ML20040E763
| ML20040E763 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 01/21/1982 |
| From: | Davidson D CLEVELAND ELECTRIC ILLUMINATING CO. |
| To: | Tedesco R Office of Nuclear Reactor Regulation |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.K.1, TASK-2.K.3.03, TASK-2.K.3.13, TASK-2.K.3.15, TASK-2.K.3.16, TASK-2.K.3.17, TASK-2.K.3.18, TASK-2.K.3.21, TASK-2.K.3.25, TASK-2.K.3.30, TASK-2.K.3.31, TASK-2.K.3.45, TASK-TM NUDOCS 8202050329 | |
| Download: ML20040E763 (23) | |
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' T!!E CL EVELAND ELECTRIC ILLUMIN ATING COMPANY ILLUMINATING BLDG. e PUBLIC SOUARE e CI EVELAND. OHIO 44101 e TELEPHONE (216) 6231350 e Mall ADDRESS:
P. O. BOX 5000 Semng The Best Location in the Nation D;lwyn R. Davidson A
vlCE PRESIDENT f) f SYSTE M ENGINEERING AND CONSTRUCTION
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RECEEyfiD 9
January 21, 1982 p.
FEB 419ggs,."7 10 Mr. Robert L. Tedesco c r.qm 7gff E
NZU anp Assistant Director of Licensing I5*
Division of Licensing g
U. S. Nuclear Regulatory Commission Washington, D. C.
20555 Perry Nuclear Power Plant Docket Nos. 50-440; 50-441 Response to Request for Additional Information -
Reactor Systems
Dear Mr. Tedesco:
This letter and its attachment is submitted to provide draft responses to the concerns identified in your letter dated November 20, 1981 in regard to reactor systems.
It is our intention to incorporate these responses in a subsequent amendment to our Final Safety Analysis Report.
Very Truly Yours, h
l Dalwy". Davidson Vice President System Engineering and Construction DRD: mlb Attachment ec:
Jay Silberg, Esq.
M. D. Houston NRC Resident Inspector pool 8202050329 820121 hi PDR ADOCK 05000 j
A
d 440.25 The minimum design water level elevations in the suppression (6.3) pool used for calculating NPSH for ECCS pumps is not the same for all the pumps.
RHR - El. 589'-0" (P5.4-42) i HPCS - El. 593'-3" (P6.3-12a)
LPCS - El. 589'-6" (P6.3-18)
Explain why different elevations are used?
In calculating HPCS pump NPSH, two different flow rates, i.e.,
7655 gpm and 7800 gpm (P6.3-12a) were used; 7655 gpm pump design maximum run-out flow was used to calculate NPSH when pump suction is from the suppression pool, and 7800 gpm was used in calculating NPSH when pump suction is from the condensate storage tank. Explain why two different flow rates were used to calculate the pump NPSH7
Response
The NPSH calculations for ECCS pumps are based on a minimum suppression pool drawdown elevation of 589'-0".
4 The NPSH calculations for the HPCS pump are based on a 7800 gpm pump design maximum run-out flow.
Refer to revised Section 6.3.
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The HPCS system is capable of delivery r"ated flow into the reactor vessel within 27 seconds following receipt of an catomatic initiation signal.
1 When a high water level in the reactor vessel is signaled, the HPCS is
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automatically stopped by a signal to the injection va,1ve to close, unless a high drywell pressure signal exists.
If a high drywell pressure signal exists in conjunction with a high reactor water level signal, HPCS injection will continue until manually stopped. The HPCS system also serves as a backup to the RCIC system in the event the reactor becomes isolated from the main condenser during operation and feedwater flow is lost.
If normal auxiliary power is not available, the HPCS pump motor is driven by its own onsite power source. The HPCS standby power source is discussed in Section 8.3.
1 The HPCS pump head flow characteristic used in LOCA analyses is shown in Figure 6.3-4.
When the system is started, initial flow rate is established by primary system pressure. As vessel pressure decreases, flow will increase.
When vessel pressure reaches 200 psid (differential pressure between the reactor vessel and the suction source) the system reaches rated core spray flow. The HPCS motor size is based on peak horsepower requirements.
The elevation of the HPCS pump (suction nozzle centerline at elevation 571'-7") is sufficiently below the water level of both the condensate storage tank and the suppression pool to provide a flooded pump suction.
The minimum NPSH requirement specified by the manufacturer is five feet at a
\\0 location two feet above the pump mounting flange for pump suction from both d
the suppression pool and condensate storage tank.
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b NPSH requirements are met by providing adequate suction head and suction line size. The available NPSH, calculated in accordance with Regulatory Guide 1.1, is based on the follcwing design tenditions:
1 a.
Pump design maximum runout flow of 7800 gpm.
6.3-12
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b.
Containment at atmospheric pressure'.
Condensate Storage Tank (CST) at atmospheric pressure.
c.
Maximum suppression pool temperature of 212 F.
Maximum CST temperature of 120 F.
a d.
CST at automatic transfer water level of 622'-6".
Suppression pool at minimum drawdown water level of 589'-0".
e.
HPCS pump suction piping arrangement as shown on Figure 6.3-7.
f.
Suction strainer 50 percent clogged for a 2.31 f t. pressure drop.
k The available NP3H at the time immediately preceding automatic transfer from A
the condensate storage tank to the suppression pocl is approximately 56 feet, 6
based on the above design conditions.
3 The available NPSH with suction taken from the suppression pool is approximately 12 feet, based on the above design conditions.
The final design calculations, based on the Regulatory Guide 1.1 position, indicate an available NPSH for the HPCS system sufficient to ensure pump performance capable of accomplishing the required safety functions in both modes.
For pre-operational testing the HPCS pump is provided with a test line back to the condensate storage test.
During pre-operational testing the HPCS pump will be tested for flow capacity and suction pressure, since the condensate storage tank is pumped down to the low level transfer point. From this test the flow capacity and NPSH will be compared to the vendor data, and visual observations will be made for-vortexing.
A motor operated valve is provided in the suction line from the suppression pool. The valve is located as close to the suppression pool penetration as p ra ctical. This valve is used to isolate the suppression pool water source when HPCS system suction is from the condensate storage system and to isolate the system from the suppression pool in the event a leak develops in the HPCS
- system, 6.3-12a
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t The HPCS pump characteristics, head, flow, horsepower, and required NPSH are 4
U shown in Figure 6.3-71.
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The design pressure and temperature of the system components are established based on the ASME Section III Boiler and Pressure Vessel Code. The design pressures and temperatures, at various points in the system can be obtained from the miscellaneous information blocks on the HPCS process diagram, Figure 6.3-1.
A check valve, flow element and restricting orifice are provided in the HPCS discharge line from the pump to the injection valve. The check valve is located below the minimum suppression pool water level and is provided so the piping downstream of the valve can be maintained full of water by the discharge line fill system (see Section 6.3.2.2.5).
The flow element is provided to measure system flow rate during LOCA and test conditions and for automatic control of the minimum low flow bypass gate valve. The measured flow is indicated in the main control room. The restricting orifice is sized during pre-operational test of the system to limit system flow to acceptable values as described on the HPCS system process diagram, Figure 6.3-1.
A low flow bypass line with a motor-operated gate valve connects to the HPCS discharge line upstream of the check valve on the pump discharge line. The line bypasses water to the suppression pool to prevent pump damage to overheating when other discharge line valves are closed.
The valve automatically closes when flow in the main discharge line is sufficient to provide required pump cooling.
To assure continuous core cooling, signals to isolate the containment do not operate any HPCS valves.
The HPCS system incorporates relief valves to protect the components and piping from inadvertent overpressure conditions. One relief valve, set to relieve at 1560 psig, is located on the discharge side of the pump downstream of the check valve to relieve thermally expanded fluid.
A second relief valve is located on the suction side of the pump and is set at 100 psig with a 6.3-13
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The design pressure and temperature of the system components are established based on the ASME Section III boiler and pressure vessel code.
The design pressures and temperatures at various points in the system can be obtained f rom the miscellaneous information' blocks on the LPCS process diagram Figure 6.3-2.
The LPCS pump is located in the auxiliary building sufficiently.below the water level in the suppression pool to assure a flooded pump suction and to meet pump NPSH requirements are met with the containment at atmospheric pressure and the suction strainers 50 percent plugged. A pressure gage is provided to indicate the suction head. The available NPSH, calculated in accordance with Regulatory Guide 1.1, is based on the following design conditions:
a.
Pump design maximum runout flow of 7800 gpm b.
Atmospheric containment pressure
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c.
Maximum suppression pool water temperature of 212* F 2
d.
Suppression pool minimum design water level at el. 589'-0" Y
e.
LPCS pump suction nozzle centerline at el. 571'-7" f.
Suction strainer 50 percent clogged The minimum NPSH requirement is, as specified by the manufacturer, 5 feet at a point 2 feet above the top of the pump mounting flange. This reference point is 11 inches below the pump suction nozzle. The calculated minimum available NPSil for the LPCS pump is 13.8 feet. The LPCS pump characteristics are shown l g' '
on Figure 6.3-72.
The LPCS system incorporates relief valves to prevent the components and piping from inadvertent overpressure conditions. One relief valve, located on the pump discharge, is set at 600 psig with capacity of 100 gpm --10%
accumulation. The second relief valve is located on the suction side of the pump and is set for 100 psig at a capacity of 10 gpm - 10% accumulation.
Relief valve F018 of the LPCS system has a discharge line terminating below the surface of the suppression pool. For this valve, the dynamic loads such as thrust and momentum caused by relief valve opening are calculated ft.: the 6.3-18
440.26 Calculations of NPSH available to ECCS pumps in BWRs are (6.3) normally provided with reference to the pump suction. We are concerned that under certain post accident conditions the potential may exist for damage to ECCS pumps from cavitation because of local flashing in the sys'.em suction lines.
'Ihe potential can result, for example, from local elevation changes in the piping runs. Calculstions of NPSH available at the pump suction may erroneously assume liquid continuity up to the point of pump suction.
Provide an analysis with calculations which demonstrates that the NPSH available at all points in ECCS pump suction piping is adequate to preclude local flashing and pump cavitation under the worst postulated conditions.
Response
ECCS pump suction piping has been designed to slope continuously downward; therefore there are no local elevation changes that would result in an available NPSH inadequate to preclude local flashing and pump cavitation under the worst postulated conditions.
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440.27 Your FSAR states that no operator action is required until (6.3) 10 minutes after accident. It is our position that no operator action be required for 20 minutes after an accident. Discuss the consequences of not performing operator actions until 20 minutes after a LOCA.
(LRG-II issue 4-RSB)
Response
This issue will be addressed as an LRG-II issue 4-RSB, which is scheduled for submittal in January 1982.
440.28 Provide the assumed values that comprise the total break area for (6.3) the recirculation line break; steamline break inside and outside containment; feedwater line break; and core injection spray line break.
Response
2 The maximum recirculation break area of 273 ft consists of the following area:
recirculation safe end area 2
of one recirculation loop (0.468 ft{2.18 ft ), total jet pump nozzle area
) and the minimum flow area of the reactor 2
water cleanup system piping connecting the two loops (0.08 ft ).
The maximum steam line break inside the containment is based on the steam line safe end 2
area (3.05 ft ).
The m vinnm outside containment steam line break area 2
(3.21 ft ) is based on the minimum flow limiter area for each steam line (0.80 ft2). The feedwater line break area (1.07 ft ) is based on the 2
2 inside area of the feedwater sparger pipe (0.18 ft ).
The maximum core spray line break area is based on the limiting area of the core spray line 2
tee / reducer connection inside the vessel (0.28 ft ),
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440.29 What are the differences between steam line breaks inside and (6.3) outside containment with regard to break area? The analyses suggest that core uncovery could occur if no operator action took place before 20 minutes.
Provide the effect on peak clad temperature of no action prior to 20 minutes and discuss all assumptions.
(LRG-II issue 4-RSB)
Response
This issue is being addressed as an LRG-II issue 4-RSB, which is scheduled for submittal in January 1982.
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240.30 The references provided for the ECCS analysis must include 4
(6.3) references for the latest model changes and corrections.
Response
The ECCS analysis for Perry will include the appropriate references for models used when it is submitted.
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440.31 Justify selection of a lead plant for the LOCA break spectrum (6.3 3.7.3) analysis. Perry is committed to submit a plant specific IOCA analysis. We require a schedule for submittal of the plant specific IDCA analysis.
Response
A " typical" LOCA break spectrum analysis was provided as an example whose results would be similar to the Perry plant specific ECCS analysis. The plant specific analysis will replace the " typical" analysis when it is complete in March 1982.
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440.32 What provisions are made to protect level instrumentation for the condensate storage tank and the lines from this tank leading to the HPCS systems from the effects of cold weather?
Response
The lines leading to the level instrumentation and the line leading to the IIPCS/RCIC systems are provided with heat tracing for protection from the effects of cold weather.
440 33 During long-term cooling following a small LOCA, the operator must control primary system pressure to preclude overpressurizing the pressure vessel after it has been cooled off.
1.
Describe the instructions given the operator to perform long-term cooling.
2.
Indicate and justify the time frame for per-forming the required action.
3.
List the instrumentation and components needed to perform this action and confirm that these components meet safety grade standards.
4.
Discuss'tlie safety concerns during this period and the design margins available.
5 Provide temperature, pressure, and RCS inventory graphs that would show the important features during this period.
The above discussion should account for the following:
1.
2.
Operator error or single failure.
-(LRG-II issue-4-RSB)
Response
During long-term cooling following a small LOCA, no operator actions are required to control system pressure to preclude overpressurizing the pressure vessel after it has been cooled off. The system is always protected by relief valve capacity that is more than adequate to handle decay heat energy generation.
If a small LOCA caured reactor vessel water level to drop to Level 3 or the dryvell to pressurize the plant would scram. If water level drops to Level 2, then HPCS (and RCIC) automatically start, reestablish water level for the postulated small LOCA, and automatically control water level between Levels 2 and 8.
If a small LOCA caused high drywell pressure and water level dropped to Level 1, then all ECCS would automatically start to reestablish water level and ADS would automatically initiate to depressurize the vessel.
Once actuated, the ADS valves stay open and are designed to stay open, thereby precluding any significant repressurizing of the reactor vessel.
If the pressure vessel were cooled off following the hypothetical small LOCA, then the ADS valves would be open and would prevent repressurizing the pressure vessel.
1.
There are no operator actions required following a small LOCA to preclude overpressurizing the pressure vessel after it has been cooled off. Operator actions to establish long-term cooling are discussed in subsections 6.2.2.2 and 6.2.2.3 2.
No actions are required.
3 No actions are required. Safety grade instrwnentation is described in Chapter 7.
4.
Limiting safety concerns are addressed in Section '6.2, Containment Systems, Section 6.2.1.1.3 3 Accident Response Analysis, and Section 15 7 Radioactive Releases from subsystems and components. The event postulated is not a limiting event for design to assure the health and safety of the public.
5 System characteristics for the more severe design basis events are shown in Sections 6.2 and 6.3 The above discussion accounts for:
Operator error or single failure l
440.34 The SRP 6.3 does not allow credit for operator action for 20 minutes following a loss-of-coolant accident (LOCA). The FSAR states no operator action is required for at least 10 minutes. The applicant should confirm that no operator action is required until 20 minutes aft-r the LOCA, or provide technical, justification and an associated data base to support a time less than 20 minutes. The applicant should identify the manual actions which must be performed to prevent safety criteria from being exceeded following a LOCA over the break spectrum, including single failures.
It should also be shown that adequate alarms, instrumen-tation, and time will be available to the operator to perform manual actions necessary to prevent safety criteria from being exceeded.
(LRG-II issue-4-RSB)
Response
This issue will be addressed as LRG-II issue 4-RSB which is scheduled for submittal in January 1982.
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e 440.35 Address the inadvertent closure of the reactor recirculation system line suction valve as a single failure in the LOCA analysis, for the break size most affected by this failure.
(LRG-II issue-10-RSB)
Response
The response to this question was submitced as an LRG-II position paper for issue 10-RSB in a letter to H. J. Faulkner from D. L. Holtzscher on November 20, 1981. This position was endorsed on the Perry docket in a letter to J. R. Miller from D. R. Davidson dated November 25, 1981
440 36 Response to the following 'IMI action items are required to complete the review of section 6.3 (a)
II.K.1 IE Bulletins on measures to mitigate mall break LOCA's and Less-of Feedwater Accidents.
(i)
II.K.l.5 Review of E. G. F. Valves (ii) II.K.l.10 Operability Status (b) II.K.3 17 ECCS outages (c) II.K.3 18 ADS Actuation (LRG-II issue 1-RSB)
K (d) II.D.3.21 Restart of LPCS and LPCI (LRG-II issue 1-RSB)
(e)
II.K.3 25 Power on Recirculation Pump Seals (f) II.K.3.30 SB LOCA methods (g) II.K.3.31 Plant Specific Analysis (h) II.K.3.45 Manual ADS (i) II.K.3 3 Reporting SV&RV failures and Challenges (j) II.K.3.16 Challenges to & Failure of Relief Valves
Response
(a)(1) Item II.K.l.15 IE Bulletins - Safety Related Valve Position Perry Nuclear Power Plant is equipped with valve position status monitoring that satisfies the requirements of Regulatory Guide 1.47 as discussed in FSAR section 7.1.
Perry Plant procedures for tagging, maintenance, and surveillance will assure verification of valve position status on the affected portions of system to verify ESF systems are functional after the performance of surveillance tests, and maintenance activities. These plant procedures will be available for review by Region III Division of Inspection and Enforcement.
(a)(ii) Item II.K.l.10 IE Bulletins - Operability Status i
Perry Plant procedures for removing safety related systems from service and restoring to service will assure the operability status is known.
Release of all ESF equipment from service will require Shift Supervisor's approval. Plant procedures will include verification of operability of safety related equipment after restoration following surveillance and maintenance activities.
These procedures will be available for review by Region III Division of Inspection and Enforcement.
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(b)
Item II.K.3.17 Report on Outages of Emergency Core Cooling Systems Licensee Report and Proposed Technical Specification Changes Cleveland Electric Illuminating Company commits to reporting a summary of emergency core cooling system outages annually.
(c)
Item II.K.3.18 Modification of Automatic Depressurization System (ADS) Logic - Feasibility for Increased Diversity for Some Event Sequences.
Cleveland Electric Illuminating Company has participated in the BWR Owners' Group evaluation of logic nolifications to simplify ADS actuation. The results of this study are submitted to the NRC in a letter from D. B. Waters to D. G. Eisenhut dated March 31, 1981.
The BWR 0/G is presently reevaluating the recommendations due to recently identified conflicts between the proposed modifications to ADS actuation logic and the Emergency Procedures Guidelines.
CEI is participating in this study and will document the resolution of this item in a future amendment.
(d)
Item II.K.3.21 Restart of Core Spray and Low-Pressure-Coolant Injection Systems Cleveland Electric Illuminating Company has endorsed the BWR Owners' Group position in the letter from D. B. Waters to D. G.
Eisenhut dated December 29, 1980. That position is the current LPCI, LPCS, and HPCS system designs are adequate and no design changes are required.
However, as discussed in the LRG-II position paper for issue 1-RSB, a modification is planned for the HITS system to automatically restart the HPCS pump on low reactor water level following manual termination.
CEI endorsed this LRG-II position in a letter from D. R. Davidson to J. R. Miller dated November 25, 1981.
(e) Item II.K.3.25 Effect of Loss of Alternating Current Power on Pump Seals Cleveland Electric Illuminating Company has participated in the BWR Owners' Group evaluation of the effect of the loss of pump seal cool-ing for a period of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
This evaluation was submitted in a letter from D. B. Waters to D. G. Eisenhut, dated May 1981. The study indicates that the loss of pump seal cooling for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is not a safety problem, but may require seal repairs prior to resuming operating. Even in the case of both seal cooling systems failing, followed by extreme degradation of the pump seals, the primary coolant loss is analyzed to be less than 70 gallons per minutes. Consequently, no hazard to the health and safety of the public will result from total loss of recirculation pump seal cooling water.
(f) Item II.K.3 30 Revised Small Break Loss-of-Coolant-Accident Methods to Show Compliance with 10CFR Part 50, Appendix K The General Electric Company has evaluated the NRC request to demon-strate that the BWR small-break LOCA analysis methods are in compliance with Appendix K to 10 CFR Part 50.
Documentation that GE's present analytical methods are acceptable was provided in a letter from R.
H. Buckholz, GE to D. G. Eisenhut dated June 26, 1981.
(g)
Item II.K.3.31 Plant Specific Calculations to Show Compliance with 10 CFR Part 50.46 The results of a typical LOCA ana]ysis have been provided in FSAR Section 6.3.3 This analysis uses the currently approved Appendix K methodology. A Perry plant specific analysis using NRC approved models will be submitted in April 1980.
(h)
Item II.K.3.45 Evaluation of Depressurization with other than Automatic Depressurization System (ADS)
Cleveland Electric Illuminating Company participated in the BWR Owners' Group generic evaluation of alternate modes of depressurization other than full actuation of the ADS. The results of this program were submitted to the NRC in a letter from D. B. Waters to D. G.
Eisenhut dated December 29, 1980. The BWR Owners' Group evaluation showed that vessel integrity limits are not exceeded for full blow-down, and lower depressurization rates have little benefit to vessel fatigue, but can have an adverse effect on core cooling capability.
(i) Item II.K.3.3 Reporting Safety and Relief Valve Failures Promptly and Challenges Annually Failures of safety valves or of primary system relief valves will be promptly reported to the NRC via the Licensee Event Report system.
All challenges to these valves will be reported annually.
(j)
Item II.K.3.16 Reduction of Challenges and Failures of Relief Valves - Feasibility Study and System Modification Cleveland Electric Illuminating Company has participated in a BWR Owners' Group evaluation of possible ways to reduce the challenges and failures of safety relief valves.
The results of this feasibility study were submitted to the NRC in a letter from D. B. Waters to D. G. Eisenhut dated March 31, 1981. The study concluded that BWR/6 plants, already include design features which significantly reduce the likelihood of stuck open relief valve (SORV) events, no further design modifications are necessary.
It is the Cleveland Electric Illuminating Company's position that further modifications to the Perry Nuclear Power Plant would not significantly reduce the frequency of SORV events.
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440.19 Eesponse to the following TMI action ite=s are required by to ec=plete the review of Section 5.4.6.
(a)
TMI Item II.K.l.22 - Auxiliary Heat Re=dval A plant specific response describing Perry design provisions is required. References to BWR Owners' position and NEDO-25224 are not sufficient.
(b)
We request that the applicant submit an acceptable response to the requirements included in Action Plan item II.K.3.13, possible need for separation of RCIC and HFCS initiation levels and restart capability of RCIC on ldw water lever (NUREG-0737)
(c)
We request that the applicant submit an acceptable response for Item II.K.3.15, provisions for preventing inadvertent RCIC syste=
isolation or trip.
Response
(a)
Item II.K.l.22 Initial Core Cooling Following a loss of feedwater and reactor scram, a low reactor water level signal (level 2) will automatically initiate high pressure core spray (HPCS) and reactor core isolation cooling (RCIC) systems. These systems operate in the reactor coolant make up injection mode to inject water into the vessel until a high water level signal (level 8) trips the system.
Following a high reactor water level 8 trip, the HPCS System will auto =atically re-initiate when reactor water level decreases to low water level 2.
The RCIC System vill auta=atically re-initiate after a high water level 8 trip.
(See response to II.K.3.13).
The HPCS and RCIC Syste=s have redundant supplies of water.
Normally they take suction from the condensate storage tank (CST).
The HPCS System suction will automatically transfer from the CST to the suppression pool if the CST water is depleted or the suppression pool water level increases to a high level.
The RCIC System suction is automatically transferred from the CST to the suppression pool, when the CST low level is reached.
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r Tne operator can manually initiate-the HFCS and ECIC Systems from tne control room before the level 2 automatic initiation level is reached. The operator has the option of manual con-trol after automatic initiation and can maintain reactor water level by throttling system flow rates.
The operator can verify that these systems are delivering water to the reactor vessel by:
a.
Verifying reactor water level increases when syste=s initiate.
b.
Verify systems flow using flow indicators in the control room, c.
Verify system flow is to the reactor by checking control room position indication of motor-operated valves. This assures no diversion of system flow to the reactor.
Therefore, the HPCS and RCIC can maintain reactor water level at full reactor pressure and until pressure decreases to where low pressure systems such as Iow Pressure Core Spray (LPCS) or Iow Pressure Coolant Injection (IJCI) can maintain water level.
Steam Condensing This mode of RHR operation is manually initiated. Reactor pressure provides the head to supply steam to the RHR (A or B).
heat exchangers via the RCIC steam lines.
In the RHR heat exchangers, the steam is condensed by Emergency Service Water passing through the heat exchanger tubes.
The condensate can be sent either to the suppression pool or the suction of the RCIC pump to maintain reactor vessel. level. ' Ibis mode of reactor water cooling is-used to maintain the reactor in either a hot standby condition or to take it to a cold shut-down condition.
Containment Cooling After reactor scram and isolation and establishment of satis-factory core cooling, the operator would start containment cooling.
This code of operation removes heat resulting from safety relief valve (SRV) discharge and RCIC turbine exhaust to the suppression pool.
This would be accomplished by placing the Residual Heat Removal (RHR) System in the containment (suppression pool) cooling mode, i.e., RHR suction from and discharge to the suppression pool.
The operator could verify proper operation of the RHR system contain=ent cooling function from the control room by:
a.
Verifying RHR and Emergency Service Water (ESW) system flow using system control room flow indicators.
b.
Verify correct RHR and ESW system flow paths using control room position indication of motor-operated valves.
s c.
On branch linec that could divert flow frcm the required flow pathc, close the motor-o;erated valves and note the effect on RHR and ESW flow rate.
Even though the RHR is in the containment cooling mode, core cooling is its primary function.
'Ibus, if a high drywell pressure signal or low reactor water level is received at any time during the period when the RHR is in the contain=ent cooling mode, the RHR system vill automatically revert to the LPCI injection mode.
The Low Pressure Core Spray (LPCS) system would automatically initiate and both the LICI and LPCS systems would inject water into the reactor vessel if the reactor pressure is below system discharge pressure.
Extended Core Cooling When the reactor has been depressuriced, the RHR system can be placed in the long tem shutdown cooling mode.
'Ibe operator manually ter-ivtes the containment cooling mode of one of the RHR containment cooling loops and places the loop in the shut-down cooling mode.
In this operating mode, the RHR' system can cool the reactor to cold shutdown.
Proper operation and flow paths in this mode can be verified by methods similar to those described for the containment cooling mode.
(b)
Item II.K.3.13 CEI has endorsed the position of the BWR Owners' Group delineated in the letter from Mr. R. H. Buchholz to Mr. D. G. Eisenhut dated October 1, 1980.
That portion is basically that "...the current design is satisfactory, and a significaht reduction in themal cycles is not necessary; "and"
...no significant reduction in thermal cycles is achievable by separating the setpoints."
Modification of the initiation logic for autocatic restart of the RCIC system on low water level is being incorporated into the Perry design and will be incorporated in a later amendment.
(c)
Item II.K.3.15
'Ibe BWR Owners' Group has evaluated this issue and has reco== ended the addition of a time delay to the HPCI/RCIC break detection cir-cuitry. CEI has contracted with General Electric to provide this change to the RCIC steam line break detection circuitry. A des-cription of this change will be included in a later amendment.
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