ML20128P449
| ML20128P449 | |
| Person / Time | |
|---|---|
| Site: | Mcguire, Catawba, McGuire, 05000000 |
| Issue date: | 07/22/1985 |
| From: | DUKE POWER CO. |
| To: | |
| Shared Package | |
| ML20128P431 | List: |
| References | |
| TAC-59320, TAC-59321, TAC-59322, TAC-59623, TAC-59624, TAC-60930, NUDOCS 8507260418 | |
| Download: ML20128P449 (31) | |
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ATTACHMENT 1 Duke Power Company Catawba Nuclear Station McGuire Nuclear Station Proposed Technical Specification Relaxation of RTS Requirements Background and Discussion l
8507260418 850722 PDR ADOCK 05000369 P
BACKGROUND AND DISCUSSION In response to growing concerns of the impact of current testing and maintenance requirements on plant operation, particularly as related to instrumentation systems, the Westinghouse Owners Group (WOG) initiated a program to develop a justification to be used to revise generic and plant specific instrumentation technical specifications.
Operating plants experienced many inadvertent reactor trips during performance of instrument-ation surveillance, causing unnecessary transients and challenges to safety systems.
Significant time and effort on the part of the operating staff was devoted to performing, reviewing, documenting and tracking the various surveillance activities, which in many instances seemed unwarranted based on the high reliability of the equipment.
Significant benefits for operating plants appeared to be achievable through revision of instrumentation test and maintenance requirements.
On February 3, 1983 the Westinghouse Owners Group (Reference 3) submitted WCAP-10271, " Evaluation of Surveillance Frequencies and Out of Service Times for the Reactor Protection Instrumentation System" (Reference 1) to the NRC as the first step in gaining approval of the instrumentation program. WCAP-10271 documents the justification to be used to justify revisions to technical specifications. The justification consists of the deterministic and numerical evaluation of the effects of particular technical specification changes with consideration given to such things as safety, equipment requirements, human factors and operational impact.
The objective is to reach a balance in which safety and operability are ensured.
The technical specification revisions evaluated were increased test and maintenance times, less frequent surveillance, and testing in bypass.
In July 1983 the NRC requested additional information from the WOG (Reference
- 4) required for continued review.
The WOG responded in October 1983 (Reference
- 5) with responses to the NRC concerns and Supplement 1 (Reference 2) to WCAP-10271 which contains information in addition to that in WCAP-10271.
Specifically, Supplement 1 demonstrates the applicability of the justification contained in WCAP-10271 to reactor protection systems for two, three and four loop plants with either relay or solid state logic.
Additionally this supple-ment extends the evaluation to topics not addressed in the original WCAP such as the interdependence (or lack there of) of surveillance intervals and hard-ware failure rates.
In February 1985 the NRC issued the SER (Reference 6) for WCAP-10271 and Supplement 1.
The SER approve 5 quarterly testing, a 6-hour outage time, increased test time and testing in bypass for analog channels.
At a meeting with Harold Denton on January 9, 1985 convened to discuss the forthcoming SER the Westinghouse Owners Group made a commitment to develop a guidance document to facilitate plant specific technical specification change requests resulting from the approval of WCAP-10271.
The NRC strongly encouraged the preparation of this sort of document in the meeting. The purpose of this guidance document was to ensure consistency in plant specific submittals in order to expedite NRC review.
This guidance document has been utilized by Duke Power Company in the preparation of this proposed license amendment.
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REFERENCES 1.
WCAP-10271, " Evaluation of Surveillance Frequencies and Out of Service Times for the Reactor Protection Instrumentation System", January 1983.
2.
WCAP-10271 Supplement 1, " Evaluation of Surveillanco Frequencies and Out of Service Times for the Reactor Protection Instrumentation System",
July 1983.
3.
Letter (0G-86) from J. J. Sheppard (WOG - CP&L) to H. R. Denton (NRC) dated February 3,1983 (WCAP-10271 submittal).
4.
Letter from C. O. Thomas (NRC) to J. J. Sheppard (WOG - CP&L) dated July 28,1983 (NRC Request Number 1 for Additional Information on WCAP-10271).
5.
Letter (0G-106) from J. J. Sheppard (WOG - CP&L) to C. O. Thomas (NRC) dated October 4,1983 (WCAP-10271 Supplement 1 and question response submittal).
6.
Letter from C. O. Thomas (NRC) to J. J. Sheppard (WOG - CP&L) dated February 21, 1985 (NRC safety evaluation for WCAP-10271).
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ATTACHMENT 2 4
Duke Power. Company Catawba Nuclear Station i
McGuire Nuclear Station Proposed Technical Specification Relaxation of RTS Requirements Technical Specification Changes Approved by NRC and NRC Imposed Conditions i
TECHNICAL SPECIFICATION CHANGES APPROVED BY NRC Four specific changes were approved by the Nuclear Regulatory Commission.
These changes are limited to the specific RPS channels evaluated in the WCAP and are subject to the specific conditions specified by NRC.
The NRC conditions that must be addressed by each utility are addressed elsewhere in this document.
No changes to the testing of the actuation logic and reactor trip breakers were approved at this time.
1.
The surveillance or test frequency may be changed from monthly to quarterly.
2.
The time allowed for a channel to be inoperable or out of service in an untripped condition may be changed from one hour to six hours.
3.
The time a channel in a functional group may be bypassed to perform testing may be increased from two to four hours.
This bypass time applies to either an inoperable channel when testing is done in the tripped mode or to the channel in test when testing is done in the bypass mode.
4.
Routine channel testing may be performed in the bypassed condition instead of the tripped condition.
Attachments 4, 5 of this submittal provide proposed technical specifications which implement three of the approved revisions described above.
The RPS functions which were evaluated in WCAP-10271 and Supplement 1 and to which the SER is applicable are listed below.
Protective Function 1.
High Flux Power Range, High Setpoint 2.
High Flux Power Range, Low Setpoint 3.
High Negative Flux Rate 4.
High Positive Flux Rate 5.
High Flux Intermediate Range 6.
High Flux Source Range 7.
Overtemperature Delta-T 8.
Overpower Delta-T 9.
Pressurizer Pressure, Low 10.
Pressurizer Pressure, High 11.
Pressurizer Water Level, High 12.
Loss of Flow, Single Loop 13.
Loss of Flow, Two Loop 14.
Steam Generator Water Level, Low-Low 15.
Steam Flow / Feed Flow Mismatch With Low Steam Generator Level 16.
RCP Bus Undervoltage 17.
RCP Bus Underfrequency 18.
RCP Underspeed, Low 19.
RCP Underspeed, Low-Low 20.
Turbine Trip 2-1
Even though NRC has approved a relaxation of the surveillance frequency from monthly to quarterly,iple reason is the administrative burden of testing R Duke Power has elected not to request this change at this time.
The princ components quarterly and ESFAS components monthly.
Many of the components serve both RTS and ESFAS functions and would result in more time being spent in setting up for testing than would be saved by going to quarterly testing.
Furthermore, due to the complexity of the system, there would be an increased likelihood of a missed surveillance.
Presently, an evaluation is in progress at Westinghouse on the ESFAS components, similar to that previously done on RTS.
Following NRC approval of the ESFAS review, Duke plans to submit a proposed Technical Specification change tha+. would allow relaxation of both RTS and ESFAS surveillance intervals simultaneously.
Three of the five conditions of approval provided by NRC relate to implementa-tion of quarterly surveillance interval on RTS components.
In as much as Duke is postponing implementation of this relaxed surveillance interval, Duke is also delaying our response to these conditions of approval.
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NRC IMPOSED CONDITIONS The NRC has imposed five conditions on utilities seeking to implement the technical specification changes approved generically as a result of their review of WCAP-10271.
The Duke response to each of these conditions is provided.
1 The first condition requires the use of a staggered test plan for the RPS channels changed to the quarterly test frequency.
As stated by NRC in the safety evaluation for WCAP-10271:
System unavailability, or probability of failure due to common cause, i proportional to the time between staggered tests.
There-fore, if the test interval is expanded, the failure probability will increase.
A staggered plan which " spreads" the channel testing over the quarter rather than " concentrating" the channel testing would reduce the potential for common cause function failure and at the same time still accomplish the goals set forth by the Owners Group.
Accordingly, the staff's acceptance of less frequent surveillance is contingent on the implementation of a staggered test plan.
Duke is postponing the implementation of quarterly testing for reasons as discussed in the cover letter.
Thus, no commitment to implement a stagger-ed test plan is provided at this time.
However, this condition will be revisited after NRC approval of the forthcoming ESFAS review is completed.
2 The second condition requires that plant procedures require a common mode evaluation for failure in the RPS channels changed to the quarterly test frequency and additional testing for plausible common cause failures.
As stated by NRC in the safety evaluation for WCAP-10271:
The staff's evaluation of RPS unavailability assumed that common cause failures would be identified during testing.
The staff's assumption was that the identification would occur because all the additional channels in a function would be tested whenever one channel failed a test. However, from a practical standpoint, there are several kinds of failures which the staff does not regard as common failures, e.g., instrument drift and failure of power to a single channel.
Additional testing is not necessary for these failures or other failures if the cause of those other failures can be evaluated and shown not to affect multiple channels.
In order to validate the staff's underlying assumption, the staff's acceptance of less frequent surveillance is contingent on implementation of procedures to identify common cause failures and to test the other channels which may be affected by the common cause.
2-3
Duke is postponing the implementation of quarterly testing for reasons as discussed in the cover letter.
Thus, no commitment to evaluate common cause failures is provided at this time.
However, this condition will be revisited after NRC approval of the forthcoming ESFAS review is completed.
3 The third condition requires installed hardware capability for testing in the bypass mode. As stated by NRC in the safety evaluation for WCAP-10271:
Testing of the RPS analog channels in the bypassed condition by use of temporary jumpers or by lifting leads is not acceptable. The chance of personnel errors leaving a number of channels in the bypassed condition would be too large for the routine use of such methods. Therefore, licensees choosing this option to perform routine channel testing in the bypass mode should ensure that the plant design allows testing in bypass without lifting leads or installing temporary jumpers.
The staff's acceptance of this option is contingent on confirmation of this capability.
Testing in bypass will not be permitted by administrative procedures until bypass hardware capability is installed.
Duke is planning to install the necessary bypass hardware capability during the next refueling outages of each unit.
Duke will design and install any and all hardware changes necessary to allow testing in bypass in accordance with the existing licensing basis and to review the hardware changes in accordance with 10CFR50.59.
4 The fourth condition involves channels that provide input to both the RPS and the engineered safety feature actuation system (ESFAS).
As stated by HRC in the safety evaluation for WCAP-10271:
In order to avoid confusion in plant technical specifications regarding such dual function channels, the staff concludes that either (1) the channels should not be changed in the RPS tables until the ESFAS review is finished or (2) cautionary notes in the RPS tables should refer to the more stringent ESFAS requirements.
The Westinghouse Owners Group recommends that the proposed changes to the RPS technical specifications be made for all evaluated channels and that appropriate cautionary statements be added to the action statements referencing the more stringent requirements for the ESFAS channels.
Administrative controls will be established to ensure that the more restrictive requirements are observed.
Duke is proposing in this sub-mittal appropriate cautionary statements be added to the Technical Specifications.
5 The fifth condition addresses setpoint drift.
As stated by NRC in the safety evaluation for WCAP-10271:
Based on review of previous Westinghouse topical reports, the staff notes that margin is included in the channel setpoint determination to account for possible instrument drift over a one month surveill-2-4
ar ance' interval.
Accordingly, the staff's acceptance is contingent on confirmation that the instrument setpoint methodology includes suffi-cient adjustments to offset the drift anticipated as a result of less frequent surveillance.
Duke is postponing the implementation of quarterly testing for reasons as discussed in the cover letter.
Thus, no commitment to evaluate set-point drift over a three month period is provided at this time.
- However, this condition will be revisited after NRC approval of the forthcoming ESFAS review is completed.
k 2-5
ATTACHMENT 3 Duke Power Company Catawba Nuclear Station McGuire Nuclear Station Proposed Technical Specification Relaxation of RTS Requirements No Significant Hazards Consideration
SIGNIFICANT HAZARDS EVALUATION Significant Hazards Consideration Analysis - Pursuant to 10CFR50.91 and 10CFR50.92 for the Proposed Amendents to the McGuire, Catawba Reactor Protection System Instrumentation Technical Specifications.
Proposed Changes The generic changes approved are as follows:
1.
Increase the surveillance interval for RPS analog channel operational tests from once per month to once per quarter, 2.
Increase the time during which an inoperable RPS analog channel may be maintained in an untripped condition from one hour to six hours, 3.
Increase the time an inoperable RPS analog channel may be bypassed to allow testing of another channel in the same function from two hours to four hours, and 4.
Allow RPS analog channel testing in a bypassed condition instead of a tripped condition.
Revisions to the McGuire, Catawba Reactor Protection System (RPS)
Instrumentation Technical Specification are proposed for items 2, 3, 4 above.
Analysis Duke Power Company has reviewed the requirements of 10CFR50.92 as they relate to the proposed RPS technical specification changes for the McGuire and Catawba Nuclear Stations and determined that a significant hazards consideration is not involved.
The generic analysis provided by WOG considers that all four changes are made in one amendment to Technical Specifications. With only three of the changes being proposed by Duke at this time, the analysis conclusion is conservative and remains valid.
Duke is utilizing the existing generic analysis for the sake of convenience and ease of NRC review.
Criterion 1 - Operation of McGuire, Catawba in accordance with the proposed license amendment does not involve a significant increase in the probability or consequences of an accideat previously evaluated.
Implementation of the proposed changes is expected to result in an increase in total Reactor Protection System yearly unavailability of less than 3%.
This increase, which is primarily due to less frequent surveillance, results in a like increase (approximately 3%) in the probability of an Anticipated Transient Without Trip (ATWT) and in the probability of core melt resulting from an ATWT.
With this slight increase, the probability of ATWT and core melt from ATWT remain within published acceptance criteria.
Implementation of the proposed changes is expected to result in a 30%
reduction in the probability of core melt from inadvertent reactor trips.
This is a result of a reduction in the number of inadvertent reactor trips (.5 fewer inadvertent reactor trips per unit per year) occurring during testing of RPS instrumentation.
This reduction is primarily attributable to testing in bypass and less frequent surveillance.
3-1
The overall impact of implementation of the proposed changes is expected to be a 1% reduction in total core melt probability.
The reduction in inadvertent core melt probability is sufficiently large to counter the increase in ATWT core melt probability resulting in the overall reduction in total core melt probability.
The proposed changes do not result in an increase in the severity or consequences of an accident previously evaluated.
Implementation of the proposed changes affects the probability of failure of the RPS but does not alter the manner in which protection is afforded nor the manner in which limiting criteria are established.
Criterion 2 - The proposed license amendment does not crente the possibility of a new or different kind of accident from any accident previously evaluated.
The proposed changes do not result in a change in the manner in which the Reactor Protection System provides plant protection.
No change is being made which alters the functioning of the Reactor Protection System (other than in a testmode).
Rather, the likelihood or probability of the Reactor Protection System functioning properly is affected as described above. Therefore, the proposed changes do not create the possibility of a new or different kind of accident nor involve a reduction in a margin of safety as defined in the Safety Analysis Report.
The proposed changes do not involve hardware changes except those necessary to implement testing in bypass.
Some existing instrumentation is designed to be tested in bypass and current technical specifications allow testing in bypass.
Testing in bypass is also recongized by IEEE Standards. Therefore testing in bypass has been previously approved and implementation of the proposed changes for testing in bypass does not create the possibility of a new or different kind of accident from any previously evaluated.
Furthermore since the other proposed changes do not alter the functioning of the RPS the possibility of a new or different kind of accident from any previously evaluated has not been created.
Criterion 3 - The proposed license amendment does not involve a significant reduction in a margin of safety.
The proposed changes do not alter the manner in which safety limits, limiting safety system setpoints or limiting conditions for operation are determined.
The impact of reduced testing other than as addressed above is to allow a longer time interval over which instrument uncertainties (e.g., drift! may act.
Experience at two Westinghouse plants with extended surveillance intervals has shown the initial uncertainty assumptions to be valid for reduced testing.
Implementation of the proposed changes is expected to result in an overall improvement in safety by:
a.
.5 fewer inadvertent reactor trips per unit.
This is due to less frequent testing and testing in bypass which minimizes the time spent in a partial trip condition.
3-2
o b.
Higher quality repairs leading to improved equipment reliability due to longer repair times.
c.
Improvements in the effectiveness of the operating staff in monitoring and controlling plant operation.
This is due to less frequent distraction of the operato* and shift supervisor to attend to instrumentation testing.
Example 10CFR50 - Statements of Consideration contains, " Examples of Amendments that are Considered Not Likely to Involve Significant Hazards Considerations".
One of the examples provided is:
(vi) A change which either may result in some increase to the probability or consequences of a previously-analyzed accident or may reduce in some way a safety margin, but where the results of the change are clearly within all acceptable criteria with respect to the system or component specified in the Standard Review Plan; for example, a change resulting from the application of a small refinement of a previoulsy used calculational model or design method.
As previously stated implementation of the proposed changes results in a slight increase in the probability of ATWT and ATWT core melt.
With this increase the probability of core melt from ATWT remains within published acceptance criteria.
Overall core melt probability decreases.
Implementation of the proposed changes does not increase the consequences of a previously analyzed accident nor reduce a margin of safety.
Functioning of the RPS and the manner in which limiting criteria is established is unaffected.
The stated example of a change which is likely not to involve a significant hazards consideration is applicable therefore to the proposed changes.
Conclusion The foregoing analysis demonstrates that the proposed amendment to the McGuire, Catawba Technical Specifications does not involve a significant increase in the probability or consequences of a previously evaluated accident, does not create the possibility of a new or different kind of accident and does not involve a significant reduction in a margin of safety.
Additionally fewer inadvertent reactor trips are expected, equipment reliability is expected to increase and operator effectiveness is expected to improve.
Based upon the preceding analysis, Duke concludes that the proposed amendment does not involve a significant hazards consideration.
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ATTACHMENT 4 3
2-1 Duke Power Company McGuire Nuclear Station Proposed Technical Specification Relaxation of RTS Requirements 1-1 I
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TABLE 3.3-1 r
E5 REACTOR TRIP SYSTEM INSTRtMENTATION j'
E
/
MINIMUM d
TOTAL NO.
CHANNELS CHANNELS APPLICABLE 5
FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERA 8tE MODES ACTION 3
1.
1 2
1, 2 1
2 1
2 3*, 4*, 5*
10 g
E 2.
Power Range, Neutron Flux - High 4
2 3
1, 2 2
[
Setpoint I
Low 4
2 3
1,,,, 2 2,
Setpoint 3.
Power Range, Neutron Flux 4
2 3
1, 2 2
High Positive Rate 4.
Power Range, Neutron Flux, 4
2 3
1, 2 2
High Negative Rate 5.
Intermediate Range, Neutron Flux 2
1 2
1
,2 3
6.
Source Range, Neutron Flux 2,,
4 a.
Startup 2
1 2
b.
Shutdown 2
1 2
3*,
4*, 5*
10 5
c.
Shutdown 2
0 1
3, 4, and 5 7.
Overtemperature AT Four Loop Operation 4
2 3
1, 2 6
Three Loop Operation
(**)
(**)
(**)
(**)
(**)
D O
O
., f
~
\\
t y f
=
go
M E
E m
TABLE 3.3-1 (Continued) g REACTOR TRIP SYSTEM INSTRUMENTATION a
MINIMUM TOTAL NO.
CHANNELS CHANNELS APPLICABLE h
FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION 8.
Overpower AT Four Loop Operr. tion 4
2 3
1, 2 6
Three Loop Operation
(**)
(**)
(**)
(**)
(**)
9.
Pressurizer Pressure-Low 4
2 3
1 6
(***)
10.
Pressurizer Pressure-High 4
2 3
1, 2 6
(***)
11.
Pressurizer Water Level-High 3
2 2
1 6
l R
12.
Low Reactor Coolant Flow i
e a.
Single Loop (Above P-8) 3/ loop 2/ loop in 2/ loop in 1
6, I
w any oper-each oper-w ating loop ating loop b.
Two Loops (Above P-7 and 3/ loop 2/ loop in 2/ loop 1
6 below P-8) two oper-each oper-ating loops ating loop 13.
Steam Generator Water 4/sta. gen.
2/stm. gen.
3/stm. gen.
1, 2 6
l Level-Low-Low 3
in any oper-each oper-(***)
kg ating stm.
ating stm.
==33 gen.
gen.
9-.9 55 E1 ee
n'E TABLE 3.3-1 (Continued) m REACTOR TRIP SYSTEM INSTRUMENTATION j
g s
~d I
MINIMUM TOTAL NO.
CHANNELS CHANNELS APPLICABLE g
FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION l
to 14.
Undervoltage-Reactor Coolant 4-1/ bus 2
3 1
6 Pumps (above P-7) 1 15.
Underfrequency-Reactor Coolant 6
g Pumps (above P-7) 4-1/ bus 2
3 1
16.
l a.
Low Fluid Oil Pressure 3
2 2
1 6
~l b.
Turbine Stop Valve Closure 4
4 4
1 6#
(
.l 17.
Safety Injection Input
.}
l from ESF 2
1 2
1, 2 9
lY 18.
Reactor Trip System Interlocks a.
Intermediate Range gg Neutron Flux, P-6 2
1 2
2 8
b.
Low Power Reactor Trips Block, P-7 P-10 Input 4
2 3
1 8
of P-13 Input 2
1 2
1 8
c.
Power Range Neutron
{mE Flux, P-8 4
2 3
1 8
2 2
3 3
d.
Low Setpoint Power
. y$
Range Neutron Flux, P-10 4
2 3
1, 2 8
5 5
e.
Turbine Impulse Chamber (1
Pressure, P-13 2
1 2
1 8
5 E
d M
ea s
v
n
[
D D
TABLE 3.3-1 (Continued) b REACTOR TRIP SYSTEM INSTRUMENTATION 5
E MINIMUM TOTAL NO.
CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS
.T0 TRIP OPERABLE MODES ACTION g
.-.d 19.
Reactor Trip Breakers 2
1 2-1-2 9
A 2
1 2
3, 4*, 5*
10
~
k 20.
Automatic Trip and Interlock 2
1 2
I 2
9 Logic 2
1 2
3g, 4 *, 5*
10
.m j
R.
Y l
9 l
~.
l
{'
o "t/
y-
' t ih
TABLE 3.3-1 (Continued)
TABLE NOTATION With the Reactor Trip System breakers in the closed position, the Control Rod Drive System capable of rod withdrawal.
AA Values left blank pending NRC approval of three loop operation.
- Comply with the provisions of Specification 3.3.2, for any portion of the l
channel required to be OPERABLE by Specification 3.3.2.
- The provisions of Specification 3.0.4 are not applicable.
N Below the P-6 (Intermediate Range Neutron Flux Interlock) Setpoint.
- elow the P-10 (Low Setpoint Power Range Neutron Flux Interlock) Setpoint.
B ACTION STATEMENTS ACTION 1 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
ACTION 2 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:
a.
The inoperable channel is placed in the tripped condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, I
b.1 For Channels With Bypass Capability one additional channel may be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing per Specification 4.3.1.1 provided the inoperable channel is in the tripped condition.
b.2 For Channels With No Bypass Capability the Minimum Channels OPERABLE requirement is met; however, the in-operable channel may be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing of other channels per Specification 4.3.1.1.
c.
Either, THERMAL POWER is restricted to less than or equal to 75% of RATED THERMAL POWER and the Power Range Neutron Flux Trip Setpoint is reduced to less than or equal to 85% of RATED THERMAL POWER within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />; or, the QUADRANT POWER TILT RATIO is monitored at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> per Specification 4.2.4.2.
MCGUIRE - UNITS I and 2 3/4 3-6 Amendment No. (Unit 1)
Amendment No. (Unit 2)
/
TABLE 3.3-1 (Continued)
ACTION STATEMENTS (Continued)
ACTION 3 - With the number of channels OPERABLE one less than the Minimum Channels OPERABLE requirement and with the THERMAL POWER level:
a.
Below the P-6 (Intermediate Range Neutron Flux Interlock)
Setpoint, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above the P-6 Setpoint, and b.
Above the P-6 (Intermediate Range Neutron Flux Interlock)
Setpoint but below 10% of RATED THERMAL POWER, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above 10% of RATED THERMAL POWER.
ACTION 4 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement suspend all operations involving positive reactivity changes.
ACTION 5 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, verify compliance with the SHUTDOWN MARGIN requirements of Specification 3.1.1.1 or 3.1.1.2, as applicable, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter.
ACTION 6 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:
a.
The inoperable channel is placed in the tripped condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and I
4 b.1 For Channels With Bypass Capability one additional channel may be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing per Specification 4.3.1.1 provided the inoperable channel is in the tripped condition.
b.2 For Channels With No Bypass Capability the Minimum Channels OPERABLE requirement is met; however, the in-operable channel may be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing of other channels per Specification 4.3.1.1.
ACTION 7 - Delete.
l ACTION 8 - With less than the Minimum Number of Channels OPERABLE, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> determine by observation of the associated permissive annunciator window (s) that the interlock is in its required state for the existing plant condition, or apply Specification 3.0.3.
MCGUIRE - UNITS 1 and 2 3/4 3-7 Amendment No. (Unit 1)
Amendment No. (Unit 2)
TABLE 3.3-1 (Continued)
ACTION STATEMENTS (Continued)
ACTION 9 - With the number of OPERABLE channels one less than the Minimum
-Channels OPERABLE requirement, be in at least HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; however, one channel may be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing per Specification 4.3.1.1, l
provided the other channel is OPERABLE.
ACTION 10 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or open the Reactor trip breakers within the next hour.
3 MCGUIRE - UNITS 1 and 2 3/4 3-8 Amendment No. (Unit 1)
Amendment No. (Unit 2)
3/4.3 INSTRUMENTATION BASES 3/4.3.1 and 3/4.3.2 REACTOR TRIP AND ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION The OPERABILITY of the Reactor Trip and Engineered Safety Features Actuation System instrumentation and interlocks ensure that:
(1) the associated ACTION and/or Reactor trip will be initiated when the parameter monitored by each channel or combination thereof reaches its Setpoint, (2) the specified coincidence logic and sufficient redundancy is maintained to permit a channel to be out-of-service for testing or maintenance consistent with main-taining an appropriate level of reliability of the Reactor Protection and Engineered Safety Features instrumentation and, 3) sufficient system functions capability is available from diverse parameters.
The OPERABILITY of these systems is required to provide the overall reliability, redundancy, and diversity assumed available in the facility design for the protection and mitigation of accident and transient conditions.
The integrated operation of each of these systems is consistent with the assumptions used in the accident analyses.
The Surveillance Requirements specified for these systems ensure that the overall system functional capability is maintained comparable to the original design standards.
The periodic surveillance tests performed at the minimum frequencies are sufficient to demonstrate this capability.
Specified surveillance intervals and surveillance and maintenance outage 1
times have been determined in accordance with WCAP-10271, " Evaluation of Surveillance Frequencies and Out of Service Times for the Reactor Protection Instrumentation System", and supplements to that report.
Surveillance inter-vals and out of service times were determined based on maintaining an approp-riate level of reliability of the Reactor Protection System and Engineered Safety Features instrumentation.
(Implementation of quarterly testing of RTS is being postponed until after approval of a similar testing interval for ESFAS).
The measurement of response time at the specified frequencies provides assurance that the Reactor trip and the Engineered Safety Feature actuation associated with each channel is completed within the time limit assumed in the accident analyses.
No credit was taken in the analyses for those channels with response times indicated as not applicable.
Response time may be demonstrated by any series of sequential, overlapping, or total channel test measurements provided that such tests demonstrate the total channel response time as defined.
Sensor response time verification may be demonstrated by either:
(1) in place, onsite, or offsite test measurements, or (2) utilizing replacement sensors with certified response times.
The Engineered Safety Features Actuation System senses selected plant parameters and determines whether or not predetermined limits are being exceeded.
If they are, the signals are combined into logic matrices sensitive to combinations indicative of various accidents, events, and transients.
Once the required logic combination is completed, the system sends actuation signals to those Engineered Safety Features components whose aggregate MCGUIRE - UNITS 1 and 2 B 3/4 3-1
function best serves the requirements of the condition.
As an example, the following actions may be initiated by the Engineered Safety Features Actuation System to mitigate the consequences of a steam line break or loss-of-coolant accident:
(1) Safety Injection pumps start and automatic valves position, (2) Reactor trip, (3) feedwater isolation, (4) startup of the emergency diesel generators, (5) containment spray pumps start and automatic valves position, (6) containment isolation, (7) steam line isolation, (8) Turbine trip, (9)~ auxiliary feedwater pumps start and automatic valves position, and (10) nuclear service water pumps start and automatic valves position.
MCGUIRE - UNITS 1 and 2 B 3/4 3-la
1 9
ATTACHMENT 5 Duke Power Company Catawba Nuclear Station Proposed Technical Specification Relaxation'of RTS Requirements f
9$
h TABLE 3.3-1 REACTOR TRIP SYSTEM INSTRUMENTATION c-5 MINIMUM TOTAL NO.
CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION 1.
1 2
1, 2
1 2
1 2
3*, 4* and 5*
10 2.
Power Range, Neutron Flux a.
High Setpoint 4
2 3
1, 2 2#
b.
Low Setpoint 4
2 3-1###, 2 2#
3.
Power Range, Neutron Flux 4
2 3
1, 2 2#
High Posit.ive Rate 4.
Power Range, Neutron Flux, 4
2 3
1, 2 2#
R High Negative Rate u
{
5.
Intermediate Range, Neutron Flux 2
1 2
1###, 2 3
6.
Source Range, Neutron Flux a.
Startup 2
1 2
2##,
4 b.
Shutdown 2
1 2
3,4,5 5
7.
Overtemperature AT Four Loop Operation 4
2 3
1, 2 6#
8.
Overpower AT Four Loop Operation 4
2 3
1, 2 6,
9.
Pressurizer Pressure-Low 4
2 3
1 6 **
l
9C z5 TABLE 3.3-1 (Continued) c REACTOR TRIP SYSTEM INSTRUMENTATION 5*
MINIMUM
~
TOTAL NO.
CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION 10.
Pressurizer Pressure-High 4
2 3
1, 2 6 ** l 11.
Pressurizer Water Level-High 3
2 2
1 6
l 12.
Reactor Cooland Flow - Low 3/ loop 2/ loop in 2/ loop in 1
6#
(_
- a. Single Loop (Above P-8) any oper-each oper-ating loop ating loop
- b. Two Loops (Above P-7 3/ loop 2/ loop in 2/ loop 1
6#
(
and below P-8) two oper-each oper-ating loops ating loop s"
13.
Steam Generator Water 4/stm 2/stm gen 3/stm gen 1, 2 6#**f
't' Level-Low-Low gen in any each i
operating operating stm gen stm gen i
14.
Undervoltage-Reactor Coolant 4-1/ bus 2
3 1
6#**l Pumps (Above P-7) 15.
Underfrequency-Reactor Coolant 4-1/ bus 2
3 1
6#
i Pumps (Above P-7) 16.
- a. Low Control Valve EH Pressure 4
2 3
1####
6#
- b. Turbine Stop Valve Closed 4
4 4
1####
6#
17.
Safety Injection Input from ESF 2
1 2
1, 2 9
i
9 5!
r5 TABLE 3.3-1 (Continued)
REACTOR TRIP SYSTEM INSTRUMENTATION-MINIMUM
~
TOTAL NO.
CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION 18.
Reactor Trip System Interlocks a.
Intermediate Range Neutron Flux - P-6 2
1 2
2##
8 b.
Low Power Reactor Trip Block - P-7 P-10 input 4
2 3
1 8
or P-13 input 2
1 2
1 8
w c.
Power Range Neutron i
Flux - P-8 4
2 3
1 8
w A
d.
Power Range Neutron Flux, P-9 4
2 3
1 8
e.
Power Range Nuetron Flux, P-10 4
2 3
1 8
f.
Power Range Neutron Flux, Not P-10 4
3 4
1, 2 8
g.
Turbine Impulse Chamber Pressure, P-13 2
1 2
1 8
19.
Reactor Trip Breakers 2
1 2
1, 2 9
2 1
2 3*, 4*, 5*
10 4 D,
't; o 20.
Automatic Trip and Interlock 2
1 2
1, 2 9
d Logic 2
1 2
3*, 4*, 5*
10 Q
n%
4oa v.
TABLE 3.3-1 (Continued)
TABLE NOTATION
- 0nly if the Reactor Trip System breakers happen to be in the closed position and the Control Rod Drive System is capable of rod withdrawal.
- Comply with the provisions of Specification 3.3.2, for any portion of the I
channel required to be OPERABLE by Specification 3.3.2.
t
- The provisions of Specification 3.0.4 are not applicable.
- Below the P-6 (Intermediate Range Neutron Flux Interlock) Setpoint.
- Below the P-10 (Low Setpoint Power Range Neutron Flux Interlock) Setpoint.
- Above the P-9 (Reactor Trip on Turbine Trip Interlock) Setpoint.
ACTION STATEMENTS ACTION 1 - With the number of OPERABLE channels one less than the M Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
ACTION 2 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:
The inoperable channel is placed in the tripped condition a.
within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
b.1 For Channels With Bypass Capability one additional channel may be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing per Specification 4.3.1.1 provided the inoperable channel is in the tripped condition, b.2 For Channels with No Bypass capabilit OPERABLE requirement is met; however,y the Minimum Channels the inoperable channel may be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing of other channels per Specification 4.3.1.1.
Either, THERMAL POWER is restricted to less than or equal c.
to 75% of RATED THERMAL POWER and the Power Range Neutron I
Flux trip setpoint is reduced to less than or e 85% of RATED THERMAL POWER within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />; or, qual to t
the QUADRANT POWER TILT RATIO is monitored at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> per Specification 4.2.4.2.
ACTION 3 - With the number of channels OPERABLE one less than the Minimum Channels OPERABLE requirement and with the THERMAL POWER level:
Below the P-6 (Intermediate Range Neutron Flux Interlock) a.
Setpoint, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above the P-6 Setpoint; or CATAWBA - UNIT 1 3/4 3-5
EBLE3.3-1(Continued)
TABLE NOTATION b.
Above the P-6 (Intermediate Range Neutron Flux Interlock)
Setpoint but below~10% of RATED THERMAL POWER, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above 10% of RATED THERMAL POWER.
ACTION 4 - With the number of OPERABLE channels one less than th Channels OPERABLE requirement, suspend all operations involving positive reactivity changes.
ACTION 5 - With the number of OPERABLE channels one less than the Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or open the Reactor trip breakers, suspend all operations involving positive reactivity changes and verify Valves NV-231, NV-237, NV-241, and NV-244 are closed and secured in position within the next hour.
ACTION 6 - With the number of OPERABLE channels one less than the Tot Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:
The inoperable channel is.placed in the tripped condition a.
within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and I
b.1 For Channels With Bypass Capability one additional channel may be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing per Specification 4.3.1.1 provided the inoperable channel is in the tripped condition.
b.2 For Channels with No Bypass Capability the Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing of other channels per Specification 4.3.1.1.
ACTION 7 - Delete.
l ACTION 8-WithlessthantheMinimumNumberofCh within I hour determine by observation of the associated perm ve status light (s) that the interlock is in its required state for the existing plant condition, or apply Specification 3.0.3.
ACTION 9 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement be in at least HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; however, 'ne c,hannel may be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing per Specification 4.3.1.1, provided the other channel is OPERABLE.
ACTION 10 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or open the reactor trip breakers within the next hour.
4 CATAWBA - UNIT 1 3/4 3-6
3/4.3 INSTRUMENTATION BASES 3/4.3.1 and 3/4.3.2 REACTOR TRIP SYSTEM and ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION The OPERABILITY of the Reactor Trip and Engineered Safety Features Actuation System instrumentation and interlocks ensure that:
(1) the associated ACTION and/or Reactor trip will be initiated when the parameter monitored by each channel or combination thereof reaches its Setpoint, (2) the specified coincidence logic and sufficient redundancy is maintained to permit a channel to be out-of-service for testing or maintenance consistent with maintaining an appropriate level of reliability of the Reactor Protection and Engineered Safety Features instrumenation and, 3) sufficient system function capability is available from diverse parameters.
The OPERABILITY of these systems is required to provide the overall reliability, redundancy, and diversity assumed available in the facility design for the protection and mitigation of accident and transient conditions.
The integrated operation of each of these systems is consistent with the assumptions used in the accident analyses.
The Surveillance Requirements specified for these systems ensure that the overall system functional capability is maintained comparable to the original design standards.
The periodic surveillance tests performed at the minimum frequencies are sufficient to demonstrate this capability.
Specified surveillance intervals and surveillance and maintenance outage times have been determined in accordance with WCAP-10271, " Evaluation of Surveillance Frequencies and Out of Service Times for the Reactor Protection Instrumentation System", and supplements to that report.
Surveillance inter-vals and out of service times were determined based on maintaining an approp-riate level of reliability of the Reactor Protection System and Engineered Safety Features instrumentation.
(Implementation of quarterly testing of RTS is being postponed until after approval of a similar testing interval for ESFAS).
The Engineered Safety Features Actuation System Instrumentation Trip Setpoints specified in Table 3.3-4 are the nominal values at which the bis-tables are set for each functional unit.
A Setpoint is considered to be adjusted consistent with the nominal value when the "as measured" Setpoint is within the band allowed for calibration accuracy.
To accommondate the instrument drift assumed to occur between operational tests and the accuracy to which Setpoints can be measured and calibrated, Allowable Values for the Setpoints have been specified in Table 3.3-4.
Oper-ation with Setpoints less conservative than the Trip Setpoint but within the Allowable Value is acceptable since an allowance has been made in the safety analysis to accommodate this error.
An optional provision has been included
. for determining the OPERABILITY of a channel when its Trip Setpoint is found to exceed the Allowable Value.
The methodology of this option utilizes the "as measured" deviation from the specified calibration point for rack and sensor components in conjunction with a statistical combination of the other uncertainties of the instrumentation to measure the process variable and the uncertainities in calibrating the instrumentation.
In Equation 3.3-1, 2 + R + S < TA, the interactive effects of the errors in the rack and the sensor, anil the "as meaured" values of the errors are considered.
Z, as specified in Table 3.3-4, in percent span, is the statistical summation of CATAWBA - UNIT 1 B 3/4 3-1
l INSTRUMENTATION BASES REACTOR TRIP SYSTEM and ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION errors assum d in the analysis excluding those associated with the sensor and rack drift and the accuracy of their measurement.
TA or Total Allowance is the difference, in percent span, R or RACK Error is the "as measured" deviation, in the percent span, for the affected channel from the specified Trip Setpoint.
5 or Sensor Error is either the "as measured" deviation of the sensor from its calibration point or the value specified in Table 3.3-4, in percent span, from the analysis assumptions.
Use of Equation 3.3-1 allows for a sensor drift factor, an increased rack drift factor, and provides a thiashold value for REPORTABLE EVENTS.
The methodology to derive the Trip Setpoints is based upon combining all of the uncertainties in the channels.
Inherent to the determination of the Trip Setpoints are the magnitudes of these channel uncertainities.
Sensor and rack instrumentation utilized in these channels are expected to be capable of operating within the allowances of these uncertainty magnitudes.
Rack drift in excess of the Allowable Value exhibits the behavior that the rack has not met its allowance.
Being that there is a small statistical chance that this will happen, an infrequent excessive drfit is expected.
Rack or sensor drift, in excess of the allowance that is more than occasional, may be indicative of more serious problems and should warrant further investigation.
The measurement of response time at the specified frequencies provides assurance that the Reactor trip and the Engineered Safety Features actuation associated with each channel is completed within the time limit assumed in the safety analyses.
No credit was taken in the analyses for those channels with response times indicated as not applicable.
Response time may be demonstrated by any series of sequential, overlapping or total channel test measurements provided that such tests demonstrate the total channel response time as defined.
Sensor response time verification may be demonstrated by either:
(1) in place, onsite, or offsite test measurements, or (2) utilizing replace-ment sensors with certified response time.
The Engineered Safety Features Actuation System senses selected plant parameters and determines whether or not predetermined limits are being exceeded.
If they are, the signals are combined into logic matrices sensitive to combinations indicative of various accidents, events, and transients.
Once the required logic combination is completed, the system sends actuation signals to those Engineered Safety Features components whose aggregate function best serves the requirements of the condition.
As an example, the following actions may be initiated by the Engineered Safety Features Actuation System to mitigate the consequences of a steam line break or loss-of-coolant accident:
(1) Safety Injection pumps start and automatic valves position, (2) Reactor trip, (3) feedwater isolatinn, (4) startup ur the emergency diesel generators, (5) containment spray pumps start and automatic valves position, (6) containment isolation, (7) steam line isolation, (8) Turbine trip (9) auxiliary feedwater pumps start and automatic valves position, (10) nuclear service water pumps start and automatic valves position, and (11) component cooling pumps start and automatic valves position.
CATAWBA - UNIT 1 B 3/4 3-2