ML19241B142
| ML19241B142 | |
| Person / Time | |
|---|---|
| Site: | Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 06/07/1979 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML19241B138 | List: |
| References | |
| TASK-05-10.B, TASK-05-11.B, TASK-07-03, TASK-10, TASK-RR NUDOCS 7907110729 | |
| Download: ML19241B142 (94) | |
Text
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SEP REVIEW Oc SAFE SHUTOOWN SYSTEMS FOR THE HADDAM NECK PLANT 309 260 June 7, 1o79 7907110,7 2 82
TABLE OF CONTENTS Eage l.0 INTRODUCTION...............
I 2.0 DISCUSSION.
6 2.1 Normal Plant Shutdown and Cooldown..
6 2.2 Shutdown and Cooldcwn with Loss of Offsite Power.
14
- 3. 0 CONFORMANCE WITH BRANCH TECHNICAL POSITION 5-1 FUNCTIONAL REQUIREMENTS.
17 3.1 Background..
18
- 3. 2 Functional Requirements..
24 Table 3.1 Classification of Shutdown Systems.
60 4.0 SPECIFIC RESIDUAL HEAT REMOVAL AND OTHER REQUIREMENTS OF BRANCH TECHNICAL POSITION 5-1.
29 4.1 Residual Heat Removal System Isolation Requirements..
69 4.2 Pressure Relief Requirements.
4.3 Pressure Relief (Fluid Discharge)....
73 76 4.4 Pressure Relief (During Isolation Valve Closure)..
78 4.5 Pump Protection Requirements.
79 4.6 Test Requirements................
80 4.7 Operational Precedures...
81 4.8 Auxiliary Feedwater Supply.
82 5.0 RESOLUTION OF SYSTEMATIC EVALUAT.UN PROGRAM TOPICS.
83 5.1 Topic V-10.6 RHP System Reliability...
83
- 5. 2 Topic V-ll. A Requirements for Isolation of High and Low Pressure Systems...
84
- 5. 3 Topic V-ll.B RHR Interlock Requirements.
84
- 5. 4 Topic VII-3 Systems Require for Safe Shutdo vn.
85 5.5 Topic X Auxiliary Feed System...
88
6.0 REFERENCES
91
?> 09 2.61 W
1.0 INTRODUCTION
The Systematic Evaluation Program (SEP) review of the " safe shutdown" subject encompassed all or parts of the following SEP topics, which are among these identified in the November 25, 1977 NRC Office of Nuc'aar Regulation document entitled " Report on the Systematic Evaluation of Operating Facilities":
1.
Residual Heat Removal System Reliability (Topic V-10.8) 2.
Requirements for Isolation of High and Low Pressure Systems (Topic V-ll.A) 3.
RHR Interlock Requirements (Topi. V-ll.8) 4.
Systems Required for Safe Shutdown (Topic VII-3) 5.
Station Service and Cooling Water Systems (Topic IX-3) 6.
Auxiliary Feedwater System (Topic X)
The review was primarily performed during an onsite visit by a team of SEP personnel.
This onsite effort, which was performed during the period July 11-13, 1978, afforded the team the opportunity to obtain current information and to examine the applicable equipment and procedures.
The review included specific system, equipment and procedural requirements for remaining in a hot shutdown condition (reactor 309 262 M
.. - ~ =
s
,, shutdown in accordance with technical specifications, temperature between 200 F and 350*F) and for proceeding to a cold shutdown condition (temperature less than 200*F).
The review for transition from operating to hot shutdown considered the requirement that the capability exists to perform this operation from outside the control room.
The review was augmented as necessary to assure resolution of the applicable topics, excert as note below:
Topic V-ll.A (Requirements for Isclz, ion of High and Low Pressure Systems) was examined only for application to the Residual Heat Removal (RHR) system.
Other high pressure /lcw pressure interfaces were not investigated.
Topic IX-3 (Station Service and Cooling Water Systems) was only reviewed to consider redundancy and seismic and quali classifi-r cation of cooling water systems that are vital to the performance of safe shutdown system components.
The criteria against which the safe shutdown systems and components were compared in this review are taken from the:
Standard Review Plan (SRP) 5.4.7, " Residual Heat Removal (RHR) Systems;" Branch Technical Position RSB 5-1, " Design Requirements of the Residual Heat Removal System;" and Regulatory Guide 1.139, " Guidance for Residual Heat Removal." These documents represent current staff criteria for the review of apolications for operating licenses.
~
g
. This comparisen of the existing systems against the current licensing criteria led naturally to at least a partial comparison of design criteria, which vill be input to SEP Topic III-1,
" Classification of Structures, Components and Systems (Seismic and Quality)."
As noted above, the six topics were considered while neglecting possible interactions with other topics and other systems and compon qts not directly related to safe shutdown.
For example, Topics II-2.8 (Flooding Potential and Protection Requirements),
II-3C (Safety-Related Water Supply), III-4.C (Internally Generated Missiles), III-5. A (Effects of Pipe Break on Structures, Systems, and Components Inside Containment), III-6 (Seismic Design Considerations), III-10. A (Thermal-Overload Protection for Motor:
of Motor-Operated Valves), III-11 (Component Integrity), III-12 (Environmental Qualification of Safety-Related Equipment) and V-1 (Compliance with Codes and Standards) are among several topics which could be affected by the results of the safe shutdown review or could have a safety impact upon the systems which were reviewed.
These effects will be determined by later review.
This review did not cover, in any significant detail, the reactor protection system nor the electrical power distribution system both of which will be reviewed later in the SEP.
309 2M
4_
The major factor in assessing the safety margin of any of the SEF facilities depends upon the ability to provide adequate protection for postulated Design Basis Events (DBEs).
The SEP topics provide a major input to the DBE review, both from the standpoint of assessing the probability of certain events and that of determining the consequences of events. As examples, the safe shutdown topics pertain to the listed DBEs (the extent of applicability will be determined during the DBE review for Haddam Neck):
Impact Upon Probability Taoic DBE Grouo*
or Consecuences of DBE V-i0.B VII (Spectrum of Loss of Coolant Consequences Accidents)
V-ll.A VII (Defined above)
Probability V-ll.B VII (Defined above)
Probability VII-3 All (Defined as a generic topic)*
Consequences IX-3 III (Steam Line eak Inside Consequences Containment (Steam Line Break Outside Containment)
IV (Loss of AC Power to Station Consequences Auxiliary)
(Loss of all AC Pcwer)
V (Loss of Forced Coolant Flow)
Probabili ty (Primary Pump Rotor Seizure)
(Primary Pump Shaft Break)
"For a listing of DBE groups and generic topics, see Reference 12.
f)09 265 h
w
JWR.
Impact Upon Probability Tooic DBE Group or Consecuences of DBE VII (Defined above)
X II (Loss of External Load)
(Steam Pressure Regulator Failure)
[ closed])
(Loss of Feedwater Flow)
(Feedwater Systen Pipe Break)
III (Defined above)
Consequences IV (Defined above)
Consequences V (Defined above)
Consequences VII (Defined above)
Consequences The completion of the safe snutdown topic review (limited in scope as noted aoove) provides significant input in assessing the existing safety margins for the Haddam Neck Plant.
}()9
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" 2.0 DISCUSSION 2.1 Normal Plant Shutdown and Cooldown A series of five operating procedures is employed to conduct a shutdowr. from full power to cold shutdown.
The first procedure is Normal Operating Procedure (NOP) 2.2-1 Revision 6, " Changing Plant Load." NOP 2.2-1 is used to operate the plant above a minimum load of approximately 80 Ne.
The reactor controls are placed in manual and the load decrease is started by reducing steam ficw with the turbine governor and manual insertion of the control group of rods.
During the load decrease, plant parameters are maintained as noted below:
1.
T and pressurizer level are being maintained in accordance avg with the pressurizer level program (25-50%) by the chemical and volume control system (CVCS).
2.
The pressure control system maintains the pressurizer and reactor coolant system at the normal operating pressure of 2000 2 25 psig.
3.
The feedwater control system maintains the steam generator water levels within the normal operating range of 25-50%.
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DRY
. 4.
Boration is performed as required to keep the control rods above the minimum position required by Technical Specifications.
When the power is reduced to 275-300 Mwe, a feedwater pump is taken out of service and, at 230-250 We, a condensate pump is taken out of service.
Seal water injection pumps are started tc supply seal water to the main feedwater pumps seals when the @ between condensate pump discharge and feedwater pump suction is less than 50 psi.
Feecwater control is placed in the manual mode before minimum load is reached.
The next phase of the shutdown utilizes NOP 2.3-1 Rev. O
" Minimum Load to Hot Standby." The plant conditions at the start of this phase are:
1.
The plant is at minimum load at app:*oximately 80 Ne.
2.
Steam generators are being maintained at normal operating level of 25-50% on narrow range with feedwater control in manual.
309 268 w
l 3.
Steam dump control is in automatic and set at 910 psig.
4.
T is being maintained at approximately 533 F by manual gg adjustment of the control group rod position within the desired operating range to compensate for reactivity changes.
The following steps t re completed to put the unit in hot standby with the reactor cr'.t.' :al:
1.
Reset steam dump pressure controller (MS-PIC-1203) to 880-890 psig.
2.
Reduce generator load and reactor power below P-7 permissive setting by gradual closing of turoine control valves and by insertion of control rods.
Maintain T f 533 2 F during avg this operation.
3.
Transfer power supplies for buses 1-1 A and 1-1B from generator to outside lines.
This places the reactor coolant pumps on off-station power 4.
Unload and separate the generator from the system in accordance with NOP 2.16-2 " Generator Phasing and Unloading."
3Oh N
1
.g.
5.
Open the feedwater regulating bypass valves and close the fecdwater regulating valves.
-7 6.
Insert control rods until power is at 1 x 10 amperes on the Intermediate Range indicators.
The reactor is then shutdown by inserting the control rods to the 10 step limit and then opening the trip breakers per NOP 2. 5 2
" Reactor Shutdown."
It is, also, possible to reach hot :tandby with autcmatic action of the reactor trip system or manual reactor trip action by the operator.
These actions, and the necessary manual actions of the operator are described in Emergency Operating Procedure (EOP) 3.1-1 Rev. O
" Emergency Shutdown."
Operation at hot standby can be maintained in accordance with NOP 2.3-3 Rev. 1 " Operatic ~ dt Hot Standby-Reactor Shutdcwn." The following conditions are maintained while operating at hot stancby:
1.
T
= 533 2 F and RCS pressure is 2000 25 psig.
avg 2.
Pressurizer levels is being maintained at normal operating range of 25 - 50%.
309 270
DRi l 3.
Volume control tank level is within the normal operating range of 30 - 55%.
4.
At least one reactor coolant pump is operating to maintain T
f 533 2 F.
avg NOTE-Tile Reactor Coolant Pump in operation must be No. 3 or 4 to provide sufficient head to operate the pressurizer sprays.
Steam generator liquid levels are manually maintained at normal operating range of 25 - 50% on narrow range indicator.
5.
One Auxiliary Feedwater Pump or a main stearr generator feed pump is in operation and feeding the steam generators via the feedwater regulating b.spass valves, FW-HICV-1301-1, 2, 3 & 4.
6.
Steam Generator may be dumping excess steam to concensers via steam dump or venting to atmosphere via atmospheric vent.
(MS-HICV-1201).
7.
Reactor Coolant System is barated to the required baron concentration to maintain a 3% shutdown margin with all rods inserted.
~f
J 8.
Letdown purification is operating in accordance with require-ments of the Plant Chemistry Department.
9.
Steam generator non-return bypass valves MS-NRV-17, 27, 37 and 47 are closed.
10.
Sufficient water is available i, the demineralized water storage tank (DWST).
The Technical Specifictions require a minimum of 50,000 gallons of water in the CWST and a minimum of 80,000 gallons of water in the primary water storage tank (PWST).
Water may be trans-ferred frca the PWST to the CWST at the rate of 200 gpm with tranfer pumps.
A third source of water is available frca the Recycle Primary Water Storage Tank (RPWST).
There are no Technical Specification requirements on the amount of water in the RPWST; however, the licensee normally, maintains ::5,000 to 100,l;00 gallons stored in this tank.
If the method of heat removal is through the atmospheric vents, the source of water fcr the auxiliary feedwater pumps is the CWST.
If the steam dumps are used, the level of water in tne hotwell will be used and the excess water is directed through the condensate pumps to the DWST and then back to the auxiliary feedwater pumps.
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4 The procedure to cool the unit to cold shutdown is NOP 2.3-4 Rev. 5 " Hot Standby to Cold Shutdown."
The reactor coolant system must be borated to the cold shutdown or refueling baron concentration before cooldown is initiated.
Makeup for coolant contraction must be at the same concentration as that required for cold or refueling shutdown.
The pressurizer heaters aca turned off and all but one reactor coolant pump are shutdown.
If it is necessary to shutdown both pumps No. 3 and 4, spray to the pressurizer is delivered through the auxiliary spray line from the charging line.
The letdown and charging flow; are adjusted to account for the reduced pressure drop across the letdown orifices and for the thermal contraction of the reactor coolant.
When the pressurizer temperature reaches approximately 450 F and the pressure is approximately 600 psig, the steam bubble is collapsed in the pressurizer and the pressurizer is filled.
The next step in the plant cooldown is to energize the low temperature overpressurization relief isolation valves RP-MOV-596, PR-MOV-597, PR-MOV-598, PR-MOV-599.
When RCS temperature reaches 340 F, pressurizer temperature <430 F, reduce RCS 309 273
a l pressure to 350 psig.
Place the ltw temperature overpres-surization relief valves PR-RV-587 and PR-RV-588 in service by opening motor operated isolation valves PR-MOV-596, PR-MOV-597, PR-MOV-598 and PR-MOV-599.
NOTE:
PR-RV-587 and PR-RV-588 are set to relieve at 380 psig.
When the reactor pressure has been reduced to 300 psig the residual heat removal (RHR) system is placed in service; and when steam pressure is at 300 psig, the auxiliary feedwster pump is taken out of service and feedwater can be supplied to the stea"i generators with the condensate pumps.
The cooldown is continued with the RHR system until the reactor coolant system meets the cold shutdown requirements.
The cooldown procedure calls for intermittent coeration of a single reactor coolant pump which requires repetitive operation of the RHR isolation valves during the cooidown.
The RHR system has two one-half size heat exchangers and two one-half size pumps (F AR 5.2.3.3).
There are two methods of removing heat from the RHR heat exchangers.
The Dreferred method for decay heat removal is to use the component cooling system and tnen transfer the heat from the comoonent cooling 309 274
L water to the service water system; the sect,ad method is to introduce service water directly to the secondary of the RHR heat exchangers.
The use of the second method is called for in Emergency Operating Procedures (EOP) 3.1-11 " Loss of Component Cooling."
The normal operating pressures of the systems used for shutdown cooling are 150 psig plus the pump suction for the RHR loop, 82 psig for the component cooling loop, and 55 to 70 psig for the service water system; therefore, the flow of imourities would be away from the reactor coolant system.
Overpressuri:ation of the RHR system from the RCS is avoided by administrative control of two locked isolation valves and by a pressure interlock on two more isolation valves.
A relief valve is installed on the RHR system that relieves at 500 psig and has a 960 gpm relieving capacity.
- 2. 2 Shutdown and Cooldown with a Loss of Offsite Power The shutdown following a loss of offsite power is achieved with E0P 3.1-9 Rev. 4 " Total Loss of AC."
A station blackout results in the loss of circulating water pumps, the main feedwater pumps and condensate pumos; the reactor coolant pumos remain in service for soproximately one minute and then 309 275
. undergo a pump coastdown that is extended by the intertia of the fly wheels on the pumps.
The pump coastdown time is estimated to be three to four minutes with no pumps running, i.e., no back flow, this estimate is given in the March, 1968 report on the natural circulation test " Natural Circulation Test of Reactor Coolant System."
On loss of offsite power, the plant emergency diesel generators start automatically.
The operator is directed to restore diesel gens ator power to certain vital.quipment and to start the auxiliary feed pump to feed the steam gene ' tors through the feedwater bypass valves.
ine atmospheri. dump valve and hogging air ejectors are used to control T in the reactor coolant system.
avg Emergency Operating Procedures ECP 3.1-9 does not contain instructions to attain and maintain cold snutdown conditions during a loss of offsite power.
E0P 3.1-9 does not contain instructions on the source of water after the supply in the CWST is exhausted.
The site expsrienced loss of offsite power on April 27, 1968, July 15, 1969 and June 26, 1976; the unit 309 276
j a
- 16 :
was on line when the first two events occurred and was in the refueling mode during the last event.
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i 3.0 CONFORMANCE WITH BRANCH TECHNICAL POSITION 5-1 FUNCTIONAL REOUIREMENTS The current NRC criteria used in the evaluaticn of the design of the systems required to achieve cold shutdown for a new facility are listed in Standard Review Plan (SRP) 5.4.7 and Branch Technical position RSB 5-1.
The fol?cwing paragraphs give a point by point comparison of Branch Technical Position RSB 5-1 to the shutdown systems at the Haddam Neck Plant.
Brancn Technical Position "A.
Functional Recuirements "The systcm(s) which can be used to take the reactor from normal operating conditions to cold shutdown shall satisfy the functional requirements listed belcw.
1.
The design shall be such that the reactor can be taken from normal operating conditions to cold shutdown using only safety grade systems.
These systems shall satisfy General Design Criteria 1 through 5.
The system (s) shall have suitable redundancy in components and features, and suitable intercon-nections, leak detection, and isolation capabilities to assure that for onsite electrical power system operation (assuming offsite pcwer is not available) and for offsite electrical power system operation (assuming onsite power is not available) the syste, function can be accomplished assuming a single failure.
2.
The system (s) shall be capable of being operated from the control room with either only onsite or only offsite power available with an assumed single failure.
In demonstrating that the system can perform its function assuming a single failure, 309 278
, limited operator action outside of the control room would be considered acceptable if suitably justified.
4.
The system (s) shall be capable of bringing the
~
reactor to a cold shutdown condition, with only offsite or onsite power available, within a reasonable period of time following shutdown, assuming the most limiting single failure."
The capabilit, of the safe shutdown systems for Haddam Neck to meet the m criteria is discussed below.
3.1 Backaround These requicements are stated witn respect to plant shutdown and cooldown with anly offsite or only onsite power availeole.
The staff evaluated the plant's ability to conduct a shrtdown with only offsite power available and determined that the only onsite power available case is more limiting.
The plant electricIl system is sufficiently versatile to allow energizing of all necessary equipment from only offsite power.
Therefore, the staff concentrated its evaluation of the safe shutdown systems to the shutcown following a loss of offsite power.
A " safety grade" system is defined, in the NUREG 0138 (Reference 1) discussion of issue #1, as one which is designed to seismic Category I (Regulatory Guide 1.29), quality group C or better (Reguiatory Guide 1.25), and is operated by electrical instruments and controls tnat meet Institute of Electrical and Electronics Engineers Criteria 309 279
1.
for Nuclear Power Plant Protection Systems (IEEE 279).
The h3dcam Neck plant received its Provisional Operating License on June 30, 1967 and its Full Term Operating License on Decemoer 27, 1974, so that plant was designed and constructed prior to the issuance of Regulatory Guides 1.26 and 1.29 (as Safety Guides 26 and 29 on March 23, 1972 and June 7, 1972 respectively).
Also, proposed IEEE 279, dated Aucust 30, 1968, was not used in the design of instrumenta-tion and control systems at Haddam Neck.
In addition, tne Haddam Neck plant was built and licensed prior to tt= issuance of the proposed General Design Criteria on July ll,1967.
Therefore, for this evaluation, systems which should be " safety grade" are the systems identified in Table 3.1 and in the following list of minimum safe shutdown systems.
General Design Criterion (GDC) 1 requires that systems important to safety be designed, fabrice*ad, erected, and tested to cuality standards, that a Quality Assurance (QA) program be implemented to assure these systems perform their safety functions, and that appropriate records of aesign, fabrication, erection, and testing are kept.
Regulatory Guide (RG) 1.26 provides the current NRC criteria for quality grouc classification of safety-related systems.
Table 3.1 provides a comparison of the Haddam Neck safety grace shutcown 309 280
. systems with RG 1.26.
Although RG 1.26 was not in effect when Haddam Neck was constructed, the licenc ae has since classified the systems in accordance with this guide (Reference 1).
Even though the safety-related systems were not designed, fabricated, erected, and tested using RG 1.26, the maintenance and repair of the classified systems is currently conducted in accordance with this guide.
In Reference 2, thu licensee has identified maximum seismic ground accelerations which wtsre used in the design of structures, systems, and components important from the stands of nuclear safety.
The reactor coolant system and " gh and i ressure safety injection systems have been designed for a 0.17 g maximum ground acceleration, and the remaining structures and elements of the plant are cons 'ered capable of withstanding the seismic forcas corresponding to a ground acceleration of at least 0.03 g.
No structures or equipment are classified as seismic category I per Regulatory Guide 1.29.
Therefore, in Table 3.1, a ground acceleration level will be stated instead of a seismic design classification.
At the time the Haddam Neck plant was originally licensed, the NRC (then AEC) criteria for QA were not ceveloped.
However, the QA program for plant operations was reviewed by tne staff and found to 309 281
DRTT be in conformance with 10 CFR 50, Appendix B (Reference 3).
Appro-priate records concerning design, fabrication, erection and testing of equipment important to safety are maintained by the licensee in accordance with the QA program and the plant Technical Specifications.
GDC 2 states that structures and equipment important to safety shall be designed to withstand the effects of natural phenomena without loss of capability to perform their safety function.
Natural phenomena considered are:
hurricanes, tornadoes, floods, tsunami, seiches and earthquakes.
Measures were taken in the design of the plant to protect against floods and earthquakes.
During the Full Term Operating License review, the staff agreed with the licensee's conclusions in Reference 4 that the effects of tornadoes, floods, earthquakes, winds, ice, and other local site effects on structures and equipment important to safety were acceptable (Reference 5).
The effects of tornadoes will be reevaluated during the course of the SEP in Topics II-2.A " Severe Weather Phencmena," III-2 " Wind and Tornado-Loadings," and III-A.A " Tornado Missiles." The effects of flood will be reassessed in the SEP review under Tcpics II-3.8
" Flooding F.cential and Protection Requirements" and III-3
" Hydrodynamic Loads." Ana within the SEP review, the ;otential for 309 282
m' _
b A and consequences of a seismic event will be reassessed under several review topics.
GDC 3 requires structures, systems, and components important to safety to be designed and located to minimize the effects of fires and explosions.
The Haddam Neck fire protection reavaluation resulting frca the Browns Ferry fire is currently undersay in the NRC Division of Operating Renctors.
The fire protection Safety Evaluation Re:: ort was issued October 3.1978.
The results of this reevaluation will be integrated into the SEP assessment of the plant.
GDC 4 requires tnat equipment important to safety be designed to withstand the effects of environmental conditions for normal operation, maintenance, testing, and postulated accidents.
Also the equipment should t;e protected against dynamic effects including internal and external missiles pipe whip,
'uid impingement.
The SEP will censider the various aspects of this criterion when reviewing topics III-12 " Environmental Qualification of Safety-Related Equipment," III-5.A " Effects of Pipe Breaks Inside Contain-ment," III-5.8 " Pip? Breaks Outside Containment," and III-4 " Missile Generation and Protection."
309 283
l
. GDC 5 is not ap?licable for the Haddam Neck plant because it does not share ary equipment with other facilities.
In order to accomplis!. a plant shutdown and coldown following a loss of offsite pcwer, certain " tasks" must be performed such as core decay heat removal, steam generator makeup, and component cooling.
The staff and licensee developed a " minimum list" of systems necessary to perform these tasks consicering a loss of AC power and the most limiting single failure.
The system were then evaluated sith respect to their ability to perform those tasks, and the functional requirement of STP 5-1.
The minimum systems (or components)* are given below:
1.
Steam System ASME Code
'ety Valves 2.
Atmospheric Dump Valve (ADV) Stean Generator Vents, and other vent paths 3.
Auxiliary Feed Pumos "CYAPC0 is evaluating the need for the Instrument Air System.
The IAS may not be required since the air operated components necessary for safe shutdown may fail to their sa'e or required position uoan a loss of air.
Also, CYAPCO has stated that pressuaizer heaters are required to maintain RCS pressure control during hot shutdown, and the subsequent RCS coolcown.
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DRET 4.
Water Scurces - Demineralized Water Storage Tank (DWST),
Primary Water Storage Tank (PWST) and Primary Water Transfer Pump 5.
Residual Heat Removal System 6.
Service Water System 7.
Chemical and Volume Control System 8.
High Pressure Safety Injection 9.
Containment Fan Coolers (Cooled by Service Water System) 10.
Pressurizer Power Operated Reliefs 11.
Emergency Power Systems (AC and CC) for the above equipment 12.
Instrumentation for the above equipment The staff's evaluation of each of these systems with respect to the BTP 5-1 functional requirements is given below.
- 3. 2 Functional Recuirements Steam System ASME Code Safety Valves Task:
Removal of core decay heat by automatically venti.g steam from the main steam syse_m.
Discussion:
Cecay heat is initially removed from the RCS by the automatic actuation of the main steam safety valves (MS9V).
These valves are ASME coce, self actuated valves that relieve incecendently and 309 285 3
i e
directly to atmosphere.
Each steam generator has four MSSVs mounted on a short length of 24" 00 piping connected to each main steam header. The size, setpoint and capacity of each MSSV is given below:
8" x 14" P
= 985 psig 594,000 lbm/hr set 8" x 14" P
= 1015 psig 594,000 lbm/hr set 8" x 14" P
= 1025 psig 594,000 lbm/hr set 8" x 14" P
= 1034 psig 594,000 lbm/hr set Therefare, the total relieving capacity avai'able to each steam 0
generator is about 2.376 x 10 lbm/hr.
Imme.fiately after the loss of AC, turbine trip and reactor scram, the steam generator pressure and the RCS temoerature (by natural circulation) will be controlled by the operation uf 10 air operated turbine bypass valves (TSV) and the MSSVs.
The TSVs will continue to relieve system pressure to the condensers as long as the condenser vacuum remains accepta'le o
(the main circulating pump will be without power) and the IAS maintains air pressure to the valves.
If the TSVs are not operable, the MSSVs will lift to control steam generator pressure.
Redundancy As noted above, the TSVs will be available for steam relieving for some period following the loss of AC.
CYAPCo has stated that during a previous loss of AC, the condenser vacuum was not lost for accroximately 20 min cue to gravity flow of tN concenser 309 286
. cooling water.
However, the staff gave no credit for the TBVs steam relieving flowrate into the condenser since the condenser vacuum following the loss of AC would depend on unquantifiable factors (river height, decay heat, plant power at time of trip, hotwell level at the time of the trip).
The staff calculated the number of MSSVs required to maintain the RCS temperature at an acceptable level following a scram from full power after a loss of AC.
Based on an initial after scram decay heat level of 6.75%, the relieving rates shown above, and an energy removal capability of about 650 Stu/lbm (h at P = 1000 psig), two 7g 985 psig (Pset) MSSVs will maintain RCS temperature (at about 540 F) immediately af ter the loss of AC and scram.* Even though the MSSVs are passive devices, and as such are normally considered failure free, the staff considers 3 MSSVs necessary to maintain RC5 temperature following the event.
Location and Oceration The staff evalua'ed the equipment discussed above with respect to its location and operability during a loss of offsite AC.
The MSSVs are located in the main steam and feedwater penetration enclosure.
'Tnis quantity (2 MSSVs) does not c;asider any pressure transients on the steam system as a result at the loss of load.
309 287
r1.9.\\,. <.
They are self actuated and require no electrical power for operation.
They cannot be manually operated.
Atmosoheric Dumo Valve Steam Generator 1" Vents, and Other Vent Paths Task:
Removal of core decay heat by venting steam from the main steam system to atmosphere.
Discussion:
Immediately after the loss of offsite AC, turbine trip and reactor s t ra.7, the MSSVs automatically actuate to control steam system prassure and RCS temperature.
However, the Haddam Neck Turbine Bypiss Controller (TBC) provides additional steam relieving paths to (1) prevent and/or limit the coeration of the MSSVs* and (2) provide one means of RCS cooldown by venting steam to the main conienser.
Several other steam relieving paths are available for RCS cocidcwn.
The al controlled Atmospheric Oump Valve (ADV) vents steam from any or all of tne four 24" (CD) steam lines via a decay heat release header (CHRH).
The DHRH is pressurized from the 24" steam lines "Since the TBC is an active component, the staff consicered the MSSVs as the principal comoonents in initially controlling RCS temperature following the loss of AC.
However, tne TBC would normally act to prevent or limit MSSV oceration.
309 288
DRAR via 3" (00) lines just upstream of the non-return valves.
The DHRH is normally pressurized, and supplies the two turbine driven auxiliary feedwater pumps as well as the ADV.
The DHRH is located ia the upper level of the steam and feedwater penetration enclosure immediately outside the reactor containment.
The ADV is a 3" (00) valve which is operated by air pressure acting on a diaphram.
The poo. tion of the ADV is controlled by the air pressure on the actuat:..
ind is controlled from the control room.
Since CYAPC0 has not included any air systems in the minimt.m list of systems, we assume air pressure (control and service air) is lost following the loss of AC.
Under this condition, the ADV would fail shut, and could not be manually operated.
Conderser vacuum is normally initially established by two " hogging jets" and maintained by two sets of steam jet air ejectors ($)AEs).
The hoggir.g jets are single stage ven'.uri type air ejectors which use main steam supplied through a p; essure reducing valve and normally draw noncondensible gases directly from the condenser steam space, and discharge to atmosphere.
Each SJAE has two first stage and two second stage nozzles. The first stage nozzles, which use reduced pressure main steam, normally draw noncondensible gases directly from the condenser steam space and 309 289
discharge to the SJAE inter-co.- ~.nser which is cooled by main condensate.
The second stage nozzles also use reduced pressure main steam :nd draw from the inter-condenser and discharge to the after-condenser which is also cooled by main condensate. The condensed steam from the inter-and after-condensers is directed back to the main cc idenser, and the accumulated non-condensible gases are vented to atmosphere.
During the cooldown following a loss of AC, the SJAEs and the hoggers are used to remove energy frcm the steam generators by bleeding steam from the main steam lines.
The normal suction paths to the main condenser would be isolated.
The hoggers and the SJAEs are manually controlled devices and recuire adjustments as steam pressure varies.
The Auxiliary Feedwatec Pumps (AFPs) are utilized to provide feedwater to the steam generators during the loss of AC, and are described in the following section.
The AFPs are tur?ine driven pumps eacf1 rateo at 430 hp at full flow.
Thus, the AFPs are another means of removing steam generator (and RCS) ener; by venting main steam through the turbine exhausting to the atmosphere.
Each AFP turbine has a relief valve which opens at psig, and relieves about 38,000 lbm/hr.
Upstream of eacn main steam non-return lines a '" vent with two manually operated isolation valves is proviced to permit steam 309 290
I'- system venting during RCS and steam system startups.
These vents relieve directly to atmosphere in the steam and feedwater penetra-tion enclosure.
Thus, these four 1" vents provide another path for steam energy removal.
ihe licensee has noted that during a previous loss of AC, the condenser vacuum did not decay below 20" for 20 minutes.
ApparenJ.y, the arrangement af the weirs r0lative to the river and the condense, heights allowed enough reverse flow through the condenser tubes to remove the energy frcm the steam flow via the turbine bypass valves.
Although the staff and licensee could not quantify the reverse flow and resulting condenser cooling, this is certainly a potential technique for RCS energy removal following a loss of AC and scram.
The earliest time following the loss of AC and scram when each component, individually can remove the amount of core decay heat being adde ' to the RCS is shown below.
The staff used the core decay heat curve om ANS 5.1, the steam flow rates presented belcw, and an energy removal rata of 650 Stu/lba (h at P = 1000 psig).
7g 309 291
I q
(I I
l t hi k 3 Steam Flow RCS Full Power Corresponding Comocnent (o 1000 osig)
Energy Removal Fraction Time after Scram 6
ADV 133,000 lbm/hr 86.4 x 10 Btu /hr 1.39%
% 50 min 6
4 1" vents 162,700 lbm/hr 105.4 x 10 Btu /hr 1.69%
% 25 min 6
2 AFPs 32,000 lbm/hr 20.7 x 10 Btu /hr 0.33%
% 117 hours0.00135 days <br />0.0325 hours <br />1.934524e-4 weeks <br />4.45185e-5 months <br /> 6
Hoggers 9,300 lbm/hr 6.0 x 10 Btu /hr 0.10%
6 SJAEs 1,000 lbm/hr 0.7 x 10 Btu /hr 0.01%
6 AFP RVs 38,000 lbm/hr 24.6 x 10 Btu /hr 0.39%
% 55 hours6.365741e-4 days <br />0.0153 hours <br />9.093915e-5 weeks <br />2.09275e-5 months <br /> The time when the component energy removal capacility equals the decay heat input corresponds to the time when (1) clant cooldown commences if the component is used and (2) intermittent MSSV lifting would stop.
Redundancy To estaclish the degree of redundancy provided by the equipment discussed above, the staff and licensee performed scoping calcu-lations to determine the RCS cooldown times (e.g., time to go from 5d4 F to 350 F) using various comoinations of the above comoonents.
The staff's calculations are presented below.
Comoonent RCS Cooldown Time '2 l
ADV 225 F at 24.7 hrs 4 1" S/G vents 400 F at 25.4 nrs ADV - a vents 15.3 hrs a vents - 2 AFPs + SJAE:
3.3 hrs
- Hoggers 309 292
lT jf Ji 41 1 Note 1:
If the staff's calculations showed that the Tech Spec minimum auxiliary feedwater inventory was expended before the RCS was cooled to 350 F, then the temperature and time shown reflect the values when the 130,000 gal is consumed.
Note 2:
The staff's calculations assumed no credit for the colder auxiliary feedwater's n, rather, the staff conservatively f
assumed the saturation h corresponding to the steam pressure.
f This is an extra conservatism of at least 350 Stu/lba which would shorten the calculated cooldown times.
The staff also performed some scoping calculations to determine the ability of the RCS to be cooled after a 4 hr waic time at the hot shutdown condition.
We found that the time to reacn 350 F is about the same as if the cooldown had begun as soon as possible after the scram (with the 1" verts + 2 AFPs +
SJAEs + Hoggers).
From the table above, the RCS temcerature is 350 F about 8.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after the scram if the ccoldown is initiated ASAP after the scram
- We calculated that if the cocidown were initiated at SCRAM + 4 hrs, the RCS temperature "For the RCS cocidown by the steam relief from the a steam generatcr vents, 2 AFP turoines, 2 SJAEs, and the ncggers, the coolcewn starts about 10 min af ter the scram.
309 293 me-
._ is 350 F about 5.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> later, or 9.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the SCRAM.
However, this resulted in a significant cooldown rate initially, although still less than the Technical Specification maximum (76.2 F/hr vice 100 F/hr).
The staff also confirmed that one AFP has sufficient flow to keep the steam generator water level during all chases of this rapid cooldown.
CYAPC0 has stated that the RCS has been cooled down from about 540 F to 350 F in 12-15 hours using (not simultaneously) the ADV, steam generator vents, 2 AFP (turbines), SJAEs and the Hogging jets.
During the cooldown, the RCS flow was provided by 1 or more RCPs, which is an additional source of heat to the RCS.
Based on the staff's calculations, the licensee's experience, the availability of the two AFP relief valved,* and the water suoplies to be discussed in a following section, we conclude that there are sufficient means to cool the RCS to the RHR cut-in point prior to the expenditure of the Tech Spec minimum 130,000 gal.
Location and Ooeration The staff evaluated the equipment discussed above with respect to its location and operability during a loss of offsite AC.
The The ADV may not be available following the loss of AC if the air system is considered unavailable.
309 294 M
. table below gives the equipment's location, the places from where it may be operated, and the equipment's power supply.
Auxiliary Feedwater Fumos Task:
Provi ing steam generator makeup inventory whenever RCS a
temperature is > 350 F.
Discussion:
While the RCS temperature is above 350 F, tne core decay heat is removed by blea ing steam from the steam generators using the various components and flowpatns discussed previously.
The condensate and feedwater pumps are normally powered from offsite power so these components will not be available.
(The Emergency Diesel Generators have insufficient capacity to power these components following the loss of the station generator and offsite power.)
Each steam generator contains about 45,980 lbm of feedwater at full power, therefore, about 184,000 lbm are immediately available for primary system energy remcyal (by MS$V actuation).
The staff calculated the amount of energy 184,000 lbm would remove by vapori::ation.
These calculations show that this inventory is sufficient to maintain RCS temperature acceptacle without initiating any steam generator makeuo, for aporoximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
Eve, if 309 295
-w
1;()tilPMt tif LOC AI 10ti A
OPERAI10N POWER SUPPLY
~
Atmospheric Dump Upper level of the Control room and Valve steam and teedwater penetration enclosure
~
llogging Jets Intermediate Local manual og. erat.iori No ejection level of the only power is turbine building, needed near generator and of turbine SJAEs Inter'e,1iate level No electrical of the turbine bldg.
power is needed
{
1" steam vents Upper level of the local manual No electrical steam and feedwater operation only power is needed penetration enclosure ww AFP turbines (see dist.ussion of AFP)
(see discussion of AFP)
(See discussion of AFP)
AIP turbine itVs Adjacent to each RVs are sel t -actt. ited No electrical power AIP turbine when turbine casing is needed pressure reaches _
psig.
The CR operator Cduse the NVs lo open, and the RVs can also be manually.pened tra CD N<
Ch t
there were a 15 sec delay time between the loss of AC (loss of load and feedwater) and the reactor scram, (i.e., the steam generators are producing 100". pcwer without feedwater), the staff calculation shows that steam generators can remove the core decay heat for about 55 minutes before boiling dry.
Two turbine driven Auxiliary Feed Pumos (AFP) provide the steam gene,'ators with feedwater following a loss of offsite AC.
The AFPs are centrifugal pumps which take wa.ter from the demineralized water storage tank (OWST) and inject it into the four steam generators.
A buried pipe connects the DWST to the suctions of both AFPs.
The pumos discharge to a common header which branches into two carallel paths to the main steam generator feed system.
One path enters the turoine building via a buried pipe and connects to the bypass lines around the four main feed regulating valves.
The cther line passes througn the centainment wall and connects to enh steam generator main feed line downstream of the main feed r3n-return valve.
The AFP discharge header to the turbine building 's equipped with a normally open manual valve in the main steam and feedwater penetration enclosure and a check valve in the turoine building.
This line branches and connects to the four main feed regulating valve bypass lines upstream of the air operated main feed regulating valve bycass valves.
The bycass valves fail open on a loss of air pressure.
309 297 w
The AFP discharge header which enters containment from the main steam and feedwater penetration enclosure is equipped with a motor operated valve (MOV-35), which is normally controlled from the control room, and a check valve outside containment.
Inside contain-ment, the header branches into four supply lines, one for each steam generator.
Each of these lines has a normally open manual isolatir valve and a cneck valve.
MOV-35 is powered from MCC #7 (bus 7-6) which can be energized from emergency diesel genera:ce 28.
Also, MOV-35 can be manually operated with an installed han theel should a failure disable electrical pcwer to the valve.
The steam supply for the AFPs ccmes from the DHRH and the piping design is such that either AFP can receive steam from any one or all four steam generators.
From the CHRH, the steam supply for each AFP passes through a normally ope'1 manual valve and an air operated control valve which is normally operated from the control room.
The air operated valves fail shut on loss of air pressure, but a handwheel is provided on each valve to effect a local manual startup of an AFP.
Based on the previous discussion of after scram steam generator boil-off rate, sufficient time is available for an operator to manually start an AFP if the control air system were inocerable.
309 298
Redundancy Each AFP delivers about 450 gpm of auxiliary feedwater to the steam generators.
The staff calculated that this flow is sufficient to control and raise steam generator level about 30 sec after the scram.*
The auxiliary feed system (AFS) is capable o.
'hstanding a single active component failure without the loss of its ability to perform its design function.
However, the approximately 20 feet of discharge header shared by both AFPs and the single suction line from the CST render the system susceptible to a single passive failure which could disable both AFPs.
Also the passive failure of the condensate supply line from the CST to several non-essential systems could divert condensate away from the AFPs since the AFP suction line connects directly to the non-essential service header from the CST.
If the AFS were disabled by one of the above passive failures, the licensee has described a method for removing core decay heat by blowing down the RCS to the primary coitainment, via the pressurizer power operated relief valves, and injecting coolant with the safety AThe calculation shows that the vaporization rate at 30 seconds is equal to the AFP mass input rate.
2bb))-
N1 me-
DRA f injection systems.* Long term cooling could be accomplished by either ECCS recirculation or by use of the RHR system (after RCS temperatures and pressures were icwered sufficiently for RHR initiation).
Containment cooling would be provided by the Contain-ment Recirculation Fan Coolers.
An alternate method of feeding the steam generators, which is not permitted by procedures, involves blowing a steam generator completely dry and feeding by means of a low head pump (fire pump, condensate pump, etc. ).
The feasibility of these alternate decay heat removal methods will be pursued with the licensee.
Location and Operation The staff evaluated the equipment discussed above with respect to its location and operability during a loss of offsite AC.
The table below gives the equipment's location, the places from where it may be operated, and the equipment's power supply.
Water Source - DWST and PWST Task:
Provide water to the Auxiliary Feedwater System for steam generator makeup.
s This method is discussed in Reference 13.
The systems involved have been included in the minimum list of safe shutdown systems in Section 3.1.
3 09 300 M
LijullHifH LOCAT10ft ERAIl0!i POWER SUPPLY Auxiliary Feedwater Lower level of the Both pumps are operable tio electrical Putnps (2) steam and feedwater from the CR using an air power is needed penetration area controller which positions (north and south end) the steam inlet valves.
If air pressure is lost, the valves can be positioned manually.
MOV 35 (single Lower level of the Control room and local manual MCC #7(bus 7-6) valve which isolates steam and feedwater AfW from entering penetration area, Containment - 1 above south pump path of Af flow)
Auxiliary fRVs (4) feedwater Regulating Control room (using air Control air,
[
valve e.
of turbine signal) fail open o
building on loss of air i
feedwater MOVs FeeJwater Regulatin0 Control room (must he shut) valve area of and turbine building or feedwater reg.
Feedwater Re0ulating Centrol room Control air, fail shut valves must valve area of on :oss of air be shut turbine building u
O<
U C
DRAI
- al -
Discussion:
Both AFPs take a tuction i,'cm the DWST via the 10" hotwell makeup and rejection line.
This line leaves the bottom of the DWST and tranches into +.he following.
1.
A 6" hotw rej. ction line (i.e., flow f rom the condenser hotwell using the condensate pump (s)).
2.
A 6" combined AFP suction 3.
A 10" hotwell makeup line 4.
A 3" water treatment system line The CWST has a capacity of 100,000 gallons and Technical Specification requires a minimum of 50,000 gallons.
Follcwing the loss of AC power, the CWST can be filled from the following sources:
1.
The PWST via the PWTP(s) 2.
The Recycle PWST via the Recycle PWTP(s) 3.
The WT system The PWST has a capacity of 100,000 gallons and Technical Specification recuires a minimum of 80,000 gallons.
The CWST is filled from the PWST by the Drimary Water Transfer Pumps (PWTP' Each of the 2 PWTP can deliver 200 gpm at 180 psig.
309 302
JL Although there are no technical specifications requiring the availability and/or operability of the Recycle PWST and the Water Treatment System (WT), these are additional sources of water for the steam generators.
Since these systems are not included on the
" minimum systems" list, the staff gave no credit for their water sucplies.
Redundancy The 2 PWTPs are both powered from e same source, MCC 8-1.
Since the PWTO is utilized in the filling of the DWST frcm the PWST, if the MCC 8-1 were lost, the only way for the PWST water to get to the DWST or to the AFP suction) would be by gravity drainage.
The staff calculcted that the feed flow required ahen the raouired Tech Spec minimum DWST and steam generator inventory is expanded is about 69.5 gpm.
If the PWTPs are unavailable due to failure of MCC S-1, then gravity drainage from the PWST to the AFP suction must be at least 69.5 gpm, and the AFP NPSH requirement for this flow (about ft from
) must be satisfied.
The licensee states The staff calculated the c.4ximum langth of time the plant can stay at hot snutcown using the initial S/G water inventory and the Technical Scecification CWST minimum inventory.
These calculations show that accroximately 10.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of water sucoly are available before CWST makeuo (from the PWST) must te initiatec.
309 303
L -
The staff also calculated that the total (Technical Specification required) secondary makeup water inventory, 130,000 gallons, is enough to either keep the olant at hot shutdat, for 27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br />, or to complete a shutdown to the point of RHR initiation, 350 F,
'.1 about 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />.
These calculations take no credit for the initial S/G inventory, nor any condensate in the hotwell.
The cornpanent cooldown times previously discussed show that the ADV, steam generator vents, hoggers and AFP :urbines can cool the RCS to the point of RHR initiation (350 F) in about 3.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.
(If the ADV 4ere not available due to a single failure, then tne AFP RVs coulo be used to provide additional steam flow).
If the plant stayed at hot shutdcwn for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the scram.
then initiated RCS cooldown, the components 3scussed above could cool the RCS to 350 F in an additional 5.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or a total elapsed time from the SCRAM of 9.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
iherefore, these calculations show that even if the ADV was unavailable, and the RC3 stayed at hot shutdown for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> then initiated the cooldown, the RCS could be at the RHR initiation temperature tefore the DWST water is expended.
Woweve-the staff's calculations are only scoping calculations, and the licensee has stated that accut 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> are required for RCS cooldcun to 350 F-309 304
1 L Both AFP's take a suction from the hotwell makeup and rejection line.
Therefore, the plant has the ability to utilize the water inventory in the condenser hotwell for AFP suction.
This could be accomplished by starting a condensate pump and opening (throttling) the hotwell rejection valve (LCV 13173) or its bypass.
The hotwell has a capacity of about 43,200 gallons and a normal operating level of about 33,000 gallons.
However, the hotwell contents following a loss of AC and subsequent prnp t.p and reactor scram cannot be estimated since event thes and comoor ant coastdowns can' t ce accurately predictec.
Therefore, no credit can be g sen for this inventory.
However, it is nighly likely that there would be a significant amoi..c of ::endensate available to supplement the already mentioned sucplies (i.e., steam generator inventory, CW$T, PWST, Recycle P C and the WT system)
Location and Oceration The staff evaluated the equipment discussed above with respect to its location and operability during a loss of offsite AC.
The table below gives the equipment's location, the places from where it may ba operated, and the equipment's power supply.
Residual Heat Re g a' System Task:
Removal of core decay heat and RCC latent heat to cool the system from 25C F to 140 F.
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46 - _
Discussion The RHR loop is placed in service after the RCS temperature has been reduced to approximately 350*F and the pressure to less than 400 psig. The RER system then reduces the RCS temperature to 140 F approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> after shutdown, and operates continuously to maintain this temperature as long as it is required by maintenance and/or refueling o' wations.
The RHR 1000 consists of 2 heat exchangers, 2 RHR pumps, and the associated piping, valves, and instrumentation necessary for operational control.
During plant shutdown, coolant is withdrawn from the loop 1 het leg througn a single letdown line, pumped through the tube side of the residual neat exchangers, and then returned to the cold leg of loop 2 through a single discharge line.
Decay ' hat load is transferred through the RHR ceoler to the component cooling systems anich is cooled by component cooling water (normal conditions) or service water (emergency conditions).
An alarm will sound in the control room if the RHR flow drops to 2200 gpm.
Remotely coerated MOVs provide double valve isolation between the suction and discharge ends of the RHR system and the RCS system.
Electrical interlocks are associated with the inocard (closest to RCS) valves which prevent valve ocening when 9CS pressure is acove RHR design prossure.
Key control switches are provicec for the 309 307
f w=
J outboard (closest to RHR) valves to prevent their inadvertent actuation.
Normally, compor. ant cooling water flows througn the shell side of the RHR coolers.
However, following a LOCA, the plant Se: / ice Water is directed to the RHR shell side.
For this evaluation, the Service Water mode of RHR cooling is censidered.
Whan placing the RHR loop in service, the hot reactor coolant must be introduced into the residual heat removal loop gradually, by regulating the remote-manual control bypass valve and observing tne flow indication instrumentation.
The RHR to RCS return temcerature is controlled by throttling the RHR '7 0w out of the heat excnangers, and CW (or service water) is neld constant.
The RHR heat exchangers design conditions are 500 psi gage and 400 F for the tubes and 150 psi gage and 200 F for the shell.
Tubes are welded to the tube sheet to prevent coolant leakage into the component cooling system.
U-tube design permits e asion caused by large thermal differences between tube and shell.
The RHR pumps are norizor :1, centrifugal units designed for 500 psi gage and 100 F with a rated flow of 2,200 gpm at 309 308
r
. 300 ft minimum developed head.
Pump surfaces in contact with reactor coolant are austenitic stainless steel or equivalent corrosion resistant material.
Leakage of radioactive coolant to the atmosphere is reduced to nearly :.ero by mechanical seals.
Any leakoff from the seals drains to the sump and then is pumped to the naste disposal system.
Redundancy Each RHR pump is sized for one-half the maximum loop flow requirement, and each RHR cooler is sized for one-half the maximum required heat removal capability.
The maximum flow and heat removal requirements are when the RHR system is first placed on line 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> following a scram from full power.
Since there are 2 RHR pumps and coolers, a single failure does not completely disable the RHR system.
The use of 2 units also allows maintenance when the plant is enut cown and after core decay heat has diminished.
The RHR HX design parameters are given below 6
Shell side:
flow 1.9 x 10 lbm/hr T-95 F
- n T
105.54 out 309 309
DRET 6 Tube side:
Flow 1.1 x 10 lbm/hr T.
140 F in T
121.8 F out Under these conditions, each RHR HX is transferring about 6
20.2 x 10 Stu/hr to the CCW (or Service Water) system, or a total 6
RCS energy removal rate of about 40.A x 10 Stu/hr.
This power corresponds to the core decay heat at about 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> after the scram.
Sccping calculations done by the st2.ff for another PWR RHR system similar to Haddam Neck's show that if the flows remain the same, and the tube inlet temperature was 350 C instead of 140 F, tne heat transferred increases by a factor of about A,.
(The shell side temperatures will increase due to the larger amount of energy transferred).
Assuming this factor ( A ) for Haddam Neck, the total RHR heat transfer capacility with a 350 F tube inlet temperature 6
would be abcut 180 x 10 Btu /hr.
This corresponds to the core decay heat at about 200 seconds after tne scram (using ANS 5.1).
Therefore, scoping calculations indicate that the Haddam Neck RHR system with an inlet temperature of 350 F can remove about 2.9 3 core cecay heat.
Since we estimate tnat the auxiliary feedwater sucoly would last about
4 DRAFI 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> whers cooling down to 350 F, and 2.92% core decay heat corresponds to about 200 seconds after the scram, the RHR system performance, without any failures, is adequate during the loss of AC.
We performed additional scoping calcula2 ions on RHR single failures to determine the most limiting single failure.
These calculations were done for a PWR RHR system desicn similar to Haddam Neck's RHR system.* The calculations are summarized below:
RHR RPR RHR Tube Heat Removal Pumos M
Inlet Temo (4 of full cower) 2 2
14G 0.70%
2 2
050 3.07%
2 1
350 2.02%
1 1
350 1.53%
"The plant used, San Onofre 1, has RhR Hxs cooled by CCW system.
Haddam Neck's RHR Hxs, under a loss of AC, would be cooled by service water, wnose inlet tem:erature is constant (unlike the CCW system).
Therefore, the heat transfer for the Hadcam Neck RHR system could be greater than the San Onofre RHR system (e.g.
more than the -%.' actor used).
39 Sll
DRIFT The most limiting single failure from the standpoint of heat removal capacity is the loss, or unavailability of one RHR HX.
This reduces the neat transfer capability of the RHR system from 3.07% of full power to 2.02% of full power.
- However, 2.02% of full po' r corresponds to about 650 secondt after the scram, which is well before the estimated time when the auxiliary feedwater is expended.
Even if an RHR pump and HX were unavailable, the heat transfer capability of the remaining PHR train is about 1.53% of 'ull power, anc this power corresponas to about 40 min after the scram.
Since the RHR system has a single drop line with 2 MOVs, a single failure to open of either valve comoletely disaoles the RHR system.
If this occurred with the :eactor vessel head installed, the RCS would be allowed to neat back up and the steam venting mode of decay heat removal would be used.
If thia occJrred with the vessel head removed, the CCre Could be adecuately cooled by keeping it floeded using the CVCS or other systems.
Procedure ECP 3.1-20 Rev. 2 " Loss of R3sidual Heat Removal System" considers three different planc situations when the RHR system is lost-(a) witn cavity full, (b) with vessel head in place, and (c) with vessel head closure stucs more
.i 309 312
DRAF" than half removed.
In the case with the head in place, the heat removal is through the steam generators and plant temperacure will go above the cold shutdown value:.
Location Ooeration The staff evaluated the equipment discussed above with respect to its location and operability during a loss of offsite AC.
The table below gives the equipment's location, the places from where it may be acerated, ano the equipment's power suoply.
Service Water System The service water system (SWS) consists of four pumps whicn supply water from the Connecticut River to a dual header system in wnich two parallel full size heacers supply both the primary and secondo*y plants.
In the turbine building, each header divides into a primary supply and a seconaary supply header.
Power operated valves at the beginning of each secondary plant header automatically shut to secure secondary service water if offsite AC power is lost and the SWS is recuced to two pumps supplied by the diesel generators (Reference 2).
Similar provision is made for shutting off nones-sential supolies to primary plant equipment.
Also, remote manual valves can be used to substitute SWS flow for component cooling water system flow to the residual heat removal heat excnangers.
Each SWS branch connection t; a system heat load in both the primary 109 313
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During normal operation, both header systems operate in parallel.
The SWS pumps and the valves which switch RHR heat exchanger cooling supply from 'ither the SWS cr the component cooling water system are controllee from the control room.
Power supply for the pumps are from the 480 y emergency buses which can be pcwered from onsite or offsitt sources.
Recundancy During the snutdown and cooldown following the loss of AC, 2 service water pumps are powered from the emergency power sucplies.
Uoon the loss of all normal alternating current power and af ter the emergency power supply is established, one service water cump will be started automatically on each diesel generator.
If the first service water pump does not start, the power supply is automatically transferred to the second pump on that diesel generator bus.
Oceration and Instrumentation The staff evaluated the location of the various equipment discussed in this section, and the relevant instrumentation available to the control room operators.
The table below listed the equipment, its location, the places from wnere it can be operated, and the equipment's power suoply.
309 315
Equilti f{T LOCATION i
(Alluti POWER SUPPLY Service Water Pumps Screen ilouse t4anually started from P-37-1A 480V Bus 4 the control room, auto-P-37-18 480V Bus 5 matically started upon P-37-lC 480V Bus 6 loss of AC & subsequent P-37-10 480V Bus 7
- DG startup, and _
SWS lleader
\\utomatically upon loss Isolation Valves if AC and U
CD so L-4
i lY E Emerger.cy Power and Instrumentation System Task:
Supply a reliabie source of AC ard DC power to the necessary i
equipment and provide sufficient instrumentation to permit control of equipment functions.
Discussion The staff evaluation of the Emergency Power and instrumentation systems, their reliacility, operability, and the associated electric 0 distribution will be evaluated later under several SEP topics Chemical and Volume Control System Task:
Provide RCS makeup (due to the contraction of the coolan; during the cooldown) and borate the RCS to the necessary shutdown margin.
Discussion During snutdown and cooldown of the RCS t".c Chemical anc Volume Control System (CVCS) is used to borate the RCS and provide makeup to accommodate for thermal contraction of tne RCS coolant.
Two 360 gpm centrifugal charging pumps, powered from redundant emergency 480 V buses, and one 30 gpm positivc displacement pump are provided by the CVCS.
Charging to the RCS can be accomolished via redundant paths through either the normal charging line or the reactor coolant pumo seals.
Scrated water is provided to the pumps from the Scric 309 317
4 Acid Tank or the refueling water storage tank (RWST) via remotely operated valves.
These valves fail as is on loss of power and are operable from the control room.
Manually operated valves are available in the Primary Auxiliary Building (PAB) to bypass the remotely operated valves.
The 30 gpm metering pump can provide suf ficient charging flow for cool' cwn at a reduced rate (less than 50 F/hr) provided letdown is secured.
Redundancy Tha amount of RCS makeup during cooldown (and filling of the pressurizer) from 542 F to 200 F was calculated by the staff to be about 18,900 gal.
Therefore, the BAT alone (12,000 gal) does not provide enough RCS makeup for the plant cooldown to 200 F.
- However, there are numerous other sources of primary grade water available (e.g., VCT, RWST, PWST, and Recycle PWST).
To ensure the pressurizer level can be controlled during the most rapid cooldown, the staff used the coolJown calculations assuming all the steam venting paths discussed in $cction 3.2 and a.1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> cooldown it,itiation waiting time.
This cooldown rate was initial's (i.e., at TRCS = 544 F) slightly greater than 100 F/hr, the Tecnnical Specification maximum (during one hour internal).
Our
. iculitions 309 318
',D:
e
'l
.J
. show that a cooldown rate of 100 F/hr causes an RCS liquid contraction rate of about 133 gpm.
Since the capacity of each charging pump is about 360 gmp, the pressurizer level can be raised by only I charging pump during the most rapid cooldown we calculated, and the other charging pump provides a redundant RCS makeup capability.
The F.ddam Neck technical specifications state that 10,000 gal cf 8% solution boric acid are required to meet cold shutdown requirements.
Thus, the 12,000 gal at 12% Scric Acia Tank is sufficient, alone, to achieve the required sr.utccwn margin.
The RWST can also borate the RCS to the required shutdown margin.
Lccation and Oceration The staff evaluated the equipment discussed above with respect to its location and operability during a loss of offsite A.C.
The table below gives the equipment's location, the olaces from wnere it mav be operated, and the equipment's power supply.
309 319
DnsI[a
'E T 10f1 POWER SUPPLY L illPHENT LOCAT10fl J
Charging Pumps (2)
Separate cubicles on Operable from the control CPA -
and Metering Pump the 21'6" level l room and CPB -
of the PAB Metering Pump -
Volume Control Ahove charging Makeup to the RCI is No electrical power lank pumps on the via the makeup con-power is needed 35'6" level of trol system which is the PAB.
controlled irom the control reom arid HWSI SE corner of Level instrumentation and lleaters?
PAB (just North makeup control is from of containment) the control room.
RWST makeup Can also he initiated E
I BAl 15'6 level of the Level instrumentation lleaters?
PAB.
and
, makeup control tloric Acid leneath the BAT, Operable from control Room BAIP-1 1ransfer 11'6" level of and BATP-2 Pumps (BAIP)
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DRM TABLE 3.1 (Continued)
Quality Group Seismic Plant Plant gynponent s/Subsys tems R.G.
1.26 Design R.G.
1.29 Design Remarks Main Steam System MS Safety vt ms (16)
ASME Ill Category I r
Class 2 MS Atmospheric relief ASML 111 Category I (Ill CV-1201 )
Piping and valves from ASME Ill Category I Steam ge:1erator t.o and Class 2 including MS isolation valves and valves lilCV-1201, PICV-1206A, B
-+
and drain and trap isola-a tion valves lV-1212 and IV-1213 and vent. isola-tion valves.
Piping and valves ASME Ill Cate00ry I (blow off) from steam Class 3 generators to and including blow off valves IV-1312-1 thru 4 and 506, 515, 522 and 529.
Piping from valves PICV-1206A, B to aux. Teed pumps g
g including valves e
SV-1216, A, B t-a N
N
j TABLE 3.1 (Continued)
Quality Group Seismic Plant Plant Cgmponenta/Subsys:. ems R.G.
1.26 Design R.G.
1.29 Desigr.
Recarks Service Water System IsH9 SWS pumps (4)
ASME Ill
?
Category 1 Class 3 Piping and valves ASME III
?
Category I for containment Class 2 cooling up to and including valves 263 thru 2/0 Piping and valves AiME III
?
Category I TubesidesofCCWandspentk excluding above and C. lass 3 fuel HX' are ASME VIII, up to and including valves 606, 282, arid MOV-1, 2, 3, and 4 Chemical and Volusine Control System FOSAR Table 5.2.1-1 Charging pumps ASML lll No code Categ..y 1 Class 2 Piping (loop 1) let-ASME Ill ASA 5
down via regen IlX Class 1 B31.1 and letdown valves to and including t-a letdown isolation TV vaives L~1
DEFI TABtf 3.1 (Continueti)
Qual _ity Group Seismic Plant Plant Components / Subsystems R.G.
1.26 Design R.G.
1.29 Design Pemarks Regenerative lleat ASME III ASME VIII Category I Exchangers (3)
Class 1 Cases 1270tl dliti 12/3tl Piping loop (train line ASML III ASA B31.1 Cateje.y I via cooler to anti Class 1 inclutling valves 184/
dihl IV-18471 Pipitig ariti valves pump ASME III ASA B31.1 Category I siistliarge f rom arul Class I inclucting valves 399 0
anal 296 to RCS i
Piping anti valves from ASME III ASA B31.1 Category I pump (listi ai ge to Class 2 containment isolation valves 399 arit! 296 Piping f rom pump (lis-ASME Ill ASA B31.1 Category I charge via reactor Class 2 ct )lant pimips ariti t i om IV-181/ t o seal water llX tra CD W
tra N
_t::=
j IABLE 3.1 (Continued)
Quality Group Seismic Plant Plant Co gonents/ Subsystems R.G. 1.26 Design H.G.
1.29 Design Remarks Piping orid valves down-ASME III ASA B31.1 Category I strearii of letdown isola-Class 2 tion valves to the VCT including valves 343A, the interface with ACS, ICVil3A via the reactor coolant tilter and via relief valves 205, S2 and ICVl!38 Volume Control Tank ASME III ASA B31.1 Non-Category (VCT) connecting pip-Class 2 m
ing asid valves up to a
valves 1847 (reliet),
a 332 (reliet) ICV 112C, 246, 251 (relief), 324, 255 and 317 Piping anil valves from ASME III ASA B313.I Category I VCl to chargirig puriips Class 2 up to asid iricluding valves 33A.
'3, MOV-366, 320, 369, arid ti e HWS1 via 3/2 i
Pipirig arid valves down-ASME III ASA B31.1 Non-Category I g
streasii of ICV ll3A via Class 1 ae demisitsralizers to valve 343A, 220, 234 235 arid including demineralizers va till and drain valves N
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J
l TABLE 3.1 (Continued)
Quality Group Seismic Plant Mant Components / Subsystems R.G.
1.26 Design R.G.
1.29 Design Remarks Mixed-bed deminera-ASME III ASME VIII Non-Category I Class 3 portions of CVCS lizers Class 3 Case 1270N associated with deminera-lizers are not required for safe shutdown.
Volume control tank ASME III ASME Vill Category 1 Class 2 Case 12/0N Seal water injection ASME Ill ASML VIII Category I tilters Class 2 Case 1270h Boric acid filter ASME 112 ASME VIII Category I Class 3 Piping and valves from ASME III ASA B31.1 Category I BAT via boric acid pumps Class C and boric acid filter to valves 320, 369, 366, ICV 1120, 391, 342A Residual Heat Removal
-[Rilif$ys tem RilR pumps (2)
ASME III W spec.
Category I RHR pumps provide ECCS con-Class 2 No code tainment recirculation u
O<
u TV N
OTH I
TABLE 3.1 (Continued)
Quality Group Seismic Plant Plant Components / Subsystems R.G.
1.26 Design R.G.
1.29 Design Remarks RilR heat excliastgers (lube side) ASML III ASME VIII Class 2 Case 1720 il (shell side) ASME III ASME VIII Class 3 Piping arid valves to ASME III ASA B31.1 Category I RilR pump suction from Class 2 RWS1, contain;nent sump and valve /81 Piping aini valves from ASME Ill ASA B31.1 Category I i
ltllR pump discharge and Class 2 via kilR heat exchangers dild hypass LO RCS (valves U/2 A, B, 803),
CVCS, RWSI, containment sprey, recirculation line to RilR pumps, relief to RWSI, and cliarcoal fiIter spiay Process Instrumentation and Controls u Diesel generators flA Category I
.17 ^
^SER by DRL dated July 1, 1971 9
C
~O Diesel fuel oil, lul e ASME III
?
Category I
.17
- 9 oil, starting air Class 3 ljDCpowersupplysystem flA Category I N
CD
DEFT TAllLE 3.1 (Continued)
Quality Grout Seismic _
Plant Plant l
Components / Subsystems R.G.
1.26 Design R.G.
1.29 Design Remarks Distribution lines, f1A Cate<jory I switchgear, control boards and motor control centers 4
V Cw us Nw
. 4.0 SPECIFIC RHR AND OTHER REOUIREMENTS OF BRANCH TECHNICAL p0SITION 5-1 BTP 5-1 contains the functional requirements discussed in Section 3.0 and also detailed requirements applied to specific systems or areat of operation.
Each of these specific requirements is presented below with a description of the applicable Haddam Neck systam or area of operation.
4.1 RHR Svstem Isolation Recuirements The RHR system shall satisfy the isolation requirements listed below.
1.
The following shall be provided in the suction sidc of the RHR system to isolate it frcm the RCS.
(a)
Isolation shall be provided by at least two power-operated valves in series.
The valve positions shall be indicated in the control room.
(b) The valves shall have independent divers. interlocks to prevent the valves from being opened unless the RCS pressure is below the RHR system design pressure.
Failure of a power supply shall not cause any valve to change position.
(c) The valves shall have independent diverse interlocks to protect against one or both valves being open during an RCS increase above the design pressure of the RHR system.
2.
One of the following shall be provided on the discharge side of the RHR system to isolate it f rom the RCS:
(a) The valves, position indicators, and interlocks described in item 1 (a )-(c ).
(b) One or more check valves in series with a normally closed power-operated valve.
The powee-opertted valve cosition snail be indicated in t.N control room.
If the RHR system discharge line is used for an ECCS ' unction the power-ocerated valve is to be opened upon receipt of a safety injection
~30 309 3
w
A
\\.by 1 signal once the reactor coolant pressure has decreased below the ECCS design pressure.
(c) Three check valves in serias, or (d) Two check valves in series, provided that there are design provisions to permit pericdic testing of the check valves for leak tightness and the testing is performed at least annually.
Isolation of the RHR system from the RCS pressure on both the suction and RHR discharge legs is provided by two remotely controlled (from the control room) motor operated RHR valves in series.
The two suction and discharge valves nearer tne RCS a.e provided with an inter 1cck wnich prevents thei opening unless RCS pressure, as sensed by the four RCS pressure channels, is less than 400 spig.
The two valves farther from the RCS are administratively controlled 'n prevent misoperation by key locked switenes on the control room control board.
There is no interlock feature which automatically shuts the valves on en increase of RCS pressure above RHR design pressure (500 psig).
The RHR suction and discharge valves fai' "as is" on loss of power and have position indication in the control room.
The ECCS functions performed by the RHR system are to provide part of the flow path from the low pressure safety injection (LPSI) pumos to the core deluge supply lines and to supply, using the RHR pumps, long-term ECCS recirculation flow.
Following a postulated loss-of-coolant accident (LCCA), wnen 100,C00 gallons of water nave been injected by the safety injection (SI) systems, the RHR system is 97) 309 3"
'M
s s.$ started and aligned to take suction on the containment sump to recycle and cool the spilled reactor coolant.
If the RCS pressure restricts RHR flow to less than 1000 gpm, recirculation is accomplished by providing RHR flow to the charging pumps (iteference 6).
Tne core deluge flowpath joins the RHR dischar,e line outside of containmer.t; then, inside containment, the flowpath consists of an eignt inch diameter 'ine, whit.h branches from the RHR discharge line.
This eight inch line splits into two parallel (six incn diameter lines each of which again branches into two parallel (four inch diameter) lines 'leading to the reactor vessel.
Isolation of the RHR sys' from RCS pressure via the core deluge lines is proviced by a motor-operated valve and a check valve in each of the six inch diameter deluge lines.
The position of the motoroperated valves is displayed in the control room.
The motor-operated valves open immediately upon receipt of a safety injection (SI) signai.
Based on tne above description, the RHR system deviates from tnese BTP provisions:
(a) The pcwer operated valves in the core delute lines open on the SI signal before RCS pressure drops below RHR design pressure.
(b) The RHR suction and discharge isolation valves do not have independent, diverse interlocks to prevent opening tne valve:
until RCS presscre is telow RhR design pressure.
)
-Se a!
wi n\\ (c) The RHR isolation valves have no interlock feature to close them when RCS pressure increases above the RHR design pressure.
The deviation from the BTF for the core deluge flow paths will be evaluated in the SEP integrated assessment of the Haddam Rock Neck plant.
The staff has concluded that no immediate action on this deviation is required because of the high degree of reliability of the check valves in these paths.
In addition, any delay in opening of the core deluge motor-operated valves would have to be assessed in light of its effects on the Haddam Neck ECCS analysis.
The deviation for lack of isolation valve diverse i:iterlocks is acceptable becr;se in addition to the single interlock pressure signal on the valves closer to the RCS, the other two valves are key-lock type and are under administrative controls to prevent opening prior to the interlock permissive pressure.
By procedure, none of these valve is opened unless RCS pressure is below 400 psig.
The deviation for lack of automatic suction valve closure on increas-ing RCS pressure is acceptable because, in addition to the administra-tive and procedural controls on these valves, an alarm is provided at 400 psig to warn the operator that RCS pressure is increasing towards RHR design pressure whenever the Overpressure Protection System (CPS) is enabled.
Upon receipt of an alarm, the control 309
-)
me
_ room operator would be able to terminate the pressure increase or to perform the required procedural steps to isolate the RHR.
(See the following discussion of BTP provision C.1, " Pressure Relief Requirements" for information on the OPS. )
4.2 "C.
Pressure Relief Reauirements The RHR system shall satisfy the pressurc relief requirements listed below.
1.
To protect the RHR system against accidental overpressuriza-tion when it is in ooeration (rot isolated from the RCS),
pressure relief in the RHR system shall be provided with relieving capacity in accordance with tne ASME Soiler ano Pressure Vessel Code.
The most limiting pressure transient during the plant operating condition when the RHR system is not isolated from the RCS shall be considered when selecting the peessure relieving capacity of the Rnd system.
For example, during shutdown cooling in a PWR with no steam bucble in the pressurizer, inadvertent operation of an additional cnargirg pump or inadvertent opening of an ECCS accumulator valve should be considered in selection of design bases."
The RHR relief valve has a setpoint of 500 psig and a ret ief capacity of 960 gpm (Reference 11).
This relief valve was not sized to accommodate the most limiting pressure increase transients which could be postulated to occur during RHR cooling of the RCS.
However, the licensee has analyzed these most severe potential pressure increase transients during the NRC generic revie < of RCS cverpressurization events (Reference 7).
To prevent and mitigate these transients, the licensee has ma a several procedural and hardware modifications.
The harcware modifications constitute the Overpressure Protecti0n System (CPS).
The OPS relieves RCS pressure via spring safety valves connected to
.b-ang JU'
L the pressurizer and is designed to relieve the pressure increase r?sociated with the worst postulated mass and heat input transients (with exception of thc.-igh pressure safety injection pump mass input case for which the licensee has implemented administrative contrals) assuming a water-solid RCS and the most limiting single active failure.
When the RHR system is cooling the RCS, the OPS also provides overpressure protection for the RHR system.
The staff has evaluated the effects of the worst case mcss and heat input events to establish the capability of the OPS and RHR relief to prevent RHR overprassurization.
Por the mass input case presented in Reference 7, the combined OPS and RHR reliefs prevent RHR pressure frcm exceeding 550 osig wnich is 110% of RHR r:esign pressure and is acceptable.
For the heat input case, the data supolied and referenced (Reference 8) by the licensee were extrapolated to include a 50 F steam generator to RCS temperature difference at an RCS temperature of 300 F since the data in Reference 8 only applied to heat input transients associated with RCS te:,,peratures from 180 F to 250 F.
Three hundred cegree; f :renheit was chosen because this is the temoerature at whicn the licensee initiates RHR cooling.
The staff determined tnat pressure transients wnir.n.ould result frcm neat input wculd not exceed 110% of RHR design pressure it both OPS IbS 30'1
. mags-
- reliefs and the RHR relief functioned.
Also, it was determined that RHR overpressure would not occur at an RCS temperature of 200 F even assuming the single failure of one of the three valves.
The staff then considered the potential for initiating a heat input transient at Haddam Neck when RCS temperature is between 250 F and 300 F.
For a heat input transient to occur, the heat frot the steam generators must be rapidly transferred to a cooler RCS in a water-colid condition.
The means of rapid heat transfer is forced convection caused by a reactor coolant pumo start In its review of overpressurization transients, the staff cunsidered steam generator to RCS temperature differences in excess of 50 F to be unlikely occurrences.
The administrative measures proposed by ti,e lic,asee to reduce the probabili*y of heat impact transients were to 1) minimize plant operation in water-solid conditions, 2) maintain no greater than a 50 F steam generator to RC'
'ture difference, and 3) prohibit reactor coolant pump start when steam generator temperature is above RCS temperature. Although items 1 and 2 above would not necessarily preclude a heat addition event, item 3 would.
Also, the staff examined the potential for initiating a heat input event during plant cooldown which it the time that steam generator temperature may exceed RCS temperature with RCS temperature above 250 F.
The licensee initiates RHR cooling at 300 F after cooling down to that point with the steam generators.
Continuing the cooldcwn with the RHR system and with reactor coolant pumps secured.ould result in the 50 e difference being fully develcped at an RCS temcerature of 250 F.
As noted 309 336 M
. before, a heat input event at this temperature would not result in RdR overpressurization even with an assumed sirigle failure.
Based on the above discussion, we concluded that the OPS and RHR relief provide sufficient RHR overpressure prote: tion for RCS temperatures of 250 F or less and that the licersee's procedures acceptably minimize tne likelihotd of a heat audition overpressure transient at an RCS temperature above '50 F.
Therefore, the OPS and RHR relief meet the pressure relief requirements of the STP.
At present the licensee has proposed to enable t'e CPS prior to RHR initiation by procedure, and has also proposed making this GPS /RHR sequencing part of the facility technical specifications.
The Haddam Neck OPS electrical review is currently underway within NRC.
4.3 "2.
Fluid discharged through the RHR system pressure relief valves must be collected and contained such that a stuck open relief valve will not:
(a) Result in flooding of any safety-related equipment.
(bi Reduce the capability of the ECCS below thr' needed to mitigate the consequences of a postulated LUCA.
(cj Result in a non-isolatable situation in which the water provided to the RCS to maintain the core in a safe condi-tion is discharged outside of the containment."
)
6
. fluid discharged through the RHR relief valve is directed to the Refueling Water Storage Tank (RWST) and cannot cause the flooding of any safety-related equipment.
Since this valve is connected to the discharge of the RHR pumps, if the valve should stick open core deluge flow and post-LOCA recirculation flow would be affected.
The RHR relief valve flowrate is 960 gpm at a relie/ing pressure of 500 psig.
In a post-LOCA scenario, the pressure felt at the RHR relief will be either LPSI pump discharge pressure, if core deluge flow is being delivered, or RHR pump discharge pressure, if recircula-tion is in progress.
As noted in Reference 9, only one LPSI pump, with a flowrate of 5000 gpm at a discharge pressure of 252 psig, and only one RHR pump, with a flowrate of 2200 gpm at a discharge pressure of 130 psig, are required to be operable to supply 100% of core deluge and recirculation requirements.
The Haddam Neck ECCS are provided with two LPSI anJ two RhR pumps to meet the redundancy requirements posed by the single failure criterion of the ECCS Interim Acceptance Criteria.
Therefore, the leakage through the RHR relief (less than 960 gpm).ould result in a esser reduction in ECCS flow than the loss of a LPSI pump (5000 gpm) or an RHR pumo (2200 gpm) wnich losses have been postulated as single failures in the ECCS analysis.
309
W DRN'l The technical specificaticn requirement for ECCS pump operability at Haddam Neck specify that one train of ECCS must be operable whenever the reactor is critical.
(One train of ECCS includes one RHR pump and one LPSI pump.) However, no technical specification reqctrement exists to govern the allowed outage time of the other ECCS train.
Such a requirement should exist to maintain the ECCS redundancy assumed in the ECCS analysis.
This technical specifica-tion requirement, as well as all of the Haddam Neck technical spec *ications will be reevaluated under SEP Topic XVI, " Technical Specifications."
The fluid discharged through the RHR relief valve goes to the RWST and is still available for RCS cocling via the hign and low pressure safety injection systems.
However. during post-LOCA recirculation, the fluid may be radioactively contaminated, and leakage of this fluid to the RWST would not be acceptable.
Isolation valves in the RHR relief piping are installed with one isolation valva at the relief valve inlet and one in the relief valve discharge line outdoors near the RWST.
These valves 1.re both manually operated valves.
The isolation valve near the RWST (SI-V-878) can be shut to isolate RHR recirculatinn flow leakage through the RHR rel' valve.
4.4 "3.
If interlocks are provided to automatically close the isolation valves when the RCS pressure exceeds the RHR system design pressure, adequate relief capacit" shall be provided during the time period while the valves ?re closing."
}f[
' As noted above, these interlocks are not provided.
However, the overpr'issure protection afforded oy the RHR relief valve in conjunc-tion with the OPS would provide adequate relief capacity to prevent RCS pressure frore exceeding RHR design pressure.
4.5 "D.
Pumo Protection Reauirements The design and operating procedures of any RHR system shall have provisions to prevent damage to the RHR system pumps due to overheating, cavitation or loss of adequate pump suction fluid."
The features of the Haddam Neck plant designed to prevent damage to the pumps are provision for pump cooling, a flow recirculation line, and a low flow alarm.
Also, indications are available in the control room for RHR ficw and valve positions of all remotely operated RHR valves.
Either the Service Water System or the Component Cooling Water System can ce aligned to provide cooling watar to the RHR pump bearings and lubricating oil cooler to help prevent pump overheating.
An alarm is providad to alert the operator to a hign temperature condition in the pump bearings.
In addition, a 3/4-inch line permits the recirculation of some RHR pump flow from the discharge side to ohe suction side of the pump to prevent overheat-ing caused by no-ficw pump operation.
An RHR system low flow alarm alerts the operator if a low flow condition occurs with an RHR pump in operation.
The availability of adecuate net positive suction head (NPSH) will be evaluated during *he SEP review of Topic VI-7.E, "ECCS Sump Design and Test for Recirculation Mode Effectiveness."
309
,M
DUfI _
4.6 "E.
Test Recuirements The isolation valve operability and interlock circuits must be designed so as to permit on line testing when operating in the RHR mode.
Testability shall meet the requirements or IEEE Standard 338 and Regulatory Guide 1.22.
The preoperational and initial startup test program shall be in conformance with Regul. tory Guide 1.68.
The programs for PWRs shall include tests with supporting analysis to (1) confirm the adequate mixing of borated water added prior to or during cooldown can be achieved under natural circulation conditions and permit estimation of the times required to achieve such nixing, and (2) c~onfirm that the cooldown under natural circula-tion conditions can be achieved within the limits specified in th. emergency operating procedures.
Comparison with performance of previously tested plants of similar design may be substituted for these tests."
The RHR isolation valve coerability and interlocks cannot be tested during the RHR cooling mode of operation.
This test requirement is not applicable to the Haddam Neck facility since the installed interlocks function only when the RHR isolation valves are shut.
Regulatory Guide 1.68 was not in existence when the Haddam Neck preoperational and initial startup testing was accomplisheu.
However, a (natural circulatian) tert was performed to confirm that cooldown under natural circulation conditions is possible (Reference 10).
The test involved timing the transit of a cold slug" of RCS water as it flowed, under natural circulation, around one of the Haddam Neck's four RCS coolant locps.
The test results indicated that a natural circulation loop flow of approximately 3%
of design loop ficw could be achieved about one hour af t-ar reactor h
$Er 8 P* shutdown. This test and subsequent ooservations o' natural circula-tion flow demonstrate that adequate flow for core cooling exists.
to testing has been performed at u ddam Neck to determine the ade-a r,uaty of baron mixing under natural circulation flow conditions.
}'owever, the staff believes that, with the boric acid concentrations used for shutJown, adequate baron mixing will occur under na.1ral circulation flow.
4.7 "F.
Coerational Procedures The operational procedures for bringing the plant from normal operating power to cold shutdown shall be in conformance with Regulatory Guide 1.33.
For pressurized water reactors, the operational procedures shall include specific procedures and information required for cooldown under natural circulation conditions."
Operational procedures reviewed in this i.omparison of the Haddam Neck to BTP RSB 5-1 are discussed in Section 2.0.
All of the procedures required the use of nonsafety grade equipment for portions of the shutdown operation.
No procedures exists for shutdown and cooldown using safety grade equipment only, but a procedure exists for pro-ceeding to cold shutdown conditions from oucice the control room. No procedure exists for plant cocidown using the ECCS system as described in the Section 3.2 discussion of the Auxiliary Feed System.
The need for procedures using only safety grade equipment is not identified in Regulatory Guide 1.33 but stems from the provisions of STP RSS 5-1 309 3 A2
, and SEP Topic VII-3.
The staff will consid..' requiring the licensee to develop these procedures during the integrated SEP assessment of the plant.
Therefore, we conclude that the procedures for safe shutdown and cooldewn are in conformance with Regulatory Guide 1.33.
The plant operating procedures also include a procedure for cooldown using natural circulation.
4.8 "G.
Auxiliary Feedwater Sucoly The seismic Ca _egory I water supply for the auxiliary feed-water system for a PWR shall have sufficient inventory to permit operation at hot shutdown for at least four hours, followed by cooldown to the conditions permitting operation of the RHR system.
The inventory needed for cooldown shall be based on the longest cooldown time naeded with either only onsite or only offsite power available with an assumed single failure."
For the discussion of this BTP provision, see Section 3.2.
DRAFT 5.0 RESOLUTION OF SEP TOPICS The SEP topics associated with safe shutdown have been identified in the INTRODL'CTION to this assessment.
The following is a discussion of how the Haddam Neck Plent meets the safety objectives of these topics.
5.1 Ty ic V-10.8 RHR System Reliability The safety objective for this topic is to ensure reliable plant shutdown capability using safety grade equipment subject to the guidelines of SRP 5.4.7 and BTP RSB 5-1.
The Haddam Neck systems have been compared with these criteria, and the results of these comparisons are discusssed in Section 3.0 and 4.0 of this assessment.
Based on these discussions, we have concluded that the systems fulfill the topic safety objective subject to the resolution of the following in the SEP integrated assessment:
1.
The requirement for plant operating procedures to shutdown and cooldcwn using safety grade systems caly.
2.
The requirement for a procedure to cooldown using the ECCS following loss of main and auxiliary feed.
7 309 x-
BRm S.2 Taoic V-11.A Recuirements for Isolation of Hich and Low Pressure Systems The safety objective of this topic is to assure adequate measures are taken to protect low pressure system connected to the pri ary system from being subjected to excessive pressure which coald cause failures and in somr. cases potentially cause a LOCA outside of containment.
This topic is assessed with regard to the isolation requirements of the RHR system from the RCS.
As discussed in Sections 4.1 and 4.2, subject to the following item, which will be considered in the SEP integratec assessment, adequate overpressure protection exists for the RHR system:
1.
The need for inte. iocks on the core deluge motor-operate valves tc prevent opening until RCS pressure is below RHR design pressure.
5.3 Tooic V-ll.B RHR Interlock Recuirements The safety objective of this topic is identical to that of Topic V-ll.A.
The staf f conclusion regarding the Haddaa Neck valve interlocks, as discussed in Sccti;1 4.1, is that acequate interlocks exists with the Uk
bRAFT exception of the potential need for interlocks on the core deluge motor operated valves.
5.4 Tooic VII-3 Systems Reauired For Safe Shutdown The Safety objecti<es of this topic are:
1.
To assure the design adequacy of the safe shutdown system to (a) initiate automatically the operation of appropriate systems, including the reactivii.y control systems, such that specified acceptable fuel design limits are not exceeded as a result of anticipated operational occurrences or postulated accidents, and (b) initiate the operation of systems and components required to bring the N ant to a safe shutdown.
2.
To assure that the required systems and equipment, including necessary instrumentation and controls to maintain the unit in a safe condiuion during hot snutdown are located at appropriate locations outside the control rocm and have a potential capabi-lity for subsequent cold shutdown of tne reactor through the use of suitable procedures.
3.
To assure that only safety grade equipment is required for a WR plant to bring the reactor coolant system from a high pressure condition to a low pressure cooling condition.
BRM _
Safety objective 1(a) will be resolved in the SEP Design Basis Event reviews.
These reviews will determine the acceptability of the ple-*
response, including automatic initiation of safe shutdown related systems, to various Design Basis Events, i.e., accidents and transients (Reference 12)
Objective 1(b) relates to availability in the control room of the control and instrumentation systems needed to initiate the operation of the safe shutdown systems and assures that the control and instrumentation systems in the control room are capable of following the plant shutdown from its initiation to its conclusion at cold shutdown conditions.
The ability of the Haddam Neck Plant to fulfill obje 'ive 1(b) is discussed in the preceding sections of this report.
Based on these discussions, we conclude t.1at safety objective 1(b) is
.1et by the safe shutdown system at Haddam Neck subject to the findings of related SEP Electrical, Instrumentation, and Control Topic reviews.
Safety objective 2 requiies the capability to shutdown to both hot shutdown and cold shutdown conditions using systems, instrumentation, and controls located outside the control room.
.addam Neck procedure E0P 3.1-42, " Plant Operation Outside Control Room," provides the necessary steps to take the plant to the hot shutdown condition and to proceed from there to the cold shutdown ccndition.
The procedure, which was made effective on July 12, 1978, contains the 309 "347
I detailed steps required to achieve the cold shutdown condition; however, it does not define the water sources for the auxiliary feedwater pumps.
Portable battery powered instrumentation is prc~
vided at the emergency control pou? in the cable vault penetration area to measure pressurizer pressure and level, reactor coolant temperature and steam generator level however, the procedure does not contain a program to ensure that the e tteries are functional.
- The various work locations where operator action or attendance is required have been described in the procedure; however, the duty stations of the individual positions of the operating staff have not been defined, therefore, an individual would not know his area of responsibility without further instructions.
The procedure does not address the need for emergency communication equipment at the various duty stations.
Local instrumentation is used for the Boric Acid Mix Tank level.
Service Water Flow, and Steam Generator Presure.
The emergency control point is located in the low 3r level of the cable vault.
The cable vault area has an automatically initiated CO 2
fire protection system.
It appears that the initiation of the CO 2
system may require evacuation of the emergency control point.
In
- his case, the time period during which control point would be unmanned would be very short and would have a negligible imoact on the shutdown anc cooldewn procedure.
309
'3 k b
s j Based on the information provided in Procedure E0P 3.1-42, and obtained during the safe shutdown site visit, we conclude that the Haddam Neck Plant meets safety objective 2 of Topic VIII-3 with the exception of procedural shortcomings regarding maintenance of batteries for portable instruments, assignments of shutdown duties for shift personnel, emergency communication methods, and water sources for the auxiliary feed puT.ps.
The licensee will be requested to modify his procedures to alieviate these shortcomings.
The adequacy af the safety grade classification of safe shutdown systems at Haddam Neck, to show conformance with safety objective 3, will be completed in part under SEP Topic III-1, " Classification of Structures, Components, and Systems (Seismic and Quality)," and in part under the Design Basis Event reviews.
Table 3.1 of this report will be used as input to Topic III-l.
. 4- --
5.5 Tooic X Auxiliary Feed System (AFS)
The safety objective for this topic is to assure the AFS can provide adequate cooling water for decay heat removal in the event of loss of all main feedwate using the guidelines of SRP 10.4.9 and CTP AS810-1.
The Haddam Neck AFS is described in Section 3.2.
This system has been compared with SRP 10.4.9 and BTP ASB 10-1 with the following conclusions:
h
4
- 8? -
1.
The Haddam Neck Plant including the AFS will be reevaluated during the SEP with regard to internally and externally generated missiles, pipe whip and jet impingement, quality and seismic design requirements, earthquakes, tornadoes, floods, and the failure of nonessential systems.
2.
The AFS conforme to General Design Criteria (GDC) 19, " Control Room," GDC 45, " Inspection of Cooling Water Systems," 46,
" Testing of Cooling Water Systems" and Regulatory Guide 1.62,
" Manual Initiation of Protection Actions." GDC 5, " Sharing of 4
Structures, Systems, and Components," is not applicable.
3.
A passive failure of the common pump suction or discharge headers or the non e. ential condensate service line, to which the AFS suction line is attached, would prevent the AFS from supplying feedwater to the steam generators even without an assumed con-current single active failure.
The low probability of a passive failure in the low pressure se: tion line or in the discharge line which is periodically tested under the licensee's inservice inspection program alleviates the need for any immediate corrective measeres.
The staff intends to examine.he need for a long-term improvement in the redundancy of the AFS at Haddam Neck.
This will be considered in the SEP integrated assessment of the plant.
309 350
. 4.
Although the AFS does not meet the provision for power diversity of BTP ASB 10-1, the system design does permit emergency feeding of tne steam generators with an assumed loss of ali AC power; but manual operation of valves in the steam supply lines to the AFS turbines is required.. In this case, manual valve operation is permissible bec.ause with no feed, the steam generator water inventory can remove decay heat for approximately one hour.
5.
The staff is continuing to evaluate feed system waterhammer for tne Haddam Neck Plant on a generic basis.
SEP Topic V-13, "Waterhammer," auplies.
6.
The AFS is not automatically initiated and the design does not have capability to automatically terminate feecwater flow to a depressurized steam generator and provide flow to the intact steam generator.
This is accomplished by the control room operator.
The effect of this provision will be assessed in the main steam line break evaluation for Haddam Neck.
7.
The technical specifications for the AFS will be reevaluated aga'ast current requirements under SEP Topic XVI, " Technical Specifications."
309 L \\
DRlFI
~
6.0 REFERENCES
1.
CYAPC0 letter D Switzer to A. ScNencer dated Jene 29, 1977 transmitting the Haddam Neck Inservice Inspection Program.
2.
Facility Description and Safety Analysic Report for the Haddam Neck Plant as amended.
3.
Supplement to the aafety Evaluation by the Directorate of Reactor Licensing, U.S. Atomic Energy Commission, December 27, 1974.
4.
Supporting Information for the Connecticut Yankee Full Term Operating License Application, December 1969.
5.
Safety Evaluation by the Directorate of Reactor Licensing, U.S.
Atomic Energy Commission, July 1, 1971.
~
CYAPC0 letter D. Switzer to R. Purple dated September 29, 1975.
7.
Specific Plant Report, Low Temperature RCS Overpressure Protection for Connecticut Yankee, August 1977, transmitted by CYAPCO ietter c;ated September 7,1977.
752 309
J j 8.
Westnghouse Analyses of Overpressure Transients July 1977.
9.
Technical Specifications, Appendix A to Facility Operating License DPR-61 for the Haddam Neck Plant.
10.
CYAPC0 Report " Reactor and Plant Performance C-ineering Tests and Tests and Measurements," October 1969, appended to AEC Division of Compliance letter dated December 1969.
11.
CYAPCO letter, D. Switzer to A. Schwencer, dated March 1, 1977.
12.
Systematic Evaluation Program, Status Summary Report, NUREG-0485.
13.
CYAPC0 letter, D. Surtzer to K. Galler, dated February 5,1975 transmitting report " Effects of a High Energy Piping System Break Outside of Contairment."
309 J y ~b 4