ML17334B233
| ML17334B233 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 10/05/1988 |
| From: | Alexich M INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG |
| To: | Murphy T NRC OFFICE OF ADMINISTRATION & RESOURCES MANAGEMENT (ARM) |
| References | |
| RTR-REGGD-01.097, RTR-REGGD-1.097 AEP:NRC:0773AB, AEP:NRC:773AB, NUDOCS 8810130179 | |
| Download: ML17334B233 (117) | |
Text
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ACCESSION NBR:8810130179 DOC.DATE: 88/10/05 NOTARIZED: NO 'DOCKET FACXL:50-315 Donald C. Cook Nuclear Power Plant, Unit 1, Indiana & 05000315 50-316 Donald C. Cook Nuclear Power Plant, Unit 2, Indiana 6 05000316 AUTH. NAME AUTHOR AFFILIATION ALEXICH,M.P. Indiana Michigan Power Co. (formerly Indiana 6 Michigan Ele.
RECIP.NAME RECIPIENT AFFILIATION MURPHY,T.E. Document Control Branch (Document, Control Desk)
SUBJECT:
Provides updated status rept re implementation of Reg Guide 1.97,Rev 3 for plant.
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TITLE: OR/Licensing Submittal: Suppl 1 to NUREG-0737(Generic Ltr 82-33) t'k N
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Indiana Michigan Power Company P.O. Box 16631 Columbus, OH 43216
à AEP:NRC:0773AB Donald C. Cook Nuclear Plant Units 1 and 2 Docket Nos. 50-315 and 50-316 License Nos. DPR-58 and DPR-74 REGULATORY GUIDE 1.97, REVISION 3 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D.C. 20555 Attn: T. E. Murley October 5, 1988
Dear Dr. Murley:
The purpose of this letter is to provide you with an updated status report (attached) that details our compliance with Revision 3 of Regulatory Guide 1.97. In our previous submittal (AEP:NRC:0773AC, dated June 20, 1988), we had committed to providing you this updated status report by October 1, 1988. This status report consolidates, clarifies and updates all of our previous submittals (AEP:NRC:07730, dated October 15, 1985 and AEP:NRC:0773S, dated June 29, 1987). We again request that your final licensing decision concerning Regulatory Guide 1.97, Revision 3 be based on the attached updated status report.
This document has been prepared following Corporate procedures which incorporate a reasonable set of controls to ensure its accuracy and completeness prior to signature by the undersigned.
Sincerely, M. P. Alexich Vice President MPA/eh Attachment cc: D. H. Williams, Jr.
W. G. Smith, Jr. - Bridgman R. C. Callen G. Charnoff (oo>
G. Bruchmann A. B. Davis - Region III NRC Resident Inspector - Bridgman
'h Dr. T. E. Murley AEP:NRC:0773AB bc: S. J. Brewer/R. A. Kraszewski S. H. Horowitz/T. 0. Argenta/R. C. Carruth J. J. Markowsky/S. H. Steinhart/P. G. Schoepf J. G. Feinstein P. A. Barrett M. L. Horvath - Bridgman J. F. Kurgan J. B. Shinnock J. F. Stang, NRC - Washington, D.C.
AEP:NRC:0773AB DC-N-6015.1
ATTACHMENT TO AEP'NRC'0773AB STATUS REPORT IMPLEMENTATION PLAN OF REGULATORY GUIDE 1.97, REVISION 3, FOR THE DONALD C. COOK NUCLEAR PLANT UNITS 1 AND 2 8810130179 I
ATTACHMENT TO AEP:NRC'0773AB Page 1
1.0 BACKGROUND
In August 1984, American Electric Power Service Corporation (AEPSC) contracted the engineering consulting firm of DiBenedetto, Farwell &
Hendricks to perform the detailed design study required to determine the status of the Cook Nuclear Plant Units 1 and 2 compliance with Regulatory Guide 1.97, Revision 3. A preliminary Status Report (AEP:NRC:0773J dated February 28, 1985), based on preliminary findings by our consultant, was submitted to the NRC staff. A Final Status Report (AEP:NRC:07730 dated October 15, 1985) was then issued based on further work done by our consultant, with the understanding that further updating may be necessary. We subsequently issued an update to our October 15, 1985, submittal (AEP:NRC:0773S dated June 29, 1987) that responded to numerous questions asked by the NRC in a Preliminary Technical Evaluation Report and also submitted various specific deviations from Regulatory Guide 1.97, Rev. 3 recommendations. In order to consolidate, clarify, and update our previous submittals, AEP:NRC:0773J, AEP:NRC:07730, AEP:NRC:0773S, we are submitting this document for NRC review and final licensing action.
It should be noted that because design change activities have been ongoing since 1986 with respect to Regulatory Guide 1.97, some planned actions identified in AEP:NRC:07730 have since been completed. These items are identified within Section 3.0 of this letter as "No Further Action Required" in the Remarks/Action Req'd column and listed as "CMPLT" in the Unit 1 or Unit 2 Schedule column.
2.0 STATUS REPORT Section 3.0 of this attachment contains information regarding instrument range, environmental qualification, seismic qualification, quality assurance, redundancy, power supply, location of display, remarks, and, as appropriate, an upgrade schedule for each type A,B,C,D and E variable listed in Regulatory Guide 1.97, Revision 3. The format and content of Section 3.0 is
ATTACHMENT TO AEP'NRC:0773AB Page 2 consistent with the requirements of Section 6.2 of Supplement No. 1 to NUREG-0737. Section 3.0 is also consistent in organization with Table 3 (PWR Variables) of Regulatory Guide 1.97, Rev. 3 dated May 1983. The schedule for each instrument indicates, as applicable, when the recommendations of Regulatory Guide 1.97, as described in this attachment, will be met.
In those instances in which the design of our post-accident monitoring (PAM) systems deviate from the guidance provided in Regulatory Guide 1.97, Revision 3, these deviations are explicitly identified in the Section 3.0 tables, consistent with the requirements of Section 6.2 of Supplement 1 to NUREG-0737. A discussion of each deviation is contained in Section 2.1 and 2.2. A summary of deviations is provided in Section 2.3. The Section 2.3 summary also cross-references the deviations to Section 3.0 table entries.
2.1 DEVIATIONS RELATED TO LICENSED DESIGN This section provides a discussion of those areas in which we have identified deviations from the Regulatory Guide 1.97, Revision 3 recommendations where the deviations are primarily a result of the originally licensed design of the Cook Nuclear Plant. A deviation number is assigned to each deviation identified; these deviation numbers are used in the Section 2.3 summary and the Section 3.0 table entries.
2.1.1 Deviation No. DV-1 Environmental uglification As provided by 10 CFR 50.49(k), originally installed Cook Nuclear Plant Qualified instrumentation located in potentially harsh environment has been qualified in accordance with "Guidelines for Evaluating Qualification of Class 1E Electrical Equipment in Operating Reactors," November 1979 (DOR Guidelines). Qualified equipment ordered after February 22, 1983, is to have environmental qualification in accordance with Category I of NUREG-0588 (i.e.,
IEEE Std. 323-1974) unless there are sound reasons to the contrary.
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ATTACHMENT TO AEP:NRC:0773AB Page 3 Equipment located in a mild environment is not required to be environmentally qualified. The above is consistent with the current licensing basis of the Cook Nuclear Plant. However, because we do not literally comply with the Reg. Guide 1.97 recommendations for environmental qualification, we are noting herein our deviation from the Reg. Guide 1.97 guidance on this issue.
2.1.2 Deviation No. DV-2'eismic uglification Seismically qualified equipment meets the provisions of Cook Nuclear Plant Updated FSAR p. 7.2-12 dated July 1982 (i.e., protection equipment is designed such that, for a design basis earthquake, the equipment will not lose its capability to perform its design objective, to shut the plant down and/or maintain the unit in a safe shutdown condition). Reactor protection Instrumentation originally installed at the Cook Nuclear Plant was seismically tested by Westinghouse Electric Corporation as documented in WCAP-7397-L, "Topical Report Seismic Testing of Electrical and Control Equipment" dated January 1970. No industry standards regarding seismic qualification existed at that time. Consistent with our current licensed design, equipment ordered for Regulatory Guide 1.97 upgrading will be seismically qualified in accordance with IEEE Std. 344-1975 unless there are sound reasons to the contrary. Seismic qualification for existing Category 1 circuits is provided from the sensor up to and including the channel isolation device (shown as a "Signal Isolator" in Figure 2.1-1), typically installed in the reactor protection cabinets located in the control room area. Our design does not provide for seismic qualification of equipment beyond the channel isolation device for existing Category 1 circuits; however, we have installed seismically qualified indicators and/or recorders on variables monitored by Category 1 instrumentation. This was done because we believe that the primary indicators/recorders that provide direct Category 1 variable indication are the only credibly vulnerable equipment installed beyond the isolators that could provide ambiguous or misleading information due to a failure during a seismic event.
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ATTACHMENT TO AEP:NRC:0773AB Page 4 It should be noted that other equipment beyond the channel isolation device (such as control equipment) that directly provides information for the channel indication is of a similar design to existing equipment that is seismically qualified (such as reactor protection instrumentation). As such, in spite of the fact that we do not take credit for seismic qualification, we believe that this equipment would not provide ambiguous or misleading information to the operator following a seismic event.
Our design does not provide seismic qualification of cables and equipment within the non-safety related portion of the PAM circuits.
Nevertheless non-safety related portions of the PAM channels that directly provide PAM indication are located in the control room, or control room vault, which are seismically qualified structures.
Cables and equipment associated with PAM circuits located outside cable vault areas (e.g., cables to valves, cables to Technical Support Center (TSC) I/O cabinets) may not be maintained entirely in a seismically qualified structure.
Since our current licensing basis, as described above, does not literally comply with the Reg. Guide 1.97 recommendations for seismic qualification beyond the isolation device for existing circuits, we are noting herein our deviation on this issue. Figure 2.1-1 provides an example of an existing PAM channel that is typical of our originally licensed plant design.
Consistent with the Cook Nuclear Plant licensing basis, PAM instrument channels or portions thereof scheduled to be upgraded or added per Reg. Guide 1.97 and requiring seismic qualification will be installed to meet Reg. Guide 1.97 Category 1 recommendations except as noted above and in the tables in Section III.
2.1.3 Deviation No. DV-3'alit Assurance The provisions of the Cook Nuclear Plant QA program as described in Updated FSAR Section 1.7 have been applied to the safety-related
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ATTACHMENT TO AEP:NRC:0773AB Page 5 portions of the PAM circuitry. This program satisfies the requirements of 10 CFR 50, Appendix B. The implementation of specific Regulatory Guides and ANSI Standards regarding quality assurance is consistent with the commitments of Cook Nuclear Plant FSAR Section 1.7, Appendix A, dated July 1988, which address all but one (Regulatory Guide 1.28) of the guidance documents referenced by Reg. Guide 1.97, Rev. 3. The Cook Nuclear Plant QA program has not necessarily been applied to non-safety related portions of the PAM system (see Fig. 2.1-1).
Since we do not literally comply with the Reg. Guide 1.97, Rev. 3 quality assurance recommendations, we have noted herein our deviations from the Reg. Guide guidance in this area.
2.1.4 Deviation No. DV-4'edundanc Instruments installed at the Cook Nuclear Plant to meet redundancy requirements have a minimum of two (2) redundant, electrically independent and physically separate channels up to and including any isolation device (shown as "Signal Isolator" in Figure 2.1-1) typically installed in the reactor protection cabinets located in the control room area. For existing circuits, the isolation device is providing isolation between safety-related circuits and
,non-safety related circuits, which includes portions of the PAM circuitry as per our licensed design. The display may be a common multi-pen recorder or a dual indicator. Separation of safety-related circuits up to and including the isolation device is in accordance with Updated FSAR p. 7.2-4 dated July 1982 Figure 2.1-1 is an electrical schematic that shows a typical cable and hardware configuration for redundant PAM channels. This illustration presents a typical configuration and is not meant to represent an actual circuit. Exact circuit configuration may vary from the illustration. This configuration reflects our originally licensed design. This design was completed prior to the issuance of the NRC guidance regarding physical independence of electrical
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ATTACHMENT TO AEP:NRC:0773AB Page 6 systems (Regulatory Guide 1.75, September 1978) and the associated IEEE standard for separation of Class 1E equipment and circuits (IEEE Std. 384-1974).
Physical separation (of both electrical cabling and hardware) is maintained between the redundant reactor protection set channels.
The BOP interconnecting cabling between the reactor protection cabinets and the various PAM readout devices is routed through the cable vault area and then back to the control room. The redundant PAM signal and power cables in the cable vault area and in the control room are not physically separated. Also, the redundant PAM readout devices are not physically separated. As previously stated, there are also some cases of redundant PAM signal cabling feeding a single readout device (recorder or computer).
At the request of NRC staff, an evaluation of the impact of this lack of physical separation in these areas was performed. This evaluation identified two events that have the potential for compromising the integrity of the PAM system as presently installed.
These events are a fire in the cable vault area or a severe natural phenomenon. In the case of a severe natural phenomenon, the only event of significance with regard to the cable would be an earthquake. Even in the unlikely event, of a design-basis earthquake, the PAM system will continue to serve its intended function, after the appropriate system modifications have been completed. In the event of a fire in the cable vault area, we would not expect to need the PAM instruments to follow the course of another accident, and the ability to bring the plant to a safety configuration would not be compromised. This position is consistent with actions we have taken to ensure compliance with Appendix R to 10 CFR 50, "Fire Protection Program for Nuclear Power Facilities Operating prior to January 1, 1979."
Figure 2.1-1 also shows cables leaving the control room and vault areas and going out into other plant areas. These areas in most cases will not offer the same missile and fire protection as offered
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ATTACHMENT TO AEP'NRC:0773AB Page 7 by the control room and vault areas. The signals going to these remote areas are also not isolated from the PAM signals in the control room or cable vault areas. The cables in mbst cases have been installed in tray and conduit which has been mounted to the same requirements as safety-related tray and conduit. The cable is the same as that used for safety-related circuits. The redundant PAM signal cables are not physically separated. In some cases, cables carrying redundant signals also terminate in a cabinet or device that has not been designed to the same separation requirements as safety-related devices. These cabinets or devices may not be seismically qualified.
Consistent with the current licensing basis of the Cook Nuclear Plant PAM instrument channels or portions thereof scheduled to be upgraded or added per Reg. Guide 1.97 and requiring redundancy will be installed to meet Category 1 recommendations except as noted above and in the tables in Section III.
Since our current license design as described above, does not conform to the Reg. Guide 1.97, Rev. 3 recommendations for physical separation beyond the isolation devices installed in PAM circuits, we are noting herein our deviations from the Reg. Guide guidance on this issue.
2.1.5 Deviation No. DV-5 Dis la Location The display will be indicated either inside the control room or at another location as permitted by Regulatory Guide 1.97. In some instances, the analog recording of Category 1 variables is not directly provided, however the Technical Support Center computer does record these variables when analog recording is not provided.
Because we do not literally comply with the recording recommendations of Reg. Guide 1.97 Rev. 3 for Category 1 variables, we are noting herein our deviation from the Reg. Guide guidance on this issue. Please note that this applies to analog variables only, Discrete variables such as breaker or valve positions are not recorded.
ATTACHMENT TO AEP'NRC:0773AB Page 8 2.2 DEVIATIONS IDENTIFIED FOR SPECIFIC VARIABLES 2.2.1 Deviation No. DV-6'ontainment Pressure Monitoring of containment pressure is currently provided by two Category 3 wide-range (-5 to 36 psig) instruments and four Category 3 narrow-range (-5 to 12 psig) instruments. The design pressure of the Cook Nuclear Plant containments is 12 psig. The four narrow-range instruments are scheduled to be upgraded to meet Reg.
Guide 1.97 Category 1 recommendations by the end of the 1987 refueling outage for Unit 1 (which has been completed) and by the end of the 1988 refueling outage for Unit 2.
The vide-range containment pressure instrumentation ranges were revised to meet the requirements of NUREG-0578 and NUREG-0737.
However, these instruments are not powered by an emergency standby power source as recommended by Regulatory Guide 1.97, Rev. 3 for Category 1 instrumentation, and they do not meet the Category 1 separation criteria. The wide-range instrumentation is, however, highly reliable, and as a result we believe it is unlikely that it would not be available if needed to monitor the course of an accident. Further, for other than short-term individual compartment pressure peaks, the narrow-range instrumentation would span the range of pressure anticipated in our evaluation of loss-of-coolant type accidents. The above justification is the basis for our deviation from the Regulatory Guide 1.97, Rev. 3 recommendation to provide Category 1 wide-range containment pressure instrumentation.
2.2.2 Deviation No. DV-7'ubcoolin Meter The saturation meter equipment was originally installed in accordance with the requirements of NUREG-0578. In an SER dated March 20, 1980, the equipment installed to monitor degrees of subcooling was found to be acceptable (NRC letter, A. Schwencer to John E. Dolan, dated March 20, 1980). As noted in that correspondence, the device installed was- a discrete digital monitor,
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ATTACHMENT TO AEP:NRC:0773AB Page 9 and the plant process computer was used in conjunction with this monitor to provide subcooling margin. Additionally, as part of the NUREG-0737 Supplement 1 requirements, a subcooling margin is provided by our Technical Support Center computer. We believe that these three instrument systems, which have been installed to be consistent with the requirements of their appropriate documents, are reliable. As a result, we believe it is unlikely that they would not be available if needed to monitor the course of an accident.
Further, neither NUREG-0578, nor subsequently, NUREG-0737 required seismic qualification or redundancy for this instrumentation.
The above information is the basis for our deviation from the Regulatory Guide 1.97, Rev. 3 recommendation to provide Category 1 instrumentation for monitoring degrees of subcooling. (This deviation is also discussed in AEP:NRC:0773S, Attachment 1, Item 3.3.3.)
2.2.3 Deviation No. DV-8'eactor Coolant S stem RCS Sam lin Boron Concentration Ran e Primary coolant boron concentration can be measured in the range of 375 ppm to 10,000 ppm. This range is based on PASS reactor coolant samples with a 1:1000 dilution.
The PASS would be used during and following loss-of-coolant accidents. In the event of a LOCA, emergency boration and injection from the refueling water storage tank would occur and we would therefore expect a reactor coolant boron concentration substantially in excess of the low range of our PASS sample measurement capability.
The above is the basis for our deviation from the Regulatory Gui.de 1.97, Rev. 3 recommendation to provide the capability to measure boron concentration in PASS samples to the lower limit of 0 ppm.
(This deviation was also discussed in AEP:NRC:0773S, Attachment 1, Item 3.3.2.)
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ATTACHMENT TO AEP:NRC:0773AB Page 10 2.2.4 Deviation No. DV-9'CS Sam lin adioactivit As stated in our original submittal (AEP:NRC:07730, dated October 15, 1985), the primary coolant system radioactivity is not continuously monitored by in-line instrumentation. Rather, periodic analysis of reactor coolant grab samples is provided to detect deterioration of fuel cladding. Our post-accident sampling system provides a diluted grab sample that is analyzed by the gamma spectrum analyzer in a range of 1 uCi/ml to 10 Ci/ml. This measurement range is consistent with the Reg. Guide 1.97, Rev. 3 recommendations for this parameter. The above information is the basis for our deviation from the Regulatory Guide 1.97, Rev. 3 recommendation for continuous monitoring of radioactivity in the reactor coolant system. (This deviation was also discussed in AEP:NRC:0773S, Attachment 1, Item 3.3.5.) It should also be noted that Category 1 requirements for this system are only to be applicable to equipment that operates equipment installed in the portion of piping that is Seismic Class I. Electrical equipment operating equipment installed in Seismic Class 3 piping is to meet Category 3 requirements.
2.2.5 Deviation No. DV-10'ench Tank Level We do not rely on the quench tank to perform any pose-pressurizer release function. However, we are providing the following information in response to the evaluation of our October 15, 1985, submittal (AEP:NRC:07730) performed by EG6G on behalf of the NRC.
The range of 74% of total tank volume originally submitted was not accurately stated to show the adequacy of the existing installation.
The correct range should have been stated as being from 7 inches above the tank bottom to 7 inches below the tank top. This range includes coverage of the sparger. With regard to the ability to quench a "design-basis" pressurizer release, as noted above we do
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ATTACHMENT TO AEP:NRC'0773AB Page 11 not rely on the quench tank to perform this function. The quench tank is used during normal plant operation to contain pressurizer releases from routine pressurizer pressure adjustments and valve leakage. In the case of a design-basis event that causes the PORVs and safety relief valves to lift, two rupture discs will burst before reaching the quench tank design pressure of 100 psi.
Subsequently, discharge through the quench tank into the containment sump will occur.
With regard to over pressurization, we do not understand the basis for the EG&G position that sufficient gas volume exists to accept pressurizer release without becoming over pressurized. As noted above, over pressurization will not occur because rupture discs will burst and discharge into the containment before reaching the tank design pressure of 100 psig.
Normal water level is kept at between 80% and 84% of the instrument range with a high alarm at 84% and a low alarm at 79%. As such, in-leakage from the relief discharge system can be adequately monitored. The above information is the basis for our deviation from the Regulatory Guide 1.97 recommendation to monitor quench tank level from top to bottom of the tank. (This deviation was also discussed in AEP:NRC:0773S, Attachment 1, Item 3.3.15.)
2.2.6 Deviation No. DV-ll' G Wide-Ran e Level On August 21, 1981, we submitted a letter (AEP:NRC:0300G) that documented discussions with NRR staff clarifying certain portions of an NRC SER (June 16, 1981) of the Cook Nuclear Plant auxiliary feedwater system. In that letter it was confirmed that Regulatory Guide 1.97 recommendations for steam generator level instrumentation did not have to be implemented at that time, but that implementation would be addressed at some time in the future through the Regulatory Guide 1.97 compliance/commitment process.
The steam generator wide-range level indication is not required for post-accident monitoring and in fact has been deleted from our
ATTACHMENT TO AEP:NRC'0773AB Page 12 Technical Specifications for Units 1 and 2. This was stated in our December 10, 1980, letter, which submitted a proposed amendment to our Technical Specifications (AEP:NRC:0449). As stated in that letter, the reasons for deletion of steam generator wide-range level indication from the Technical Specifications are.'1) the S/G wide-range level indication does not perform any safety-related function and is not assumed operable in the various plant safety analyses; and (2) the S/G narrow-range instrumentation, which we believe fulfills post-accident monitoring requirements, is environmentally and seismically qualified, powered from a Class lE source and has three redundant channels per S/G. The S/G level indication is backed up by auxiliary feedwater flow instrumentation.
The S/G wide-range level instrumentation is powered from a Class 1E Bus power source, but all four channels are powered by the same source. Since this is not in compliance with the Regulatory Guide, Rev. 3 recommendations, and based on the information given above, we are noting our deviation from the Regulatory Guide 1.97, Rev. 3 recommendation for S/G level instrumentation. (This deviation was also discussed in AEP:NRC:0773S, Attachment 1, Item 3.3.16.)
2.2.7 Deviation No. DV-12'ondensate Stora e Tank CST Level CST level indication is currently provided in the control room through three Category 3 level-measuring devices. One of these instruments is electrically operated, while the other two are pneumatic devices. In addition, CST level can be read at the local turbine-driven auxiliary feedwater pump control panel. We have also committed to provide additional CST level indication by adding one instrument channel to meet Category 1 requirements. The new channel was installed during the 1987 refueling outage on Unit 1 and will be installed before the end of the 1988 refueling outage on Unit 2.
The CST is the initial source of water for the auxiliary feedwater (AFW) system, and provides sufficient volume to maintain the reactor
ATTACHMENT TO AEP:NRC:0773AB Page 13 coolant system in a hot standby condition for nine hours. In the event that sufficient water is not available from the CST in one unit, operating procedures call for a cross-tie valve to be opened to supply feedwater from the CST in the other unit.
In the unlikely event that neither CST can supply sufficient AFW, procedures require transferring the supply source to the essential service water system (ESWS). The water supply for the ESWS is Lake Michigan.
The number and diversity of instrumentation available to provide CST level monitoring, and the ultimate availability of Lake Michigan as a source of auxiliary feedwater, is the basis for our deviation from the Regulatory Guide 1.97 recommendation to provide more than one Category 1 level indication for the CST. (This deviation was also discussed in AEP:NRC:0773S, Attachment 3, Item 1.)
2.2.8 Deviation No. DV-13 Containment S ra Flow When operating normally, each containment spray pump will deliver 3200 gpm (design flow) at 490 ft TDH. Figure 2.2-1 shows containment spray pump flow as a function of pump discharge pressure.
The Figure 2.2-1 curve indicates the expected range of operation for the containment spray pumps. This operating range stems from consideration of pump suction head, containment pressure, and pump operating characteristics. Routine surveillance of spray pump operation is performed to ensure that, if containment spray is required, the pumps will operate in the indicated area of the flow curve and hence provide the necessary flow to the containment spray system. 'he reactor operators can, therefore, verify proper containment spray flow by monitoring spray pump discharge pressure to confirm that it is within the expected range.
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ATTACHMENT TO AEP:NRC:0773AB Page 14 It should be noted that the upper containment spray flow instrumentation (IFI-330 and IFI-331) cited in our original submittal (AEP:NRC:07730, dated October 15, 1985) me'asures only the flow provided by the RHR pumps to the upper containment spray, not the flow from the containment spray pumps. However, the containment spray pumps, not the RHR pumps, are normally used to supply containment spray flow. Also, please note that the flow range of 0-200 gpm for IFI-330 and -331 (for measurement of RHR pump flow to the upper containment spray) given in that submittal is incorrect.
The correct range is 0-2500 gpm.
The above is the basis for our deviation from the Regulatory Guide 1.97, Rev. 3 recommendation for containment spray flow instrumentation. (This deviation was also discussed in AEP:NRC:0773S, Attachment 1, Item 3.3.17.)
2.2.9 Deviation No. DV-14 Volume Control Tank VCT Level Because of the following actions that apply for normal, accident, and post-accident conditions, we believe VCT level indication beyond that currently provided is not required. Upon receiving a hi-level alarm, flow into the VCT is automatically fully diverted into the hold-up tanks. If a low-level alarm is reached, an alarm alerts the operator to restore level. In the event this effort fails, an emergency lo-lo level alarm is sounded and the refueling water sequence is automatically initiated. We believe that this range (0-70 inches) is adequate to safely monitor the operation of this tank. In the unlikely event that VCT level indication is lost and the VCT becomes completely full, a safety relief valve (set at 75 psig) will open and the excess water will be discharged into the hold-up tanks. The above is the basis for our deviation from the Regulatory Guide 1.97 recommendations to monitor volume control tank level from top to bottom of'he tank. (This deviation was also discussed in AEP:NRC:0773S, Attachment 1, Item 3.3.19.)
ATTACHMENT TO AEP:NRC:0773AB Page 15 2.2.10 Deviation No. DV-15 Noble Gases and Vent Flow from Condenser Air Removal S stem Exhaust This instrumentation was recently (1985) upgraded by the addition of a high-range noble gas detector. Based on our recent primary calibration analysis, the range of this instrumentation was
-7 determined to be 5.8 x 10 uCi/cc to 1.86 x 10 4 uCi/cc Xenon-133 dose equivalent. On July 23, 1986, a letter was sent to the NRC (AEP:NRC:0678Y) in which we stated that post-accident conditions would not result in steam jet air ejector exhaust noble gas concentration greater than 2 x 10 3 uCi/cc. On this basis we requested an exemption from the NUREG-0737,Section II.F.1-1 upper-range requirement 10 5 uCi/cc in favor of a more realistic 4.
upper range of 10 uCi/cc. The above also is the basis for our deviation from the Regulatory Guide 1.97, Rev. 3 recommended range for this parameter.
It should also be noted that tag numbers SFR-1900 and SFR-2900, given in our original submittal (AEP:NRC:07730, dated October 15, 1985) are incorrect. The correct tag numbers are SRA-1900 and SRA-2900. (This information was also provided in AEP:NRC;0773S, Attachment 1, Item 3.3.21.)
2.2.11 Deviation No. DV-16 Noble Gases from S G Safet Relief Valves The range of 3 uCi/cc to 20 x 10 5 uCi/cc as provided in our original submittal (AEP:NRC:07730) was based solely on the monitor's response to Xe-133 and not to the anticipated mixture of radioisotopes following a steam generator tube rupture. The lower limit of 0.1 uCi/cc of XE-133 equivalent mixture can be measured. As stated in our September 8, 1986, letter (AEP:NRC:0678Z), when the anticipated mixture of radioisotopes for a steam generator tube rupture is used, the maximum concentration released in the main steam effluent from the S/G PORV is calculated to be 0.263 uCi/cc Xe-133 equivalent activity. With respect to this upper range limit, an exemption from the NUREG-0737 requirement of 1000 uCi/cc was requested in the September 8, 1986, letter and a 100 uCi/cc value
~t ATTACHMENT TO AEP:NRC:0773AB Page 16 proposed. No response to our request has been received at this writing. The above is a basis for our deviation from the Regulatory Guide 1.97, Rev. 3 recommended upper limit of measurement for this variable. (This information was also provided in AEP:NRC:0773S, Attachment 1, Item 3.3.22.)
2.2 '2 Deviation No. DV-17 RCS Sam lin - Chloride Content Chloride content in undiluted samples 30 days after an accident is measured in a range of 0.01 to 20 ppm. For diluted samples (1:1000 dilution) taken within 4 days of an accident, the range of measurement is 10 to 20,000 ppm. The above is the basis of our deviation from the Regulatory Guide 1.97, Rev. 3 lower limit of 0 ppm for this variable. (This information was also provided in AEP:NRC:0773S, Attachment 1, Item 3.3.24, No. 4.)
2.2.13 Deviation No. DV-18'ontainment Air - H dro en Content An exemption from the requirement for taking hydrogen grab samples of containment air was granted via a letter from Youngblood (NRC) to Dolan (AEP) dated November 5, 1986. This exemption is the basis for our deviation with respect to the Regulatory Guide 1.97, Rev. 3 recommendations for this parameter. Ve do, however, perform continuous monitoring of containment air hydrogen content in the range of 0 to 30 volume percent (see Item C-10).
2.2.14 Deviation No. DV-19 Containment Air - Ox en Content NUREG-0737 does not require sampling of containment air oxygen content. As noted above, however, we do continuously monitor hydrogen content, which makes containment air oxygen content of less concern from the standpoint of potential hydrogen flammability or deflagration. The above is the basis for our deviation from the Regulatory Guide 1.97, Rev. 3 recommendation to sample for containment air oxygen content. (This deviation was also discussed in AEP:NRC:0773S, Item 3.3.24, No. 7.)
ATTACHMENT TO AEP'NRC:0773AB Page 17 2.2.15 Deviation No. DV-20 Indicatin Lam s Circuits that require the use of indicating lamps for position indications, status indication, etc., will be using existing General Electric ET16 indicating lamps for this function. We have been advised by the manufacturer that these indicating lamps meet their (the manufacturer's) interpretation of IEEE-344-1975. This indicating lamp is a seismically rugged commercial grade device for which comprehensive qualification is not available. Since these lamps are purchased as standard commercial grade material and are not manufactured for a specific order, 10 CFR 21 can not be applied to these devices. The above is the basis for our deviation from Regulatory Guide 1.97, Rev. 3 for this device.
2.2.16 Deviation No. DV-21 Centrifu al Char in Pum CCP Flow Indication Our original submittal (AEP:NRC:07730) identified both the CCP flow and CCP motor breaker status as Type A variables. This would require Category 1 instrumentation for monitoring these parameters.
The CCP breaker status indi. cation will meet the Regulatory Guide 1.97, Rev. 3 recommendati,ons for Category 1 instrumentation except as noted in the summary table, Entry A.28.
With regard to the CCP flow indication, it should be noted that our Emergency Operating Procedures require manual operator action based on indication of pump operation or flow. The CCP breaker status indication and other parameters serve to verify pump operation. The non Category 1 CCP flow indication can serve as a backup. The above is the basis for our deviation from the Regulatory Guide 1.97, Rev.
3 recommendation to provide Category 1 instrumentation for CCP flow indication. (This deviation was also discussed in AEP:NRC:0773S, Attachment 3, Item 2).
ATTACHMENT TO AEP:NRC'0773AB Page 18 2.2.17 Deviation No. DU-22 Safet In ection SI Pum Flow Indication Reasons similar to those stated in Section 2.2.16 above are the basis for our deviation from the Regulatory Guide 1.97, Rev. 3 recommendation to provide Category 1 instrumentation for SI pump flow indication. The SI pump motor breaker status instrumentation will meet Category 1 requirements except as noted in the summary table, Entry A.29. (This deviation was also discussed in .
AEP:NRC:0773S, Item 3.)
2.2.18 Deviation No. DU-23'adiation Ex osure Rate ERA-7303 through 7308, and ERA-8303 through 8308 have ranges of 0.01 to 1000 R/HR. Monitors ERS-7401, 7403, 7404, 8401, and ERA-7507, 7601, 7603, and 7605 have ranges of .0001 to 10 R/HR. Monitors ERA-8403, 7504, 7508, 7602, and 7604 have ranges of 0.001 to 10 R/HR. These ranges are different from t'e Regulatory Guide 1.97,
-1 Rev. 3 recommended range of 10 to 10 +4 R/HR. With the exception of ERA-7305, 7306, 8305, and 8306, the worst case maximum estimated accident dose rate in the areas where these monitors are to be installed is less than the upper range limits noted above. The stated upper range limits are used to provide more accurate, useful information and to help prevent false "low fail" alarms.
In the case of the ERA-7305, 7306, 8305, and 8306, the worst case maximum estimated accident dose rate is 1730 R/HR, which exceeds the detector's upper range limit of 1000 R/HR. However, within one (1) hour, this dose rate drops to 573 R/HR, which is well within the upper range limit. Personnel entry into an area where exposure may exceed 1000 R/HR (indicated by a "high fail" status indication) is highly unlikely and the dose rate in these areas will quickly fall below the upper range limit of 1000 R/HR (at which time a quantitative indication will again be available). Therefore, the range of 0.01 to 1000 R/HR for these detectors is adequate for the areas in which they are installed.
ATTACHMENT TO AEP'NRC:0773AB Page 19 The above discussion is the basis for our deviation from the Regulatory Guide 1.97, Rev. 3 recommended range for area radiation monitors installed in areas potentially requiring personnel access for servicing of equipment important to safety.
2.2.19 Deviation No. DV-24 Valve Position Indication - CM-250 We will upgrade the valve position limit switches on valves VCR-11 and VCR-21 to meet the environmental qualification requirements of 10 CFR 50.49 and Regulatory Guide 1.97, Rev. 3 recommendations.
The valve position limit switches for valve QCM-250, as well as the associated cable and terminations, are qualified in accordance with 10 CFR 50.49(k) except that they have not been qualified'for submergence. The QCM-250 position indication limit switch is located below maximum flood level. Although this is not completely consistent with the Regulatory Guide 1.97, Rev. 3 recommendations for equipment qualification, we do not believe any upgrading of the position indication limit switch is necessary. This is due to the fact that QCM-250 is designed to close within 15 seconds of a containment isolation signal, which means that the valve will not become submerged before it performs its safety function. In addition, once the valve is closed, it is extremely unlikely that it would change position due to its submergence.
Given these considerations, we believe that QCM-250 in its present status, without upgrading, adequately meets the intent of Regulatory Guide 1.97, Rev. 3 recommendations for achieving verifiable containment isolation and is the basis for our deviation from the Regulatory Guide 1.97, Rev. 3 recommendations for this parameter.
The planned schedule for upgrading VCR-11 and VCR-21 to meet 10 CFR 50.49 requirements calls for this work to be completed in both units by the end of the refueling outages presently scheduled for 1989 (Unit 1) and 1990 (Unit 2).
ATTACHMENT TO AEP:NRC:0773AB Page 20 2.2.20 Deviation No. DV-25 CCW Water Tem erature Indication CTR -410 -415 -420 and -425 If CCW water temperature is not available, adequate CCW cooling can be verified by monitoring CCW flow and RHR inlet and outlet temperatures, all of which are qualified (or planned to be qualified) for the intended purpose. Therefore, because of the availability of suitable diverse indications, environmental qualification of instrumentation monitoring this variable is not required. We are submitting a deviation with respect to Reg. Guide 1.97, Rev. 3 recommendations for this variable for environmental qualification. (Deviation No. DV - 25) 2.3
SUMMARY
OF REGULATORY GUIDE 1.97 REV. 3 DEVIATIONS Table 2.3-1 provides a cross-referenced summary of the deviations from the Regulatory Guide 1.97, Rev. 3 recommendations that were identified and discussed in Sections F 1 and 2.2. Table 2.3-1
.shows, by deviation number, a brief description of each deviation, where the affected variables can be found in the Section 3.0 summary tables and where each deviation is discussed in Section 2.0.
2.4 ADDITIONAL CLARIFICATION OF SECTION 3.0
SUMMARY
TABLE INFORMATION The following information is provided in order to clarify certain entries contained in the Section 3.0 summary tables.
2.4.1 Sensor Location The "sensor(s) location(s)" information requested in Section 6.2(e) of Supplement 1 to NUREG-0737 is assumed to mean the parameter(s) monitored by the sensor and not the sensor's physical plant location. This information is provided in the column labeled "variable."
ATTACHMENT TO AEP:NRC:0773AB Page 21 2.4.2 Power Source Instruments reported as conforming to the Regulatory Guide 1.97, Rev. 3 power source recommendations have their power derived from a 120V AC or 250V DC safety-related power source. Some existing circuits use non-safety related cable from the source to the instrument power supply.
2.4.3 Schedule The implementation provided for each variable is the current, best estimate of the completion of the final configuration for the associated instrument including redundancy, final displays, power supplies, documentation of qualification and turnover to plant operations. The schedules are based on anticipated delivery and plant outage schedules. Equipment delivery delays, environmental qualification test difficulties, or other problems, however, may cause delays in these schedules beyond our reasonable controls Considering these factors, our overall target date for completion of work undertaken in response to Regulatory Guide 1.97, Rev. 3 is by the end of the Unit 2 refueling outage presently scheduled for 1990.
This completion date is also contingent on any changes resulting from the NRC evaluation of our deviations.
2.4.4 Chan es from October 1985 Submittal AEP:NRC:07730 Because of additional information obtained after our previous submittal in October 1985, discussions with the NRC Staff and its consultant (EG&G), and information developed as a result of our ongoing engineering/design work, there are numerous differences between our October 1985 submi.ttal and this updated submittal. All item numbers in the tables in Section 3.0 have been retained, regardless of whether they are currently in use, in order to provide easy cross referencing between this and previous reports. Most changes involve the updating of status of modifications, incorporation of deviation requests and answers to questions
ATTACHMENT TO AEP'NRC:0773AB Page 22 provided in our AEP:NRC:0773S documents, clarification of several items, and miscellaneous correction and revisions.
It is noted that although many variables presently listed are-measured with fully functional instrumentation, they are not considered operational in the sense that they meet Regulatory Guide 1.97, Rev. 3 recommendations. In addition, it should be noted that instruments previously reported to the staff as meeting the requirements of NUREG-0737 or IE Bulletin 79-01B do not, in all cases, meet all of the requirements of Regulatory Guide 1.97, Rev. 3 as noted within this document.
3.0
SUMMARY
TABLES These tables represent the status of the Donald C. Cook Nuclear Plant when we will have completed all of the recommendations associated with Regulatory Guide 1.97, Rev. 3. It does not, nor is it intended to, reflect the status of the plant as of the date of this letter.
The schedules provided in this enclosure for meeting Regulatory Guide 1.97, Rev. 3 recommendations are not intended to change any previous commitment regarding NUREG-0737 or 10 CFR 50.49, whose requirements may be different.
"A:" A letter "A" in the columns labeled EQ, SQ, QA, SF or PS indicates that we have applied the guidance provided in Regulatory Guide 1.97, Rev. 3 subject to specific deviations noted in the Remarks/Action Req'd. column.
"CMPLT" indicates that the action identified in our previous submittal AEP:NRC:07730 has been completed on Unit 1 or will be completed on Unit 2 prior to returning to service from the current steam generator repair and refueling outage.
"NA" letters mean Not Applicable; i.e., does not apply.
ACHMENT TO AEP:NRC:0773AB Page 23 TABLE 2.3-1 Summar of Deviation Re uests from Re ulator Guide 1.97 Rev. 3 Where Identified Deviation No. In Section 3.0 Where Ex lained DV-1 Environmental Qualification Various Section 2.1.1 DV-2 Seismic Qualification Various Section 2.1.2 DV-3 Quality Assurance Various Section 2.1.3 DV-4 Redundancy Various Section 2.1.4 DU-5 Display Location Various Section 2.1.5 DV-6 Containment Pressure Table Items A.13/B.13 Section 2.2.1 DV-7 Subcooling Meter Table Item A.17 Section 2.2.2 DV-8 RCS Sampling/Boron Concentration Table Item B.3 Section 2.2.3 Range DV-9 RCS Sampling/Radioactivity Table Item C.2 Section 2.2 '
DV-10 Quench Tank Level Table Item D.13 Section 2.2.5 DV-11 S/G Wide Range Level Table Item D.15 Section 2.2.6 DV-12 CST Level Table Item D.19 Section 2.2.7 DV-13 Containment Spray Flow Table Item D.20 Section 2.2.8 DV-14 VCT Level Table Item D.26 Section 2.2.9 DV-15 Noble Gases and Vent Flow from Table Item E.3d Section 2.2.10 Condenser Air Removal System Exhaust DV-16 Noble Gases from S/G Safety Table Item E.3f Section 2.2.11 Relief Valves DV-17 RCS Sampling - Chloride Content Table Item E.9d Section 2.2.12 DV-18 Containment Air - H2 Content Table Item E.10a Section 2.2.13 DV-19 Containment Air - 02 Content Table Item E.lob Section 2.2.14 DU-20 Indicating Lamps Table Item A.28, A.29 Section 2.2.15 and B.14 DV-21 Centrifugal Charging Pump Flow Table Item A.01 Section 2.2.16 Indication DV-22 SI Pump Flow Indication Table Item A.34 Section 2.2.17 DU-23 Radiation Exposure Rate Table Item E.2 Section 2.2.18 DV-24 Position Indication - QCM-250 Table Item B.14 Section 2.2.19 DV-25 CCW Water Temperature Table Item D.27 Section 2.2.20
Page ATTACHMENT TO AEPiNRC<0773AB ATT C H N CH I SAFETY RELATED CABLE CH I NON-SAFETY RELATED CABLE CH II SAFETY RELATED CABLE CH II NON-SAFETY RELATED CABLE NON-SAFETY RELATED CABLE
<NO CHANNEL DESIGNATION)
CONTROL ROOM AND CABLE VAULT AREA CH I PROCESS TRANSMITTER SOLID STATE PROT SYS (SSPS) LOGIC CABINETS (SAFETY RELATED) (SAFETY RELATED>
PROCESS INPUTS REACTOR FLOV, PRESSURF PROTECTION LEVE4 etc. CABINETS TO CIRCUIT BRKS, HOTORS; PUNPS, SIGNAL ISOLATOR (I/I) VALVES, RELAYS, (SAFETY RELATED) etc.
NOTD LOCATED IN AUL BLDG. HEAR CONPU TER COHTRQL ROON COHTROL CONPUTER I/O CABINETS INPUT CABINETS CABINETS (NON-SAFETY RELATED>
(HOH-SAFETY RELATED)
L INDICATORS (HQN-SAFETY RELATED)
TO TSC CONPUTER (HQN-SAFETY RELATED)
TO PLANT CONPUTER (HOH-SAFETY RELATED)
TO RENQTE, NON-SAFETY RELATED Et>UIPHEHT Oe SIGNAL ISOLATOR
VALVES, etc>
PROCESS INPUT, (HQN-SAFETY RELATED)
FLOV, PRESSURE (SAFETY RELATED>
LEVE4 etc. REACTOR TO CIRCUIT BRKS, PROTECTIOH HQTORS, PUNPS, CABIHETS VALVES, RELAYS, etc.
CH II PROCESS (SAFETY RELATED)
TRANSMITTER (SAFETY RELATED) SOLID STATE PROT SYS <SSPS) LOGIC CABINETS (SAFETY RELATED)
TYPICAL POST ACCIDENT MONITORING SIGNAL CABLING L HARDMARE LAYOUT F IGURE 2,1-i
'! t'l CONTAINMENT SPRAY PUNIP FLOW VS.
DSGHARGE DISCHARGE PRESSURE Pi PRESSURE ~~
(r SK') 2s PJ O
250 o IA 240 ANTlCPATED 220 OPERATNG RANGE 210 190 0 1000 1500 2000 2500 3500 FLOW (GPM)
Attachment to AEP:NRC:0773AB Page 26 Type A Var s: "those variables to be monitored that provide the p y information required to permit the control room operator to take specific manually controlled actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for design basis accident events. Primary information is information that is essential for the direct accomplishment of the specified safety funtions; it does not include those variables that are associated with contingency actions that may also be identified in written procedures." Note: These variables are plant-specific and based on review of the D. C.
Cook Nuclear Plant Emergency Operating Procedures (EOP's) plus anticipated future changes to the EOP's. The schedule and status for each instrument indicated is for when all of the applicable recommendations of Regulatory Guide 1.97, Rev 3 will be met.
Item Purpose Variable Tag Nos. Range E S Q S P Display Remarks/Action Req'd U-1 U-2 No. Q Q A F S Location Schedule Schedule A-1 Maintain Pressur- Centrifigal IFI-51,52, 0-200 GPM A A A A A Control Room No further action required CMPLT CMPLT izer Level during Chg Pump Flow 53,54 Panel SIS See footnote (t)
S/G Tube rupture (CCP) (Deviation No.s DV-21 and DV-5)
A-2 Manual Trip of RC RCS Pressure NPS-121,122 0-3000psig A A A A A Control Room No further action required CMPLT CMPLT Pumps based on RCS (wide range) Panel RHR (Deviation No.s DV-1, DV-2, pressure DV-3, and DV-4)
A-3 NOT USED A-4 NOT USED NOT USED A-6 NOT USED A-7 Determination of S/G Pressure MPP-210,211, 0-1200psig A A A A A Control Room No further action required CMPLT CMPLT required core exit 212,220, Panel SG (Deviation Nos. DV-l, DV-2, temperature by S/G 221,222, DV-3, DV-4)
Pressure 230>231, 232,240, 241,242 For Definite.on of "A" 'See Section 3.0
Attachment AEP:NRC:0773AB Page Item Purpose Variable Tag Nos. Range E S Q S - P Display Remarks/Action Req'd U-1 U-2 No. I A F S Location Schedule Schedule A-8 Determination of Containment NLA-320 599'-3" to A A A A A Control Room Replace transmitters. 1989 re- CMPLT adverse containment Water Level NLI-321 614 ft. el- Panel RHR See footnote (u) fueling evation (Deviation Nos. DV-1, outage (Containment DV-2 ~ DV-3, & DV-5)
Floor to max 1 flood level)
A-9 Manual Reduction of S/G Level BLP-110,111, Prom below A A A A A Control Room No further action required CMPLT CMPLT ECCS Flow Narrrow range 112,120, 1st stage Panel SG (Deviation No.s DV-1, DV-2, (Secondary heat 121,122, separator to DV-3, DV-4) sink capability) 130,131 I 2nd stage 132,140, separator 141,142 A-10 Manual Reduction of Pressurizer NLP-151,152, 0-100X A A A A A Control Room No further action required CMPLT CMPLT ECCS Flow Level 153 (96X of Panel PZR (Deviation No.s DV-1, DV-2, Total DV-3, and DV-4)
Volume)
A-11 NOT USED A-12 Determination of Containment VRA-1310, 1 R/)R to A A A A A Control Room See footnote (v) NA NA adverse containment Area Radiation 1410, 1X10 R/HR Panel RMS (Deviation Nos. DV-l, DV-2, Monitor High (Unit 1) DV-3, and DV-5)
Range 2310, 2410 (Unit 2)
A-13 Manually establish Containment PPP-300,301, -5 to +12 A A A A A Control Room No further action required CMPLT CMPLT or trip containment Pressure 302,303 psig Panel SPY See Footnotes (d) & (w) spray (Narrow range) (Deviation No. DV-6)
A-14 NOT USED For Definition of "A" See Section 3.0
Attachment to AEP:NRC:0773AB Page 28 Item urpose Variable Tag Nos. Range S Q S P Display Remarks/Action Req'd U-1 U-2 No. Q Q A F . S Location Schedule Schedule A-15 Manual Reduction of Auxiliary FFI-210,220, 0-2)0 A A A A A Control Room No further action required CMPLT CMPLT ECCS Flow Feedwater Flow 230,240 x10 PPH Panel SG Redundancy provided by (Secondary heat diverse variable - S/G sink capability) narrow range level which is qualified (Deviation Noe. DV-1, DV-2, DV 3~ DV 4~ & DV 5)
A-16 Manual Transfer to RWST Level ILS-950,951 essentially NA A A A A Control Room No further action required CMPLT CMPLT cold leg recircula- Top (bottom Panel SPY (Deviation No.s DV-2, DV-3, tion in low level of overflow) & DV-4) in RWST to Bottom (100X of Total Volume)
A-17 Manual Trip or re- Degrees Sub- NA 0-199'F sub- A NA A NA A Control Room No further action required CMPLT CMPLT duction of Press- cooling cooling Panel BA See footnotes (b) & (c) urizer Spray and 0-199'F which apply beyond the ECCS Flow Superheat isolating devices. Also see footnote (x)
(Deviation No.s DV-7, DV-1, DV-3, & DV-5)
A-18 NOT USED A-19 NOT USED A-20 NOT USED A-21 NOT USED A-22 NOT USED A-23 NOT USED A-24 NOT USED For Definition of "A" See Section 3.0
Attachment to AEP:NRC:0773AB Page 29 Item rpose Variable Tag Nos. Range E g S P Display Remarks/Action Req'd U>>1 U-2 No. A F S Location Schedule Schedule A-25 Manual Reduction Core Exit T/C 1-65 200-2300 F A A A A A Control Room No further action required CMPLT CMPLT of ECCS Flow T/C's Panel FI (Deviation No.s DV-1, DV-2, (U-1) Panel & DV-3)
RMS (U-2)
A-26 NOT USED A-27 NOT USED A-28 Manual trip of CCP Breaker Pump IE,IW OPEN/CLOSE NA A A A A Control Room gualify or replace End of End of RCP's Status 2E,2W Panel BA control room indicators 1988 1988 with seismically qualified equipment See footnotes (d),(t)
& ()$ )) (Deviation No.s DV-2, DV-3, DV-20 & DV-21)
A-29 Manual trip of SI Pump Pump 1N,1S OPEN/CLOSE NA A A A A Control Room gualify or replace End of End of RCP's Breaker Status 2N,2S Panel SIS control room indicators 1988 1988 with seismically qualified equipment See footnotes (d), (y)
& (ggj) (Deviation No.s DV-2, DV-3, DV-20 & DV-22)
A-30 NOT USED A-31 NOT USED A-32 NOT USED A-33 NOT USED A-34 Manual Trip of Safety In)ec- IFI-260,266 0-800GPM NA A A A A Control Room No further action required CMPLT CMPLT RCPss tion Pump Flov Panel SIS See footnote (d) & (y)
(Deviation No. DV-22 &
DV-5)
For Definition of "A" See Section 3.0
// /~ ~
Attachment to AEP:NRC:0773AB
~ ~ Page 30 Item Purpose Variable Tag Nos. Range S Q S P Display Remarks/Action Req'd No. A P AS Location Schedule Schedule A-35 S/G Blovdovn NOT USED - DELETED See footnote (z) NA Radiation A-36 NOT USED A-37 NOT USED Por Definition of "A" See Section 3.0
Attachment to AEP:NRC:0773AB Page Type B Va es: "those variables that provide information to indicat hether plant safety functions are being accomplished. Plant safety functions are (1) reactivity control,. (2) core cooling, (3) maintaining reactor coolant system integrity, and (4) maintaining containment integrity (including radioactive effluent control)." Note: The schedule and status of each instrument is for when all of the applicable recommendations of Regulatory Guide 1.97, Rev 3 will be met.
Item Purpose Variable Cat. Tag Nos. Range E S Q S P Display Remarks/Action Req'd U-1 U-2 No. A F S Location Schedule Schedule B-1 Reactivity Neutron 1 NE-21,23 10 -200Z A A A A A Control Room Install New, Cat. 1 1989 re- 1990 re-Control Flux power Panel NIS Channel to provide fueling fueding Indication. Upgrade outage outage 1 existing channel to meet Category 1 require-ments. See footnote (aa)
(Deviations No.s DV-1, DV-2 & DV-3)
B-2 Control Rod 3 CA1-8, CBl-4 Full in or NA NA NA NA NA Control Room None required NA Position CC1-8, CD1-9 not full in Panel RC SA1-8. SB1-8 B-3 RCS Soluble. 3 NSX-101,103 375-2000 NA NA NA NA NA NA See Item C-2 NA NA Boron Con- ppm and footnotes (a) & (bb) centrate (Deviation No. DV-8)
B-4 RCS Cold 1 NTR-210,230, 0-700'F A A A A A Control Room Relocate R/I and I/I 1989 re- 1990 re-Leg Temp- Panel DTU converters to control fueling fueling erature room. Upgrade cable to outage outage meet Category 1 require-ments. See footnote (cc)
(Deviation No.s DV-1, DV-2, DV-3 & DV-4)
B-5 Core Cooling RCS Hot 1 NTR-1100130, 0-700 F A A A A A Control Room Relocate R/I and I/I 1989 re- 1990 re-Leg Water Panel DTU converters to control fueling fueling Temperature room. Upgrade cable to outage outage meet Category 1 require-ments. See footnote (cc)
(Deviation No.s DV-1, DV-2~ DV-3 & DV-4)
For Definition of "A" See Section 3.0
Attachmen to AEP:HRC:0773AB Page 32 Item ose Variable Cat. Tag Nos. Range S Q S P Display Remarks/Action Req'd U-l U-2 No. A F' Location Schedule Schedule B-6 RCS Cold 1 See item B-4 Leg Water Temperature B-7 RCS Pressure See item A-2 1
B-8 Core Exit See item A-25 Temperature B-9 Coolant NLI-110,111 Top of head A A A A A Control Room Upgrade Power Supply 1989 re- 1990 re-Inventory 120,121i vent piping Panel SIS to Hot Leg Temperature fueling fueling 130,131 to bottom Input. See Item B-4 outage outage of vessel which provides an input (100X of to this variable (Devia-Volume) tion No.s DV-1, DV-2, DV-3 & DV-5)
B-10 Degrees of See item A-17 Subcooling B-11 Maintaining RCS Pressure See item A-2 RCS Integrity B-12 Containment 2 NLA-310 589'-6" to A NA A NA NA Control Room See footnote (u) & (dd) 1989 re- CMPLT Sump Water HLI-311 599'-8" Panel RHR (Deviation Ho.s DV-1 & fueling Level (Bottom of DV-3) outage Sump to Containment Floor)
B-13 Containment 1 PPA-310,312 -5 to 36psig NA A A A A Control Room No further action NA NA Pressure Panel SPY required. Also see (Wide Range) Item A-13 for narrow range. See footnotes (d) and (w) narrow range (Deviation No. DV-6)
For Definition of "A" See Section 3.0
Attachment to AEP:NRC:0773AB Page 33 Item se Variable Cat. Tag Nos. Range S Q S P Display Remarks/Action Req'd U-1 U-2 No. A P ~ S Location Schedule Schedule B-14 Naintaining Containment 1 See listing CLOSED- A A A A A Control Room Replace Limit switches 1989 re- 1990 re-Containment Isolation in Attach- NOT CLOSED Panels IV, with env & seismically fueling fueling Integrity Valve Posi- ment 1 to BA,SIS,SPY .
qualified devices as outage outage tion (ex- these tables noted in Attachments 1 &
cluding 2 to these tables.
check Qualify or replace valves) control room indicators with seismically quali-fied equipment. See foot-note (ee) & ($ /))
(Deviation No.s DV-20 DV-1, DV-2 & DV-3)
B-15 Containment Pressure See items A-13 and B-13 For Definition of "A" See Section 3.0
Attachment to AEP:NRC:0773AB Page 34 Type C Va es: "those variables that provide information to indicat e potential for being breached or the actual breach of the barriers to fission product releases. The barriers are (1) fuel cladding, (2) primary coolant pressure boundary, and (3) containment."
Note: The schedule and status for each instrument is for when all of the applicable recommendations of Regulatory Guide 1.97, Rev 3 will be met.
Item Purpose Variable Cat. Tag Nos. Range E S Q S P Display Remarks/Action Req'd U-l U-2 No. A F S Location Schedule Schedule C-l Fuel Cladding Core Exit See item A-25 i Temperature C-2 Radioactive 1 NSX-101,103 NA A A A A A No further action CMPLT CMPLT concentra- required. See footnotes tion or (h) and (ff)
Radiation (Deviation No.s DV-9, DV-1, Level in DV-2, DV-3 6 DV-5)
Circulating Primary Coolant C-3 Analysis of See item C-2 and footnote Primary (gg)
Coolant (Gamma Spectrum)
C-4 Reactor Cool- RCS Pres- See item A-2 ant Pressure sure Boundary C-5 Containment See items A-13 and B-13 Pressure C-6 Containment See item B-12 Sump Water Level C-7 Containment See item A-12 Area Radi-ation For Definition of "A" See Section 3.0
Attachment AEP:NRC:0773AB Page Item ose Variable Cat. Tag Nos. Range E S P Display Remarks/Action Req'd U-l U-2 No. A P S Location Schedule Schedule C-8 Effluent 3 SRA-1900 5.8E-7 to NA NA NA NA NA Control Room No action required NA NA Radioactiv- (Unit 1 1.86E4 CT-1 Control ity-Noble SRA-2900 uCi/cc Terminal gas Effluent (Unit 2) from Con-denser Air Removal Sys-tem Exhaust C-9 Containment RCS Pressure See item A-2 C-10 Containment 1 ESR-1 0-30 NA A A A A Control Room See footnote (d) NA NA Hydrogen thru 9 Volume X Panel IV No action required Concentra- (Deviation No.s DV-1, tion DV-2, & DV-3)
C-11 Containment See items A-13 and B-13 Pressure C-12 Containment 2 VRS-1500, 5.8E-07 to NA NA A NA NA Control Room See footnotes (d) 6 (hh) NA NA Effluent (Unit 1) 1.86E4 CT-1 (Deviation No. DV-3)
Radioactiv- uCi/cc Terminal No Action Required ity-Noble VRS-2500, gases from (Unit 2) identified release points For Definition of "A" See Section 3.0
Attachment to AHP:NRC:0773AB Page 36 Item pose Variable Cat. Tag Nos. Range E S P Display Remarks/Action Req'd U-1 U-2 No. Q A F . S Location Schedule Schedule C-13 Effluent SEE ITEM C-12 Radioactiv-ity-Noble Gases (from buildings or areas where penetra-tions and hatches are located, eg, secondary containment and AUX buildings that are in direct con-tact with primary containment For Definition of "A" See Section 3.0
Attachment o AEP:NRC:0773AB Page 37 Type D Va es: "those variables that provide information to indicat he operation of individual safety systems and other systems important to safety. These variables are to help the operator make appropriate decisions in using the individual systems important to safety in mitigating the consequences of an accident." Note: The schedule and status for each. instrument is for when all of the applicable recommendations of Regulatory Guide 1.97, Rev 3 will be met.
Item Purpose Variable Cat. Tag Nos. Range E S g S P Display Remarks(Action Req'd U-1 0-2 No. A F S Location Schedule Schedule D-1 RHR System RHR System 2 IFI-310,311, 0-1500 GPM A NA A NA NA Control Room No Action Required NA NA Flow 320,321 1500-5000 Panel RHR See footnotes (jj) & (mmm)
GPM (Deviation No. DV-3)
D-2 RHR Heat Ex- 2 ITI-310,320 0-400 F A NA A NA NA Control Room No further action CMPLT CMPLT change Out- Panel RHR required let Temp (See footnote (ii)
(Deviation No.s DV-1, &
DV-3)
D-3a SI Systems Accumulator 2 ILA-110,111 4.148 to A NA A NA NA Control Room Replace the wide range 1989 re- 1990 re-Tank Level 120,121, 120.8 in. Panel SIS transmitter each tank fueling fueling 130,131, (wide range) with env. qual. equipment outage outage 1401141 (52X of Total See footnotes (iii)
Volume) gualification shall 104.15 to apply to the wide range 120.8 in. instruments only.
(narrow (Deviation No.s DV-1, 6 range) (DV-3)
(7.5X of Total Volume)
D-3b Accumulator 2 IPA-110,111, 0-800 psig A NA A NA NA Control Room Replace one transmitter( 1989 re- 1990 re-Tank Pres- 120,121, Panel SIS tank with env. qualified fueling fueling sure 130,131, equipment. Qualification outage outage 140,141 shall apply to only one instrument/tank.
(Deviation No.s DV-1, &
DV-3)
D-4 Accumulator 2 IM0-110,120, Closed or NA NA A NA NA Control Room None Required NA NA Tank Isola- 130,140 Open Panel SIS See footnote (r) & (kk) tion Valve (Deviation No. 3)
Position For Definition of "A" See Section 3.0
Attachmen to AEP:NRC:0773AB Page 38 Item pose Variable Cat. Tag Nos. Range Q S P Display Remarks/Action Req'd U-l U-2 No. A F S Location Schedule Schedule D-5 Boric Acid See item D-24 Charging Flow D-6 Flow in HPI See item A-1 System D<<7 Flow in LPI See item D-1 System D-8 RWST Level See item A-16 D-9 Primary Cool- RCP Status 3 QI,Q2,Q3,Q4 0-1200A NA NA NA NA NA Control Room No Action Required NA NA ant System Panel RCP D" 10 Primary Sys- 2 QR-107 A,B, NA A NA A NA NA Control Room See footnote (b) NA NA tem Safety C,D Panel RC No Action Required Relief Valve (Deviation No.s DV-l, Positions or DV-3)
Flow Thru or pressure in Relief Valve Lines D-11 Pressurizer See item A-10 Level Pressurizer 2 Group Al,A2, ON/OFF NA NA A NA NA Control Room See footnotes (d) 6 (ll) NA NA Heater Sta- A3,C1,C2,C3 Panel PZR No Action Required tus (Deviation No. DV-3)
D-13 Quench Tank 3 NLA-351 7 inches NA NA NA NA NA Control Room None required NA NA Level above tank Panel PZR See footnote (mm) bottom to (Deviation No. DV-10) 7 inches below tank top D-14 Quench Tank 3 NTA-351 50-750 F NA NA NA NA NA Control Room No further action CMPLT CMPLT Temperature Panel PRZ required For Definition of "A" See Section 3.0
Page 39 Item Variable Cat. Tag Nos. Range E S P Display Remarks/Action Req'd No. A F S. Location Schedule Schedule D-14a quench Tank 3 NPA-351 -10 to 100 NA NA NA NA NA Control Room None Required NA NA Pressure psig Panel PRZ D-15 Secondary Sys- S/G Level 1 BLI-110,120, From 12" A A A A A Control Room None required See NA NA tern (Steam 130,140 above tube Panel SG footnotes (i) 6 (oo)
Generator) (wide range) sheet to sep- (Deviation No. DV-11) arators D-16a Safety/Re- See Item D<<16b for lief Valve alternate instrumentation Positions D-16b Main Steam 2 MFC-110 F 111, 0-4xl0 6 PPH A NA A NA NA Control Room None required NA NA Flow 120 '21, Panel SG (Deviation No.s DV-1, 130 '31, DV-3) 140,141 D-17 Main Feed- 3 FFC-210,211, 0-4x10 6 PPH NA NA NA NA NA Control Room None required water Flow 220,221, Panel BA See footnote (pp) 230,231, 240,241 D-18 Auxiliary Feed- Aux Feed- See item A-15 water System water Flow
'\
D-19 Condensate 1 CLI-113,114 Essentially A A A A A Control Room No further action CMPLT CMPLT Storage CLR-110, Top to Bot- Panel CP required. See footnotes Tank Level 111 tom (95K (qq) 6 (mmm)
Total (2 channels only)
Volume) (Deviation No. DV-12)
D-20 Containment Containment 2 IFI-330,331 0-2500GPM NA NA A NA NA Control Room No Action Requ'ired. NA NA Cooling System Spray Flow (Upper con- Panel SPY See footnotes (d), (e),
tainment) and (rr)
(Deviation No.s DV-13, DV-3)
For Definition of "A" See Section 3 0
Attachment o AEP:NRC:0773AB Page 40 Item ose Variable Cat. Tag Nos. Range E S P Display Remarks/Action Req'd U-1 U-2 No. A P S. Location Schedule Schedule D-21 Heat Removal D. C. Cook Nuclear Plant NA NA by contain- Units 1&2 do not have a ment Heat Re- Containment Heat Removal moval System System, therefore this item does not apply 1
D-22 Containment 2 ETR-11,12,13, 0 to A NA A NA NA Control Room Replace six (6) tech spec 1989 re- 1990 re-Atmosphere 14,15,16, 400'F Panel A-14 related RTD's with envi- fueling fueling Temperature 17,18,19, ronmentally qualified outage outage 20,21,22; equipment. Increase range 23,24,25, from -0 to 300'P to as 26,27 specified. Qualification shall apply for the six (6)
T.S. related instr. only.
(Deviation No.s DV-1, DV-3)
D-23 Containment 2 ITR-311,321 50 to A NA A NA NA Control Room Replace RTD's with quali- 1989 re- 1990 re-Sump Water 400 P Panel RHR fied equipment. See fueling fueling Temperature footnote (ss) outage outage (Deviation No.s DV-1, DV-3)
D-24 Chemical end Make up 2 QFI-200 0-200 GPM NA NA A NA NA Control Room No Action Required See NA NA Volume Control Flow-In Panel BA footnote (d)
System (Deviation No. DV-3)
D-25 Letdown Flow 2 QFI-301 0-200 GPM NA NA A NA NA Control Room No Action Required NA NA Out Panel BA and See footnote (d)
HSD (Deviation DV-3)
D-26 Volume Con- 2 OLC-451,452 Essential- NA NA A NA NA Control Room No Action Required NA NA trol Tank ly top to Panel BA See footnote (d),
Level bottom (65X and (tt) of Total (Deviation No.s DV-14 Volume) & DV-3)
D-27 Cooling Water CCW water 2 CTR-410,415, 0-200'P A NA A NA NA Control Room No Action Required NA NA System Temperature 420,425 Panel ESW See footnote (d) & (ill) to ESF Sys- (Deviation No. DV-3 &
tem DV<<25)
For Definition of "A" See Section 3.Q
Attachment to AEP:NRC:0773AB Page 41 Item se Variable Cat. Tag Nos. Range E Q S P Display Remarks/Action Req'd U-1 U-2 No. Q Q A F S. Location Schedule Schedule D-28 CCH Flow to 2 CFI-410,419, 0-10000GPM A NA A NA NA Control Room No Action Required NA NA ESF System 420,429 0-6000GPM Panel CCM See footnote (mmm)
(Deviation DV<<3)
D-29 Radwaste High Level RLS-255,256 Essentially NA NA NA NA NA Panel HDG None required NA Systems Radioactive Top to Bot-Liquid Tank tom (84X of Level Total Volume)
D-30 Radioactive 3 RPC-310,320, 0-225 psig NA NA NA NA NA Panel M)G No further action CMPLT CMPLT Gas Holdup 330,340, required Tank Pres- 350,360, sure 370,380 D-31 Ventilation Emergency 2 VCR-201 thru Open-Closed A NA A NA NA Control Room Replace Limit Switches 1989 re- 1990 re-System Ventilation 207 Panel IV VCR-201 6 202 with env. fueling fueling Damper Pos- VCR-207 qualified equipment. outage outage ition on Control Footnote (d) applies to Room Panel VCR-203 thru 207.
SPY See footnote (s)
(Deviation Nos. DV-l, DV-3)
Power Supplies Status of Standby Power and other Energy Sources Im-portant to Safety D-32a Diesel Cen 2 DGlAB 0-800A NA NA A NA NA Control Room See footnote (d) NA NA Status DCICD Panel SA No Action Required (Deviation No. DV-3)
D-32b 4KV Safety 2 Bus T11A, 0-150V NA NA A NA NA Control Room See footnote (d) NA NA Related Po- T11B, Panel SA No Action Required Power Systems Tllc (Deviation No. DV-3)
Status T11D For Definition of "A" See Section 3.0
Attachment to AEP:NRC:0773AB Page 42 Item ose Variable Cat. Tag Nos. Range E S P Display Remarks/Action Req'd U-1 U-2 No. R 0 A F S Location Schedule Schedule D-32c 250VDC 2 Battery AB 0-300V NA NA A NA NA Control Room See footnote (d) NA NA Battery Power Battery CD Panel SA No Action Required System Status (Deviation No. DV-3)
D-32d 120VAC Safe- 2 Channel I,II, 0-150V NA NA A NA NA Control Room See footnote (d) NA NA ty Related III, IV Panel SA No Action Required Power System (Deviation No.> DV-3)
Status D-32e Instrument 2 XPI-100 0-150psig NA NA A NA NA Control Room These are mechanical NA NA Air Status XP!-50 0-100psig Panel SV devices - no electrical XPI-20 0-60psig components No Action XPI-85 0-160psig Required (Deviation No. DV-3)
For Definition of "A" See Section ~F0
Attachment to AEP:NRC:0773AB Page 43
- " ho se variables to be monitored as required for use determining the magnitude of the release of radioactive materials d yp continually assessing such releases." Note: The schedule and status for each instrument is for when all of the applicable recommendations of Regulatory Guide 1.97, Rev. 3 will be met.
Item Purpose Variable Cat. Tag Nos. Range E S Q S P Display Remarks/Action Req'd U-l U-2 No. A F S Location Schedule Schedule E-l Containment Containment See item A-12 i Radiation Area Radia-tion High Range E-2 Area Radiation Radiation 3 ERA-7303 See Foot- NA NA NA NA NA Control Room Install new monitors By end of By end of Exposure thru 7308 note (kkk) CRT See footnote (uu) & 1989 19&9 Rate (in- ERA-8303 (kkk) (Deviation No.
side build- thru 8308 DV-23) ings or ERS-7401 where areas ERA-7403, of access are 7404 required to ERS-8401 service ERA-&403, equipment ERA-7504, important to. 7507, 75Q8 safety) ERA-7601 thru 7605 E-3a Noble Gases Containment 2 SEE ITEM E-3e and vent Flow or Purge Rate Effluent E-3b Reactor SEE ITEM E-3e Shield Building Annulus E-3c Aux Building 2 SEE ITEM E-3e E-3d Condenser 2 SRA-190Q 5.8E-07 NA NA A NA NA See footnotes NA NA Air Removal (Unit 1) to (d), (ww) and System Ex- SRA-2900 1.86E4 (xx) haust (Unit 2) uCi/cc (Deviation No.s DV-15 SFR-401 0-250 scfm & DV-3)
For Definition of "A" See Section 3.0
At'tachme to AEP:NRC:0773AB Page 44 Item rpose Variable Cat. Tag Nos. Range E S Q S P Display Remarks/Action Req'd U-1 U-2 No. Q A F ' Location Schedule Schedule E-3e Common VRS-1500 5.8E-07 to NA NA A NA NA Control Room None Required NA Plant Vent (Unit 1) 1.86E4 CT-1 Control See footnote (d)
VRS-2500 uCi/cc Terminal (Deviation DV-3)
(Unit 2)
VRF-315 0-200K scfm E-3f Vent from 2 MRA-1600 0.01 to NA NA A NA NA Control Room None Required NA NA S/G Safety 1700 100 uCi/cc Panel RMS See footnote (yy)
Relief (Unit 1) (Deviation No.s DV-16 Valves NRA-2600 6 DV-3) 2700 (Unit 2)
E-3g Other ident- 2 SRA-1800 5.8E-07 to NA NA A NA NA Control Room None Required NA NA ified re- (Unit 1) 1.86E4 Panel FI See footnote (d) lease points SRA-2800 uCi/cc (Deviation No. DV-3)
(Unit 2)
SFR-201 0-1000 scfm E-4 Particulates All identi- 3 See Item E-3e and Halogens fied release points (ex-cept S/G Safety Re-lief valves and Conden-ser air re-moval System exhaust)
Sampling and onsite analysis E-5a Environ Radia- Airborne 3 NA 1E-9 to NA NA NA NA NA NA None Required NA NA tion and Radio- Radioacti- 1E-3 activity vity and uCi/cc Particulates (minimum) sampling and analysis (portable)
For Definition of "A" See Section 3.0
~ WE ~~fly%% tl<<+
Attachment t AEP:NRC:0773AB Page 45 Item P e Variable Cat. Tag Nos. Range E Q S P Display Remarks/Action Req'd U-1 U-2 No. A F S - Location Schedule Schedule E-5b Plant and 3 NA Gamma NA NA NA NA NA NA Completion of End of End of Environs 1.0E-3 to Calibration 89 89 Radiation 1.0E4 R/hr.
(Portable) Beta/low energy gama 1.0E-3 to 1.0E4 Rad/hr E-5c Plant and NA Isotopic NA NA NA NA NA NA No further action CMPLT CMPLT Environs Analysis required. See Radioacti- footnote (zz) vity (Port-able)
E-6 Heteorology Wind Direc- 3 EFR-410,412, 0-360 NA NA NA NA NA Control Room None required NA NA tion 413.414 Panel Flx and/or CRT E-7 Wind Speed 3 EFR-400,404, 0-100 mph NA NA NA NA NA Control Room None required NA NA 402,403 Panel Flx and/or CRT E-8 Estimation 3 ETR-400,402, -30 to 50'C NA NA NA NA NA Control Room None required NA NA of Atmos- 403 Panel Flx pheric ETQ-401 and/or CRT Stability E-9a Accident Samp- Gross Acti- 3 NSX-101,103 1 uCi/ml to NA NA NA NA NA NA See Item C-2 NA NA ling Primary -vity ESX-400 10 Ci/ml See footnote (aaa)
Coolant and Sump E-9b Gamma Spec- 3 NSX-101,103 0.050 to NA NA NA NA NA NA See item C-2 NA NA trum ESX-400 2.05 HeV See footnote (bbb)
Isotopic Analysis For Definition of "A" See Section 3.0
Attachment to AEP:NRC:0773AB Page 46 Item ose Variable Cat. Tag Nos. Range S Q S P Display Remarks/Action Req'd U-1 V-2 No. Q A . F S Location Schedule Schedule E-9c Boron Con- 3 NSX-101,103 375 to 2000 NA NA NA NA NA NA See Item C-2 tent ESX-400 ppm See footnote (ccc)
& (bb)
E-9d Chloride 3 NSX-101,103 0.01 to NA NA NA NA NA NA SEE ITEM C-2 NA NA Content ESX-400 20 ppm (See footnote (ddd)
(Deviation No. DV-17) 1 E-9f Dissolved 3 NSX-101,103 0-2000 cc/ NA NA NA NA NA NA SEE ITEM C-2 NA H2 or total ESX-400 kg gas E-9g gissolved 3 NSX-101,103 0-20 ppm NA NA NA NA NA NA SEE ITEM C-2 NA 2 ESX"400 NA'-9h pll NSX-101,103 1.0 to 13.0 NA NA NA NA NA NA SEE ITEM C-2 NA NA ESX-400 pH See footnote (eee)
E-10a Containment H2 Content, 3 ESX-001 NA NA NA NA NA NA NA None required NA NA Air See footnote (fff)
(Deviation No. DV-18)
E-10b 0 2 Content 3 NA NA NA NA NA NA NA NA None required NA NA See footnotes (q) and (ggg)
(Deviation No. DV-19)
E-10c Gamma Spec- 3 ESX-001 1 uCi/cc to NA NA NA NA NA NA None required NA trum 10 Ci/cc See footnote (hhh)
Isotopic Analysis For Definition of "A" See Section 3.0
ATTACH TO AEP I NRC'773Ab Page 47 ATTACHMENT NO. 1 TO TYPE B ABLES TABLE ITEM NO. B-14 CONTAINMENT ISOLATION VALVES Plant ID Channel Plant ID Channel YCR-20 Glycon Return fros Contsineent VCR-932 NESV to RCP CUY Unit 4 YCR-21 Glycon Return fros Contsinaent VCR-922 NESV froa CUY Unit 1 XCR-100 Cntrl Air to Cntnsent Islstion Ylvs VCR-923 NESV froa CUY Unit 1 XCR-101 Cntrl Air to Cntnsent Islstion Ylvs VCR-926 NESV froa.CUY Unit 2 XCR-102 Cntrl Air to Cntnsent Ielstion Ylvs VCR-927 NESV fros CUY Unit 2 XCR-103 Cntrl Air to Cntnsent Islstion Ylvs VCR-930 NESV froa CUY Unit 3 GCR-301 M2 Supply to Pressurixer Relief TnM 'VCR-931 MESV fros CUY Unit 3 Cctt-451 CCV fr RCPs Lvr Guide Bearing Coolr VCR-934 NESV fros CUY Unit 4 CCN-452 CCV fr RCPs Lvr Guide Bearing Coolr VCR-935 NESV froa CUY Unit 4 CClt-453 CCV iros RCPs Therssl Barriers VCR-941 NKSV to RCP 1 Air Cooler CCtt-454 CCV froa RCPs Therasl Barriers VCR-942 NKSV to RCP 2 Air Cooler CCN-458 CCV to RCPs Oil Coolers snd Therasl VCR-943 NESV to RCP 3 Air Cooler CCM-459 CCV to RCPs Oil Coolers snd Therssl VCR-944 NESV to RCP 4 Air Cooler Barriers VCR-945 -NESV fros RCP 1 Air Cooler ECR-31 Contsinsent Air Monitor VCR 955 NESV froa RCP 1 Air Cooler ECR-32 Contsinsent Air Monitor VCR-946 NESV froa RCP 2 Air Cooler ECR-33 Contsinaent Air ttonitor ltCR-956 NESV froa RCP 2 Air Cooler ECR-35 Contsinsent Air Monitor VCR-947 NESV froa RCP 3 Air Cooler KCR-36 Contsinsent Air Monitor VCR.957 NKSV froa RCP 3 Air Cooler VCR-901 NESV to CLY Unit 1 VCR-948 NESV fros RCP 4 Air Cooler VCR-905 NES'V to CLY Unit 2 VCR.958 NKSV froa RCP 4 Air Cooler VCR-909 NESV to CLY Unit 3 VCR-951 MESV to RCP 1 Air Cooler VCR-913 'MESV to CLY Unit 4 VCR-952 NESV to RCP 2 Air Cooler VCR-900 NKSV to RCP CI.Y Unit 1 VCR-953 NKSV to RCP 3 Air Cooler VCR-904 MESV to RCP Ct.Y Unit 2 VCR-954 NESV to RCP 4 Air Cooler VCR-908 NESV to RCP CLY Unit 3 VCR-960 NESV to Instrsnt Rs Yntilstn Unite VCR-912 MESV to RCP CLY Unit 4 VCR-961 MES'V to Instrsnt Ra Yntilatn Units VCR-902 MESV froa CLY Unit 1 VCR-964 NESV to Instrsnt Rs Yntilstn Units VCR-903 MESV froa CLY Unit 1 VCR-965 MESV.to instrsnt Ra Yntilstn Units VCR-962 NESV fr Instrsnt Rs Yntilstn Units VCR.906 MESV froa CLY Unit 2 VCR-907 MESV fros CLY Unit 2
'VCR-963 NKSV to Inatrsnt Rs Yntilstn Units VCR-910 NESV froa CLY Unit 3 VCR-966 NES'V to Instrsnt Ra Yntilatn Units VCR-967 MESV fr Instrsnt Ra Yntilstn Units VCR-911 NESV fros CLY Unit 3 CCR-440 CCV fros Nein Stesa Penetration VCR-914 NESV fros CLY Unit 4 .CCR-441 CCV froa Main Stess Penetration VCR-915 NESV fros CLY Unit 4 NCII-221 Nein Stess to Auxiliary Feed Pusp VCR-921 NESV to CUY Unit 1 VCR-925 NESV to CUY Unit=2 NCM-231 ltsin Stess to Auxiliary Feed Pusp CClt-430 CCV to E Pressure Equslixstion Fsn VCR-929 NESV to CUY Unit 3 CCM-431 CCV to E Pressure Equslixstion Fsn VCR-933 NESV to CUY Unit 4 CCN-432 CCV to V Pressure Equslixstion Fsn VCR-920 IIESV to RCP CUY Unit 1 CCtt-433 CCV to V Pressure Equslixstion Fsn VCR-924 NESV to RCP CUY Unit 2 VCR-928 ,NESV to RCP CUY Unit 3
'1 ATTACH> TO AEP:NRC10773AB Page 48 ATTACllMLrNT NO. 1 TO TYI'Lx 9 'ADLL'S TABI E ITLM NO . 8- l4 CONTAINMENT ISOLATION VALVES Plant ID Channel Plant ID Channel CCR-A55 CCV to Reactor Supports Cntnsent CCR-A56 CCV froa Reactor Supports KCR-10 H2 Sasple 6 Return Valves CCR-157 CCV froa Reactor Supports ECR-11 Cntnsent H2 Sssple 6 Return Valves CCR-460 fros ECR-12 Cntnaent H2 Sasple 6 Return Valves CCV Excess Letdovn Hx to Excess Letdovn KCR-13 Cntnsent H2 Sasple 6 Return Valves CCR-462 DCR-201 CCV RC Drain Tank to Vent Hx Header KCR- I i Cntnaent Cntnsent H2 Saaple 6 Return Valves
))Cl)-202 ECR-15 H2 Sasple 6 Return Valves NC Drnln Tnnk tu Cnu Analyzer ECR-16 Cntnsent H2 Saaple 6 Return Valves Ix:I)-2))'I IH: l)rnln Tn))k tn Vv))t Cntnsent Hu()dcl'CR-20'C KCR-17 H2 Sasple 6 Return Valves Drain Tank to Oas Analyzer KCR-18 Cntnaent H2 Seeps 6 Return Valves DCR-205 RC Drain Tank Suction ECR-19 Cntnsent H2 Saspl ~ Return Valves DCR-206 RC Drain Tank Suction Isolation 6
Isolation ECR-20 ,Cntnsent H2 Saaple 6 Return Valves DCR-207 Nitropen ECR-21 )Cntnaent Sasple Return Valves Supply to RC Drain Tank H2 6 DCR-301 S/0 Blovdovn ECR-22 )Cntnaent H2 Sasple Return Valves DCR-302 S/0 Blovdovn Seeps Isolation C
Saaple Isolation ECR-2( )Cntnunt H2 Saaple 6 Return Valves DCR-303 S/0 Blovdovn Sasple ECR-23 iCntnsent H2 Saapl ~ 6 Return Valves DCR-301 S/0 Blovdovn Saaple Isolatfon Isolation KCR-25 )Cntnaent H2 Saaple 6 Return Yalves DCR-310 S/0 If, l2, i3 6 ECR-26 )Cntnsent H2 Saaple 6 Return Valves IA Blovdovn Yalves OCR-320 S/0 ef, A2, e3 C ECR-27 Cntnaent )aspic 6 Return Valves i4 Blovdovn Valves H2 DCR-.330 S/0 il, 82, A3 6 ii Blovdovn Valves ECR-28 Cntnsent H2 Saaple 6 Return Valves DCR-340 S/0 tf, i2, l3 6 DCR-600 Containsent Susp li to Blovdovn Valves ECR-29 GCR-31(
Cntnsent H2 Saaple 6 Return iNftrogen Supply to Accusulators Valves Vesta Holdup DCR-601 Containaent Susp ICR-5 Accusulator Sasple Valves DCR-610 Ice Condenser Drain to Vesta Holdup ~
to Drain Header ICR-6 Accusulator Sasple Valves DCR-611 Ice Condenser Drain to Drain Header HCR-251 iSasple fros Hain Steas Lines DCR-620 Cntnaent Ventilation Drain to Hldup NCR-252 .Sasple fros Hain Steas l.ines DCR-621 Cntnsent Ventilation Drain to Hlduup HCR-253 Sasple fraa Hain Steas Lines KCR--<f6 Containsent Liquid HCR-25( Sasple fros Hain Steaa Lines ECR-41 7 Containsent Saaplfng ng S ys t ea NCR-105 Priaary Systes Hot Lep Saaple Liquid Sasplfng Systes KCR-496 Containsent Liquid Saapllnp S t NCR-106 Prisary Systes Hot Leg Sasple
-i97 Contafnaent Liquid NCR-107 iPressurlxer Liquid Saaple KCR-535 Containeent Oae Saaplfnp Systea NCR-108 Pressurizer l.iquid Sasple
- 36 Contafnsent Saapli np S ya t ea ECR-5 Oas Saapling Systea NCR-109 Preseurixer Steas Saspl>>
OCR-91 9 Cont. Desin.
Cleanup Vater Isol. NCR-110 Pressurlxer Steaa Saaple OCR-920 Cont. Basin.
Cleanup Vater Isol. OCR-300 Letdavn Line Isolation Yalve OCR-301 .Letdovn Line Isolation Valve NCR-252 )Prsary Nkup H20 to Prsarzer Rlf Tnk OCN-250 )RCP Seal H20 Return Isolation Valve OCN-350 iRCP Seal H20 Return Isolation Valve RCR-100 iPrssrxer Rlf Tnk to Gas Analyzer RCR-101 Prssrxer Rlf Tnk to Oaa Analyzer VCR-10 Olycon Supply to Containsent VCR-11 Olycon Supply to Containaent
ATTACHMENT TO AEP:NRC:0773AB Page 49 ATTACHMENT NO. 2 TO TYPE B VARIABLES TABLE ITEM NO. B-14 Most of the valves listed in Attachment No. 1 to Type B Variables Item No. B-14 are located outside of containment and are only subject to an HELB outside of containment. Since they are not required to operate (per EOP's) in the event of an HELB, qualification is not required because they will be located in a mild environment should a Design Basis Event (DBE) occur where their use is required. Redundant indication is also not required because the valves are backed up by a second, redundant valve, also listed in Attachment No. 1.
Exceptions to the above are listed as follows:
DCR-301,302,303,304,310,320,330,340, and XCR-100,101,102,103 will be upgraded by replacing the position indication limit switches with environmentally and seismically qualified equipment. These valves are located outside of containment and are required to operate during an HELB.
The position indication limit switch for QCM-250 is located outside containment and is not qualified for a DBE inside of containment.
It is, however, backed up by QCM-350 which is located outside of containment and its position indication limit switch is qualified.
Should there be a DBE inside containment and QCM-250 did not indicate appropriately, QCM-350 could be used to verify isolation.
In addition an operator could be dispatched to visually verify QCM-350 closure. If a DBE outside of containment should occur, QCM-350 is qualified for the adverse environment generated and could be backed up by QCM-250 which would not be subjected to the harsh environment and therefore, would be expected to indicate appropriately. See footnote (ee)
The position indication limit switches for VCR-11 and 21 are located inside containment and not qualified for a DBE inside containment. They are, however, backed up by VCR-10 and 20, respectively, which are located outside of containment. Should there be a DBE inside containment and VCR-ll or 21 did not indicate appropriately, VCR-10 and 20 can be used to verify isolation. In addition, an operator could be dispatched to visually verify closure. DBE's outside of containment will not create a harsh environment at VCR-10 and 20 locations. See footnote (ee)
CCM-451 452 453,454,458,459; CCM-430,431,432,433; and MCM-221,231 are qualified for an HELB.
VCR-101 thru 107 and 201 thru 207 are not listed in Attachment 1 because their function is specifically listed in the Type D Variables Table, Item D-31.
ATTACHMENT TO AEP:NRC:0773AB Page 50 4.0 FOOTNOTES DESIGNATING DEVIATIONS TO REGULATORY GUIDE 1.97, REV. 3 (a) The automatic in)ection of boric acid into the RCS by the safety injection system following a postulated LOCA/HELB will be monitored and verified through the use of qualified instrumentation. In addition, since all sources of water for the safety infection system (Accumulators, Boron Injection Tank and Refueling Water Storage Tanks) are required by Technical Specifications to contain boric acid solution of a minimum concentration, the proper operation of the ECCS ensures an adequate boron concentration in the reactor coolant to achieve and maintain the safe shutdown of the reactor core. The RCS soluble boron content is not expected to change rapidly, all, following the initial borating during the SI phase of an accident.
if at Periodic analysis of RCS samples would detect any significant changes in boron concentration. Instrumentation to continuously monitor RCS soluble boron concentration is not required since periodic analysis of RCS grab samples is adequate for verification of reactivity control. This is a deviation from the recommendations of Reg. Guide 1.97 Rev. 3 for providing continuous RCS boron concentration indication (Deviation No. DV Also see footnote (bb)).
(b) Redundancy not required per NUREG 0737 requirements.
(c) Seismic qualification not required per NUREG 0737 requirements.
(d) All equipment when required to be used, is located in a mild environment, therefore environmental qualification is not required.
(e) Lack of lower containment spray flow monitoring instrumentation will not deter the operator's ability to determine adverse containment conditions.
adverse containment conditions can be monitored by looking at items such as containment pressure. If we see containment pressure conditions different than what is expected, then we can confirm whether adverse containment conditions are due to a lack of spray flow by the monitoring of containment spray pump discharge pressure.
(f) DELETED (g) DELETED (h) Instrumentation to continuously monitor RCS radioactivity is not required. See footnote (ff). Periodic analysis of RCS grab samples is adequate to detect deterioration of fuel cladding. Indicative of an inadequate core cooling (ICC) event, fast deterioration of fuel cladding could be detected by sensing the ICC conditions through diverse instrumentation (i.e., RVLIS, CET's, TSAT meter).
(i) Per SER issued June 16, 1981 concerning Auxiliary Feedwater System reliability, it is only required that qualified, S/G narrow range level indication be provided and backed up by qualified Auxiliary Feedwater Flow Indication. S/G wide range level indication is not required to be environmentally qualified or powered from a Class IE power source.
ATTACHMENT TO AEP:NRC:0773AB Page 51 (j) DELETED (k) DELETED (l) INTENTIONALLY LEFT BLANK (m) DELETED (n) DELETED (o) INTENTIONALLY LEFT BLANK (p) DELETED (q) Not required per NUREG 0737 II.B.3 (r) These valves are left normally open (safe position), the breakers racked out and they cannot change position. Therefore, Environmental Qualification of position indication is not required.
(s) Redundancy can be provided by VCR-101 thru 107 which are located inside containment. VCR-201 thru 207 are located outside containment.
(t) Our original submittal identified both the centrifugal charging pump (CCP) flow and CCP motor breaker status as type A variables. This would require Category 1 instrumentation for monitoring these parameters. The CCP breaker status indication will meet the Regulatory Guide 1.97, Rev. 3 recommendations for Category 1 instrumentation, except as noted in the Table under item No. A.28.
With regard to the CCP flow indication, it should be noted that our Emergency Operating Procedures require manual operator action based on indication of pump operation or flow. The CCP breaker status indication and other parameters serve to verify pump operation. The non Category 1 CCP flow indication can serve as a backup.
The above is a basis for our deviation from the Regulatory Guide 1.97, Rev 3 recommendation to provide Category 1 instrumentation for CCP flow indication.
(This deviation was discussed in AEP:NRC:0773S, Attachment 3, Item 2).
(u) Transmitters to be replaced to improve accuracy. See AEP:NRC:0836T dated July 16, 1987.
(v) Credit was not originally taken for the seismic qualification of equipment as noted in AEP:NRC:07730. We will take credit for seismic qualification of this equipment which has been established. This response was also given in AEP:NRC:0773S Attachment 1, Item 3.3.7.
(w) Monitoring of containment pressure is currently provided by two Category 3 wide-range (-5 to 36 psig instruments) and four Category 3 narrow-range (-5 to 12 psig) instruments. The design pressure of the Cook Nuclear Plant containments is 12 psig. The four narrow-range instruments are scheduled to be upgraded to meet Category 1 requirements by the end of the 1987 refueling outage for Unit 1 (which has been completed) and by the end of the 1988 refueling outage for Unit 2.
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ATTACHMENT TO AEP:NRC:0773AB Page 52 The wide-range containment pressure instrumentation ranges were revised to meet the requirements of NUREG-0578 and NUREG-0737. These instruments are not powered by a emergency standby power source as recommended by Regulatory Guide 1.97, Rev. 3 for Category 1 instrumentation, and they do not meet the Category 1 separation criteria. The wide-range instrumentation is, however, highly reliable, and as a result we believe it is unlikely that it would not be available if needed to monitor the course of an accident. Further, it is our belief that for other than short-term individual compartment pressure peaks, the narrow-range instrumentation would span the range of pressure anticipated in our evaluation of loss-of-coolant-type'ccidents. On the above basis, this is a deviation from the Regulatory Guide 1.97, Rev. 3 recommendation to provide Category 1 wide-range containment pressure instrumentation (Deviation No. DV-6). See response to AEP:NRC:0773S , Item 4.
(x) The saturation meter equipment was originally installed in accordance with the requirements of NUREG-0578. In an SER dated March 20, 1980, the equipment installed to monitor degrees of subcooling was found to be acceptable (NRC letter, A. Schwencer to John E. Dolan, dated March 20, 1980).
As noted in that correspondence, the device installed was a discrete digital monitor, and the plant process computer was used in conjunction with this monitor to, provide subcooling margin. Additionally, as part of the NUREG-0737 Supplement 1 requirements, a subcooling margin curve is provided by our Technical Support Center computer. We believe that these three instrument systems, which have been installed to be consistent with the requirements of their appropriate documents, are reliable. As a result, we believe unlikely that they would not be available if
't needed to monitor the course of is an accident.
It should be noted that our original submittal providing status of Regulatory Guide 1.97, Rev. 3 compliance (AEP:NRC:07730, dated October 15, 1985) was intended to identify instrumentation currently in compliance with the Regulatory Guide; instrumentation not in compliance for which upgrading to the Regulatory Guide recommendations was planned; and instrumentation not in compliance for which justification for- a deviation from the Regulatory Guide recommendations was provided. The instrumentation for monitoring degrees of subcooling falls into the latter category.
Based on the above information and justification, we again submit a deviation from the Regulatory Guide 1.97, Rev. 3 recommendation to provide Category 1 instrumentation for monitoring degrees of subcooling (Deviation No. DV-7). See AEP:NRC:0773S Attachment 1, Item 3.3.3.
(y) For similar reasons to those stated in (t) above, we submit a deviation from the Regulatory Guide 1.97, Rev. 3 recommendation to provide Category 1 instrumentation for safety injection (SI) pump flow indication (Deviation No. DV-22). The SI pump motor breaker status instrumentation will meet Category 1 requirements except as noted in the Table under Item A.29. This deviation was detailed in AEP:NRC:0773S Attachment 3, Item 3.
(z) Our original submittal identified the steam generator blow down radia-tion indication as a Type A variable. However, because of changes in our Emergency Operating Procedures made subsequent to our original submittal,
ATTACHMENT TO AEP:NRC:0773AB Page 53 manual operator action is no longer based on this variable. We therefore request that steam generator blowdown radiation indication be deleted from our original list of Type A variables. This response was given in AEP:NRC:0773S Attachment 3, Item 6.
(aa) We will provide Neutron Flux Monitoring to comply with Reg Guide 1.97 Rev 3 recommendations, except as noted in the Table.
(bb) Primary coolant boron concentration can be measured in a range of 375 ppm to 10,000 ppm. This range is based on PASS reactor coolant samples with a 1:1000 dilution. The undiluted reactor coolant grab sample will be measured in the .375 to 10 ppm range.
PASS would be used during and following loss-of-coolant accidents. In the event of a LOCA, emergency boration and injection from the refueling water storage tank would occur and we would therefore expect a reactor coolant boron concentration substantially in excess of the low range of our PASS sample measurement capability.
On the basis of the above, we submit a deviation from the Regulatory Guide 1.97, Rev. 3 recommendation to provide the capability to measure boron concentration in PASS samples to the lower limit of 0 ppm (Deviation No. 8).
This deviation was also detailed in AEP:NRC:0773S Attachment 1, Item 3.3.2.
(cc) Our original submittal indicated that we would replace the cold and hot leg RCS water temperature recorders with Category 1 instruments by the end of the 1987 refueling outages for Units 1 and 2. However, a more detailed review of our current design has resulted in the identification of additional work (e.g., control room equipment and cable relocation, and installation of new emergency standby power sources) that needs to be performed beyond that identified at the time of our original submittal. We therefore request that the completion dates for upgrading the recorders to meet Category 1 require-ments be changed to the 1989 refueling outage for Unit 1 and 1990 refueling outage for Unit 2. This was noted in AEP:NRC:0773S Attachment 3, Item 5. We have also since determined that only two hot leg and two cold leg channels are necessary to comply with the Reg. Guide 1.97 recommendations and therefore we are only taking credit for the instruments noted in the table.
This item is pending NRC approval of an Appendix R change request.
(dd) Because of changes to the EOP's from the original October, 1985 submittal and planned changes to this instrumentation, we have reclassified this instrumentation as Category 2 per Reg. Guide 1.97 guidance.
(ee) We will upgrade the valve position limit switches on valves VCR-11 and VCR-21 to meet the environmental qualification requirements of 10 CFR 50.49 and Regulatory Guide 1.97, Rev. 3 recommendations.
The valve position limit switches for valve QCM-250, as 'well as the associated cable and terminations, are qualified in accordance with 10 CFR 50.49(k) except that they have not been qualified for submergence. The QCM-250 position indication limit switch is located below maximum flood level. Although this is not completely consistent with the Regulatory Guide 1.97, Rev. 3 recommendations for equipment qualification, we do not believe any upgrading of the position indication limit switch is necessary.
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ATTACHMENT TO AEP:NRC:0773AB Page This is due to the fact that QCM-250 is designed to close within 15 seconds of a containment isolation signal, which means that the valve will not become submerged before it performs its safety function. In addition, once the valve is closed, its it is extremely unlikely that it would change position due to submergence.
Given these considerations, we believe that QCM-250 in its present status, without upgrading, adequately meets the intent of Regulatory Guide 1.97, Rev. 3 recommendations for achieving verifiable containment isolation.
We therefore submit a deviation from the recommendation of Reg. Guide 1.97 Rev. 3 with respect to environment qualification for QCM-250. (Deviation No.
DV-24).
The planned schedule for upgrading VCR-11 and VCR-21 to meet 10 CFR 50.49 requirements calls for this work to be completed in both units by the end of the refueling outages presently scheduled for 1989 (Unit 1) and 1990 (Unit 2).
This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.4.
(ff) As stated in our original submittal (AEP:NRC:07730, dated October 15, 1985) the primary coolant system radioactivity is not continuously monitored by in-line instrumentation. Rather, periodic analysis of reactor coolant grab samples is provided to detect deterioration of fuel cladding. Our post-accident sampling system provides a diluted grab sample which is analyzed by the gamma spectrum analyzer. See our response to footnote (gg) below for the range of our gamma spectrum analyzer. On the basis of the sampling capability described in footnote (gg) we are submitting a deviation from the Regulatory Guide 1.97, Rev. 3 recommendation for continuous monitoring of radioactivity in the reactor coolant system (Deviation No.
DV-9). It should also be noted that Category 1 requirements for this system are only to be applicable to equipment that operates equipment installed in the portion of piping that is Seismic Class I. Electrical equipment operating equipment installed in Seismic Class 3 piping is to meet Category 3 requirements. This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.5.
(gg) We believe the EG&G evaluation should have cited a range of 1 uCi/ml to 10 Ci/ml for this variable as per Table 3 of Regulatory Guide 1.97, Rev. 3.
Our range of measurement for gamma spectrum analysis of the diluted post-accident system grab samples of primary coolant is 1 uCi/ml to 10 Ci/ml.
This complies with the Regulatory Guide 1.97, Rev. 3 recommended range.
(hh) The instrumentation identified for this parameter in our original submittal was incorrect. We initially identified our lower containment normal process radiation monitors (ERS-1300 and 1400 for Unit 1 and ERS-2300 and 2400 for Unit 2) for this parameter. The instruments used to monitor this parameter are the unit vent radiation monitors (VRS-1500 for Unit 1 and VRS-2500 for Unit 2).. The display location for these instruments is the control room CT-1 control terminal, not panel WDG. All other information contained in our original submittal for this item remains the same. This information was provided in AEP:NRC:0773S Attachment 3, Item 7.
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ATTACHMENT TO AEP:NRC:0773AB Page 55 (ii) We incorrectly identified the instruments as ITR-311 and 321. These are actually the RHR heat exchanger inlet temperature devices. The outlet instrumentation tag numbers are ITI-310 and 320. These devices have a range of 0-400'F and indicate locally and in the Technical Support Center computer terminal located in the Technical Support Center and the control room. We believe this instrumentation meets the Regulatory Guide 1.97 recommendations for RHR heat exchanger outlet temperature measurement range. This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.10.
(jj) The correct range for IFI-310 and 320 is 1500-5000 GPM. We inadvert-ently reported the incorrect range to you in our previous submittal AEP:NRC:
07730. We believe that this still complies with Reg. Guide 1.97 Rev. 3 requirements for range for this variable.
(kk) To clarify our initial response, these motor-operated valves are normally left in the open position when the plant is operating in Mode 1 and Mode 2. The circuit breakers are racked out and the valves cannot, there-fore, spuriously change position. They can change position only as the result of deliberate operator action. This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.12.
(ll) We presently have instrumentation installed that we believe meets Regulatory Guide 1.97, Rev. 3 recommendations. Pressurizer heater current can be monitored by observing ammeters located on the pressurizer control panel-in the control room. The range is 0-200 amps. The pressurizer heaters are powered from the safety buses and therefore have the capability of being powered by the emergency power sources. Automatic shedding of the pressurizer heaters following a blackout is provided to prevent overloading of the emergency power sources. The operator can afterwards, at his discretion, manually energize the pressurizer heaters, taking care not to overload the emergency power sources. This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.14.
(mm) We do not rely on the quench tank to perform any post-pressurizer release function. However, we are providing the following information in response to the EG&G evaluation. The range of 74% of total tank volume originally submitted was not accurately stated to show the adequacy of the existing installation. The correct range should have been stated as being from 7 inches above the tank bottom to 7 inches below the tank top. This range includes coverage of the sparger. With regard to the ability to quench a "design-basis" pressurizer release, as noted above we do not rely on the quench tank to perform this function. The quench tank is used during normal plant operation to contain pressurizer releases from routine pressurizer pressure adjustments and valve leakage. In the case of a design-basis event that causes the PORVs and safety relief valves to lift, two rupture disks will burst before reaching the quench tank design pressure of 100 psi.
Subsequently discharge through the quench tank into the containment sump will occur.
With regard to overpressurization, we do not understand the basis for the EG&G position that sufficient gas volume exists to accept pressurizer release without becoming overpressurized. As noted above, overpressurization will not occur, because rupture discs will burst and discharge into the containment before reaching the tank design pressure of 100 psig.
g, ATTACHMENT TO AEP:NRC:0773AB Page 56
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Normal water level is kept at between 80X and 84X of the instrument range with a high alarm at 84X and a low alarm at 79X. As such, in-leakage from the relief discharge system can be adequately monitored. We therefore submit a deviation from the Regulatory Guide 1.97 recommendation to monitor quench tank level from top to bottom of tank (Deviation No. DV-10). This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.15.
(oo) On August 21, 1981 we submitted a letter (AEP:NRC:0300G) that documented discussions with NRR staff clarifying certain portions of an NRC SER (June 16, 1981) of the Cook Nuclear Plant auxiliary feedwater syst'm. In that letter it was confirmed that Regulatory Guide 1.97 recommendations for steam generator level instrumentation did not have to be implemented at that time, but that implementation would be addressed at some time in the future through the Regulatory Guide 1.97 compliance/commitment process.
The steam generator wide-range level indication is not required for post-accident monitoring and in fact has been deleted from our Technical Specifications on Units 1 and 2. This was stated in our December 10, 1980 letter, which submitted a proposed amendment to our Technical Specifications (AEP:NRC:0449). As stated in that letter, the reasons for deletion of steam generator wide-range level indication from the Technical Specifications are:
(1) the S/G vide-range level indication does not perform any safety-related function and is not assumed operable in the various plant safety analyses; and (2) the S/G narrow-range instrumentation, which we believe fulfills post-accident monitoring requirements, is environmentally and seismically, qualified, powered from a Class 1E source and has three redundant channels per S/G. The S/G level indication is backed up by auxiliary feedwater flow instrumentation.
The S/G wide-range level instrumentation is powered from a Class lE source, but all four channels are powered by the same source. Since this is not in compliance with the Regulatory Guide 1.97, Rev. 3 recommendation, and based on the information given above, we are submitting a deviation from the Regulatory Guide 1.97, Rev. 3 recommendation for S/G level instrumentation.
(Deviation No. DV-11) This information was provided in AEP:NRC:0773S , Item 3.3.16.
(pp) We incorrectly identified the range of instr~entation measuring this variable as 0-5x10 PPH. It should read 0-4x10 PPH. We believe that this still complies with Reg. Guide 1.97 Rev. 3 requirements for range for this variable.
(qq) I6MECo currently provides condensate storage tank (CST) level indication in the control room through three highly reliable Category 3 level-measuring devices. One of these instruments is electrically operated, while the other two are pneumatic devices. In addition, CST level can be read at the local turbine-driven auxiliary feedwater pump control panel. I&MECo has also committed to provide additional CST level indication by adding an instrument channel to meet Category 1 requirements. The new channel was installed during the 1987 refueling outage on Unit 1 and the 1988 refueling outage on Unit 2.
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ATTACHMENT TO AEP:NRC:0773AB Page 56 Normal water level is kept at between 80% and 84X of the instrument range with a high alarm at 84% and a low alarm at 79X. As such, in-leakage from the relief discharge system can be adequately monitored. We therefore submit a deviation from the Regulatory Guide 1.97 recommendation to monitor quench tank level from top to bottom of tank (Deviation No. DV-10). This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.15.
(oo) On August 21, 1981 we submitted a letter (AEP:NRC:0300G) that documented discussions with NRR staff clarifying certain portions of an NRC SER (June 16, 1981) of the Cook Nuclear Plant auxiliary feedwater system. In that letter it was confirmed that Regulatory Guide 1.97 recommendations for steam generator level instrumentation did not have to be implemented at that time, but that implementation would be addressed at some time in the future through the Regulatory Guide 1.97 compliance/commitment process.
The steam generator wide-range level indication is not required for post-accident monitoring and in fact has been deleted from our Technical Specifications on Units 1 and 2. This was stated in our December 10, 1980 letter, which submitted a proposed amendment to our Technical Specifications (AEP:NRC:0449). As stated in that letter, the reasons for deletion of steam generator vide-range level indication from the Technical Specifications are:
(1) the S/G wide-range level indication does not perform any safety-related function and is not assumed operable in the various plant safety analyses; and (2) the S/G narrow-range instrumentation, which we believe fulfills post-accident monitoring requirements, is environmentally and seismically qualified, powered from a Class 1E source and has three redundant channels per S/G. The S/G level indication is backed up by auxiliary feedwater flow instrumentation.
The S/G vide-range level instrumentation is powered from a Class 1E source, but all four channels are powered by the same source. Since this is not in compliance with the Regulatory Guide 1.97, Rev. 3 recommendation, and based on the information given above, we are submitting a deviation from the Regulatory Guide 1.97, Rev. 3 recommendation for S/G level instr'umentation.
(Deviation No. DV-11) This information was provided in AEP:NRC:0773S , Item 3.3.16.
(pp) We incorrectly identified the range of instrgmentation measuring this variable as 0-Sx10 PPH. It should read 0-4x10 PPH. We believe that this still complies with Reg. Guide 1.97 Rev. 3 requirements for range for this variable.
(qq) I&M currently provides condensate storage tank (CST) level indication in the control room through three highly reliable Category 3 level-measuring devices. One of these instruments is electrically operated, while the other two are pneumatic devices. In addition, CST level can be read at the local turbine-driven auxiliary feedwater pump control panel. I&M has also committed to provide additional CST level indication by adding an instrument channel to meet Category 1 requirements. The new channel was installed during the 1987 refueling outage on Unit 1 and the 1988 refueling outage on Unit 2.
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ATTACHMENT TO AEP:NRC:0773AB Page 57 The CST is the initial source of water for the auxiliary feedwater (AFW) system, and provides sufficient volume to maintain the reactor coolant system in a hot standby condition for 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />. In the event that sufficient water is not available from the CST in one unit, operating procedures call for a cross-tie valve to be opened to supply feedwater from the CST in the other unit.
In the unlikely event that neither CST can supply sufficient AFW, procedures require transferring the supply source to the essential service water system (ESWS). The water supply for the ESWS is Lake Michigan.
In view of the number and diversity of instrumentation available to provide CST level monitoring, and the ultimate availability of Lake Michigan as a source of auxiliary feedwater, we are submitting a deviation from the Regulatory Guide 1.97 recommendation to provide more than one Category 1 level indication for the CST (Deviation No. DV-12). This information was provided in AEP:NRC:0773S Attachment 3, Item 1.
(rr) When operating normally, each containment spray pump will deliver 3200 gpm (design flow) at 490 ft. TDH. We have attached to this response a curve showing containment spray pump flow as a function of pump discharge pressure (drawing No. HXP87055JW-1). See Attachment No. 4.
The attached curve indicates the expected range of operation for the containment spray pumps. This operating range stems from consideration of pump suction head, containment pressure, and pump operating characteristics.
Routine surveillance of spray pump operation is performed to ensure that, containment spray is required, the pumps will operate in the indicated area if of the flow curve and hence provide the necessary flow to the containment spray system. The reactor operators can, therefore, verify proper containment spray flow by monitoring spray pump discharge pressure to confirm that it is within the expected range.
It should be noted that the upper containment spray flow instrumentation cited in our original submittal (AEP:NRC:07730, dated October 15, 1985
[IFI-330 and 331]) measures only the flow provided by the RHR pumps to the upper containment spray, not the flow from the containment spray pumps.
However, the containment spray pumps, not the RHR pumps, are normally used to supply containment spray flow. Also, please note that the flow range of 0-200 gpm for IFI-330 and 331 (for measurement of RHR pump flow to the upper containment spray) given in that submittal is incorrect. The correct range is 0-2500 gpm.
Based on the above, we are noting a deviation from the Regulatory Guide 1.97, Rev. 3 recommendation for containment spray flow instrumentation (Deviation No. DV-13). This information was provided in AEP:NRC:0773S , Item 3.3.17.
(ss) The RHR heat exchanger inlet temperature instrumentation will be upgraded to meet Regulatory Guide 1.97 Rev. 3 recommendations except as noted in the tables. This response was given in AEP:NRC:0773S Attachment 1, Item 3.3.18.
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ATTACHMENT TO AEP:NRC:0773AB Page 58 (tt) Because of the following actions which apply for normal, accident, and post-accident conditions, we believe level indication beyond that currently provided is. not required. Upon receiving a hi-level alarm, flow into the Volume Control Tank (VCT) is automatically fully diverted into the hold-up tanks. If.",:a low-level alarm is reached, an alarm alerts the operator to restore level. In the event this effort fails, an emergency lo-lo level alarm is sounded and the refueling water sequence is automatically initiated.
We believe that this range (0-70 inches) is adequate to safely monitor the operation of this tank. In the unlikely event that VCT level indication is lost and the VCT becomes completely full, a safety relief valve (set at 75 psig) will open and the excess water will be discharged into the hold-up tanks. We therefore are submitting a deviation from the Regulatory Guide 1.97 recommendations to monitor Volume Control Tank Level from top to bottom (Deviation No. DV-14). This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.19.
(uu) An analysis previously performed for one of the radiation exposure rate monitors (VRC-301) listed in our original submittal (AEP:NRC:0(720, dated Oc)ober 15, 1985) showed that the exposure rate range of 10 mR/hr to 10 mR/hr was adequate to monitor plant operation in the area in which this monitor is installed.
As part of a general upgrade of area radiation monitors at the Cook Nuclear Plant, monitor numbers NRA-340 and RRA-332 will be replaced.
As previously noted in our submittal AEP:NRC:0773S, Item 3.3.9, concurrent with the upgrade activities, analyses of the type mentioned above was to be performed to determine what range of exposure rate measurement is appropriate for the monitors in the areas where they are to be installed. We expected that the analysis would show that a range less than that recommended by Regulatory Guide 1.97, Rev. 3 would be adequate to safely monitor plant operations in the areas where these monitors are to be installed. This analysis has been completed and the results are explained in footnote (kkk) herein. The upgrading program is scheduled f'r completion at both Unit 1 and Unit 2 by the end of 1989.
(VV) INTENTIONALLY LEFT BLANK (ww) The range for SFR-401 was incorrectly identified as 0-2000 SCFM. The correct range for measurement of this variable is 0-250 SCFM. We believe that this still complies with the Reg. Guide 1.97 Rev. 3 requirements for range for this variable.
(xx) This instrumentation was recently (1985) upgraded. by the addition of a high-range noble gas detector. Based on our recent primary calibratioy analysis, the range gf this instrumentation was determined to be 5.8 x 10 uCi/cc to 1.86 x 10 uCi/cc Xenon-133 dose equivalent. On July 23, 1986 a letter was sent to the NRC (AEP:NRC:0678Y) in which we stated that post-accident conditions would not result in steam jet air ejector exhaust noble gas concentration greater than 2 x 10 uCi/cc. On this basis we requested an exeqytion from the NUREG-0737,Section II.F.l-l upper-rangy requirement of 10 uCi/cc in favor of a more realistic upper range of 10 uCi/cc. We therefore are submitting a deviation from the Regulatory Guide 1.97, Rev. 3 recommendation for this parameter (Deviation No. DV-15).
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ATTACHMENT TO AEP:NRC:0773AB Page 59 It should also be noted that the tag numbers SFR-1900 and SFR-2900 given in our original submittal are incorrect. The correct tag numbers are SRA-1900 and SRA-2900. This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.21.
5 (yy) The range of 3 uCi/cc to 20 x 10 uCi/cc as provided in our submittal was based solely on the monitor's response to Xe-133 and not to the anticipated mixtuie of radioisotopes following a steam generator tube rupture. The lower limit of O.l, uCi/cc of Xe-133 equivalent mixture can be measured. As stated in our September 8, 1986 letter (AEP:NRC:0678Z), when the anticipated mixture of radioisotopes for a steam generator tube rupture is used, the maximum concentration is calculated to be 0.263 uCi/cc Xe-133 equivalent activity. With respect to this upper range limit, an exemption from the NUREG-0737 requirement of 1000 uCi/cc was requested in the September 8, 1986 letter and a 100 uCi/cc value proposed. No response to our request has been received at this writing. We are submitting the same upper limit deviation from the Regulatory Guide 1.97, Rev. 3 guidelines (Deviation No.
DV-16). This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.22.
(zz) It was planned to have available by the end of 1988 a portable gamma-ray spectroscopy system providing the capab'ility for field analysis of plant and environs radioactivity. This equipment was shipped to the Donald C. Cook Nuclear Plant on July 30, 1987 and is now available for use. Information related to this variable was provided in AEP:NRC:0773S Attachment 1, Item 3.3.23
'aaa)
The capability to measure gross activity in the range of 1 uCi/ml - 10 Ci/ml is available; however, this measurement is not normally used to assess core damage. Rather, our initial core damage assessment is done through gamma spectrum analysis of primary coolant. This method provides an isotopic analysis as well as giving an indication of total primary coolant activity.
This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3;24 No. l.
(bbb) Gamma spectrum isotopic analysis is performed in an energy range of 0.050-2.05 MeV. This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.24 No. 2.
(ccc) Boron content is measured in the range of 375-10,000 ppm (see footnote (bb)) This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.24 No. 3.
(ddd) Chloride content in undiluted samples 30 days after an accident is measured in a range of 0.01 to 20 ppm. For diluted samples 1:1000 taken within 4 days of an accident, the range of measurement is 10 to 20,000 ppm.
We are noting a deviation from the Regulatory Guide 1.97, Rev. 3 lower limit of 0 ppm (Deviation No. DV-17). This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.24 No. 4.
(eee) Our range of measurement of pH is 1 to 13. Our original submittal showed a range of 5 to 8 which we believed to be the range of interest for this parameter. This information was provided in AEP:NRC:0773S Attachment 1, No. 5.
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ATTACHMENT TO AEP:NRC:0773AB Page 60 (fff) An exemption from the requirement for taking hydrogen grab samples of containment air was granted via letter from Youngblood (NRC) to Dolan (AEP) dated November 5, 1986. Therefore, we are also submitting a similar deviation with respect to Reg. Guide 1.97 Rev. 3 (Deviation No. DV-18). We do, however, perform continuous monitoring of containment air hydrogen content in the range of 0 to 30 volume percent (see Item C-10) This information was provided in AEP:NRC:0773S Item 3.3.24 No. 6.
(ggg) NUREG-0737 does not require sampling of containment air oxygen content. As noted above, however, we do continuously monitor hydrogen content which mades containment air oxygen content of less concern from the standpoint of potential hydrogen flamability or deflagration. We therefore are submitting a deviation from the Regulatory Guide 1.97, Rev. 3 recommendation to sample for containment air oxygen content (Deviation No.
DV-19). This information was provided in AEP:NRC:0773S Item 3.3.24 No. 7.
(hhh) We do not understand the EGGG request to provide containment'ir gamma spectrum "capacity." Regulatory Guide 1.97, Rev. 3 recommends that the capability be provided to perform an isotopic analysis of containment air.
As recommended by Regulatory Guide 1.97, Rev. 3, gamma spectroscopy techniques are used to provide an isotopic analysis of noble gases in containment air. This gamma spectrum isotopic analysis is performed in a energy range of 0.050 to 2.05 MeV using a Canberra series 85 multichannel analyzer with a Digital PDP 11/24 computer and either a germanium (lithium-drifted) (Ge[Li]) or high-purity germanium (HPGe) detector. This information was provided in AEP:NRC:0773S Attachment 1, Item 3.3.24 No. 8.
(iii) Actual measured range was noted incorrectly in our previous submittal.
Per our response in AEP:NRC:0773S Attachment 1, Item 3.3.11 we have made a minor correction to the actual measured range value. We believe that we still comply with the requirements for range for this variable.
(jjj) Circuits which require the use of indicating lamps for position indications, status indication, etc. will be using existing General Electric ET16 Indicating Lamps for this function. We have been advised by the manufacturer, that these indicating lamps meet their (the manufacturer's) interpretation of IEEE-344-1975. This indicating lamp is a seismically rugged commercial grade device for which comprehensive qualification is not available. Since these lamps are purchased as standard commercial grade material and are not manufactured for a specific order, 10CFR21 can not be applied to these devices. Therefore, we are submitting a deviation from Reg.
Guide 1.97 for this device so we may continue to use and purchase it and its parts for use in monitoring Post Accident conditions (Deviation No. DV-20).
(kkk) ERA-7303 thru 7308, and ERA-8303 thru 8308 have ranges of 0.01 to 1000 R/HR. ERS-7401, 7403, 7404, 8401, ERA-7507, 7601, 7603, 7605 have ranges of
.0001 to 10 R/HR. ERA-8403, 7504, 7508, 7602, 7604 have ranges of 0.001 tg 10 R/HR. These are different than the recommended range of 10 -1 to 10 R/HR and we therefore are submitting a deviation for this variable in regards to range (Deviation No. DV-23). The justification for this request is as follows. With the exception of ERA-7305, 7306, 8305, and 8306, the worst case maximum estimated accident dose rate is less than the upper range limit noted above. The lower upper range limit is used to provide more accurate, useful information and to help prevent false "low fail" alarms.
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ATTACHMENT TO AEP:NRC:0773AB Page 61 In the case of ERA-7305, 7306, 8305, 8306, the worst case maximum estimated accident dose rate is 1730 R/HR which exceeds the upper range limit of 1000 R/HR. However, within one (1) hour, this drops to 573 R/HR which is well within the upper range limit. We believe that because personnel entry in an area where-'exposure may exceed 1000 R/HR (indicated by a "high fail" status indication) is highly unlikely and because the dose rate will quickly fall below the upper range limit of 1000 R/HR (at which time a quantitative indication will again be available) the range of 0.01 to 1000 R/HR is adequate. Again, using this range will provide more useful information and help prevent false "low fail" alarms.
(ill) If CCW water temperature is not available, adequate CCW cooling can be verified by monitoring CCW flow and RHR Inlet & Outlet temperatures, all of which are qualified (or planned to be qualified) for the intended purpose.
Therefore, because of the availability of suitable diverse indications, environmental qualification of instrumentation monitoring this variable is not required. We are submitting a deviation with respect to Reg. Guide 1.97, Rev. 3 recommendations for this variable for environmental qualification, (Deviation No. DV-25).
(mmm) All equipment when required to be used, is located in a mild environment except for cables serving the following instruments. For these instruments the cables pass through harsh environment areas. Equipment qualification is not required except for these cables. The instruments served by these cables are: 2-IFI-310, 2-IFI-311, 2-IFI-320, 2-IFI-321, 2-CFI-419, 2-CLI-114, and 1-CLI-114.
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