVISION 0 8 MARCH 1989 h
SHEARON HARRIS UNIT 1 CYCLE 2 1.0 Core Operating Limits This Core Operating Limits Report for SH1C2 has been prepared in accordance with the requirements of Technical Specification 6.9.1.6. The core operating limits have been developed using the NRC-approved methodologies specified in References 1 and 2.
The following cycle-specific core operating limits are included in this report:
- 1) Control Rod Insertion Limits (Figure 1) . Fully withdrawn for all control and shutdown banks shall be 228 steps.
- 2) AFD Limits and W(z) Curves for RAOC Operation (Figures 2 through 5).
These W(z) curves are sufficient to determine the RAOC W(z) versus core height for Cycle 2 burnups through the end of full power reactivity plus a power coastdown of up to 1000 MWD/MTU through the use of three point interpolation.
ND
- 3) AFD Limits, APL , and W(z) Curves for Base Load Operation (Table 1 and Figures 6 through 8) . These W(z) curves are sufficient to determine the Base Load W(z) versus core height for Cycle 2 burnups through the end of full power reactivity plus a power coastdown of up to 1000 MWD/MTU through the use of three point interpolation.
2.0 References
- 1. "Westinghouse Reload Safety Evaluation Methodology," WCAP-9273-A, July 1985.
- 2. "Relaxation of Constant Axial Offset Control F Surveillance
~
~
e Technical Specification," WCAP-10217-A, June 1983.
~
~
Page 1 of 10 (REV 0)
~.
FIGURE 1 SHEARON HARRIS UNIT 1 CYCLE 2 ROD GROUP INSERTION LIMITS VERSUS THERMAL POWER (THREE-LOOP OPERATION) 220 .538 228 200 1 186 c 180 0
l BANK
~ 160
~ 140 CL 0 128
~ 120 CO BANK
~ 100 ll)
C) o- 80
~ 60 C)
CO 40 20 0, 0
.00 . 10 '20 .30 .40 .50 .60 .70 .80 .90 1.0 FRACTION OF RATED THERMAL POWER (Fully withdrawn shall be 228 steps)
This figure is referred to by Technical Specifications 3.1.3.1.d.2 3.1.3.5 3.1.3.6 Page 2 of 10 (REV 0)
FIGURE 2 SHEARON HARRIS UNIT 1 CYCLE 2 AXIALFLUX DIFFERENCE LIMITS AS A FUNCTION OF RATED THERMAL POWER FOR RAOC 120 110
-13. 100 7, 100 100 CCEP7 BLg ACGEP7 BLE IJJ C) 80 CEP7AB E p5 70 Q 60 50
-34. 50 29, 50 z 40 20 10 I
0
-50 -40 -30 -20 -10 0 10 20 30 40 50 AXIAL FLUX DIFFERENCE (% DELTA I )
This figure is referred to by Technical Specifications 3.2.1 4.2.2.2f B3/4.2.1 Page 3 of 10 (REV 0)
'P>>
1 1
)
,1 8 ~
,'$r Xi "4
AJ 4
FIGURE 3 SHEARON HARRIS UNIT 1 CYCLE 2 RAOC W(Z) AT 160 MWD/MTU Height BOL 135 ~Feat ~ll z I
s Ill I I I I I I 0.00 F 0000 I I I I I I I 0.20 1. 0000 III 0.40 1.0000 I I I 0.60 1. 0000 I I I ! I I 0.80 1 . 0000 1.00 1. 0000 I I I I I I 1.20 1. 0000 1.30 1.40 1. 0000 1.60 1. 0000 1.80 .3459 2.00 .3121 2.20 . 2821 2.40 .2577 F 60 .2321 2.80 .2062 3.00 . 1836 1.25 3.20 . 1679 I Il 3.40 3.60 1599 1560 3.80 ~ 1519 4.00 . 1486 4.20 . 1450 4.40 . 1428 I I 4.60 . 1394 4.80 . 1352
- 1. 20 5.00 . 1307 5.20 . 1239 5.40 . 1198 5.BO . 1285 5.80 . 1387 6.00 . 1476 6.20 . 1554 6.40 . 1619 6.60 . 1671 1.15 6.80 . 1709 7.00 . 1726 7.20 . 1742 7.40 . 1787 F 60 . 1774 7.80 . 1764 8.00 . 1738 8.20 . 1696 8'.40, . 1635
- 1. 10 8.60 . 1558 F 80 . 1488 9.00 . 1378 9.20 . '1349 9.40 ~ 1481 9.60 . 1622 9.80 . 1751 10.00 1.2090
- 10. 20 1. 2551
- 10. 40 1.0000 1.05 10. 60 1.0000-10.80 1. 0000
- 11. 00 1. 0000 11.20 1. 0000 11.40 1. OOOO-
- 11. 60 1.0000 11.80 1. 0000
- 12. 00 1. 0000 1.00 Top and Bottom 15%
2 3 4 5 6 7 8 9 10 11 excluded as per Technical CORE HEIGHT ( Feet) SpecS 4.2.2.2 f ication
~
This figure is referred to by Technical Specifications 4.2.2.2c S3/4.2.2 Page 4 of 10 (REV 0)
T FIGURE 4 SHEARON HARRIS UNIT 1 CYCLE 2 RAOC W(Z) AT 6000 MWD/MTU He1ght MOL
~Feet ~wz 0.00 1. 0000 0.20 1. 0000 0.40 1 . 0000 e 0.60 1. 0000 0.80 1 . 0000
- 1. 00 1 0000
~
1.20 1.0000
- 1. 40 1. 0000 e 1.60 1. 0000 1 80
~ . 1988
- 2. 00 . 1834 2.20 . 1677 2.40 . 1517 2.60 . 1356 2.80 . 1193 3.00 . 1035 3.20 1.0983 3.40 1. 1050 3.60 1. 1093 3.80 1. 1171 4.00 1. 1280 4.20 1. 1390 4.40 1. 1489 4.80 1. 1576 4.80 1. 1649 f I 5.00 . 1712 d 5.20 . 1749 5.40 . 1789 5.60 . 1902 F 80 .2055 6.00 .2198 6.20 1. 2315 6.40 1.2412 6.60 1.2486 6.80 1.2536 F 00 1.2560 7.20'.40 1.2559 1.2532 7.BO 1.2479 7.80 1.2398 8.00 1 2294
~
8.20 1.2158 8.40 1 . 2012 8.80 1. 1928 8.80 1. 1925 9.00 1. 1922
'.20 1 1930
~
9.40 1. 2028 9
9.80
'0 1.2262 1.2644
- 10. 00 1. 3020
- 10. 20 1.3333
- 10. 40 1. 0000
- 10. BO 1 . 0000 10.80 1 . 0000 11.00 1. 0000 e 11. 20 1. 0000
- 11. 40 1. OOOO 11.60 1 OOOO
~
- 11. 80 1. 0000
- 12. 00 1.0000 Top and Bottom 15X 2 3 4 5 6 7 8 9 10 11 1 2 excluded as per Technical CORE H EIG HT (Feet) Spec1f ) cat 1 on 4.2.2.2.
This figure is referred to by Technical Specifications 4.2.2.2c S3/4.2.2 Page 5 of 10 (REV 0)
FIGURE 5 SHEARON HARRIS UNIT 1 CYCLE 2 RAOC W(Z) AT 12000 MWD/MTU 1.35 44'eight ~Feet 0.00 0.20 0.40 0.60 0.80 1.00 EOL
~Mz
- 1. 0000 1 0000
~
1 . 0000 1 0000
~
- 1. 0000
- 1. 0000 1 ~ 20 1. 0000
- 1. 30 1. 40 1 . 0000
- 1. BO 1.0000
- 1. 80 .2266 2.00 . 2104
- 2. 20 . 1939 2.40 . 1770 2.60 ~ 1598 2.80 . 1430 3.00 . 1229 1.25 3.20 . 1129 3.40 . 1193 3.60 . 1273 3.80 . 1415 4.00 . 1565 4.20 ~ 1694 4.40 . 1811 4.60 . 1910 4.80 . 1993 1.20 5.00 .2052 5.20 . 2108 5.40 . 2215 5.60 . 2401 5.80 .2563 6.00 .2694 6.20 .2802 6.40 .2882 6.60 .2934
- 1. 15 6.80 ~ 2957 7.00 ~ ~ 2950 7.20 . 2913 7.40 .2845 7.60 .2747 7.80 .2B17 8.00 .2462 8.20 .2269 8.40 1. 2124 8.60 1.2151
- 1. 10 8.80 1. 2143 9.00 1. 2124 9.20 1. 2092 9.40 1.2050 9.60 1.2149 9.80 1. 2528
- 10. 00 1. 2941
- 10. 20 1 '298
- 10. 40 1.0000
- 1. 05 10.60 1.0000
- 10. 80 1. 0000 11.00 1 0000
~
11.20'1. 1 0000
~
40 1. OOOO
- 11. 60 1.0000 11.80 1.0000 12 00 ~ 1. 0000 1.00
- Top and Bottom 15X 4 5 6 7 8 9 10 11 12 excluded as per Technical CORE HEIGHT (F Speci f 1 cation 4.2 '.2.
This figure is referred to by Technical Specifications 4.2.2.2c SS/4.2.2 Page 6 of 10 (REV 0)
SHEARON HARRIS UNIT 1 CYCLE 2 TABLE 1 BASE LOAD OPERATING LIMITS The following data is required to define the operating limits for Base Load Operation.. These data are referred to in Technical Specifications 3.2.1, 4.2.2.3a, 4.2.2.4c, and B3/4.2.1.
Parameter Operating Limits AFD Limits within a +3% band about the target AFD APLND 85 percent of rated thermal power W(z) Curves Figures 6 through 8 Page 7 of 10 (REV 0)
h, qV IQ e >g ig bg C
FlGURE 6 ~+>
SHEARON HARRIS UNlT 1 CYCLE 2 BASE LOAD W(Z) AT 150 MWD/MTU FOR POWER LEVELS ABOVE 85% OF RATED THERMAL POWER Height BOL I I II ~Feet ~ez 0.00 1. 0000 0.20 1. 0000 0.40 1.0000
~ I 0.60 1.0000 0.80 1. 0000 1.00 1. 0000
- 1. 20 1 . 0000 1.40 1 . 0000 1.60 1.0000
- 1. 80 1.0779 2.00 1. 0771 2.20 1.0760 2.40 1. 0746 l ~ 2.60 1.0730 2.80 1. 0712 3.00 1. 0692 3.20 1 . 0670 3.40 1 . 0646 Id I I I 3.60 1.0625 3.80 1. 0608 11 I I 4.00 1. 0596 dl 4.20 1.0586 4.40 1. 0574 4.60 1.
4.80 0561'.
0547 5.00 1 ~ 0532 I I I 5.20 1 ~ 0516 5.40 1. 0499 5.60 1 0482
~
5.80 1.0463 le i 6.00 1.0443 6.20 1.0422 6.40 1.0399 6.60 1.0376 6.80 1.0355 7.00 1.0352 7.20 1 0360
~
7.40 1.0372 7.60 1. 0395 7.80 1.0419 8.00 1.0443 8.20 1.0467 8.40 1.0491 8.BO 1.0515 8.80 1.0539 9.00 1. 0563 9.20 1. 0587 9.40 1.0609 9.BO 1. 0631 9.80 1. 0652
- 10. 00 1.0671 10.20 1 0688
~
- 10. 40 1 0000
~
10.60 1 0000
~
10.80 1 . 0000
- 11. 00 1.0000
- 11. 20 1. 0000
- 11. 40 1. 0000 11.60 1. 0000
- 11. 80 1. 0000
~
1
- 12. 00 1.0000 4 5 6 7 8 9 10. 11 12 Top and B ottom 15'X excluded as per CORE HEIGH T (F eet Technical Speci f 4.2.2.4.
1 ca tion This figure is referred to by Technical Specifications 4.2.2.3a 4.2.2.4c S3/4.2.2 Page 8 of 10 (REV 0)
ik ip y,
'F oW tt,
'I
(
's'm ~
q I
kv
~ 4
FIGURE 7 SHEARON HARRIS UNIT 1 CYCLE 2 BASE LOAD W(Z) AT 6000 MWD/MTU FOR POWER LEVELS ABOVE 85% OF RATED THERMAL POWER HeIght MOL
~Feet ~ll z 0.00 l
i l
I lilt l ll Il htl 0.20 0.40
- 1. 0000 1 . 0000 1.0000
- 1. 10 0.60 1.0000 li I i i ii 0.80 1.00 1.0000 1.0000 I I I I I I I 1.20 1 0000
~
- 1. 40 1. 0000 1.60 1. 0000 1.09 ll I I I 1. 80 2.00 1 . 0907 1.0878 l < I I I 2.20 1.0846 2.40 1 0809
~
ib 2.60 1.0769 1.08 2.80 1.0726 3.00 1.0681 3.20 1. 0635 3.40 1.0597 3.60 1. 0586 3.80 1. 0573 1.07 4'.00 1.0558 4.20 1 '542 4.40 1.0526 4.60 1.0509 4.80 1.0490 5.00 1. 0471 1.06 ill I 5.20 5.40
- 1. 0452
- 1. 0431 N 5.60 1.0409 5.80 1. 0411 6.00 1.0419 1.05 I l I I 6 '0 6.40 1.0424
- 1. 0428 6.60 1 0430
~
6.80 1.0430 7.00 1.0430 7 '0 7.40 1.0426
- 1. 0427
>.o4 7.60 1.0460 7.80 1. 0498 8.00 1. 0534 8.20 1. 0571 8.40 1.0608 8.60 1 '645 1.03 8.80 1.0681 9.00 1.0716 9.20 1.0749 9.40 1. 0782 9.60 1. 0815 1.02 9.80 1.0846
- 10. 00 1.0873
- 10. 20 1. 0896
- 10. 40 1. 0000
- 10. 60 1.0000
- 10. 80 1 . 0000 1.01 11.00 1. 0000 11.20 1 . 0000
- 11. 40 1. 0000 11.60 1 . 0000
- 11. 80 1 . 0000
- 12. 00 1. 0000 1.00 2 3 4 5. 7 9 10 11.- 12 > Top and Bottom 15%
excluded as per ORE HE IGH T (Feet Techntcal Spec 1 f 1cat I on 4.2.2.4 ~
This figure is referred to by Technical Specifications 4.2.2.3a 4.2.2.4c S3/4.2.2 Page 9 of 10 (REV 0)
0 FIGURE 8 SHEARON HARRIS UNIT 'I CYCLE 2 BASE LOAD W(Z) AT 12000 MWD/MTU FOR POWER LEVELS ABOVE 85% OF RATED THERMAL POWER aviv vv t Height
~Fact EOL
~tv z II I I 0.00 1. 0000 I i I I I I I i I 0
0
'0
'0 F 0000 1 . 0000
~
I v' I I I 0.60 1. 0000
- 1. 10 iI i V tv 0.80 1.0000 1.00 1.0000
- 1. 20 1.0000 1.40 1.0000 1.60 1 F 0000 1.09 1. 80 1. 1044 2.00 1 0994
~
2.20 1.0938 2.40 1.0878 2.60 1. 0815 2.80 1. 0749 1.08 3.00 1 0678
~
3.20 1.0820 3.40 1.0585 I itv 3.60 1.0559 3.80 1.0531 4.00 1.0503 1.07 4.20 1.0475 4.40 1. 0448 4.60 1. 0421 4.80 1. 0396 5.00 1.0368 1.06 5.20 1.0349 I i I I I I I 5.40 1.0348 I I I I 5.60 1. 0354 5.80 1. 0360 6.00 1.0364 6.20 1. 0370 1.05 I F 6.40 1.0384 I I I I 6.60 1.0403 6.80 1.0419 7.00 1.0432 7.20 1.0443 7.40 1. 0451 1.04 7.60 1.0457 7.80 1 ~ 0465 8.00 1. 0499 8.20 1. 0548 8.40 1.0592 8.60 1.0637 1.03 8.80 1.0682 9.00 1. 0725 9.20 1. 0768 9.40 1. 0806 9.60 1.0844 9.80 1.0878
- 1. 02 Iv I 10. 00 1.0907
- 10. 20 1.0932
- 10. 40 1 . 0000
- 10. 60 1.0000
- 10. 80 1.0000 1.01 11.00 1.0000 I I I I 11.20 1.0000
- 11. 40 F 0000 11.60 1. 0000
- 11. 80 1 0000
~
- 12. 00 1.0000 1,00 > Top and Bottom 15%
5 6 7 8 9 10 11 12 excluded as per ORE HEIGHT (Fe e't ) Technical Spec) f lest{on 4.2.2.4.
This figure is referred to by Technical Specifications 4.2.2e3a 4.2.2.4c S3/4.2.2 Page 10 of 10 (REV 0)
ATTACllMENT 6 SIGNIFICANT HAZARDS EVALUATION FOR THE SHEARON HARRIS NUCLEAR POWER PLANT TRANSITION TO WESTINGHOUSE 17 x 17 VANTAGE 5 FUEL ASSEMBLIES (277CRS/lah)
I
, Carolina Power & Light Company has evaluated the proposed changes associated with the transition to VANTAGE 5 fuel against the Significant Hazards Criteria of 10CFR50.92 and against NRC guidance concerning the application of this standard. The Shearon Harris Nuclear Power Plant (SHNPP) proposed license amendment is closely related to an example (51 FR 7751) of action not likely to involve a significant hazard. Specifically, Example (iii) of the guidance states:
"For a nuclear power reactor, a change resulting from a nuclear reactor core reloading, if no fuel assemblies significantly different from those found previously acceptable to the NRC for a previous core at the facility in question are involved. This assumes that no significant changes are made to the acceptance criteria for the Technical Specifications, that the analytical methods used to demonstrate conformance with Technical Specifications and regulations are not significantly changed, and that the NRC has previously found such methods to be acceptable."
The SHNPP proposed licensing amendment is directly related, to. the above.,
example in that the core reload uses VANTAGE 5 fuel which is not'significantly different from previous cores at SHNPP, the changes to the Technical Specifications are as a result of, the core reload and not because of any significant change made to the acceptance criteria for Technical Specifications, and the analytical methods and designs used in the required reload analysis have been previously found acceptable by the NRC. Detailed descriptions of the VANTAGE 5 fuel and the Westinghouse reload methodology can be found in WCAP-10444-P-A (Proprietary) and WCAP-10445 (Nonproprietary),
"Reference Core Report VANTAGE 5 Fuel Assembly" and WCAP"9272-P-A (Proprietary) and WCAP-9273-A (Nonproprietary), "Westinghouse Reload Safety Evaluation Methodology," respectively. Both of these reports have received generic approval from the NRC. WCAP-9272-P-A was utilized in the reload evaluation for SHNPP Cycle 2. Therefore, based on the above, CP&L" concludes that the proposed Technical Specification changes do not involve a significant hazard consideration.
CP&L has evaluated the proposed changes in design, analytical methodologies, and Technical Specifications associated with the transition to VANTAGE 5 fuel and the use of a Core Operating Limits Report against the Significant Hazards Criteria of 10CFR50.92. The results of CP&L's evaluations demonstrate that the changes do not involve any significant hazard as described below.
- a. The probability or consequences of an accident previously evaluated is not significantly increased.
The VANTAGE 5 reload fuel assemblies are mechanically and hydraulically compatible with the current low parasitic (LOPAR) fuel assemblies, control rods, reactor internals interfaces, the fuel handling equipment, and the refueling equipment. The VANTAGE 5 design dimensions are essentially equivalent to the current SHNPP LOPAR assembly design from an exterior assembly envelope and reactor internals interface standpoint. Also, the implementation of VANTAGE 5 fuel does not cause a significant change in the physics characteristics of the SHNPP cores beyond the normal range of.,
variation seen from cycle to cycle. Thus, both fuel types satisfy the design basis for SHNPP as proposed for this amendment.
(277CRS/lych)
0 The proposed changes have been assessed from a core design and safety analysis standpoint. No increase in the probability of occurrence of any accident was identified, but an extensive reanalysis, as described in the Reload Transition Safety Report, was required to demonstrate compliance with the revised SHNPP Technical Specifications as proposed herein. These reanalyses applied methods which have been previously found acceptable by the NRC. The results, which includes transition core effects, show changes in consequences of accidents previously analyzed. However, the results are all clearly within pertinent acceptance criteria and demonstrate the plant's capability to operate safely at 100 percent power.
The use of a Core Operating Limits Report follows the guidelines set Eorth in NRC Generic Letter 88-16, Removal of Cycle-Specific Parameter Limits from Technical Specifications. The use of this report is administrative in nature and does not impact the present analyses or future analyses since the relaxed axial offset control and rod insertion limits will continue to be calculated with approved NRC methodology.
The Cycle 2 corrections which include the elimination of Surveillance Requirement 4.2.l.l.a.2 requiring monitoring and logging of indicated AFD for a 24-hour period after the automatic computer monitoring is returned to an operable status and the deletion of a reference to LCO 3.1.1.1 in Action 5 of TS 3.3.1 are strictly administrative in nature and as such, do not significantly increase the probability or consequences of an accident previously evaluated.
Thus, it is concluded that there is not a significant increase in the consequences of an accident previously evaluated.
The possibility for an accident or malfunction of a different type than any evaluated previously in the safety analysis reports is not created.
These proposed changes do not signiEicantly affect the overall method and manner of SHNPP operation and can be accommodated without'"compromising the<
performance or qualiEication of safety-related equipment. Thus, the creation of a new accident or different kind of accident from any previously evaluated accident is not considered a possibility.
The margins of safety as defined in the bases of the Technical Specifications are not significantly reduced.
The analysis oE the LOPAR and VANTAGE 5 fuel is based on the NRC approved Improved Thermal Design Procedure (ITDP) (WCAP-8567, "Improved Thermal Design Procedure" ). The LOPAR fuel analysis uses the WRB-1 DNB correlation, while the VANTAGE 5 Euel analysis utilizes the WRB-2 DNB correlation. These DNB correlations take credit for the significant improvement in the accuracy of the critical heat flux predictions in comparison with previous DNB correlations. The WRB-2 DNB correlation also takes credit for the VANTAGE 5 fuel assembly mixing vane design. A DNBR limit of 1.17 is applicable for both the WRB-1 and WRB-2 correlations. In addition, the W-3 DNBR correlation is used where appropriate.
When appropriate, the design method employed to meet the DNB design basis is the ITDP. Uncertainties in plant operating parameters, nuclear and (277CRS/lnh)
y:
thermal parameters, and fuel fabrication parameters are considered statistically such that there is at least 95 percent probability at a 95 percent confidence level that the minimum DNBR will be greater than or equal to 1.17 for the limiting power rod. Plant parameter uncertainties are used to determine the plant DNBR uncertainties. These DNBR uncertainties, combined with the DNBR limit, establish a DNBR value which must be met in plant safety analyses. In addition to the above considerations, specific plant DNBR margin is included in the analyses. A part of the plant-specific margin is used to accommodate a transition core penalty due to the localized flow redistribution resulting from the VANTAGE 5 intermediate flow mixing grids and an appropriate fuel rod bow DNBR penalty. Since the parameter uncertainties are considered in determining the design DNBR value, the plant safety analyses are performed using values of input parameters without uncertainties. The change to ITDP and the use of new DNBR correlations does not involve a significant reduction in the margin of safety since the DNB design basis (i.e., that there is a 95X probability with a 95X confidence level that the hottest rod does not experience DNB) remains unchanged. In addition,, the:.,
increased core hydraulic resistance due to the IFH grids results in an increase in the control rod scram time to the dashpot from 2.2 seconds to 2.7 seconds. This increase, as well as the other effects of the changes in the design, have been incorporated in the non-LOCA and LOCA transient analyses. In some cases, an increase in a parameter (such as pressure or peak clad temperature) occurs and may reduce the margin between the analysis and the pertinent acceptance criterion. The results of the new non-LOCA analyses indicate that the ANS Condition II, III, and IV acceptance criteria as endorsed by NRC NUREG-0800 are still met. The results of the new LOCA analyses indicate that for breaks up to a double-ended severence of the, reactor coolant piping, the Emergency Core Cooling System will meet the acceptance criteria of 10CFR50.46.
The use of the Core Operating Limits Report is administrative and does not impact existing analyses or future analyses since the relaxed axial offset control limits and rod insertion limits will continue to be'determi:ned 'f'r each cycle using NRC approved methodology. As indicated in proposed Technical Specification 6.9.1.6, these limits shall continue to be determined so that all applicable limits of the safety analyses are met.
The Cycle 2 corrections are administrative in nature and as such, do not significantly reduce the margins of safety as defined in the bases of the Technical Specifications.
Therefore, the results of the changes are clearly within all pertinent design and safety acceptance criteria using approved methods. Thus, there is no significant reduction in the margin of safety.
(277CRS/lah)
ATTACHMENT 7 RADIOLOGICAL IMPACT ASSESSMENT FOR THE SHEARON HARRIS NUCLEAR POWER PLANT TRANSITION TO WESTINGHOUSE 17 x 17 VANTAGE 5 FUEL ASSEMBLIES (277CRS/Iah)
S I lf lK V J a I t4
" ~
Radiolo ical
~
Im act Assessment CP&L has reviewed accidents analyzed in the Final Safety Analysis Report (FSAR) with respect to the radiological, source terms and radiological consequences in association with the transition to Vantage-5 fuel. The possible avenues for a change in radiological consequence are the applicability of the existing fission product source terms for the Vantage-5 fuel and core designs, and whether the specific amount of calculated fuel failures in any accident increases.
By separate letter, dated April 11, 1989 (NLS-89-074), CP&L indicated that the source terms currently utilized in the FSAR were applicable for fuel enrichments up to 5.0 w/o U-235 and batch average discharge burnups up to 50,000 WD/MTU. The proposed change to Vantage-5 fuel will operate within these restrictions; therefore, the existing source terms remain applicable.
For those events in Chapter 15 which had to be reevaluated as a result of the proposed changes, no increase in the amount of fuel failures was calculated.
Since there was no increase in failed fuel and the fission product source terms are unaffected, there is no impact on the, radiological,consequencesl@ ~--"'-
resulting from the proposed changes. For the Steam Generator Tube Rupture Analysis (SGTR), an increase in offsite doses resulted from revised initial steam generator conditions. The results of the revised analysis continue to show that the offsite doses for SGTR are well within the allowable guidelines ~
specified in the Standard Review Plan, NUREG-0800 and 10 CFR 100.
(277CRS/I ah )
0