ML20140E062
| ML20140E062 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 01/27/1986 |
| From: | Williams J TOLEDO EDISON CO. |
| To: | Stolz J Office of Nuclear Reactor Regulation |
| References | |
| RTR-REGGD-01.097, RTR-REGGD-1.097 1232, TAC-51084, NUDOCS 8602030172 | |
| Download: ML20140E062 (19) | |
Text
_
TOLEDO
%ss EDISON Docket No. 50-346 JOE WILUAMS. JR.
License No. NFP-3 S= va *"a'* -'*'*-
[419)249-2300
[419)249-5223 Serial No. 1232 January 27, 1986 Mr. John F. Stolz, Director PWR Project Directorate No. 6 Division of PWR Licensing -B United States Nuclear Regulatory Commission Washington, D.C.
20555
Dear Mr. Stolz:
This is in response to your letter dated October 16, 1985 (Log No. 1838) concerning conformance to Regulatory Guide 1.97 by the Davis-Besse Nuclear Power Station, Unit No. 1.
That letter transmitted an interim report on the NRC's evaluation of Davis-Besse's instrumentation as compared to the recommendation of Regulatory Guide 1.97, Revision 3 and requested a response to the open items identified in the report.
In the attachment to this letter, Toledo Edison has provided a response to all items except 3.3.30/4.17, which will be provided by April 15, 1986. Modifications committed to by this response will be made in accordance with our Inte-grated Implementation Plan.
Very truly yours, J a Lu W J e / m JW:MLB: GAB Attachment cc: DB-1 NRC Resident Inspector 8602030172 060127 PDR ADOCK 05000346 Ao - a caurcurino (n.
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. 3.3.4/4.1 RCS Pressure Regulatory Guide 1.97 recommends instrumentation for this variable with a range from 0 to 3000 psig. The licensee has provided instrumentation with a range from 0 to 2500 psig. They state that no new operator action would
- be taken or performed with an extended range from 2500 'to 3000 psig; that all operator actions occur within the provided 0-2500 psig range.
I Regulatory. Guide 1.97 states that it is essential that the range be sufficient to keep-the instruments on scale. The licensee has not shown that this is the situation for all design basis accident scenarios.
Therefore, we cannot concur with this deviation. The licensee should either show that the supplied range encompasses all anticipated RCS pressures or provide the recommended range.
Response
Chapter 15 of our Updated Safety Analysis Report (USAR) pertains to Accident Analysis.
In section 15.4, for Class 3 - Design Basis Accidents (DBA), it shows that the Reactor Coolant System (RCS) pressure would not exceed 2500 psi..Likewise in section 15.3, for Class 2 - Events Leading to Small to Moderate Radioactive Releases at Exclusion Area Boundary, show that RCS pressure would not exceed 2500 psi. However in section 15.2, for Class 1 - Events Leading to No Radioactive Release at Exclusion Area Boundary, there are five scenarios in which RCS pressure would exceed 2500 psi but do not exceed the. code pressure limit of 2750 psi and they are as follows:
USAR Section Title 15.2.1 Uncontrolled Control Rod Assembly Group Withdrawal from a Subcritical Condition (Startup Accident), Fig.
15.2.1-1 & 15.2.1-2.
15.2.2 Uncontrolled Control Rod Assembly Group Withdrawal at Power, Fig. 15.2.2-8.
15.2.8 Loss of Normal Feedwater, Fig. 15.2.8-1.
15.2.8 Loss of Normal Feedwater with Offsite Power Available, Fig. 15.2.8-5.
15.2.8 Loss of Normal Feedwater with Loss of Offsite Power at Trip, Fig. 15.2.8-11.
Even though the existing instrumentation is adequate for all design basis
- accident scenarios and that no new operator actions would be taken or performed in the extended range, we will provide the extended range to comply with Regulatory Guide 1.97 to ensure that the instrumentation will remain on scale for all anticipated RCS pressures.
. 3.3.7/4.2, 4.3, 4.4 Containment Effluent Radioactivity -
Noble Gases from Identified Release Points.
Effluent Radioactivity -
Noble Gases (from Buildings or Areas Where Penetrations and Hatches are Located)
Radiation Exposure Rate -
(Inside Buildings or Areas Where Access is Required)
The information on these variables is missing from the licensee's submit-tal.
The licensee should provide the information required by Section 6.2 of NUREG-0737, Supplement No. I for these variables, identify any devia-tions from Regulatory Guide 1.97 and justify any deviations.
Response
These three items; Containment Effluent Radioactivity, Effluent Radioac-tivity and Radiation Exposure Rate are included in the Regulatory Guide 1.97 submittal on pages 8 & 9 of the Inventory & Compliance Table. The instru-ment nomenclature of the Inventory & Compliance Table is different from that stated in Regulatory Guide 1.97.
The table below provides a cross refer-ence between Regulatory Guide 1.97 and TED nomenclature.
Reg. Guide 1.97 Nomenclature TED Nomenclature 1.
Containment Effluent Radioactivity -
1.
Containment Purge Noble Gases from Identified Release Points.
2.
Effluent Radioactivity - Noble Gases 2.
Reactor Shield Building (from Buildings or Areas Where Annulus / Auxiliary Penetrations and Hatches are Located)
Building Effluent 3.
Radiation Exposure Rate - (Inside 3.
Area Radiation Monitors Buildings or Areas Where Access is Required)
. 3.3.8/4.5 Residual Heat Removal (RHR) Heat Exchanger Outlet Temperature Regulatory Guide 1.97 recommends Category 2 instrumentation for this variable. The licensee has provided instrumentation that, except for environmental qualification, is Category 2.
The licensee states that Category 3 instrumentation is acceptable since an accident signal causes maximum cooling to take place, i.e.,
the heat exchanger bypass valve is automatically shut, diverting full flow through the heat exchangers.
Environmental qualification has been clarified by the Environmental Qualification Rule, 10 CFR 50.49.
We conclude that Regulatory Guide 1.97 has been superseded by a regulatory requirement. Any exception to this rule is beyond the scope of this review and should be addressed in accor-dance with 10 CFR 50.49.
Response
The decay heat system is utilized to cool down the reactor coolant system (RCS) under normal conditions. The operator uses RCS Tg&TC to monitor the cooldown rate. The decay heat cooler inlet and outIet temperature can be used to monitor the cooler performance.
For DBA's (small to large LOCA) the decay heat system is utilized for long-term core cooling when lined up to recirculate the sump contents through the Low Pressure Injection / Decay Heat (LPI/DH) lines. During the initial stages of the event, when Safety Features Actuation System (SFAS) level 2 actuates (RCS pressure < 1600 psig or containment pressure > 18.4 psia.), the Component Cooling Water (CCW) heat exchangers Service Water (SW) outlet valves are tripped wide open providing maximum SW cooling to the CCW system. Upon a SFAS level 3 actuation, (RCS pressure <450 psig or containment pressure > 18.4 psia), the decay heat removal coolers CCW outlet valves are tripped wide open thereby providing maximum CCW cooling to the decay heat removal system. Thus via automatic initiation of SEAS, maximum cooling is provided to the decay heat removal coolers which in turn provide maximum cooling to the decay heat removal system. The inlet and outlet temperatures of the decay heat removal coolers can be monitored, however, no operator action would be taken based on these indicators since maximum cooling is already being supplied to the coolers.
Verification of decay heat removal flow and core exit thermocouple temper-ature, which are both Category 1, are monitored to ensure that the decay heat removal system (including the decay heat removal coolers) is performing its intended function.
With the Category 1 indication provided to the operator, the overall intent of Regulatory Guide 1.97 is met to ensure reactivity control and core cooling with respect to the decay heat remov.a. system.
Based on this consideration along with the fact no operator actions could or would be taken based on decay heat removal cooler inlet or outlet temperature indication, Category 3 is appropriate for these indications.
. 3.3.9/4.6 Accumulator Tank Level and Pressure
. Regulatory Guide 1.97 recommends Category 2 instrumentation for this variable.with a range of 10 to 90 percent volume and 0 to 750 psig. The licensee has identified deviations in this instrumentation: a range of 0 to 14 ft. level and Category 3 pressure instrumentation with a range of 0 to 700 psig.
The licensee has not provided justification for the deviation in level range nor stated the extent of the deviation. The licensee should identify and justify this deviation in range.
Table 6.11 of the Final Safety Analysis Report (FSAR, Reference 6) indi-cates that the accumulator pressure is manually controlled at 600 t 15 psig.
Further, there are relief valves that relieve pressure in excess of 700 paig, the tank design pressure. Therefore, we find the range of the pressure instrumentation acceptable.
The accumulators are passive, and the licensee indicates that there are no manual actions taken as a result of the pressure indication. All operator actions are done based on pressurizer level. Thus, the licensee concludes that Category 3 instruments are adequate for backup instrumentation.
We find' the O to 700 psig Category 3 instrumentation is satisfactory for the pressure portion of this variable.
Response
The Accumulator (Core Flood) Tank Level of 0 to 14 ft. corresponds to 2.4 to 84.1% volume of the linear portion of the tank. Davis-Besse Technical Specification Section 3.5.1.b requires the volume of the Core Flood Tank to be maintained between 7555 and 8004 gal. of borated water and the tank water volume is verified at least once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (Technical'Specifi-cation Section 4.5.1.a.1) as is the tank cover pressure.
In accordance with the operating procedure SP 1104.1, " Core Flooding System", the Core Flood Tanks are maintained at 13.3 ft as normal tank level which corre-sponds to a normal water volume of 1040 ft.a or 7800 gal. (total tank volume = 1410 ft.8).
Therefore, we conclude that the tank level range of
-0 to 14 feetois sufficient to ensure compliance with Davis-Besse Technical Specifications and Regulatory Guide 1.97.
. 3.3.11/4.7 Pressurizer Level Regulatory Guide 1.97 recommends instrumentation for this variable with a range from the top to the bottom of the pressurizer vessel. The licensee states that this range is not met.
The licensee does state that the range covers any design basis transients, and that the level indication will remain on scale.
Based on the licensee's statement, we find that the range is adequate.
However, the licensee should state the range per the requirements of Section 6.2 of NUREG 0737, Supplement No. 1.
Response
The Control Room indication for the pressurizer level is 0 to 320" which is equivalent to 0.7 to 78.2% volume of the linear portion of the pres-surizer. Normal operating level of the pressurizer is 200".
Since our initial submittal / response to Regulatory Guide 1.97 and subse-quent B&W Owner's Group meetings, it has been determined that the pressur-izer level response was in error. The error is that the pressurizer level indication will not remain on scale for all design transients as previous-ly stated.
For anticipated transients such as decreasing feedwater temperature, excessive main feedwater flow, loss of main feedwater flow, decreasing steam flow, small steam leaks, loss of external load, loss of off-site power, loss of condenser vacuum and small steam generator tube leaks, the existing range for the pressurizer level is sufficient such that indicated level should remain on-scale.
For severe transients (accidents) such as steam line break, steam genera-tor tube rupture and many small break LOCAs, the pressurizer may void.
Following SFAS actuation of the HPI system, actions can be taken as necessary to stabilize the plant.
Those actions are based on subcooled margin, pressurizer level and RCS pressure. Pressurizer level is utilized to throttle High Pressure Injec-tion / Makeup (HPI/MU) flow to keep the pressurizer level near the nornal operating level when the subcooled margin exists. This is to preclude the undesirable opening of the PORV if the pressurizer level becomes too high or a loss of subcooled margin if the pressurizer becomes too low.
HPI/MU flow must also be throttled to prevent overpressurizing the RCS when the subcooled margin exists by keeping RCS pressure within the pressure - temperature limits.
If MU is not available, which it need not be for DBA's since the MU' system is not safety grade and not required for accident mitigation, HPI/LPI flow would still need to be throttled based on pressurizer level to maintain the subcooled margin and to keep RCS pressure within the temperature - pressure limits.
Challenging the PORV is not possible using HPI/LPI flow due to not having high head HPI pumps.
. For the case of a total loss of feedwater, the pressurizer will go solid unless either main or auxiliary feedwater is restored to the steam gener-ators within about 15 minutes. Actions taken are dependent on when feedwater is restored, subcooling margin, RCS pressure, and pressurizer level.
In general, for severe transients or accidents the pressurizer will either void or go solid. A voided pressurizer will cause indicated level to go off-scale low followed by a rapid decrease in RCS pressure to saturation.
A solid pressurizer will cause indicated level to go off-scale high accompanied by; high RCS pressure, possible large and rapid changes in RCS pressure, PORV and pressurizer safety valve actuation. All of these indications are available in the control room and are Category 1.
Based on this information the existing range of pressurizer level indica-tion is sufficient for anticipated transients. For severe transients or accidents, indicated pressurizer level will go off-scale high or low due to the pressurizer going solid or voiding and, as a result, top to bottom instruments would provide no significant additional information.
In these cases, subcooling margin, RCS pressure, PORV status and pressurizer safety valve status are monitored to determine actions to be taken.
. 3.3.12/4.8 Pressurizer Heater Status Regulatory Guide 1.97 recommends instrumentation to monitor the current drawn by the pressurizer heaters. The licensee's instrumentation consists of on/off indication of the redundant emergency pressurizer heaters. The licensee indicates that the control of these heater banks is either on or off, and therefore the instrumentation is appropriate.
Section II.E.3.1 of NUREG 0737 requires a number of the pressurizer heaters to have the capability of being powered by the emergency power sources.
Instrumentation is to be provided to prevent overloading a diesel generator. Also, technical specifications are to be changed accordingly. The Babcock and Wilcox Standard Technical Specifications, Section 4.4.3.2, require that the emergency pressurizer heater current be measured quarterly. These emergency power supplied heaters should have the current instrumentation recommended by Regulatory Guide 1.97.
Response
The primary area of concern of pressurizer heater status is to prevent overloading the diesel generators by providing adequate instrumentation.
The two essentially powered heater banks (126 KW each) are manually loaded onto the diesel generator buses via control switches located in the control room. The on/off status of the two heater banks is provided by these switches.
In addition to the breaker status (on/off) of the pres-surizer heaters, the following instrumentation is monitored in the control room to preclude overloading the diesel generators when manually loading the heater banks:
Diesel Generator 1 & 2 Voltmeters, Ammeters & Wattmeters 4160 Essential Bus C1 & D1 Voltmeters & Ammeters Voltmeters & Ammeters on feed to 4160/480 redundant transformers Essential 480 Bus E1 & F1 Voltmeters The essentially powered pressurizer heater banks are powered from MCC's E12A & F12A wlich are fed from Bus E1 & F1, respectively. Thus, adequate instrumentation has been provided to preclude overloading the diesel generators.
Technical Specifications for the essential pressurizer heaters have previously been addressed in accordance with Section II.E.3.1 of NUREG 0737. TED responded to the NRC letter dated July 2, 1980 (Log No. 581) concerning model technical specifications by Lesson Learned Category "A" requirements of NUREG 0578 in a submittal dated September 16, 1980 (Serial No. 650). On March 24, 1981 (Log No. 681), Amendment 37 to Davis-Besse Operating License, the NRC concurred that existing Technical Specification comply with Category "A" requirements.
. 3.3.15/4.9 Steam Generator Level Regulatory Guide 1.97 recommends Category 1 instrumentation with a range from tube sheet to separators. This is for U-tube steam generators.
The Davis-Besse steam generators are of once-through design, and as such the heat exchange area would be described as tube sheet to tube sheet. The licensee has Category 3 instrumentation that measures from tube sheet to tube sheet (0-600 in.) and Category 1 instrumentation that reads 0 to 250 in.
(It appears that the zero for these two sets of instrumentation is not the same.)
The licensee justifies this deviation based on the auxiliary feedwater control, which is used to mitigate the effects of a small break LOCA, using the narrow range instruments (the level is maintained between 33 and 96 in.) The Category 3 wide range channels are considered backup instru-ments by the licensee. The licensee notes, however, that a study regard-ing possible additional steam generator instrumentation is in progress.
This is in conjunction with the steam feedwater rupture control system trips.
The licensee has not shown that the narrow range instruments will remain on scale for every analyzed transient or accident. Therefore, the narrow range is not acceptable. The license has not shown that the Category 3 wide range instruments will remain operational for every analyzed tran-sient or accident.
We conclude that the instrumentation provided is not acceptable for this variable. The licensee should provide the modifica-tions necessary to provide wide range Category 1 steam generator level instrumentation.
Response
The steam generator (SG) level instrumen ation at Davis-Besse consists of the following:
One (1)
SG full range /SG with indication of 0" to 650" Two (2)
SG operate levels /SG with indication of 0" to 100% which corresponds to 96" to 388" Two (2)
SG start-up levels /SG with indication of 0" to 250" & used for Auxiliary Feed Pump Turbine (AFPT) control (Category 1)
Four (4) SG start-up levels /SG with indication of 0" to 400" & used for Steam Feedwater Rupture Control System (SFRCS) trips (Category 1)
The actual distance from tube sheet to tube sheet is 625".
The lower source tap for the full range and all start-up level instrumentation is located 6" above the lower tube sheet.
Therefore the zero reference for these instruments is the same, i.e., 6" above the lower tube sheet. The upper source tap for the start-up level instrumentation for AFPT control and indication is located 394" above the lower tube sheet or 388" above the lower source tap.
The SG operate level instrumentation lower source tap is located 96" above the start-up level and full range lower source tap.
The operate level upper source tap is the same as that for the upper
. source tap of the start-up range level instrumentation for AFPT control.
These taps provide for a calibratable range of 96" to 388".
The SFRCS start-up level instrumentation upper source tap is the same as that for the operate and start-up level for AFPT control. The SG full range level instrumentation upper source tap actually penetrates the upper tube sheet and is configured such that the calibratable range of the instrumentation is 0" to 641".
A sketch has been provided for clarification on page 10.
The SG full range instrumentation is utilized when placing the SG's in a wet lay-up condition when the unit is shutdown and also as a back-up to the operate and start-up level.
In reviewing the USAR Chapter 15, Design Basis Accidents, the abnormal and emergency operating procedures, the full range level instrumentation is not utilized and therefore is not required to mitigate the consequences of a design basis accident. Therefore Category 3 instrumentation is appropriate for the SG full range instrumentation.
The SG operate level instrumentation is utilized during normal plant operation, per the abnormal operating procedure for SG overfill and per the emergency procedure for Steam Generator Tube Rupture (SGTR). During the abnormal and emergency conditions, the SG operate level would be used in conjunction with the AFPT start-up level indication since this Category 1 equipment's range (indicated) is only 0 to 250".
During the Detailed Control Room Design Review (DCRDR), the need to provide the operators with SFRCS start-up level indication (0-400") in the control room was identi-fled. Presently, SFRCS start-up level indication is available only in the control room cabinet room. A facility change request has been written to provide the SFRCS start-up level indication and when implemented, will resolve the two DCRDR concerns and eliminate the need to monitor the SG operate level.
Even with the present configuration, if no operator action were to be taken based on the SG operate level, SFRCS would still be actuated on high SG 1evel at 280" via the Category 1 SFRCS start-up level instrumentation.
The SFRCS high level trip actuates, among other items, AI)[ which in turn is controlled via the Category 1 SG start-up level instrumentation for AFPT control.
Based on the above considerations along with the review of USAR Chapter 15, Design Basis Accidents, abnormal and emergency proce-dures, the SG operate level instrumentation need not be utilized and therefore is not required to mitigate the consequences of a design basis accident. Therefore, Category 3 instrumentation is appropriate for the SG operate range instrumentation.
1 Further justification exists for Category 3 full range and operate range SG 1evel instrumentation in that procedure AB 1203.04, "Depressurization of the RCS Using Safety Grade Equipment", provides a path to cold shutdown using fully qualified safety grade equipment (Category 1).
The Category 1 SG start-up level instrumentation is not required for every analyzed transient or accident. For those analyzed transients or acci-dents where start-up range level instrumentation is utilized, the level instrumentation will remain on scale and be operatiotal.
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- s 3.3.17/4.10 Safety / Relief Valve Positions or Main Steam Flow Regulatory Guide 1.97 recommends Category 2 instrumentation for this variable. The licensee states that the position of the atmospheric vent valves (AVV) and the main steam safety valves (MSSV) is not monitored and that monitoring is not required to mitigate the consequences of a design basis accident. AVV position is indicated in the control room via indict-ing lights on the safety features actuation system panel and the hand / auto stations indicators for the AVV's which are used to reduce and maintain the steam generator pressure below the MSSV setpoints.
In addition, the licensee states that the sound emitted from the valves provides an audible 4
indication to the operators when either the MSSV's or AVV's lift.
t The licensee has not verified Category 2 instrumentation for the AVV's, the MSSV's nor the alternate main steam flow. We conclude the licensee has not provided acceptable instrumentation for this variable. The licensee should provide the recommended instrumentation.
Response
TED will comply with the above and provide Category 2 position indication for the AVV's and MSSV's.
During the Detailed Control Room Design Review (DCRDR), the AVV and MSSV position indication was identified as Inadequate Information. TED will coordinate this modification with the display study
' established by the DCRDR.
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. 3.3.19/4.11 Containment Spray Flow Regulatory Guide 1.97 recommends Category 2 instrumentation for this variable. The licensee indicates that the flow is determined by the status lights for the pumps and the status lights for the valve position.
These are Category 1.
The flow meters are considered by the licensee to be backup Category 3 indication.
The status lights are not acceptable for determining flow. The licensee should identify any specific deviations from the Category 2 recommenda-tions for the flow meters, and either provide justification for the deviation or upgrade the instrumentation to Category 2.
Response
The specific deviations from the Category 2 recommendations of the Con-tainment Spray Flow Strings is identified on page 7 of the Inventory and Compliance Table of our Regulatory Guide 1.97 submittal.
Specifically, the flow transmitters are not environmentally qualified for a harsh environment.
The containment spray system is automatically actuated as follows:
the containment spray valves are automatically lined up (opened) upon a Safety Features Actuation System (SFAS) level 2 actuation, i.e. containment pressure has increased to 18.4 psia or reactor coolant pressure has decreased to 1600 psig. The containment spray pumps are automatically started upon receiving a SFAS level 4 actuation signal, i.e.,
containment pressure has increased to 38.4 psia. Thus the containment spray system is initialized based upon containment pressure and as such, containment pressure is the key parameter to ensure containment integrity.
Containment integrity is one of four parameters to be maintained post accident per Regulatory Guide 1.97.
By initiating the containment spray system, the containment atmosphere will be cooled thus lowering the pressure and in doing so, ensuring containment integrity. Therefore, with Category I containment pressure indication along with Category 1 contain-ment spray pump and valve status, containment cooling is assured. Thus the containment spray flow indication becomes useful backup alternate indication to the operators and as such appropriately classified as Category 3.
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. 3.3.20/4.12 Containment Atmosphere Temperature Regulatory Guide 1.97 recommends Category 2 instrumentation for this variable with a range from 40 to 400*F.
The licensee hes supplied Catego-ry 3 instrumentation with a range of 0 to 300*F.
Their justification for this deviation is that the primary variable required to show accident mitigation and containment integrity is reactor building pressure which is j
a Category 1 variable. They consider the atmosphere temperature a Catego-ry 3 variable.
1 The containment atmosphere temperature directly indicates the accomplish-ment of a safety function (containment cooling), and is, therefore, a key variable. As such, Category 2 requirements should be met by the licensee.
The licensee indicated that the maximum containment temperatures will be less than 285 F.
Therefore, the range of 0 to 300*F is acceptable.
Response
The installed instrumentation for containment atmosphere temperature meets the requirements of Regulatory Guide 1.97 Category 2 with the exceptions. '
as listed on the Inventory & Compliance Table pg. 7; environmental quali-fication, range and the associated QA requirements for environmentally qualified equipment. Justification for the range was acceptable. The instrumentation was addressed per 10CFR50.49 (NUREG 0588) and was exempt-ed.
This exemption was transmitted in our EQ submittal dated October 5, 1981 (Serial No. 748) and accepted in NRC Safety Evaluation Report (SER) dated January 31, 1985 (Log. No. 1684).
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We concur that containment atmosphere temperature directly indicates the accomplishment of a safety function (containment cooling). However, due to thermodynamic equations of state for ideal gases, containment pressure is also a direct indication of containment cooling.
Past experience and monitoring with permanently installed additional temperature equipment at various elevations has shown during normal operating conditions that containment temperature varies from location to location and with elevation.
This fact, coupled with accident conditions, could lead to erroneous, conflicting information even if the temperature equipment were Category 1.
Therefore containment pressure is utilized for accident mitigation since pressure will be constant throughout the containment volume.
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. 3.3.21/4.13 Containment Sump Water Temperature Regulatory -Guide 1.97 recommends Category 2 instrumentation for this variable with a range of 50 to 250*F.
The licensee does not have direct instrumentation for this variable. Their justification is that monitoring the sump temperature is not needed to assure that net positive suction head (NPSH) exists for the decay heat pumps or the containment spray pumps. They state that containment sump water temperature is not required to mitigate the consequences.of any design basis accidents. Additionally,
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the sump water temperature can be measured by use of the decay heat removal heat exchanger (cooler) inlet temperature when recirculating the 1
sump contents.
We find this alternative acceptable for this variable; however, the licensee should verify that this instrumentation meets Category 2 recommendations.
Response
Refer to the response for Residual Heat Removal (RHR) Heat Exchanger Outlet temperature (page 3 of this response, item 3.3.8/4.5) which ad-dresses both the decay heat cooler inlet and outlet temperatures.
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. 3.3.22/4.14 Makeup Flow-In Regulatory Guide 1.97 recommends Category 2 instrumentation for this variable with a range of 0 to 110 percent of design flow. The licensee indicates that their instrumentation does not comply with this range, though the actual range is not identified. An on going review is to established a new range.
The licensee should commit to meet or exceed the range recommended by the regulatory guide.
The licensee indicates that this instrumentation deviates from the Catego-ry 2 requirements in that it is not environmentally qualified. Environ-mental qualification has been clarified by the Environmental Qualification Rule, 10 CFR 50.49.
We conclude that Regulatory Guide 1.97 has been superceded by a regulatory requirement. Any exception to this rule is beyond the scope of this review and should be addressed in accordance with 10 CFR 50.49.
Response
TED presently has a 0 to 160 gpm Makeup Flow-In indication available to the operators in the control room which corresponds to O to 115% design flow. The range of this indication is adequate for operation of one (1)-
makeup pump and meets the range requirements of the regulatory guide.
However, when the second makeup pump is started, which is normally done after a reactor trip, the makeup flow indication is pegged high. The second makeup pump is started in order to maintain pressurizer level which is Category 1.
TED will provide the appropriate makeup flow indication range to adequately cover the two pump operation and which will meet the range requirements of the regulatory guide for two pump operation. TED will also provide the appropriate environmentally qualified equipment for Category 2 requirements even though the MU system is not safety grade and not required for accident mitigation.
. 3.3.23/4.15 Letdown Flow-Out Regulatory Guide 1.97 recommends Category 2 instrumentation for this variable. The licensee, has provided instrumentation that, except for environmental qualification, is Category 2.
The licensee state that this variable is not required in the mitigation of an accident, and that the letdown system is isolated by accidents requiring containment isolation.
Environmental qualification has been clarified by the Environmental Qualification Rule, 10 CFR 50.49.
We conclude that Regulatory Guide 1.97 has been superceded by a regulatory requirement. Any exception to this rule is beyond the scope of this review and should be addressed in accor-dance with 10 CFR 50.49.
Response
Letdown flow was previously addressed per 10 CFR 50.49 and was exempted, as specified in our EQ submittal dated October 5,1981 (Serial No. 748),
for the following reason:
"This instrument is exempt from qualification because it is not w
considered to be safety-related.
It functions to transmit flow
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signals of the non-safety-related letdown system for supplementary display information only. Alternate letdown paths are available and letdown flow can be verified through the use of the safety-related pressurizer level indication. The operator is aware of the instru-ment's non-safety-related status and therefore will not be misled by erroneous indication. Since the instrument does not provide a control function, accident mitigation will not be affected by its failure.
Based on the exemption, which was accepted in the NRC Safety Evaluation Report (SER) dated January 31, 1985 (Log. No. 1684), along with the fact that for accidents requiring containnent isolation the letdown system is isolated, Category 3 instrumentation is appropriate for this variable.
. 3.3.26/4.16 Component Cooling Water Flow to ESF System Regulatory Guide 1.97 recommends Category 2 flow instrumentation to monitor the operation of the component cooling water system. The licensee i
does not have instrumentation for this variable, citing a study that determined that this variable is not required to mitigate the consequences of a design basis accident.
There is alternate instrumentation consisting of pump motor status (on/off) and system valve position.
t We do not concur with the licensee. The alternate instrumentation will not determine proper system operation should there ce flow blockage or a pipe rupture. The licensee should supply the recommended instrumentation.
Response
The component cooling water (CCW) system supplies cooling water to various j
systems and numerous pieces of equipment. Due to the wide range of design flows to various components under various plant conditions, CCW flow indication would not necessarily be representative of overall CCW system perfo rmance. In addition to the Category 1 pump motor status and critical system valve position, each system or piece of equipment utilizing CCW has its own monitoring instrumentation, i.e. high temperature alarms and indication, low CCW flow indicators (local) and alarms, to indicate its operating status thus implying status of the CCW being supplied to that system or equipment.
In addition to the local and remote indications and alarms, interlocks have been provided, such as high temperature or low CCW flow, for system and equipment protection. The Category into which this monitoring instrumentation falls is commensurate with that systems or equipment importance.
Flow blockage or pipe rupture, depending on the location, would be indi-cated by the system or equipment monitoring instrumentation located downstream of the blockage or rupture. A CCW pipe rupture would also be indicated via control room CCW surg'e tank level indication and associated
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alarms.
In addition to the CCW surge tank level indication and associated alarms, interlocks are provided, based on CCW surge tank level, to auto-matically isolate various portions of the CCW system. When the level drops to 45 inches, the CCW to the Auxiliary Building non-essential equipment will be isolated in an attempt to isolate the leak.
If the level continues to fall below 35 inches, except for the essential lines, the CCW system will be isolated in an attempt to isolate the leak.
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- 3.3.30/4.17 Noble Gas Vent from Steam Generator Safety Relief Valves or Atmospheric Dump Valves Regulatory Guide 1.97 recommends this Category 2 instrumentation for the variable. The recommended parameters to be monitored for this variable are noble gas, duration of release in seconds and mass of steam per unit time.
In regard to this variable, the licensee states that the position indica-tion of the atmospheric vent valves (AVV) and the main steam safety valves (MSSV) is not monitored and that monitoring is not required to mitigate the consequences of a design basis accident. AVV position is indicated in the control room via indicating lights.
In addition, the licensee states that the sound emitted from the valves provides an audible indication to the operators when either the MSSV's or AVV's lift.
Dose estimate proce-dures are used to quantify noble gas /radioiodine releases from the AVV's, MSSV's and auxiliary steam turbine exhaust utilizing the currently in-stalled main steamline radiation monitors or the steam jet air ejector radiation monitor.
We find this arrangement unacceptable for this variable. First, the licensee should identify the range of the main steamline monitors, verify that the range is adequate and that the instrumentation is Category 2.
Second, the licensee should indicate how the duration of the release and the mass of steam per unit time is determined. Third, the licensee should show that the results derived from this method are within an acceptable tolerance from the actual release.
Response
This response will be provided by April 15, 1986.
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