ML20052E266
| ML20052E266 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 04/30/1982 |
| From: | NEBRASKA PUBLIC POWER DISTRICT |
| To: | |
| Shared Package | |
| ML20052E265 | List: |
| References | |
| TAC-48385, NUDOCS 8205100257 | |
| Download: ML20052E266 (235) | |
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, Enclo;ura 1 Appendix A Technical Specification Page and Section Changed Discussion of Changes 11 Table of Contents Page number errors are corrected.
, iv, Temporary Restrictions The issue of alternate flow path holes in the lower tie plates is a generic issue which has been resolved for many years. Since this practice is accept-able per NRC approved GE topical reports, these temporary restrictions should be removed.
1, Definitions-Minimum -
The word "in-core" is deleted in the Critical Power Ratio term " minimum in-core critical power ratio" to make the term consistent with the GE topical reports presently referenced in the technical specifications.
I and 5, Definitions-Design The precise relationship between Power and Rated Power design and rated power is being included.
4, Definitions L.2 and P Typographical errors are corrected.
Sa, Definition Y A typographical error,is corrected.
7, 1.1.D A heading is added for clarity as well as a reference to Figure 2.1.1.
8, 2.1.A.1.d The word "of" is inserted.
14, 15, 16 These blank pages are being combined to reduce volume.
17 and 18, 2.1 Bases The bases paragraph discussing
". . . operation without forced recirculation . . ." is being deleted because present specification 3.11.D (page 212a) allows for this operation.
22, 2.1 Bases - References Reference 3 is being revised to accurately reflect the licensing process because under 10CFR50.59 the NRC does not " approve" each reload analysis document.
24, 1.2 Bases The word " arbitrarily" is deleted from the third paragraph for clarity. The fifth paragraph is revised to more fully reflect referer ce six. A typographical error is corrected.
f205100257 820430 hDRADOCK 05000298 PDR L
a Appendix A Technical Specification Page and Section Changed Discussion of Changes 25, 2.1 Bases - References Reference 6 is being revised to accu-rately reflect the licensing process because under 10CFR50.59 the NRC does not " approve" each reload analysis document.
26, 2.2 Bases The last three sentences of the first paragraph are being deleted because they are no longer current. There are also minor editorial corrections made.
26, 2.2 Bases - References Reference 6 is being revised to accu-rately reflect the licensing process because under 10CFR50.59 the NRC does not " approve" each reload analysis document. Spelling is corrected in Reference 7.
27, 37, 3.1 Reactor Protection The present LCO on page 27 contains System LOC & Bases the design number (100 milliseconds) for the system response time. Since
, the system has been designed and j start-up tested to verify a response time of less than 50 milliseconds, this type of design da a is being moved to the bases section on page 37.
27, 4.1.D A typographical error is corrected.
- 31, Table 3.1.1 Notes Note 15 is deleted because it is not used in Table 3.1.1.
l 32, Table 4.1.1 (Page 1) The APRM flow bias functional test is performed with a simulated electrical signal. This is required by the de-sign of the system circuitry. Note 4 applies to the APRM flow bias func-tional test. The APRM inoperative functional test does not use a simulated electrical signal and Note 4 is not applicable. These are editorial corrections.
34, Table 4.1.1 Notes An AEC reference is changed to NRC in Note 1.
40, 4.1 Bases Typographical errors are corrected.
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Appendix A Technical Specification Page and Section Changed Discussion of Changes 43, 4.1 Bases An editorial change is made to the fist sentence and a sentence is added to maintain consistency with the MCPR requirements of Section 4.11.C.
45 & 46 These blank pages are being combined to reduce volume.
47, 3.2A & C Editorial inaccuracies are corrected.
48, 3.2.D.4 .A better reference to Section 3.12 is provided.
57, 58, Table 3.2.B Two typographical errors are corrected relating to the HPCl and RCIC Steam-line High AP actuation timers which were added by Amendment 75.
61 Table 3.2.C The RBM upscale (flow bias) trip level setting is being changed in the con-servative direction for two reasons:
- 1) so that subsequent reload analyses done in accordance with NRC approved methods will not require changes to this setting; 2) the present cycle 7 reload submittal inadvertently omitted changing this equation in Amendment 70 to reflect the RBM setting of 106%
used in the reload analysis. This was a clerical error only because CNS presently uses a setting of less than 106% for conservatism.
63 & 63a, Table 3.2.D Page 63a is being combined on page 63 to reduce volume.
73, Table 4.2.B (Page 4) A column heading is revised for clarity.
75, Table 4.2.B (Page 6) A column heading is revised for clarity and the ID number for item 8 is corrected.
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, AppIndix A Technical Specification Page and Section Changed Discussion of Changes 77, Table 4.2.C Since there is no Rod Group C Bypass at CNS, this function should have been changed along with the " note" with Amendment 75. This similar entry on page 61 was deleted with Amendment 61.
Since station procedures test func-tions associated with RSCS bypass, this entry is being changed accordingly.
87, 3.2 Bases A typographical error is being corrected.
93 & 93a Page 93a is being combined on page 93 to reduce volume.
94a, 4.3.B.1.b A typographical error is being corrected.
96, 3.3.B.5.C Since the safety limit MCPR (1.07) is contained in Specification 1.1, it need not appear in other sections of the technical specifications and is being referenced.
97, 4.3.C A punctuation error is corrected and the words "(with saturation tempera-ture)" are being deleted because this is not a requirement per Standard Technical Specification 4.1.3.2 (NUREG-0123, Revision 3) and it unnecessarily restricts CNS from doing scram time testing when cold.
98 A vertical line is added for clarity.
99, 3.3 Bases A typographical error is corrected.
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- Appendix A Technical Specification Page and Section Changed Discussion of Changes 100, 3.1 Bases Delete * (asterisk) from first sentence on page and associated note at bottom of page. Disconnecting the-four amphenol connectors from the insert and withdrawal solenoids is the preferred method to disarm a drive electrically, however, there are several other acceptable methods of electrically disarming a drive. This
. requirement is overly restrictive and it is not proper to make this requirement in the bases section of the technical specification.
101, Bases 3.3.B.3 The first paragraph is revised to more fully reflect Reference 1 (" Generic Reload Fuel Application" NED0-24011).
101a, 102, 103, 104, 105, The exhaustive description of early Bases 3.3.C BWR scram performance degradation on pages 102 and 103 is being deleted since this type of historical infor-mation ,does not belong in technical specifications. After deletion of this'information, blank pages 104 and 105 are being combined.
104 3.3 Bases - References References 1 and 2 are being replaced by the current NRC approved topical report and Reference 3 is revised as before, f
104, 3.3.C Bases Minor editorial changes are made to the second paragraph.
107, 4.4.A.2.b A typographical error is corrected.
108, 3.4.B.1, 4.4.A.2.C A typographical error is corrected and the correct surveillance column head-ing is provided. Also the wording of 4.4.A.2.C is revised for clarity.
1 115, 4.5.A.4 A typographical error is corrected.
119, 4.5.E.1 A typographical error is corrected.
- 122, 3.5.F.5.1 Solid lines are added for clarity and
] this specification is revised for clarity.
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I Appgndix A Technical Specification Page and Section Changed Discussion of Changes 124, 3.5.A Bases Paragraphs two and four are deleted because the descriptions are no longer current. An additional description for the Core Spray System is provided.
An editorial change is also made.
125, 126, 3.5 Bases The headings for certain sections are being changed for uniformity.
129, 130 These blank pages are being combined to reduce volume.
131, 4.5 Bases A typographical error is corrected.
132, 3.6.A.1 A typographical error is corrected.
133, 4.6.A.3 Typographical errors are being corrected.
133a Solid lines are added for clarity.
134, 4.6.B.3 A punctuation error is corrected in paragraph 3 and the word "but" is included in paragraph 3.b for continuity.
1371, Table 3.6.3 Per Specification 3.6.H.5, snubbers were recently added or removed from the drywell.
146, 3.6.A Bases The correct figure reference is provided.
147, 3.6.A Bases Typographical errors are being i
corrected and a better figure reference is provided.
149, 3.6.C Bases The last paragraph is being deleted because the issue involving the first i
year of plant operation is historical l
information.
! 149, 3.6.D Bases The current reload license document is added for reference.
151, 3.6.E Bases The last paragraph is being deleted because the Start-up Test Program is completed and this is historical i information.
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Appendix A Technical Specification Page and Section Changed Discussion of Changes 151, 3.6.F Bases A typographical error is corrected.
152, 3.6.G Bases A typographical error is corrected.
162, 4.7.A.F A typographical error is corrected.
163, 4.7.A.3.b A typographical error is corrected.
164, 165, 165a Ve'rtical lines are added for clarity and a typographical error is corrected in Specification 3.7.A.5.b. The ward
" remove" is added to Specifica-tion 3.7.B.2.a.
166, 4.7.D.1.a A typographical error is being corrected.
169, 173, and 174, Table 3.7.1 Since final licensing of the ACAD and 3.7.4 system is indefinite, the ACAD isolation valves are being added at this time.
178a, 3.7.A Bases Reference to the CAD system is being deleted because an ACAD systet was installed and because 10CFR50.44 now requires inerting.
179, 3.7.A Bases An AEC reference is changed to NRC.
180, 3.7.A Bases A typographical error is corrected.
182, 3.7.B Bases A typographical error is corrected.
187, 188, 189, 190, 191, 192 These blank pages are being combined to reduce volume.
195 & 196, 3.9.B AEC references are being changed to NRC.
199, 200, 201, 202 The information on page 200 is being moved to page 199. These blank pages <
are being combined to reduce volume.
206 A vertical line is added for clarity.
209, 3.10.B Bases A typographical error is corrected.
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Appendix A Technical Specification Page and Section Changed Discussion of Changes 212c, 212d, 212e, MCPR Figures The MCPR values are being moved in the conservative direction so that sub-sequent reload analyses done in accordance with NRC approved methods will not require changes to these figures.
214, 214a, 214b, 214c, 214d, Minor editorial changes and reformat-214e, 3.11 Bases ing to correct error from Amendment 32 which puts basis for 3.11.D under 4.11.D. Excess pages are also eliminated by reformating.
215b, 4.12.B.2 A typographical error is corrected.
216b, 3.14.B.2 Typographical errors are corrected.
216k, Table 3.14 As discussed in the letter from J. M. Pilant to H. R. Denton dated July 2, 1981, " Request for exemption from 10CFR50.48 and Appendix R - Fire Protection", two smoke detectors were
, recently added at CNS. A minor editorial change is also being made.
217, 5.1 Site Features A typographical error is corrected.
217, 5.2.A Reactor "In any combination" is being added for clarity.
> 220, 6.2.1.A.4.b A typographical error is corrected.
230, 6.7.1.C A reference is being deleted because Specification 6.7.1.C.4 was removed by Amendment 75.
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219a, 221, 222, 223, 227, 230, Changes of District titles and refer-
! 231, 232, 234, 6.1.4.A. ences to the distribution requirements of Regulatory Guide 10.1 are being 6.2.1.A.4.f 6.2.1.A.5.b, 6.2.1.A.6, 6.4.1, 6.5.1, made. Typographical errors are also j 6.7.1.A, 6.7.1.B.2, 6.7.1.D, corrected.
6.7.2.A, 6.7.2.B l
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TABLE OF CONTENTS (cont'd)
Page No.
SURVEILLANCE LIMITING CONDITIONS FOR OPERATION REQUIREMENTS 3.6 PRIMARY SYSTEM BOUNDARY (cont'd) 4.6 B. Coolant Chemistry B 133a C. Coolant Leakage C 135 D. Safety and Relief Valves D 136 E. Jet Pumps E 137 F. Jet Pump Flow Mismatch F 137 G. Structural Integrity G 137 3.7 CONTAINMENT SYSTEMS 4.7 159 - 192 A. Primary Containment A 159 B. Standby Gas Treatment System B 165 C. Secondary Containment C 165a D. Primary Containment Isolation Valves
- D 166 3.8 MISCELLANEOUS RADIOACTIVE MATERIAL SOURCES 4.8 185 - 186 3.9 AUXILIARY ELECTRICAL SYSTEMS 4.9 193 - 202 A. Auxiliary Electrical Equipment A 193 B. Operation with Inoperable Equipment B 195 3.10 CORE ALTERATIONS 4.10 203 - 209 A. Refueling Interlocks A 203 B. Core Monitoring B 205 C. Spent Fuel Pool Water Level C 205 D. Time Limitation D 206 E. Spent Fuel Cask Handling E 206 3.11 FUEL RODS 4.11 210 - 214e A. Average Planar Linear Heat Generation Rate (APLHGR) A 210 B. Linear Heat Generation Rate (LHGR) B 210 C. Minimum Critical Power Ratio (MCPR) C 212 D. Thermal-hydraulic Stability D 212a 3.12 ACDITIONAL SAFETY RELATED PLANT CAPABILITIES 4.12 215 - 215f A. Main Control Room Ventilation A 215 B. Reactor Building Closed Cooling Water System B 215b C. Service Water System C 215c D. Battery Room Vent D 215c 3.13 RIVER LEVEL 4.13 216 L
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. 1.0 DEFINITIONS The succeeding frequently used terms are explicitly defined so that a uniform interpretation of the specifications may be achieved.
A. Thermal Parameters
- 1. Critical Power Ratio (CPR) - The critical power ratio is the ratio of
- that assembly power which causes some point in the assembly to experience transition boiling to the assembly power at the reactor condition of interest as calculated by application of the GEXL correlation. (Reference NED0-10958)
- 2. Maximum Fraction of Limiting Power Density - The Maximum Fraction of Limiting Power Density (MFLPD) is the highest value existing in the core of the Fraction of Limiting Power Density (FLPD). ,
- 3. Minimum Critical Power Ratio (MCPR) - The minimum critical power l ratio corresponding to the most limiting fuel assembly in the core.
- 4. Fraction of Limiting Power Density - The ratio of the linear heat generation rate (LHGR) existing at a given location to the design LHGR for that bundle type. Design LHGR's are 18.5 KW/ft for 7x7 bundles and 13.4 KW/ft for 8x8 bundles.
- 5. Transition Boiling - Transition boiling means the boiling regime between nucleate and film boiling. Transition boiling is the regime in which both nucleate and film boiling occur intermittently with neither type being completely stable.
B. Alteration of the Reactor Core - The act of moving any component in the region above the core support plate, below the upper grid and within the i shroud. Normal control rod movement with the control rod drive hydraulic l system is not defined as a core alteration. Normal movement of in-core instrumentation is not defined as a core alteration.
C. Cold Condition - Reactor coolant temperature equal to or less than 212 F.
D. Design Power - Design power means a steady-state power level of 2486 thermal megawatts. This is 104.4% of Rated Power (105% of rated steam flow) and the l power to which the safety analysis applies.
l E. Engineered Safeguard - An engineered safeguard is a safety system the actions of which are essential to a safety action required to maintain the consequences of postulated accidents within acceptable limits.
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. K. Limiting Safety System Setting (LSSS) - The limiting safety system settings are settings on instrumentation which initiate the automatic protective ,
action at a level such that the safety limits will not be exceeded. The I region between the safety limit and these settings represent a margin with normal operation lying below these settings. The margin has been established so that with proper operation of the instrumentation the safety limits will never be exceeded.
L. Mode - The reactor mode is established by the mode selector-switch. The modes include refuel, run, shutdown and startup/ hot standby which are defined as follows:
- 1. Refuel Mode - The reactor is in the refuel mode when the mode switch is in the refuel mode position. When the mode switch is in the refuel position, the refueling interlocks are in service.
- 2. Run Mode - In this mode the reactor system pressure is at or above 825 psig and the reactor protection system is energized with APRM protection (excluding the 15% high flux trip) and RBM interlocks l in service.
- 3. Shutdown Mode - The reactor is in the shutdown mode when the reactor mode switch is in the shutdown mode position.
- 4. Startup/ Hot Standby - In this mode the reactor protection scram trips initiated by the main steam line isolation valve closure are bypassed when reactor pressure is less than 1000 psig, the low pressure main steam line isolation valve closure trip is bypassed, the reactor protection system is energized with APRM (15% SCRAM) and IRM neutron monitoring system trips and control rod withdrawal interlocks in service.
M. Operable - A system or component shall be considered operable when it is capable of performing its intended function in its required manner.
i N. Operating - Operating means that a system or component is performing its intended functions in its required manner.
O. Operating Cycle - Interval between the end of one refueling outage and the end of the next subsequent refueling outage.
l P. Primary Containment Integrity - Primary containment integrity means l that the drywell and pressure suppression chamber are intact and all of l the following conditions are satisfied:
- 1. All manual containment isolation valves on lines connected to the l reactor coolant system or containment which are not required to be open during accident conditions are closed.
- 2. At least one door in each airlock is closed and sealed.
- 3. All automatic conteinm:nt isolation valves are operable or ds-activatzd in the isolated position.
- 4. All blind flanges and manways are closed.
Q. Rated Power - Rated power refers to operation at a reactor power of 2381 megawatts thermal. This is also termed 100% power and is the maximum power level authorized by the operating license. Rated steam flow, rated coolant flow, rated neutron flux; and rated nuclear system pressure refer to the values of these parameters when the reactor is at rated power. Design power, the power to which the safety analysis applies, is 104.4% of rated power (105% of rated steam flow), which corresponds to 2486 megawatts thermal.
R. Reactor Power Operation - Reactor power operation is any operation with the mode switch in the "Startup/ Hot Standby" or "Run" position with the reactor critical and above 1% rated power.
S. Reactor Vessel Pressure - Unless otherwise indicated, reactor vessel pressures listed in the Technic'al Specifications are those measured by the reactor vessel steam space detectors.
T. Refueling Outage - Refueling outage is the period of time betwe_n the shutdown of the unit prior to a refueling and the startup of the plant after that refueling.
U. Safety Limits - The safety limits are limits within which the reasonable maintenance of the fuel cladding integrity and the reactor coolant system integrity are assured. Violation of such a limit is cause for unit shut ,
down and review by the Nuclear Regulatory Commission before resumption of unit operation. Operation beyond such a. limit may not in itself result in serious consequences but it indicates an operational deficiency subject to regulatory review.
V. Secondary Containment Integrity - Secondary containment integrity means that the reactor building is intact and the following conditions are met:
- 1. At least one door in each access opening is closed.
l 2. The standby gas treatment system is operable.
- 3. All automatic ventilation system isolation valves are operable or secured in the isolated position.
W. Shutdown - The reactor is in a shutdown condition when the mode switch is in the " Shutdown" or " Refuel" position.
- 1. Hot Shutdown means conditions as above with reactor coolant temperature greater than 212 F.
- 2. Cold Shutdown means conditions as above with reactor coolant temperature equal'to or less than 212 F and the reactor vessel vented.
X. Spiral Reload - Pertains to the spiral reloading of the core with fuel, at least 50% of which has previously accumulated a minimum exposure of 1000 MWD /T.
Y. Survaillenca Frrqur;ncy - Surveillenca rtquirtments chall bs applicabic during the operational conditions associated with individual LCO's l unless otherwise s.tated in an individual Surveillance Requirement.
Each Surveillance Requirement shall be performed within the specified time interval with:
- a. A maximum allowable extension not to exceed 25% of the surveillance interval.
- b. A total maximum combined interval time for any 3 consecutive surveillance intervals not to exceed 3.25 times the specified interval.
Performance of a Surveillance Requirement within the specified time interval shall constitute compliance with operability requirements for an LCO unless otherwise required by the specification.
Z. Surveillance Interval - The surveillance interval is the calendar time between surveillance tests, checks, calibrations and examinations to be performed upon an instrument or component when it is required to be operable. These tests may be waived when the instrument, component or system'is not required to be operable, but the instrument, component or system shall be tested prior to being declared operable or as practicable following its return to service.
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T Appendix.A Technical Specification Page and Section Changed Discussion'of Changes L 151', 3.6.F. Bases A typographical error'is corrected.
152, 3.6.G Bases A typographical error is corrected.
162, 4.7.A.F A typographical error is corrected.
l 163, 4.7.A.3.b A typographical error is corrected.
164, 165, 165a Vertical lines are added for clarity and a-typographical error is corrected in Specification 3.7.A.5.b. The word 1
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" removal" is added to Specifica-
,' tion 3.7.B.2.a.
166, 4.7.D.I.a A typographical error is being corrected.
169, 173, and 174, Table 3.7.1 Since final licensing of the ACAD
, and 3.7.4 system is indefinite, the ACAD isolation valves are being added at this time.
178a, 3.7.A Bases Reference to the CAD system is being
' deleted because an ACAD system was installed and because 10CFR50.44 now requires inerting.
179, 3.7.A Bases An AEC reference is changed to NRC.
i 180, 3'.7.A Bases A typographical error is corrected.
182, 3.7.B Bases A typographical error is corrected.
187, 188, 189, 190, 191, 192 These blank pages are being combined to reduce volume.
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195 & 196, 3.9.B AEC references are being changed to NRC.
199, 200, 201, 202 The information on page 200 is being moved to page 199. These blank pages art being combined to reduce volume.
I 206 A vertical line is added for clarity.
4 209, 3.10.B Bases A typographical error is corrected.
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SAFETY LIMITS LIMITING SAFETY SYSTEM SETTINGS 2.1.A.1 (Cont'd) l
S 1 *0 RB where:
S = d block setting in RB percent of rated thermal power (2381 MWt)
W = Loop recirculaf:fon flow rate in percent of rated (rated loop recirculation flow rate is that recirculation flow rate which provides 100%
coreflow at 100% power)
In the event of operation with a maximum fraction of limiting l
power density (MFLPD) greater than the fraction of rated power (FRP), the setting shall be modified as follows:
S 1(0.66 W + 42%) FRP RB MFLPD where, FRP = fraction of rated thermal power (2381 MWt) t MFLPD - maximum fraction of limiting power density where the limiting power density is 18.5 KW/ft for 7x7 fuel and 13.4 KW/ft for 8x8 fuel.
The ratio of FRP to MFLPD shall be set equal to 1.0 unless the actual operating value is less than the design value of 1.0, in which case the actual operating value will be used.
> +12.5 in. on vessel level instruments.
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2 .1" Basen:
The abnormal operational transients applicable to operation of the CNS Unit have been analyzed throughout the spectrum of planned operating con-ditions up to 105% of rated steam flow. The analyses were based upon plant operation in accordance with Reference 3. In addition, 2381 MWt is the licensed maximum power level of CNS, and this represents the maximum steady-state power which shall not knowingly be exceeded.
Conservatism is incorporated in the transient analyses in estimating the controlling factors, such as void reactivity coefficient, control rod scram worth,~ scram delay time, peaking factors, and axial power shapes. These factors are selected conservatively with respect to their effect on the applicable transient results as determined by the current analysis model.
This transient model, evolved over many years, has been substantiated in operation as a conservative tool for evaluating reactor dynamic performance.
Results obtained from a General Electric boiling water reactor have been compared with predictions made by the model. The comparisons and results
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are summarized in Reference 1.
The absolute value of the void reactivity coefficient used in the analysis is conservatively estimated to be about 25% greater than the nominal maximum value expected to occur during the core lifetime. The scram worth used has been derated to be equivalent to approximately 80% of the total scram worth of the control rods. The scram delay time and rate of rod insertion allowed by the analyses are conservatively set equat to the longest delay and slow-est insertion rate acceptable by Technical Specifications. The effect of scram worth, scram delay time and rod insertion rate, all conservatively applied, are of greater significance in the early portion of the negative reactivity insertion. The rapid insertion of negative reactivity is assured by the time requirements for 5% and 25% insertion. By the time the rods are 60% inserted, approximately four dollars of neg'ative reactivity have been inserted which strongly turns the transient, and accomplishes the desired effect. The times for 50% and 90% insertion are given to assure proper completion of the expected performance in the earlier portion of the tran-sient, and to establish the ultimate fully shutdown steady-state condition.
This choice of using conservative values of controlling parameters and initi-ating transients at the design power level produces more pessimistic answers than would result by using expected values of control parameters and analy-zing at higher power levels.
2.1" Breaa: (Cont'd)
In summary:
- 1. The abnormal operational transients were analyzed to 105% of rated steam flow.
ii. The licensed maximum power level is 2381 MWt.
iii. Analyses of transients employ adequately conservative values of the controlling reactor parameters.
iv. The analytical procedures now used result in a more logical answer than the alternative method of assuming a higher start-ing power in conjunction with the expected values for the parameters.
A. Trip Settings The bases for individual trip settings are discussed in the following paragraphs.
- 1. Neutron Flux Trip Settings
The average power range monitoring (APRM) system, which is calibrated using heat balance data taken during steady state conditions, reads in percent of rated thermal power (2381 MWt). Because fission chambers provide the basic input signals, the APFM system responds directly to average neutron' flux. During transients, the instanta-neous rate of heat transfer from the fuel (reactor thermal power) is less than the instantaneous neutron flux due to the time constant of the fuel. Therefore, during abnormal operational transients, the thermal power of the fuel will be less than that indicated by the neutron flux at the scram setting. Analyses demonstrate that with a 120% scram trip setting, none of the abnormal operational transients analyzed violate the fuel Safety Limit and there is a substantial margin from fuel damage. Therefore, the use of flow referenced scram trip provides even additional margin.
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2.1. Bessat (Cont'd)
- 5. Main Steam Line Isolation Valve Closure on Low Pressure The low pressure isolation of the main steam lines (Specifi-cation 2.1.A.6) was provided to protect against rapid reactor depressurization.
B. Reactor Water Level Trip Settings Which Initiate Core Standby Cooling System (CSCS)
The core standby cooling subsystems are designed'to provide suf-
- ficient cooling to the core to dissipate the energy associated with the loss-of-coolant accident and to limit fuel clad temperature, to assure that core geometry remains intact and to limit any clad metal-water reaction to less than 1%. To accomplish their intended function, the capacity of each Core Standby Cooling System component was established based on the reactor low water level scram set point. To lower the set point of the low water level scram would increase the capacity requirement for each of the CSCS components.
Thus, the reactor vessel low water level scram was set low enough to permit margin for operation, yet will not be set lower because of CSCS capacity requirements.
The design for the CSCS components to meet the above guidelines was dependent upon three previously set parameters: -The maximum break
, point.- To lower the set point for initiation of the CSCS may lead to a decrease in effective core cooling. To raise the CSCS initia-tion set point would be in a safe direction,.but it would reduce the margin established to prevent actuation of the.CSCS during normal operation or during normally expected transients.
Transient and accident analyses reported in Section 14 of the Final Safety Analyses Report demonstrate that these conditions result in adequate safety margins for the fuel.
I C. References
- 1. Linford, R. B., " Analytical Methods of Plant Transient Evaluations for the General Electric Boiling Water Reactor,"
NEDO-10801, Feb., 1973.
- 2. Station Safety Analysis Report (Section XIV).
- 3. " Supplemental Reload Licensing Submittal for Cooper Nuclear Station Unit 1," (applicable reload document).
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1.2 BASES 4
The reactor coolant system integrity is an important barrier in the prevention of uncontrolled release of fission products. It is essential that the integrity of this system be protected by establishing a pressure limit to be observed for all operating conditions and whenever there is irradiated fuel in the reactor vessel.
The safety limits for reactor coolant system pressure are derived directly from unacceptable safety results 1-3, 2-3, and 3-3 of the Station Nuclear Safety Operational Analysis (Appendix G). These unacceptable results require that l
applicable code limits for the nuclear system not be exceeded. Thus, the safety limits are direct measures of the unacceptable safety results.
The safety limits for the reactor coolant system pressure have been selecte'd so that they are below pressures at which it can be shown that the integrity of the system is not endangered. However, the pressure safety limits are set high enough that no foreseeable circumstances can cause the system pressure to rise over these limits. The pressure safety limits are selected to be the lowest transient overpressures allowed by the applicable codes. ASME Boiler l and Pressure Vessel Code,Section III, and USAS Piping Code, Section B31.1.
The reactor vessel steam dome pressure of 1337 puig is equivalent to a pressure of 1375 psig at the vessel bottom. The design pressure (1250 psig) of the reactor vessel is established so that, when the 10 percent allowance (125 psi) allowed by the ASME Boiler and Pressure Vessel Code,Section III, for pressure transients, is added to the design pressure, a transient pressure limit of 1375 psig at the vessel bottom is established. Correspondingly, the suction and discharge design pressures (1148 and 1274 psig) of the reactor coolant system piping are set so that, when the 20 percent allowance (230 and 254 psi) allowed by the USAS Piping Code, Section B31.1 for pressure transients, are added to the design pressures, transient pressure limits of 1378 and 1528 psig are established. Thus, the pressure safety limit for power operation is established at 1375 psig, the lowest transient overpressure allowed by the pertinent codes, ASME Boiler and Pressure Vessel Code,Section III, and USAS Piping Code, Section B31.1.
Reference 6 provides the most severe abnormal operational transient resulting l directly in a reactor coolant system pressure increase. The reactor vessel
- pressure code limit of 1375 psig, given in Subsection IV2 of the Safety Analysis l Report, is well above the peak pressure produced by the pressurization transient l described in Reference 6. Thus, the pressure safety limit applicable to power l operation is well above the peak pressure that can result from reasonably expected pressurization transients. l Higher design pressures have been established for piping within the reactor l coolant system than for the reactor vessel. These pressures create a consistent l design with assurance that, if the pressure within the reactor vessel does not
, exceed 1375 psig, the pressures within the piping cannot exceed their respective l transient pressure limits because of static and pump heads.
l l
A ccfsty linit is cppliGd to th2 Raciduni H2ct R:moval Systca (RHRS) wh2n it is operating in the shutdown cooling mode. When operating in the shutdown cooling mode, the RHRS is included in the reactor coolant system. '
REFERENCES
- 1. Station Safety Analysis (Section XIV)
- 2. ASME Boiler and Pressure Vessel Code Section III
- 3. USAS Piping Cede, Section B31.1 4 Reactor Vessel and Appurtenances Mechanical Design (Subsection lV-2)
- 5. Station Nuclear Safety Operational Analysis (Appendix G)
- 6. " Supplemental Reload Licensing Submittal for Cooper Nuclear Station Unit 1,"
(applicable reload document). l I
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, 2.2 BASES The 8 relief valves and 3 safety valves are sized and set pressures are established in accordance with the requirements of Section III of the ASME Code. The relief valve settings satisfy the Code requirements that the lowest l
valve set point be at or below the vessel design pressure of 1250 psig.
These settings are also sufficiently above the normal operating pressure range to prevent unnecessary cycling caused by minor transients. The postulated transients where inherent relief valve actuation is required are described in Section XIV of the Safety Analysis Report.
Reanalysis in Reference 6 for the case of MSIV-Closure with flux scram transient results in a peak pressure at the vessel bottom which is below the maximum of 110 percent of design pressure allowed by the Code.
This is adequate margin to ensure that the 1375 psig pressure safety limit is not exceeded. A sensitivity study on peak vessel pressure to the failure to open of one of the lowest set-point safety valves was performed for a typical high power density BWR (Reference 7). The study is appli-cable to the Cooper reactor and shows that the sensitivity of a high power density plant to the failure of a safety valve is approximately 20 psi. A plant specific analysis for the Cooper overpressure transient would show ,
results equal to or less than this value.
The design pressure of the shutdown cooling piping of the Residual Heat Removal System is not exceeded with the reactor vessel steam dome less than 75 psig.
REFERENCES
- 1. Topical Report, " Summary of Results Obtained from a Typical Startup and Power Test Program for a General Electric Boiling Water Reactor".
General Electric Company, Atomic Power Equipment Department (APED-5698)
- 2. Station Nuclear Safety Operational Analysis (Appendix G)
- 3. Station Safety Analysis (Section XIV)
- 4. Control and Instrumentation (Section VII)
- 5. Summary Technical Report of Reactor Vessel Overpressure Protection (Question 4.20, Amendment 11 to SAR)
- 6. " Supplemental Reload Licensing Submittal for Cooper Nuclear l
Station Unit 1," (applicable reload document). l l
- 7. Letter from I. F. Stuart (GE) to v. Stello (NRC) dated l December 23, 1975. <
LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.1 REACTOR PROTECTION SYSTEM 4.1 REACTOR PROTECTION SYSTEM Applicability: Applicability:
Applies to the instrumentation and Applies to the surveillance of the associated devices which initiate instrumentation and associated a reactor scram. devices which initiate reactor scram.
Objective: Objective:
To assure the operability of the To specify the type and frequency reactor protection system. of surveillance to be applied to the protection instrumentation.
Specification: Specification:
The setpoints, minimum number of A. Instrumentation systems shall trip systems, and minimum number of be functionally tested and instrument chaanels that must be calibrated as indicated in Tables operable for each position of the 4.1.1 and 4.1.2 respectively.
reactor mode switch shall be as given in Table 3.1.1. B. Daily during resctor power operation, the peak heat flux and maximum fraction of limiting power density shall be checked and the SCRAM and APRM Rod Block settings given by equations in Specification 2.1.A.1 and 2.1.B shall be calculated if maximum fraction of limiting power den-sity exceeds the fraction of rated power.
C. During reactor power operation with MFLPD > FRP, MCPR shall be calculated at least daily and following any change in power level or distribution that would cause operation with a limiting control rod pattern as defined in Specification 3.3.B.5 and associated bases.
D. When it is determined that a channel has failed in the unsafe condition, the other RPS c' 2nnels that monitor the same variable shall be functionally tested immediately before the trip system containing the failure is tripped.
The trip system containing the l unsafe failure .ay be placed in the untripped condition during the period in which surveillance testing is being performed on the other RPS channels.
11., The APRM downscals trip function in only activa whtn tha razetor gode switch is in run.
i
- 12. The APRM downscale trip is autcmatically bypassed when the mode switch is not in RUN.
- 13. An APRM will be considered inoperable if there are less than 2 LPRM inputs per level or there is less than 11 operable LPRM detectors to an APRM.
- 14. W is the recirculation flow in percent of rated flow.
- 15. This note deleted.
- 16. The 15% APRM sciam is bypassed in the RUN mode.
- 17. The APRM and IRM instrument channels function in both the Reactor Protection System and Reactor Manual Control System (C4ti:rol Rod Withdraw Block, Section 3.2.C.). A failure of one channel will affect both of these systems.
9
COOPER NUCLEAR STATION ,
TABLE 4.1.1 (Page 1) ,
REACTOR PROTECTION SYSTEM (SCRA!! INSTRUMENTATION) FUNCTIONAL TESTS MINIMUM FUNCTIONAL TEST FREQUENCIES FOR SAFETY INSTR. AND CONTROL CIRCUITS Instrument Channel Group (2) Functional Test Minimum Frequency (3)
Mode Switch in Shutdown A Place Mode Switch in Each Refueling Outage Shutdown Manual Scram A Trip Channel and Alarm Once/3 Months RPS Channel Test Switch (5) A Trip Channel and Alarm Each Refueling Outage IRM liigh Flux C Trip Channel and Alarm Before each startup and weekly (4) when required to be operable, i Inoperative C Trip Channel and Alarm Before each startup and weekly U when required to be operable.
I APRM Before each startup and weekly liigh Flux (15%) C Trip Output Relays (4) when required to be operable.
liigh Flux B Trip Output Relays (4) Once/ Week inoperative B Trip Output Relays Once/ Week !
Downscale B Trip Output Relays (4) Once/ Week Flow Bias B Trip Output Relays (4) Once/ Month (1) l liigh Reactor Pressure A Trip Channel and Alarm Once/ Month (1)
NB1-PS-55 A,B.C,& D liigh Drywell Pressure A Trip Channel and Alarm Once/ Month (1)
PC-PS-12 A,B,C,& D Reactor Low Water level (6) A Trip Channel and Alarm Once/ Month (1)
NB1-LIS-101 A,B,C &D
. NOTES FOR TABLE 4.1.1
- 1. Initially ogce.per month until exposure (M as defined on Figure 4.1.1) is 2.0 x 10 ; thereafter, according to Figure 4.1.1 with an interval not less than one month nor more than three months after review and approval of the NRC. The compilation of instrument failure rate data may include l data obtained from other boiling water reactors for which the same design instrument operates in an environment similar to that of CNS.
- 2. A description of the three groups is included in the Bases of this Speci-fication.
- 3. Functional tests are not required when the systems are not required to be operable or are tripped. If reactor startups occur more frequently than once per week, the maximum functional test frequency need not exceed once per week.
If tests are missed, they shall be performed prior to returning the systems to an operable status.
- 4. This instrumentation is exempted from the instrument channel test definition. This instrument channel functional test will consist of injecting a simulated electrical signal into the measurement channels.
- 5. Test RPS channel after maintenance.
- 6. The water level in the reactor vessel will be perturbed and the corresponding level indicator changes will be monitored. This perturbation test will be performed every month after completion of the monthly functional, test program.
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LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.1 BASES 4.1 BASES The reactor protection system auto- A. The minimum functional testing matically initiates a reactor scram frequency used in this specifi-to: cation is based on a reliability analysis using the concepts
- 1. Preserve the integrity of the developed in reference (6).
fuel cladding. This concept was specifically adapted to the one out of two
- 2. Preserve the integrity of the taken twice logic of the reactor reactor coolant system. protection system. The analysis shows that the sensors are pri-
- 3. Minimize the energy which must marily responsible for the be absorbed following a loss of reliability of the reactor coolant accident, and prevent protection system. This analysis inadvertent criticality. makes use of " unsafe failure" rate experience at conventional This specification provides the lim- and nuclear power plants in a iting conditions for operation reliability model for the system.
necessary to preserve the ability An " unsafe failure" is defined ,
of the system to perform its in- as one which negates channel tended function even during periods operability and which, due to its when instrument channels may be out nature, is revealed only when of service because of maintenance. the channel is functionally tested When necessary, one channel may be or attempts to respond to a real made inoperable for brief intervals signal. Failures such as blown to conduct required functional tests fuses, ruptured bourdon tubes, and calibrations. faulted amplifiers, and faulted cables, which result in " upscale" The designed system response times or "downscale" readings on the from the opening of the sensor con- reactor instrumentation are " safe" tact up to and including the open- and will be easily recognized ing of the trip actuator has been by the operators during operation shown by start-up testing to not because they are revealed by r; exceed 50 milliseconds. alarm or a scram.
The reactor protection system is of The channels listed in Tables the dual channel type (Reference 4.1.1 and 4.1.2 are divided into subsection VII.2 FSAR). The system three groups for functional is made up of two independent trip tecting. These are:
systems, each having two subchannels of tripping devices. Each subchannel A. On-off sensors that provide has an input from at least one in- a scram trip function.
strument channel which monitors a critical parameter. B. Analog devices coupled with bi-stable trips that provide The outputs of the subchannels are a scram function.
combined in a 1 out of 2 logic; i.e.,
an input signal on either one or both C. Devices which only serve a
! of the subchannels will cause a trip useful function during some system trip. The outputs of the trip systedx are arranged so that a trip on both systems is required to produce a reactor scram.
l This system meets the intent of IEEE-279 for Nuclear Power Plant Protection
(
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., LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.1 BASES (cont'd.) 4.1 BASES (cont'd.)
against short reactor periods in revealed only on test. Therefore, these ranges. it is necessary to test them periodi-cally.
The control rod drive scram system is designed so that all of the water A study was conducted of the instru-which is discharged from the reactor mentation channels included in the by a scram can be accommodated in the Group (B) devices to calculate their discharge piping. The scram discharge " unsafe" failure rates. The analog volume accommodates in excess of 36 devices (sensors and amplifiers) gallons of water and is the low point a,re predicted to have an unsafe -6 in the piping. No credit was taken failure rate of less than 20 X 10 for this volume in the design failures / hour. The bi-stable trip of the discharge piping as concerns circuits are predicted to have an the amount of water which must be unsafe _gailurerate.oflessthan accommodated during a scram. 2 X 10 failures / hour. Consider-ing the two hour monitoring interval During normal operation the dis- for the analog devices as assumed charge volume is empty; however, above, and a weekly test interval should it fill with water, the water for the bi-stable trip circuits, discharged to the piping from the the design reliability goal of reactor could not be accommodated which 0.99999 is attained with ample margin.
would result in slow scram time.s or partial control rod insertion. To pre- The bi-stable devices are monitored clude this occurrence, level switches during plant operation to record their have been provided in the instrument failure history and establish a test 4
volume which alarm and scram the interval using the curve of Figure reactor when the volume of water reaches 4.1.1. There are numerous identical l
36 gallons. As indicated above, there bi-stable devices used throughout is sufficient volume in the piping to the plant's instrumentation system.
accommodate the scram without impairment Therefore, significant data on the of the scram times or amount of inser- failure rates for the bi-stable devices tion of the control rods. This func- should be accumulated rapidly.
! tion shuts the reactor down while i
sufficient volume remains to accommo- The frequency of calibration of the date the discharged water and precludes APRM Flow Biasing Network has been the situation in which a scram would established as each refueling out-be required but not be able to perform age. The flow biasing network is l
its function adequately. functionally tested at least once per month and, in addition, cross A source range monitor (SRM) system is calfbration checks of the flow also provided to supply additional input to the flow biasing network neutron level information during start- can be made during the functional up but has no scram functions (refer- test by direct meter reading. There ence paragraph VII.5.4 FSAR). Thus, are several instruments which must the IRM and APRM are required in the be calibrated and it will take sev-
" Refuel" and " Start / Hot Standby" modes. eral days to perform the calibration In the power range,the APRM system of the entire network. While the provides required protection (refer- calibration is being performed, a
, LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.1 BASES 4.1 BASES (Cont'd) flux is very high. Therefore, with MFLPD < FRP there is no technical requirement for calculating MCPR.
However, to be consistant with Section 4.11.C. MCPR shall be deter-mined daily during reactor power operation at > 25% rated thermal power. With MFLPD greater than FRP, a daily calculation of MCPR is suffi-cient since power distribution shifts are very slow when there have not been significant power or control rod changes. The requirement for calculat-ing MCPR when a limiting control rod pattern is approached insures that MCPR will be known following a change in power or power shape (regardless of magnitude) that could place operation at a thermal limit.
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" INTENTIONALLY LEFT BLANK"
-45, 46-
g LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENT 3.2 Protective Instrumentation 4.2 Protective Instrumentation Applicability: Applicability:
Applies to the plant inst rumenta- Applies to the surveillance requirement tion which initiates and controls a of the instrumentation that initiates protective function, and controls protective function.
Objective: Objective:
To assure the operability of pro- To specify the type and frequency of tective instrumentation. surveillance to be applied to protec-tive instrumentation.
Specifications: Specifications:
A. Primary Containment Isolation F. unctions A. Primary Containment Isolation Functions When primary containment integrity is Instrumentation shall be functionally l required, the limiting conditions for tested and calibrated as indicated in operation for the instrumentation that Table 4.2.A.
initiates primary containment isola-tion are given in Table 3.2.A. System logic shall be functionally tested as indicated in Table 4.2.A.
B. Core and Containment Cooling Systems B. Core and Containment Cooling Systems Initiation and Control Initiation & Control The limiting conditions for operation Instrumentation shall be functionally for the instrumentation that initiates tested, calibrated and checked as in-or controls the core and containment dicated in Table 4.2.B.
cooling systems are given in Table 3.2.B. This instrumentation must System logic shall be functionally tested be operable when the system (s) it as indicated in Table 4.2.B.
initiates or controls are required to be operable as specified in Section 3.5.
C. Control Rod Block Actuation C. Control Rod Block Actuation l The limiting conditions for operation Instrumentation shall be functionally for the instrumentation that initiates tested, calibrated and checked as indi-l control rod blocks are given in Table cated in Table 4.2.C.
3.2.C.
System logic shall be functionally tested as indicated in Table 4.2.C.
. LIMITING CONDITION FOR OPERATION SURUEILLANCE REQUIREMENT 3.2 (cont'd.) 4.2 (cont'd)
D. Radiation Monitoring Systems - D. Radiation Monitoring Systems -
Isolation & Initiation Functions Isolation & Initiation Functions
- 1. Steam Jet Air Ejector Off-Cas System 1. Steam Jet Air Ejector Off-Gas System
- a. Except as specified in Specification Instrumentation surveillance require-2.4.3.a.7 of Appendix B, both steam ments are given on Table 4.2.D.
jet air ejector off-gas system radiation monitors shall be operable.
- b. The time delay setting for closure of the steam jet air ejector isolation valves shall not exceed 15 minutes.
- c. Other limiting conditions for oper-ation are given on Table 3.2.D and Sections 2.4.3.a.6.b and 2.4.3.a.7 of the Environmental Technical Specifications.
- 2. Reactor Building Isolation and 2. Reactor Building Isolation and Standby Gas Treatment Initiation Standby Gas Treatment Initiation The limiting conditions for operation Instrumentation surveillance require-are given on Table 3.2.D and Section ments are given on Table 4.2.D.
2.4.3.a of Appendix B.
- 3. Liquid Radwaste Discharge Isolation 3. Liquid Radwaste Discharge Isolation The limiting conditions for operation Instrumentation surveillince requirements are given on Table 3.2.D and Section are given on Table 4.2.D and Section 2.4.1.b.3 of Appendix B. 3.4.1.b.7 of the Environmental Technical Specifications.
- 4. Main Control Room Ventilation 4. Main Con;rol Room Ventilation Isolation Isolation The limiting conditions for operation The instrument surveillance requirements are given on Table 3.2.D and Sec- are given on Table 4.2.D.
l tion 3.12 entitled " Addition Safety Related Plant Capabilities."
COOPER NUCLEAR STATION TABLE 3.2.B (PAGE 5) ,
llPCI SYSTEM CIRCUITRY REQUIREMENTS Minimum Number of Action Required When Instrument Operable Components Component Operability Instrument I.D. No. Setting Limit Per Trip System (1) Is Not Assured Suppression Chamber HPCI-LS-91 A & B 2b" H7 0 (5" Above 1(2) A High Water Level NormaI)
HPCI Gland Seal Cond. HPCI-LS-356 B >18" 1(3) A Hotwell Level HPCI-LS-356 A 546" 1(3) A HPCI Turbine Stop HPCI-LMS-4 N.A. 1(2) B Valve Monitor Suppression Chamber HPCI-LMS-2 N.A. 1(2) A HPCI Suction Valve 23-58 i
HPCI Control Oil HPCI-PS-2787-H 3,85 psig 1(2) B
, i Pressure Low HPCI-PS-2787-L 3,20 psig Turbine Conditional HPCI-TDR-K14 13.5fT<16.5 sec. 1(3) E Supervisory Alarm Actuation Timer Pump Discharge Line
- Low Pressure CM-PS-268 >10 psig (3) D HPCI Steamline liigh HPCI-TDR-K33 2.7<T<3.3 sec. 1 A AP Actuation Timer HPCI-T?n-K43 l
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COOPER NUCLEAR STATION TABLE 3.2.B (PAGE 6)
REACTOR CORE ISOLATION COOLING SYSTEM (RCIC) CIRCUITRY REQUIREMENTS Minimum Number of Action Required When Instrument Operable Ccmponents Component Operability Instrument I.D. No. Setting Limit Per Trip System (1) Is Not Assured RCIC High Turbine RCIC-PS-72, A & B j,25 psig 1(2) A Exhaust Press.
RCIC Low Pump Suction RCIC-PS-67-1 f-15" Hg 1(2)
Press.
RCIC Steam Line Space RCIC-TS-79, A,B,C,&D 3,200 F 2(4) A Excess Temp. RCIC-TS-80, A,B.C,&D RCIC-TS-81, A,B,C,&D RCIC-TS-82, A,B.C,8D RCIC Steam Line High RCIC-dPIS-83 & 84 370" <S<620" H O 1 A 2
AP RCIC Steam Supply RCIC-PS-87, A,B,C,8D 3,50 psig 2(2) A Press Low I
f RCIC Low Pump Disch. Flow RCIC-FIS-57 3,40 gpm 1(2) A Pump Discharge Line CM-PS-269 3,10 psig (3) D Low Pressure RCIC Turbine Condition- RCIC-TDR-K9 13.5 < T f,16.5
, (3) E al Supervisory Alarm Timer Reactor Low Water 10A-K80, A & B 3-37" Indicated Level 2(2) A Level 10A-K79, A & B (NBI-LIS-72, A B.C.
& D)
Reactor High Water NBI-LIS-101, A & C #2 <+58.5 Indicated Level 2(2) A Level RCIC Steamline High RCIC-TDR-K12 2.7<T<3.3 sec 1 A AP Actuation Timer RCIC-TDR-K32 l
4 -
TABLE 3.2.C CONTROL ROD WITilDRAWAL BLOCK INSTRUMENTATION ,
Minimum Number Of Function Trip Level Setting Operable Instrument Channels / Trip System (5)
APRM Upscale (Flow Bias) 1 (0.66W + 42%) FRP (.2) '
2(1)
APRM Upscale (Startup) 1 12% MFLPD 2(1)
APRM Downscale (9) 1 2.5% 2(1)
APRM Inoperative (10b) 2(1)
RBM Upscale (Flow Bias) 1 (0.66W + 40%) (2) 1 l
RBM Downscale (9) 1 2.5% 1 RBM Inoperative (10c) ,
1 IRM Upscale (8) 1 108/125 of Full Scale 3(1)
IRM Downscale (3)(8) 1 2.5% 3(1) i IRM Detector Not Full In (8) 3(1) 8 IRM Inoperative (8) (10a) 3(1) 5 SRM Upscale (8) < 1 x 10 Counts /Second 1(1)(6)
SRM Detector Not Full In (4)(8) (1 100 cps) 1(1)(6)
SRM Inoperative (8) (10a) 1(1)(6)
Flow Bias Comparator 1 10% Difference In Recirc. Flows 1 Flow Bias Upscale /Inop. I 110% Recirc. Flow 1 SRM Downscale (8)(7) 1 3 Counts /Second (11) 1(1) (6)
SDV Water Level High < 18 gallons 1(12)
COOPER NUCLEAR STATION TABLE 3.2.D RADIATION MONITORING SYSTEMS TilAT INITIATE AND/OR ISOLATE SYSTEMS Number of Sensor Instrument Setting Channels Provided Action System I. D. No. Limit by Design (1)
Steam Jet Air Ejector Off-Cas RMP-RM-150 A & B < 1 ci/sec 2 A System Reactor Building Isolation RMP-RM-452 A & B < 100 mr/hr 2 B and Standby Gas Treatment Initiation Liquid Radwaste Discharge RMV-RM-2 (2) 1 C Isolation 3
Main Control Room Ventilation (RMV-RM-1) 4x10 CPM 1 D Isolation Mechanical Vacuum Pump Isolation RMP-RM-251 A-D 3 times normal full power 4 E background. Alarm at C 1.5 times normal full power background NOTES FOR TABLE 3.2.D
- 1. Action required when component operability is not assured.
A. (1) If radiation level exceeds 1.0 cf/sec (prior to 30 min. delay line) for a period greater than 15 con-secutive minutes, the off-gas isolation valve shall close and reactor shutdown shall be initiated immediately and the reactor placed in a cold shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
A. (2) Refer to Section 2.4.3.a.7 of the Environmental Technical Specifications.
B. Cease refueling operations, isolate secondary containment and start SBGT.
C. Refer to Sections 2.4.1.b of the Environmental Technical Specifications D. Refer to Section entitled " Additional Safety Related Plant Capabilities."
E. Refer to Section 3.2.d.5 and the requirements for Primary Containment Isolation on high main steam line radiation. Table 3.2.A
- 2. Trip setting to correspond to Specification 2.4.1.b.1 of the Environmental Technical Specifications.
COOPER NUCLEAR STATION TABLE 4.2.B (Page 4) ,
IIPCI TEST & CALIBRATION FREQUENCIES Instrument Item Item I.D. No. Functional Test Freq. Calibration Freq. Check l
- 1. Reactor Low Water Level NBI-LIS-72, A,B,C, & D, #3 Once/ Month (1) Once/3 Months Once/ Day
- 2. Reactor liigh Water Level NBI-LIS-101, (B & D #3) Once/ Month (1) Once/3 Months Once/ Day
- 3. liigh Drywell Pressure 14A - K5 A a B (7) (7) None 14A - K6 A & B (7) (7) None
- 4. IIPCI Turbine liigh Exhaust llPCI-PS-97 A & B Once/ Month (1) Once/3 Months None Press.
- 5. IIPCI Pump Low Suction Press. HPCI-PS-84-1 Once/ Month (1) Once/3 Months None
- 6. IIPCI Pump Low Discharge Flow HPCI-FS-78 Once/ Month (1) Once/3 Months None
- 7. IIPCI Low Steam Supply Press, llPCI-PS-68, A,B,C, & D Once/ Month (1) Once/3 Months None l 8. HPCI Steam Line High AP llPCI-dPIS-76 Once/ Month (1) Once/3 Months None llPCI-JPIS-77 Once/ Month (1) Once/3 Months None
- 9. IIPCI Steam Line Space High IIPCI-TS-101, A,B,C, & D Once/ Month (1) Once/Oper. Cycle None Temp. 102, 103, 104, llPCI-TS-125, 126, 127, 128
- RilR-TS-150,151,152,153,154, U 155,156,157,158,159,160,161
- 10. Emergency Cond. Stg. Tk. Low HPCI-LS-74 A & B Once/ Month (1) Once/3 Months None Level llPCI-LS-75 A & B Once/ Month (1) Once/3 Months None
- 11. Suppression Chamber liigh IIPCI-LS-91 A & B Once/ Month (1) . Once/3 Months None Water Level
- 12. IIPCI Gland Seal Cond. Ilotwell llPCI-LS-356 B Once/ Month (1) Once/3 Months None Level llPCI-LS-356 A Once/ Month (1) Once/3 Months None
- 13. IIPCI Control Oil Pressure Low HPCI-PS-2787-Il Once/ Month (1) Once/3 Months None llPCI-PS-2787-L Once/ Month (1) Once/3 Months None
- 14. Turbine Condition Supr. Alarm IIPCI-TDR-K14 Once/ Month (1) Once/Oper. Cycle None Actuation Timer
- 15. Pump Disch. Line Low Press. CM-PS-268 Once/3 Months Once/3 Months None
- 16. IIPCI Turbine Stop Valve Mon. HPCI-LMS-4 Once/ Month .N.A. None
- 17. Sup. Chamber IIPCI Suction V1v.HPCI-LMS-2 Once/ Month N.A. None
- 18. IIPCI Steam Line liigh AP HPCI-TDR-K33, once/ Month Once/Oper. Cycle None Actuation Tirer llPCI-TDR-K43 Once/ Month Once/Oper. Cycle None Logic (4)(6)
- 1. Logic Bus Power Monitor Once/6 Months N.A.
- 2. 1.lPCI Initiation Once/6 Months N.A.
- 3. IIPCI Turbine Trip Once/6 Months N.A.
4 COOPER NUCLEAR STATION TABLE 4.2.B (Page 6) ,
RCIC TEST & CALIBRATION FREQUENCIES Instrument Item Item 1.D. No. Functional Test Freq. Calibration Freq. Check [
Instrument Channels
- 1. Reactor liigh Water Level NBI-LIS-101 A & C, #2 Once/ Month (1) Once/3 Months once/ Day
- 2. Reactor Low Water Level 10A - K79 A & B 10A- Once/ Month (1) Once/3 Months Once/ Day K80 A & D
- 3. RCIC High Turbine Exhaust RCIC-PS-72, A & B Once/ Month (1) Once/3 Months None Press.
- 4. RCIC Low Pump Suction Press. RCIC-PS-67-1 Once/ Month (1) Once/3 Months None
- 5. RCIC Steam Line Space Excess RCIC-TS-79, A,B.C. & D Once/ Month (1) Once/Oper. Cycle None Temp. RCIC-TS-80, A,B,C, & D Once/ Month (1) Once/Oper. Cycle None RCIC-TS-81, A,B,C, & D Once/ Month (1) Once/Oper. Cycle None RCIC-TS-82, A,B,C, & D Once/ Month (1) Once/Oper. Cycle None
- 6. RCIC Steam Line Iligh AP RCIC-dPIS-83 Once/ Month (1) Once/3 Months None b RCIC-dPIS-84 Once/ Month (1) Once/3 Months None Y' 7. RCIC Steam Supply Press. Low RCIC-PS-87. A,B,C, & D Once/ Month (1) Once/3 Months None
- 8. RCIC Low Pump Disch. Flow RCIC-FIS-57 Once/ Month (1) Once/3 Months None l
- 9. Pump Disch. Line Low Pressure CM-PS-269 Once/3 Months Once/3 Months None
- 11. RCIC Steam Line High AP RCIC-TDR-K-12 Once/ Month Once/Oper. Cycle None Actuation Timer RCIC-TDR-K-32 Once/ Month Once/Oper. Cycle None Logic Systems (4)(6)
- 1. Logic Buss Power Monitor Once/6 Months N.A.
- 2. RCIC Initiation once/6 Months N.A.
- 3. Turbine Trip once/6 Months N.A.
- 4. RCIC Automatic Isolation Once/6 Months N.A.
TABLE 4.2.C SURVEILLANCE REQUIREMENTS FOR ROD WITHDRAWAL BLOCK INSTRUMENTATION ,
Functional Function Test Freq. Calibration Freq. Instrument Check APRM Upscale (Flow Bias) (1) (3) Once/3 Months Once/ Day APRM Upscale (Startup Mode) (1) (3) Once/3 Months Once/ Day APRM Downscale (1) (3) Once/3 Months Once/ Day APRM Inoperative (1) (3) N.A. Once/ Day RBM Upscale (Flow Bias) (1) (3) Once/6 Months Once/ Day RBM Downscale (1) (3) Once/6 Months once/ Day RBM Inoperative (1) (3) N.A. Once/ Day IRM Upscale (1) (2) (3) Once/3 Months Once/ Day IRM Downscale (1) (2) (3) Once/3 Months once/ Day IRM Detector Not Full In (2) (Once/oper- Once/Oper. Cycle (10) Once/ Day ating cycle)
IRM Inoperative (1) (2) (3) N.A. N.A.
SRM Upscale (1) (2) (3) Once/3 Months once/ Day SRM Downscale (1) (2) (3) Once/3 Months Once/ Day SRM Detector Not Full In (2) (Once/oper- Once/Oper. Cycle (10) N.A.
i ating cycle) 2$ SRM Inoperative (1) (2) (3) N.A. N.A.
' Once/Oper. Cycle N.A.
Flow Bias Comparator (1) (8)
Flow Bias Upscale (1) (8) Once/3 Months N.A.
Rod Block Logic (9) N.A. N.A.
RSCS Bypass (1) Once/3 Months N.A.
l SDV liigh Water Level Quarterly Once/Oper. Cycle N.A.
1 i
i
e 3.2 BASES (Cont'd)
Trip settings of <100 mr/hr for the monitors in the ventilation exhaust ducts are based upon initiating normal ventilation isolation and standby gas treat-ment system operation so that none of the activity released during the re-
) fueling accident leaves the Reactor Building via the normal ventilation path but rather all the activity is processed by the standby gas treatment system.
Flow transmitters are used to record the flow of liquid from the drywell sumps. An air sampling system is also provided to detect leakage inside the primary containment.
For each parameter monitored, as listed in Table 3.2.F there are two (2) channels of instrumentation. By comparing readings between the two (2) channels, a near continuous surveillance of instrument performance is available.
Any deviation in readings will initiate an early recalibration, there-by maintaining the quality of the instrument readings.
The recirculation pump trip has been added as a means of limiting the con-sequences of the unlikely occurrence of a failure to scram during an antici-pated transient. The response of the plant to this postulated event falls within the envelope of study events given in General Electric Company Topical Report, NED0-10349, dated March, 1971.
The liquid radwaste monitor assures that all liquid discharged to the discharge canal does not exceed the limits of Section 2.4.1.b of Environmental Technical Specifications. Upon sensing a high discharge level, an isolation signal is generated which closes the radwaste discharge valve. The' set point j is adjustable to coepensate for variable isotopic discharges and dilution .
flow rates.
The main control room ventilation isolation is provided by a detector monitoring the intake of the control room ventilation system. Automatic isolation of the normal supply and exhaust and the activation of the emergency filter system is provided by the radiation detector trip function at the predetermined trip level.
The mechanical vacuum pump isolation prevents the exhausting of radioactive gas thru the 1 minute holdup line upon receipt of a main steam line high radiation signal.
The operability of the reactor water level instrumentation in Tables 3/4.2.F ensures that sufficient information is available to monitor and ascess accident situations.
j t
, LIMITING CONDITION FOR OPERATION SURVEILLANCE REQUIREMENT i 3.3 REACTIVITY CONTROL 4.3 REACTIVITY CONTROL Applicability: Applicability:
Applies to the operational status Applies to the surveillance require-of the control rod system. ments to the control rod system.
Objective: Objective:
To assure the ability of the control To verify the ability of the control rod system to control reactivity, rod system to control reactivity.
Specification: Specification:
A. Reactivity Limitations, A. Reactivity Limitations
- 1. Reactivity margin - core loading 1. Reactivity margin - core loading A sufficient number of control r,ods Sufficient control rods shall be shall be operable so that the core withdrawn following a refueling outage could be made suberitical in the most when core alternations were performed reactive condition during the operating to demonstrate, with a margin of 0.38%
cycle with the strongest control rod Ak/k, that the core can be made sub-fully withdrawn and all other operable critical at any time in the subsequent control rods fully inserted, fuel cycle with the analytically de-termined strongest operable control rod fully withdrawn and all other operable rods fully inserted.
- 2. Reactivity margin - inoperable control 2. Reactivity margin inoperable control rods rods
- a. Control rods which cannot be moved a. Each partially or fully withdrawn with control rod drive pressure shall operable control rod shall be exer-be considered inoperable. If a par- cised one notch at least once each tially or fully withdrawn control rod week, when operating above 30% power.
drive cannot be moved with drive This test shall be performed at least or scram pressure the reactor shall once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when operating above be brought to a shutdown condition 30% power in the event power operation within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> unless investigation is continuing with three or more demonstrates that the cause of the inoperable control rods or in the event failure is not due to a failed con- power operation is continuing with one I
trol rod drive mechanism collet fully or partially withdrawn rod which housing. cannot be moved and for which control
- b. The control rod directional control r d drive mechanism damage has not been ruled out. The surveillance need not valve for inoperable control rods be completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if the i shall be disarmed electrically, l
number of inoperable rods has been
- c. Control rods with scram times reduced to less than three and if it greater than those permitted by has been demonstrated that control rod drive mechanism collet housing failure is not the cause of an immovable con-trol rod.
- b. A second licensed operator shall verify the conformance to Specification 3.3.A.
2.d before a rod may be bypassed in the Rod Sequence Control System.
- c. Once per week, check the status of the pressure and level alarms for each accumulator.
LIMITING CONDITION FOR OPERATION SURVEILLANCE REQUIREMENT O
3.3 (cont'd) 4.3 (cont'd)
B. Control Rods B. Control Rods
- 1. Each control rod shall be coupled to 1. The coupling integrity shall be its drive or completely inserted and verified for each withdrawn control the control rod directional control rod as follows:
valves disarmed electrically. This requirement does not apply in the a. When a rod is withdrawn the first refuel condition when the reactor is time after each refueling outage vented. Two or more control rod or af ter maintenance, observe dis-drives may be removed as long as cernible response of the nuclear Specification 3.10.A.5 or 3.10.A.6 instrumentation and rod position is met. indication. However, for initial rods when response is not discerni-ble, subsequent exercising of these rods after the reactor is above 30%
power shall be performed to verify instrumentation response,
- b. When the rod is fully withdrawn the first time after each refueling l outage or after maintenance, ob-serve that the drive does not go to the overtravel position.
i i
l l
l t
-94a-L
LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENT 3.3.B.3 (cont'd) 4.3.B.3.b (cont'd)
- e. If Specifications 3.3.B.3a 1) The correctness of the control through d cannot be met, the rod withdrawal sequence input to reactor shall not be started, the RWM computer shall be veri-or if the reactor is in the fied.
run or startup modes at less than 20% rated power, it shall 2) The RWM computer on line diag-be brought to a shutdown nostic test shall be sucess-condition immediately. fully performed.
- f. The sequence restraints imposed 3) Proper annunciation of the se-on the control rods may be re- lection error of at least one moved by the use of the individual out-of-sequence control rod in rod position bypass switches for each fully inserted group shall scram testing only those rods be verified.
which are fully withdrawn in the 100% to 50% rod density range. 4) The rod block function cf the RWM shall be verified by with-drawing the first rod as an out-of-sequence control rod no more than to the block point.
- c. When required, the presence of a second licensed operator or other qualified employee to
. verify the following of the correct rod program shall be verified.
- 4. Control rods shall not be with- 4. Prior to control rod withdrawal drawn for startup unless at least for startup, verify that at two source range channels have an least two source range channels observed count rate equal to or have an observed count rate of greater than three counts per at least three counts per second.
second.
- 5. During operation with limiting 5. When a limiting control rod control rod patterns, as deter- pattern exists an instrument mined by the designated quali- functional test of the RBM shall fled personnel, either: be performed prior to withdrawal of the designated rod (s).
- a. Both RBM channels shall be operable: or
(
, b. Control rod withdrawal shall be l
blocked: or
- c. The operating power level shall be limited so that the MCPR will remain above'the safety limit assuming a single error that results in complete with-drawal of any single operable control rod.
LIMkTINGCONDITIONFOROPERATION SURVEILLANCE REQUIREMENT 3.3 (cont'd) 4.3 (cont'd)
C. Scram Insertion Times C. Scram Insertion Times
- 1. The average scram insertion time, 1. After each refueling outage all based on the deenergization of the operable rods shall be scram time scram pilot valve solenoids as time tested from the fully withdrawn zero, of all operable control rods position with the nuclear system in the reactor power operation condi- pressure above 800 psig and the l tion shall be no greater than: requirements of Specification 3.3.B.3.a met. This testing shall
% Inserted From Avg. Scram Inser- be completed prior to exceeding Fully Withdrawn tion Times (sec) 40% power. Below 20% power, only 5 0.375 rods in those sequences (A and 12 20 0 . ')0 A or B and B which were 50 2.0 fdklywik$ drawn 2n)theregionfrom 90 3.50 100% rod density to 50% rod density shall be scram time tested. During all scram time testing below 20%
power, the Rod Worth Minimizer shall be operable or a second licensed operator or other qualified employee shall verify that the operator at the reactor console is following the control rod program.
- 2. The average of the scram insertion 2. At 16-week intervals,10% of the times for the three fastest control operable control rod drives shall be rods of all groups of four control scram timed above 800 psig. Whenever rods in a two-by-two array shall be such scram time measurements are made, no greater than: an evaluation shall be made to provide reasonable assurance that proper con-
% Inserted From Avg. Scram Inser- trol rod drive performance is being Fully Withdrawn tion Times (sec) maintained.
5 0.398
, 20 0.954 l 50 2.120 90 3.71 1
c 1
1 I
LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REOUIREMENTS 3.3.C (Cont'd.) 4.3.C (Cont'd.)
- 3. The maximum scram insertion time for 90% insertion of any operable control rod shall not exceed 7.00 seconds.
D. Reactivity Anomalies D. Reactivity Ancaalies At a specific steady state base condi- During the startup test program and tion of the reactor actual control rod startup following refueling outages, inventory will be periodically com- the critical rod configurations will pared to a normalized computer pre- be compared to the expected configura-diction of the inventory. If the tions at selected operating conditions.
difference between observid and pre- These comparisons will be used as base dicted rod inventory reaches the data for reactivity monitoring during equivalent of 1% Ak reactivity, the subsequent power operation through-reactor will be shut down until the out the fuel cycle. At specific power cause has been determined and correc- operating conditions,'the critical rod tive actions have been taken as configuration will be compared' to the appropriate. configuration expected based upon ap-propriately corrected past data. This E. Recirculation Pumps comparison will be made at least every full power month.
A recirculation pump shall not be started while the reactor is in natural circulation flow and reactor power is greater than 1% of rated ,
thermal power.
F. If Specifications 3.3.A through D above cannot be met, an orderly shutdewn shall be initiated and the reactor shall be in the Shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
- 1. The scram discharge volume (SDV) vent and drain valves shall be cycled and verified open at least once every 31 days and prior to reactor start-up.
- 2. The SDV vent and drain valves shall be verified to close within 30 sec-onds after receipt of a signal for control rod scram once per rerueling cycle.
- 3. SDV vent and drain valve operabil-ity shall be verified following any maintenance or modification to any portion (electrical or mechan-ical) of the SDV which may affect the operation of the vent and drain valves.
~
3.3 and 4.3 BASES A. Reactivity Limitation
- 1. The requirements for the control rod drive system have been identified by evaluating the need for reactivity control via control rod movement
. over the full spectrum of plant conditions and events. As discussed in subsection III.4 of the Final Safety Analysis Report, the control rod system design is intended to provide sufficient control of core reactivity that the core could be made suberitical with the strongest rod fully withdrawr.. This reactivity characteristic has been a basic assumption in the analysis of plant performance. Compliance with this requirement can be demonstrated conveniently only at the time of initial fuel loading or refueling. Therefore, the demonstration must be such
, that it will apply to the entire subsequent fuel cycle. The demonstra-tion shall be performed with the reactor core in the cold, xenon-free condition and will show that the reactor is suberitical by at least R + 0.38% Ak/k with the analytically determined strongest cor*rol rod fully withdrawn.
The value of "R", in units of %Ak/k, is the amount by which the core reactivity, in the most reactive condition at any time in the subse-quent operating cycle, is calculated to be greater than at the time of the demonstration. "R", therefore, is the difference between the calculated value of maximum core reactivity during the operating cycle and the calculated beginning-of-life core reactivity. The value of "R" must be positive or zero and must be determined for each fuel cycle.
The demonstration is performed with a control rod which is calculated to be the strongest rod. In determining this " analytically strongest" rod, it is ast.umed that every fuel assembly of the same type has identical material properties. In the actual core, however, the control cell material properties vary within allowed manufacturing colorsnces, and the secongest rod is determined by a combination of the control cell geometry and local k=. Therefore, an additional margin is included in the shutdown margin test to account for the fact that the rod used for the demonstration (the " analytically strongest") is not necessarily
( the strongest rod in the core. Studies have been made which compare l
experimental criticals with calculated criticals. These studies have shown that actual criticals can be predicted within a given tolerance l band. For gadolinia cores the additional margin required due to control cell material manufacturing tolerances and calculational uncertainties has experimentally been determined to be 0.38% Ak/k. When this additional margin is demonstrated, it assures that the reactivity control requirement is met.
, 2. Reactivity margin - inoperable control rods.
Specification 3.3.A.2 requires that a rod be taken out of service if it l
i i
3.3.and 4.3 BASES (cont'd.)
cannot be moved with drive pressure. If the rod is fully inserted and then disarmed electrically, it is in a safe' position of maximum con-tribution to shutdown reactivity. If it is disarmed electrically in a non-fully inserted position, that position shall be consistent with the shutdown reactivity limitation stated in Specification 3.3.A.l.
This assures that the core can be shutdown at all times with the remaining control rods assuming the strongest operable control rod does not insert. An allowable pattern for control rods valved out of service, which shall meet this Specification, will be determined and made available to the operator.
In order to perform shutdown margin and control rod drive scram time tests subsequent to any fuel loading operation as required by the Technical Specifications, the relaxation of the following Rod Sequence Control System restraints is required: (a) The sequence restraints imposed on the control-rods may be removed by the use of the individual rod position bypass switches for scram testing only those rods which are fully withdrawn in the 100% to 50% rod density range. (b) Verify that subsequent to the use of the rod position bypass switches rod movement in the 50% rod density to preset power level range is restricted to the single notch mode.
If damage within the control rod drive mechanism and in particular, cracks in drive internal housings, cannot be ruled out, then a generic problem affecting a number of drives cannot be ruled out. Circumferential cracks resulting from stress assisted intergranular corrosion have occured in the collet housing of drives at several BWRs. This type of cracking could occur in a number of drives and if the cracks propagated until severance of the collet housing occurred, scram could be prevented in the affected' rods. Limiting the period of operation with a potentially severed collet housing and requiring increased surveillance af ter detecting one stuck rod will assure that the reactor will not be operated with a large number of rods with failed collet housings.
B. Control Rod
- 1. Control rod drop accidents as discussed in the FSAR can lead to significant core damage. If coupling integrity is maintained, the possibility of a rod dropout accident is eliminated. The overtravel position feature provides a positive check as only uncoupled drives may reach this position. Neutron instrumentation response to rod movement provides a verification that the rod is following its drive.
Absence of such response to drive movement could indicate an uncoupled condition. Rod position indication is required for proper function of the rod sequence control system and the rod worth minimizer (RWM).
-100-
- 2. The control rod housing support restricts the outward movement of a
,~
control rod to less than 3 inches in the extremely remote event of a housing failure. The amount of reactivity which could be edded by this small amount of rod withdrawal, which is less than a normal single withdrawal. increment, will not contribute to any damage to the primary coolant system. The design basis is given in subsection III.8.2 of the FSAR and the safety evaluation is given in subsection VIII.8.4. This support is not required if the reactor coolant c . tem is at atmospheric pressure since there would then be no driving force to rapidly eject a drive housing. Additionally, the support is not required if all control rods are fully inserted and if an adequate shutdown margin with one control rod withdrawn has been demonstrated, since the reactor would remain subcritical even in the event of complete ejection of the ,
strongest control rod.
- 3. The Rod Worth Minimizer (PWM) and the Rod Sequence Control System (RSCS) restrict withdrawals and insertions of control rods to prespecified sequences. These sequences are established such that the drop of any in-sequence control rod or control rod segment (i.e., one or l more notches) would not cause the reactor to sustain a power excursion result-ing in a peak fuel enthalpy in excess of 280 cal./gm. An enthalpy of 280 cal./gm. is well below the level at which rapid fuel dispersal could occur (i.e., 425 cal./gm.). Primary system damage in this accident is not possible unless a significant amount of fuel is rapidly dispersed.
Ref. Subsections III.6.6, VIII 7.4.5, and XIV.6.2 of the FSAR and Reference 1.
In performing the function described above, the RWM and RSCS are not required to impose any restrictions at core power levels in excess of 20% of rated. Material in the cited references shows that it is impossible to reach 280 calories per gram in the event of a control rod drop occurring at power greater than 20%, regardless of the rod pattern. This is true for all normal and abnormal patterns including those which maximize the individual control rod worth.
At power levels below 20% of rated, abnormal control rod patterns could produce rod worths high enouFh to be of concern relative to the 280 calories per gram rod drop limit. In this range the RWM and the RSCS constrain the control rod sequences and patterns to those which involve only acceptable rod worths.
The Rod Worth Minimizer and the Rod Sequence Control System provide automatic supervision to assure that out of sequere ? control rods will not be withdrawn or inserted; i.e., it limits >perator deviations from planned withdrawal sequences. They serve as a backup to pro-cedural control on control rod sequences, which limit the maximum reactivity worth of control rods. In the event that the Rod Worth Minimizer is out of service, when required, a second licensed operator or other qualified technical plant employee whose qualifi-cations have been reviewed by the NRC can manually fulfill the control rod pattern conformance functions of this system. In this case, the RSCS is hacked up by independent procedural control to assure con-formance.
-101-
The functions of the RbH and RSCS make it unnecessary to, specify a license limit on rod worth to preclude unacceptable consequences in the event of a control rod drop. At low powers, below 20%, these devices force adherence to acceptable rod patterns. Above 20% of rated power, no constraint on rod pattern is required to assure that rod drop accident consequences are acceptable. Control rod pattern constraints above 20% of rated power are imposed by power distribu-tion requirements as defined in Section 3.3.B.5 of these Technical Specifications. Power level for automatic cutout of the RSCS function is sensed by first stage turbine pressure. Because the instrument has an instrument error of + 2% of full power, the nominal instrument setting is 22% of rated power. Power level for automatic cutout of the RWM function is sensed by feedwater and steam flow and is set nominally at 30% of rated power to be consistent with the RSCS setting.
Functional testing of the RbH prior to the start of control rod,,
withdrawal at startup, and prior to attaining 20% rated thermal power during rod insertion while shutting down, will ensure reliable opera-tion and minimize the probability of the rod drop accident.
The RSCS can be functionally tested prior to control rod withdrawal for reactor startup. By selecting, for example, A g and attempting towithdraw,byonenotch,arodorallrodsineacikothergroup,it can be determined that the A group is exclusive. By bypassing to full-out all A g rods,seleckkngA and attempting to withdraw, by onenotch,aroborallrodsingroupB,theA 34 group is determined exclusive. ThesameprocedurecanberepeatedhortheBgroups.
Af ter 50% of the control rods have been withdrawn (e.g., groups A g and A34), it isdemonstratedthattheGroupNotchmadeforthecon$rol drives is enforced. This demonstration is made by performing the hardware functional test sequence. The Group Notch restraints are automatically removed above 20% power.
During reactor shutdown, similar surveillance checks shall be made with regard to rod group availability as soon as automatic initiation of the RSCS occurs and subsequently at appropriate stages of the control rod insertion.
- 4. The Source Range Monitor (SRM) system performs no automatic safety system function; i.e., it has no scram function. It does provide the
- operator with a visual indication of neutron level. The consequences of reactivity accidents are functions of the initial neutron flux. The requirements of at least 3 counts per second assures that any trgnsient, should it occur, begins at or above the initial value I
of 10 % of rated power used in the analyses of transients cold con-ditions. One operable SRM channel would be adequate to monitor the approach to criticality using homogeneous patterns of scattered control rod withdrawal. A minimum of two operable SRM's are provided as an added conservatism.
-101a-
, 3.3 and 4.3 BASES: (Cont'd)
- 5. The Rod Block Monitor (RBM) is designed to automatically prevent fuel damage in the event of erroneous rod withdrawal from locations of high power density during high power level operation. Two channels are pro-vided, and one of these may be bypassed from the console for maintenance and/or testing. Tripping of one of the channels will block erroneous rod withdrawal soon enough to prevent fuel damage. This sytem backs up the operator who withdraws control rods according to written se-quences. The specified restrictions with one channel out of service conservatively assure that fuel damage will not occur due to rod with-drawal errors when this condition exists.
A limiting control rod pattern is a pattern which results in the core being on a thermal hydraulic limit (i.e., MCPR = 1.07, and LHGR = as defined in 1.0.A.4). During use of such patterns, it is judged that testing of the RBM system prior to withdrawal of such rods to assure its operability will assure that improper withdrawal does not occur.
It is the responsibility of the Reactor Engineer to identify these limiting patterns and the designated rods either when the patterns are initially established or as they develop due to the occurrence of inoperable control rods in other than limiting patterns. Other person-nel qualified to perform this function may be designated by the station superintendent.
C. Scram Insertion Times The control rod system is designed to bring the reactor suberitical at a rate fast enough to prevent fuel damage; i.e., to prevent the MCPR from becoming less than the safety limit. The limiting power transient is defined in Reference 3. Analysis of this transient shows that the negative reactivity rates resulting from the scram provide the required protection, and MCPR remains greater than the safety limit.
I The surveillance requirement for scram testing of all the control rods after each refueling outage and 10% of the control rods at 16-week intervals is adequate for determining the operability of the control rod system yet is not so frequent as to cause excessive wear on the control rod system components.
The numerical values assigned to the predicted scram performance are based on the analysis of data from other BWR's with control rod drives the same as those on Cooper Nuclear Station.
l l The occurrence of scram times within the limits, but significantly longer than the average, should be viewed as an indication of a systematic problem with control rod drives.
In the analytical treatment of the transients which are assumed to scram on high neutron flux, 290 milliseconds are allowed between a neutron sensor reaching the scram point and start of motion of the control rods. This is adequate and conservative when compared to the typical time delay of about 210 milliseconds estimated from scram test results. Approximately the first 90 milliseconds of each of these time l intervals result from the sensor and circuit delays; at this point, the pilot scram solenoid deenergizes. Approximately 120 milliseconds later, l
i
-102-
3.3'end 4.3 BASES: (Cont'd) the control rod motion is estimated to actually begin. However, 200 milliseconds is conservatively assumed for this time interval in the transient analyses and this is also included in the allowable scram insertion times of Specification 3.3.C. The time to deenergize the pilot valve scram solenoid is measured during the calibration tests required by Specification 4.1. l D. Reactivity Anomalies During each fuel cycle excess operative reactivity varies as fuel depletes and as any burnable poison in supplementary control is burned. The magni-tude of this excess reactivity may be inferred from the critical rod con-figuration. As fuel burnup progresses, anomalous behavior in the excess reactivity may be detected by comparison of the critical rod pattern at selected base states to the predicted rod inventory at that state. Power operating base conditions provide the most sensitive and directly inter- -
pretable data relative to core reactivity. Furthermore, using power operating base conditions permits frequent reactivity comparisons.
Requiring a reactivity comparison at the specified frequency assures that a comparison will be made before the core reactivity change exceeds 1% Ak. Deviations in core reactivity greater than 1% Ak are not expected and require thorough evaluation. One percent reactivity limit is con-sidered safe since an insertion of the reactivity into the core would not lead to transients exceeding design conditions of the reactor system.
E. Recirculation Pumps Until analyses are submitted for review and approval by the NRC which prove that recirculation pump startup from natural circulation does not cause a reactivity insertion transient in excess of the most severe coolant flow increase currently analyzed, Specification 3.3.E prevents starting recirculation pumps while the reactor is in natural circulation above 1%
of rated thermal power.
G. Scram Discharge Volume To ensure the Scram Discharge Volume (SDV) does not fill with water, the vent and drain valves shall be verified open at least once every 31 days.
(
This is to preclude establishing a water inventory, which if sufficiently large, could result in slow scram times or only a partial control rod insertion.
The vent and drain valves shut on a scram signal thus providing a j contained volume (SDV) capable of receiving the full volume of water
! discharged by the control rod drives at any reactor vessel pressure.
Following a scram the SDV is discharged into the reactor building drain system.
REFERENCES
- 1. Licensing Topical Report GE-BWR Generic Reload Fuel Application, NEDE-24011-P, (most current approved submittal).
- 2. " Supplemental Reload Licensing Submittal for Cooper Nuclear Station Unit 1,"
(applicable reload document). g 1
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e
" INTENTIONALLY LEFT BLANK" i
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-104, 105, 106-l E - --- . . . . . __ _ _ _ __ ._
LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.4 STANDBY LIQUID CONTROL SYSTEM 4.4 STANDBY LIQUID CONTROL SYSTEM Applicability: Applicability:
Applies to the operating status of Applies to the surveillance require-the Standby Liquid Control System. ments of the Standby Liquid Control System.
Objective: Objective:
To assure the availability of a sys- To verify the operability of the tem with the capability to shutdown Standby Liquid Control System.
the reactor and maintain the shutdown condition without the use of control rods.
Specification: Specification:
A. Normal System Availability A. Normal System Availability During periods when fuel is in the The operability of the Standby Liquid reactor and prior to startup from a Control System shall be shown by the Cold Condition, the Standby Liquid performance of the following tests:
Control System shall be operable, except as specified in 3.4.B below. 1. At least once per month each pump This system need not be operable loop shall be tested for operability when the reactor is in the Cold by recirculating demineralized water Condition and all control rods are to the test tank.
fully inserted and Specification 3.3.A is met. 2. At least once during each operating cycle:
- a. Check that the settings of the system relief valves are 1400 < P < 1680 psig and the valves will reset at P >1215 psig.
- b. Manually initiate the system, except l explosive valves, and pump boron solution from the Standby Liquid Control System through the recirculation path.
. Minimum pump flow rate of 38.2 gpm
! against a system head of 1215 psig l
shall be verified. After pumping boron solution the system will be flushed with demineralized water.
- c. Manually initiate one of the Standby Liquid Control System Pumps and
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LIlf1 TING CONDITIONS FOR~ 0PERATION SURVEILLANCE REQUIREMENTS 3.4 4.4.A.2.c (Cont'd.)
pump demineralized water into the reactor vessel from the test tank.
These tests check the actuation of the explosive charge of the tested 1 cop, proper operation of the valves, and pump operability.
The replacement charges to be installed will be selected from the same manufactured batch as the. tested charge.
- d. Both systems, including both ex-plosive valves, shall be tested in
' the course of two operating cycles.
B. Operation with Inoperable Components: B. Surveillance with Inoperable Com-ponents:
- 1. From and after the date that a redun-l dant component is made or found to 1. When a component is found to be inop-be inoperable, Specification 3.4.A.1 erable, its redundant component i shall be considered fulfilled and shall be demonstrated to be operable continued operation permitted pro- immediately and daily thereafter vided that the component is returned until the inoperable component is to an operable condition within repaired.
seven days.
C. Sodium Pentaborate Solution C. Sodium Pentaborate Solution 1 At all times when the Standby Liquid The following tests shall be performed Control System is required to be op- to verify the availability of the erable the following conditions shall Liquid Control Solution:
he met:
- 1. The net volume versus concentration 1. Volume: Check and record at least once-of the Liquid Control Solution in per day.
the liquid control tank shall be main-tained as required in Figure 3.4.1.
- 2. The temperature of the liquid control 2. Temperature: Check and record at least solution shall be maintained above the once per day.
curve shown in Figure 3.4.2.
- 3. Concentration: Check and record at least once per month. Also check con-4 centration anytime water or boron is
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LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.5.A (cont'd.) 4.5.A (cont'd.)
- 2. From and after the date that one of 2. When it is determined that one core the core spray subsystems is made or spray subsystem is inoperable, the found to be inoperable for any reason, operable core spray subsystem, the continued reactor operation is per- LPCI subsystem and the diesel gener-missible during the succeeding seven ators shall be demonstrated to be days provided that during such seven operable immediately. The operable days all active components of the core spray subsystem shall be demon-other core spray subsystem and active strated to be operable daily there-components of the LPCI subsystem and after.
the diesel generators are operable.
(1) prior to reactor startup from a Item Frequency Cold Condition, except as specified in 3.5.F.7, or a. Simulated Auto- Once/ Operating matic Actuation Cycle (2) when there is irradiated Test fuel in the vessel and when the reactor vessel pressure b. Pump Operability Once/ month is greater than atmospheric prccsure, except as specified c. Motor Operated Once/ month in 3.5.A.4 and 3.5.A.5 below. Valve Operability
- d. Pump Flow Rate once/3 months During single pump LPCI, each RHR pump shall deliver at least 7700 GPM but no more than 8400 GPM against a system head equivalent to a reactor vessel pressure of 20 psid above dry-well pressure with water level below the jet pumps. At the same condi-tions, two pump LPCI flow shall be at least 15,000 GPM.
! e. Recirculation pump discharge valves shall be tested each refueling outage to verify full open to full closed in 20 < t < 26 seconds.
- 4. From and after the date that one of 4. When it is determined that one of the i the RHR (LPCI) pumps is made or found RHR (LPCI) pumps is inoperable at a to be inoperable for any reason, con- time when it is required to be operating l tinued reactor operation is permissi- the remaining active components of the
! ble only during the succeeding thirty LPCI subsystems, the containment cool-j days provided that during such thirty ing subsystem, both core spray systems l days the remaining active components and the diesel generators shall be l
- of the LPCI subsystem and all active demonstrated to be operable immediately components of both core spray sub- and the operable LPCI pumps daily systems and the diesel generators are thereafter.
7 operable.
[
(
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LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENT 3.5.D (cont'd.) 4.5.D (cont'd.)
Item Frequency
- b. Pump Operability Once/ month
- c. Motor Operated Once/ month Valve Operability
- d. Flow Rate at Once/3 months approximately 1000 psig Steam Pressure
- e. Flow Rate at Once/ operating approximately 150 cycle psig Steam Pressure The RCIC pump shall be demonstrated to be capable of delivering at least 400 gpm for a system head corresponding to a reactor pressure of 1000 to 150 psig.
- 2. From and after the date that the 2. When it is determined that the RCIC RCICS is made or found to be in- subsystem is inoperable, the HPCIS operable for any reason, continued shall be demonstrated to be operable reactor power operation is per- immediately and weekly thereafter.
missible only during the succeeding seven days provided that during such seven days the HPCIS is op-erable.
- 3. With the surveillance requirements of 4.5.D not performed at the required intervals due to reactor
- shutdown, a reactor startup may
! be conducted provided the appropriate surveillance is performed within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of achieving 150 psig reactor steam pressure.
- 4. If the requirements of 3.5.D 1 & 2 cannot be met, an orderly shutdown shall be initiated and the reactor l pressure shall be reduced to 113 psig or less within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
E. Automatic Depressurization System (ADS) E. Automatic Depressurization System (ADS)
- 1. The Automatic Depressurization Sub- 1. During each operating cycle the follow-system shall be operable whenever ing tests shall be performed on the l there is irradiated fuel in the ADS:
i reactor vessel and the reactor l pressure is greater than 113 psig A simulated automatic actuation test and prior to a startup from a Cold shall be performed prior to startup Condition, except as specified in after each refueling outage.
3.5.E.2 and 3.5.E.3 below.
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LIMITING CONDT710NS FOR OPERATION SURVEILLANCE REQUIREMENT 3.5.F (cont'd) 4.5.F (cont'd)
- h. A special flange, capable of sealing a leaking control rod housing, is available for immediate use,
- i. The control rod housing is covered with the special flange following the removal of the control rod drive.
- j. No work is being performed in the vessel while the housing is open.
- 6. During a refueling outage, refueling operation may continue with one core spray system or the LPCI system in- I operable for a period of thirty days.
- 7. The LPCI System is required to be operable while performing training startups at atmospheric pressure at v
power le'els less than 1% of rated -
thermal power with the exception that the RHR system may be aligned in the shutdown cooling mode rather than ,
the LPCI mode.
G. Maintenance of Filled Discharge Pipe G. Maintenance of Filled Discharge Pipe Whenever core spray subsystems, LPCI The following surveillance requirements subsystem, HPCI, or RCIC are required shall be adhered to, to assure that the to be operable, the discharge piping discharge piping of the core spray from the pump discharge of these sys- subsystems, LPCI subsystem, HPCI and' tems to the last block valve shall RCIC are filled:
be filled.
- 1. Whenever the Core Spray, LPCI, HPCI or RCIC systems are made operable, the discharge piping shall be vented from the high point of the system and water flow observed initially and on a monthly basis.
- 2. The pressure switches which monitor .
the LPCI, core spray, HPCI and RCIC lines to ensure they are full shall be functionally tested and calibrated every three months.
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3.9 BASES A. Core Spray and LPCI Subsystems This specification assures that adequate emergency cooling capability is available whenever irradiated fuel is in the reactor vessel.
I The limiting conditions of operation in Specifications 3.5.A.1 through 3.5.A.6 specify the combinations of operable subsystems to assure the availability of the minimum required cooling systems. During reactor shutdown when the l residual heat removal system is realigned from LPCI to the shutdown cooling mode, the LPCI System is considered operable.
The core spray system is designed to provide emergency cooling to the core by spraying in the event of a loss-of-coolant accident. This system functions in combination with the LPCI system to prevent excessive fuel clad temperature.
The LPCI subsystem is designed to provide emergency cooling to the core by flooding in the event of a loss-of-coolant accident. This system functions in combination with the core spray system to prevent excessive fuel clad temperature. The LPCI subsystem and the core spray subsystem provide ade-quate cooling for break areas of approximately 0.2 square feet up to and including the double-ended recirculation line break without assistance from the high pressure emergency core cooling subsystems.
The allowable repair times are established so that the average risk rate for repair would be no greater than the basic risk rate. The method and concept are described in reference (1). Using the results developed in this reference, the repair period is found to be 1/2 the test interval. This assumes that the (1) Jacobs, I.M., " Guidelines for Determining Safe Test Intervals and Repair Times for Engineered Safeguards", General Electric Co. A.P.E.D., April, 1969 (APED 5736).
t I
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3.5.A BASES (cont'd.)
core spray subsystems and LPCI e.nstitute a 1 out of 3 system; however, the combined effect of the two systems to limit excessive clad temperatures must also be considered. The test interval specified in Specification 4.5 is 1 month. Should a subsystem fail, a daily test is called for on the remaining systems to ensure that they will function.
Should one core spray subsystem become inoperable, the remaining core spray and the LPCI system are available should the need for core cooling arise. To assure that the remaining core spray and LPCI subsystems and the diesel generators are available, they are demonstrated to be operable immediately. This demonstration includes a manual initiation of the pumps and associated valves and diesel generators.
Should the loss of one LPCI pump occur, a nearly full complement of core and containment cooling equipment is available. Three LPCI pumps in conjunction with the core spray subsystem will perform the core cooling function. Because of the availability of the majority of the core cooling equipment, which will be demonstrated to be operable, a thirty day repair period is justified. If the LPCI subsystem is not available, at least 1 LPCI pump must be available to fulfill the containment cooling function. The 7 day repair period is set on this basis.
B. Containment Cooling Subsystem
(
The containment cooling subsystem for CNS consists of two loops each with 2 RHR (LPCI) pumps serving one side of the RHR heat exchanger and two RHR Service Water Booster Pumps serving the other side. The design of the loops is predicted upon the use of one RHR Service Water Booster Pump and one EHR heat exchanger, for heat removal after a design basis accident. Thus, there are ample spares for margin above design conditions. Loss of margin should be avoided and the equipment maintained in a state of operation. So a 30 day out-of-service time is chosen for this ecuipment. If one loop is out-of-service reactor operation is permissible for seven days with daily testing of the operable loop after testing the appropriate diesel. generator.
With components or subsystems out-of-service, overall core and containment cooling reliability is maintained by demonstrating the operability of the re-maining cooling equipment. The degree of operability to be demonstrated depends l
j on the nature of the reason for the out-of-service equipment. For routine out-of-service periods caused by preventive maintenance, etc. , the pump and valve operability checks will be performed to demonstrate operability of the remaining components. However, if a failure, design deficiency, etc., caused the out-of-service period, then the demonstration of operability should be thorough enough to assure that a similar problem does not exist on the remaining com-ponents. For example, if an out-of-service period were caused by failure of a pump to deliver rated capacity, the other pumps of this type might be sub-l jected to a capacity test. In any event, surveillance procedures, as required l by Section 6 of these specifications, detail the required extent of testing.
The pump capacity test is a comparison of measured pump performance parameters l
l l -125-l
3.5.B BASES (cont'd.) l to shop performance tests. Tests during normal operation will be performed by measuring the flow and/or the pump discharge pressure. These parameters and its power requirement will be used to establish flow at that pressure.
C. HPCI The limiting conditions for operating the HPCI System are derived from the Station Nuclear Safety Operational Analysis (Appendix G) and a detailed func-tional analysis of the HPCI System (Section VI.).
The HPCIS is provided to assure that the reactor core is adequately cooled to limit fuel clad temperature in the event of a small break in the nuclear system and loss-of-coolant which does not result in rapid depressurization of the reactor vessel. The HPCIS permits the reactor to be shut down while main-taining sufficient reactor vessel water level inventory until the vessel is depressurized. The HPCIS continues to operate until reactor vessel pressure is below the pressure at which LPCI operation or Core Spray System operation maintains core cooling.
The capacity of the system is selected to provide this required core cooling.
The HPCI pump is designed to pump 4250 gpm at reactor pressures between 1120 and 150 psig. Two sources of water are available. Initially, demineralized water from the emergency condensate storage tank is used instead of injecting water from the suppression pool into the reactor.
When the HPCI System begins operation, the reactor depressurizes more rapidly than would occur if HPCI was not initiated due to the condensation of steam by the cold fluid pumped into the reactor vessel by the HP'CI System. As the reac-tor vessel pressure continues to dscrease, the HPCI flow momentarily reaches equilibrium with the flow through the break. Continued depressurization causes the break flow to decrease below the HPCI flow and the liquid inventory begins to rise. This type of response is typical of the small breaks. The core never uncovers and is continuously cooled throughout the transient so that no core damage of any kind occurs for breaks that lie within the capacity range of the HPCI.
The analysis in the FSAR, Appendix G, shows that the ADS provides a single failure proof path for depressurizction for postulated transients and accidents.
The RCIC serves as an alternate to the HPCI only for decay heat removal when feed water is lost. Considering the HPCI and the ADS plus RCIC as redundant paths, reference (1) methods would give an estimated allowable repair time of l
15 days based on the one month testing frequency. However, a maximum allowable repair time of 7 days is selected for conservatism. The HPCI and RCIC as well as all other Core Standby Cooling Systems must be operable when starting up from a Cold Condition. It is realized that the HPCI is not designed to operate until reactor pressure exceeds 150 psig and is automatically isolated before the reactor pressure decreases below 100 psig. It is the intent of this speci-
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"LEFT BLANK INTENTIONALLY" i
I l
l l
l
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4.5 BASES Core and Containment Cooling Systems Surveillance Frequencies The testing interval for the core and containment cooling systems is based on industry practice, quantitative reliability analysis, judgement and practicality.
The core cooling systems have not been designed to be fully testable during operation. For example, in the case of the HPCI, automatic initiation during power operation would result in pumping cold water into the reactor vessel, which is not desirable. Complete ADS testing during power operation causes an undesirable loss-of-coolant inventory. To increase the availability of the core and containment cooling systems, the components which make up the system; i.e., instrumentation, pumps, valves, etc., are tested frequently.
The pumps and motor operated injection valves are also tested each month to assure their operability. A simulated automatic actuation test once each cycle combined with frequent tests of the pumps and injection valves is deemed to be adequate testing of these systems.
When components and subsystems are out-of-service, overall core and contain-ment cooling reliability is maintained by demonstrating the operability of the remaining equipment. The degree of operability to be demonstrated depends on the nature of the reason for the out-of-service equipment. For routine out-of-service periods caused bv preventative maintenance, etc., the pump and valve operability checks will be performed to demonstrate operability of the remaining components. Howevet, if r failure or design deficiency caused the outage, then the demonstration of operability should be thorough enough to assure that a l generic problen does not exist. For example, if an out-of-service period were caused by failure of a pump to deliver rated capacity due to a design defi-ciency, the other pumps of this type might be subjected to a flow rate test in addition to the operability checks.
Redundant operable components are subjected to increased testing during equipment out-of-service times. This adds further conservatism and increases assurance that adequate cooling is available should the need arise.
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LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.6 Primary System Boundary 4.6 Primary System Boundary Applicability: Applicability:
Applies to the operating status of Applies to the periodic examination the reactor coolant system. and testing requirements for the reactor cooling system.
Objective: Objective:
To assure the integrity and safe op- To determine the condition of the cration of the reactor coolant sys- reactor coolant system and the tem. operation of the safety devices related to it.
Specification: Specification:
A. Thermal and Pressurization Limitations A. Thermal and Pressurization Limitations
- 1. The average rate of reactor coolant 1. During heatups and cooldowns, the temperature change during normal heat- following temperatures shall be per-up or cooldown shall not axceed manently logged at least every 15 l 100*F/hr when averaged over a one- minutes until the difference between hour period, any two readings taken over a 45 minute period is less than 50*F.
- a. Bottom head drain.
- b. Recirculation loops A and B.
- 2. During operation where the core is 2. Reactor vessel temperature and reactor critical or during heatup by non- coolant pressure shall be permanently nuclear means, the reactor vessel logged at least every 15 minutes when-metal and fluid temperatures shall ever the shell temperature is below be at or above the temperatures shown 220*F and the reactor vessel is not on the limiting curves of Fig- vented.
ures 3.6.1.a or 3.6.1.b where the curve for the beltline is increased by the expected shift in RT f#*
NDT Figure 3.6.1.
- 3. The reactor vessel metal temperatures 3. Test specimens of the reactor vessel during inservice hydrostatic or leak base, weld and heat affected zone metal testing shall be at or above the tem- subjected to the highest fluence of peratures shown on the limiting curves greater than 1 Mev neutrons shall be of Figure 3.6.2 where the curve for the installed in the reactor vessel adjacent beltline is increated by the expected to the vessel wall at the core midplane shift in RT NDT fr m Figure 3.6.1. level. The specimens and sample program shall conform to ASTM E 185-73 to the degree possible.
Selected neutron flux specimens shall be removed during the first refueling
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LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.6.A (cont'd.) 4.6.A (cont'd.)
outage and tested to experimentally verify or adjust the calculated values of integrated neutron flux that are used to determine the RT NDTT for Figure 3.6.1.
If the adjusted reference temperature established in accordance with App. G of Section III of the Code 1972 Summer Addendum does not exceed 100 F over l the li,fe of the vessel, the withdrawal schedule should be as follows:
First Capsule: 1/4 service life Second Capsale: 3/4 service life Third capsule: Standby In the event the surveillance specimens exhibit at 1/4 of the vessel's service life, a shift of the charpy V-notch frac-ture energy curve greater than predicted l by test data the remaining withdrawal schedule shall be modified as follows:
Second Capsule: 1/2 service life Third Capsule: Standby
- 4. The Reactor vessel head bolting 4. When the reactor vessel head bolting studs shall not be under tension studs are tensioned and the reactor is unless the temperature of the vessel in a Cold Condition, the reactor vessel head flange and the head is greater shell temperature immediately below than 80 F. the head flange shall be permanently recorded.
- 5. The pump in an idle recirculation loop 5. Prior to and during startup of an shall not be started unless the temp- idle recirculation loop, the temperature' eratures of the coolant within the of the reactor coolant in the operating idle and operating recirculation loops and idle loops shall be permanently are within 50 F of each other, logged.
- 6. The reactor recirculation pumps shall 6. Prior to starting a recirculation pump, l not be started unless the coolant the reactor coolant temperatures in temperatures between the dome and the the dome and in the bottom head drain bottom head drain are within 145 F. shall be compared and permanently logged.
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LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUTREMENTS 3.6 (cont'd.) 4.6 (cont'd.)
B. Coolant Chemistry B. Coolant Chemistry
- 1. The reactor coolant radioactivity 1.a. A sample of reactor coolant shall be concentration shall be maintained collected and analyzed for gross within the following limits: gamma activity as Zollows:
- a. Whenever the reactor is critical, 1. At least every 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> whenever the reactor coolant activity shall the reactor is critical, not exceed the equilibrium value of 3.1 pCi/gm of dose equivalent I-131. 2. Prior to reactor startup.
- b. The limit of 3.6.B.1.a above may be 3. In the STARTUP mode, at 4-hour exceeded by a factor of 10 or less intervals following a power for a maximum of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> following change exceeding 5% of rated power transients. The reactor shall power in one hour or less, not be operated more than 5% of its annual power operation under this 4. In the RUN mode, at 4-hour inter-exception. vals followed a power change exceeding 20% of rated power
- c. If the iodine concentration in the in one hour or less.
coolant exceeds the equilibrium limit by a factor greater than 10, the 5. At 4-hour intervals following reactor shall be shutdown in an an off-gas activity increase of orderly manner and in the cold shut- 10,000 uCi/see measured at the down condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and SJAE.
the steam line isolation valves shall be closed. 6. At 4-hour intervals whenever measurements indicate the equilibrium iodine concentration limit of 3.6.B.1 is exceeded, until a stable value below the equilibrium limit is established.
The samples required in 4.6.B.1.a.3, 4, and 5 shall be collected for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> but may be discontinued if the reactor coolant concentration is shown to be less than 1% of the equilibrium value specified in 3.6.B.1 or when a stable iodine con-centration below the limiting equilibrium value is established.
Whereas a single measurement may be used to show an activity level below 1%, at least 3 consecutive samples with the last 2 yielding activities below the equilibrium value are required to establish a stable concentration below the equilibrium limit.
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LIh!ITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.6.B. (cont'd) 4.6 (cont'd)
- 2. Prior to startup and during the b. If the gross activity counts of a operating of the reactor up to sample indicate an activity con-10% of rated power, and during centration above 3.1 pCi/gm of hot standby, the reactor coolant dose equivalent I-131, an isotopic shall not exceed the following analysis shall be performed and limits: quantitative measurements made to determine the dose equivalent
- a. Conductivity < 5 pmho/cm at 25 C I-131 concentration.
- b. Chloride 0.1 ppm c. An isotopic analysis of a reactor coolant sample shall be made at The reactor shall be shut down least once per month.
if pH is <5.6 or >8.6 for a 24-hour period. 2. Reactor coolant shall be continuously, monitored for conductivity.
- 3. During reactor operation in excess of 10% of rated power, the 3. Prior to startup, during the operation reactor coolant shall not exceed of the reactor and during hot the following limits: standby, a sample of the reactor coolant shall be analyzed:
- a. Conductivity 1 umho/cm at 25 C l
- a. At least every 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> for
- 4. During the reactor operation in monitor reading is <0.7 pmho/cm 25 C.
excess of 10% of rated power, the reactor coolant may exceed b. At least every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the limits of Paragraph 3.6.B.3 conductivity and chloride ion content
! only for the time limits specified when the continuous conductivity l here. If these time limits or the monitor reading is >0.7 but l following maximum limits are exceeded, <2.0 pmho/cm at 25 C.
the reactor shall be shutdown and placed in the Cold Shutdown c. At least every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for Condition. conductivity and chloride ion content when the continuous
- a. Conductivity Time above 1 pmho/cm conductivity monitor reading is >2 at 25 C, 2 weeks / year but <3.5 pmho/cm at 25 C.
Maximum limit-10 paho/cm at 25 C d. At least every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for l conductivity, chloride ion content,
- b. Chloride Time above 0.2 ppm, and pH, when the continuous 2 weeks / year conductivity monitor reading is l
Maximum limit-0.5 ppm >3.5 pmho/cm at 25 C or when the l continuous conductivity monitor is The reactor shall be shut down if inoperable, pH is <5.6 or >8.6 for a 24-hour period. 4. When the reactor is not pressurized, a sample of the reactor coolant shall
- 5. When the reactor is not pressurized be analyzed at least every 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> (i.e. at or below 212 F), reactor for conductivity and chloride ion coolant shall be maintained below content.
the following limits:
- a. Conductivity 10pmho/cm at 25 C l b. Chloride 0.5 ppm
, -134-
. Table 3.6.3 INACCESSIBLE SAFETY RELATED MECHANICAL SH0CK SUPPRESSORS (SNUBBERS)
(Cont'd)
Snubber No. Location Elevation VR-H-61D Drywell 897' VR-H-62C Drywell 899' VR-H-63B Drywell 897' VR-H-63C Drywell 898' VR-55-9-Y Drywell 919' VR-55-9-Z Drywell 919' VR-55-23-X Drywell 906' VR-55-23-Y Drywell 907' VR-55-26-Z Drywell 906' VR-56-12-Y- Drywell 913' VR-56-26-Y Drywell 916' VR-56-24-X Drywell 907' VR-56-24-Z Drywell 910' VR-58-12-Y Drywell 924' VR-59-7-X Drywell 920' VR-59-7-Z Drywell 920' VR-60-7-X Drywell 920' VR-60-7-Z Drywell 920' VR-61-8-X Drywell 919' VR-61-8-Z Drywell 919' VR-61-17-X Drywell 915'
, VR-62-8-X Drywell 922' VR-62-8-Z Drywell 915' VR-62-17-X Drywell 915' VR-S-10 Drywell 919' VR-S-11 Drywell 917' VR-S-14 Drywell 896' VR-S-20 Drywell 925' VR-S-21 Drywell 922' VR-S-22 Drywell 915' VR-S-30 Drywell 927' VR-S-31 Drywell 926'
, VR-S-32 Drywell 897' VR-S-40 Drywell 924' VR-S-41 Drywell 925' VR-S-42A Drywell 924' VR-S-42B Drywell 924' VR-S-43 Drywell 894' VR-S-50A Drywell 925' VR-S-50B Drywell 925' VR-S-51 Drywell 896' VR-S-60 Drywell 927' VR-S-61 Drywell 925' VR-S-62A Drywell 926' VR-S-62B Drywell 928' VR-S-63 Drywell 921' VR-S-87A Drywell 894'
- VR-S-87B Drywell 894' VR-S-88 Drywell 894' VR-H-62B Drywell 899' VR-H-64D Drywell 899'
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3.6.A & 4.6.A BASES Thermal and Pressurization Limitations The requirements for the reactor vessel have been identified by evaluating the-need for its integrity over the full spectrum of plant conditions and events.
This is accomplished through the Station Nuclear Safety Operational Analysis (Appendix G) and a detailed functional analysis of the reactor vessel. The limits expressed in the technical specification for the applicable operating states are taken from the actual Nuclear Safety Operational Requirements for the reactor vessel as given in Subsection IV-2.8 of the Safety Analysis Report.
The components of the nuclear system pressure boundary are constructed so that its initial maximum nil-ductility transition temperature (RT NDT) is not greater than 40*F, as cited in Subsection IV-2.5 of the Safety Analysis Report. The heatup-cooldown and hydrostatic test minimum pressurization temperatures were calculated to comply with the recommendations of Appendix G of Section III, ASME Boiler and Pressure Vessel Code, 1972 Summer Addendum.
The temperature versus pressure limits when critical which are presented in Figure 3.6.1.b assure compliance with Appendix G of 10CFR50.
Tightening the studs on the reactor vessel head flexes it slightly to bring together the entire contact surfaces adjacent to the 0-rings of the head and vessel flange. The reactor vessel head flange and head are constructed so that their initial maximum NDTI is 20*F, as cited in Paragraph IV-2.5 of the Safety Analysis Report. Therefore, the initial minimum temperature at which the studs can be placed in tension is established at 80*F (20*F + 60*F). The total integrated neutron flux in the head flange regiog will be less than that at the core mid-plane level by a factor of 10 or 10 , therefore, tgymaximum calculated fluence in the head flange region will be far below 1 x 10 nyt.
With such a low total integrated neutron flux in the head flange region, there will be no detectable or significant NDTT shift, and the minimum stud tightening temperature remains at 80*F.
The reactor vessel is designed in accordance with the ASME Boiler and Pressure Vessel Code,Section III, for a pressure of 1250 psig. The pressure limit of 1035 psig represents the maximum expected operating pressure in the steam dome when the station is operating at design thermal power. Observation of s this limit assures that the operator remains within the envelope of conditions considered by the Station Analysis (Section XIV).
Stress analyses have been made on the reactor vessel for both steady-state and transient conditions with respect to material fatigue. The results of these analyses are compared to allowable stress limits. The specific conditions analyzed included a maximum of 120 cycles of normal startup and shutdown with a heating and cooling rate of 100*F per hour applied continuously over a temp-erature range of 100*F to 546*F. The expected number of normal heatup and cool-down cycles to which the vessel will be subjected is 80.
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3.6.A & 4.6.A BASES (cont'd). l As described in the safety analysis report, detailed stress analyses have been made on the reactor vessel for both steady-state and transient conditions with respect to material fatigue. The results of these analyses-are compared to allowable stress limits. Requiring the coolant temperature in an idle re-circulation loop to be within 50*F of the operating loop temperature before a recirculation pump is started assures that the changes in coolant temperature at the reactor vessel nozzles and bottom head region are acceptable.
The coolant in the bottom of the vessel is at a lower temperature than that in the upper regions of the vessel when there is no recirculation flow. This colder water is forced up when recirculation pumps are started. This will not result in stresses which exceed ASME Boiler and Pressure Vessel Code,Section III limits when the temperature differential is not greater than 145'F.
The maximum calculated neutron fluence of 1 Mev or greater, based on 100 percent rated power and 100 percent availability for 40 years, is given by Figure 3.6.1. The neutron flux wires are removed and tested after approximately one year of operation during the first refueling outage to experimentally verify the calculated values of integrated neutron flux. The RT NDT is determined by utilizing the value of the fluence measured at the core mid-plane level.
This approach is conservative because the fluence level decreases as the point of measurement is removed frem the core mid-plane level. In addition, vessel material samples will be located within the vessel to monitor the effect of neutron exposure on these materials. The samples include specimens of base metal, weld zone metal and heat affected zone metal. These samples will receive neutron exposure more rapidly than the vessel wall material and there-fore, will lead the vessel in integrated neutron flux exposure. These samples will provide further assurance that the Shift in /RT NDT used in the specification is conservative.
B. Coolant Chemistry l Materials in the primary system are primarily Type-304 stainless steel and Ziracloy cladding. The reactor water chemistry limits are established to provide an environment favorable to these materials. Limits are placed on conductivity and chloride concentrations. Conductivity is limited because it can be continuously and reliably measured and gives an indication of abnormal conditions and the presence of unusual materials in the coolant. Chloride limits are specified.
to prevent stress corrosion cracking of stainless steel.
Several investigations have shown that ie. neutral solutions some oxygen is required to cause stress corrosion cracking of stainless steel, while in the absence of oxygen no cragking occurs. One of these is the chloride-oxygen relationship of Williams , where it is shown that at high chloride concentration little oxygen is required to cause stress corrosion cracking of stainless steel, and at high oxygen concentration little chloride is required to cause cracking. <
These measurements were determined in a wetting and drying situation using alkaline-phosphate-treated boiler water and therefore, are of limited significance to BWR conditions. They are, however, a qualitative indication of trends.
W. L. Williams, Corrosion 13, 1957, p. 539t.
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3.6.C & 4.6.C BASES (cont'd.)
indicates that leakage from a crack can be detected before the crack grows to a dangerous or critical size by mechanically or thermally induced cyclic loading, or stress corrosion cracking or some other mechanism characterized by gradual crack growth. This evidence suggests that for leakage somewhat greater than the limit specified for unidentified leakage, the probability is small that imperfections or cracks, associated with such leakage would grow rapidly.
However, the establishment of allowable unidentified leakage greater than that given in 3.6.C on the basis of the data presently available would be premature because of uncertainties associated with the data. For leakage of the order of 5 gpm, as specified in 3.6.C, the experimental and analytical data suggest a reasonable margin of safety that such leakage magnitude would not result from a crack approaching the critical size for rapid propagation.
Leakage less than the magnitude specified can be detected reasonably in a matter of a few hours utilizing the available leakage detection schemes, and if the origin cannot be determined in a reasonably short time the plant should be shutdown to allow further investigation and corrective action.
The total leakage rate consists of all leakage, identified and unidentified, which flows to the drywell floor drain and equipment drain sumps.
The capacity of the drywell floor sump pumps is 50 gpm and the capacity of the drywell equipment sump pumps is also 50 gpm. Removal of 25 gpm from either of these sumps can be accomplished with margin.
Reactor coolant leakage is also sensed by the containment radiation monitoring unit which senses gross beta, gamma particulate and iodine as well as by oxygen and hydrogen analyzers. Leakage can also be detected by area temperature detecters, humidity detectors and pressure instrumentation. Due to the many and varied ways of detecting primary leakage, a 30 day allowable repair time is justified.
l D. Safety and Relief Valves The safety and relief valves are required to be operable above the pressure (113 psig) at which the core spray system is not designed to deliver full flow. The pressure relief system for Cooper Nuclear Station has been sized to meet two design bases. First, the total safety / relief valve capacity has been established to meet the overpressure protective criteria of the ASME code. Second, the distribution of this required capacity between safety valves and relief valves has been set to meet design basis IV.4.2.1 of sub-section IV.4 which states that the nuclear system relief valves shall pre-vent opening of the safety valves during normal plant isolations and load rejections.
The details of the analysis which shows compliance with the ASME code require-ments is presented in subsection IV.4 of the FSAR and the Reactor Vessel Over-pressure Protection Summary Technical Report presented in question 4.20 of Amendment 11 to the FSAR. Results of the overpressure protection analysis are provided in the current reload license document.
l l
l Experience in relief and safety valves operation shows that a testing of 50 percent of the valves per year is adequate to detect failures or deteriorations.
i l
t
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3.6.E & 4.6.E BASES. (Cont'd) jet pump body; however, the converse is not true. The lack of any substantial stress in the jet pump body makes failure impossibl.e without an initial nozzle riser system failure.
F. Jet Pump Flow Mismatch Requiring the discharge valve of the lower speed loop to remain closed until the speed of faster pump is equal to or less than 50% of its rated speed provides assurance when going from one to_two pump operation that excessive vibration of l the jet pump risers will not occur.
G. Structural Integrity A preservice inspection of accessible components listed in Table 4.6.1 will be conducted before initial fuel loading to assure the system is free of gross defects and as a reference base for later inspections. Construction orien-tated nondestructive testing is being conducted as systems are fabricated to assure applicable code requirements are met. Prior to operation, the pri-I mary system boundary will be free of gross defects. In addition, the facility has been designed such that gross defects should not occur throughout the life of the station. The inspection program given in Table 4.6.1 is based on the requirements of Section IS-242: Table IS-251, Components, Parts and Methods of Examination, and Table IS-251, Examination Categories, all of Section XI of the 1970 ASME Boiler and Pressure Vessel Code, except where accessibility for inspection was not provided. The initial program was revised to update to the summer 1972 Addendum Table 15-261. Modifications were made to vessel nozzle insulation and nozzle blockout removable shielding designs with the intent to make the inspection areas more accessible by reducing the personnel radiation exposure required for inspection utilizing available equipment.
The inspection program and the modifications described above were developed
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3.6.G & 4.6.G BASES (cont'd.)
by the Nebraska Public Power District with assistance from its contractors.
The services of General Electric were retained to aid in developing the in-spection program, provide advice on practical modifications to existing designs for improved inspectability and to perform the preservice inspection.
It is not possible, however, to make all changes that might be desired to insure literal compliance with all areas of the current inspection code.
The areas of exclusion and reasons for this exclusion are discussed below.
Category A Accessibility is not provided for these welds. The permanent standoff type insulation was installed on the vessel and then the concrete sacrificial shield was erected. It was not possible to obtain any base line data on these welds. However, Nebraska Public Power District will evaluate new advances in inspection techniques and will inspect these areas when the equipment and techniques become practicable.
Category B In addition to the exclusion bases stated for Category A welds, at the present time there is no practical way to volumetrically inspect welds in the bottom head because of the combination of insulation and control rod and incore monitor housings configuration on the outside of the vessel and jet pumps and core shroud on the inside of the vessel.
Category E-(2)
At the present time there is no practical way to volumetrically or visually inspect the bottom head penetrations or drain nozzle weld because of the com-bination of insulation and control rod and in-core monitor housings config-uration. The combination of hydrostatic test and visual checks to be per-formed to provide reasonable assurance these examination areas are free of gross l
defects.
Category L-(2)
It is the intent that no internal examination be performed on the recirculation pumps unless they are disassembled for maintenance because of the high personnel radiation exposures which would be involved.
Category M-(2)
There are several valves in the primary pressure boundary which cannot be inspected unless the reactor fuel is removed and reactor water level lowered to the level of the entrance to the jet pump mixer assembly resulting in high personnel radiation exposures from the loss of shielding from the water.
Therefore, those valves which would require the reactor water level to be lowered below the low-low water level protection system trip point are ex-cluded from the requirement of visual inspection of internals.
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LINITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.7.A (Cont'd) 4.7.A (cont'd) repeated provided locally measured leakage reductions, achieved by re-pairs, reduce the containment's overall measured leakage rate suf-ficiently to meet the acceptance criteria.
- f. *With the exception of main steam isolation valves and main steam line and feedwater line bellows, (see below) local leak rate tests (LLRT's) shall be performed on the primary containment testable penetrations and isolation valves at , pressure of 58 psig during each reactor shut-down for refueling, or other conven-ient internals, but in no case at intervals greater than two years.
Bolted double-gasket seals shall be tested after each opening and during each reactor shutdown for refueling, or other con <enient intervals but in no case at intervals greater than two years.
- The main steam isolation valves (MSIV's) shall be tested at a pres- l sure of 29 psig. If a total leak-age rate of 11.5 scf/hr for any one MSIV is exceeded, repairs and retest shall be performed to correct the condition.
- Main steam line and feedwater line expansion bellows shall be tested at a pressure of 5 psig.
- g. Continuous Leak Rate Monitor When the primary containment is inerted the containment shall be continuously monitored for gross leakage by review of the inerting system makeup requirements. This monitoring system may be taken out of service for maintenance but shall be returned to service as soon as practicable.
- h. Drywell Surfaces The interior surfaces of the drywell and torus shall be visually inspected i each operating cycle for evidence of I
- Exemptions to Appendix J of 10 CFR 50.
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LDjlTIt!G CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.7.A (cont'd.) 4.7.A (cont'd.)
torus corrosion or leakage.
- 3. Pressure Suppression Chamber - 3. Pressure Suppression Chamber -
Reactor Building Vacuum Breakers Reactor Building Vacuum Breakers
- a. Except as specified in 3.7.A.3.b a. The pressure suppression chamber-reactor below, two pressure suppression building vacuum breakers and associated chamber-reactor building vacuum instrumentation, including set points breakers shall be operable at all shall be checked for proper operation times when primary containment in- every three months.
tegrity is required. The set point of the differential pressure instru-mentation which actuates the pressure suppression chamber-reactor building air actuated vacuum breakers shall be 0.5 psid. The self a,ctuated vacuum breakers shall open fully when subjected to a force equivalent to 0.5 psid acting on the valve disc.
- b. From and after the date that one of b. During each refueling outage each l
the pressure suppreseion chamber- vacuum breaker shall be tested to reactor building vacuum breakers is determine that the force required made or found to be inoperable for to open the vacuum breaker does not any reason, the vacuum breaker switch exceed the force specified in shall be secured in the closed position Specifications 3.7.A.3.a and each and reactor operation is permissible vacuum breaker shall be inspected only during the succeeding seven days and verified to meet design unless such vacuum breaker is sooner requirements.
made operable, provided that the repair procedure does not violate primary containment integrity.
- 4. Drywell-Pressure Suppression Chamber 4. Drywell-Pressure Suppression Chamber Vacuum Breakers Vacuum Breakers
- a. When primary containment is required, a. Each drywell-suppression chambe- vacuum all drywell-suppression chamber vac- breaker shall be exercised throuC.,an uum breakers shall be operable at the opening-closing cycle every 30 days.
0.5 psid setpoint and positioned in the fully closed position as indicated by the position indicating system except during testing and except as specified in 3.7.A.4.b and .c below.
- b. Three drywell-suppression chamber b. When it is stermined that a vacuum vacuum breakers may be determined breaker valve is inoperable for opening to be inoperable for opening pro- at a time when operability is required vided they are secured in the fully all other vacuum breaker valves shall closed position or that the require- be exercised immediately and every 15 ment of 3.7.A.4.c is demonstrated to days thereafter until the inoperable be met. valve has been returned to normal
, service.
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LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.7.A (cont'd.) 4.7.A (cont'd.)
- c. The total leakage between the dry- c. Once each operating cycle, each vacuum well and suppression chamber shall breaker valve shall be visually in-be less than the equivalent leakage spected to insure proper maintenance through a 1" diameter orifice. and operation of the position indication switch. The differential pressure set-point shall be verified.
- d. If specifications 3.7.A.4.a. b or c, d. Prior to reactor startup after each cannot be met, the situation shall refueling, a leak test of the drywell be corrected within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or the to suppression chamber structure reactor will be placed in a cold shall be conducted to demonstrate shutdown condition within the sub- that the requirement of 3.7.A.4.c sequent 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. is met.
- a. After completion of the startup test a. The primary containment oxygen con-program and demonstration of plant centration shall be measured and electrical output, the primay con- recorded at least twice weekly.
tainment atmosphere shall be reduced to less than 4% oxygen with nitrogen gas during reactor power operation with reactor coolant pressure above 100 psig, except as specified in 3.7.A.5.b.
- b. Within the 24-hour period subsequent b. The quantity of liquid nitrogen in to placing the reittor in the Run mode the liquid nitrogen storage tank shall following a shutdown, the containment be determined twice per week when the atmosphere oxygen concentration shall volume requirements of 3.7.A.5.c are l be reduced to less than 4% by volume in effect.
and maintained in this condition.
De-inerting may commence 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a shutdown.
- c. When the containment atmosphere oxygen concentration is required to be less than 4%, the minimum quantity of liquid nitrogen in the liquid nitroger. storage tank shall be 500 gallons.
- d. If the specifications of 3.7.A.5.a thru e cannot be met, an orderly shutdown ,
shall be initiated and the reactor shall be in a cold shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,
- e. The specifications of 3.7.A.S.a thru d are not applicable during a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> continuous period between the dates ci March 22, 1982 and March 25, 1982.
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LI$1TINGCONDITIONSFOROPERATION SURVEILLANCE REQUIREMENTS 3.7. (cont'd.) 4.7 (cont'd.)
B. Standby Gas Treatment System B. Standby Gas Treatment System
- 1. Except as specified in 3.7.B.3 below, 1. At least once per operating cycle the both circuits of the standby gas treat- following conditions shall be demon-ment system and the diesel generators strated.
required for operation of such circuits shall be operable at all times when a. Pressure drop across the combined HEPA secondary containment integrity is filters and charcoal adsorber banks is required. less than 6 inches of water at the sys-tem design flow rate.
- b. Inlet heater input is capable of reduc-ing R.H. from 100 to 70% R.H.
2.a. The results of the in-place cold DOP '2.a. The tests and sample analysis of Speci-and halogenated hydrocarbon tests at fication 3.7.B.2 shall be performed at design flows on HEPA filters and char- least once per year for standby service coal adsorber banks shall show 3,99% or after every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of system oper-DOP removal and 3,99% halogenated hydro- ation and following significant painting.
l carbon removal. fire or chemical release in any ventila-tion zone communicating with the system.
- b. The results of laboratory carbon sample b. Cold DOP testing shall be performed after analysis shall show 3,95% radioactive e.ch complete or partial replacement of methyl iodide removal at a velocity the HEPA filter bank or after any struc-within 20 percent of getual system de- tural maintenance on the system housing.
sign, 0.5 to 1.5 mg/m inlet methyl iodide concentration, 3,70% R.H. and 3,190
- F.
- c. Fans shall be shown to operate within c. Halogenated hydrocarbon testing shall be
+10% design flow. performed after each complete or partial replacement of the charcoal adsorber bank or after any structural maintenance on the system housing.
- d. Each circuit shall be operated with the heaters on at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> every month,
- e. Test sealing of gaskets for housing doors downstream of the HEPA filters and char-coal adsorbers shall be performed at, and in conformance with, each test per-formed for compliance with Cyecification 4.7.B.2.a and Specification 3.7.B.2.a.
- 3. From and after the date that one cir- 3. System drains where present shall be in-cuit of the standby gas treatment sys- spected quarterly for adequte water level tem is made or found to be inoperable in loop-seals.
for any reason, reactor operation or fuel handling is permissible only during the succeeding seven days unless such circuit is sooner made operable, pro-vided that during such seven days all active components of the other st.andby gas treatment circuit shall be operable.
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LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.7.B (cont'd) 4.7.B (cont'd)
- 4. If these conditions cannot be met, 4.a. At least once per operating cycle procedures shall be initiated automatic initiation of each branch of immediately to establish reactor the standby gas treatment system shall conditions for which the standby be demonstrated.
gas treatment system is not required.
- b. At least once per operating cycle manual operability of the bypass valve for filter cooling shall be demonstrated.
- c. When one circuit of the standby gas
, treatment system becomes inoperable the other circuit shall be demon-strated to be operable immediately ~
and daily thereafter.
C. Secondary Containment C. Secondary Containment
- 1. Secondary containment integrity shall 1. Secondary containment surveillance be maintained during all modes of shall be performed as indicated plant operation except when all of below:
the following conditions are met.
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LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.7.C (cont'd.) 4.7.C (cont'd.)
- e. The reactor is suberitical and Speci- a. A preoperational secondary containment fication 3.3.A is met, capability test shall be conducted af ter isolating the reactor building and
- b. The reactor water temperature is below placing either standby gas treatment 212*F and the reactor coolant system system filter train in operation. Such is vented. tests shall demonstrate the capability to maintain 1/4 inch of water vacuum
- c. No activity is being performed which under calm wind (2<U<5) conditions can reduce the shutdown margin below with a filter train flow rate of not that specified in Specification 3.3.A. more than 100% of building volume per day. (U= wind speed)
- d. Irradiated fuel is not being handled ,
in the secondary containment. b. Additional tests shall be performed during the first operating cycle under
- e. If secondary containment integrity an adequate number of different envir-cannot be maintained, restore onmental wind conditions to enable secondary containment integrity valid extrapolation of the test results, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or;
- c. Secondary containment capability to
- a. Be in at least Hot Shutdown maintain 1/4 inch of water vacuum within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and under calm wind (2<3<5 mph) conditions in cold shutdown within the with a filter train flow rate of not following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, more than 100% of building volume per day, shall be demonstrated at
- b. Suspend irradiated fuel handling each refueling outage prior to operations in the secondary con- refueling.
tainment and all core alterations and activities which could reduce d. After a secondary containment viola-the shutdown margin. The pro- tion is determined, the standby gas visions of Specification 1.0.J treatment system will be operated are not applicable. immediately after the affected zones are isolated from the remainder of the secondary containment to confirm its ability to maintain the remainder of the secondary containment at 1/4 inch of water negative pressure under calm wind conditions.
D. Primary Containment Isolation Valves D. Primary Containment Isolation Valves
- 1. During reactor power operating con'di- 1. The primary containment isolation tions, all isolation valves listed in valves surveillance shall be performed Table 3.7.1 and all instrument line as follows:
flow check valves shall be operable except as specified in 3.7.D.2. a. At least once per operating cycle the operable isolation valves that are power operated and automatically initiated shall be tested for simulated automatic initiation and closure times. l
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o COOPER NUCLEAR STATION TABLE 3.7.1 (Page 2) ,
PRIMARY CONTAINMENT ISOLATION VALVES Number of Power Maximum Action On Operated Valves Operating Normal Initiating Valve & Steam Inboard Outboard Time (Sec) (1) Position (2) Signal (3)
Primary Containment Purge & Vent 2 15 C SC PC-246AV, PC-231MV Primary Containment & N SUPP l y 2 15 C SC 2
PC-238AV, PC-232MV Suppression Chamber Purge & Vent 1 40 C SC(4)
PC-230MV Bypass (PC-305MV)
Primary Containment Purge & Vent 1 40 C SC(4)-
PC-231MV Bypass (PC-306MV) 1 ACAD Supply g MV 1303, MV 1304 2 15 C SC i MV 1305, MV 1306 2 15 C SC ACAD Supply MV 1301, MV 1302 2 15 0 CC MV 1311, MV 1312 2 15 0 GC ACAD Suppression Chamber Bleed Isolation 1 15 C SC MV 1308 ACAD Drywell Chamber Bleed Isolation 1 15 C SC MV 1310
TABLE 3.7.4
, PRIMARY CONTAINMENT TESTABLE ISOLATION VALVES TEST PEN. No. VALVE NUMBERS MEDIA X-7A MS-AO-80A and MS-AO-86A, Main Steam Isolation Valves Air X-7B MS-A0-80B and MS-AO-86B, Main Steam Isolation Valves Air X-7C MS-AO-80C and MS-AO-86C, Main Steam Isolation Valves Air X-7D MS-AO-80D and MS-AO-86D, Main Steam Isolation valves Air X-8 MS-M0-74 and MS-MO-77, Main Steam Line Drain Air X-9A RF-15CV and RF-16CV, Feedwater Check Valve Water X-9A RCIC-AO-22, RCIC-MO-17, and RWCU-15CV, RCIC/RWCU Connection to Feedwater Water X-9B RF-13CV and RF-14CV, Feedwater Check Valves Water X-9B HPCI-AO-18 and HPCI-M0-57. HPCI Connection to Feedwater Water X-10 RCIC-M0-15 and RCIC-MO-16, RCIC Steam Line Air X-ll HPCI-MO-15 and HPCI-MO-16, RPCI Steam Line Air X-12 RHR-M0-17 and RHR-M0-18, RHR Suction Cooling Air ,
X-13A RHR-MO-25A and RHR-M0-27A, RHR Supply to RPV Air X-13B RHR-M0-25B and RHR-MO-27B, RHR Supply to RPV Air X-14 RWCU-MO-15 and RWCU-MO-18, Inlet to RWCU System Air X-16A CS-MO-llA and CS-MO-12A, Core Spray to RPV Air X-16B CS-MO-llB and CS-M0-12B, Core Spray to RPV Air X-17 RHR-MO-32 and RHR-M0-33, RPV Head Spray Air A X-18 RW-732AV and RW-733AV, Drywell Equipment Sump Discharge Air X-19 RW-765AV and RW-766AV, Drywell Floor Drain Sump Discharge Air X-25 PC-232MV and PC-238AV, Purge and Vent Supply to Drywell Air X-25 ACAD-1305MV and ACAD-1306MV, Supply to Drywell Air X-26 PC-231MV and PC-246AV, Purge and Vent Exhaust from Drywell Air X-26 ACAD-1310MV, Bleed from Drywell Air
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TABLE 3.7.4 (prga 2)
PRIMARY CONTAINMENT TESTABLE ISOLATION VALVES TEST PEN. NO. VALVE NUMBERS MEDIA X-39A RHR-MO-26A and RHR-MO-31A, Drywell Spray Header Supply Air X-39B RHR-MO-26B and RHR-MO-31B, Drywell Spray Header Supply Air X-39B ACAD-1311MV and ACAD-1312MV, Supply to Drywell Air l X-41 RRV-740AV and RRV-741AV, Reactor Water Sample Line Air X-42 SLC-12CV and SLC-13CV, Standby Liquid Control Air X-205 PC-233MV and PC-237AV, Purge and Vent Supply to Torus Air X-201 PC-13CV and PC-243AV, Torus Vacuum Relief Air X-205 PC-14CV and PC-244AV, Torus Vacuum Relief Air X-205 ACAD-1303MV and ACAD-1304MV, Supply to Torus Air X-210A RCIC-MO-27 and RCIC-13CV, RCIC Minimum Flow Line Air X-210A RHR-MO-21A, RHR to Torus Air X-210A RHR-MO-16A, RHR-10CV, and RHR-12CV, RHR Minimum Flow Line Air X-210B RHR-M0-21B, RHR to Torus Air X-210B HPCI-17CV and HPCI-M0-25. HPCI Minimum Flow Line Air X-210B RHR-MO-16B, RHR-llCV, and RHR-13CV, RHR Minimum Flow Line Air X-210A and 211A RHR-MO-34A, RHR-MO-38A, and RHR-MO-39A, RHR to Torus Air X-210B and 211B RER-MO-34B, RHR-M0-38B, and RHR-M0-39B, RHR to Torus Air X-211B ACAD-1301MV and ACAD-1302MV, Supply to Torus Air X-212 RCIC-15CV and RCIC-37, RCIC Turbine Exhaust Air X-214 HPCI-15CV and HPCI-44, HPCI Turbine Exhaust Air l
X-214 HPCI-AO-70 and HPCI-AO-71 HPCI Turbine Exhaust Drain Air X-214 RHR-MO-166A and RHR-MO-167A RHR Heat Exch. Vent Air X-214 RHR-MO-166B and RHR-M0-167B E!fR Heat Exch. Vent Air X-220 PC-230MV and PC-245AV, Purge and Vent Exhaust from Torus Air X-220 ACAD-1308MV, Bleed from Torus Air f X-221 RCIC-12CV and RCIC-42, RCIC Vacuum Line Air X-222 HPCI-50 and HPCI-16CV, HPCI Turbine Drain Air
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3.I.A & 4.7.A BASES (cent'd) e The primary containment is normally slightly pressurized during periods of reactor operation. Nitrogen used for inerting could leak out of the contain-ment but air could not leak in to increase oxygen concentration. Once the containment is filled with nitrogen to the required concentration, no moni-toring of oxygen concentration is necessary. However, at least twice a week the oxygen concentration will be determined as added assurance.
The 500 gallon conservative limit on the nitrogen storage tank assures that adequate time is available to get the tank refilled assuming normal plant operation. The estimated maximum makeup rate is 1500 SCFD which would require about 160 gallons for a 10 day makeup requirement. The normal leak rate should be about 200 SCFD.
Vacuum Relief The purpose of the vacuum relief valves is" to equalize the pressure between the t
-178a-
Q n 3.7.A & 4.7.A BASES (cont'd.)
drywell and suppression chamber and reactor building so that the structural integrity of the containment is maintained. The vacuum relief system from the pressure suppression chamber to reactor building consists of two'100%.
. vacuum relief breakers (2 parallel sets of 2 valves in series). Operation of either system will maintain a pressure differential of less than 2 psi, the external design pressure. One valve may be out of service for repairs for a period of 7 days. If repairs cannot be completed within 7 days the reactor coolant system is brought to a condition where vacuum relief-is no longer required.
The capacity of the 12 drywell vacuum relief valves are sized to limit the pressure differential between the suppression chamber and drywell-during post-accident drywell cooling operations to well under the design limit of 2 psi. They are sized on the basis of the Bodega Bay pressure suppression system tests.' The ASME Boiler and Pressure Vessel Code,Section III, Sub-section B, for this vessel allows a 2 psi differential; therefore, with three vacuum relief valves secured in the closed position and 9 operable valves, containment integrity is not impaired.
Leak Rate Testing The maximum allowable test leak rate is'O.635%/ day at a pressure of 58 psig, the peak calculated accident pressure. Experience has shown that there is negligible difference between the leakage rates of air at normal temperature.
and a steam-hot air mixture.
Establishing the t'est limit of 0.635%/ day provides an adequate margin of safety to assure the health and safety of the general public. It is further considered that the allowable leak rate should not deviate significantly from the containment design value to take advantage of the design leak-tightness capability of the structure over its service lifetime. Additional margin to maintain the containment in the "as built" condition is achieved by establishing the allowable operational leak rate. The allowable operational leak rate is derived by multiplying the maximum allowable leak rate,- La or the allowable test leak rate, Lt by 0.75 thereby providing a 25% margin to allow for leakage deterioration which may occur during the period between leak rate tests.
The primary containment leak rate test frequency is based on maintaining adequate assurance that the leak rate remains within the specification.
The leak rate test frequency is based on the NRC guide for developing leak l rate testing and surveillance of reactor containment vessels. Allowing the test intervals to be extended up to 8 months permits some flexibility needed to have the tests coincide with scheduled or unscheduled shutdown periods.
The penetration and air purge piping leakage test frequency, along with the containment leak rate tests, is adequate to allow detection of leakage
-179-
, 3.7.A & 4.7.A BASES (cont'd.)
trends. Whenever a bolted double-gasketed penetration is broken and remade, the space between the gaskets is pressurized to determine that the seals are performing properly. It is expected that the majority of the leakage from valves, penetrations and seals would be into the reactor building. However, it is possible that leakage into other parts of the facility could occur.
Such leakage paths that may affect significantly the consequences of accidents are to be minimized.
Table 3.7.4 identifies certain isolation valves that are tested by pressurizing the volume between the inboard and outboard isolation valves. This results in conaervative test results since the inboard valve, if a globe valve, will be tested such that the test pressure is tending to lift the globe off its seat. Additionally, the measured leak rate for such a test is conservatively assigned to both of the valves equally and not divided between the two.
The main steam and feedwater testable penetrations consist of a double layered metal bellows. The inboard high pressure side of the bellows is subjected to drywell pressure. Therefore, the bellows is tested in its entirety when the drywell is tested. The bellows layers are tested for the integrity of both layers by pressurizing the void between the layers to 5 psig. Any higher pressure could cause permanent deformation, damage and possible ruptures of l the bellows.
The primary containment pre-operational test pressures are based upon the calculated primary containment pressure response in the event of a loss-of-coolant accident. The peak drywell pressure would be about 58 psig which would rapidly reduce to 29 psig following the pipe break. Following the pipe break, the suppression chamber pressure rises to 27 psig, equalizes with drywell pressure and therefore rapidly decays with the drywell pressure decay.
The design pressure of the drywell and suppression chamber is 56 psig. Based on the calculated containment pressure response discussed above, the primary containment pre-operational test pressure was chosen. Also, based on the primary cor.tainment pressure response and the fact that the drywell and suppression chamber function as a unit, the primary containment will be tested as a unit rather than the individual components separately.
The design basis loss-of-coolant accident was evaluated at the primary con-tainment maximum allowable accident leak rate of 0.635%/ day at 58 psig.
Calculations made by the NRC staff with leak rate and a standby gas treat-ment system filter efficiency of 90% for halogens and assuming the fission product release fractions stated in NRC Safety Guide 3, show that the maximum total whole body passing cloud dose is about 1.0 REM and the maximum total thyroid dose is about 12 REM at 1100 meters from the stack over an exposure duration of two hours. The resultant doses reported are the maximum that would be expected in the unlikely event of a design basis loss-of-coolant ,
accident. These doses are also based on the assumption of no holdup in the secondary containment resulting in a direct release of fission products from the primary containment through the filters and stack to the environs.
Therefore, the specified primary containment leak rate and filter ef ficiency are conservative and provide margin between expected off-site doses and 10 CFR 100 guidelines.
The water in the suppression chamber is used for cooling in the event of an accident; i.e., it is not used for normal operation; therefore, a daily
-180-
3.7.B & 3./.C BASIS (cont'd)
High efficiency particulate absolute (HEPA) filters are' installed before and after the charcoal adsorbers to minimize potential release of particulates to the environment and to prevent clogging of the iodine adsorbers.
The charcoal adsorbers are installed to reduce the potential release of radioiodine to the environment. The in-place test results should indicate a system leak tightness of less than 1 percent bypass leakage for.the charcoal adsorbers and a HEPA efficiency of at least 99 percent removal of DOP particulates. The laboratory carbon sample test results l should indicate a radioactive methyl iodide removal efficiency of at least 95 percent for expected accident conditions. If the efficiencies of the HEPA filters and charcoal adsorbers are as specified, the resulting doses will be less than the 10 CFR 100 guidelines for the accidents analyzed. Operation of the fans significantly different from the design flow will change the removal efficiency of the HEPA filters and charcoal adsorbers.
Only one of the two standby gas treatment systems is needed to cleanup the reactor building atmosphere upon containment isolation. If one system is found to be inoperable, there is no immediate threat to the containment system performance and reactor operation or refueling operation may continue while repairs are being made. If neither circuit is operable, the plant is brought to a condition where the standby gas treatment system is not required.
4.7.5 & 4.7.C BASES Standby Gas Treatment System and Secondary Containment Initiating reactor building isolation and operation of the standby gas treatment system to maintain at least a 1/4 inch of water vacuum within the secondary containment provides an adequate test of the operation of the reactor building isolation valves, leak tightness of the reactor building and performance of the standby gas treatment system. Functionally testing the initiating sensors and associated trip channels demonstrates the capability for automatic actuation. Performing these tests prior to re-fueling will demonstrate secondary containment capability prior to the time the primary containment is opened for refueling. Periodic testing gives sufficient confidence of reactor building integrity and standby gas treat-ment system performance capability.
Pressure drop across the combined HEPA filters and charcoal adsorbers of less than 6 inches of water at the system design flow rate will indicate that the filters and adsorbers are not clogged by excessive amounts of foreign matter. A 7.8 kw heater is capable of maintaining relative humidity below 70%. Heater capacity and pressure drop should be determined at least once per operating cycle to show system performance capability.
The frequency of tests and sample analysis are necessary to show that the HEPA filters and charcoal adsorbers can perform as evaluated. Tests of the charcoal adsorbers with halogenated hydrocarbon refrigerant shall be performed in accordance with USAEC Report DP-1082. The charcoal adsorber efficiency test procedures should allow for the removal of one adsorber tray, emptying of one bed from the tray, mixing the adsorbent thoroughly and obtaining at least two samples. Each sample should be at least two inches in diameter and a length equal to the thickness of the bed. If test results are unacceptable, all adsorbent in the system shall be replaced
-182-
f
" INTENTIONALLY LEFT BLANK"
-187, 188, 189, 190, 191, 192- l
I i
LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS
- i 3.9.A 4.9.A (cont'd.)
cell and overall battery voltage shall be measured and logged.
- b. Every three months the measurements shall be made of the voltage of each cell to nearest 0.1 Volt, specific gravity of each cell, and temperature of every sixth cell. These measure-ments shall be logged.
- c. Once each operating cycle, the stated batteries shall be subjected to a rated load discharge test. The specific gravity and voltage of each cell shall be determined after the discharge and logged.
B. Operation with Inoperable Equipment Whenever the reactor is in Run Mode or Startup Mode with the reactor not in a Cold Condition, the availability of electric power shall be as specified in 3.9.A, except as specified in 3.9.B.l.
- 1. From and after the date incoming power is not available from a startup or emer-gency transformer, continued reactor operation is permissible under this condition for aeven days. At the end of this period, provided the second source of incoming power has not been made immediately available, the NRC l must be notified of the event and the plan to restore this second source.
During this period, the two diesel gener-ators and associated critical buses must be demonstrated to be operable.
- 2. From and after the date that incoming power is not available from both start-up and emergency transformers, continued operation is permissible, provided the two diesel generators and associated critical buses are demonstrated to be
-195-
LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.9.B (cont'd.) 4.9.B operable, all core and containment
- cooling systems are operable, reactor power level is reduced to 25% of the l rated and NRC is notified within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the situation, the precau-tions to be taken during this period and the plans for prompt restora-tion of incoming power.
- 3. From and after the date that one of the diesel generators or an associated critical bus is made or found to be inoperable for any reason, continued reactor operation is permissible in accordance with Specification 3.5.F.1 if Specifica-tion 3.9.A.1 is satisfied.
- 4. From and after the date that both diesel generators are made or found to be inoperable for any reason, continued reactor operation is permissible only during the succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in accordance with Specification 3.5.F.2 if Specifi- -
cation 3.9.A.1 is satisified.
- 5. From and after the date that one of the diesel generators or associated critical buses and either the emer-gency or startup transformer power source are made or found to be in-operable for any reason, continued reactor operation is permissible in accordance with Specification 3.5.F.1, provided the other off-site source, startup transformer or emergency transformer is available and capable of automatically supplying power to the 4160V critical buses and l the NRC is notified within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the occurrence and the plans for restoration of the inoperable compo-nents.
-196-
4.9 BASES The monthly test of the diesel generator is conducted to check for equipment failures and deterioration. Testing is conducted up to equilibrium operating i conditions to demonstrate proper operation at these conditions. The diesel generator will be manually started, synchronized and connected to the bus and load picked up. The diesel generator should be loaded to at least 35%
of rated load to prevent fouling of the engine. It is expected that the diesel generator will be run for at least two hours. Diesel generator experience at other generating stations indicates that the testing frequency is adequate and provides a high reliability of operation should the system be required.
Each diesel generator has two air compressors and two air receivers for starting. It is expected that the air compressors will run only infrequently.
During the monthly check of the diesel generator, each receiver in each set of receivers will be drawn down below the point at which the corresponding
~
, compressor automatically starts to check operation and the ability of t.he compressors to recharge the receivers.
The diesel generator fuel consumption rate at full load is approximately 275 gallons per hour. Thus, the monthly load test of the diesel generators will test the operation and the ability of the fuel oil transfer pumps to refill the day tank and will check the operation of these pumps from the emergency source.
The test of the diesel generator during the refueling outage will be more comprehensive in that it wil' functionally test the sys~ tem; i.e, it will check diesel generator starting and closure of diesel generator breaker and sequencing of load on the diesel generator. The diesel generator will be started by simulation of a loss-of-coolant accident. In addition, an
't undervoltage condition will be imposed to simulate a loss of off-site power.
Periodic tests between refueling outages verify the ability of the diesel generator to run at full load and the core and containment cooling pumps to deliver full flow. Periodic testing of the various components, plus a func--
tional test once-a-cycle, is sufficient to maintain adequate reliability.
Although station batteries will deteriorate with time, utility experience indicates there is almost no possibility of precipitous failure. The type i
of surveillance described in this specification is that which has been demonstrated over the years to provide an indication of a cell becoming irregular or unserviceable long before it becomes a failure. In addition, the checks described also provide adequate indication that the batteries have the speci-i fied ampere-hour capability.
The diesel fuel oil quality must be checked to ensure proper operation of the diesel generators. Water content should be minimized because water in the fuel could contribute to excessive damage to the diesel engine.
l When it is determined that some auxiliary electrical equipment is out of l service, the increased surveillance required in Section 4.5.F is deemed
! adequate to provide assurance that the remaining equipment will be operable.
l l
-199-
8
" INTENTIONALLY LEFT BLANK" I
l l
J
-200, 201, 202-
LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.10 (Cont'd) 4.10 (Cont'd)
E. Spent Fuel Cask Handling E. Spent Fuel Cask Handling
- 1. Fuel cask handling above the 931' l. Prior to fuel cask handling operations, level of the Reactor Building will the redundant crane including the be done in the RESTRICTED MODE rope, hooks, slings, shackles and only except as specified in 3.10.E.2. other operating mechanisms will be inspected.
The rope will be replaced if any of the following conditions exist:
- a. Twelve (12) randomly distributed broken wires in one lay or four (4) broken wires in one strand of one rope lay,
- b. Wear of one-third the original diameter of outside individual.
wire.
- c. Kinking, crushing, or any other damage resulting in distortion of the rope.
'd. Evidence of any type of heat damage.
- e. Reductions from nominal diameter of more than 1/16 inch for a rope diameter from 7/8" to 1 1/4" inclusive.
- 2. Fuel cask handling in other than the 2. Prior to operations in the RESTRICTED RESTRICTED MODE will be permitted MODE in emergency or equipment failure situations only to the extent a. the contrelled area limit switches necessary to get the cask to the will be tested; closest acceptable stable location,
- b. the "two-block" limit switches will be tested;
- c. the " inching hoist" controls will be tested.
- 3. Operation with a failed controlled 3. The empty spent fuel cask will be area limit switch is permissible for lifted free of all support by a 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> providing an operator is on maximum of 1 foot and left hanging the refueling floor to assure the for 5 minutes prior to any series crane is operated within the of fuel cask handling operations.
restricted zone painted on the floor.
- 4. Spent fuel cashs weighing in excess of 140,000 lbs. shall not be handled.
-206-
3.10 BASES (Cont'd)
B. Core Monitoring The SRM's are provided to monitor the core during periods of station shutdown and to guide the operator during refueling operations and station startup. Requiring two. operable SRM's in or adjacent to any core quadrant where fuel or control rods are being moved assures adequate monitoring of that quadrant during such alterations. The requirement of 2,3 counts per second provides assurance that neutron flux is being monitored and insures that startup is conducted only if the source range flux level is above the minimum assumed in the control rod drop accident.
A spiral unloading pattern is one by which the fuel in the outermost cells (four fuel bundles surrounding a control blade) is removed first.
Unloading continues by removing the remaining outermost fuel cell by cell. The center cell will be the last removed. Spiral reloading is the reverse of unloading. Spiral unloading and reloading will preclude the creation of flux traps (moderator filled cavities surrounded on all sides by fuel).
During spiral unloading, the SRM's shall have an initial count rate of 2,3 cps with all rods fully inserted. The count rate will diminish during fuel removal. After all the fuel is removed from a cell, the control rod may be withdrawn in that cell. After the control rod is withdrawn, the refueling interlock will be bypassed on that control l rod. Following the withdrawal and bypassing of the control rod, two licensed o'perators will verify that the interlock bypassed is on the correct control rod. Once the control rod is withdrawn, it will be valved out of service. The refueling interlocks will prevent the withdrawal of another control rod unless the control rod just withdrawn from the unloaded cell is bypassed.
Under this special condition of complete spiral core unloading, it is
. expected that the count rate of the SRM's will drop below 3 cps before all of the fuel is unloaded. Since there will be no reactivity additions, a lower number of counts will not present a hazard. When all of the fuel has been removed to the spent fuel storage pool, the SRM's will no longer be ree 2. Requiring the SRM's to be operational prior to l fuel removal assures that the SRM's are operable and can be relied on even when the count rate may go below 3 cps.
During spiral reload, SRM operability will be verified by using a portable external source every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> until the required amount of fuel is loaded to maintain 3 cps. As an alternative to the above, two fuel assemblies will be loaded in different cells containing control blades around each SRM to obtain the required 3 cps. Until these two
, assemblies have been loaded, the 3 cps requirement is not necessary.
l l C. Spent Fuel Pool Water Level To assure that there is adequate water to shield and cool the irradiated fuel assemblies stored in the pool, a minimum pool water level is established. The minimum water level of 8 ' above the top of the fuel l is established because it provides adequate shielding and is well above the level to assure adequate cooling.
i l -209-
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Figwe 3.Il-2d P8x 8R Fuel 212 e
3.11 BASES A. Average Planar Linear Heat Generation Rate (APLHCR)
This specification assures that the peak cladding temperature following the postulated design basis loss-of-coolant accident will not exceed the limit specified in the 10CFR50, Appendix K.
The peak cladding temperature following a postulated loss-of-coolant accident is primarily a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is only dependent secondarily on the rod to rod power distribution within an assembly. Since expected local variations in power distribution within a fuel assembly affect the calculated peak clad temperature by less than
+ 20 F relative to the peak temperature for a typical fuel design, the limit on the average linear heat generation rate is sufficient to assure that calculated temperatures are within the 10CFR50 Appendix K limit.
The limiting value for APLHGR is shown in Figure 3.11-1.
The calculational procedure used to establish the APLHGR shown on Figure 3.11.1 is based on a loss-of-coolant accident analysis. The analysis was performed using General Electric (CE) calculational models which are con-sistent with the requirements of Appendix K to 10CRF50. A complete dis-cussion of each code employed in the analysis is presented in Reference 1.
References for Bases 3.11.A
- 1. General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with 10 CFR 50, App'endix K, NED0-20566, dated January 1976.
B. Linear Heat Generation Rate (LHGR)
- This specification assures that the linear heat generation rate in any
! rod is less than the design linear heat generation if fuel pellet densi-fication is postulated. The power spike penalty specified is based on the analysis presented in Section 5 of Reference 2 and assumes a linearly increasing variation in axial gaps between core bottom and top, and assures with a 95% confidence, that no more than one fuel rod exceeds the design linear heat generation rate due to power spiking. The LHGR as a function of core height shall be checked daily during reactor operation at > 25% power to determine if fuel burnup, or control rod movement has caused changes in power distribution. For LHGR to be a limiting value below 25% rated thermal power, the MTPF would have to be greater than 10 which is precluded by a considerable margin when employing any permissible control rod pattern. Pellet densification power spiking in 8x8 fuel has been accounted for in the safety analysis presented in Reference 5; thus no adjustment to the LHGR limit for densification effects is required for <
8x8 fuels.
-214-
3.11 Buca: (Cont'd)
C. Minimum Critical Power Ratio (MCPR) (
The required operating limit MCPR's at steady state operating conditions _
as specified in Specification 3.11C are derived from the established fuel cladding integrity Safety Limit MCPR of 1.07, and an analysis of abnormal operational transients (Reference 5). For any abnormal operating tran-sient analysis evaluation with the initial condition of the reactor being at the steady state operating limit it is required that the resulting MCPR does not decrease below the Safety Limit MCPR at any time during the transient assuming instrument trip setting given in Specification 2.1.
To assure that the fuel cladding integrity Safety Limit is not exceeded during any anticipated abnormal operational transient, the more limiting transients have been analyzed to determine which result in the largest reduction in critical power ratio (CPR). The type of transients evaluated were loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease.
The limiting transient which determines the required steady state MCPR limit and thus yields the largest ACPR is discussed in Reference 5. When added to the safety limit MCPR of 1.07 the deterministic MCPR's are obtained. The required minimum operating limit MCPR's are determine by methods given in References 8 and 9.
t Prior to the analysis of abnormal operational transients an initial fuel bundle MCPR was determined. This parameter is based on the bundle flow calculated by a GE multi-channel ste g state flow distribution model as described in Section 4 of NEDO-24011 and on core parameters shown in Table 5-2 of Reference 2.
The evaluation of a given transient begins with the system initial para-meters shown in Table 5-2 of Reference 2 that are input totheGEcg dynamicbehavigtransientcomputerprogramdescribedinNED0-10802 and NED0-24154 . The outputs of the program along with the initial MCPR form the input for further analyses of the thermally limiting bundle with the single nnel transient thermal hydraulic SCAT code described in NEDE-20566 The principal result of this evaluation is the reduction in MCPR caused by the transient.
l The purpose of the Kg factor is to define operating limits at other than l
rated flow conditions. At less than 100% flow, the required MCPR is the product of the operating limit MCPR and the Kg factor, Specifically, the K g factor provides the required thermal margin to protect against a flow l increase transient. The most limiting transient initiated from less than j rated flow conditions is the recirculation pump speed up caused by a l motor-generator speed control failure.
For operation in the automatic flow control mode, the K g factors assure that the operating limit MCPR will not be violated should the most limiting i transient occur at less than rated flow. In the manual flow control l
mode, the K factors assure that t.b Safety Limit MCPR will not be vio-lacedfortbesamepostulatedtrannientevent.
l l -214a-
3.11 BScrat (Cont'd)
The Kg factor curves shown in Figure 3.11-3 were developed generically which are applicable to all BWR/2, BWR/3, and BWR/4 reactors. The K factorswerederivedusingtheflowcontrollinecorrespondingtoraked thermal power at rated core flow.
factors were calculated such For that the manual at the flow flow maximum control mode, state the K, d by the pump scoop tube set (as limite point) and the corresponding core power (along the rated flow control line), the limiting bundle's relative power was adjusted until the MCPR was slightly above the Safety Limit. Using this relative bundle power, the MCPR's were calculated at different points along the rated flow control line corresponding to different core flows. The ratio of the MCPR calculated at a given point of core flow, divided by the operating limit MCPR determines the Kg .
For operation in the automatic flow control mode, the same procedure was employed excant the initial power distribution was established such that the MCPR was equal to the operating limit MCPR at rated power and flow.
The Kg factors shown in Figure 3.11-3, are conservative for Cooper opera-tion Because the operating limit MCPR's are greater than the original 1.20 operating limit MCPR used for the generic derivation of K . g D. Thermal-hydraulic Stability The calculations, regarding reactor core stability, presented in Reference 5 show that the reactor is in compliance with the ultimate performance criteria, including the most responsive condition at natural circulation and rod block power. However, to preclude the possibility of operation under conditions which could result in reactor core instability, the NRC requested the incorporation of a specification limit.
The power level specified results in a decay ratio (X /X2 )nwhich is significantly less than the ultimate stability limit of I.0.
References for Bases 3.11.B, 3.11.C, 3.11.D
- 1. " Cooper Nuclear Station Channel Inspection and Safety Analyses with Bypass Holes Plugged," NEDO-21072, October 1975.
- 2. Licensing Topical Report, General Electric Boiling Water Reactor, Generic Reload Fuel Application, (NEDE-24011-P), (most current approved submittal).
- 3. R. B. Linford, Analytical Methods of Plant Transient Evaluations for the GE BWR, February 1973 (NEDO-10802).
- 4. General Electric Company Analytical Model for Loss-of-Coolant Analy-sis in Accordance with 10 CFR 50, Appendix K, NEDO-20566, dated January 1976.
- 5. " Supplemental Reload Licensing Submittal for Cooper Nuclear Station Unit 1," (applicable reload document).
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- 6. April 18, 1978 letter from J. M. Pilant (NPPD) to G. E. Lear (NRC).
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3.11 Brecat (Cont'd)
- 7. " Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors," NED0-24154, Volumes 1, 2 and 3, October 1978.
- 8. Letter, R. H. Buckholz (GE) to P. S. Check (NRC), "0DYN Adjustment Methods for Determination of Operating Limits," January 19, 1981.
- 9. Letter (with attachment) R. H. Buckholz (GE) to P. S. Check (NRC),
" Response to NRC Request for Information on ODYN Computer Model,"
September 5, 1980.
4.11 Bases:
A&B. Average and Local LHGR The LHGR shall be checked daily to determine if fuel burnup, or control rod movement has caused changes in power distribution.
Since changes due to burnup are slow, and only a few control rods are moved daily, a daily check of power distribution is adequate.
C. Minimum Critical Power Ratio (MCPR) - (Surveillance Requirement) l At core thermal power levels less than or equal to 25%, the reactor will be operating at less than or equal to minimum recirculation pump speed and the moderator void content will be very small. For all designated control rod patterns which may be employed at this point, operating plant experience indicated that the resulting MCPR value is in excess of requirements by a considerable margin. With this low void content, any inadvertent core flow increase would only place operation in a more conservative mode relative to MCPR. During initial start-up testing of the plant, a MCPR evaluation was made at 25% thermal power level with minimum recirculation pump speed.
The MCPR margin was thus demonstrated such that subsequent MCPR evaluation below this power level was shown to be unnecessary. The daily requirement for calculating MCPR above 25% rated thermal power is sufficient since power distribution shifts are very slow when there have not been significant power or control rod changes. The requirement for calculating MCPR when a limiting l control rod pattern is approached ensures that MCPR will be known following l a change in power or power shape (regardless of magnitude) that could place l operation at a thermal limit.
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. LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS B. Reactor Building Closed Cooling Water B. Reactor Building Closed Cooling Water System (REC) System (REC)
- 1. Both reactor building closed cooling 1. REC System Testing water loops and their associated Item Frequency pumps shall be operable whenever irradiated fuel is in the vessel or a. Pump Operability Once/ Month the spent fuel pool, except as speci- b. Motor operated once/ Month fied in 3.12.B.2 and 3.12.B.3 Valve Operability below. c. Pump flow rate Once/3 months and Each pump shall after pump mainten-deliver 1175 gpm ance at 65 psid.
- d. System head tank Daily level shall be monitored.
- 2. From and after the date that any 2. When it is determined that any active component in one loop becomes in- componentinanRECloopisinoperable,l operable continued reactor operation all components in the other loop shall is permissible during the succeeding be demonstrated operable immediately thirty days provided that during and weekly thereafter.
such thirty days all the components of the other loop and the active com-ponents of the engineered safeguards compartment cooling systems, the diesel generator associated with the operable loop are operable. .
The allowable repair time does not apply when the reactor is in the shutdown mode and reactor pressure is less than 75 psig.
- 3. Both reactor building closed cooling water loops with one pump per loop shall be operable as stated in 3.12.
B.1 and 3.12.B.2 above during reactor head-off operations requiring LPCI or Core Spray System availability or service water cooling shall be available.
l l 4. If the requirements of 3.12.B.1 l through 3.12.B.3 cannot be met, the l reactor shall be shutdown in an I
orderly manner and in the Cold Shut-down condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or operations requiring LPCI or core spray system availability shall be
- halted.
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, LI$11TINGCONDITIONSFOROPERATION SURVEILLANCE REQUIREMENTS 3.14 FIRE DETECTION SYSTEM 4.14 FIRE DETECTION SYSTEM APPLICABILITY APPLICABILITY Applies to the operational status of the Applies to the operational status of the Fire Detection System. Fire Petection System.
OBJECTIVE To assure continuous automatic surveillance throughout the Main Plant.
SPECIFICATIONS SPECIFICATIONS A. Tne Fire Detection System instumen- A. Each detector on Table 3.14 shall be tation for each fire detection zone demonstrated operable every 6 months shown in Table 3.14 shall be operable. by perforrance of a channel functional test.
B. With one or more of the fire detection B. The NFPA Code 72.D Class B supervised instrument (s) shown in Table 3.14 circuits supervision associated with inoperable: the detector alarms of each of the above required fire detection
- 1. Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> establish a fire instruments shall be demonstrated watch patrol to inspect the OPERABLE at least once per 6 months.
zone (s) with the inoperable instru-ment (s) at least once per hour, and
- 2. Restore the inoperable instrument (s) to OPERABLE status within 14 days or prepare and submit a Special Report to the Commission pursuant to Specification 6.7.2 within the next 30 days outlining the action taken, the cause of the inoperability and the plans and schedule for re-storing the instrument (s) to OPERABLE status.
3.15 FIRE SUPPRESSION WATER SYSTEM 4.15 FIRE SUPPRESSION WATER SYSTEM APPLICABILITY APPLICABILITY Applies to the availability of water for Applies to the availability of water fire fighting purposes. for fire fighting purposes.
OBJECTIVE To assure a continuous operable water supply for fire fighting systems from at least 2 of the 3 fire pumps.
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- INSTRUMENT LOCATION INSTRUMENT ID NO.
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2 Control Room FP-SD-17-1 FP-SD-17-2 FP-SD-17-3
'3 Cable Spreading Room FP-SD-16-1 FP-SD-16-2 FP-SD-16-3 FP-SD-16-4 FP-SD-16-5 FP-SD-16-6 Cable Expansion: Room FP-SD-16-7 FP-SD-16-8 I 4 Switchgear Rooms DC Switchgear Rooms FP-SD-15-2 FP-SD-15-3 Critical Switchgear Room FP-SD-22-1 FP-SD-22-2 5 Station Battery Rooms FP-SD-15-1 FP-SD-15-4 FP-SD-15-1A FP-SD-15-4A 6 Diesel Generator Rooms FP-SD-10-1 FP-SD-10-2
~
FP-SD-10-3 FP-SD-10-4 CO2-SD-DG-1A CO2-SD-DG-1B CO2-SD-DG-1C CO2-SD-DG-1D CO2-SD-DG-2A CO2-SD-DG-2B CO2-SD-DG-2C CO2-SD-DG-2D I 7._ Diesel Fuel Storage Rooms CO2-TD-DG-1A l CO2-TD-DG-1B 8 Safety Related Equipment not in Reactor Building RIIR Service Water Booster Pumps FP-SD-14-3 Emergency Condensate Storage "ry s FP-SD-14-1 Fire Water Pumps & Servie- 1 tee ?uvps FP-FD-32-1 FP-FD-32-2 9 Auxiliary Relay Room & R; actor vecjection System Rooms Auxiliary Relay Room FP-SD-15-9 Reactor Protection System Room 1A FP-SD-15-7 Reactor Protection System Room IB FP-SD-15-8 l
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5.0 MAJOR DESIGN FEATURES 5.1 Site Features The Cooper Nuclear Station site is located in Nemaha County, Nebraska, on the west bank of the Missouri River, at river mile 532.5. This part of the river is referred to by the Corps of Engineers as the Lower Brownville Bend.
Site coordinates are approximately 40 21' north latitude and 95 38' west longitude. The site consists of 1351 acres of land owned by Febraska Public Power District. About 205 acres of this property is locats' in Atchison County, Missouri, opposite the Nebraska portion of the sto- kT site. The land area upon which the station is constructed is crossed c3 the l Missouri River on the east and is bounded by privately owned property on t;.e north, south, and west. At the west site bcundary, a county road and Burlington Northern Railroad spur pass the site.
The reactor (center line) is located approximately 3600 feet from the nearest property boundary. No part of the present property shall be sold or leased by the applicant which would reduce the minimum distance from the reactor to the nearest site boundary to less than 3600 feet without prior NRC approval.
The protected area is formed by a seven foot chain link fence which surrounds the site buildings.
5.2 Reactor A. The core shall consist of not more than 548 fuel assemblies in any combination of 7x7 (49 fuel rods) and 8x8 (63 fuel rods) and 8x8R/P8x8R (62 fuel rods).
B. The core shall contain 137 cruciform-shaped control rods. The control material shall be boron carbide powder (B C) 4 compacted to approximately 70% theoretical density.
5.3 Reactor Vessel
! The reactor vessel shall be as described in Section IV-20 of the SAR. The applicable design shall be as described in this section of the SAR.
5.4 Containment A. The principal design parameters for the primary containment shall be as given in Table.V-2-1 of the SAR. The applicable design shall be as des-cribed in Section XII-2.3 of the SAR.
B. The secondary containment shall be as described in Section V-3.0 of the SAR.
C. Penetrations to the primary containment and piping passing through such l
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G. A Fira Brigide of at least 5 me bsra chmll be maintsin d et all
- times. This excludes the 3 members of the minimum shift crew necessary for safe shutdowns, and other personnel required for other essential functions during a fire emergency. Three fire Brigade members shall be from the Operations Department and 2 support members may be from other departments inclusive of Security personnel.
Fire Brigade composition may be less than the minimum requirements for a period of time not to exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in order to accommodate unexpected absence of Fire Brigade members provided immediate action is taken to restore the Fire Brigade to within the minimum requirements.
H. In order to perform the function of accident assessment an engineer from the normal plant engineering staff shall be assigned to each shift during reactor operation. If the lack of qualified engineers necessitates, an additional senior reactor operator assigned to each shift may substitute in the performance of the accident assessment function. This requirement is ef'fective until January 1, 1981.
6.1.4 The minimum qualifications, training, replacement training, and retraining of plant personnel at the time of fuel loading or appointment to the active position shall meet the requirements as described in the American National Standards Institute N-18.1-1971,
" Selection and Training of Personnel for Nuclear Power Plants".
The Assistant to Station Superintendent qualifications shall comply with Section 4.2 of, ANSI-N18.1-1971. The Chemistry and Health Physics Supervisor shall meet or exceed the qualifications of Regulatory Guide 1.8, Sept. 1975; personnel qualification equivalency as stated in the Regulatory Guide may be proposed in selected cases. The minimum frequency of the retraining program shall be every two years. The training program shall be under the direction of a designated member of the plant staff.
A. A training program for the fire brigade will be maintained
- under the direction of the plant training coordinator and shall meet or exceed the requirements of Section 27 of the NFPA Code 1976, except for Fire Brigade training sessions which shall be held at least quarterly.
The training program requirements will be provided by a quali-fied fire protection engineer.
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6.I Ravir.w and Audit 6.2.1 The organization and duties of committees for the review and audit of station operation shall be as outlined below:
A. Station Operations Review Committee
- 1. Membership:
z
- a. Chairman: Station Superintendent or Assistant to Station
- Superintendent
- b. Engineering Supervisor
- c. Operations Supervisor t
- d. Chemistry and Health Physics Supervisor
- e. Maintenance Supervisor
- f. Quality Assurance Supervisor - non-voting member.
Alternate members shall be appointed in writing by the Station Superintendent to serve on a temporary basis; however, no-more than one alternate shall serve on the Committee at any one time.
- 2. Meeting Frequency: Monthly, and as required on call of the Chairman.
- 3. Quorum: Station Superintendent or Assistant to Station Superintendent plus two other members including alternates.
- 4. Responsibilities:
- a. Review all proposed normal, abnormal, maintenance and emergency operating procedures specified in 6.3.1, 6.3.2, 6.3.3, and 6.3.4 and proposed changes thereto: and any other proposed procedures or changes thereto determined by any member to effect nuclear l safety.
- b. Review all proposed tests and experiments and their results, which involve nuclear hazards not previously reviewed for conformance with technical specifications. Submit tests which may constitute an unreviewed safety question to the NPPD Safety Review and Audit Board for review. l
- c. Review proposed changes to Technical Specifications, license and the Final Safety Analysis Report.
- d. Review proposed changes or modifications to station systems or-equipment as discussed in the FSAR or which involves an unre-viewed safety question as defined in 10CFR50.59(c). Submit changes to equipment or systems having safety significance to the NPPD Safety Review and Audit Board for review.
- e. Review station operation to detect potential unsafe conditions.
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6.2 (cont'd)
- f. Investigate all reported ins'.ances of violations of Technical Specifications, including reporting evaluation and recommendations to prevent recurrence, to the Division Manager of Power Operations l and to the Chairman of the NPPD Safety Review and Audit Board.
- g. Perform special reviews and investigations and render reports thereon as requested by the Chairman of the Safety Review and Audit Board. l
- h. Review all events which are required by regulations or Technical Specifications to be reported to the NRC in writing within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
- i. Review drills'on emergency procedures (including plant evacuation) and adequacy of communication with off site groups.
- j. Review all procedures required by these Technical Specifications, including procedures of the Emergency Plan and the Security Plan with a frequency commensurate with their safety significance but at an interval of not more than two years.
5.
Authority
- a. The Station Operations Review Committe shall be advisory,
- b. The Station Operations Review Committee shall recommend to the Station Superintendent approval or disapproval of proposals under items 4, a through e and j above. In case of disagreement between the recommendations of the Station Operations Review Committee and the Station Superintendent, the course determined by the Station Superintendent to be the more conservative will be followed. A written summary of the disagreement will be sent to the Division Manager of Power Operations and to the NPPD l Safety Review and Audit Board.
- c. The Station Operations Review Committee shall report to the Chairman of the NPPD Safety Review and Audit Board on all re-views and investigations conducted under items 4.f 4.g, 4.h, and 4.1.
- d. The Station Operations Review Committee shall make tentative
! determinations regarding whether or not proposals considered l by the Committee involve unreviewed safety questions. This determination shall be subject to review and approval by the I NPPD Safety Review and Audit Board.
- 6. Records:
Minutes shall be kept for all meetings of the Station Operations Review Committee and shall include identification of all documen-
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6.2 (cont'd) 1 l
tary material reviewed; copies of the minutes shall be for- ,
warded to the Chairman of the NPPD Safety Review and Audit
. Board and the Division Manager of Power Operations within one month. l
- 7. Procedures:
Written administrative procedures for Committee operation shall be prepared and maintained describing the method for submission and content of presentations to the committee, provisions for use of subcommittees, review and approval by members of written Committee evaluations and recommendations, dissemination of minutes, and such other matters as may be appropriate.
B. NPPD Safety Review and Audit Board.
The board must: verify that operation of the plant is consistent with company policy and rules, approve operating procedures and l operating license provisions; review safety related plant changes, proposed tests and procedures; verify that unusual events are promptly investigated and corrected in a manner which reduces the probability of recurrence of such events; and detect trends which may not be apparent to a day-to-day observer.
Audits of selected aspects of plant operation shall be performed with a frequency commensurate with their safety significance and in such a manner as to assure that an audit of all nuclear safety related activities is completed within a period of two years. Periodic review of the audit programs should be performed by the Board at least twice a year to assure that such audits are being accomplished in accordance with requirements of Technical Specifications. The audits shall be performed in accordance with appropriate written instructions or procedures and should include verification of compliance with inter-nal rules, procedures (for example, normal, off-normal, emergency, op-erating, maintenance, surveillance, test and radiation control proce-dures and the emergency and security plans), regulations involving nuclear safety and operating license provisions; training, qualification and performance of operating staff; and corrective actions following abnormal occurrences or unusual events. A representative portion of procedures and records of the activities performed during the audit period shall be audited and, in addition, observations of perfor-mance of operating and maintenance activities shall be included.
Written reports of such audits shall be reviewed at a scheduled meeting of the Board and by appropriate members of management including those having responsibility in the area audited. Follow-up action, including reaudit of deficient areas, shall be taken when indicated.
In addition to the above, the Safety Review and Audit Board will audit the facility fire protection and its implementing procedures at least once every 24 months.
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n 6.2 (cont'd)
- 1. Membership
- a. Senior Division Manager of Power Operations (chairman)
- b. Division Manager of Licensing and Quality Assurance (alternate Chair-man)
- c. Division Manager of Power Projects
- d. Division Manager of Power Supply
- e. Division Manager of Environmental Affairs
- f. ' Consultants (as required)
The Board members shall collectively have the capability required l to review problems in the following areas: nuclear power plant operations, nuclear engineering, chemistry and radiochemistry, metallurgy, instrumentation and control, radiological safety, mechanical and electrical engineering, and other appropriate fields associated with the unique characteristics of the nuclear power plant involved. When the nature of a particular problem dictates, special consultants will be utilized.
Alternate members shall be appointed in writing by the Board Chairman to serve on a temporary basis; however, no more than two alternates shall serve on the Board at any one time.
- 2. Meeting frequency: Semiannually, and as required on call of the Chairman.
- 3. Quorum: Chairman or Vice Chairman, plus three members including alternates. No more than a minority of the quorum shall be from groups holding line responsibility for the operation of the plant.
4 Responsibilities: The following subjects shall be reported to and reviewed by the NPPD Safety Review and Audit Board.
- a. The safety evaluations for 1) changes to procedures, equipment or systems and 2) 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.
l b. Proposed changes to procedures, equipment or systems which involve an unreviewed safety question as defined in Section 50.59, 10 CFR.
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6.k Actions to bn Taken in the Event of Occurrences Specified in Section 6.7.2.A.
6.4.1 Occurrences, as specified in Section 6.7.2.A., shall be promptly reported to the Station Superintendent, Division Manager of Power Operations and the Chairman of the NPPD Safety Review and Audit Board and shall be promptly reviewed by the Station Operations Review Committee. This committee shall prepare a separate report. This report shall include an evaluation of the cause of the occurrence, a record of the corrective action taken, and recommendations for appropriate action to prevent or reduce the probability of a repetition of the occurrence. Copies of all such reports shall be submitted to the Power Operations Department and the NPPD Safety l Review and Audit Board Chairman for review and approval of any recommendations.
6.4.2 All occurrences as specified in Section 6.7.2.A. shall be reported to the General Manager on a periodic basis.
6.5 Action to be Taken if a Safety Limit is Exceeded 6.5.1 If a safety limit is exceeded, reactor shall be shut down and reactor operation shall not be resumed until authorized by the NRC. An immediate report shall be made to the Division Manager of Power Operations, the l General Manager and to the chairman of the NPPD Safety Review and Audit Board.
A complete analysis of the circumstances leading up to and resulting from the situation together with recommendations to prevent a recurrence shall be prepared by the Station Operations Review Committee. This report shall be submitted to the Division Manager of Power Operations and the NPPD Safety Review and Audit Board. Appropriate analyses or reports will be submitted l to the NRC. Notification of such occurrences will be made to the NRC by the Station Superintendent within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as specified in Specifica-tion 6.7.
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6.7 Stetion Reporting Rtquirem:nta e
6.7.1 Routine Reports A. In addition to the applicable reporting requirements of Title 10, Code of Federal Regulations, the following identified reports shall be submitted to the individual (s) designated in the current revision of Reg. Guide 10.1 unless otherwise noted.
B. Start up Report
- 1. A summary report of plant startup and power escalation testing shall be submitted following:
- a. Receipt of an operating license.
- b. Amendment to the license involving a planned increase in power level.
- c. Installation of fuel that has a different design or has been manufactured by a different fuel supplier.
- d. Modifications t'at may have significantly altered the nuclear, thermal, or hydrttlic performance of the plant.
The report shall address each of the tests identified in the FSAR and shall include a description of the measured values of the operating conditions or characteristics obtained during the test program and a comparison of these values with design predictions and specifications. Any corrective actions that were required to obtain satisfactory operation shall also be described. Any additional specific details required in license conditions based on other commitments shall be included in this report.
- 2. Startup reports shall be submitted within (1) 90 days following completion of the startup test program, (2) 90 days following resumption or commencement of commercial power operation, or (3) 9 months following initial criticality, whichever is earliest.
If all three events are not completed, supplementary reports shall be submitted every three months.
C. Annual Reports Routine reports covering the subjects noted in 6.7.1.C.1 6.7.1.C.2, and 6.7.1.C.3 tor the previous calendar year shall Le submitted prior to March 1 of'each year.
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- 1. A tabulation on an annual basis of the nu;bsr of station.
utility and other personnel (including contractors) re-ceiving exposures greater than 100 mrem /yr and their associated man rem exposure according to work and job functions, 1/ e.g., reactor operations and surveillance, inservice inspection, routine maintenance, special main-tenance (describe maintenance), waste processing, and refueling. The dose assignment to various duty functions may be estimates based on pocket dosimeter, TLD, or film badge measurements. Smal1' exposures totaling less than 20%
of the individual total dose need not be accounted for. In the aggregate, at least 80% of the total whole body dose received from external sources shall be assigned to specific major work functions.
- 2. A summary description of facility changes, tests or experi-ments in accordance with the requirements of 10CFR50.59(b).
- 3. Pursuant to 3.8.A, a report of radioactive source leak testing. This report is required only if the tests reveal the presence of 0.005 microcuries or more of removable contamination.
D. Monthlv Operating Report Routiae reports of operating statistics, shutdown experience, and a narrative summary of operating experience relating to safe operation of the facility, shall be submitted on a monthly basis to the individual designated in the current revision of Reg. '
Guide 10.1 no later than the tenth of each month following the calendar month covered by the report.
6.7.2. Reportable Occurrences Reportable occurrences, including corrective actions and measures to prevent reoccurrence, shall be reported to the NRC. Supplemental reports may be required to fully describe final resolution of occurence. In case of corrected or supplemental reports, a licensee event report shall be completed and reference shall be made to the original report date.
1/ This tabulation supplements the requirements of $20.407 of 10CFR Part 20.
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1 A. Prompt Notificction With Written Follow-up. The types of c evsnto listed below shall be reported as expeditiously as possible, but within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by telephone and confirmed by telegraph, ma11 gram, or facsimile transmission to the appropriate Regional Office, no later than the first working l, day following the event, with a written follow-up report within two weeks. The written follow-up report shall include, as a minimum, a completed copy of a licensee event report form.
Information provided on the licensee event report form shall be supplemented, as needed, by additional narrative material to provide complete explanation of the circumstances surround-ing the event.
- 1. Failure of the reactor protection system or other systems subject to limiting safety system settings to initiate the required protective function by the time a monitored parameter reaches the setpoint specified as the limiting safety system setting in the technical specifications or failure to complete the required protective function.
Note: Instrument drift discovered as a result of testing need not be reported under this item but may be reportable under items 6.7.2.A.5, 6.7.2.A.6 or 6.7.2.B.1 below.
- 2. Operation of the unit or affected systems when any parameter or operation subject to a limiting condition is less conservative than the least conservative aspect of the limiting condition for operation established in the technical specifications.
Note: If specified action is taken when a system is found to be operating between the most conservative and the least conservative aspects of a limiting condition for operation listed in the technical specifications, the limiting condition for operation is not considered to have been violated and need not be reported under this item, but it may be reportable under item 6.7.2.B.2 below.
- 3. Abnormal degradation discovered in fuel cladding, reactor coolant pressure boundary, or primary containment.
Note: Leakage of valve packing or gaskets within the limits for identified leakage set forth in technical spec-ifications need not be reported under this item.
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Nota: This itsn is intend d to provida for reporting of potentially generic problems.
B. -Thirty Day Written Reports. The reportable occurrences discussed below shall be the subject of _ written reports to the appropriate l Regional Office within thirty days of occurrence of the event.
The written report shall include, as a minimum, a completed copy of a licensee event report form. Information provided on the licensee event report form shall be supplemented, as needed, by additional ~ narrative material to provide complete explanation of the circumstances surrounding the event.
- 1. Reactor protection system or engineered safety feature instrument settings which are found to be less conserv-ative than those established by the technical specifica-tions but which do not prevent the fulfillment of the -
functional requirements of affected systems.
- 2. Cohditions leading to operation in a degraded mode permitted by a limiting condition for operation or plant shutdown required by a limiting condition for
. operation.
Note: Routine surveillance testing, instrument calibration, or preventative maintenance which require system configurations as described in items 6.7.2.B.1 and 6.7.2.B.2 need not be reported except where test results themselves reveal a degraded mode as described above.
- 3. Observed inadequacies in the implementation 'of admin-istrative or procedural controls which threaten to cause reduction of degree of redundancy provided in reactor protection systems or engineered safety feature systems.
- 4. Abnormal degradation of systems other than those specified in itea 6.7.2.A.3 above designed to contain radioactive material resulting from the fission process.
Note: Scaled sources or calibration sources are not included under this item. Leakage of valve packing or gaskets within the limits for identified leakage set forth in technical specifications need not be reported under this item.
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Enclorura 2 e
Appendix B
" Environmental Technical Specifications" Discussion of Changes The following blank pages.are being combined to reduce volume:
Pages 3 through 5-Pages 3r through 40 Pages 68 through_76 k
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