ML19274E045
| ML19274E045 | |
| Person / Time | |
|---|---|
| Site: | Yankee Rowe |
| Issue date: | 02/14/1979 |
| From: | Ziemann D Office of Nuclear Reactor Regulation |
| To: | Groce R YANKEE ATOMIC ELECTRIC CO. |
| References | |
| TASK-05-10.B, TASK-05-11.B, TASK-07-03, TASK-10, TASK-5-10.B, TASK-5-11.B, TASK-7-3, TASK-RR NUDOCS 7903070437 | |
| Download: ML19274E045 (98) | |
Text
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.p j/ %'4, UNITED STATES f
NUCLEAR REGULATORY COMMI5310N
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WASHINGTON, D. C. 20555 February 14, 1979 g,
ss je Docket No. 50-29 flc. Robert H. Groce Licensing Engineer Yankee Atomic Electric Company 20 Turnpike Road Westboro, Massachusetts 01581
Dear Mr. Groce:
Enclosed is a document entitled "SEP Review of Safe Shutdown Systems for the Yankee-Rowe Nuclear Power Plant," which contains draft evaluations for SEP Topics V-10.B, V-ll.B Vll-3, and X.
Other Topics (V.ll-A and 1X-3) are also addressed to the extent necessary to assess the functional adequacy of the safe shutdown systems.
You are requested to examine the facts upon which the staff has based its evaluations and respond either by confirming that the facts are correct, or by identifying any errors.
If in error, please supply corrected information for the docket. We encourage you to supply for the docket any other material related to these topics that might affect the staff's evaluation.
Your response within 30 days of the date you receive this letter is requested.
If no response is received within that period, we will assume that you have no comments or corrections.
Si ncerely, s
/
~.
Dennis L. Ziemann,~ Chief Operating Reactors Branch *2 Division of Operating Reactors
Enclosure:
1.
Safe Shutdown Review for Yankee-Rowe cc w/ enclosures:
See next page 7903070431
r. Rcber: H. Groce February 14, 1979 Cc
- '. Lawrence E. Minnick, President Yankee Atonic Electric Cenpany 23 TJrnpike Road Westboro, Massachusetts 01531 Green #ield Connunity College 1 Cellege Drive Greenfield, Massachusetts 01301 K M C Inc.
ATTft : fir. Jack McEwen 1747 Pennsylvania Avenue, fl. 'i.
Suite in50 Washington, D. C.
20006
SEP Review of Safe Siiutdown Systems for the Yankee Rowe Nuclear Power Plant
TABLE OF CONTENTS Page
1.0 INTRODUCTION
1 2.0 DISCUSSION...................
7 2.1 Normal Plant Shutdown and Cooldown......
7 2.2 Shutdown and Cooldown with Loss of Offsi te Power......
9 3.0 CONFORMANCE WITH BRANCH TECHNICAL POSITION 5-1 FUNCTIONAL REQUIREMENTS...................................
11 3.1 Background............
12 3.2 Functional Requirements..........................
15 Table 3.1 Classification of Shutdown Systems...........
57 4.0 SPECIFIC RESIDUAL HEAT REMOVAL AND OTHER REQUIREMENTS OF BRANCH TECHNICAL POSITION 5-1....
65 4.1 Residual Heat Removal System Isolation Requirements...
65 4.2 Pressure Relief Requirements.......................
68 4.3 Pump Protection Requirements................
77
- 4. 4 Test Requirements................................
79 4.5 Operational Procedures..............
80 4.6 Auxiliary Feedwater Supply...........
81
- 5. 0 RESOLUTION OF SYSTEMATIC EVALUATION PROGRAM TOPICS........
82 5.1 Topic V-10.8 RHR System Reliability.
82 5.2 Topic V-11. A Requirements for Isolation of High and Low Pressure Systems................
86 5.3 Topic V-11.B RHR Interlock Requirements..
86 5.4 Topic VII-3 Systems Require for Safe Shutdown.
89 5.5 Topic X Auxiliary Feed System..............
92
WAFT
1.0 INTRODUCTION
The Systemat'ic Evaluation Program (SEP) review of the " safe shutdown" subject encompassed all or parts of the following SEP topics, which are among those identified in the November 25, 1977 NRC Office of Nuclear Reactor 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-11.A) 3.
RHR Interlock Requirements (Topic 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 June 13-16, 1978, afforded the team the opportunity to
~
obtain current information and to examine the applicable equipment and' procedures, and it also gave the licensee (Yankee Atomic Electric Company) the' opportunity to provide input into the review.
The review included specific system and equipment requirements for remaining in a hot shutdown condition (T
~ 540 F, Reactor shutdown)
AVE and for proceeding to a cold shutdown condition (T
~ 330 F).
AVE The review for transition from operating to hot standby 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, except as noted below:
Topic V-11.A (Requirements for Isolation of High and Low Pressure Systems) was examined only for application to the Residual Heat Removal (RHR) system.
Other high pressure / low pressure interfaces were not investigated.
Topic VII-3 (Systems Required for Safe Shutdown) was completed except for determination of design adequacy of the systems.
Topic IX-3 (Station Service and Cooling Water Systems) was only reviewed to consider redundancy and seismic and quality classification 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) System"; 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 and are used in the review of facilities being processed for operating licenses.
This comparison of the existing systems against the current licensing criteria led naturally to at least a partial comparison of design criteria, which will be input to SEP Topic III-1, " Classification of Structures, Components and Systems (Seismic and Quality)." This report will also be reviewed for its application to the resolution of other topics.
As noted above, the six topics were examined while neglecting possible interactions with other topics and other systems and components not directly related to safe shutdown.
For example, Topics II-3.B (Flooding Potential and Protection Requirements),
II-3.C (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 (Th'ermal-0verload Protection for Motors of Motor-0perated Valves), III-ll (Component Integrity), III-12 (Environmental Qualifi-cation 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.
Further, this review did not cover in any significant detail the reactor protection system, nor the electrical power distribution, both of which will also be reviewed later.
The staff considers that the ultimate decision concerning the safety of.any of the SEP facilities depends upon the ability to witistand the Design Basis Events (DBEs).
The SEP topics provide a major input to the 08E review, both from the standpoint of assessing the probho' ility of the event and that of determining the consequences of the event.
As examples, the safe shutdown topics pertain to the listed DBEs (the extent of applicability will be determined during plant-specific review):
. Impact Upon Probability Topic DBE Group or Consecuences of DBE V-10.8 VII -(Spectrum of Loss-of-Coolant Consequences Accidents)
V-11.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 Break Inside Consequences Containment)
(Steam Line Break Outside Containment)
IV (Loss of AC Power to Station Consequences Auxiliary)
(Loss of all AC Power)
V (Loss of Forced Coolant Flow)
Probability (Primary Pump Rotor Seizure)
(Primary Pump Shaft Break)
VII (Defined above)
Consequences X
II (Loss of ExterrA.- Load)
Consequences (Turbine Trip)
(Steam Prescore Regulator
[ closed])
(Loss of Feedw6ter Flow)
(Feedwater System Pipe Break)
III (Defined above)
Consequuces IV (Defined above)
Consequences V (Defined above)
Consequences VII (Defined above)
Consequences
. Completion of the safe shutdown topic review (limited in scope as note'd above), as documented in this report, provides significant input in ass'essing the existing safety margins.
. W4 0 m
2.0 Discussion 2.1 Normal Plant Shutdown and Cooldown A normal shutdown from full power to hot standby is accomplished with the use of operating procedure OP-2104, Rev. 7, " Scheduled Plant Shutdown to Hot Standby." The shutdown from power is accomplished by reducing the generator load using the turbine control system and following with control rod insertion to control T
The load reduction is performed at a rate of 8 MWe per 5 AVE.
minutes and changes in main coolant average temperature are controlled at a rate of 2 F per 5 minutes.
The reactor is borated using the charging pumps to the amount necessary to maintain the control rod bank above the low insertion limit and ensure that the axial flux difference will remain within its target band.
The first main feedwater pump and conJensate pump are removed from service when the generator load has been reduced to less than 140 MWe.
When the generator load has been reduced to less than 60 MWe, the second main feedwater pump and condensate pump are removed from service.
The power reduction is continued using the variable speed charging pump to provide spray to the pressurizer and the auxiliary feed pump (emergency feed pump) to provide feed to the steam
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generators. When the load on the generator has decreased to less than 30 MWe, station service loads are transferred to the auxiliary transformers fed from the offsite power suoply and condensate
recirculation is established back to the condenser hot well.
Manual control of the turbine bypass is taken when the generator load is reduced to less than 15 MWe.
The turbine is tripped just before the generator load reaches 0 MWe.
Normally, the plant can be maintained in a hot standby condition (main coolant average temperature at 514*F, 2000 psig) by using main coolant pump heat, decay heat, and discharging steam to the main steam header.
One group of control rods remains withdrawn (in the safety position) until the reactor coolant system (RCS) reaches near ambient temperature.
Pressurizer temperature and pressure are controlled to maintain the reactor vessel within NDT temperature range.
At least 2 RCS pumps are left operating until the shutdown cooling system is in operation.
The RCS is borated before cooldown using the charging and volume control system to the shutdown boron concentration.
The charging pumps take suction from the bcric acid mixing and storage tank.
If RCS loops are shutdown, they too are borated to the shutdown concentration.
The plant cooldown is limited to 50 F per hour, and cooling is accomplished by continuing the bypass of steam to the main condenser.
Pressurizer level is now manually controlled using the charging punps to provide makeup for contraction from the cooldown to RCS water.
RCS pressure is also controlled manually.
~9~
Just before reaching 330*F the remaining RCS pump is shut down.
The shutdown cooling system is placed in service beluw this temperature.. Charging flow is increased and the pressurizer is vented arid filled when system temperature reaches about 200*F.
(The RCS is now solid.) Shutdown c1oling continues until the RCS reaches about 140*F, where it is maintained by the shutdown cooling system.
This system is cooled by the component cooling system which is cooled by the service water system.
The service water system takes cold water from the river, circulates it through the component cooling system heat exchangers and returns the warmer water to the river.
Thus, heat is transferred f om the RCS to the river to accomplish cooldown and decay heat removal.
2.2 Shutdown and Cooldown With Loss of Offsite Power When offsite power is unavailable, the main condenser circulating water pumps cannot be powered from onsite sources and the main condenser is unavailable for heat removal.
The RCS cooling is accomplished by venting steam and providing makeup to the steam generators.
Manual operator actions are required to align the venting and feed operation.
Steam may be vented via the main steam vent valve or by means of the main condenser hogger.
Either has the capacity to accomplish decay heat removal and cooldown.
I Normal feedwater cannot be powered readily from onsite sources to makeup to the steam generators.
Therefore, the auxiliary steam driven feedwater pump (emergency boiler feed pump) is used to feed the steam generators.
Steam from the main steam system is used to drive the turbine of the auxiliar; feedwater pump.
The pump takes suction from the condensate storage tank and delivers a flow of about 80 gpm (total) to the steam generators.
Alternate sources of feedwt.ter are available to this pump and alternate methods to provide steam to the turbine drive can be arranged.
The auxiliary feedwater system is used to cool the RCS below 300 F, at which temperature the shutdown cooling system may be placed in service.
Cooling to ambient with the shutdown cooling system is then accomplished in the same manner as was discussed in 2.1.
. 3. 0 CONFORMANCE WITH BRANCH TECHNICAL FCSITION 5-1 FUNCTIONAL REQUIREMEN The functional requirements stated in BTP 5-1 for the safe shutdown systems are reiterated below:
(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.
(2) The system (s) shall have suitable redundancy in components and features, and suitable interconnections, leak detection, and isolation capabilities to assure that for onsite electrical power system operation (assuming offsite power is not available) and for offsite electrical power system operation (assuming onsite power is not available) the system function can be accomplished assuming a single failure.
(3) 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, 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 capability of the safe shutdown systems for Yankee Rowe to meet theJe criteria is discussed below.
A Processes involved in cooldown are heat removal, depressurization, flow circulation, and reactivity control.
The cold shutdown condition, as described in the Standard Technical Specifications, refers to a subcritical reactor with a reactor ccolant temperature no greater than 200*F.
3.1 Background
The STP requirements are stated with respect to plant shutdown and cooldown with only offsite or onsite power available.
The staff evaluated the plant's ability to conduct a unit shutdown with only offsite power available and determined that the onsite power only case is more limiting.
The plant electrical system is sufficiently versatile to allow the energizing of all necessary equipment from offsite power (and without the main generator).
Therefore, the staff concentrated its evaluation of the Yankee Rowe safe shutdown systems during 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 (Regulatory Guide 1.26), and is operated by electrical instruments and controls that meet Institute of Electrical and Electronics Engineers Criteria for Nuclear Power Plant Protection Systems (IEEE 279).
The Yankee Rowe Nuclear Plant received its Operating License prior to the issuance of Regulatory Guides 1.26 and 1.29 (as Safety Guides 26 and 29 on 3/33/72 and 6/7/72 respectively).
Also, proposed IEEE 279, dated August 30, 1968, was not used in the design of the "The staff also noted that Yankee Rowe can remain in a stable state for a certain length of time with a loss of all power (DC and AC).
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- MT I
facility.
Therefore, for this evaluation the systems which should be " safety grade" are the systems identified in Table 3.1 and in the followin'g minimum list of safe shutdown systems.
General Design Criteria (GDC) I through 4 (Appendix A of 10 CFR Part 50) require that systems, structures, and components important to safety 1) be constructed to quality standard, 2) be protected from the effects of natural phenomena (earthquakes, etc.) and other conditions (fires, pipe breaks, etc).
GDC 5 require that systems important to safety not be shared among other nuclear power units unless such sharing does not significantly impair the performance of the safety function.
The various aspects of GDC 1-5 will be evaluated for Yankee Rowe, including the systems required for safe shutdown elsewhere under several SEP topics.
The BTP 5-lfunctional requirements are centered around the systems necessary to take the plant from a normal operating condition to a cold shutdcwn condition.
In order to accomplish this, 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 considering a loss of AC power
- and the most limiting single failure.
The systems were then evaluated with respect to their capability to perform those tasks.
^Since the plant must be able to remain (for some time interval) in a hot shutdown condition prior to initiating an RCS cooldown, the
" minimum list" also includes those systems necessary to remain at hot shutdown.
. Ni The minimum list of systems (or components)* is given below:
1.
Steam System ASME Code Safety Valve 2.
Atmospheric Dump Valve (ADV) other steam ~ relieving paths 3.
Emergency Boiler Feed Pump 4.
Water Sources - Demineralized Water Storage Tank (DWST) and Primary Water Storage Tank (PWST) 5.
Shutdown Cooling System 6.
Component Cooling System 7.
Service Water System 8.
Emergency Power System 9.
125 VDC Power System 10.
Chemical and Volume Control System The staff's evaluation of each of these systems, with respect to the BTP 5-1 functional requirements, is given below.
YAEC has stated that the pressurizer heaters are not required since experience has shown that although the RCS pressure does decay, the rate is not extreme.
As long as no significant transients occur along with the loss of AC, the pressure will remain satisfactory for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> while the plant is at hot shutdown.
Once the cooldown starts, the plant pressure is allowed to decay.
YAEC has also stated that the compressed air systems (Instrument and Control Air) are not necessary since all controls are either
" fail safe" or can be manually controlled.
. 3.2 Functional Reauirements Steam System - ASME Code Safety Valves Task:
Removal of core decay heat by automatically venting steam from the main steam system.
Discussion:
Decay heat is initially removed from the RCS by the automatic actuation of the main steam safety valves (MSSV).
These valves are ASME code, self-actuated valves that are located on the four main steim lines.
Each main steam line has three safety valves with their discharges directed tc a common " secondary vent stack".
The size, setpoint and capacity of each of the MSSVs is given below:
2 '1" x 6" P
= 935 psig 80,872 lbm/hr set 2 ' " x 6" P
= 985 psig 118,260 lbm/hr q
set 6" x 8" P
= 1035 psig 573,329 lbm/hr set Therefore, the total relieving capacity for each steam generator is 6
about 772,000 lbm/h.", or a total of about 3.09 x 10 lbm/hr for all four steam generators.
Immediately after the loss of AC power and plant scram, the steam generator pressure and hence the RCS temperature
. (by natural circulation) will be controlled by the operation of the turbine bypass valves
- and the MSSVs.
Redundancy The staff calculated the number of MSSVs required to maintain the RCS temperature at an acceptable level.
Based on an initial after scram decay heat output of 6.75%, the relieving rates shown above, and an energy removal capability of about 650 Btu /lbm (h at fg P = 1000 psig), the three 935 psig (Pset) MSSVs will maintain the RCS at about 535 F immediately after the loss of AC and scram.**
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 location, the places where it may be operated, and the equipment's power supply.
The instrumentation available to control room operators relevant to the equipment is
^The two main circulating water pumps are lost as a result of the loss of AC power, and the condenser vacuum will decay in about 1 minute.
Since the turbine bypass valve has a low vacuum trip at 18" Hg, energy removal via this path is not accounted for in this evaluation, but certainly exists for a short period of time.
- This quantity does not consider any pressure transients on the steam system as a result of the loss of load.
EQUIPMENT LOC 1 TION OPERATION POWER SUPPLY HSSV's Outside, mounted on Self actuated.
Local opera-No electrical power is needed main steam lines tion using a permanently between VC and PAB.
installed lifting lever is Accessible by a catwalk possible, but not preferable.
about 30' above ground.
0 Il
' also a subject of staff review, and will be evaluated in the electrical portion of the staff's review of Topic VII-3.
ADV and Other Steam Relieving Paths Task:
Removal of core decay heat and RCS sensible heat by venting steam from the main steam system.
Discussion:
Immediately after the loss of offsite AC, turbine trip and reactor scram, the MSSVs automatically actuate to control steam system pressure and RCS temperature.
However, the MSSVs are not normally used at presiJre below their lift pressure, although a lifting lever is furnished on each valve for manual operation.
The cooldown of the Yankee Rowe RCS following a loss of AC would be accomplished using the Atmospheric Dump Valve (ADV) and several other steam flow paths.
The air controlled ADV* vents steam from any or all of the four 14-inch (00) steam lines between the Vapor Cortainment (VC) and the Turbine Building.
The ADV vents steam from a " vent header" which
^ Air is supplied to the ADV diaphragm from either the instrument air system or from a newly installed (dedicated) N b ttle.
2 is pressurized (using manually operated 1-inch isolation valves) from cny or.all of the four main steam lines.
Since there are no automatically shut Main Steam Isolation Valves (MSIVs), there is no possibility of isolating a vent path due to MSIV closure.
- Thus, the ADV can remove energy from any, or all steam generators.
The plant procedure for a loss of AC power, OP 3251 (discussed in Section 2) directs the operator to start the Emergency Boiler Feed Pump (EBFP) and line up steam to the large " hogger".
The large and small hoggers at Yankee Rowe, are single stage venturi type air ejectors which draw from the condenser and exhaust directly to atmosphere (unlike the main air ejectors which exhaust to the shell side of a condenser cooled by condensate).
The hoggers are normally used for removing large amounts of air and gasses from the condenser dering startups.
(During startups, steam for the hoggers comes from the two site boilers.)
During a loss of AC, the hoggers remove energy from the steam gen-erators by bleeding steam from the main steam lines.
In this event, the suction valves to the main condenser are shut.
Main steam is throttled at the nozzle inlets to maintain about 300 psig on the large hogger and 60 psig on the small hogger.
Since there is no automatic pressure regulator, as main steam pressure drops during the RCS cooldown, the throttle valve setting must be manually adjusted.
The Emergency Boiler Feed Pump (EBFP) is utilized to provide feedwater to the steam generators during the loss of AC, and is described in s
the followins section.
The EBFP turbine utilizes main steam (via an automatic reducer) or auxiliary boiler steam (two boilers are available). When using main steam, the EBFP removes energy from the primary.
Redundancy The licensee calculated the capacity of the ADV based on 775 psig saturated steam and critical flow.
The mass flow rate out the ADV is about 29,000 lbm/hr or about 9100 Btu /sec (based on 1217 Btu /lbm hg and 88 Btu /lbm h *).
Actual measurements, however, indicated f
that the capacity of the ADV is considerably less.
The tests were conducted by calculating the cooldown rate with the ADV fully open, knowing the heatup rate with the ADV shut.
The tests showed the ADV able to remove only about 3100 Btu /sec.
Yankee Rowe considered 't necessary to provide another flow path for energy removal based on these actual measurements.
Therefore, another flow path was created which allows steam to pass from the
- The s*.aff notes that most of the feedwater inside the steam generator is at T and therefore an h of about 350 Btu /lbm would have been more approprf$,teinitially.
However, even using this enthalpy does not account 7
for the difference between the calculated and measured energy removal rate of the ADV.
. vent header through two manually operated valves then to atmosphere through a 1-inch pipe.
The licensee's calculated energy removal rate using this path is about 9661 Btu /sec, but the staff's calcula-tions (based on a hotter feeds.ater) show ab.out 7400 Btu /sec.
The staff calculated the earliest time following the loss of AC and scram when each component's energy release rate exactly equals the core decay heat.
Steam RCS Component Flow Eneroy Removal Time ADV no data 11.16 x 10 Btu /hr*
~20 hours 1" vent 40,377 lbm/hr 26.64 x 10 Btu /hr**
< 1 hr Large Hogger 4,500 lbm/hr 3.90 x 10 Btu /hr**
Note 1 Small Hogger 865 lbm/hr
.75 x 10 Btu /hr**
Note 1 EBFP 3,850 lbm/hr 3.34 x 10 Btu /hr**
Note 1 Note 1 these components, alone, can not remove enough core decay
=
heat to initiate an RCS cooldown for the first 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />.
The time when the component energy removal capability equals the decay heat input corresponds to the time when (1) plant cooldown commmences if the component is used and (2) intermittent steam generator safety lifting would stop.
To establish the degree of redundancy provided by the various com-ponents discussed above, the staff and licensee estimated the RCS
- Based on actual test data.
- Using h = 1217 Btu /lbm and h = 350 Btu /lbm.
g
cooldown times using various combinations of the components.
The calculations are summarized below:
RCS Cooldown Times,2,3 1
Comoonent Staff Calculations Licensee Calculations 1" vent 381 F in 70.4 hrs 4 ADV 417*F in 72.6 hrs 5 378 F in 70.8 hrs 5 1" vent + ADV 52.8 hrs
,5 335 F in 68.7 hrs 5 4
1" vent + ADV + EBFP 52.8 hrs,5,6 4
1" vent + ADV + EBFP + Hoggers 20.8 hrs
,7 5
1" vent + ADV + EBFP + Hoggers 26.4 hrs
,8 7
1" vent + ADV + EBFP + Hoggers 41.5 hrs,1o a
1" vent + ADV + FBFP + Hoggers 10.3 hrs,9,10 5
Note 1:
If the calculations show that the RCS cooldown is terminated due tc the depletion of auxiliary feedwater (85,000 gallons),
then the temperature shown will be above 330 F,and will correspond to the RCS temperature when the water is depleted.
Note 2:
The staff's calculations assumed no credit for the colder auxiliary feedwater h, rather, the staff used the saturation f
h corresponding to the pressure.
This amounts to at least an f
extra conservatism of about 350 Btu /lbm which would shorten the cooldown times shown.
Note 3:
The staff's calculations also assumed a slightly higher initial RCS temperature than the licensee's calculations (544 F vice 539 F).
' Note 4:
The staff erroneously assumed a flow rate slightly higher
. than actual.
Note 5:
This calculation assumes the theoretical flow through the ADV.
As discussed in Section 3.2, the actual ADV energy removal rats is less than that determined by using the theoretical flow.
Note 6:
This calculation assumes the EBFP is isolated from the main steam system when pressure is below 300 psig, and received steam from the heating boilers.
Note 7:
This calculation assumes the EBFP continues to run when steam pressure falls below 300 psig.
Note 8:
This calculation assumes the actual value of ADV energy removal (from the physics tests).
Note 9:
This calculation assumes a constant value for the energy removal rate for the hoggers and the EBFP.
(That is, the energy removal rate does not vary with steam pressure. )
Note 10:
This calculation assumes a realistic value for the energy consumption by the hoggers.
The staff also performed scoping calculations to determine the
. dependence of RCS cooldown time on the initiation time.
We found that if the cooldown were delayed 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the time to reach 330 F is the same as if the cooldown began immediately (as soon as possible after the SCRAM).
Since the core decay heat is less at 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, and the energy removal rate is the same, the cooldown rate is very high initially, but then decreases as the energy removal rate (determined mainly by steam pressure) decreases.
Using the above table to establish redundancy, it is apparent that both the ADV and the 1-inch vent are necessary to achieve RCS cooldown before expending the Technical Specification required minimum (85,000 gallons).
However, the licensee has stated that any of the 12 MSSVs can be manually jacked open, using the installed lever arm, to either supplement or replace the steam flows discussed above.
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
EQUIPMENT LOCATION OPERATION POWER SUPPLY Large and Small Turbine building, adja-Local manual operation only.
No electrical power is needed.
Iloggers cent to condenser hotwell (0 pen / shut steam inlet valves) about 50 ft. from feed-water reg. valves, and 1 flight of stairs below
~
control room.
Atmosphere Duap Outside, in the vicinity Control room operation only No electrical power is needed.
Valve of the MSSV's, accessible by catwalk about 30 ft.
above ground level.
1" Vent Pipe Valves to lineup to con-Local operation only using the No electrical power is needed.
trol this path are manual control valves located in the floating Boiler room, the 1" vent pipe goes to atmosphere just outside the Boiler 02 room.
e EBFP (See following section)
(See following section)
(See following section) 4 8m I
. below gives the equipment's location, the places from where it may be operated, and the equipment's power supply.
The design of the electrical instrumentation and controls for this and other safe shutdown related equipment will be evaluated in the electrical portion of the staff's review of Topic VII-3.
Emergency Boiler Feedwater Pumo Tas k:
Provide steam generator makeup during the loss of AC while RCS temp > 330 F.
Discussion:
While the RCS temperature is above 330 F, the core decay heat is removed by bleeding steam from the steam generators using the various flowpaths discussed previously.
The condensate and feed pumps are powered from the 2400 V bus which is normally supplied from offsite power, therefore, steam generator makeup must De provided using other pumps.
Each steam generator contains about 3000 gallons of feedvater at full power,* therefore, about 12,000 gallons are available for RCS
- The Yankee Rowe Steam Generator Level control system maintains the steam generator water inventory at about 3000 gallons at all power loads.
energy removal following a loss of AC.
As previously discussed, the primary energy removal method immediately after the scram is the operation of the MSSVs.
Later, to cool the plant and to limit the MSSV operation, the ADV, 1-inch vent, and hoggers are used.
The staff calculated the amount of energy 12,000 gallons would remove by vaporization.
These calculations show that this inventory is sufficient to maintain RCS temperature acceptable, without initiating any steam generator makeup, for approximately 90 minutes following the SCRAM.
The staff's calculations also show that even if there were a 15-second delay time between the loss of AC and the reactor SCRAM (i.e., the steam generators are producing 100% power without feedwater for 15 seconds), the steam generators can remove about 72 minutes of core decay heat before boiling dry.
The Emergency Boiler Feed Pump (EBFP) is a turbine driven recipro-cating pump that provides about 80 gpm directly into the four feedwater lines immediately upstream o' the air operated feedwater regulating valves (FRVs).
Steam for the turbine is supplied from the auxiliary steam header which is supplied 'from either main steam via an automatic reducing valve or from auxiliary boilers.
Turbine exnaust is directly to atmosphere via the vent stack.
The EBFP is lined up to receive water from the Demineralized Water Storage Tank (DWST) and can also receive water directly from the Primary Water Storage Tank (PWST).
The EBFP discharges to the main feed system via a 2-inch (00) header.
The header divides into four 1 -inch
. (00) lines which pressurize each of the four normal feed line.
dowastream of the motor operated isolation valves (MOVs).
Each l\\-inch (00) line has a manual isolation valve which is opened to pressurize the four feed lines.
Steam generator level control is performed using the individual FRVs* from the local station, after the four MOVs are shut.
As a backup means of supplying steam generator feedwater under certain conditions, the licensee has installed piping from the high pressure safety injection pump discharge and from the charging pump discharge lines to the steam generator via the steam generator blowdown lines.
This backup was installed only to provide a method of feeding the steam generators in the event that a fire or other emergency in the turbine building disabled the normal feed methods which depend on the main feed pumps and the EBFP.
The backup method is described in the licensee's letter to the NRC (L. Minnick to D. Ziemann) dated October 30, 1978.
The EBFP is located in the Turbine Building and is manually started and lined up to the steam generators from outside the control room.
The valves, including power-operated valves, in the steam supply to the EBFP and in the suction and discharge lines of the ESFP and
- The FRVs are normally air operated but can be manually operated (during a loss of instrument air) using a handwheel.
)
charging pumps (for the alternate steam generator feed path) are capable of local manual ope *ation or can be bypassed with manually operated valves.
Use of the backup feed path requires manual opening of locked closed valves to line up the flowpath to the steam generators.
Another steam generator feed flowpath, use of which is forbidden by the plant Technical Specifications, exists at Yankee Rowe.
This path is established by the installation of a spool piece between t.he charging pump discharge line and the main feed header.
Redundancy Since the EBFP subsystem consists of a single pump and piping train, it is susceptible to the following single failures:
1.
Valve TV-405, in the steam supply line to the EBFP, may fail shut and prevent operation of the EBFP.
2.
The pump itself or " : turbine drive may fail.
3.
The single pump suction and discharge headers are susceptible to passive pipe failures which would disable the subsystem.
TV-405 may be manually opened should it fail shut using a local air supply.
Because of the time available for steam generator boiloff,
' as discussed above, manual opening of this valve is acceptable.
- Also, if arly of the above failures were to occur, the alternate steam generator feed flow path may be used.
However, the transient or accident scenarios, during which the EBFP subsystem single failures are postulated to occur, must be evaluated during the SEP design basis event reviews to ascertain that the alternate flowpath will be available.
For example, a postulated earthquake may disable the non-nuclear-safety portion of the alternate flowpath.
Thus a postulated earthquake and a postulated single failure of the EBFP may result in no operable means of supplying steam generator feed.
The failure of non-assential portions of the EBFP subsystem may prevent the subsystem from performing its function.
Specifically, the failure of non essential portions of the steam supply lines requires the operator to shut normally open manual valves to prevent the loss of steam pressure to the EBFP turbine.
Also if valve LCV-600, in the line from the DWST to the auxiliary boilers, failed to close, the condensate supply for the EBFP could be diverted to a non-essential portion of the system.
Again, because of the time available for operator action, we have determined that manual isolation of these non-essential portions of the subsystem is acceptable.
'~
The control room instrumentation provided is sufficient to inform the operator that the EBFP subsystem is operating in a correct mode and whether or not excessive system leakage is occurring.
- In discussions with the Yankee Rowe operations personnel regarding alternate methods to feed the steam generators, the plas.t's ability to utilize the normal feedwater system was discussed.
A Condensate and Boiler Feed Pump could be run from two Emergency Diesel Generators (EDGs) operating in parallel, and the remaining electrical loads could be supplied by the other EDG.
The necessary plant loads and their ratings are given below:
Component HP Amo Volt Charging Pump
~30 ETX 4T6v S/D Cooling Pump 60 72A 440V CCW Pump 125 26.8A 2400V Service Water Pump 125 26.75A 2400V Condensate Pump 250 57A 2400V Feed Pump 700 153A 2400V The licensee has never attempted to parallel and supply loads with two EDGs, and there is no procedure regarding this technique.
Also, the ECCS requires two of the three EDGs to be available for LOCA requirements, and if two EDGs were in parallel supplying a Condensate and Boiler Feed pump, the two EDG availability requirement may not be satisfied.
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 location, the places from where it may be operated, and the equipment's power supply.
EQUIPMENT _
LOCATI0tt OPERATI0tt POWER SUPPLY Emergency Boiler fM corner of Heating Local operation only.
Once at No electrical power is needed Feed Pump Doiler room floor, which proper rpm, governor maintains is a partitioned part of speed the Turbine Building Charging to feed Spool pieces and piping Local manual only No electrical power is needed System Spool flanges (and bolts) are Piece in charging pump cubicle.
Valves connecting to feed system must be opened in lower level of turbine bldg, in vicinity of BFP's (6 ft north of BFP motors)
Charging Pumps Pumps are located in Pumps operated from control CP#1 - MCC 4, Bus 1 (480) i and Valves Separated cubicles in room or locally at their CP#2 - MCC 2, Bus 1 (480) u" PBA.
Valves are under controllers [open door and use CP#3 - MCC 4, Bus 2 (480)
PAB floor with reach jumpers].
Valves are local rods.
nanual only.
BFP's and Lower level of turbine
> umps operated from control Condensate Pump #1 - Bus #3 (2400)
Condensate Pumps bldg.
room or locally at. their Condensate Pump #2 - Bus #1 (2400v) ireaker (supply)
Condensate Pump #3 - Bus #2 (2400v)
BFP #1 - Bus #3 (2400v)
BFP #2 - Bus #1 (2400v)
BFP #3 - Bus #2 (2400v)
EDG (See Emergency Power See Emergency Power (See Emergency Power System discussion System discussion System discussion below) below) below)
Water Sourc~es - DWST and PWST Task:
Providing water to the Emergency Boiler Feed Pump or to the Charging Pumps for steam generator makeup.
Discussion:
The EBFP takes a suction from the Demineralized Water Storage Tank (DWST) via a 10-inch OD line which also serves as the hotwell makeup and rejection line.
This line leaves the bottom of the DWST and from there branches into the following:
1.
A 10-inch hotwell rejection line (i.e., flow from hotwell i
using condensate pumps and a level control valve) 2.
A 10-inch hotwell makeup line 3.
A 3-inch EBFP suction line 4.
A 4-inch LPST makeup and charging pump suction line 5.
A inch Auxiliary Boiler makeup line Condensate and demineralized water are stored in the Demineralized Water Storage Tank (DWST), Tank 1, and the Primary Water Storage Tank (PWST), Tank 39.
The DWST is an aluminum 30,000 gallon tank that is normally filled from the water treatment plant.
The DWST is sized to handle all expected transients in the condensate /feedwater system.
This is accomplished by providing makeup to and accepting rejected water from the condenser hotwell.
h J The EBFP can also take a suction from the PWST via a 4-inch (0D) line which also serves as an alternate supply of water to the charging pumps.
The PWST provides demineralized water for the primary plant as well as for various demands in the primary auxiliary building, the radwaste building and the spent fuel storage area.
It is the supply for the low pressure surge tank make-up pumps and, as such, serves the above areas.
It is constructed of aluminum and has a capacity of 135,000 gallons.
An inner floating roof prevents aeration of the tank contents.
It receives make-up water directly from the water treatment plant.
Technical Specification 3.7 1.3 requires there to be a minimum of 85,000 gallons available from the DWST ar.d/or the PWST.
The Service Water System (discussed later) which receives fresh water from Sherman Pond, supplies the Water Treating Plant for PWST and DWST makeup.
The WT plant
- is sized to provide 40 gpm of demineralized water on a continuous basis and 80 gpm maximum, based on the average chemical analysis of Sherman Pond water obtained over a one year period.
Redundancy The staff calculated the maximum length of time the plant can stay at hot shutdown following the loss of AC, using the initial steam
^The WT plant is not included in the list of " minimum systems" but would probably be available since it is essentially a passive system which is pressurized using the SWS.
generator water inventory and a maximum. DWST level of 30,000 gallons.
These calculations show '. hat approximately 21.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of water supply are available for RCS temperature control, and after that, the EBFP suction must be shifted to the PWST.
The staff also calculated that the total water inventory required by Technical Specifications, 85,000 gallons, is enough to either keep the plant at hot shutdown for about 83 hours9.606481e-4 days <br />0.0231 hours <br />1.372354e-4 weeks <br />3.15815e-5 months <br />, or to complete a shutdown to the point of SCS system operation, 330*F, in about 72.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
These calculations take no credit for the initial steam generator inventory, nor any condensate in the hotwell.
The table of component cooldown times shown in the ADV discussion section identifies the necessary components required to be used to avoid expending all the Technical Specification required water.
Further calculations show that if the plant 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 />, and then initiated a plant cooldown, the cooldown rates would be higher, but the time to cool the RCS to 330 F would remain the same.
Since the condensate pump motor is much smaller than the BFP motor (250 HP vice 700 HP), a single condensate pump can be started to pump the contents of the condenser hotwell back to the DWST for EBFP usage.
Tha EBFP would not have to be stopped during this operation since its suction would just be augmented by the condensate o
' pump (The condensate pump rejection line would pressurize the E8FP suction and fill the DWST).
The hotwell has a capacity of 15,000 gallons and_a normal operating level of about 10,000 gallons.
However, the hotwell contents following a loss of AC and subsequent feed and condensate pump trips cannot be predetermined since event and component coast down times can not be accurately predicted.
Therefore, no credit can be given for this inventory, however it is likely that there would be a significant quantity of condensate available and useable.
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.
Shutdown Cooling System Task:
Removal of core decay heat and RCS sensible heat to cool the system from 330 F to 140 F.
E311PMENT LOCATION OPERAT IO.'l POWER SUPPLY DWST (TK 1)
(Outside, North (true)
Filling and drawing using valv es No electrical power is needed of the VC, between VC below and Aux Boiler Room PWSI (TK 39)
Outside, East (true) of Filling and drawing using valv as No electrical power is needed the VC in take form area below e
M 5
Valve #
location Power Supply DW-V-608 Aux. Boiler Room 0
X X
0 X
X No electrical power is needed DW-V-609 Aux. Boiler Room X
0 0
0 X
X No electrical power is needed DW-V-630 PAB X
0 X
0 X
0 No electrical power is needed DW-V-631 PAB X
X X
X X
X No electrical power is needed DW-V-662 PAB X
0 X
X 0
X No electrical power is needed DW-V-699 At PWST X
0 X
0 0
No electrical power is needed DW-V-7//
Aux. Boiler Room No electrical power is needed DW-V-632 PAB X
X X
0 0
0 No electrical power is needed Filling DWST at the same time D
X = shut 0 = open
- Discussion:
The shutdowrr cooling system is placed in service after the main coolant temperature has been reduced to approximately 330 F and the pressure to less than 300 psig.
The shutdown cooling system then reduces the main coolant temperature to 140 F or less and operates continuously to maintain this temperature as long as is required by maintenance or refueling operations.
The shutdown cooling system consists of a heat exchanger, circulating pump, piping, valves, and instruments arranged in a low pressure auxiliary loop parallel witn the main coolant loops.
The shutdown cooling pump takes suction from the hot leg of the main coolant piping on the reactor side of the loop stop valves and recirculates main coolant water through the tube side of the shutdown cooler and back into the cold leg of the main coolant piping, also on the reactor side of the loop stop valves.
The main coolant is contained in a closed system and reactor decay heat load is transferred through the shutdown cooler to the component cooling system which in turn is cooled by river water.
This arrangement of providing the intermediate cooling medium of the component cooling system was selected in order to assure that any possible leakage of radioactive main coolant would not enter the river water.
. Redundancy Complete backup of the system is provided by the icw pressure surge tank pump and heat exchanger which are identical units connected in parallel.
By employing double valving in the inlet and outlet lines to the main coolant piping, any required maintenance can be accomplished on the shutdown cooling system components.
The shutdown cooling system is designed to remove the reactor decay heat about 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after shutdown following 10,000 full power hours of operation.
According to the licensee's estimates, about 6
16.2 x 10 Btu /hr are generated by the reactor and transferred to the RCS.*
The SCS circulates the RCS, using the SCS pump, through the 6
SCS cooler.
The CCW system removes the 16.0 x 10 Btu /hr from the SCS cooler using one CCW pump and cooler.
If both the LPST cooling pump and the SCS pump, with their respective 0
coolers, were operating, then more than 16.0 x 10 8tu/hr could be removed by the CCW system.
Therefore, there is redundancy in the SCS (and LPST cooling) system's ability to remove the reactor decay heat at 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after shutdown.
3
- ANS 5.I decay heat gurve predicts a P/po a 0.008 at t = 18.0 x 10 sec, or about 16.34 x 10 Btu /hr.
EQUIPMENT LOCATION OPERATION POWER SUPPLY SCS and LPST Cubicles in the PAB, The SCS and LPST cooling pumps SCS sump:
Bus 5-2 (480v) cooling pumps lower level are operated from stations in LPST Cooling Pump:
Bus 6-3 (480v) and coolers the PAB hallway, adjacent to the pumps.
The coolers are local, manual operation.
No control room operation possibl e SCS valves (See Sections 4.1 and (See Sections 4.1 and 4.2)
(See Sectio,ns 4.1 and 4.2) 4.2) 5 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.
Comoonent Cooling Water System Tas k:
Provide cooling water to the SCS and/or LPST coolers and to other essential equipment.
Discussion:
The Component Cooling System is necessary to remove reactor decay heat from the Shutdown Cooling System heat exchanger (or the Low Pressure Surge Tank cooler), and to provide cooling to equipment necessary for plant cooldown.
The component cooling system consists of two coolers, two circulating pumps, a surge tank, a chemical addition tank and associated piping, system and instrumentation piping, valves, fittings and instruments.
This equipment is connected to two main piping headers.
One supplies vapor container components, the other supplies equipment outside the containment.
Independent lines, provided with isolation valves
. located outside the vapor container, are connected from the vapor container supply header to the various components inside the vapor container.
A surge tank (4,000 gallons) is used in the component cooling system to provide makeup water for the system, to accommodate the expansion and contraction of the water in the system as temperature changes, and to act as a receiver for the safety valves in the component cooling lines.
The water level in the tank is maintained at approximately 2,500 gallons.
The surge tank is equipped with a vent to the primary vent stack and a safety valve which discharges into the vapor container drain tank.
Level controls and alarms are provided on the surge tank.
A low pressure alarm and pressure indicators are provided in the outlet of the component cooling pumps.
A prescure switch starts the standby pump on low pressure.
The common cooler inlet and outlet pipes are provided with local temperature indicators; while the outlet pipe is also provided with a remote temperature indicator, a high temperature alarm, a flow meter and a flow meter alarm.
Controls for the component cooling pumps are located on the nuclear auxiliary panel in the main control room.
- Two motor driven centrifugal circulating pumps are provided.
The capac.ity of each pump is approximately 2,000 gpm, with a total dynamic head of 190 feet of water and a design discharge shutoff pressure of 110 psig.
The switches may be set in "Close", " Auto",
or " Trip" position with provision for " Pull-out" in the trip position.
The two component coolers are of the shell and tube design and are provided to transfer heat from the component cooling water to the service cooling water.
The tubes are made of admiralty metal.
During an RCS cooldown following a loss of offsite AC, the SCS is used to circulate the hot RCS through the SCS cooler (tube side).
The shell side of the cooler is furnished with CCW and the cooldown is controlled by an air operated Temperature Control Valve * (TCV-200) on the component cooling water discharge of the LPST and SCS coolers (common line).
TCV 200 controls either the LPST or SCS return (to the RCS) temperature at 140 F by throttling the component cooling flow from the coolers.
When the SCS cooler is first placed on line, the heat load is greatest and the SCS return temperature is highest, so the maximum CCW ficw the SCS cooler is allowed. When the SCS to RCS temperature drops, then the CCW flow is reduced to decrease the heat removal.
^TCV-200 is normally air operated but fails open (during a loss of instrument air).
Control of the CCW flow can thereafter be accomplished using the manual isolation valve.
. Redundancy Each cooler is designed for the full cooling capacity reached 6
during normal plant operation (8.5 x 10 Btu per hour) and either cooler serves as a spare for the other, but can be operated in parallel, if required.
Also, each cooler can remove the maximum decay heat removal by the SCS cooler, 6
16.0 x 10 Btu /hr, with the same amount of CCW flow.
Normal Load Full Load 6
Heat Removal (h.0 Btu /hr) 8.5 16.0 CCW inlet temp 100.5 F 96.0 F CCW outlet temp 92.0 F 80.0 F Service Water inlet temp 81.0 F 60.0 F Service Water outlet temp 87.8 F 72.8 F CCW flow 2000 gpm 2000 gpm SW flow 2500 gpm 2500 gpm Each pump can be operated singly or in parallel, and is provided with a redundant independent power supply.
Additionally, there are installed hose connections at the CCW pump discharge and suction to allow service water or fire water to provide component cooling should both CCW pumps be inoperable, or
. if a rupture in the system has occurred.
The procedure (OP3115 -
Loss of Component Cooling) directs the operator to first attempt to hook up,the portable fire hose from the fire system to the CCW system, then, if unable to use the fire system, use the service water system.
Thus, there are redundant and diverse means to provide component cooling.
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 equipmeat's power supply.
Service Water Syste_m Task:
Provide cooling water to the Component Cooling Water coolers and the SCS pump and/or LPST cooling pump coolers.
Discussion:
The service water system consists of three 2,500 gpm vertical deep well type pumps which obtain their suction from a common intake well in the Circulating Water Pump House.
The pumps discharge to a common 12-inch header which branches into two 12-inch supply headers.
EQUIPMENT LOCATION OPERATION POWER SUPPLY CCW pumps (2)
Floor level of the PAB, Operable from the Control room CCW pump #1 - Bus #3 (2400v)
SW end of building, and at 2400 V breaker by using CCW pump t/2 - Bus #2 (2400v) under CCW surge tank
" test" switch CCW coolers (2)
Side-by-side, upper level Local-manual operation of valv is No electrical power is needed of PAB, SW end of build-ir.g, adjacent to CCW surge tank CCW hose fittings Located at various places Local-manual operation only Na electrical power is needed and portable hoses in the SW end of the PAB, all within about 50 ft t
Em
' J The.upply headers run parallel to the southern wall of the turbine room 1tsement.
The two 12-inch supply headers furnish the various components with service water via separate taps from one or both of these 2 main supply headers.
The headers can be (manually) cross-co'nnected so that any combination of pumps supplies the necessary loads.
The greatest heat load on the system occurs when the SCS is first placed in operation.
2500 gpm of 60*F cooling water is required at that time.
This same flow is required at any time when the main coolant system water chemistry requires operating the purification system at its maximum capacity of 100 gym.
There is adequate capacity in the service water pumps to meet these special operating conditions.
Redundancy Normally, two pumps will be in operation with one pump on standby.
If the pressure in the discharge header falls below a preset value, the standby pump will start and simultaneously an alarm will be given at the control board.
The pressure switch for initiating this standby operation is located in the turbine room and is set at approximately 50 psig.
I The 2400V power supplies to SWP #1, 2 and 3 are Bus #3, Bus #1 and Bus #2, respectively.
These busses can be separated so a fault in one would not disable any more than one SWP.
Should all pumps fail due tn electrical problems, localized damage in the screen house or loss of suction from Sherman Pond, or if a break affecting certain portions of the service water header has occurred, selected service water loads can be provided with cooling water from the fire system.
The fire system could be supplied by either the installed fire pumps or from portable fire pumps connected in series taking a suction from the river or from Sherman Pond.
Also, the potable water system can supply selected service water loads with cooling water.
The plant procedure (OP-3009, Loss of Service Water) describes which components may receive fire water or potable water, and the locations of the necessary connections.
Location and 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 operated, and the equipment's power supply.
EQtilPHENT LOCATION OPERATION POWER SUPPLY SWP's (3)
Circulatirig water pump Operable from the control roon SWP #1 - Bus #3 (2400v) iiouse at the Nuclear Aux. Panel, anc SWP #2 - Bus #1 (2400v) from the 2400 V supply breake SWP #3 - Bus #2 (2400v)
(manual closure) llose connectic,ns Inlet and outlet to the Local-manual No electrical power is needed to SW system CCW coolers S
8 I
- i Emergency Power System Tas k:
Supply a reliable source of AC. power to run the necessary equipment Discussion.
The 3 Emergency Diesel Generators (EDGs) are each rated for continuous operation at 500KVA, 480V, 0.8 pf and 1800 rpm.
The engines are fast-starting, V-16 (cylinders), two cycle water cooled engines that are directly coupled to an air cooled synchronous generator.
Each engine has a closed, self-contained water cooling cycle, and is started with a 125 VDC c cranking motor that is supplied with power from an independent battery.
Air for operation of the engine and for cooling generator and engine radiator is obtained from roof intake vents.
The cooling air exhausts to the outside atmosphere, and the engine exhaust is via a muffler.
Each EDG has a 275 gallon fuel oil supply tank which contains enough fuel for 1135 hrs at full load.
A 30,000 gallon fuel oil storage tank can supply any supply tank via gravity flow.
The storage tank Tech Spec minimum (8,000 gal) can supply enough fuel
. for all EDGs at full load for more than 7 days.
HI-LOW level in the three supply tanks is annunciated in the control room.
Redundancy The expected electrical load (minimum) during a shutdown and cooldown following a loss of AC is given below:
1.
Charging Pump 50 HP 2.
Service Water Pump 125 HP 3.
Component Cooling Pump 125 HP
~4.
Shutdown Cooling (or LPST) Pump 60 HP Total 360 HP Since each EDG is rated at about 536 HP (400 KW), each EDG is sufficient to supply the necessary electrical loads during the shutdown and cooldown of the plant.
Also, the plant 480 and 2400 V electrical systems are designed such that if a particular pump is unavailable, breakers may be repositioned so that the redundant pump or component may be energized.
The EDGs are further evaluated in the resolution of SEP Topics VII-3, VII-2 (electrical portion).
125 VDC Power Task:
Supply a reliable source of DC power for breaker control and instrumentation.
Discussion:
This system will be evaluated in the resolution of SEP Topics VII-3, VII-3A, VII-38.
Charging and Volume Control System Tas k:
Provide RCS makeup (due to the contraction of the coolant during the cooldown) and borate the RCS to the necessary shutdown margin.
Discussion:
The CSCS consists of three positive displacement charging pumps, feed and bleed heat exchangers, pressure reducing orifices, LPST, LPST pump, LPST cooler, LPST makeup pumps, and associated piping, valves, fittings and instruments.
During normal operation, bleed flow passes from No.1 loop Tc line, through the tube side of the feed and bleed heat exchangers, through the vari-orifice and finally into the LPST through an eductor.
Charging flow passes from the purification pump discharge through the charging pumps, through the shell side of the feed and bleed heat exchangers and into No. 4 loop T line.
In addition, charging h
flow can be lined up to the individual loops via the safety injection system.
Each charging pump is a positive displacement reciprocating pump rated at 33 gpm, 2500 psig and driven by a 50 horsepower motor.
No. I and 3 pumps have variable speed motors.
No. 2 pump is directly coupled to its motor and its constant speed.
No. 2 pump could put out a variable flow by throttling CH-V-690 between the discharge and suction of the pump.
Charging pump suction can be from the following sources:
1.
LPST (gravity flow) 2.
Purification System (IX gravity) 3.
Purification System (Pumps) 4.
Boric Acid Mix Tank (gravity) 5.
Safety Injection Tank (gravity) 6.
WT System (via LPST makeup pumps) 7.
PWST (gravity or LPST makeup pump) 8.
0WST (gravity)
Boration of the RCS is accomplished by injecting borated water from either the Borated Acid Mix Tank (3000 gal 12000) or the Safety Injection Tank (175,000 gal - 2200 ppm).
The SI tank is normally used since it provides finer reactivity control because of its lower boron concentration, however the BAMT is available also.
Redundancy The amount of RCS makeup during the cooldown (and filling of the pressurizer) from 539 F to 330 F was calculated by the staff (Appendix 5) to be about 6,000 gal.
Therefore, the BAMT alone
' )
j doesn't provide enough RCS makeup for the plant cooldown to 300 F.
Howev.er, there are numerous other sources of primary grade water available (e.g., PWST, DWST, SIT, WT system).
To ensure the pressurizer level can be controlled during the most rapid cooldown (i.e., ensure sufficient charging pump discharge is sufficient) the staff used the calculations of the RCS cooldown with the 1-inch vent after a wait time of 4 hrs.
This cooldown rate was initially (i.e., at T E 540?F) slightly greater than RCS 50 F/hr.
The staff calculated that the liquid contraction rate due to the cooldown at about 50 F/hr is less than the input rate available from each charging pump.
Therefore, the pressurizer level can be raised by only one charging pump during this cooldown, and the remaining pumps provide further redundancy.
The boration capability is sufficient to provide a SHUTDOWN MARGIN from all operating conditions of 5.0%.1k/k after xenon decay and cooldown to 200 F.
The maximum baration capabiilty requirement occurs at EOL from full power equilibrium xenon conditions and requires 776 gallons of 22,000 ppm borated water from the boric acid mix tank or 9192 gallons of 2200 ppm barated water from the safety injection tank.
Since the Technical Specifications require J
both these tanks for continued operation, there is redundancy in the source of borated water to achieve a sufficient shutdown margin.
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.
EQUIPMENT LOCATION OPERATION POWER SUPPLY Charging pumps (See EBFP discussion)
(See EBFP discussion)
(See EBFP discussion)
(3)
Boric Acid Mix Upper level of PAS in Local manual operation only Mechanical agitator and trace Tank general vicinity of the (filling,etc.)
heaters are pow'ered from Component Cooling Water
, however, these Surge Tank components are not needed after the loss of AC to the redundancy (SIS)
Safety Injection Outside Tank is filled by lining up There is a small heat exchanger Tank various valves in the PAB.
and circulating pump which keeps Suction path to SIS is automa-the water > 40 F, but these are tically aligned not necessary following the loss of AC.
Therefore, no electrical power is needed.
Em
TABLE 3.1 CLASSIFICATION OF SiluTDOWN SYSTEMS Quality Group Seismic Plant Plant Components / Subsystems R.G. 1.26 Design R.G. 1.29 Design Remarks Main Steam System Code safety valves ASME III ASME VIII Category I Class 2 Main steam headers
?
from steam generators up to and including te EBFP, the 18 inch turbine throttle valves, the bypass valve, and connecting piping up to and including the first valve that is i
normally closed or capable o
m of automatic closure Emergency Boiler Feed Pump pump ASME III
?
Class 3 o
.:t 3::::=r TW
TABLE 3.1 CLASSIFICATION OF SHUTDOWN SYSTEMS Quality Group Seismic Plant Plant Components / Subsystems R. G. 1.26 Design R.G. 1.29 Design Remarks EBFP piping fr6m discharge ASME III
?
Category I of pump tn main feed lines Class 3 including EBFP relief.
Main feed piping from and including valves MOV-1003 through 1006, CV-1000A, CV-1100A, CV-1200A, and CV-1300A, up to valves CV-1000, 1100, 1200, and 1300.
Main feed piping fror.
ASME III and including CV-1000, Class 2 1100, 1200, and 1300 up m*
to the steam generators e
and connected piping up to and including the first valve that is normally closed or capable of automatic closures D$
21
TABLE 3.1 CLASSIFICATION OF SiluTDOWN SYSTEMS Quality Group Seismic Plant Plant Components / Subsystems R. G. 1.26 Design R.G.
1.29 Design Remarks EBFP piping from suction ASME III
?
Category I Refer to Technical of pump to and including Class 3 Specification 3.,7.1.3 the DWST and/or the PWST and connected piping up to and including the first valve that is either manually closed or capable of automatic closure.
Shutdown Cooling System Pump ASME III
?
Class 2 Heat Exchanger (shell side)
ASME III ASME VIII fleat exchanger also constructed Class 2 in accordance with the 1956 (tube side)
ASPE III 1956) edition of Standards of the Turbular Exchanger Hfgr's.
SCS piping from MOV-552 Class 2 ASA B31.1 Association.
g through the SCS pump and (1955) heat exchanger to MOV-551 Sections 1 and 6 and connected piping up to the first normally closed valve or valves capable i
of automatic closure.
Em
TABLE 3.1 CLASSIFICATION OF SHUTDOWN SYSTEMS Quality Group Seismic Plant Plant Components / Subsystems R. G. 1.26 Design R.G. 1.29 Design Remarks Component Cooling Water pumps (2)
ASME III ASME VIII Category I Class 3 (1956) heat exchangers (tube side)
(shell side)
'o CCW piping and connected piping ASA B31.1 Note:
Piping which up to and including the first (1955) Sect.
penetrates containment valve that is either normally 1 and 6 up to the outermost clo'ed or capable of automatic containment isolation closure.
valve should be ASME III, Class 2.
CCW surge tank ASME VIII (1956) cn CCW Valves and fittings ASA B16.5 y
(1957)
B
TABLE 3.1 CLASSIFICATION Of SHUTDOWN SYSTEMS Quality Group Seismic Plant Plant Components /5ubsystems R.G. 1.26 Design R.G.
1.29 Design Remarks Service Water System pumps (3)
ASME III
?
Category I Class 3 SWS piping and connected
?
Note:
Piping which piping up to and including penetrates containment the first valve that is up to the outermost either normally closed or e
o containment isolation capable of automatic valve should be ASME III closure.
Class 2.
Vapor containment No Code NA*
Vapor containment coolers coolers perform no safety related function.
e S
Vapor containment booster No code NA
- not applicable pumps (2)
D$Q
TABLE 3.1 CLASSIFICATION OF SiluTDOWN SYSTEMS Quality Group Seismic Plant Plant Components / Subsystems R.G. 1.26 Design R.G. 1.29 Design Remarks Chemical and Volume Control FSAR Section 203 and 204 System pumps (3)
ASME III ASME III Category I Note:
The system Class 2 (1956) boundary includes low Pressure Surge Tank connecting piping up to and including Piping and valves from ASA 31.1 the first valve that pump discharge to (1955) Sect.
is either normally Cil-V-617 and CH-V-611 1 and 6 closed or capable of e
automatic closure.
Piping from and including ASME III Cll-V-617 and Cil-V-611 to Class 1 the main coolant system I
Letdown piping from the main coolant system to and R;
including the orifice o
it isolation valves.
D$
21
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. 4.0 SPECIFIC RESIDUAL HEAT REMOVAL AND OTHER REQUIREMENTS OF BRANCH TECHNICAL POSITION 5-1 The BTP 5-1 contains the functional requirements discussed in Section 3.0 herein and also detailed requirements applied to specific systems or areas of operation.
Each requirement is presented below along with a description of the Yankee-Rowe system or component applicable to the requirement.
4.1 RHR Isolation Reouirements The following shall be provided in the suction side of the RHR system to isolate it from the RCS.
1.
Isolation shall be provided by at least power-operated valves in series.
The valve positions shall be indicated in the control room.
2.
The valves shall have independent diverse 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.
3.
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.
Evaluation 1.
The Yankee-Rowe SCS suction line has two power operated isola-tion valves which do not have position indication in the control room.
=
. 2.
Neither of the two SCS suction valves are provided with "open permissive" interlocks.
The opening of these valves is adminis-tratively controlled.
The controls for the valves are located in the PAB.
Key lock switches control each MOV, and the key is in the custody of the shift supervisor.
The two suction valves, MOV 552 and 554, are powered from MCC 1, Bus #1.
A failure of power supply will not effect the position of these valves (either open-to-close, or close-to-open).
3.
Neither of the two SCS suction valves are provided with " auto-closure" interlocks.
The SCS pressure is controlled by the RCS pressure and SCS (LPST) pump perfcrmance when the two systems are connected.
To insure the SCS is not overpressurized, the RCS overpressure protection system, which includes the SCS relief valves, is provided.
This is further discussed in Section 4.2.
One of the following shall be provided on the discharge side of the RHR system to isolate it from the RCS:
1.
The valves, position indicators, and interlocks described in Section 4.1 (above),
2.
One or more check valves in series with a normally closed power-operated valve.
The power operated valve position shall be indicated in the control room.
If the RHR system discharge line is useo fer an ECCS function the power-operated valve is to be opened u)on receipt of a safety injection signal once the reactor coalant pressure has decreased below the ECCS design pressure.
3.
Three check valves in series, or 4.
Two check valves in series, provided that there are design provisions to permit periodic testing of the check valves for leak tightness and the testing is performed at least annually.
Evaluation 1.
The Yankee-Rowe SCS has two motor operated isolation valves in series on the system discharge.
The position of these valves is not indicated in the control.
Like the two SCS suction MOVs discussed in Section 4.1, neither SCS discharge MOV control circuitry is provided with an "open permissive" or " auto-closure" interlock.
The opening / closing of these valves is administrativaly controlled.
The controls for these valves are adjacent to the controls for the suction valves.
Like the SCS suction M0V control switches, these are key lock switches with the key under the control of the shift supervisor.
The two SCS discharge valves, MOV-551 and 553, are powered from MCC 1 Bus #1.
A failure of this power supply will not j
affect the. position of these valves (either open-to-close, or closa-to-open).
4.2 Pressure Relief Requirements - Over pressure Protection To protect the RHR systere against accidental overpressurization when it is in operation (not isolated from the RCS), pressure relief in the RHR system shall be provided with relieving capacity in accordance with the ASME Boiler and 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 pressure relieving capacity of the RHR system.
For example, during shutdown cooling in a PWR with no steam bubble in the pressurizer, inadvertent operation of an additional charging pump or inadvertent opening of an ECCS accumulator valve should be considered in selection of the design bases.
Evaluation All operating PWRs have been required to modify plant operating procedures and install the necessary hardware to ensure the reactor coolant system (RCS) when in a cold and shutdown condition is not overpressurized.
The RCS low temperature overpressure protection system (LTOPS) must be capable of mitigating the most limiting mass and energy input events.
The LTOPS will also afford protection for the RHR (Shutdown Cooling System - SCS).
The RCS au Shutdown Cooling System (SCS) can be connected whenever RCS temperature is below 330 F and the RCS pressure is below about 300 psig.
There are no interlocks associated with the two suction or two discharge MOVs and their position is under administrative control.
The SCS design pressure is 425 psig and the system has two spring loaded safety valves (SV) set to open at 425 psig.
The RCS low temperature overpressure protection system (LTOPS) is designed to prevent exceeding the 10 CFR 50 Appendix G (Isothermal curve) limit during the design basis mass and energy input evests.
The LTOPS utilizes the two SCS SVs and the pressurizer solenoid operated relief valve (50RV) with a manually enabled low pressure setpoint of 500 psig.
The SORV is switched to the low setpoint when the RCS pressure is below 324 F.
The LTOPS, while being specifically designed to maintain the RCS pressure within the Appendix G limits, is available for overpressure protection of the SCS.
Each credible mass and energy input event is listed below along with the peak RCS (hence SCS) pressure.
The information concerning mass and energy input events as well as additional discussion of the LTOPS equipment, its employment, testing, and associated Techical Specifications are further discussed in the staff's evaluation of the Yankee Rowe LTOPS.
~
TABLE OF LTOPS ENERGY ADDITION EVENTS LTOPS Single Peak Heat input Source RCS Temp Lines of Defense Failure Pressure Core Decay Heat &
T<300 F 1 SV5 + SORV 1 SV 515 psig RCP (thermal)
J All heaters T<300 F 2 SV + SORV 1 SV 470 psig 3
RCP startup T
= 50 AT=100 F 2 SVs + SORV 2 SVs 513 psig RCS (Note 6) 3 RCP startup T
= 100 AT=100 F 2 SVs + SORV 2 SVs 520 psig
{
RCS o
RCP startup TRCS = 100 AT=100 F 2 SVs + SOFV SORV 452 psig 3
RCP startup TRCS = 150 AT=1004 2 Ws + S0W 2 Ws 531 psig 3
RCP startup T
= 200 AT=100 F 2 SVs + SORV 2 SVs 538 psig RCS 3
RCP startup T
= 100 AT=150 F 2 SVs + SORV 2 SVs 536 psig RCS D$W
TABLE OF LTOPS MASS ADDITION EVENTF, Mass Mass Input Input Single Peak Source Rate RCS Temp Lines of Defense Failure Pressure -
1 CCP 30 gpm 200 F<T<300 F 2 SVs + SORV 1 SV 470 psig 1 CCP 30 gpm T<200 F 2 SVs + SORV 1 SV 470 psig 1 IlPSIP 220 gpm 200 F<T<300 F 2 SVs + SORV 1 SV 450 psig i
l llPSIP 220 gpm T<200 F 2 SVs + SORV 1 SV 450 psig 1 LPSIP 1100 gpm 200*F<T<300 F 2 SVs + SORV 1 SV 700 psig 2
1 LPSIP,4 1100 gpm T<200 F 2 SVs + SORV 1 SV 700 psig i
l 1 Train 1320 gpm 200 F<T<300 F 2 SVs + SORV 1 SV 700 psig D$
21
i Notes for Tables of LTOPS Mass and Energy Addition Events:
Note 1:
An ECCS train is composed of one LPSIP and.one HPSIP operating in series.
The mass addition from a single train of ECCS equipment is postulated since only one train is energized in this temperature band.
Note 2:
Only the mass addition from one LPSIP is postulated in this temperature band since all HPSIPs and LPSIPs are de-energized, but an operator error during testing of the LPSIP could result in mass addition.
Note 3; The licensee's analyses assumed only the availability of the 50RV, and took no crec.it for the SCS SVs.
The staff has found no failure which would disable both SCS SVs.
Note 4:-
The peak RCS pressure in this event is above the Appendix G (Isothermal) limits.
Note 5:
One SV is assumed initially unavailable since an SCS MOV closure is assumed to initiate the event.
The closure of an SCS suction MOV makes the SCS suction side SV unavailable.
Note 6:
The.1T indicated is the differential temperature between the steam generator secondary water and the coldest water anywhere in the RCS.
The SCS design limit of 440 psia is based on the pressure limit for the bellows seals employed in certain system valves.
If the bellows failed, the valve stem packing would be subject to system pressure, and even if the packing itself failed, there would not be a total loss of the ability of the SCS to perform its function.
The governing standard for the allowable pressure on the pipes and other major components of the SCS is American Standard ASA B31.1, 1955.
This standard allows the imposed stress of 115 percent of design during ten percent of the operating period and 120 percent of design during one
- percent of the operating period.* The licensee states that
,the Stone and Webster (AE for Yankee-Rowe) specifications for the SCS_are based on these ASA B31.1 requirements, and are given below.
System Temperature Allowable Pressure **
300 F 680 psig 200*F 700 psig 100*F 720 psig Since these limits are not exceeded during any of the postulated transients given above, we conclude that the SCS piping and major components are adequately protected for the LTOPS design base transients.
The relief protection used, however, is not in accordance with the ASME code since an active component (SORV) is utilized.
We do not consider this a significant deviation, and conclude that the overall SCS pressure relief requirements of BTP 5-1 are met.
This evaluation of SCS overpressure protection also applies to the Low Pressure Surge Tank (LPST) cooling loop since the LPST loop design is identical to the SCS.
ASA 831.1, 1955, paragraph 123(b).
- It should be noted that these pressures are above the allowable pressures (at comparable temperatures) required by Appendix G (Isothermal curve) for the RCS.
. Fluid' discharged through the RHR system pressure relief valves must be collected and contained such that a stuck open relief valve w1..
not:
1.
Result in flocaing of any safety-related equipment.
2.
Reduce the capability of the ECCS below that needed to mitigate the consequences of a postulated LOCA.
3.
Result in a nonisolable situation in which the water provided in the RCS to maintain the core in a safe condition is discharged outside of the containment.
Evaluation 1.
The SCS relief valves (2) can discharge to either the Low Pressure Surge Tank (LPST) or to the Primary 3 rain Collecting Tank (PDCT).
During SCS operation, the SCS relief valve discharge is valved directly to the LPST.
A common 6-inch (00) header directs relief discharge from several sources to 3
two eductors under water.
The LPST has a capacity of 750 ft and a level control system maintains the tank at about 1/2 full.
The tank and water level control is designed to take three pressurizer steam volumes before tank pressure reaches 70 psig.
The LPST has seven safety valves which relieve to a common header.
The header has a rupture disc which opens at 75 psig and relieves directly to containment.
~ 75 -
If one of the SCS relief valves stuck open, then approximately
.101 gpm* would be lost out the RCS (and SCS) system.
In about 29 minutes, the LPST would overflowing out the open rupture disc.**
In this situation, the following alarms would alert the operator:
LPST level and LPST safety valve discharge (5).
Since there is no safety-related equipment in the containment sump or on the containment floor where the LPST safeties and rupture disc would relieve, no flooding of ECCS related equipment would occur.
2.
The SCS is not utilized during either the injection or the recirculation phases following a LOCA.
During normal operations, the LPST receives RCS letdown from the CVCS.
The purification pumps take a suction from the LPST and pump the RCS liquid through the various ion exchangers for purification, then to the charging pumps for return to the RCS.
During SCS operation, the LPST operates as a reservoir for RCS makeup.
If the SCS pumps are operating, the LPST could be operating as it does during normal operations.
If the LPST cooling pumps are being A
101 gpm.t 465 psig (110% of PSET) en The safety valves and rupture disc would open in about 15 min.
. used for RCS cooling, then the LPST serves as a reservoir for both pump suctions:
the LPST cooling pumps and the purification pumps.
Following a LOCA, vapor containment sump recirculation is performed by the purification and charging pumps.
A 4-inch line directs water from the VC sump to the purification pump suction, and the normal LPST purification pump suction is interrupted (automatically with MOVs that shut on high VC pressure).
The purification pumps pressurize the charging pumps, which are used for return to the RCS.*
3.
The SCS relief valves are outside containment, but relieve to the LPST which relieves back inside the VC, therefore, on a stuck open SCS relief, there is no net loss of RCS or ECCS fluid.
If interlocks are provided to automatically close the isolation valves when the RCS pressure exceeds the RHR system design pressure, adequate relief capacity shall be provided during the time period while the valves are closing.
- A recent Yankee-Rowe submittal proposes piping changes which allow the LPSIPs to be utilized for post-LOCA recirculation.
The purification and charging pumps would not be required with this proposed change.
The staff is reviewing this submittal.
i Evaluation As discussed in Sections 4.1 and 4.2, the SCS isolation valves
(. to suctions and twc discharges) are not furnished with auto closure features.
Therefore, this requirement is not applicable.
4.3 Pump Protection Recuirements The design and operating procedures of ay RHR system shall have provisions to prevent damage to the RHR system pumps due to over-heating, cavitation or loss of adequate pump suction fluid.
Evaluation There are no automatic trip or other features associated witr the SCS or LSPT cooling pumps which are designed to protect from over-heating, cavitation or loss of adequate pump suction fluid.
- However, the Yt.nkee-Rowe SCS is designed so that either pump can obtain suction from the LPST as well as from the RCS (Loop 4 T ) directly.
g Therefore, unlike other PWR RHR' systems which can only be pres-surized from the RCS, the Yankee-Rowe SCS has a diverse method of pressurizing the SCS pumps.
Therefore, the probability of an inadvertent suction valve closure causing pump damage is lower.
The 480V breakers supplying power to the SCS and LPST cooling pumps have the following trip setpoints.
Short time (12-20 seconds @ 100 Amps)
Instantaneous trip (5-12 times the short time trip setpoint (100 Amps))
These features are designed to protect the power supplies from an equipment fault, but under certain circumstances (overheating), the trips may protect the pump motors.
The licensee has not evaluated these features with respect to cavitation, o/erheating or loss of suction fluid.
The following indicatiens (in the indicated locations) could alert the operator (s) to an abnormal situation.in the SCS:
MOV 554, 552 Position Indication MOV 551, 553 Position Indication LPST level LPST pressure SCS inlet temperature SCS or LPSI pump discharge pressure SCS or LPST cooler temp (discharge)
SCS discharge (to RCS) flow SCS or LPST cooler control valve (TICV 200) position
. 4.4 Test Requirements The isol. tion. 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 of IEEE Standarj 338 and Regulatory Guide 1.22.
The preoperational and initial startup test program shall be in conformance with Regulatory Guide 1.68.
The programs for PWRs shall include tests with supporting analysis to (a) confirm that adequate mixing of barated water added prior to or during cooldown can be achieved under natural circulation conditions and permit estimation of the times required to Mieve such mixing, and (t,)
confirm that the cooldown under natural circulations can be achieved within the limits specified in the emergency operating. procedures.
Comparison with performance of previously tested plants of similar design may be substituted for these tests.
Evaluation The operability of the two SCS suction valves, MOV 552 and 554, can be checked while the SCS is in service by transferring SCS cooling to the LPST cooling pump taking suction from the LPST.
Since there are no "open permissive" interlocks associated with any of the four MOVs (two suctions and two discharge), it is not necessary to bypass interlocks.
Yankee-Rowe has conducted plant cooldowns using RCS natural circulation, but has not performed any tests regarding flov measurement, cocidown rates, or boron mixing.
However, the staff believes that, with the boric acid concentrations used for shutdown, adequate boring mixing will occur under natural circulation flow.
4.5 Operational Procedur2s The operational procedures for bringing the plant from normal operating poder to cold shutdown shall be in conformance with Regulatory Guide 1.13.
For pressurized water reactors, the opera-tional procedures ard information reTaired for cooldown under natural circulation conditions.
The licensea has procedures to perform safe shutdown operations including shutdown to hot standby, operation at hot standby, hot shutdown, operation at hot shutdown and cold shutdown including long-term decay hee +. removal.
The licensee has also provided the operating staff procedures covering offncrmal and emergency conditions for shutting down the reactor and decay heat removal under conditions of loss of system or parts of system functions normally needed for shutdown and cooling the core.
Procedures for systems operation for systems used in safely shutting down the reactor are also included in the plant operating procedures.
These procedures were reviewed and are in conformance with Regulatory Guide 1.33.
In addition, the licensee has technical specifications (Section 6.8
" Procedures") which assures establishment of written procedures in accordance with NRC standards and Regulatory Guides (including Reg.
Guide 1.33).
An operation not currently covered by an operating procedure that should be addressed is the feeding of the steam generators from the safety injection system (discussed in Section 3.0).
~
~
4.6 Auxiliary Feedwater Supply The seismic Category I water supply for the auxiliary feedwater system for a PWR shall have sufficient invertory to permit operation at hot shutdown for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, followed by cocidown to the conditions permitting operation of the RHR system.
The inventory needed for cooldown shall be based on the longest cooldown time with either only onsite or only offsite power available with an assumed single failure.
Evaluation The RCS cooldown rates with varying equipment and the adequacy of the water supplies are discussed in Section 3.2.
. l 5.0 Resolution of SEP Topics The SEP-topics associated with safe shutdown have been identified in the Introduction to this assessment.
The following is a discussion of how the Yankee Rowe Plant meets the safety objective of these topics.
5.1 Topic V-10.8 RHR System Reliability The safety objective of this topic is to ensure reliable plant shutdown capability using sa',.ty grade equipment subject to t
guidelines of SRP 5.4.7 and BTP RSB 5-1.
The Yankee Rowe
' systems have been compared with the criteria fo BTP 5-1 and the results of these comparisons ce discussed in Section 3.0 and 4.0 of this assessment.
Section 3.0 discusses the way the functional requirements are met and Section 4.0 discusses the Shutdown Cooling System (SCS) which performs the function identified in BTP RSB 5-1 as Residual Heat Removal.
Redundancy to the SCS is provided by the Low Pressure Surge Tank (LPST) system.
The LPSTS is physically arranged in parallel with the SCS.
The components (pump and heat exchanger) of both the LPSTS and SCS are identical and share a common suction and discharge line in the shutdown cooling mode.
Eoth the suction and discharge lines are isolated by two motor operated valves in series. We find this degree of redundancy
.. acceptable, however, several deviations exist which could impair.the reliability of the system.
These are:
- 1) The SCS suction and discharge motor operated isolation valves do not have position indication in the control The valves are operated from the primary auxiliary room.
building (PAB) and cannot be operated from the control room;
- 2) There are no provisions to prevent damage to the SCS pump or LPST system cooling pump due to overheating, cavitation, or loss of adequate suction fluid; and 3) in order to cool the reactor coolant system to the SCS cut in point, significant operator action must be performed from outside the control room.
The first two deviations relate to interrupting the operation of the SCS while the plant is shutdown and being maintained at a temperature equal to or less tha.7 330 F and at a pressure less than 300 psig. The consequences resulting from an inadvertent valve closure or pump failure is that the cooldown would terminate and the plant would start to heat up.
Installation of valve position indicators and,bmp protective trips would alert the operator of the abnormal condition but would not preclude it from occurring. Other plant parameters which are monitored continuously in the control room are available to
- indicate the status of the cooldown to the operator.
In the event that the cooldown has been terminated due to a pump failure, the redundant pump and heat exchanger from the LPST systea can be put ifito service.
Two modes of plant status must be considered when evaluating the overall effects of a loss of the SCS function and the acceptability of the deviations 1) plant shutdowa sith the temperature being maintained at less than 33C F and at some pressure greater than atmospheric but less than 300 psig, 2) the plant shutdown and cooled down to less than 212 F, the reactor vessel head removed, and the system pressure at atmospheric.
In mode 1, if the SCS were disabled due to a pump failure a second pump, from the LPST system, is available for continued cooldown.
If the disruption of SCS is due to valve problems, an alternate method of maintaining the coolt.own would have to be employed. One such method would tid to ',et the plant heat up and remove tM heat generated through the steam generators (feed to the steam generators can be provided by a variety of sources and present an acceptable manner in which to continue the heat removal from the primary system). With the primary plant in Mode 2, as dafined above, and shutdown cooling were
., interrupted due to valving failures, adequate cooling of the reactor could be accomplished by keeping the core covered with water.
Based on the discussions above we conclude that although deviations from current licensing practice exist, the Yankee Rowe SCS can reliably perform the intended functions and in the unlikely event of a pump or valve failure, acceptable alternatives exist to maintain the plant in a manner which will not endanger the public health and safety.
The third deviation relates to the amount of operator action required to establish shutdown cooling.
The Branch Technical Position (BTP 5-1) states that a limited amount of operator action from outside the control room is permissible.
In the case of Yankee Rowe, substantial effort is required of the operators from outside the control room to decrease RCC tempera-ture and pressure to a point where SCS can be placed in operation.
Our evaluation shows that the time required before any operator action is necessary to be on the order of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or more, that is, without any operator action, from inside or outside the control room, the facility can sustain itself with the water inventory at hand.
[
The majority of the equipment that requires manipulation for cooldown is located and controlled from outside the Yankee Rowe control room.
Based on review of the Yankee Rowe operating procedures, proximity of the equipment, and the time period after which no action has to be taken, we conclude that the amount of operator action required for this ever.t is not unreasonable and does not present a significant problem.
Therefore we do not require any cdditional actions or changes to the facility or its procedures.
Based on our review of the functional intent of topic V-10.8 (RHR system reliability) as compared to the Yankee Rowe facility, we conclude it is acceptaFay resolved for this facility.
52 aid 5.3 Topic V-ll.A Requirements for Isolation of High And Low Pressure Systems Topic V-ll.B RHR Interlock Requirements The safety objectives of these topics is to assure that adequate measures are taken to protect low pressure systems connected to the primary system from being subjected to excessive pressure which could cause failures and in some plants have the potential for causing a LOCA outside of containment.
The current criteria
.. for RHR isolation and pressure relief are discussed in Sections 4.1 and 4.2, The Yankee Rowe SCS suction and discharge (isolation) valves do not have any open permissive interlocks or automatic closure features, and valve position indication is not provided in the control room. This deviation insolves violating a pressure boundary between a high pressur. system (RCS) and a low pressure system (SCS or LPST). The concern is valid anytime the RCS is at a pressure greater than the design pressure of the SCS or LPST (300 psig). The most limiting case is when the RCS is at operating temperature and pressure.
The SCS/LPST is isolated from the RCS at both the suction and discharge side by two key locked motor operated valves in series. An inadvertent opening of the pair of suction or discharge valves could cause overpres-surization of the low pressure system which could cause a pipe or system failure thereby creating a loss of coolant accident (LCCA) outside of containment.
Current criteria require open permissive interlocks which prevent opening the valves when a specific pressure differential exists across the valves.
In lieu of the open permissive interlock, Yankee Rowe has key operated valves, operated locally '
the Primary Auxiliary Building, with the keys maintained under administrative control.
In order to change the state of either of the SCS valves, an
., operator must obtain the key from the shift supervisor.
During routine operation of the plant there is no reason that an operator would want to.hange the state of these valves, a more reaiistic concern would be an inadvertent operation by maintenance workers.
Even though Yankee Rowe has had a significant period of ope"ation, incident free, without open permissive interlocks on the SCS isolation valves, because of the nature of the potential accident in question, the staff will pursue alternate ways to reduce the possibility of valve opening in the SEP integrated assessment of the plant.
The SCS isolation valves do not have automatic closure interlocks to close the valves during slow increase:, in RCS pressure.
This is to prevent RCS pressurization with any SCS isolation valves in the open position.
Rapid increases in RCS pressure are discussed in the Section 4.2 evaluation of the Low Temperature Overpressure Protection (LTOP) system.
Some of these rapid p essure increases oc.;ur sufficiently fast that an automatic closure interlock would not respond in time to prevent overpres-surization of the SCS.
However, we concluded that the LTOP provides acceptable SCS and LPST cooling loop pressure relief for these rapid transients. We have determined that the installation of automatic closure interlocks would not be desirable since two of the three LTOP relief valves are on the
.. SCS, and automatic isolation of the SCS from the RCS would render the LTOP system inoperable.
However, we will evaluate in the SEP integrated assessment the potential need for additional measures, such as control room valve indications, to prevent RCS startup and pressurization with any SCS isolation valves in the open position.
5.4 Topic VII-3 Systems Required For Safe Shutdown The Safety objectives 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.j 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 plant 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 condition during hot shutdown are located at appropriate locations outside the control room and
have a potential capability for subsequent cold shutdown of_the reactor through the use of suitable procedures.
3.
To assure that only safety grade equipment is required for a PWR plant to bring the reactor coolant system from a high pressure condition to a low pressure cooling condition.
Safety objective 1(a) will be resolved in SEP Design Basis Event Reviews.
These reviews will determine the acceptability of the plant response, including automatic initiation of safe shutdown related systems, to Design Basis Events, i.e., accidents and transients.
Objective 1(b) relates to availability in the control room of the control and instrumentation systems in the control room are capable of following tne plant shutdown from its initiation to its conclusion at cold shutdown conditions; this does not apply to Yankee Rowe, since the entire operation of shutdown cooling is performed outside the control room.
Safety objective 2 requires the capability to shut down to both hot shutdown and cold shutdown conditions using systems, instrumentation and controls located outside the control room.
Yankee Rowe has procedures, "Energency Reactor Shutdown from Power and Emergency Shutdown and Cooldown under abnormal circumstances."
The procedures identify several methods of tripping the plant and methods to cooldown and provides adequate instruction for determining the operability and condition of the essential plant equipment and indicates the surveil-lance instrumentation ~and instructions for interpreting the information The review team visited each designated operators station and assessed the capability of the plant staff to perform the necessary operations. We conclude that the plant can perform these shutdown operations.
The adequacy of the safety grade classification of safe shutdown systems at Yankee Rowe, 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 Design Basis Review Event reviews.
5.5. Topic 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 feedwater using the guidelines of SRP 10.4.9 and BTP ASB 10-1.
The AFS for Ya".xee Rowe consists of 1) the Emergency Boile-Feed Pump (EBFP), which was described in Section 3.2; 2) the piping from the Demineralized Water Storage Tank (DWST) and Primary Water Storage Tank (PWST) to the pump; and 3) the piping from the pump discharge to the steam generator.
As a backup for the EBFP subsystem, the licensee has installed an alternate means of steam generator feeding via the steam generator blowdown lines.
This is also described in Section 3.2.
The EBFP system and backup method were compared with SRP 10.4.9 and BTP ASB 10-1 with the following conclusions:
1.
The Yankee Rowe Nuclear 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, and earthquakes, tornadoes, and floods.
4
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. 2.
The AFS conforms to General Design Criteria (GDC) 45 "Iospection of Cooling Water Systems," and GDC 46, " Testing must be operated outside the control room to align both of Cooling Water Systems." GDC 5, " Sharing of Structures, the EBFP discharge flowpath and the alterrate steam Systems, and Components," is not applicable.
generator feed flowpath. This deviation will be reevalcated in the SEP Design Basis Event evaluations of accidents 3.
The EBFP aubsystem, by itself, does not meet the BTP ASB 10-1 provisions for power diversity and protection from single failures (active and passive). But the EBFP subsystem and the alternate feedwater flow path (using the charging pumps), when considered together, do meet
- ** 9" thase provisions. However, the alternate feed method wu
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designed and installed only to sitigate the effects of a fire or other emergency in the turbine building. The acc@ Med h heal, maM de wah N availability of this alternate feed metnod for accidents and transients other than a fire in the turbine building will be determined in the SEP DBE reviews. Even though this alternate method exists, the staff intends to examine the need for a long term improvement in the redundancy of E ""
the EBFP system in the SEP integrated assessment of waterhammer.
he staff is continuing its evaluation of Yankee Rowe.
feed system waterhammer on a generic basis. SEP Topic V-13 "Weterhammer," applies.
4.
The AFS control system deviates from the provisions of Regulato,y Guide 1.62 regarding manual actuacion at the 7.
The technical specifications for the AFS will be reevaluated system leve? from the control room. The EBFP must be
'98 Speci fications. "
O
.. 2.
The AFS conforms to General Design Criteria (GDC) 45,
" Inspection of Cooling Water Systems," and GDC 46, " Testing of Cooling Water Systems." GDC 5, " Sharing of Structures, Systems, and Components," is not applicable.
3.
The EBFP subsystem, by itself, does not meet the BTP ASB 10-1 provisions for power diversity and protection from single failures (active and passive). But the EBFP subsystem and the alternate feedwater flow path (using the charging pumps), when considered together, do meet these provisions. However, the siternate feed method was designed and installt.J only to mitigate the effects of a fire or other emergency in the turbine building.
The availability of this alternate feed method for accidents and transients other than a fire in the turbine building will be determined in the SEP DBE reviews.
Even though this alternate method exists, the staff intends to examine the need for a long term improvement in the redundancy of the EBFP system in the SEP integrated assessment of Yankee Rowe.
4.
The AFS control system deviates from the provisions of Regulatory Guide 1.62 regarding maqual actuation at the system level from the control room.
The EBFP must be s
p.r manually started in the Turbine Building. Manual valves must be operated outside the control room to align both the EBFP discharge flowpath and the alternate steam generator feed flowpath. This deviation will be reevaluated in the SEP Design Basis Event evaluations of accidents and transients for the plant.
The electrical design of the AFS controls will be evaluated later in the SEP.
5.
The Yankee Rowe AFS is not automatically initiated and the design does not have capability to automatically terminate feedwater flow to a depressurized steam generator and provide flow to the intact steam generator.
This is accomplished by local, manual valve operation.
The effect of this deviation will be assessed in the main steam line break evaluation for the plant.
6.
In 1967, the licensee made modifica' ions to th) Yankee Rowe plant to prevent the cccurrence of feed system waterhammer. The staff is continuing its evaluation of feed system waterhammer on a generic basis.
SEP Topic V-13, "Waterhammer," applies.
7.
Tl.e technical spacifications for the AFS will be reevaluated against current requirements under 55P Tcpic XVI, " Technical Speci fi cations. "