ML19309D503
| ML19309D503 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 04/07/1980 |
| From: | BOSTON EDISON CO. |
| To: | |
| Shared Package | |
| ML19309D500 | List: |
| References | |
| NUDOCS 8004100389 | |
| Download: ML19309D503 (36) | |
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ATTACHMENT A Technical Specification Change to Core Spray Sparger Break Detection Setpoint i
References:
a) IE Circular No. 79-24 titled, " Proper Installation and Calibration of Core Spray Pipe Break Detection Equipment on BWR's" b) General' Electric Service Information Letter No. 300, titled " Instrumentation for Core Spray-Sparger Line Break Detection" i
Proposed Change i
Reference is made to PNPS Technical Specification Appendix A, Table 3.2.B
" Instrumentation that Initiates or Controls the Core and Containment Cooling l
Systems".
The desired change consists of replacing the current Core Spray i
Sparger to Reactor Pressure Vessel d/p Trip Level Setting of 5(i 1.5) psid with a new setpoint of 1 5 psid.
Reason for Change 3
IE Circular 79-24 identified potential problems related to BWR core spray pipe break detection systems and recommended that licensees investigate this problem as it relates to setpoint, function, and installation of the d/p instruments used as monitors for core spray pipe breaks. As a result of-our investigation and recommendations by General Electric Company, it was determined that the current alarm setpoint on instruments used to measure core spray differential pressure should be changed to take into account the effect of density changes of the water in the pressure leg connections.
Safety Considerations -
Changing the core spray differential pressure switch setpoint from 5(i 1.5) psid 4
to -1.0(t 1.5)psid with a limit of 0.5' psid ' increasing takes into consideration the density fluctuations experienced in the instrument reference leg during normal ~
rated power operation not previously accounted for in setpoint determination.
Actual instrument readings including reference leg density considerations together i
with a predicted 5.3 psid increase in differential pressure following a core spray header break (Reference b) provide the basis and justification for this change.
This change has been reviewed by the Nuclear Safety Review and Audit Committee and l
has been reviewed and approved by the Operations Review Committee.
l Schedule of Change t
l Approval of this change is requested prior to startup from our current refueling outage.
i Boston' Edison Company proposes that pursuant to 10 CFR Part 170 this is.a Class II t:
i
~ Amendment.
l 800410'03&1 -
Attachment-
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PNPS TABLE 3.2.B (Cont'd)
INSTRUMENTATION THAT INITIATES OR CONTROLS THE CORE AND CONTAINMENT COOLING SYSTEMS Minimum i of Operable Instrument Channels Per Trip System (1)
Trip Function Trip Level Setting Remarks 1
RHR (LPCI) Trip System NA Monitors availability of power bus power monitor to logic systems.
1 Core Spray Trip System NA Monitors availability of power bus power monitor to logic systems.
1 ADS Trip System bus NA Monitors availability of power power monitor to logic systems and valves.
1 HPCI Trip System bus NA Monitors availability of power power monitor to logic systems.
1 RCIC Trip System bus NA Monitors availability of power power monitor to logic systems.
2 Recirculation Pump A d/p
<2 psid Operates RHR (LPCl) break de-tection logic which directs 2
Recirculation Pump B d/p (2 psid cooling water into unbroken recirculation loop.
2 Recirculation Jet Pump 0.5<p<l.5 psid Riser d/p A>B
[
1 Core Spray Sparger to
$0.5 psid Alarm to detect core spray Reactor Pressure Vessel d/p sparger pipe break.
ATTACIDfENT B Technical Specification Change Concerning Hydraulic Snubbers Proposed Change Reference is made to PNPS Technical Specification Appendix A, Page 137.
The desired change consists of removing Snubber No. SS-23-3-33 (HPCI) from the table of Safety Related Shock Suppressors (Snubbers).
1 Reason For Change Per IE Bulletin #79-14, the pipe stress reanalysis performed by Bechtel on the llPCI piping system has shown that this snubber is not required to protect the llPCI system piping.
Thus removal of this snubber was recommended by Bechtel to ensure that the proper design configuration is maintained in accordance with the rea nalysis.
Safety Considerations Removal of this snubber from the h..t piping system does not decrease the level of safety as originally designed to provide protection from structural damage to the piping as a result of a seismic or other event initiating dynamic loads.
Through pipe stress reanalysis, the remaining snubbers have been determined to be of correct size and location to ensure proper system rigidity for the preven-tion of unrestrained pipe motion under dynamic loads.
This change has been reviewed by the Nuclear Safety Review and Audit Committee and reviewed and approved by the Operations Review Committee
[
Schedule of Change Approval of this change is requested prior to startup from our current refueling outage.
Boston Edison Company proposes that pursuant to 10 CFR 170 this is a Class II amendment.
i i
At tachment y
Table 3.6.1 SAFETY RELATED SHOCK SUPPRESSORS (SNUBBERS)
Snubber No.
Location Elevation Snubber in High Snubbers Snubbers Snubbers Radiation Area Especially Inaccessible Accessible During Shutdown Difficult to During Normal During Normal Remove Operation Operation V
SS-6-10-1 Feedwater System 42' X (Drywell)
SS-6-10-2 Feedwater System 42' X (Drywell)
SS-6-10-3 Feedwater System 42' X (Drywell)
SS-6-10-4 Feedwater System 42' X (Drywell)
S S 10-5 Feedwater System 42' X (Drywell)
SS-13-3-1 RCIC 38' X (Drywell)
SS-13-3-2 RCIC 38' X (Drywell)
SS-14-3-1 Core Spray 65' X (Drywell)
SS-14-3-2 Core Spray 65' X (Drywell)
SS-14-3-3 Core Spray 65' X (Drywell)
SS-14-3-4 Core Spray 65' X (Drywell)
SS-23-10-1 H.P.C.I.
42' X (Drywell)
SS-23-10-2 H.P.C.I.
42' X (Drywell)
S-23-3-30 H.P.C.I.
-3' 09" X H.P.C.I. Quadrant S-23-3-31 H.P.C.I.
- 3' 09" X H.P.C.I. Quadrant S-23-10-32 H.P.C.I.
-3'09" X H.P.C.1. Quadrant S-23-10-34 H.P.C.I.
- 6' X H.P.C.I. Quadrant S-23-10-35 H.P.C.I.
- 6' X H.P.C.I. Quadrant S-23-3-36 H.P.C.I.
-3' 09" X H.P.C.I, Quadrant S-23-3-37 H.P.C.I.
- 3' 09" X H.P.C.I. Quadrant S-10-3-43 RHR
-3' 06" X RHR Pump Room S-10-20-44 RHR
- 3' 06" X RHR Pump Room S-30-3-45 RBCCW 83'5" X Reactor Building S-10-10-46 RHR 6"
X Torus Compartment Modifications to this Table due to changes in high radiation areas should be submitted to the NRC as part of the next license amendment.
C
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i ATTACHMENT C i
Supplement to August 24, 1977 " Proposed Electrical Power Systems Technical Specifications" Proposed Change Reference is made to BECo letter (J. E. Howard) to NRC (D. K. Davis) dated August 24, 1977, Attachment A (proposed Tech. Specs.), Page 194A.
The pro-posed change consists of supplementing our original proposal with-additional surveillance requirements on the Shutdown transformer.
I Reason for Change During telephone conversations on February 4, 6 and 7, 1980, members of your staf f involved in the review of the above stated correspondence requested Boston Edison Company to supplement the proposed August 1977 technical specif-ication with a section which would ensure surveillance testing for the timers on the shutdown transformer.
Enclosure A provides this supplement.
Safety Considerations This testing on the shutdown transformer does not present any hazard considera-tions not described or implied in the license application as amended, as this testing has always been in effect via station procedures.
This change has been reviewed by the Nuclear Safety Review and Audit Committee and reviewed and approved by the Operations Review Committee.
Schedule of Change This change will be put into effect upon receipt of approval from the Commission Boston Edison Company proposes that no submittal fee is required since this is a supplement to changes submitted prior to implementation of 10 CFR 170 and is made at the request of the Commission.
?
Attachment
3-LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 1.
Verifying de-energization of the emergency buses and load shedding from the emergency buses.
2.
Verifying the diesel starts from ambient condition on the auto-start signal energizes the emergency buses with permanently connected loads, energizes the auto-connected emergency loads through the load sequence and operates for i 5 minutes while its generator is loaded with the emergency loads.
p cn The results shall be logged.
]
C.
Once per operating cycle with the g
diesel loaded per 4.9.A.1.b verify that on diesel generator trip sec-ondary (off-site) a-c power is auto-matica11y connected to the emergency service buses and emergency loads are energized through the load sequencer in the same manner as described in 4.9.A.1.b.1.
The results shall be logged.
2.
Secondary.0ff-Site Power A.
A test will be performed once per c3 operating cycle to verify that the e
shutdown transformer breakers will close on to the safety related g
buses within 12 to 14 seconds.
y E
F 194A
i ATTACHMENT D l
Technical Specification Concerning Modifications To Safety Relief Valves Ref. (a) USNRC Letter (B. K. Grimes) to All BWR Licensees dated July 26, 1979 (b)
NUREC-0462 Proposed Change Reference is made to PNPS Technical Specifications, Appendix A, Pages 126, 127 &
146.
The desired changes consist of deleting the requirement associated with the relief / safety valve bellows (as shown in Exhibit A), since this feature will be removed from the valves during our current refueling outage.
Reason for Change The Target Rock SRV will be modified this outage in -that the 3 stage topworks will be replaced with 2 stage topworks, thereby eliminating the bellows and its associated pilot valve leakage.
This in turn creates the need to remove valve bellows operability requirements from the Technical Specifications.
Safety Considerations Replacing the original 3 stage pilot operated activator with a redesigned 2 stage pilot operated actuator is consistent with General Electric's long term program to reduce the likelihood of failures of BWR safety relief valves, as described and recommended in a letter from B. K. Grimes to all Eoiling Water Reactor Licensees, dated July 16, 1979. Reference (a).
This change has been reviewed and approved by the Operations Review Committee and reviewed by the Nuclear Safety Review and Audit Committee.
Schedule of Change Approval of this change is requested prior to startup from our current refueling outage.
Boston Edison Company proposes that pursuant to 10 CFR Part 170 this is a Class II amendment.
s a
Attachments J
LIMITING CONDITION FOR OPERATION SURVEILLANCE REQUIREMENT i
3.6.C Coolant Chemistry (Cont'd) 4.6 power operation is permissible only during the succeeding seven
< lays.
3.
If the conditions in'1 or 2 above cannot be met, an orderly shutdown shall be initiated and the reactor shall be in a Cold Shutdown Condi-tion within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
D.
Safety and Relief Valves D.
Safety and Relief Valves 1.
During reactor power operating 1.
At least one safety valve and two conditions and prior to reactor relief / safety valves shall be startup from a Cold Condition, or checked or replaced with bench whenever reactor coolant pressure checked valves once per operating is greater than 104 psig and tem-cycle. All valves will be tested perature greater than 340 F, both avery two cycles.
safety valves and the safety modes
.if all relief valves shall be op-The set point of the safety valves erable.
shall be as specified in Specifi-cation 2.2.
2.
At least one of the relief / safety valves shall be disassembled and inspected each refueling outage.
3.
If Specification 3.6.D.1 is not met, an orderly shutdown shall be initi-ated and the reactor' coolant' l
126 i
LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENT 3.6.D Safety and Relief Valves (Cont'd) pressure shall be below 104 psig within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
E.
Jet Pumps E.
Jet Pumps 1.
Whenever the reactor is in the Whenever there is recirculation flow startup or run modes, all jet with the reactor in the startup or pumps shall be operable.
If it is run modes, jet pump operability shall determined that a jet pump is be checked daily by verifying that inoperable, an orderly shutdown the following conditions do not oc-shall be initiated and the reactor cur simultaneously:
shall be in a Cold Shutdown Condi-tion within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
1.
The two recirculation loops have a flow imbalance of 15%
or more when the pumps are operated at the same speed.
2.
The indicated value of core flow rate varies from the value derived from loop flow measurements by more than 10%.
3.
The diffuser to lower plenum differential pressure reading on an individual jet pump varies from established' jet pump P charac' eristics by more than 10%.
F.
Jet Pump Flow Mismatch F.
Jet Pump Flow Mismatch 1.
Whenever both recirculation pumps Recirculation pump speeds shall be are in operation, pump speeds shall checked and logged at least once he maintained within 10% of each per day.
other when power 1cvel is greater than 80% and within 15% of each l
other when power level is less than or equal to 80%.
l 8;.
. Structural Integrity G.
Structural Integrity f
1.
The structural integrity of the The nondestructive inspections listed l
primary system boundary shall in Table 4.6.1 shall be performed as be maintained at the level re-specified.
The results obtained from quired by the ASME Boiler and compliance with this specification l
Pressure Vessel Code, Section will be evaluated after 5 years and l
XI, " Rules for Inservice In-the conclusions of this evaluation spection of Nuclear Power will be reviewed with AEC.
Plant Components," 1974 127
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ATTACHMENT E Technical Specification Change to ECCS High Drywell Pressure Setpoint Proposed Change Reference is made to PNPS Technical Specifications, Appendix A, pages 27, 45 and 48 The desired change consists of raising the High Drywell Pressure trip level setting from 12 psig to 12.5 psig.
Reason for Change Current Technical Specifications require that a A P between the drywell and suppression chamber be maintained at equal to or greater than 1.50 psid. This requirement coupled with the High Drywell Pressure trip setting of 52 psig, impose operational hardships that could be lessened by raising this setpoint to 12.5 psig.
Safety Considerations The ECCS high drywell setpoint was originally set a) low enough to give proper safety system response, and b) high enough to avoid spurious safety system activation (Ref:
FSAR Section 7.4 and Bases for PNPS Technical Specification 3.2).
Accident analyses (e.g. LOCA Analysis, NED 21696 and FSAR Amendment #20) have been performed with a setpoint of 2.0 psig. These analyses assumed initiation of an accident with a unpressurized drywell followed by analyzed pressurization to 2.0 psig at which time ECCS actuation is initiated.
thrk I Containment studies and resultant analyses have resulted in a Tech-nical Specification requirement of normal drywell pressurization of 1.5 psi above the containment wetwell which is nominally atmospheric. This has resulted in the normal operating pressure of the drywell being substantially closer to the ECCS set point.
It is therefore desireable to increase the drywell Technical Specification setpoint to 2.5 psig to reduce the potential for spurious ECCS actuation.
The initiation time of the ECCS system depends primarily on the rate of pressure rise in the drywell and the pressure difference between the setpoint and normal operation.
Since the first parameter is relatively unaffected by the initial drywell pressure and since the proposed setpoint change will re-sult in a pressure difference between normal operation and the setpoint less than that used in previous LOCA analyses, the change will result in a more responsive performance of 'ECCS Systems following drywell pressurization than -
in the original analyses.
This change has been reviewed by the Nuclear Safety Review and Audit
' Committee and has been reviewed and approved by the Operations Review Committee.
Schedule of Change
- Approval of this change is requested prior to startup from our current refueling outage.
Boston Edison Company proposes that pursuant to 10CFR Part 170 this is a Class II Amendment.
Attachments
RFSCTOR P2UTECTION SYSTEM (SCRAM)
TRUMENTATION REQUIREMENT Mina. Number Modes in Vhich Function Operabia Inst.
Mult Be Operablo Channels per Trip Trip Function Trip Level Setting Refuel (7)
Startup/ Hot Run Action (1)
(1) System Standby 1
Mode Switch in Shutdown X
X X
i A
1 Manual Scram I
X X
A IRM 3
High Flux 5120/125 of full scale X
X (5)
A 3
Inoperative X
X (5)
A APRM 2
High Flux (14) (15)
(17)
(17)
X A or B 2
Inoperative X
X(9)
X A or B 2
Downscale 2 2.5 Indicated on Scale (11)
(11)
X(12)
A or B 2
High Flux (15%)
515% of Design Power X
X (16)
A or B 2
High Reactor Pressure
$1085 psig X(10)
X X
A l
2 High Drywell Pressure
$2.5 psig X(8)
X(8)
X A
2 Reactor Low Water Level 29 In. Indicated Level X
X X
A 2
High Water Level in Scram Discharge Tank 139 Gallons X(2)
X X
A 2
Turbine Condenser Low Vacuum 123 In. Hg Vacuum X(3)
X(3)
X A or C 2
Main Steam Line High 57X Normal Full Power Radiation
Background
X X
X A or C 4
Main Steam Line Isolation valve Closure 110% Valve Closure X(3) (6)
X(3) (6)
X(6)
A or C 2
72rb. Cont. Valve Fast 1150 psig Control Oil Closure Pressure at Acceleration Relay X(4)
X(4)
X(4)
A or D 4
Turbine Stop Valve Closure
$10% Valve Closure X(4)
X(4)
X(4)
A or D U
- APRM high flux scram setpoint s(.65W + 55)~ A ~
Two recirc. pump operation
- MTPF.
m%m
PNPS TABLE 3.2.A INSTRUMEhTATION THAT INITIATES PRIMARY CONTAINMENT ISOLATION Minimum i of Operable Instrument Channels Per Trip System (1)
Instrument Trip Level Setting Action (2) 2(7)
Reactor Low Water Level L9" indicated level (3)
A and D 1
Reactor High Pressure
$L110 psig D
2 Reactor Low-Low Water Level at or above -49 in.
A indicated level (4) 2 Reactor High Water Level tL48" indicated level (5)
B l
2(7)
High Drywell Pressure
<2.5 psig A
2 High Radiation Main Steam y_7 times normal rated B
Line Tunnel full power background 2
Low Pressure Main Steam Line
> 880 psig (8)
B 2(6)
Digh Flow Main Steam Line
<140% of rated steam flow B
2 Main Steam Line Tunnel Exhaust Duct High Temperature 1,170 F B
0 2
Turbine Basement Exhaust Duct High Temperature
<150 F B
0 1
Reactor Cleanup System High Flow 1,300% of rated flow C
s-2 Reactor Cleanup System High Temperature
- (150 F C
1
PNPS TABLE 3.2.B (Cont'd)
INSTRUMENTATION TH**T INITIATES OR CONTROLS THE CORE AND CONTAINMENT COOLING SYSTEMS Minimum # of Operable Instrument Channels Per Trip System (1)
Trip Function Trip Level Setting Remarks 2
High Drywell Pressure j[2.5 psig 1.
Initiates Core Spray; LPCI; HPCI.
2.
In conjunction with Low-Low Reactor Water Level.
120 second time delay and LPCI or Core Spray pump running, initiates Auto Blowdown (ADS).
3.
Initiates starting of Diesel Generators.
I Reactor Low Pressure 400 psig f;25 Permissive for Opening Core Spray and LPCI Admission valves.
1 Reactor Low Pressure
<110 psig In conjunction with PCIS signal permits closure of RHR (LPCI) injection valves.
1 Reactor Low Pressure 400 psig + 25 In conjunction with Low-Low Reactor Water Level initiates Core Spray and LPCI.
2 Reactor Low Pressure 900 psig + 25 Prevents actuation of LPCI am break detection circuit.
,e; ATTACID!ENT F PROPOSED TECHNICAL SPECIFICATIONS FOR PILGRIM NUCLEAR POWER STATION ATWS RPT/ARI PROPOSED CHANGES Page 44a Add a new LCO as follows:
Recirculation Pump Trip / Alternate Rod Insertion Initiation "G.
Whenever the reactor is in the RUN mode, the limiting conditions for operation for the instrumentation listed in Table 3.2.G shall be met."
Add a new Surveillance Requirement as follows:
"G.
Recirculation Pump Trip / Alternate Rod Insertion l
Surveillance for instrumentation which initiates f
Recirculation Pump Trip and Alternate Rod Insertion i
shall be as specified in Table 4.2-G."
Page 59a - Insert a new page as shown in Exhibit B.
This page includes Table 3.2.G and notes pertaining to the table.
j Page 66a - Insert an additional item in table 4.2.G as shown in Exhibit B which provides RPT/ARI instrumentation surveillance requirements.
i l
Page 67 - Modify notes to include Table 4.2.G.
Insert the paragraphs shown in Exhibit B which state the bases Page 73 for the recirculation pump trip and alternate rod insertion systems and the limiting conditions for operation. ' Additionally three references are added.
Page 77 - Insert the paragraph shown in Exhibit B whic rod insertion instrumentation.
REASON FOR CHANGES Numerous studies have been performed to assess the probability and consequences of the failure to scram immediately following an abnormal operational transient. In volume 3 of NUREG 0460, the Staff proposed requirements including installation of a reciculation pump trip system as a means of substantially reducing maxisum reactor vessel pressure in The proposed technical spect-the unlikely event of a failure to scram.
fications for the new trip system are modeled after the specifications In addition, an alternate rod for existing protective instrumentation.
insertion system has been proposed to provide a diverse means for initiation of control rod insertion.
SAFETY CONSIDEP.ATIONS A safety evaluation for the ATWS Recirculation Pump Trip and Alternate Rod Insertion systems ATVS RPT/ARI was submitted on the docket for the Monticello Nuclear Generating Plant (Docket No. 50263, License No. DPR-This evaluation was reviewed by the NRC Staff and a favorable 22).
23, 1977 for the RPT Safety Evaluation Report was issued on February Since the RPT/ARI systems proposed for the Pilgrim Nuclear function.
Power Station are essentially identical to that described in the Monticello evaluation only the minor differences and facets unique to l
the technical specifications will be considered in depth here.
The proposed limiting condition for operation requires the recirculation pump trip system to be operable when the reactor is in the RUN mode and the alternate rod insertion system to be operable in all modes except REFUELING. Since the capacity of the safety / relief valves is far in excess of the steam generation rate achievable in any other mode, there is no potential for vessel overpressurization in modes other than RUN.
Restricting the LCO to the RUN mode for the RPT function is therefore appropriate.
The proposed operability requirements are similar to those of like systems. These requirements were assumed in the design and reliability analysis of the trip system.
The proposed surveillance requirements incorporate the fact that analog transmitters are used in ATVS RPT/ARI systems. These devices are a new, improved line of BWR instrumentation. The calibration frequency is therefore proposed to be once per operating cycle which is consistent with both the equipment capabilities and the requirements for similar The calibration frequency for equipment used by other reactor vendors.
the trip units isproposed to be quarterly, the same as other similar Likewise, the test frequency is specified protective instrumentation.
A sensor as monthly like that of other protective instrumentation.
l check is proposed unce per day; this is considered to be an appropriate l
frequency, commensurate with the design applications and the fact that the recirculation pump trip / alternate rod insertion systems are backups to existing protective instrumentation..
With the implementation of the above proposed technical specification changes, there is adequate assurance that the ATWS RPT/ARI systems will perform to provide the intended plant protection in the extremely low probability of a plant transient with a failure to scram.
As discussed above, the ATWS RPT/ARI systems proposed are essentially identical with the systems as described on the Monticello docket. Several changes have been made to improve the system which are described below:
The Monticello ATWS RPT design as approved by the NRC Staff was not coupled with an ARI system. The ARI system design is; however, identical with the ARI design provided by Monticello in their safety evaluation report, with the exceptions noted below:
The Monticello RPT design includes a " Manual Initiation" push button on the operator control console. The proposed RPT/ARI design removes this push button but does provide manual control of the ARI function from the operator control console. Manual initiation of RPT at the console is unnecessarily redundant due to the variety of means already available to the operator for manually tripping the recirculation pumps or otherwise reducing recirculation flow.
The addition of the ARI function results in additional crowding of the operator control console.
In order to reduce this crowding the manual reset push buttons have been eliminated and automatic reset logic sub-stituted. Although the Monticello RPT design included a seal-in logic with manual reset it is unntessarily redundant.
Once a trip signal actuates the field breakers, it can be removed without affecting the state of the field breakers. The field breakers must be manually reset.
Therefore, the automatic reset feature only reduces the manual actions required to reset the pumps for operation and does not affect the trip function. The ARI automatic reset logic includes a seal-in logic for a 30 second interval to assure sufficient time to blow down the pilot air header and insure complete rod insertion. The automatic reset cannot function, however, if the trip signal is still present.
In this case an additional 30 seconds of delay will occur before reset and this sequence will continue until the trip signal is removed.
The high pressure setpoint for ATVS RPT/ARI as proposed is higher than the specification for the Monticello RPT. With the current plant con-figuration initiation of the ATWS RPT function is predicted during certain pressurization transients if the ATWS RPT setpoint is not raised.
Since the initiation of ATWS RPT causes an increase in severity of the transients this is an undesirable condition.
Raising the setpoint decouples the more frequent pressurization transients from ATWS RPT With the proposed setpoint, the only events which will initiate effects.
ATWS RPT are the turbine / generator trip with bypass failure and the ASME l
overpressure protection event (MSIV closure with trip scram failure).
The turbine / generator trip events will not result in exceeding the vessel pressure limit despite the increased severity due to ATWS RPT initiation and the limiting event will remain the MSIV closure with trip scram failure.
The MSIV closure event, with ATWS RPT, has a margin of 34 psi to the ASME code limit with the higher setpoint of 1160 psig.
Increasing the AWS RPT setpoint will also affect the peak pres peak pressure but it is expected to result in less than 25 psi increase during an ATVS event.
The qualified DC power supplies and DC to AC inverter specified for th ATVS RPT/ARI systems are not currently available.
power supplies and elimination of the inverter are necessary changesT pending resolution of the supply difficulty.
One power supply cabinet includes two qualified 24 VDC power supplies.is The second power supply is in the event of loss of offsite power.
inverter (125 VDC sourced by the station batteries (125 VDC) through an The uninterruptible power supplied by the inverter allows the system logic to remain energized during the event of loss of offs to 115 VAC).
The temporary power until the transfer to onsite generators occurs. modifica RI during a loss of offsite power event.
In the unlikely event of loss of offsite power, a trip of the recircula-tion pumps and the ARI function can be initiated without the inverter.
A pump trip occurs when the offsite AC power is interrupted deene The ARI function can be the motor of the recirculation pump MG sets. initiated manua The ARI manual trip utilizes power from the of power annunciator.125 VDC station batteries to actuate the solenoid-o air valves.
A failure of one or both power supplies alerts the opera The ARI can be manually initiated as explained above.
lation pumps.
In order to maintain the diversity of the original design the following steps are proposed:
l The ATVS cabinets would include provisions for installation of the 1.
inverters at a later date.
I The ATVS cabinets would include non-safety qualified power supp 2.
to be replaced or qualified later.
The changes which have been incorporated into the proposed desig change the basic functions of the ATVS systems as described for the Monticello RPT/ARI system.
the Nuclear Safety Review and Audit These changes have been reviewed byCommittee and review
SCllEDl'LE OF CilANGE Approval of this change is requested prior to startup from our current refueling outage.
Boston Edison Company proposes that pursuant to 10 CFR Part 170 this is a Class II Amendment.
Attachments
EXHIBIT A LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS G.
Recirculation Pump Trip / Alter-G.
Recirculation Pump Trip / Alternate nate Rod Insertion Initiation Rod Insertion The recirculation pump trip Surveillance for instrumentation system causes a pump trip on which initiates Recirculation a' signal of high reactor dome Pump Trip and Alternate Rod Inser-pressure or low-low reactor water tion shall be as specified in level when the mode select Table 4.2-G.
switch is in the RUN mode. The alternate rod insertion system provides for initiating control rod insertion whenever the mode switch is in the RUN, STARTUP or SHUTDOWN mode.
The limiting con-ditions for operation for the instrumentation are listed in Table 3.2-G.
I e
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PNPS TABLE 3.2-G INSTRUMENTATION THAT INITIATES RECIRCULATION PUMP TRIP AND ALTERNATE ROD INSERTION Minimum Number of Operable or Tripped Mode Select Instrument Channels Trip Level Settino Requirements (2)
Per Trip System (1)
Trip Function 2
High Reactor 1160 psig A/B Pressure 2
Low-Low Reactor
> 78.5" above the A/B Water Level top of the active fuel NOTES Minimum number of operable trip systems shall be two.
1.
Required mode select when minimum number of operable or tripped 2.
channels are not satisfied:
Reactor in STARTUP, REFUEL or SHUTDOWN mode for recirculation A.
pump trip system.
Reactor in REFUEL mode for alternate rod insertion system.
B.
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PNPS Table 4.2-G Minimum Test and Calibration Frequency for ATWS RPT/ARI Instrumentation Instrument Instrument (2)
Instrument Functional (2) Calibration (2)
Check Channel Test 1.
Reactor High Pressure (1)
Once/ Operating Once/ day Cycle-Transmitter Once/3 months -
Once/ day Trip unit 2.
Reactor Low-Low Water Level (1)
Once/ Operating Once/ day Cycle-Transmitter Once/3 months -
Once/ day Trip unit M
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NOTES FOR TABLES 4.2. A THROUGH 4.2.G Initially once per ponth until exposure hours (M as defined onthe 1.
Figure 4.1.1) is 2.0 x 105; with an interval not less than one month nor more than three m Functional tests, calibrations and instrument checks are not required when these instruments are not required to be operable or are 2.
Functional tests shall be performed before each startup Calibrations tripped.
with a required frequency not to exceed once per week, of IRMs and SRMs shall be performed during each startup or during controlled shutdowns with a required frequency not to exceed once Instrument checks shall be performed at least once per day during those pericds when the instruments are required to be per week.
This instrumentation is ex 'pted from the functional test definition.
The functional test will consist of injecting a simulated electrical 3.
signal into the measurement channel.
These instrument channels will be calibrated using simulated electrical signals once every three months.
Simulated automatic actuation shall be performed once each operating Where possible, all logic system functional tests will be 4.
cycle.
performed using the test jacks.
Reactor low water level, high drywell pressure and high radiation main steam line tunnel are not included on Table 4.2.A since they 5.
are tested on Table 4.1.2.
The logic system functional tests shall include a calibration of time delay relays and timers necessary for proper functioning of 6.
the trip systems.
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3.2 BASES (Cont'd)
For each parameter monitored, as listed in Table 3.2.F, there are By comparing readings between two (2) channels of instrumentation.
the two (2) ch annels, a near continuous surveillance of instrument Any deviation in readings will initiate performance is available.an early recalibration, thereby maintaining instrument reafinos.
The recirculation pump trip / alternate rod insertion systems are consistent with the "Monticello RPT/ARI" design described in NEDO j
25016 (Referer ce 1) as referenced by the NRC as an acceptable design (Refer 6nce 2) for RPT.
Reference 1 provides both system The pump trip is provided descriptions and performance analyses.
to minimize reactor pressure in the highly unlikely event of a plant transient coincident with the failure of all contro l
High pressure sensors and low water levet scram.
negative reactivity feedback.The recirculation pump trip is only sensors initiate the trip.
required at high reactor power levels, where the safety / relief valves have insufficient capacity to relieve the steam which continues Requiring the to be generated in this unlikely postulated event.
trip to be operable only when in the RUN mode is therefore conserva-The low water level trip function includes a time delay of nine tive.
(9) seconds 1 one (1) second to avoid increasing the consequences of a postulated LOCA. This delay has an insignificant effect on ATWS consequences.
Alternate rod insertion utilizes the same initiation logic and functions as RPT and provides a diverse means of initiatin reactor s. cram.
system to depressurize the scram pilot air header, which in turn causes all control rods to be inserted.
References NEDO-25016, " Evaluation of Anticipated Transients Without Scram for the Monticello Nuclear Generating Plant," September 1.
1976.
NUREG 0460, Volume 3, December 1978.
2.
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4.2 8ASES (Cont'd) instruments of sia11ar design, a testing interval of once every three sonths has been found adequate.
The automatic pressure relief instrumentation can be considered to be a 1 out of 2 logic system and the discussion above applies also.
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The instrumentation which is required for the recirculation pump trip and alternate rod insertion systems incorporate analog trans-The mitters and are a new, improved line of BWR instrumentation.
calibration frequency is once per operating cycle which is consistent with both the equipment capabilities and the requirements for The calibration similar equipment used by other reactor vendors.
frequency of the trip units is proposed to be quarterly, the same as other similar protective instrumentation.
Likewise, the test frequency is specified at monthly like that of other protective instrumentation. A sensor check is proposed once per day; this is considered to be an appropriate frequency, commensurate with the design applications and the fact that the recirculation pump trip and alternate rod insertion systems are backups to existing protective instrumentation.
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ATTACIDfENT G Technical Specification Change to Containment Isolation Valve Logic Proposed Change Reference is made to Pilgrim Nuclear Power Station Technical Specification Appendix A, Table 3.7.1 " Primary Containment Isolation Valves".
The proposed change consists of providing high drywell pressure isolation signal to existing isolation logics for reactor water sample valves.
Reason For Change NUREG 0578 Section 2.1.4 (1) requires a diversity in parameters sensed for the initiation of containment isolation as described in Standard Review Plan 6.2.4.
In particular, isolation of all non-essential systems must be accomplished based on diverse signals indicative of a LOCA obtained from qualified Class IE systems.
The reactor water sample valves presently receive only one isolation signal (low low reactor water level)which meets the above criteria. A second isolation signal containing high drywell pressure will be added to the existing logics to provide the diverse signals required.
Safety Considerations The new isolation signals have been obtained from new auxiliary relays wired in parallel to existing isolation trip relays in Panels C941 and C942. The addition of these Class 1E relays to the existing circuits, the only interface with other safety components, does not degrade the logic circuit, as the wiring changes are accomplished in separate divisional Class IE Panels.
These design modifications do not diminish the ability of the affected components from performing their required safety function assuming a single active failure.
The installation is designed to withstand the affects of the most severe natural phenomena postulated, and does not increase the probability of occurrence or con-sequences of an accident or malfunction of equipment important to safety.
This change has been reviewed by the Nuclear Safety Review and Audit Committee and has been reviewed and approved by the Operations Review Committee.
Schedule of Change Approval of this change is requested prior to startup from our current refueling outage.
Boston Edison Company proposes that since this change is part of our implementation to the Commission's January 2,1980, Confinnatory Order (NUREG 0578), it is exempt from any fees associated with 10 CFR 170.
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.w TABLE 3.7.1 PRIMARY CONTAINMENT ISOLATION VALVES Number of Power Maximum Action on Operated Valves Operating Normal Initiating Group Valve Identification Inboard Outboard Time (sec.)
Position Signal 1
Main Steam Line isolation valves 4
4 3iT d-5 0
CC 1
Main steam line drain isolation valves 1
1 30 C
SC 1**
Reactor Water sample line isolation valves 1
1 10 C
SC 2
Drywell purge supply isola-C(l)
SC tion valves 2
15 0(1)
GC 2
Suppression chamber purge supply isolation valves 2
15 0
GC l
E 2
Nitrogen purge isolation valve 1
10 0
CC E
2 Nitrogen makeup isolation valve
-1 10 C
SC 2
Suppression chamber nitrogen makeup isolation valve 1
10 C
SC 2~
Drywell purge exhaust isola-tior valves 2
15 C
SC 2
Drywell exhaust isolation valves 2
10 C
SC 2
Suppression chamber purge exhaust isolation valves 2
15 C
SC 2
Suppression chamber exhaust isolation valves 2
10 C
SC
NOTES FOR TABLE 3.7.1 (Cont'd) 2.
High reactor vessel pressure 3.
High drywell pressure 3
t CROUP 4:
Isolation valves in the high pressure coolant injection system (HPCI) are closed upon any one of the following signals:
1.
HPCI steam line high flow 2.
High temperature in the vicinity of the HPCI steam line 3.
Low reactor pressure CROUP 5:
Isolation valves in the RCIC system are closed upon any one of the following signals:
1.
RCIC steam line high flow 2.
High temperature in the vicinity of the RCIC steam line i
3.
Low reactor pressure 1
CROUP 6: Actions in Group 6 are initiated by any one of the following:
8 1.
Reactor low water level 2.
Cleanup. area high temperature 3.
Cleanup inlet high flow I
- The RHRS shutdown cooling injection isolation valves require a Group 2 signal plus high reactor vessel pressure.
C*The Reactor Water Sample Line Isolation Valves initiate on a Group 1 signal plus high drywell pressure.
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ATTACKMENT H Proposed Technical Specifications Related To Fire Protection Alternate Shutdown Stations Proposed Technical Specifications Reference is made to PNPS Technical Specifications, Appendix A, pages 103, 104, 106, 107, 108, 109 and 194. The proposed technical specifications provide surveillance requirements for equipment not already covered by existing technical specifications.
Reason for Change Amendment #35 (Fire Protection) to our Operating License (DPR-35) required that an alternate shutdown system, independent of cabling and equipment in the cable spreading room be provided. As a result, modifications have been necessary which in turn require the inclusion of additional surveillance requirements into the technical specifications.
Safety Considerations This proposal has been reviewed and approved by the Operations Review Committee and reviewed by the Nuclear Safety Review and Audit Committee.
Schedule of Change This change will be put into effect upon receipt of approval by the Commission.
As stated in Amendment #35, no license amendment fee is required for technical spec-ifications made necessary as a result of Commission requested changes related to Fire Protection.
Attachments l
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LII41Til!G C0!!DITIO?!S FOR OPERATION SURVEILLA7!CE MI)UIH4TitT 3.$ CORE A!.'D CO!!TAff.'t'E!!T C001.1 TIC 1.5 CORE AflD CONTAITCEfff COOLING 4
SYSnXS SYSTFXS Applicability Applicability Applies to the operational status of Applies to the Surveillance Requirements the core and suppression pool cooling of the core and suppression pool cooling subsystems.
subsystems which are required when the correspondinC Limiting Condition for op-eration is in effect.
Objective Objective Tb assure the operability of the core To verify the operability of the core and and suppression 19o1 coolinC subsystems suppression pool cooling subsyster.s under under all conditions for which this all conditions for which this cooling ca-cooling capability is an essential re-pability is an essential response to sta-sponse to station abnormalitiec.
tion abnormalities.
Specification Specification A.
Core Spray and 1,1'CI Subeveters A.
_ Core Serav and LPCI Cubr este-1 Both core spray cubsystems shall 1.
Core Spray Subsystem Testing.
be operable thenever irradiated fuel is in the vessel and prior Item Frequer.cy to reactor startup from a Cold
.a.
Simulated Once/Operatir.g Condition, except as specified A o atic Cycle in 3.5.A.2 below.
Actuation test.
b.
Pump Operability Once/ month and Once/ cycle from the Alternate Shutdown Panel c.
!!otor Operated Once/ month and Valve Operability Once/ cycle from the Alternate Shutdown Panel i
d.
Pump flow rate Each pump shall deliver at least 3600 gpm against a system head corresponding to a reactor vessel pressure of 104 psig, e.
Core Spray licader A p Instrumentation e
103 m.
LIMITING CONDITIONS FOR OPERATION SURVEILLANCE EQUIPMENT 3.5.A Core Spray and LPCI Subsystems 4.5.A Core Spray and LPCI Subsystems (con t' d)
(cont'd)
Check Once/ day Calibrate Once/3 months Test Once/3 months 2.
From and after the date that one 2.
When it is determined that one core of the core spray subsystems is spray subsystem is inoperable, made or found to be inoperable the operable core spray subsystem, for any reason, continued reactor the LPCI subsystem and the diesel operation is permissible during generators shall be demonstrated to the succeeding seven days, pro-be operable immediately.
The oper-vided that during such seven days able core spray subsystem shall be all active components of the other d'emonstrated to be operable daily core spray subsystem and active thereafter.
components of the LPCI subsystem and the diesel generators are op-erable.
3.
The LPCI Subsystems shall be oper-3.
LPC1 Subsystem Testing shall be as able whenever irradiated fuel is follows:
in the reactor vessel, and prior to reactor startup from a Cold a.
Simulated Automa-Once/ Operating Condition, except as specified tic Actuation Test Cycle in 3. 5. A. 4, 3. 5. A. 5 and 3. 5. F. 5.
b.
Pump Operability Once/ month and Once/ cycle from the Alternate Snutdown Panel c.
!!otor Operated once/!onth and valve operability once/ cycle from-the Alternate Shutdown Panel d.
Pump Flow Once/3 months Three LPCI pumps shall deliver 14,400 gpm against a system head corresponding to a vessel pressure of 20 psig l
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104
- o LIMITING CONDITION FOR OPERATION SURVEILLANCE REQUIREMENT 3.5.B Containment Cooling subsystem 4.5.B Containment Cooling Subsystem 1.
Except as specified in 3.5.B.2, 1.
Containment Cooling Subsystem Testing
- 3. 5.B. 3, and 3.5.F.3 below, shall be as follows:
both containment cooling subsystem loops shall be operable whenever Item Frequency irradiated fuel is in the reactor Pump & Valve Operability Once/3 months vessel and reactor coolant temper-a.
ature is greater than 2120F, and and Once/ cycle prior to reactor startup from a fron the Alternate Cold Condition.
Shutdown Station b.
Pump Capacity Test After pump Each RBCC11 pump shall raintenance deliver 1700 gpa at and every 70 ft. TDH.
Each SSWS 3 nonths pump shall deliver 2700 gpm at 55 ft. TDH.
c.
Air test on drywell and once/5 years torus headers and nozzles 106
= >
,'s LIMITING CONDITION FOR OPERATION SURVEILLANCE REQUIREMENT 3.5.B Containment Coolina subsystem 4.5.5 Containment Coolina Subsystem (Cont'd)
(Cont'd) 2.
From and after the date that one 2.
When one containment cooling subsystem containment cooling subsystem loop loop becomes inoperable, the operable is made or found to be inoperable subsystem loop and its associated f or any reason, continued reactor diesel generator shall be demonstrated operation is permissible only during to be operable immediately and the the succeeding seven days unless operable containment cooling subsystem such subsysten loop is sooner made loop daily thereafter.
operable, provided that the other containment cooling subsystem loop, including its associated diesel generator, is operable.
3.
If the requirements of 3.5.B can-not be met, an orderly shutdown shall be initiated and the reac-tor shall be in a Cold Shutdown Condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
C.
HPCI Subsystem C.
HPCI Subsystem 1.
The HPCI Subsystem shall be oper-able whenever there is irradiated 1.
RPCI Subsystem testing shall be per-fuel in the reactor vessel, reactor formed as follows:
pressure is greater than 104 psig, and prior to reactor startup from a.
Simulated Auto-Once/ operating a Cold Condition, except as speci-matic Actuation cycle fled in 3.5.C.2 and 3.5.C.3 below.
Test b.
Pump Operability Once/ month and Once/ cycle from the Alternate Shut-down Station c.
Motor Operated Once/ month and Valve Operability Once/ cycle from the Alternate Shutdown Station d.
Flow Rate at once/3 months 1000 psig e.
Flow Rate at Once/ operating 150 psig cycle l
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LIMITING CONDITION FOR OPr_MAnote
- ' own v r.2 wud. k w -- -
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3.5.C HPCI Subsyste9 (Cont'd)
'4.5.C HrCI Subsysten (C:nt'd) e The HPCI pump shall deliver at least 4250 gpm for a sys-tem head corresponding to a reactor pressure of 1000 to 150 psig.
2.
From and after the date that the 2.
When it is determined that the HPCI HPCI Subsystem is made or found to Subsystem is inoperable the RCIC, the be inoperable for any reason, con-LPCI subsystem, both core spray sub-tinued, reactor operation is per-systems, and the ADS subsystem actua-missible only during the succeed-tion logic shall be demonstrated to ing seven days unless such subsys-be operable immediately. The RCIC tem is sooner made operable, pro-system and ADS subsystem logic shall viding that during such seven be demonstrated to be operable daily days all active components of the thereafter.
ADS subsystem, the RCIC system, the LPCI subsystem and both core spray subsystems are operable.
3.
If the requirements of 3.5.C can-not be met, an orderly shutdown shall be initiated and the reac-tor pressure shall be reduced to or below 104 psig within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
3 5.D Reactor core Isolation Cooling 4.5.D Reactor core Isolation Cooling (RCIC) Subsystem (RCIC) Subsystem 1.
The RCIC Subsystem shall be oper-1.
RCIC Subsystem testing shall be per-able whenever there is irradiated formed as follows:
fuel in the reactor vessel, the re-l actor pressure is greater than 104 a.
Simulated Auto-Once/ operating psig, and prior to reactor startup matic Actuation cycle from a Cold Condition, except as Test specified in 3.5.D.2 below, b.
Pump Operability Once/ month and l
Once/ cycle from I
the Alternate l
Shutdown Station c.
totor Operated Once/ month and Valve Operability Once/ cycle fron the Alternate Shutdown Station 108
LIMITING CONDITION TOR OPERATION SUHVEILI/J.CE REQUI!CC?iTS 3 5.D Reaeter Cero Icalation Coolinc 4.5.D Reactor Core Isolation Cooling (RCIC) Subsystem (Cont'd)
(RCIC) Subsystem (Cont'd) d.
Flow Rate at Once/3monthe 1000 psig e.
Flow Rate at once/ operating 150 psig cycle The BCIC pump shal.1 deliver at least 400 sp= for a system hett corresponding to a reactor pres-sure of 1000 to 150 psig 2.
From and after the date that the 2.
When it is determined that the RC1C RCICS is made or found to be inop-subsystem is inoperable, the hPCIO erable for any reason, continued shall be deconstrated to be operstle reactor power operation is percis-immediately and veekly thereaf ter, sible only during the succeeding seven days provided that during such seven days the HPCIS is oper-able.
3.
If the requirements of 3.5.D cannot be met, an orderly shutdown shall be initiated and the reactor pres-sure shall be reduced to or below 104 psig within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
3.5.E Auto =atic Depressurization 4.5.E Auto =atic Depressurization System ( ADS)
System ( ADS) 1.
The Automatic Depressurization Sub-1.
Daring each operating cycle the system shall be operable whenever following tests shall be performed there is irradiated fuel in the on the ALO*
reactor vessel and the reactor pres-sure is greater than 104 psig and a.
A simulated automatic accustion prior to a startup from a Cold Con-test shall be perforced prior to dition, except as specified in startup after each refueling out-3 5.E.2 below.
age.
This test shall also be performed l
from the Alternate Shutdown Station within the same time frame.
b.
With the reactor at pressure, each relief valve shall be man-ually opened until a corresponding change in reactor pressure or main turbine bypass valve positions indicate that steam is flowing from the valve 109
...o LIMITING CONDITIONS st)R OPERATION SURVEILIANCE RirlUIRDfENTS 3 9 AUXILIARY ELECTRICAL SYSTEM 4 9 AUXILIARY ELECUtICAL SYSTD4 Applicability:
Applicability:
Applies to the auxiliary electrical Applies to the periodic testing re-power system.
quirements of the auxiliary electri-cal systems.
Objective:
Objective:
To assure an adequate supply of elec-Verify the operability of the
. trical power for operation of those auxiliary electrical system.
~
systems required for safety.
Specification:
Specification:
A.
Auxiliary Electrical Equipment A.
Auxiliary Electrical Dauipment Surveillance The reactor shall not be made critical 1.
Diesel Generators unless all of the following conditions are satisfied:
a.
Each diesel generator shall be manually started and loaded once each month to
)
At least one offsite transmission line' demonstrate operational readiness. The and the startup transformer are avail-test shall continue for at least a able and capable 'of automatically one hour period at rated load, supplying auxiliary power to the emer-gency buses, During the monthly generator test the diesel generator starting air compres-2.
An additional source of offsite power sor shall be checked for operation and consisting of one of the following:
its ability to recharge air receivers.
The operation of the diesel fuel oil a.
A transmission line and shutdown trans-transfer pumps shall be demonstrated, former capable of supplying power to and the diesel starting time to reach the emergency 4160 volt buses, rated voltage and frequency shall be logged.
b.
The main transformer and unit auxiliary transformer available and capable of Also, once per operating cycle the diesel supplying power to the emergency 4160 generator shall be manually started and volt buses.
loaded from the Alternate Shutdown Static 3
Both diesel generators shall be oper-able. Each diesel generator shall have
- b. Once per operating cvele the condition a minimum of 19,800 gallons of diesel under which the diesel generator is required will be simulated and a test fuel on site, conducted to demonstrate that it will start and accept the emergency load within the specified time sequence.
The results shall be logged.
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