ML20052H930
| ML20052H930 | |
| Person / Time | |
|---|---|
| Site: | Summer  |
| Issue date: | 05/10/1982 |
| From: | NRC |
| To: | |
| Shared Package | |
| ML20052H927 | List: |
| References | |
| NUDOCS 8205240203 | |
| Download: ML20052H930 (55) | |
Text
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1 V. C. SUMMER, UNIT 1 i,
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l TECHNICAL SPECIFICATIONS, PROOF AND REVIEW 1
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ENCLOSURE 1 I
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$AFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS
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2.2 LIMITING SAFETY SYSTEM SETTINGS REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS 2.2.1 'The reactor trip system instrumentation and interlocks setpoints shall be consistent with the Trip Setpoint values shown in Table' 2.2-1.
APPLICABILITY: As shown for each channel in Table 3.3-1.
ACTION:
a.
With a reactor trip system instrumentation or interlock setpoint less con-servative than the value shown in the Trip Setpoint column of Table 2.2-1 adjust the setpoint consistent with the Trip Setpoint value.
b.
With a reactor tr.ip system instrumentati'on or interlock setpoint less con-servative than the vIlue shown in the Allowable Values column of Table 2.2-1, place the channel in the tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, and within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> either:
1.
Determine that Equation 2.2-1 was satisfied for the affected channel e
and adjust the setpoint consistent with the Trip Setpoint value of Table 2.2-1, or 2.
Declare the channel inoperable and apply the applicable ACTION state-ment requirement of Specification 3.3.1 until the cnannel is restored to OPERABLE status with its setpoint adjusted consistent with the Trip Setpoint value.
SUWiER-UNIT 1 '
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'h.2 LIMITING SAFETY SYSTEM SETTIfiGS C
y EQUATION 2.2-1 Z + R + S 6::TA q.
where:
Z = the value from column Z of Table 2.2-1 for the affected channel, R = the "as measured" value (in percent span) of rack error for the affected channel, S = either the "as measured" value (in percent span) of the sensor error, or the value in column S of Table 2.2-1 for the affected channel, and TA = the value from column TA of Table 2.2-1 for the affected channel.
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j-TABLE 2.2.-1 r%
l REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS g
s C,
Functional Unit Total Allowance (TA)
Z S
C Trip Setpoint Allowable Value Il 1.
Manual Reactor Trip Not Applicable NA NA NA NA W.
2.
Power Range, Neutron Flux 7.5 4.56 0
High Setpoint
-<109% of RTP
-<111.2% of RTP l
l 1
I Low Setpoint 8.3 4.'56 0
3.
Power Range, Neutron Flux 1.6 0.5 0
<5% of RTP with
<6.3% of RTP with I
i High Positive Rate i time constant i time constant >2 l
>2 seconds seconds
~
4.
Power Range, Neutron Flux 1.6 0.5 0
<5% of RTP with
<6.3% of RTP with j
High Negative Rate i time constant i time constant >2
>2 seconds seconds h
5.
Intermediate Range, 17.0 8.4 0
125% of RTP 131% of RTP Neutron Flux f
5 5
6.
Source Range, Neutron Flux 17.0 10.0 0
110 cps 11.4 x 10 cp 7.
Overtemperature AT 7.1 2.94 0.8 See note 1 See note 2 l
8.
Overpower AT 4.5 1.4 0.2 See note 3 See note 4 9.
Pressurizer Pressure-Low 3.1 0.71 1.5
>1870 psia
>1859 psig
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~
10.
Pressurizer Pressure-High 3.1 0.71
- 1. 5 12380 psig 12391 psig r
4 l).
11.
Pressurizer Water Level-iligh 5.0 2.18
- 1. 5 192% of instru-593.8% of instru-
)
ment span ment span 12.
Loss of Flow 2.5 1.0 1.5
>90% of loop
>89.2% of loop design flow
- design flow" i
l Loop design f1on = 98,000 gpm p 7 p : f a re a we n s t.
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REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS Functional Unit Total Allowance (TA)
Z_
5_
Trip Setpoint Allowable Value 13.
Steam Generator Water 12.0 9.18 1.5
>12% of span
>10.2% of span 0
Level Low-Low G
Trom 0 to 30%
from 0 to 30% RTP
- Q' RTP increasing increasing linearly linearly to >
to >53.1% of span W
~
54.9% of span from 30% to 100% R1 from 30% to 100%
RTP 14.
Steam /Feedwater Flow Mis-16.0 13.24 1.5/1.5 <40% of full
<42.5% of full i
i Hatch Coincident With iteam flow at iteam flow at RT'P ! '
'i g.pp RM uc. el
.hted Thermai
-Rowa %
Powe*
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Steam Generator Water Level 12.0 9.18
- 1. 5
>12% of span
>10.2% of span t
g Low-Low
'i Trom 0 to 30% RTP Trom 0 to 30% RTP increasing increasing linearly linearly to >
to >53.1% of span 54.9% of spaii from froin 30% to 100% RTP 30% to 100% RTP 15.
Undervoltage - Reactor 2.1 1.28 0.23
->4830 volts
>4760 Coolant Pump 16.
Underfrequency - Reactor 7.5 0
0.1
->57.5 M4
->57.
/r Coolant Pumps 1
)
17.
Turbine Trip A.
Low Trip System Pressure NA NA NA
>800 psig
>750 sig B.
Turbine Stop Valve Closure NA NA NA
>1% open
>1% o n grp Ag$ RnTED TII6fAAL Auto
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j TABLE 2.2.-1 REACTOR TRIP SYSTEM 1NSTRUMENTATION TRIP SETPOINTS Funct.ional Unit Total Allowance (TA)
.Z.
.S.
Trip Setpoint Allowable Value o
9 18.
Safety Injection Input NA NA NA NA NA
'I from ESF F
19.
Reactor Trip System Interlocks
-10
-11 A.
Intermediate RanDe NA NA NA 11 x 10 amps 16 x 10 amps Neutron Flux, P-6
}
B.
Low Power Reactor Trips Block, P-7 RJP
}
a.
P-10 input 7.5 4.56 0
110%ofentedDP
$12.2% of rebed t+re rz a; p e c r lher:21 ps.cr b.
P-13 input 7.5 4.56 0
<10% Turbine
<12.2% of turbine Impulse Pressure Impulse Pressure D
Equivalent Equivalent LTP W
C.
Power Range Neutron 7.5 4.56 0
<38% of pabed 7
<ther='! peeer 40.2% of cated Flux P-8 therma 4-pewee i
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D.
Low Setpoint Power 7.5 4.56 0
>10% of certvd
>7.8% of rated Range Neutron Flux, P-10 Th at = ' '
^ ci-:e r Iba w l y wer E.
Turbine Impulse Chamber 7.5 4.56 0
<10% turbine
<12.2% turbine Pressure, P-13 Tmpulse pressure jiressure equivalent equivalent 20.
Reactor Trip Breakers NA NA NA NA N)k 21.
Automatic Actuation Logic NA NA NA NA A
b.
l gre = Race Ti a n (- Batt l
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1 TABLE 2.2-1 (Continued)
REACTOR TRIP SYSTEM INSTRUMENTATION TPIP SETPOINTS I
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NOTATION C-NOTE 1:
OVERTEMPtRATURE AT
--q
) [T (7
{I (1 + T 5) 1 AT [K
-K 1
AT
) - T'I+ K (P - P') - f (AI))
t 2
3 t
t 3
g Where:
AT
=
Measured AT by RTO Manifold Instrumentation I
t Lead-lag compensator on measured AT
=
It, T2 Time constants utilized in lead-lag controller for AT, 1 = 8 sec.,
i
=
T2 = 3 sec.
1 Lag compensator on measured AT
=
1+13 Ta Time constants utilized in the lag compensator for AT, 13 = 4 secs.
=
D AT
=
Indicated AT at RATED THERMAL POWER
\\
o K
1.090
=
3 K
=
0.01450 2
1 * **6 1*Tb The function generated by the lead-lag controller for T
=
dynamic compensation avg.
5 Time constants utilized in the lead-lag controller for Tavg.
t, = 33 secs.,
14, & Is
=
is = 4 secs.
Average temperature *F T
=
1 1,7,3 Lag compensator on measured T,yg
=
l Timi constant utilized in the measured T,yg, lag compensator, is = 4 secs.
=
Ts t
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TABLE 2.2-1 (Continued) i REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS of y
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@TATION(Continued) f g
NOTE,1:
(Continued) l 3
T' 5
587.4*F Reference T,yg at RATED TilERM't. POWER b.
Ka
.0006728 I
=
I Pressurizer pressure, psig
/
P
=
P' 2235 psig, Nominal RCS operating pressure i
=
Laplace transform operator, sec 1 S
=
I and f (AI) is a function of the indicated difference between top and bottom detectors of the I
t power-range nuclear ion chambers; with gains to be selected based on measured instrument response j
during plant startup tests such that:
i D
(i) for qt 9b between - 34 percent and + 8 percent f (al) = 0 where qt and q are percent y
b b
RATED TilERMAL POWER in the top and bottom halves of the core respectively, and qt
- 9 IS b
total TilERMAL POWER in percent of RATED TitERMAL POWER.
i (ii) for each percent that the magnitude of qt q exceeds -34 percent, the AT trip setpoint b
shall be automatically reduced by 1.67 percent of its value at RATED TilERMAL POWER.
(iii) for each percent that the magnitude of q(
qb exceeds +8 percent, the AT trip setpoint I
shall be automatically reduced by 1.11 percent of its value at RATED TilERMAL POWER.
NOTE 2:
The channel's maximum trip setpoint shall not exceed its computed trip point by more than 3.9 percent AT an.
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TABLE 2.2-1 (Continued) u g REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS i
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NOTATION (Continued)
O9 NOTE 3:
OVERPOWER AT T 3) (1 f S}
[K - Ks (y*! 3 ) (1 # 7s3) T - Ka [T (1 TsS} ~
- (6I)]
b 1
I AT y
~
T3 O
7 Where:
AT as defined in Note 1
=
fI i
as defined in Note 1
=
i T1. T2 as defined in Note 1
=
as defined in Note 1 i
=
TS 1
3
- 3 as defined in Note 1
=
AT, as defined in Note 1
=
I
{
K 1.091 4
~
0.02/*F for increasing average temperature and 0 for decreasing average Ks
=
temperature The function generated by the rate-lag controller for T,yg dynamic compensation
=
i 1
15 7
I Time constant utilized in the rate-lag controller for T,yg
=
17 7 = 10 secs.
t y) as defined in Note 1
=
4 3
ta as defined in Note 1
=
e I
5 O
s y
i
.un t H
g 1u TABLE 2.2-1 (Continued)
C3 REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS 3!L i
g NOTATION (Continued)
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., NOTE.3 (continued) s Cq Ks 0.001190 for T > T" and Ks = 0 for T 1 I"
=
i E
T as defined in Note 1
=
I" 1
587.4?F Reference T at RATED THERMAL POWER avg S
as defined in Note 1
=
Ii f (AI) 0 for all AI
=
2 l#
NOTE 4:
The channel's maximum trip setpoint shall not exceed its computed trip point by more than 3.1 percent AT Span.
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BASES 2.2.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS The Reactor Trip 5e:pefr.t i.1mits specified in Table 2.2-1 are the nominal values
'at which the Reactor Trips are set for each functional unit.
The Trip Setpoints have been selected to ensure that the reactor core and reactor coolant system are prevented from exceeding their safety limits during normal operation and design basis anticipated operational occurrences and to assist the Engineered Safety Features Actuation System in mitigating the consequer.ces of accidents. The set-point for a reactor trip system or interlock function is considered to be adjusted consistent with the nominal value when the "as measured" setpoint is within the band allowed for calibration accuracy.
To accommodate the instrument drift assumed to occur between((gffp)I$J U c.
u.
and the accuracy to which setpoints can be measured and calibrated, Allowable Values for the reactor trip setpoints have been specified in Table 2.2-1.
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 ana,
lysis 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 method 16gy of this option utilizes the "as measured" deviation from the specified calibration point for rack and ensor components in conjunction with a statistical combination of the other uncertain-ties of the instrumentation to measure the process variable and the uncertainties in calibrating the instrumentation.
In Equation 2.2-1, Z + R + S6 TA, the inter-active effects of the errors in the rack and the sensor, and the "as measured" values of the errors are considered.
Z, as specified in Table 2.2-1, in percent h
span, is the statistical summation of errors assumed in the analysis excluding s.
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BASES g': ;.-
REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS (continued) those associated with the sensor and rack drift and the accuracy of their measure-ment.
TA or Total Allowance is the difference, in percent span, between the trip setpoint and the value used in the analysis for reactor trip.
R or Rack Error is the "as measured" deviation, in percent span, for the affected channel from the specified trip setpoint.
S or Sensor Error is either the "as measured" deviation of the sensor from its calibration point or the value specified in Table 2.2-1, in p:rcent span, fro,m the analysis assumptions.
Use of Equation 2.2-1 allows for a sensor drift factor, an increased rack drift factor, and provides a h*4 threshold value for REPORTABLE OCCURRENCES.
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 set-points are the magnitudes of thesa channel uncertainties.
Sensors and other instrumentation utilized in these channels are expected to be capable of opera-ting within the allowances of these uncertainty magnitudes. Rack drift in exces,s +
'of the Allowable Value exhibits the behavior that the rack has not met its allow-ance. Being that there is a small statistical chance that this will happen, an infrequent excessive drift is expected.
Rack or sensor drift, in excess of the l
allowance that is more than occasional, may be indicative of more serious problems i
l and should warrant further investigation.
i
.The various reactor trip circuits automatically open the reactor trip breakers whenever a condition monitored,hy, the Reactor Protection System reaches a preset or calculated level.
In addition to redundant channels and trains, the design i
?.. ' approach provides a Reactor Protection System which monitors numerous system L^
variables, therefore, providing protection system functionsl diversity.
1456i7 f60 (A4f 6 2-3 d.
BASES i
i REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS (continued)
The Reactor Protection System initiates a turbine trip signal whenever reactor trip is initiated.
This prevents the reactivity insertion that would otherwi'se result from excessive reactor system cooldown and thus avoids unnecessary actu-ation of the Engineered Safety Features Actuation System.
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M 2.2 1.IMITING SAFETY SYSTEM SETTINGS
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i BASES-I I
N.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETPCINTS Reactor Trip Setpoint Limits specified in Table 2.2-1 ar he nominal values which the Reactor Trips are set for each functional u The Trip i
Setpoints e been selected to ensure that the reactor core reactor coolant sys re prevented from exceeding their safety li s during normal f
operation and gn basis anticipated operational occurr es and to assist the Engineered Sa Features Actuation System in siti ing the consequences I
of accidents. The ious reactor trip circuits auto ically open the reactor rip breakers whenever condition monitored by the
' actor Protection System resches a preset 9r calc ted level. In additio o redundant channels and I
p/numerou,ssystemvariables,the trains the design approach ovides a Reactor P tection System which monitors fore, providi protection system functional i
diversity. The functional capab ty at th pecified trip settings is
[
required for those anticipatory or ~ ers eactor trips for which no direct t
credit was assumed in the accident ana s to enhance the overall reliability f
of the Reactor Protection System.
I The Reactor Protection Syste nitiates a bine trip signal whenever i
reactor trip is initiated. Thi revents the rea ity insertion that would otherwise. result from excessi. reactor system cool and thus avoids g;/
unnecessary actuation of th ngineered Safety Features uation System.
[
l Operation with a set less conservative than its Tr1 tpoint but I
within its specified owable Value is acceptable on the basis the i
difference between h Trip Setpoint and the Allowable Value is e to or less than the dri allowance for all trips including those trips ass in the safety ana es.
I b ual Reactor Trip The Reactor Protection System includes manual reactor trip capability.
Power Range. Neutron Flux In each of the Power Range Neutron Flux channels there are two independent i
bistables, each with its own trip setting used for a high and low range trip setting. The low setcoint trip provides protection during subcritical and low power operations to mitigate the consequences of a power excursion beginning i
from low power, and the high setpoint trip provides protection during power operations to mitigate the consequences of a reactivity excursion from all power levels.
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SUMMER - UNIT 1 B.1-3J/.
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2 LIMITING SAFETY SYSTEM SETTINGS g
BASES PowerR$nge,NeutronFlux(Continued)
The low setpoint trip may be manually blocked above P-10 (a power level of approximately 10 percent of RATED THERMAL POWER) and is automatically reinstated below the P-10 setpoint.
Power Range, Neutron Flux, High Rates The Power Range Positive Rate trip provides protection against rapid flux increases which are characteristic of a rupture of a control rod drive housing.
Specifically, this trip complements the Power Range Neutron Flux High and Low trips to ensure that the criteria are met for rod ejection from mid power.
The Power Range Negative Rate trip provides protection for control rod drop accidents.
At high power, a rod drop accident of a single or multiple rods could cause local flux peaking which could cause an unconservative local DNBR to exist.
The Power Range Negative Rate trip will prevent this from occurring by tripping the reactor.
No credit is taken for operation of the Power Range Negative Rate trip for those control rod drop accidents for which DN.BR's will be greater than 1.30.
Zntermediate and Source Range, Nuclear Flux The Intermediate and Source Range, Nuclear Flux trips provide reactor core protection during reactor startup to mitigate the consequences of an uncontrolled rod cluster control assembly bank withdrawal from a subcritical condition.
These trips provide redundant protection to the low setpoint trip of the Power Range, Neutron Flux channels.
The Source Range channels will initiate a reactor trip at about 10+5 counts per second unless manually blocked when P-6 becomes active.
The Intermediate Range channels will initiate a r@ actor trip at a current level equivalent to approximately 25 percent of RATED THERMAL POWER unless manually blocked when P-10 becomes active.
5 SUMMER - UNIT 1 B 2-4
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L?MITING SAFETY SYSTEM SETTINGS w
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BASES Overtemocrature aT The Overtemperature delta T trip provides core protection to prevent DNS for all combinations of pressure, power,. coolant temperature, and axial power distribution, provided that the transient is slow with respect to piping transit delays from the core to the temperature detectors (about 4 seconds),
and pressure is within the range between the Pressurizer high and low pressure trips. The setpoint is cutomatically varied with 1) coolant temperature to correct for temperature induced changes in density and heat capacity of water and includes dynamic compensation for piping delays from the core to the loop temperature detectors, 2) pressurizer pressure, and 3) axial power distribution.
With normal axial power distribution, this reactor trip limit is always below the core safety limit as shown in Figure 2.1-1.
If axial peaks are greater than design, as indicated by the difference between top and bottom power range nuclear detectors, the reactor trip is automatically reduced according to the notations in Table 2.2-1.
Overoower ai The Overpower delta T trip provides assurance of fuel integrity (e.g., no fuel melting and less than 1 percent cladding strain) under all possible overpower conditions, limits the required range for Overtemperature delta T
! L/' }2 protection, and provides a backup to the High Neutron FTux trip. The setpoint
,s is automatically varied with 1) coolant temperature to correct for temperature induced changes in density and heat capacity of water, and 2) rate of change of temperature for dynamic compensation for piping delays from the core to the loop temperature detectors to ensure that the allowable heat generation rate (Xw/ft) is not exceeded. The overpower aT trip provides protection to mitigate the consequences of various size steam breaks as reported in WCAP 9226, " Reactor Core Response to Excessive Secondary Steam Break."
Pressurizer Pressure In each of the pressure channels, there are two independent bistables, each with its own trip setting to provide for a high and low pressure trip thus limiting the pressure range in which reactor operation is per '.tted.
The low setpoint trip protects against low pressure which could lead to ONS by tripping the reactor in the event of a loss of reactor coolant pressure.
On decreasing power the low setpoint trip is automatically blocked by P-7 (a power level of approximately 10 percent of RATED THERMAL POWER with turoine impulse chamber pressure at approximately 10 percent of full power equivalent);
and on increasing power, automatically reinstated by P-7.
The high setpoint trip functions in conjunction with the pressurizer relief and safety valves to protect the Reactor Coolant System against system overpressure.
l SUMMER - UNrr 1 B 2-5 MAR 3 UNE!
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Pressurizer Water Level The pressurizer high water level trip is provided to prevent water relief through the pressurizer safety valves. On decreasing power the pressurizer high water level trip is automatically blocked by P-7 (a power level of approximately 10 percent of RATED THERMAL POWER with a turbine impulse chamber pressure at approximately 10 percent of full equivalent); and on increasing power, automatically reinstated by P-7.
Loss of Flow The Loss of Flow trips provide core protection to prevent DNB by mitigating the consequences of a loss of flow resulting from the loss of one or more reactor coolant pumps.
On increasing power above P-7 (a power level of approximately 10 percent of RATED THERMAL POWER or a turbine impulse chamber pressure at approximately 10 percent of full power equivalent), an automatic reactor trip will occur if the flow in more than one loop drops below 90% of ncminal full' loop flow.
Above P-8 (a power level of approximately 38 percent of RATED THERMAL POWER) an automatic reactor trip will occur if the flow in any single loop drops below 90 percent of nominal full loop flow. Conversely on decreasing power between P-8 and the P-7 an automatic reactor trip will occur on loss of flow e
in more than one loop and below P-7 the trip function is automatically blocked.
Steam Generator Water Level The steam generator water level low-low trip protects the reactor from loss of heat sink in the event of a sustained steam /feedwater flow mismatch resulting from loss of normal feedwater. The specified setpoint provides allowances for starting delays of the auxiliary feedwater system.
Steam /Feedwater Flow Mismatch and Low Steam Generator Water level The steam /feedwater flow mismatch in coincidence with a steam generator low water level trip is not used in the transient and accident analyses but is included in Table 2.2-1 to ensure the functional capability of the specified trip settings and thereby enhance the overall reliability of the Reactor Protection System. This trip is redundant to the Steam Generator Water Level Low-Low trip. The Steam /Feedwater Flow Mismatch portion of this trip is activated when the steam flow exceeds the feedwater flow by greater than or equal to 1.63 x 10s 1bs/ hour. The Steam Generator Low Water level portion of the trip is activated when the water level drops below the programmed low level setpoint, as indicated by the narrow range instrument. These trip values include sufficient allowance in excess of normal operating values to preclude spurious trips but will initiate a reactor trip before the steam generators are dry. Therefore, the required capacity and starting time requirements of the auxiliary feedwater pumps are reduced and the resulting thennal transient on the Reactor Coolant System and steam generators is minimized.
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SUMMER - UNIT 1 8 2-6
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LIMITING SAFETY SYSTEM SETTINGS BASES Undervoltace and Underfrecuency - Reactor-Coolant Pumo Busses The U.ndervcitage and Underfrequency Reactor Cuolant Pump Bus tr1ps provide reactor core protection against DN8 as a result of complete loss of forced coolant flow.
The specified set points assure a reactor trip signal is generated before the low flow trip set point is reached.
Time delays are incorporated in the underfrequency and undervoltage trips to prevent spurious reactor trips from momentary electrical power transients.
For undervoltage, the delay is set so that the time required for a signal to reach the reactor trip breakers following the simultaneous trip of two or more reactor coolant pump bus circuit breakers shall not exceed 1.2 seconds.
For underfrequency, the delay is set so that the time required for a signal to reach the reactor trip breakers after the underfrequency trip set point is reached shall not exceed 0.6 seconds. On decreasing power the Undervoltage and Underfrequency Reactor Coolant Pump Bus trips are automatically blocked by P-7 (a power level of approximately 10 per-cent of RATED THERMAL POWER with a turbine impulse chamber pressure at approximately 10 percent of full power equivalent); and on increasing power, reinstated automatically by P-7.
Turbine Trio A Turbine Trip initiates a reactor trip.
On decreasing power the turbine trip is automatically blocked by P-7 (a power level of approximately 10 percent of RATED THERMAL POWER with a turbine impulse chamber at approximately 10 percent of full power equivalent); and on increasing power, reinstated automatically by P-7.
Safety Iniection Inout from ESF If a reactor trip has not already been generated by the reactor protective instrumentation, the ESF automatic actuation logic channels will initiate a reactor trip upon any signal which initiates a safety injection. The ESF instrumentation channels which initiate a safety injection signal are shown in Table 3.3-3.
Se.
SUMMER - UNIT 1 B 2-7
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1 W(~p LIMITING SAFETY SYSTEM SETTINGS 0"
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Reactor Trio System Interlocks The Reactor Trip System Interlocks perform the following functions:
P-6 On increasing power P-6 allows the manual block of the Source Range reactor trip and de-energizing of the high voltage to the detectors.
On decreasing power, Source Range level trips are automatically reactivated and high voltage restored.
P-7 On increasing power P-7 automatically enc 51es reactor trips on low flow in more than one primary coolant loop, more than one reactor coolant pump breaker open, reactor coolant p%mp bus undervoltage and underfrequency, turbine trip, pressurizer low pressure and pressurizer high level. On decreasing power the above listed trips are automati-cally blocked.
P-8 On increasing power P-8 automatically enables reactor trips on low flow in one or more primary coolant loops, and one or more reactor coolant pump breakers open. On. decreasing power the P-8 automatically
' ~ '
blocks the above listed trips.
P-10 On increasing power P-10 allows the manual block of the Intermediate Range reactor trip and the low setpoint Power Range reactor trip; and automatically blocks the Source Range reactor trip and de-energizes the Source Range high voltage power. On decreasing power the Inter-mediate Range reactor trip and the low setpoint Power Range reactor trip are automatically reactivated.
Provides input to P-7.
P-13 Provides input to P-7.
l l
y.
SUMMER - UNIT 1 B 2-8
---m-
~ "*
- * ~ " * ' -
y ;;
REACTIVITY CONTROL SYSTEMS D
BORATED WATER SOURCE - SHUTDOWN
'd'a*,i. ggpy LIMiTINGCONDITIONFOROPERATION 3.1.2.5 As a minimum, one of the following borated water sources shall be OPERABLE:
a.
A boric acid storage system with:
S! lob 1.
A minimum contained borated water volume of 9900 gallons, 2.
Between 7000 and 7700 ppm of baron, and 3.
A minimum solution temperature of 65*F.
b.
The refueling water storage tank with:
31,9o*
1.
A minimum contained borated water volume ofM gallons, 2.
A minimum boron concentration of 2000 ppm, and 3.
A minimum solution temperature of 40*F.
APPLICABILITY: MODES 5 and 6.
ACTION:
With no borated water source OPERABLE, suspend all operations involving CORE ALTERATIONS or positive reactivity changes.
SURVEILLANCE REOUIREMENTS 4.1.2.5 The above required borated water source shall be demonstrated OPERABLE:
a.
At least once per 7 days by:
1.
Verifying the boron concentration of the water, 2.
Verifying the contained barated water volume, and 3.
Verifying the boric acid storage tank solution temperature when it is the source of borated water.
b.
At least onca.per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by verifying the RWST temperature when it is the source of borated water and the outside air temperature is less than 40*F.
SUMMER - UNIT 1 3/4 1-11
~.
_e..
-_e
=~- --
e
-e e
-W"'
REACTIVITY CONTROL SYSTEMS C;. "g BORATED WATER SOURCES - OPERATING LIMITING CONDITION FOR OPERATION
~
3.1.2.6 As a minimum, the following borated water source (s) shall be OPERA 8LE as required by Specification 3.1.2.2:
a.
A boric acid storage system with:
15,2o0 1.
A minimum contained borated water volume of 4Gv4fS gallons, 2.
Between 7000 and 7700 ppm of boron, and 3.
A minimum solution temperature of 65*F.
b.
The refueling water storage tank with:
L}gs,400 se -e 1.
Ancontained borated water volume of 5:t,... ::0,000 :nd *?0,'00
- gallons, 2.
Between 2000 and 2100 ppm of.boren, and 3.
A minimum solution temperature of 40*F.
]
t-
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
With the boric acid storage system inoperable and being used as one a.
of the above required borated water sources, restore the storage system to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-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 /> and borated to a SHUTDOWN MARGIN equivalent to at least 2 percent delta k/k at 200*F; restore tne boric acid storage system to OPERABLE status within the next 7 days or be in COLD SHUTDOWN within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
b.
With the refueling water storage tank inoperable, restore the tank to OPERABLE status within one hour or be in at least HOT STANOSY l
within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
r l'
.)
\\
Iaddi)I SUMMER - UNIT 1 3/4 1-12 MAR 3 1982 S
.A_,_
/ _ ___, G 3/4.3.2 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION s-.
3.3.2 The Engineered Safety Feature Actuation System (ESFAS) instrumentation channels and interlocks shown in Table 3.3-3,,shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3-4 and with RESPONSE TIMES as shown in Table 3.3-5.
APPLICABILITY: As shown in Table 3.3-3.
ACTION:
a.
With an ESFAS instrunentation or interlock setpoint less conservative than the value shown in the Trip Setpoint coluan of Table 3.3-4 adjust the set-point consistent with the Trip Setpoint value.
b.
With an ESFAS instrumentation or interlock setpoint less conservative than the value shown in the Allowable Values column of Table a.
-4, place the channel in the tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, and vith t e following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> either:
1.
Determine that Equation 2.2-1 was satisfied for the affected channel
~
and adjust th setpoint consistent with the Trip Setpoint value of Table 3.3-4, or 2.
Declare the channel inoperable and apply the applicable ACTION state-ment requirements of Table 3.3.3 until the ch.annel is restored to OPERABLE status with its setpoint adjusted consistent with the Trip Setpoint value.
$(,
SUMMER UNIT 1 3/4 3-15
i 3/4.3 INSTRUMENTATION
[
3 P
k EQUATION 2.2-1 Z+R+SdTA where:
Z = the value from column Z of Table 3.3.5 for the affected channel, R = the "as measured" value (in percent span) of rack error for the affected channel, S = either the "as measured" value (in percent span) of the sensor error, or the value in column S of Table 3.3-4 for the affected channel, and TA = the value from column TA of Table 3.3-4 for the affected channel.
SURVEILLANCE REQUIREMENTS
- 4. 3. 2.1 Each ESFAS instrumentation channel dnd interlock and the automatic actu-ation logic and relays ; hall be demonstrated OPERABLE by performance of the engi-neered safe'.y feature actuation system instrumentation surveillance requirements specified in Table 4.3-2.
4.3.2.2 The ENGINEERED SAFETY FEATURES RESPONSE TIME of each ESFAS function sh*all be demonstrated to be within the limit at least once per 18 months.
Each test shall include at least one train such that both trains are tested at least once per 36 months and one channel per function such that all channels are tested at least once per N times 18 months where N is the total nunber of redundant channels in a specific ESFAS function as shown in the " Total No. of Channels" Column of Table 3.3-3.
__)A
(
)
SUMMER UNIT 1 3/4 g 3-isi.,
I
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=.
o " 's, (l*j
/
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g; Q,
i E
TABLE 3.3-3 (Continued) i 39 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION C
HINIMUM 5
l TOTAL NO.
CilANNELS CilAtitlELS APPLICABLE FUNCTIONAL UNIT OF CilANNELS TO TRIP OPERABLE H0 DES ACTION I
H f.
Steam Line Pressure-Low I pressure /
1 pressure 1 pressure 1, 2, 3 1
19" loop and 2 loops and 2 loops 2.
REACTOR UUILDING SPRAY f
I a.
Manual 2 sets - 2 1 set 2 sets 1, 2, 3, 4 18 switches / set i
4 b.
Automatic Actuation 2
1 2
1,2,3,4 14 LoDic and Actuation T
Relays G
c.
Reactor Building 4
2
- 3 1,2,3 16 8
Pressure--Illah-3 (Phase 'A' isolationo1 Q
.. ' f or system 4 N N discharge valves and Na0ll tank suction valves) 1 Bl:e u
5 I
s' t 1.
[: " i
(
}
..{,
3 TABLE 3.3-4
, g ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS g
Functional Unit Total Allowance (TA)
Z 5
Trip Setpoint Allowable Value C-l-
z:.
1.
St.FETY INJECTION, REACTOR TRIP l:
q FEE 0 WATER ISOLATION, CONTROL E
ROOM ISOLATION, START DIESEL s
GENERATORS, CONTAINMENT COOLING FANS AND ESSENTIAL
{
b
,I a.
Manual Initiation NA NA NA NA NA
- I b.
Automatic Actuation Logic NA NA NA NA NA c.
Reactor Building Pressure-3.0 0.71 1.5
<3.6 psig
<3.86 psig High 1 d.
Pressurizer Pressure-Low 13.1 10.71
- 1. 5 11850 psig 11839 psig e.
Differential Pressure b(31 Between Steamlines-High 3.0 0.87 1.5/1.5 <97 psi
-<106 psi i
U)s?
f.
Steamline Pressure-Low 20.0 10.71 1.5 1675 psig 1635 psig (htr-1-)
k 2.
REACTOR BUILDING SPRAY r"
a.
Manual Initiation NA NA NA NA NA b.
Automatic Actuatien Logic NA NA NA NA NA and actuation relays c.
Reactor Building Pressure-3.0 0.71 1.5
<12.05 psig
-<12.31 psig l.igh 3 (Phase 'A' isolation H
N i.i h d for system dis-charge valves and Na0li tank suction valves.)
1 L,J M
!8 19 f 0'
M M
d T, s 60AW.
k,. = E>dca.
f.,
1 c_
m(
e TABLE 3.3-4 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS 9t, Functional Unit Total Allowance (TA)
Z 5,
Trip Setpoint Allowable Value C-P 3.
CONTAINMENT ISOLATION A
j F
a.
Phase "A" Isolation 1.
Manual NA NA NA NA NA 2.
Safety Injection See 1 above for all safety injection setpoints and allowable values 3.
Automatic Actuation NA NA NA NA NA Logic and Actuation Relays i
'i b.
Phase "B" Isolation 1.
Manual NA NA NA NA NA l
2.
Automatic Actuation NA NA NA NA NA Logic and Actuation Relays g
'd.11 i.5
'512.05psig
<12.31 psig
.......... g..i BNg 3'. 0 -
,l N Pressure-liigh 3 t
i D c.
Purge and Exhaust Isolation ll 1.
Manual NA NA NA NA NA 2.
Safety Injection See 1 above for all safety injection setpoints and allowable values
'l 3.
Containment Radio-NA NA NA 2X Background 2X Background activity High
.g 4.
Automatic Actuation NA NA NA NA NA Logic and Actuation Relays r-2 ji
.i
y
.=
(j o
~E,
-l -
.o 2
I TABLE 3.3-4 p'
ENGINEERE0 SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS l
functional Unit Total Allowance (TA)
Z S
Trip Setpoint Allowable Value l
4.
STEAM LINE ISOLATION a.
Manual NA NA NA NA NA b.
Automatic Actuation Logic HA NA NA NA NA and Actuation Relays l
c.
Reactor Building Pressure-3.0 0.71 1.5
-<6.35
-<6.61 High 2 i
d.
Steam Flow in two 20.0 13.16 1.5/1.5 < a function
< a function defined l
Steamlines - High 3efined as as follows: A Ap Coincident with follows: A Ap corresponding to 44.lI corresponding to of full steam flow y
40% of full steam between 0% and 2 c.
finw hetween 0%
and than 3 A ib b
~
end 20% load increasing linearly It and then a Ap a Ap corresponding increasingly to 114.0% of full p -
e iineariy Lu o ap tIow at full load.
A corresponding to 110% of full steam flow at full load I
l Tavg - Low-Low 4.0 1.12
- 0. 2
>553 F
>550.5*F l
e.
Steamline Pressure - Low 20.0 10.71 1.5
>675 psig
>635 psig (Nets 4) l o
H (1)Timeconstantsutilizedinleadlagcontrollerforsteamlinepressurelowareasfollows:(=50 secs.
'( : 5 secs.
4
l
[-]
I tp i.
t c.
'l 3
li 1
TABLE 3.3-4 "rl ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS C
j.
3 Functional Unit Total Allowance (TA)
Z_
S Trip Setpoint Allowable Value
't
-tF 5.
TUR81HE TRIP AND FEE 0 WATER l
ISOLATION a.
Steam Generator Water 5.0 2.18 1.5
<82.4% of
<84.2% of narrow I
Level - liigh-liigh iiarrow range range instrument I
instrument span span 6.
EMERGENCY FEE 0 WATER a
a.
Manual NA NA NA NA NA 1
I
!l b.
Automatic Actuation Logic NA NA NA NA NA 1
c.
Steam Generator Water 12.0 9.18 1.5
>12% of span
>10.2% of span from i'
Level - Low-Low Trom 0% to 30%
D% to 30% RTP in-l RTP increasing creasing linearly to g
linearly to 8
>53.1 of span from I
>54.1 of span 30% to 100% RTP K2 from 30% to 100%
g RTP
- d. & f.
Undervoltage-ESF Bus
>5760 Volts with
>5652 Volts with a a <0.25 second
<0.275 second time tiie delay delay
~"
>6576 volts with
>6511 volts with a i <3.0 second 73.3 second time tiie delay Belay I
- g..
11 1
P
,e t
ll 4
G 3
TABLE 3.3-4 l
3.
ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS I
\\
Functional Unit Total Allowance (TA)
Z S
Trip Setpoint Allowable Value e.
Safety Injection See 1 above (all SI setpoints) g.
Trips of Main Feedwater NA NA NA NA NA f
Pumps h.
Suction trar.<.fer on Low NA NA NA 1442 f t. 4 in.(2) 441 ft. 1 in.
Pressure 7.
LOSS OF POWER a.
7.2 kV Emergency Bus NA NA NA
>5760 Volts with 15652 Volts with a Undervoltage (Loss of a 10.25 second 10.275 second time Voltage) time delay delay b.
7.2 kv Emergency Bus NA NA NA
>6576 Volts
>6511 Volts with a undervoltage with a <3.0 23.3 second time second time delay delay U
8.
AUTOMATIC SWITCHOVER TO
-4 CONTAINMENT SUMP N
M a.
RWST Level Low-Low NA NA NA 218%
>15%
i b.
Automatic Actuation NA NA NA NA NA Logic and Actuation Relays t
(2) Pump suction head at which transfer is initiated is stated in effective water elevation in the condensate storage tank.
i
p; D' * -
'3 i
A l!-
.1
'2 TABLE 3.3-4 i
1 T
ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS i
Functional Unit Total Allowance (TA)
Z S
Trip Setpoint Allowable Value i
?
9.
ENGINEERED SAFETY FEATURE
'r
. ACTUATION SYSTEM INTERLOCKS i
A INTERLOCKS N
{
s a.
Pressurizer Pressure, P-11 3.1
.71
- 1. 5 1985 psig 11974 psig & 11996 psi }
l b.
Tavg low-Low, P-12 4.0 1.12 0.2 553 F 1550.5*F & $555.5'F c.
Reactor Trip, P-4 NA NA NA NA NA
's
- D Al I
I kN
!*d b
(T e
i
' l' 1.1.>
1
(.
ll i.
(
i TABLE 4.3-9 (Continued)
RAul0AC1tVE GASEOUS EFFLUENT H0H110 RING INSTRUMENTATION SURVEltLANCE REQUIREHENTS 9
'i c
ANALOG CilANNEL H0 DES IN WillCil i'
5 CilANNEL SOURCE CilANNEL OPERATIONAL SURVEILLANCE INSIRIMENI CllECK CilECK CALIBRATION TEST REQUIRED 3.
HAIN PLANI VENT EXilAUST SYSTEM (M
- a. Noble Gas Activity Monitor -
^
RM-A3 D
>H R(3)
QM
- b. Iodine Sampler W
H.A.
N.A.
N.A.
i t.
- c. Particulate Sampler W
N.A.
N.A.
N.A.
B t'
- d. Flow Rate Measuring Device D
N.A.
R Q
'4"
- e. Sampler flow Hate Monitor D
N.A.
R Q
f
^
i
'1 4.
REACTOR BullDING PURGE SYSTEM di a
- a. Noble Gas Activity Monitor -
0 P.H R(3)
QM RM-A4
- b. Iodine Sampler W
H.A.
N.A.
H.A.
't
- c. Particulate Sampler W
N.A.
N.A.
N.A.
i
- d. Flow Rate Heasuring Device D
'N.A.
R R
^
Sampler Flow Rate Monitor D
N.A.
R R
e.
l i, e
n i
c.
lI fi
- I
~
I (.
j I
M:
- 4
k5 v
{huwablsid'J.si)bd/f
,TC rs rmr r.; w, SURVEILLANCE REOUIREMENTS (Continued) 4.4.5.4 Acceotance Criteria a.
As used in this Specification:
1.
Imperfection means an exception to the dimensions, finish or contour of a tube from that required by fabrication drawings or specifications. Eddy-current testing indications below 20% of the nominal tube wall thickness, if detectable, may be considered as imperfections.
2.
Degradation means a service-induced cracking, wastage, wear or general corrosion occurring on either inside or outside of a tube.
3.
Decraded Tube means a tube containing imperfections greater
~
than or equal to 20% of the nominal wall thickness caused by degradation.
4.
'A Degradation means the percentage of the tube wall thickness affected or removed by degradation.
5.
Defect means an imperfection of such severity that it exceeds the plugging limit. A tube containing a defect is defective.
6.
Plugging Limit means the imperfection depth at or beyond which tne tube shall be removed frem service and is equal to75E1 of the nominal tube wall thickness.
qhgr 7.
Unserviceable describes the condition of a tube if it leaks or contains a defect large enough to affect its st.uctural integrity in the event of an Operating Basis Earthquake, a loss-of-coolant accident, or a steam line or feedwater line break as specified in 4.4.5.3.c, above.
8.
Tube Insoection means an inspection of the steam generator tube from the point of entry (hot leg side) completely around the U-bend to the top support of the cold leg.
1 SUMMER - UNIT 1 3/4 4-14
,m._,_
_~
+
d
-n
,j EMERGENCY CORE COOLING SYSTEMS f^',df (2 i!$V.Oi d,yy 7g p I
I y
3/4.5.5 REFUELING _ WATER STORAGE TANK LIdITING CONDITION FOR OPERATION 3.5.5 The refueling water storage tank (RWST) shall be OPERABLE with:
e' 45 5, Toch a.
A Nontained borated water volume of h=+o-^-
250,000 :.d *00,700
- gallons, b.
A boron concentration of between 2000 and 2100 ppm of baron, and c.
A minimum water temperature of 40*F.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
With the refueling water storage tank inoperable, restore the tank to OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or 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 /> 'and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
s SURVEILLANCE REOUIREMENTS 4.5.5 The RWST shall,be demonstrated OPERABLE:
a.
At least once per 7 days by:
1.
Verifying the contained borated water volume in the tank, and 2.
Verifying the boron concentration of the water.
b.
At least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by verifying the RWST temperature when the outside air temperature is less than 40*F.
S
/
e i
e-4 SUMMkR-UNIT 1 3/4 5-11 l
l
~
~ ~ ~ ~~
i
~'I;$
N CONTAINMENT SYSTEMS f
SURVEILLANCE REOUIREMENTS 4.6.1.3 Each reactor building air lock shall be demonstrated OPERABLE:
a.
Within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following each closing, except when the air lock is being used for multiple entries, then at least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, by verifying that the seal leakage rate is less than or equal to 0.01 L when the volume between the door seals is pressurized to greatef than or equal to 8.0 psig for at least 3 g,_.,%
b.
By conducting overall air lock leakage tests at not less than P '
a 47.1 psig, and verifying the overall air lock leakage rate is within its limit:
1.
At least once per 6 months #, and 2.
Prior to establishing CONTAINMENT INTEGRITY when maintenance has been performed on the air lock that could affect the air lock sealing capability.*
At least once per six months by verifying that only one door in each c.
air lock can be opened at a time.
- d. 04. bedt. m p 6 MM b
Q p35, h M h dL d -b O.01 l.g M
& c d u
..t hh b y gr.m g.p u cu gAi se 6 y e.ka.w..+~.
- The provisions of Specification 4.0.2 are not applicable.
- Exemption to Appendix J of 10 CFR 50.
p,.
N j
~
SUMMER - UNIT 1 3/4 6-5 i
is:N?
~
\\
l ly PTW
,e o h
- 9 4L-J u si 2
CONTAINMENT SYSTL~S.
g,,s
' (1 s..
s.
SPRAY ADDITIVE SYSTEi LIMITING CONDITION FOR OPERATION 3.6.2.2 The spray additive :ystcm shall be OPERABLE rith:
31/0 SL343 a.
A spray additive tank containing a volume :f between -MNH' and St+&
r gallons of between 20.0 and 22.0 percent b;< weight NaOH solution, and b.
A flow path capable of adding NaOH solution from the spray additive tank to the suction of each reactor building spray pump.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
With the spray additive system inoperable, restore the system to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT STANOBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; restore the spray additive system to OPERABLE status within the next 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in COLD SHUTOOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
SURVEILLANCE REOUIREMENTS 4.6.2.2 The spray additive system shall be demonstrated OPERABLE:
a.
At least once per 31 days by verifying that each vals3 (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.
b.
At least once per 6 months by:
1.
Verifying the contained solution volume in the tank, and 2.
Verifying the concentration of the NaOH solution by chemical analysis.
c.
At least once per 18 months during shutdown, by verifying that each automatic valve in the flow path actuates to its correct position on l
a Phase 'A' signal.
d.
At least once per 5 years by verifying each solution flow rate {t.
50 det:c......;d dur'ng pr: Oper; tion:I t::t ) from the following drain connections in the spray additive system:
16 1.
NaOH Tank to Loop A
- C _
g,.s gW
~
.(.,.
2.
NaOH Tank to Loop B 50 t 5 cpm _ 3, gj[
y43 W-SUMMER - UNIT 1 3/4 6-13
,==ew="
~ ~ ~ ~
h
i g - g m.;,,,w L,O ]I
.a PLANT SYSTEMS
,.- p 3 o i
~-
i 3.
u CONDENSATE STORAGE TANK LIMITING CONDITION FOR OPERATION
~
- 3. 7.1. 3 The condensate storage tank (CST) shall be OPERABLE with a contained volume of at least 150,000 gallons of water.
8'lZs700 APPLICABILITY: MODES 1, 2 and 3.
ACTION:
With the condensate storage tank inoperable, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either:
a.
Restore the CST to OPERABLE status 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 /> and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, or b.
Demonstrate the OPERABILITY of the service water system as a backup supply to the emergency feedwater pumps and restore the condensate storage tank to OPERABLE status.within 7 days 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 /> and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
SURVEILLANCE REOUIREMENTS 4.7.1.3.1 The condensate storage tank shall be demonstrated OPERABLE at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> by verifying the contained water volume is within its limits when the tank is the supply source for the emergency feedwater pumps.
4.7.1.3.2 The service water system shall be demonstrated OPERABLE at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> by verifying service water rystem pressure whenever the service water system is the supply source for the emergency feecwater pumps.
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PLANT SYSTEMS Q.
SURVEILLANCE REQUIREMENTS (Continued) 1.
Verifying that the cleanup system satisfies the in place testing acceptance criteria and uses the test procedures of Regulatory Positions C.S.a, C.S.c and C.S d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rate is 20,000 cfm 1 10%.
2.
Verifying, within 31 days after removal, that a laboratory analysis of a representative' carbon sample obtained in accord-ance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.
3.
Verifying a system ficw rate of 20,000 cfm 110% during system operation when tested in accordance with ANSI N510-1975.
d.
After every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of charcoal adsorber operation by verifying within 31 days after removal, that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.
At least once per 18 months by:
e.
(
l.
Verifying that the pressure drop across the combined HEPA and roughing filters and charcoal adsorber banks is less than 6 inches Water Gauge while operating the system at a flow rate of 20,000 cfm i 10L i
2.
Verifying that on a simulated SI or high radiation test signal, the system automatically switches into a recirculation mode of operation with flow through the HEPA filters and charcoal e
adsorber banks.
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Verifying thatAthe system starts the normal and emergency air handling systems which pressurize the control room to a positive pressure of greater than or equal to 1/8 inch W.G. relative to the outside atmosphere and maintains the 1/8 inch W.G. position pressure during system operation.
f.
After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter banks remove greater than or equal to L
99.95% of the DOP when they are tested in place in accordance I
with ANSI N510-1975 while operating the system at a flow rate of i
20,000 cfm 1 10%.
g.
After each complete or partial replacement of a charcoal adsorber bank by verifying that the charcoal adsorbers remove greater than or equal to 99.95% of a halogenated hydrocarbon refrigerant test gas when they are tested in place in accordance with ANSI N510-1975 while operating the system at a flow rate of 20,000 cfm 110%.
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7 ELECTRICAL POWER SYSTEMS
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3/4.8.4 ELECTRICAL EOUIPMENT PROTECTIVE DEVICES CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES (s.
LIMITING CONDITION FOR OPERATION l
3.8.4.1 All containment penetration conductor overcurrent protective devices shown in Table 3.8-1 shall be OPERABLE.
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i APPLICABILITY: MODES 1, 2, 3 and 4.
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TCTION-With one or more of the above required containment penetration conductor overturrent protective device (s) inoperable:
Restore the protective device (s) to OPERABLE status or de-energize a.
the circuits (s) by tripping the associated backup circuit breaker or racking out or removing the inoperable circuit breaker within i
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, declare the affected system or component inoperable, and verify the backup circuit breaker to be tripped or the inoperable circuit breaker racked out, or removed, at least once per 7 days M
thereafter; the provisions of Specification 3.0.4 are not applicable to overcurrent devices in circuits which have their backup circuit breakers tripped, their inoperable circuit breakers racked out,or' removed, or b.
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 /> and in COLD SHUTOOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
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SURVEILLANCE REOUIREMENTS 4.8.4.1 All containment penetration conductor overcurrent protective devices e
shown in Table 3.8-1 shall be demonstrated OPERABLE:
a.
At least once per 18 months:
1.
By verifying that the medium voltage (7.2 KV) circuit breakers are OPERABLE by selecting, on a rotating basis, at least 10% of the circuit breakers of each voltage level, and performing the following:
(a) A CHANNEL CALIBRATION of the associated protective relays, and (b) An integrated system functional test which includes simulated automatic actuation of the system and verifying that each relay and associated circuit breakers and control circuits function as designed and as specified in Table 3.8-1.
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RADICACTIVE GASEOUS WASTE MONITORING AND SAMPLING AND ANALYSIS PROGRAM v.
c E
Lower Lielt m
Minimum of Detection j
Sampling Analysis E
Gaseous Release lype Frequency Frequency Type of Activity Analysis (LLD)(pCi/ml)a "4
4 A.
Waste Gas Storage P
P 9
1x10 1
Tank Ear.h Tank Each Tank Principal Ganaa Emmitters Grab Sample
-4 B1 Reactor Building P
P 9
1x10 U
b
-36" Purge Line Each Purge
Each Purge Principal Ganuna Emitters
-6
- d' bt LM ll-3 1x10 C
D 4
82 Heactor Building H
H 9
1x10 Principal Gamma Emmitters
-6" Purge Line Grab Sample
-6 h & ' ^' 4 )
11-3 1x10 b
b C.
Main Plant Vent H,e g
~4 9
1x10 Principal Gamma Emitters U
~0 11 - 3 1x10
-I W
I-131 1x10 d
-I0 D.1. Reactor Building Continupus Purge Sampler Charcoal Sample I-133 1x10 d
9 1x10'II W
Principal Gamma Emitters
- 2. Main Plant Vent Continu9us Sampler Particulate Sample 1-131, others H
_gg Continupus Sampler Composite Gross Alpha 1x10 Particulate Sample
_gy Continuyus Q
1x10 Sampler Composite Sr-89, Sr-90 j
Particulate Sample l
-6 l
I' Continuous Noble Gas Noble Gases 2x10 1
Honitor Honitor Gross Beta
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REACTIVITY CONTROL SYSTEMS i..
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BASES B0 RATION SYSTEMS (Continued) f9feg5
MARGIN from expected operating conditions of 1.77% delta k/k after xenon decay and cooldown to 200?F. The maximum expected boration capability requirement occurs at EOL from full power equilibrium xenon conditions and requires 12 gallons of 7000 ppm borated water from the boric acid storage tanks or 1,0 5 gallons of 2000 ppm borated water from the refueling water storage tank.
With the RCS temperature below 200?F, one injection system is acceptable without single failure consideration on the basis of the stable reactivity condition of the reactor and the additional restrictions prohibiting CORE ALTERATIONS and positive reactivity changes in the event the single injection system becomes inoperable.
The limitation for a maximum of one centrifugal charging pump to be OPERABLE and the Surveillance Requirement to verify all charging pumps except the required OPERABLE pump to be inoperable below 275 F provides assurance that a mass addition pressure transient can be relieved by the operation of a single PORV.
g The boron capability requi. red below 0?F is sufficient to provide a SHUTDOWN MARGIN of 2 percent delta k/k aft r xenon decay and cooldown from 200?F to 140?F. This condition requires either eGGO gallons of 7000 ppm barated water from the boric acid storage tanks or GGGO gallons of 2000 ppm borated water from the refueling water storage tank.
p gg The contained water volume limits include allowance for water not available because of discharge line location and other physical characteristics.
The limits on contained water volume and boron concentration of the RWST
- also ensure a pH value of between 8 5 and 11.0 for the solution recirculated within containment after a LOCA.
This pH band minimizes the evolution of iodine and minimizes the effect of chloride and caustic stress corrosion on mechanical systems and components.
The OPERABILITY of one boron injection system during REFUELING ensures that this system is available for reactivity control while in MODE 6.
3/4.1.3 MOVABLE CONTROL ASSEMBLIES The specifications of this section ensure that (1) acceptable power distribution limits are maintained, (2) the minimum SHUTDOWN MARGIN is main-tained, and (3) limit the potential effects of rod misalignment on associated accident analyses.
OPERABILITY of the control rod position indicators is required to determine control rod positions and thereby ensure compliance with the control rod alignment and insertion limits.
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.d-3/4.3.1 and 3/4.3.2 REACTOR TRIP AND ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION The OP'ERABILITY of the Reactor Protection System and Engineered Safety Feature 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 co-incidence logic is maintained, 3) sufficient redundancy is maintained to permit a channel to be out of service for testing or maintenance, and 4) sufficient system functional capability is available from diverse parameters.
The OPERABILITY of these systems is required to provide the overall reliabil-ity, redundancy, and diversity assumed available in the facility design for the protection and mitigation of accident aid transient conditions.
The in-I tegrated 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 main-tained comparable to the original design standards.
The periodic surveillance tests performed at the minimum frequencies are sufficient to demonstrate this capability.
The Engineered Safety Feature Actuation System Instrumentation Trip Setpoints specified'in Table 3.3-4 are the nominal values at which the b stables are set for each functional unit. A setpoint is considered to be adjusted con-sistent with the nominal value when the "as measured" setpoint is within the band allowed for calibration accuracy.
k.
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. BASES REACTOR TRIP AND ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION
- hj (continued) w, and the accuracy to which setpoints can be measured and calibrated, Allowable Valuet for the setpoints have been specified'in Table 3.3-4.
Operation 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 deter-mining 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 uncertainties in calibrating the instrumentation.
In Equation 3.3-1, Z + R + 5 6 TA, the in-r' teractive effects of the errors in the rack and the sensor, and the "as mea-sured" val' es' of' the errors are considered.
Z, as specified in Table 3.3-4, u
in percent span, is the statistical sumation of errors assumed in the ana-lysis excluding those associated with the sensor and ra.g drift and the accu-racy of their measurement. TA or Total Allowance is the difference, in per-cent span, between the trip setpoint and the value used in the analysis for the actuation.
R or Rack Error is the "as measured" deviation, in percent span, for the affected channel from the specified trip setpoint.
S or Sen-sor Error is either the "as measured" deviation of the sensor from its ca-libration point _or._the_ value specified in Table 3.3-4, in percent span, from
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the analysis assumptions. Use of Equation 3.3-1 allows for a sensor drift factor, an increased rack drif t factor, and provides a pthreshold value for REPORTABLE OCCURRENCES.
I SUMMER-UNIT 1 B 3/4 3-l a t
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, BASES TC REACTOR TRIP AND ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION (continued)
The methodology to derive the trip setpoints is based upon combining all of the
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uncertainties in the channels.
Inherent to,the detennination of the trip set-points are the magnitudes of these channel uncertainties.
Sensor and rack in-strumentation utilized in these channels are expected to be capable of opera-ting 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 drift is expected.
Rack or sensor drift, in excess of the allowance that is more than occassional, may be indicative of more serious problems and should warrant further investigation.
The measurement of response time at' the specified frequencies provides assu-rance that ti.e reactor trip and the engineered safety feature actuation asso-ciated 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 de-monstrated 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 para-meters and detennines whether or not predetermined limits are being exceeded.
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If they are, the signals are combined into logic matrices sensitive to com-s binations indicative of various accidents, events, and transients. Once SUMMER-UNIT 1 B 3/4 3 -l b r...
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REACTOR TRIP AND ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION 1
(continued)
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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) feed-water 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 valve position,10) containment cooling fans start and automatic valves position,11) essential service water pumps start and automatic valves position, and 12) control room isolation and ventilation systems start.
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es BASES 3/4.4.5 STEAM GENERATORS The Surveillance Requirements for inspection of the steam generator tubes ensure that the structural integrity of this portion of the RCS will be main-tained. The progr:m for inservice inspection of steam generator tubes is based on a modification of Regulatory Guide 1.83, Revision 1.
Inservice inspection of steam generator tubing is essential in order to maintain surveillance of the conditions of the tubes in the event that there is evidence of mechanical damage or progressive degradation due to design, manufacturing errors, or inservice conditions that lead to corrosion.
Inservice inspection of steam generator tubing also provides a means of characterizing the nature and cause of any tube degradation so that corrective measures can be taken.
The plant is expected to be operated in a manner such that the secondary coolant will be maintained within those chemistry limits found to result in negligible corrosion of the steam generator tubes.
If the secondary coolant chemistry is not maintained within these limits, localized corrosion may likely result in stress corrosion cracking.
The extent of cracking during plant cperation would be limited by the limitation of steam generator tube
[
leakage between the primary coolant system and the secondary coolant system (primary-to-secondary leakage = 500 gallons per day per steam generator).
Cracks having a primary-to-secondary leakage less than this limit during cperation will have an adequate margin of safety to withstand the loads imposed during normal operation and by postulated accidents.
Operating plants have demonstrated that primary-to-secondary leakage of 500 gallons per day per steam generator can readily be detected by radiation monitors of steam generator blowdown.
Leakage in excess of this limit will require plant shutdown and an unscheduled inspection, during which the leaking tubes will be located and plugged.
Wastage-type defects are unlikely with proper chemistry treatment of the secondary coolant. However, even if a defect should develop in service, it will be found during scheduled inservice steam generator tube examinations.
-Elucainn up be %equired for all tubes with imperfections exceeding the r
hD plugging limit of of the tube nominal wall thickness.
Steam generator tube inspections of operating plants have demonstrated the capability to reliably detect degradation that has penetrated 20% of the original tube wall thickness.
Whenever the results of any steam generator tubing inservice inspection fall into Category C-3, thase results will be promptly reported to the Commission pursuant to Specification 6.9.1 prior to resumption of plant operation.
Such cases will be considered by the Commission on a case-by-case basis and may l
result in a requirement for analysis, laboratory examinations, tests, additional eddy-current inspection, and revision of the Technical Specifications, if necessary.
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ADMINISTRATIVE CONTROLS 6.5 REVIEW AND AUDIT 6.5.1 PLANT SAFETY REVIEW COMMITTEE (PSRC)
FUNCTION 6.5.1.1 The PSRC shall function to advise the Manager, Virgil C. Summer Nuclear Station on all matters related to nuclear safety.
COMPOSITION 6.5.1.2 The Plant Safety Review Committee shall be composed of the:
w Det
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Manager; Virgi C. Summer Nuclear Station Member:
Assistant Manager Operations Member:
Assistant Manager Technical Support Assistant Manager Maintenance Services Member:
Assistant Manager Support Services Member:
Director of Health Physicsna fleik k@,
A' Member:
h ALTERNATES 6.5.1.3 All alternate members shall be appointed in writing by the PSRC Chairman to serve on a temporary basis; however, no more than alternates 3 shall participate as voting members in PSRC activitjes at any one tim r ia.. - % uu.+ A-
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MEETING FREQUENCY g
6.5.1.4 The PSRC shall meet at least once per calendar month and as convened by the PSRC Chairman or his designated alternate.
OUORUM 6.5.1.5 The minimum quorum of the PSRC necessary for the performance of the PSRC responsibility and authority provisions of these Technical Specifications three me bers shall consist of the Chaj{y ggj%[gnoghisdesignatedalternatean includingalternatesgy, RESPONSIBILITIES 6.5.1.6 The Plant Safety Review Committee shall review:
Station aaministrative precedures and changes thereto, a.
The safety evaluations for 1) prc:edures, 2) changes to procedures, b.
equipment or systems, and 3) tests or experiments completed under the provision of Section 50.59, 10 CFR, to verify that such actions did not constitute an unreviewed safety question and all programs required I
by Specification 6.8 and changes thereto.
Proposed procedures and changes to procedures, equipment or systems c.
which may involve an unreviewed safety question as defined in Section 50.59, 10 CFR.
Proposed tests or experiments which may involve an unreviewed safety d.
cuestion as defined in Section 50.59, 10 CFR.
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Proposed changes to Technical Specifications or the Operating License.
e.
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Q. _ ADMINISTRATIVE CONTROLS I
i AUDITS 6.5.2.8 Th NSRC shall have cognizance of he audits listed below. Audits may be performed by using established SCE&G g oups such as the ISEG and QA cr by outside groups as determined by the NSRC.
A0dit reports or summaries will be the basis for NSRC action:
a.
The conformance of unit opera' ion to provisions contained within the Technical Specifications and pplicable license conditions at least once per 12 months.
b.
The performance, training an qualifications of the entire unit staff at least once per 12 nths.
c.
The results of actions take to correct deficiencies occurring in unit equipment, structures, systems or method of operation that affect nuclear safety at 1 ast once per 6 months.
d.
The performance of activit es required by the Operational Quality Assurance Program to meet he criteria of Appendix "B",
10 CFR 50, at least once per 24 mont s.
e.
The Emergency Plan and i piementing procedures at least once per 24 months.
f.
The Security Plan and i.plementing procedures at least once per 24 months.
f g.
Any other area of uni operation considered appropriate by the NSRC or the Vice President and Group Executive, Nuclear Operations.
h.
The Fire Protection agram and implementing procedures at least once per 24 months.
i.
An independent fir protection and loss prevention inspection and audit shall be p formed annually utilizir.g either qualified offsite.
licensee person 1 or a qualified outside firm.
j.
An inspection nd audit of the fire protection and loss prevention program shal be performed by an outside qualified fire consultant at interva no greater than 3 years.
k.
The radi ogical environmental monitoring program and the results thereo at least once per 12 months.
1.
T;ie OFFSITE DOSE CALCULATION MANUAL and implementing procedures at t
least once per 24 months.
m.
The PROCESS CONTROL PROGRAM and implementing procedures for solidification of radioactive wastes at least once per 24 months.
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42 cary 1979-at Mae+ =ce-g 12.aonther-l AUTHORITY
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6.5.2.9 The NSRC shall report to and advise the Vice President and Group Executive, Nuclear Operations on those areas of responsibility specified in Sections 6.5.2.7 and 6.5.2.3.
APR 151982 SUMMER - UNIT 1 6-10 w.
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Critical operation of the unit shall not be resumed until authorized by the Commission.
6.8 PROCEDURES AND PROGRAMS 6.8.1 Written procedures shall be established, implemented and maintained covering the activities referenced below:
a.
The applicable procedures recommended in Appendix "A" of Regulatory Guide 1.33, Revision 2, February 1978.
b.
Refueling operations.
c.
Surveillance and test activities of safety-related equipment.
d.
Security Plan.
e.
f.
h.
OFFSITE DOSE CALCULATION MANUAlp"egr:r for tffluent and environmental monitori 1.
Quclity '.::tr:"-a
---__ V using the guidance in Regulatory Guide 4.15, Revision 1, February 1979.
6.8.2 Each procedure of,6.8.1 above, and ch'anges thereto, shall be reviewed
(
prior. to implementation as set forth in 6.5 above.
6.8.4 The following programs shall be established, implemented, and maintained:
a.
Primary Coolant Sources Outside Containment A program to reduce leakage from those port-:u:s of systems outside containment that could contain highly radi.uctive fluids during a serious transient or accident to as low as practical levels.
The systems include the chemical and volume control, letdown, safety injection,- residual heat removal, nuclear sampling, liquid radwaste handling, gas radwaste handling and reactor building spray system.
The program shall include the following:
(i) Preventive maintenance and periodic visual inspection requirements, and (ii) Integrated leak test requirements for each system at refueling cycle intervals or less.
b.
In-Plant Radiation Monitoring A program which will ensure the capability to accurately determine the airborne iodine concentration in vital areas under accident conditions. This program shall include the following:
(i) Training of personnel,
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(ii) Procedures for monitoring, and (iii) Provisions for maintenance of sampling and analysis equipment.
SUMMER - UNIT 1 6-13 APR I 5 Gs2
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'OMINISTRATIVE CONTROLS c.
Secondary Water Chemistry A program for eonitoring of secondary water chemistry to inhibit j
steam generator tube degradation. This program shall include:
(i) Identification of a sampling schedule for the critical variables and control points for these variables, (ii) Identification of the procedures used.to weasure the values of the critical variables, (iii) Identification of process sampling points, including monitoring the discharge of the condensate pumps for evidence of condenser in-leakage.
(iv) Procedures for the recording and management of data, (v) Procedures. defining corrective actions for all off-control point chemistry conditions, (vi) A procedure identifying (a) the authority responsible for the interpretation of the data, and (b) the sequence and timing of administrative events required to initiate corrective action.
d.
Postaccident Samoling A program which will ensure the capability to obtain and analyze reactor coolant, radioactive iodines and particulates in plant gaseous effluents, and containment atmosphere samples under accident conditions. The program shall include the following:
(i) Training personnel, (ii) Procedures for sampling and analysis, (iii) Provisions for maintenance of sampling and analysis equipment.
Seismic Monitoring, A seismic mbo oring regram a. e Monticel R
rvoir whic s 1
nelude:
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ADMINISTRATIVE CONTROLS s.-
%smic Mon g (Co ued)
) Noti ' cation hin 24 ho by telepho e to the headquarters proj c a ger, f the c
~on, dep and mag tu of any of the foll ing:
E thqua es lar er in magni de than 2..
2.
are than 0 events per v.ek.
Proposed c n s in wat level n
e reservoir t les than 415 et o reat than 43 et.
iii) A su lemen to the quar rly submitt w ich inclu es a copy of the ac leromter re r nd its r spons spectr m and a calcula 'on of its st ss dr sho d the be oc free field accele m ter recor an earth ak with a pea cceleration of at 1 st 0. 1 g wi an interva of at least cond where pea acceler tio exceed 0.05 l
(iv) nvestigatio o correlation between sei icity an variables such as wat le 1 change A suppleme to the qua erly submittal hall include th results of his investigati l
m 6.9 REPORTING REQUIREMENTS ROUTINE REPORTS AND REPORTABLE OCCURRENCES In addition to the applicable reporting requirements of Title 10, Code 6.9.1
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of Federal Regulations, the following reports shall be submitted to the Regional Administrator Office of Inspection and Enforcement unless otherwise noted.
STARTUP REPORT 6.9.1.1 A summary report of plant startup and power escalation testing shall bn submitted following (1) receipt of an operating license, (2) amendtrent to the license involving a planned increase in power level, (3) installation of fuel that has a different design or has been manufactured by a different fuel supplier, and (4) modifications that may have significantly altered the nuclear, thermal, or hydraulic performance of the plant.
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map 9 to82 SUMMER - UNIT 1 6-14a
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ADMINISTRATIVE CONTROLS
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Records of Quality Assurance activities
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Records of reviews performed for changes made to procedures or equipment or reviews of tests and1xperiments pursuant to 10 CFR 50.59.
lscords of meetings of the PSRC and the N5RC.
k.
1.
Records of the service lives of all hydraulic and mechanical snubbers listed on Tables 3.7-4a and 3.7-4b including the date at which the service life commences and associated installation and maintenance records.
,m.
Records of secondary water sampling and water quality.
n.
Records of analysis required by the radiological environmental monitoring program.
6.11 RADIATION PROTECTION PROGRAM Procedures for personnel radiation protection shall be prepared consistent with the requirements of 10 CFR Part 20 and shall be approved, maintained and adhered to for all operations involving personnel radiation exposure.
6.12 HIGH RADIATION AREA
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.6.12.1 In lieu of the " control device" or " alarm signal" required by paragraph 20.203(c)(2) of 10 CFR 20, each high radiation area in which the intensity of radiation is greater than 1.00 mrem /hr but less than 1000 mrem /hr shall be barricaded and conspicuously posted as a high radiation area and entrance thereto shall be controlled by requiring issuance of a Radiation Work Permit (RWP).* Any individual or group of individuals permitted to enter such areas shall be provided with or accompanied by one or more of the following:.
a.
A raciation monitoring device which continuously indicates the radiation dose rate in the area.
b.
A radiation monitoring device which continuously int.egrates the radiation dose rate in the area and alarms when a preset integrated dose is received.
Entry into such areas with this monitoring device may be made after the dose rate level in the area has been
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established and personnel have been made knowledgeable of them.
c.
A health physics qualif.ied individual (i.e., qualified in radiation protection procedures) with a radiation dose rate monitoring device who is responsible for providing positive control over the activities within the area and shall perform periodic radiation surveil' lance at the frequency specified b'y the facility Health Physicist in the Radiation Work Permit.
^ Health Physics personnel or personnel escorted by Health Physics personnel shall be exempt from the RWP issuance requirement during the performance of their assigned radiation protection duties, provided they otherwise comply with H
approved radiation protection procedures for entry into high radiation. areas.
SUMMER - UNIT 1 6-22
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ADMINISTRATIVE CONTROLS q,
6.12.2 In addition to the requirements of 6.12.1, areas accessible to personnel with radiation levels such that a major portion of the body could receive in one hour a dose greater than 1000 mrem shall be provided with locked doors to prevent unauthorized entry, and the keys shall be maintained under the admin-istrative control of the Shift Foreman on duty and/or health physics supervision. Doors shall remain locked except during periods of access by personnel under an approved RWP which shall specify the dose rate levels in the immediate work area.
The maximum allowable stay time for individuals in that area shall be established prior to entry.
For individual areas accessible to personnel with radiation levels such that a major portion of the body could receive in one hour a dose in excess of 1000 mrem ** that are located within large areas, such as PWR containment, where no enclosure exists for purposes of locking, and no enclosure can be reasonably constructed around the individual areas, then that area shall be roped off, conspicuously posted and a flashing light shall be activated as a warning device.
In lieu of the stay time gf ^ specification of tneW direct or remote (such as use of closed circuit TV cameras) continuous surveillance shall be made by personnel qualified in radiation protection procedures to provide positive exposure control over the activities within the area.
6.13 PROCESS CONTROL PROGRAM (PCP)
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6.13.1 The PCP shall be approved by the Commission prior to implementation.
6.13.2 Licensee initiated changes to the PCP:
1.
Shall be submitted to the Commission in the semi-annual Radioactive Effluent Release Report for the period in which the change (s) was made. This submittal shall contain:
a.
Sufficiently detailed information to totally support the rationale for the change without benefit of additional or supplemental information; b.
A determination that the change did not reduce the overall conformance of the solidified waste product to existing criteria for solid wastes; and c.
Documentation of the fact that the change has been reviewed and j
found acceptable by the PSRC.
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2.
Shall become effective upon review and acceptance as set forth in 6.5 above.
6.14 0FFSITE DOSE CALCULATION MANUAL (ODCM) 6.14.1 The ODCH shall be approved by the Commission prior to implementation.
- Measurement made at 18" from source of radioactivity.
SUMMER - UNIT 1 6-23 r.-
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v e-INFORMATION REQUIRED FROM THE APPLICANT TO COMPLETE THE TECHN.ICAL SPECIFICATIONS FOR V. C. SUMMER, UNIT 1 1.
Specification 3/4.3.2, " Engineered Safety Features Actuation Instrumentation."
Clarification of system design for the Phase B, " Isolation and Spray Actuation,"
with proposed Technical Specifications.
2.
Specification 3/4.9.11, " Spent Fuel Pool Ventilation System."
Additional information/FSAR revision to support proposed Technical Specification revision.
3.
Specification 3/4.6.4, " Containment Isolation Valves."
Additional valves (to complete list) required to be consistent with GDC 54 through 57 of Appendix A to 10 CFR Part 50.
ENCLOSURE 2 l
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PROPOSED TECHNICAL. SPECIFICATIONS UNDER REVIEW BY THE STAFF 1.
Specification 3/4.9.3, " Overpressure Protection System."
Applicant's proposal dated February 26, 1982.
2.
Specification 3/4.6.1.6, " Containment Structural Integrity."
Applicant's proposal dated March 22, 1982.
3.
Specification 3/4.8.1.1.2, " Diesel Generator Fuel Oil Sampling."
Applicant's proposal dated January 22, 1982.
4.
Specification 3/4.6.4, " Containment Isolation Valves."
Applicant's proposal dated March 26, 1982.
5.
Specification 3/4.2.3, " Reactor Coolant System Flow Measurement Uncertainty."
Applicant's proposal dated April 12, 1982.
6.
Specification 3/4.9.11, " Spent Fuel Pool Ventilation System."
Applicant's proposal dated April 12, 1982.
ENCLOSURE 3 i
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