ML19347F467
| ML19347F467 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 05/08/1981 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML19347F465 | List: |
| References | |
| NUREG-0011, NUREG-0011-DRFT, NUREG-0011-DRFT-S05, NUREG-11, NUREG-11-DRFT, NUREG-11-DRFT-S5, NUDOCS 8105190343 | |
| Download: ML19347F467 (81) | |
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NUREG-0011 Supp. No. 5 P
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SUPPLEMENT NO. 5 TO THE t
SAFETY EVALUATION REPORT BY THE I
0FFICE OF NUCLEAR REACTOR REGULATION l
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U.S. NUCLEAR REGULATORY COMMISSION IN THE MATTER OF l
TENNESSEE VALLEY AUTHORITY SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2 i
I DOCKET NOS. 50-327 AND 50-328 i
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'8105190 M 3
t' TABLE OF CONTENTS Pa2!
1 INTRODUCTION AND GENERAL DISCUSSION................................
1-1 1.1 Introduction..................................................
1-1 4 -
2 SITE CHARACTERISTICS...............................................
2-1 2.2 Nearby Industrial, Transportation, and Military Facilities....
2-1 2.3 Meteorology..................................................
2-2.6 Foundation....................................................
2-2.6.3 Foundation Evaluations.................................
2-6 ENGINEERED SAFETY FEATURES........................................
6-6.2 Containment Systems..........................................
6-1 6.2.6 Containment Leakage Testing Program...................
6-7 INSTRUMENTATION AND CONTR0L........................................
7-1 7.2 Reactor Trip System...........................................
7-1 7.2.2 Process Analog System (Environmental Qualification)....
7-1 9
AUXILIARY SYSTEMS.............................................
9-1 I
9.5 Fire Protection System............
9-1 1
11 RADI0 ACTIVE WASTE MANAGEMENT.......................................
11-1 1
17 QUALITY ASSURANCE..................................................
17-1 i
TABLE OF CONTENTS (Continued)
Pag 22 TMI-2 REQUIREMENTS.................................................
22-1 22.2 Full-Power Requirements......................................
22-1 I.
Operational Safety......................................
22-1 I. A.1.1 Shift Technical Advisor.......................
22-1 I. A.1. 3 Shift Manning.................................
22-
- 1. B.1.1 Organization and Management Criteria..........
22-I.B.l.2 Independent Safety Engineering Group..........
22-I. C.1 Short-Term Accident Analysis and Procedure Revision..............
22-I.C.6 Verify Correct Performance of Operating Activities....................................
22-I.D.1 Control Room Design Review....................
22-I.D.1 Plant-Safety Parameter Display Console........
22-I. G.1 Training During Low-Power Testing.............
22-II. Siting and Design.......................................
22-II.B.1 Reactor Coolant System Vents..................
22-II.B.2 Plant Shielding...............................
22-II.B.4 Training For Mitigating Core Damage...........
22-II.B.7 Analysis of Hydrogen Contro1..................
22-II.D.1 Relief and Safety Valve Test Requirements.....
22-II.E.1.1 Auxiliary Feedwater System Reliability Evaluation....................................
22-II.E.4.2 Containment Isolation Dependability...........
22-II.F.2 Instrumentation for Detection for ICC.........
22-II.K.2.17 Potential for Voiding in the RCC During Transients.............................
22-II.K.2.19 Sequential Auxiliary Feedwater Flow Analysis..
22-II.K.3 Final Recommendations of B&O Task Force.......
2'-
ii
TABLE OF CONTENTS (Continued)
Pjyle II.K.3.1 Installation and Testing of Automatic Power-Operated Relief Valve Isolation System.,
22-II.K.3.2 Report on Overall Safety Effect of Power-Operated Relief Valve Isolation System........
22-II.K.3.5 Automatic Trip of Reactor Coolant Pumps During Loss-of-Coolant Accident...............
22-II.K.3.9 PID Controller Modi fication...................
22-II. K.3.10 Proposed Anticipatory Trip Modi fication.......
22-II.K.3.11 Justification for Certain P0RVs.............
22-II.K.3.12 Anticipatory Trip Turbine Trip................
22-II.K.3.17 Report on Outage of ECCS License Report and Prepared Technical Specification Changes......
22-II. K. 3. 25 Powe r on Pump Sea 1 s...........................
22-II.K.3.30 Revised Small Break Loss-of-Coolant Accident Methods..............................
22-II.K.3.31 Plant-Specific Calculations...................
22-III. Emergency Preparations and Radiation Protection.........
22-III.0 Worker Protection.............................
22-III.A.1.1 Upgrade Emergency Preparedness................
22-III.A.1.2 Upgrade Emergency Support Facilities..........
22-III.A.2 Long-Term Emergency Preparedness..............
22-III.B.2 Implementation of NRC and FEMA Responsibility.
22-III.D.1.1 Primary Coolant Sources Outside Containment...
22-III.D.2.4 Offsite Oose Measurements.....................
22-III.0.3.4 Control Room Habitability.....................
22-1 22.3 Dated Requirements...........................................
22-I.
Operational Safety......................................
22-I.A.1 Operating Personnel and Staffing..............
22-fii
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TABLE OF CONTENTS (Continued)
Page II.
Siting and 0esign.......................................
22-III. Emergency Preparations and Radiation Protection.........
22-
-III.A.1.2 Upgrade Emergency Support Facilities..........
22-24 REACTOR SAFETY STUDY METHODOLOGY APPLICATION PROGRAM...............
24-1 Tables and Figure 3..................................
Table 1-1 Reference SSERs..............................................
F i g u re 2-1 Ma p o f A re a.................................................
Figure 2-2 Picture of Area.............................................
APPENDIX A CHRONOLOGY FOR RADIATION SAFETY REVIEW 4
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iv
1.0 INTRODUCTION
AND GENERAL DISCUSSION 1.1 Introduction On September 17, 1980, we issued a license to operate Sequoyah Unit No. 1 at full power in accordance-with the facility license and Technical Specifications.
This was based on our Safety Evaluation Report and Supplements 1 through 4 which are applicable to Sequoyah Units 1 and 2.
The TMI-2 requirements imposed have been specifically approved by the Commission for implementation in new operating licenses.
The requirements are derived from NRC's Action Plan (NUREG-0660) and are found in NUREG-0694, "TMI-Related Requirements for New Operating Licenses," as clarified and supplemented by NUREG-0737, " Clarification of TMI Action Plan Requirements," dated November 1980.
The purpose of this supplement is to update our evaluations on issues identified in the previous SER and supplements that need resolution prior to licensing Unit No. 2; and to clarify or supplement, as necessary our evaluations to be censistent with NUREG-0737.
The following sections of this supplement are numbered to correspond to identi '
cally numbered sections of the Safety Evaluation Report and the earlier supple-ments.
Except where noted, the material herein supplements material in the SER and Supplement Nos. 1, 2, 3, and 4.
The following table 1-1 provides a SSER reference for discussions on TMI-related items for licensing Sequoyah Units 1 and 2.
We conclude that the Sequoyah Unit No. 2 may be operated safely at full power in accordance with the facility license and Technical Specifications without undee risk to the health and safety of the general public.
l 1-1 Sequoyah SSER#5/Stahle 1/B
l Table 1.1 SSER Reference Table on NUREGs 0694 and 0737 I
for Fuel Load and Full Power Requirements fcr Sequoyah, Units 1 and 2 Supplements License Conditions Item Shortened Title 1
2 3
4 5
Unit 1 Unit 2 I.A.1.1 Shift technical advisor X
X X
X X
I.A.l.2 Shift supervisor i
responsibilities X
I.A.1.3 Shift manning X
X X
I.A.2.1 Immediate upgrade of R0 & SRO training and qualifications X
I.A.2.3 Administration of training programs X
I.A.3.1 Revise scope & criteria for licensing exams X
I.B.1.1 Organization and management criteria X
X X
I.B.1.2 Independent Safety Engineering Group X
X X
X I.B.l.4 Licensee Onsite Oper-ating Experience Evaluation Capacity X
I.B.2.2 Resident Inspector X
i I. C.1 Short term accident and procedure review X
X X
X X
I.C.2 Shift and relief turn-over procedures X
l I.C.3 Shift supervisor responsibility X
I.C.4 Control-room access X
I.C.5 Feedback of operating experience X
1-2 Sequoyah SSER#5/Stahle 1/B
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Table 1.1 (continued)
Supplements License Conditions Item Shortened Title 1
2 3
4 5
Unit 1 -Unit 2 I.C.6 Verify correct per-formance of operating activities X
i i
I. C. 7
-NSSS vendor rev of proc X
X I.C.8 Pilot mon of selected 4
emergency proc for NTOLs X
l I.D.1 Control-room design reviews X
X X
X l
l I.D.2 Plant-safety param-eter display console X
i I.G.1 Training during low power testing _
X X
X II.B.1 Reactor-coolant-system vents X
X X
X II.B.2 Plant shielding X
X X
X II.B.3 Postaccident sampling X
X X
II.B.4 Training for mitigating core damage X
X X
II.B.7 Analysis hydrogen control X X
X X
X X
X II.B.8 Rulen.a. '.ig proceeding on degraded core accidents X
II. O.1 Relief and safety-valve X
X t
II.D.2 lest requirements X
X X
II.D.3 Relief and safety X
II.D.5 Valve position indication X l
II.E.1.1 Auxiliary feedwater system evaluation X
X X
X 1-3 Sequoyah SSER#5/ Stable 1/8 L
t Table 1.1 (continued)
Supplements License Conditions Item Shortened Title 1
2 3
4 5
Unit 1 Unit 2 II.E.1.2 Auxiliary feedwater system initiation and flow X
X X
II.E.3.1 Emergency power for pressurizer heaters X
j II.E.4.1 Dedicated hydrogen l
X II.E.4.2 Containment isolation dependability X
X X
II.F.1 Accident-monitoring instrumentation a.
Noble gas monitoring X
X X
-X b.
Iodine particulate
~
s upling X
X c.
Containment high-range monitor X
X X
X
- d. _ Containment pressure X
X X
e.
Containment water level X
X f.
Containment hydrogen X
X II.F.2 Instrumentation for 4
detection of inadequate core-cooling X
X X
X X
i II.G.1 Power supplies for pressurizer relief valves, block valves, and level indicators X
II.K.1 IE Bulletins 5.
review ESF valves X
- 10. operability status X
- 17. trip per low-level B/S X
II.K.2 Orders on plants
- 17. Voiding in RCS X
X
- 19. Benchmark Analysis seq. AFW flow X
X 1-4 Sequoyah SSER#5/Stahle 1/B
o a
P Table 1.1 (continued) f
-Supplements License Conditions-i Item Shortened Title 1
2 3
4 5
Unit 1 Unit 2 II.K.3 Final recommendations, B&O Task Force
{
1.
Auto PORV isolation X
2.
Report on PORV failures X
l 3.
Reporting'SV and l
RV failures and challenges X
5.
Auto trip of RCPs X
9.
PID controller X
l
- 10. Applicant's pro-
)
pose anticipatory I
trip at high powv X
i 4
- 11. Justification use i
l of certain PORVs X
t
- 12. Conform anticipatory trip X
- 17. ECCS outages X
- 25. Power on pump seals X
- 31. Plant specific X
X III.A.1.1 Emergency preparedness, short term X
X X
X III A.1.2 Upgrade emergency tupport facilities X
X X
X X
III.A.2 Emergency preparedness X
X III.A.3 Upgrade license emergency preparedness X
X
.A I II.A.3.3 Communications X
III.B.1 NRC approval of overall emergency preparedness X
1 III.B.2 Implementation of NRC and FEMA responsibility X
III.D Worker Protection X
X III.D.1.1 Primary coolant outside containment X
1-5 Sequoyah SSER#5/ Stable 1/8 i
6 Table 1.1 (continued) r Supplements License Conditions t
Item Shortened Title 1
2 3
4 5
Unit 1 Unit 2 j
III.D.2.4 Offsite dose measurements X
III.D.3.3 Inplant I2 radiation monitoring X
X III.D.3.4 Control-room habitability X
IV.F.1 Power ascension test X
Note:
(a)
NUREG-0737 combined some of the NUREG-0694 items for clarity.
(b)
Some title changes have been made in NUREG-0737 from the previous TMI requirement documents.
1-6 Sequoyah SSER#5/ Stable 1/8 i
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2.0 SITE CHARACTERISTICS 2.2 Nearby Industrial, Transportation, and Military Facilities In our SER Supplement No. 2 of August 1980, we indicated that TVA would provide an analysis on the probability of an upstream barge collision with the new intake structure (ERCW) in response to a question raised by the ACRS in their review of the Sequoyah operating license (letter dated July 17, 1980 from R. F. Fraley to W. J. Dircks).
TVA, on April 6, 1981, submitted an analysis of an upstream barge tow which indicated a random probability of collision with the C3 ft. x 118 ft. intake structure of 1.6 x 10.s/ year.
This was based on 3 groundings on the Chickamuga Reservoir in 34 years that were judged to be relevant to the risk analysis.
TVA also described the features of the site, navigational aids and barge maneuverability which they indicated would further reduce the probability of collision.
In order to verify independently the applicants' analysis, members of the staff contacted the U.S. Coast Guar.1 and in addition traveled up to the site on the Chickamuga Raservoir on a U.S. Coast Guard tow boat and barge.
Based on conversation with the Nashville, Tennessee office of the U.S. Coast Guard, it was indicated that in good weather the cooling towers are visible and that navigation on the reservoir near to the reactor site is not a problem.
The trip on the Coast Guard tow boat on April 8,1981, indicated to the staff that the river is well marked with channel buoys and lights and that the shore line in the vicinity of the site is quite visible on radar for barge traffic in inclement weather.
Normal up-river barge traffic is guided by a day marker and light on the farside of the channel directly opposite the site. These features guide upstream traffic away from the Sequoyah intake structure.
The navigation channel in the vicinity of the site is approximately 1100 feet wide.
There are prominent features, namely the cooling pond dike, and the skimmer wall dike extending out into the reservoir, which would tend to keep 2-1 Sequoyah SSER#5/ Stable 1/C
up-river barge traffic from the area of the intake structure, if the tow for some reason violated the " Western Rules of the Road" and approached the reactor site on the wrong side of the river.
In addition, the skimmer wall, composed of 12 rock filled steel cassons 20 feet in diameter, capped with 18 inches of j
concrete and connected with 30 inch thick concrete skimmer walls would tend to deflect upstream barges before they could impact with the downstream side of the intake structure.
(See Figure 1.) In event of loss of power, the river current would move a barge tow towards the opposite side of the lake and away from the intake structure.
The reservoir at mile marker 485 is approximately 4200 feet wide (See Figure 2).
The strobe lights on the two cooling towers are visible even in daylight at several miles from the plant, and there are flood lights on the roof of the ECRW which would give an indication of its position in darkness.
In addition, the ERCW structure is now indicated on the navigation charts for the Chickamuga Reservoir.
In conclusion, it is the staff's qualitative judgement that the presence of the downstream cooling pond dike, and the skimmer wall and skimmer wall dike will tend to reduce the target length of the ECRW from 200 feet to 118 feet.
This would reduce the estimated probability of collision to 9.5 x 10 8 per year for random grounding.
Taking into consideration the use of Coast Guard regulations on water travel, barge manueverability, modern navigational aids and the geometric location of the intake structure on the shoreline, the staff judges that the probability for impact into the ERCW is lower than that determined for a randov grounding and is estimated to be of the order of 10 7/ year. This value is within the guidelines described in Standard Review Plan Section 2.2.3 and is acceptable.
In addition to the collision probability, the ACRS requested infomration on the ability of the ERCW intake to withstand the effects of barges carrying flammable cargoes including liquid natural gas (LNG).
1 l
2-2 Sequoyah SSER#5/ Stable 1/C
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i Figure 1 2-3 Sequoyah SSER#5/ Stable 1/C
Figure 2 t
2-4 Sequoyah SSER#5/Stahle 1/C
f 6.0 ENGINEERED SAFETY FEATURES 6.2 Containment Systems 6.2.6 Containment Leakage Testing Program By letter dated April 23, 1981, the applicant requested an exemption for Sequoyah Nuclear Plant Unit 2 from certain requirements of 10 CFR Part 50, Appendix J, paragraph II.D.2(b)(ii), which states:
" Air locks opened during periods when containment integrity is not requred by the plant's Technical Specifications shall be tested at the end of such periods at not less than P,."
Whenever the plant is in Mode 5 (cold shutdown), Containment Integrity is not required. Hence, if an air lock is opened during Mode 5 operations, paragraph II.D.2 (b)(ii) requires that an overall air lock leakage test at not less than P be conducted prior to entry into Mode 4.
a Even if the periodic six month test required by paragraph III.D.2(b)(i) of Appendix J has been satisfied, to meet the requirement of paragraph III.D.2(b)(fi), no access to the containment can be allowed while preparing to leave Mode 5 until every air lock that has been opened in Mode 5 is first tested and the plant has entered Mode 4.
The test would effectively be required every time mode 5 was entered.
The containment would have to be cleared of employees during performance of this test or they would be required to remain inside containment during the test and until the plant reached mode 4.
Usually there are several minor operational and maintenance problems that require containment entry just prior to entering Mode 4; the special air lock test would have to wait until all problems requiring containment entry were first corrected. This is a very restrictive requirement and would slow the process of returning to operation.
If the periodic six month test of paragraph III.D.2(b)(i) and the test required by paragraph III.D.2(b)(iii) are current, no maintenance has been performed on the air lock, and the air lock is properly 6-1 Sequoyah SSER#5/ Stable 1/J
sealed, there should be no reason to expect the air lock to leak excessively just because it has been opened in Mode 5 or Mode 6.
Accordingly, we conclude that the applicant's proposed approach of substituting the seal leakage test specified in Technical Specifications surveillance requirement 4.6.1.3.a, is acceptable when no maintenance has been performed on air lock. Whenever maintenance has been perfomed on an air lock, the require-ments of paragraph III.D.2(b)(ii) must still be met by the licensee.
Therefore, an exemption from this requirement (10 CFR Part 50, Appendix J, para-graph III.D.2 (b)(ii) is justified and acceptable for Sequoyah Unit 2.
The Technical Specification surveillance requirement 4.6.1.3.b for Sequoyah Unit No. 2 is rewritten as follows:
By conducting an overall air lock leakage test not less than P, (12 psig) and by verifying the overall airlock leakage rate is within its limit:
1.
At least once per six months, and 2.
Prior to establishing CONTAINMENT INTEGRITY if open.ed when CON TAINMENT INTEGRITY was not required when maintenance has been performed on the air lock that could affect the air lock sealing capability.
6-2 Sequoyah SSER#5/ Stable 1/J
7.0 INSTRUMENTATION AND CONTROL 7.2 Reactor Trip System 7.2.2 Process Analysis System Environmental Qualification for Safety-Related Electrical Equipment In Supplement No. 2 to the SER we stated that we would conduct our review ir accordance with Commission Memoranda and Orders dated May 23, 1980.
The staff conducted audits on August 5 and 6, 1980 and December 17-19, 1980 of the Environmental Qualification Documentation and/or test data for electrical equipment which could be exposed to a harsh environment.
In addition to the audit, the staff reviewed the licensee's systems evaluation and service con-ditions, and compared the qualification values with the specified values required by the licensee's design. The preliminary results of the staff's review are being complied with and an equipment evaluation report will be sent to the licensee.
In addition, an equipment qualification safety evaluation report is being completed and will be issued to the licensee which will include the require-ments and conclusions regarding the staff's review.
Within 90 days of receipt of the safety evaluation, the licensee should provide documentaton of any missing information identified in the SER, which demonstrates that the equipment meets the NUREG-0588, or commit to a corrective action (requalification, replacement, relocation, etc.) consistent with the raquirements to establish compliance by June 30, 1982.
If this option is chosen, the licensee must provide justification for operation until such corrective action is complete.
In addition, complete and auditable records must be available and maintained at a central location, which describes the environmental qualification method used for all safety related electrical equipment in sufficient detail to document the degree of compliance with NUREG-0588.
7-1 Sequoyah SSER#5/ Stable 1/0
9.0 AUXILIARY SYSTEMS 9.5 Fire Protection Systems [ Rewrite say-be required.]
In Supplement No. 2 to the safety evaluation report, we stated that when the proposed rule concerning fire protection and its Appendix R become effective, applicable provisions would be implemented in accordance with the rule.
By letter dated April 2, 1981, the licensee stated that only Parts III.G (Fire Protection of Safe Shutdown Capacity), III.J (Emergency Lighting), and III.0 (011 Collection System for Reactor Coolant Pumps) could be considered as i
applicable additional requirements.
TVA considers that no modifications a'e r
' quired at Sequoyah as a result of Appendix R.
We will condition the license for Sequoyah Unit No. 2 requiring the licensee to comply with Appendix R to 10 CFR 50 in accordance with the requirements of 10 CFR Part 50.48.
Also, Supplement No. 2 identified further fire protection modifications that would be needed dealing with the essential raw cooling water supply prior to Unit 2 startup.
These modifications are expected to be completed in June 1981.
Since the system is needed for two-unit operation, TVA proposed in their i
letter of March 9,1981 the following measures until the fire protection modifications are complete:
(1) A continuous fire waten in the area of ERCW junction box on elevation 690.0 of the auxiliary building.
(2) A roving fire watch in the area of the conduits which exit the top of the junction box, pass through floor elevation 714.0, and terminate on floor elevation 734.0.
This interim measure is acceptable to the staff.
[ Add position on carpet / ceiling tile.]
9-1 Sequoyah SSER#5/ Stable 1/E
9 11.0 RADIOACTIVE WACTE MANAGEMENT
-Process Control Program (PCP)
On April 3,1981, TVA submitted a revised PCP describing the methodology for packaging radioactive spent-resins generated at Sequoyah Nuclear Plant Units 1 and 2.
At this time, the solid radioactive waste treatment system described in NUREG-0011 (March 1979) and Supplement 1 (February 1980) is capable of dewatering radioactive spent-resin from the shared system and a portable demineralizer system installed for treating wastes from the plant.
Plans are underway to revise the method for solidifying " wet" radioactive wastes to meet the acceptable criteria for offsite shipment and subsequently revise the PCP by July 3, 1981. The staff has re reviewed the inventory, generation, and retention of spent-resins and finds that there is adequate capacity in the design for the solid radioactive waste treatment system, and that the PCP for dewater resin and plant procedures are acceptable.
The technical specifications for Unit No. 2 will utilize the approved PCP for solidification at Units 1 and 2.
11-1 Sequoyah SSER#5/ Stable 1/F
l 17.0 QUALITY ASSURANCE In Supplement No. 2 to the SER we stated that our review of the quality assurance program description for the operations phase for the Sequoyah Nuclear Plant veriffel that the criteria of Appendix B to 10 CFR Part 50 have been adequately addressed in Chapter 17 of the FSAR.
This determination of accepta-bility included a review of the list of items to which the quality assurance program applies.
The list of items was reviewed by the technical review branches to assure that safety-related items within their scope of review fall under the quality assurance program controls.
The l?st has been expanded to include safety-related items reflected in NUREG-0737, " Clarification of TMI Action Plan Requirements," November 1980.
Differences between the staff and the applicant regarding the list have been resolved-to the staff's satisfaction.
Therefore, the staff has no open items concerning the quality assurance program for operations or to what the program applies.
17-1 Sequoyah SSER#5/ Stable 1/G
22.0 MI REQUIREMENTS 22.2 Full-Power Requirements I.
Operational Safety t
I.A.1 Operating Personnel and Staffing I. A.1.1 Shift Technical Advisor The Shift Technical Advisor shall have a technical education which is taught at the college level and is equivalent to at,out 60 semester hours in basic subjects of engineering and science and specific training in the design, function, arraigement, and operation of plant systems in the expected response of the plant and instruments to normal operation, transients, and accidents including multiple failures of equipment and operator errors.
This requirement shall be.T.et by January 1,1981.
See NUREG-0578, Section 2.2.lb and letters of September 27 and November 9, 1979.
Discussion in a letter dated November 13, 1980, TVA submitted a description of their STA training program and their plans for requalification training. TVA stated i
that the STAS on duty beginning January 1,1981 have completed this program.
The STA training program covers : 1e uvne technical areas as listed in the INPO document entitled " Nuclear Power Plant Shift Technical Advisor Recommendations for Position Descriptions, Qualifications, and Education and Training."
We find that this requirement of NUREG-0737 has been satisfied.
22-1 Sequoyah SSER#5/Stahle 1/H
I.A.1.3 Shift Manning Position This position defines shift manning requirements for normal operation.
The letter of July 31, 1980 from D. G. Eisenhut to all power reactor licensees and applicants (copy attached) sets forth the interim criteria for shift staffing (to be effective pending general criteria that will be the subject of future rulemaking). Overtime restrictions were also included in the July 31, 1980 4
letter.
Discussf n 2
TVA meets the requirements for shift manning for one unit operation at Sequoyah Nuclear Plant.
Sequoyah Unit 1 Technical Specification 6.2.2, " Unit Staff,"
lists the minimum snitt crew for single unit operation.
The Technical Specifica-tions for Unit No. 2 include minimum shift crew requirements for operation of two units with a single control room. We consider this requirement of NUREG-0737 is met.
The Unit 1 Technical Specification will be revised to be consistent with Unit 2 specifications.
I.C.1 Guidance for the Evaluation and Development of Procedures for Transients and Accidents Position In letters of September 13 and 27, October 10 and 30, and November 9, 1979, the Office of Nuclear Reactor Regulation required licensees of operating plants, applicants for operating licenses and licensees of plants under con-struction to perform analyses of transients and accidents, prepare emergency procedure guidelines, upgrade emergency procedures, including procedures for operating with natural circulation conditions, and to conduct operator retraining (see also item I.A.2.1).
Emergency procedures are required to be consistent with the actions necessary to cope with the transients and accidents analyzed.
Analyses of transients and accidents were to be completed in early 1980 and implementation of procedures and retraining were to be completed 3 months 22-2 Sequoyah SSER#5/ Stable 1/H
after emergency procedure guidelines were established; however, some difficulty in completing these requirements has been experienced.
Clarification of the scope of the task and appropriate schedule revisions are being developed.
In the course of review of these matters the staff will follow up on the bulletin and orders matters relating to analysis methods and resu!ts, as listed in NUREG-0660, Appendix C (see Table C.1, items 3, 4, 16, 18, 24, 25, 26, 27; Table C.2, items 4, 12, 17, 18, 19, 20; and Table C.3, items 6, 35, 37, 38, 39, 41, 47, 55, 57).
Discussion i
In Supplement No. 2, we stated that TVA provided an adequate response to this l
item in accordance with NUREG-0694. The issuance of NUREG-0737 provided further guidance on this matter.
In a letter dated Decemter 19, 1981, TVA stated they were a member of the Westinghouse owners' group which is responcling to the requirements for this item. On this basis we consider this requirement satisfied.
I.3.1.1 Organization and Management Criteria The material in this Section is in addition to that stated in Section I.B.1 of Supplement No. 1.
TVA is a very large utility with more than 45,000 employees.
It does its own design engineering and it handles its own construction using in-house forces; as a result, it has an impressive in-house technical capability to apply to potential problems. At the same time, TVA has a large commitment to nuclear l
power.
There presently are four TVA nuclear units in operation at two different sites (Browns Ferry 1, 2 and 3 and Sequoyah Unit 1).
In addition, there are 13 nuclear units under construction at six different sites, including Sequoyah Unit 2.
This is an enormous undertaking, particularly in view of the complexity of nuclear plant construction and the stringent safety requirements governing nuclear plant operation.
Not unsurprisingly, perhaps, some problems have been encountered.
l 22-3 Sequoyah SSER#5/ Stable 1/H
A memorandum from James P. O'Reilly, Director of the NRC's Region II office, dated January 30, 1981, to the Chairman, Systematic Assessment of Licensee Performance (SALP) Review Group, subject:
"SALP Board Results for Tennessee Valley Authority," provided an assessment of TVA's performance, both at the individual nuclear plant sites and on an overall basis, in comparison with other nuclear units within the NRC Region II area.
The report covered the
- 2riod from April 1,1979 to August 31. 1980, although evaluations of particular plants varied within this period; the report is available in the NRC's Public Document Room.
The report found that construction activities at four of the TVA nuclear plant sites, including Sequoyah Unit 2, were above average as compared to other plant sites within the Region II area.
Construction activi-ties at two sites were rated below average on the same basis.
Operational activities at the Browns Ferry site were rated as acceptable, but below average, in comparison to other operating plants in Region II, while operations at Sequoyah Unit 1 were rated as acceptable.
Problems identified at the individual sites reflect an apparent unevenness of management attention to some areas, notably quality assurance and adherence to procedures.
Overall, the SALP evaluation of TVA was as follows:
It is difficult to arrive at an overall evaluation due to the many dif-ferent inputs to the evaulations (i.e., construction and operation) with these inputs providing widely divergent results.
An overall evaluation of TVA places it slightly below average for utilities in Region II.
TVA's largeness is not providing the excellence of operations that it is capable of, at operating or construction sit s.
Site discipline is lax as exemplified by their attitude toward procedural adherence and the apparent lack of control exercised by the supervisors.
Region II has identified these areas to TVA management and will continue to monitor their progress toward improved performance.
However, the evaluation also noted:
TVA is generally responsive to NRC regulations and findings of noncom-pifance.
TVA's size and large nuclear commitment have allowed tremendous 22-4 Sequoyah SSER#5/Stahle 1/H
technical support resources to be dev:, loped within its organization. TVA has initiated a Nuclear Safety Review Staff, which is to perform independent reviews of safety significant areas. This staff should provide valuable aid to focusing high level management attention on potential problem areas.
The SALP team audit of Sequoyah Unit 1 covered the period from August 1, 1979 to March 29, 1980. Since Sequoyah Unit 1 did not receive its 5% power operating license until February 29, 1980, this audit period covered only one month of plant operation. The overall evaluation of Sequoyah Unit 1 was:
The licensee performance of licensed activities is acceptable. This facility was recently licensed and therefore the evaluation as an opera-tional facility covers a relatively small period of time. Apparent trends in noncompliance and LER completeness will be closely monitored to ensure they are corrected.
Increased inspection scope is recommended for three areas to assure that corrective actions are adequately implemented.
NRR project manager indicated that good communications existed with the licensee and no problem areas had developed.
The three problem areas noted pertain to effluent monitoring, fire protection, and the quality and t'imeliness of subn'ission of Licensee Event Reports.
On February 11, 1981, an incident occurred at Sequoyah Unit 1 involving an inadvertent containment spray actuation.
Subsequent investigation by the NRC's Office of Inspection and Enforcement revealed that the event was largely attributable to a combination of inadequate training to Auxiliary Unit Operators, failure to implement or utilize procedures governing valve alignment in the Reactor Heat Removal system, and failure of administrative procedures to clearly delineate authorities and responsibilities for all operations personnel, specifically Auxiliary Unit Operators, involved in safety-related activities.
On the basis of (1) our knowledge of TVA, (2) our earlier evaluation of the TVA management capability for operation of the Sequoyah Nuclear Plant, (3) the 22-5 Sequoyah SSER#5/ Stable 1/H
results of the SALP team audit of TVA, and (4) the findings of the team investi-gating the February 11, 1981 containment spray actuation incident at Sequoyah Unit 1, we conclude that TVA does have the technical resources and management capability to support and control the safe operation of both Units 1 and 2 of the Sequoyah Nuclear Plant.
However, we consider that the SALP team audit and the investigation of the February 11 incident have revealed areas where TVA management needs to intensify their efforts to improve performance.
Specifically, these are:
1.
Training of Auxiliary Unit Operators, and other unlicensed personnel, whose activities in the plant may affect safety-related equipment and systems.
2.
Adequacy of and adherence to administrative procedures delineating authori-ties and responsibilities of all operations personnel, with specific attention to Auxiliary Unit Operators, engaged in safety-related activities.
I.B.1.2 Independent Safety Engineering Group POSITION An independent safety engineering group shall be established to increase the available technical expertise located onsite and to provide for continuing, systematic, and independent assessment of nuclear plant activities.
This group, which shall consist of not less f
.n five dedicated, full-time engineers, shall be physically located onsite, but shall report offsite to a high-level corporate official who is not in the management chain for power production.
The function of this group shall be to examine plant operating characteristics, NRC issuances, Licensing Information Service advisories, Licensee Event Reports, and other appropriate sources which may indicate areas for improving plant safety. Where useful improvements can be achieved, it is expected that this group will develop detailed recommendations for revised procedures, equipment modifications, or other means of achieving the goal of improved plant safety.
A principal function of the independent safety engineering group shall be to j
maintain surveillance of plant operations and maintenance activities to provide 22-6 Sequoyah SSER#5/Stahle 1/H
O-O independent verification that these activities are performed correctly and that human errors are reduced as much as practical.
The independent group shall not be responsible for sign-off function such that it becomes involved in the operating organization.
Discussion and Conclusion By letter of August 11, 1980, TVA agreed to maintain the independent safety engineering group.
This requirement has been incorporated in the Technical Specificatons for Units 1 and 2.
I.C.6 s
I.D.1 Control Room Design Review Position In accordance with Task Action Plan, NUREG-0660 and Clarification of Task Action Plan Requirements, NUREG-0737, all licensees and applicants for operating licenses will be required to conduct a detailed control room design review (DCRDR) to identify and correct human factors design deficiencies. This DCRDR is expected to take one (1) year and be completed around the middle of 1982.
Therefore, NRR requires applicants for OLs with expectcd fuel load dates occurring before completion of the one year review to make preliminary assess-ments of its control room, to identify significant human factors deficiencies and establish a schedule approved by the NRC for correcting deficiencies.
Discussion In Section IV of Part II of Supplement No.1 and Section 22.2, I.D.1 of Supplement No. 2 of NUREG-0011, we identified a number of corrective actions which we believed were necessary to improve the Unit 1 operator effectiveness during an upset or accident condition.
TVA was required to implement a number of corrective actions in the Unit 1 control room prior to criticality and several other corrective actions before escalation beyond 5 percent of rated power.
22-7 Sequoyah SSER#5/ Stable 1/H
o Because of the similarity between the Units 1 and 2 control rooms, we will require that all co'rrective actions specified for Unit 1 also be implemented on Unit 2, as appropriate.
In a letter dated August 11, 1980, TVA has docu-mented proposed changes to the Unit 2 control room with confirmation that Unit 1 improvements will be made on Unit 2 as appropriate.
C.
Conclusion We conclude that implementation of the Unit 1 improvements in Unit 2 will enhance the operator's detection and response capability to permit safe low power testing and full power operation. We anticipate no significant differ-ences between the corrective measures applied to. Units 1 and 2.
However, if differences are identified by TVA, HFEB will evaluate the differences. We will arrange for the I&E Resident Inspector to verify ' implementation of the
~
required corrective actions.
I.G.1 Training During Low-Power Testing Position The TMI Task Action Plan states that applicants for operating licenses will perform a set of low power tests to increase the capability of shift crews and ensure training in plant evolutions ar.d off-normal events. Near-term operating license facilities will be required to develop and implement intensified exercises during the low power testing programs.
This may involve the repetition of startup tests on different shifts for training purposes.
Discussion On March 31, 1981, the NRC agreed that the Special Low Power Test Program need not be performed on Sequoyah Unit No. 2 since most of the Sequoyah Unit No. 2 operators participated in the actual test program for Unit No. 1 and the other operators would receive simulator training on natural circulation which was revised to include the results of low power test program.
22-8 Sequoyah SSER#5/ Stable 1/H
0-o II.B.2 Plant Shielding Position Complete modification to assure adequate access to vital areas and protection of safety equipment following an accident resulting in a degraded core.
This requirement shall be met by January 1,1981.
(See NUREG-0578, Section 2.1.6b and letters of September 27 and November 9,1979).
Discussion In a letter dated June 16, 1980, TVA submitted the Sequoyah shielding design review report. No additional shielding is required at the Sequoyah Nuclear Plant.
Therefore, we find that this requirement of NUREG-0737 has been satisfied.
II.3.4 Training for Mitigating Core Damage Position Complete the training of all operating personnel in the use of installed plant systems to control er mitigate an accident in which the core is severely damaged. The training program shall include the following topics.
The training program shall include the following topics:
Incore Instrumentation 1.
Use of fixed or movable incore detectors to determine extent of core damage and geometry changes.
2.
Use of thermocouples in determining peak temperatures; methods for extended range readings; methods for direct readings at terminal junctions.
22-9 Sequoyah SSER#5/Stahle 1/H
l Excore Nuclear Instrumentation (NIS) k 1.
Use of NIS for determination of void information; void location basis for NIS response as a function of core temperatures and density changes.
Vital Instrumentation 1.
Instrumentation response in an accident environment; failure sequence (time to failure, method of failure); indication reliability (actual vs indicated level).
2.
Alternative methods for measuring flows, pressures, levels, and temperatures:
a.
Determination of pressurizer level if all level transmitters fail.
b.
Determination of letdown flow with a clogged filter (low flow).
c.
Determination of other Reactor Coolant System parameters if the primary method of measurement has failed.
Primary Chemistry 1.
Expected chemistry results with severe core damage; consequences of transferring small quantities of liquid outside containment; importance of using leak tight systems.
2.
Expected isotopic creakdown for core damage; for clad damage.
3.
Corrosion effects of extended immersion in primary water; time to failure.
Radiation Monitoring 1.
Response of Process and Area Monitors to severe damages; behavior of detectors when saturated; method for detecting radiation readings by 22-10 Sequoyah SSER#5/Stahle 1/H
i direct measurement at detector output (over-ranged detectors); expected accuracy of detectors at different locations; use of detectors to determine extent of core damage.
i 2.
Methods of determining dose rate inside containment from measurements taken outside containment.
Gas Generation 1.
Methods of H2 generation during an accident; other sources of gas (Xe, Kr); techniques for venting or disposal of noncondensibles.
2.
H flammability and explosive limit; sources of 02 2
in containment or Reactor Coolant System.
Discussion and Conclusions IVA has a training program that meets all the requirements stated above. This initial training program submitted on July 22, 1979, has been completed for all currently licensed Sequoyah Unit 2 operations personnel.
An abbreviated program of the operator training will be presented to managers and technicians in the Health Physics, Plant Chemistry, and Instrumentation and Controls Sections commensurate with their responsibilities in the event of a core damaging cccident.
By letter of May j_, 1981, TVA has confirmed implementation of this training program.
Training for STA's will be performed during the requalification training program. TVA has committed to completion of the initial training program by January 1, 1982.
Based on the foregoing, we have concluded that the Sequoyah Nuclear Plar,t has provided adequate training of all licensed operating personnel for Unit 2 in the use of installed plant systems to control or mitigate an accident in which the core is severely damaged.
22-11 Sequoyah SSER#5/Siable 1/H
o II.B.7 Ana?ysis of Hydrogen Control Position Reach a decision on the immediate requested, if any, for hydrogen control on small containments, and apply, as appropriate to new OLs pending completion of the degraded core rulemaking.
Discussion Item II.B.7 of the TMI Action Plan, NUREG-0660, May 1980, provides that certain analyses be performed relative to hydrogen control for nuclear plants with small containments. These analyses have been performed and the results reported in SECY 80-107, dated February 22, 1980.
The staff's licensing requirements relative to provisions for hydrogen control beyond those prescribed in 10 CFR Section 50.44 have evolved from numerous delibertations among the Corr.ission, the ACRS, the staff and applicants and licensees. A summary statement of the staff's requirements for ice condenser containments is that a supplemental hydrogen control system be providei so that the consequences of that hydrogen which is generated during the more probable degraded core accident sequences do not involve a breach of containment nor adversely affect the functioning of essential equipment.
For Sequoyah, Unit 2, the staff's licensing requi ements are substantially the same as those that were required for Sequoyah, Unit 1.
This mean that prior i
to full power licensing of Unit 2, the applicant must demonstrate to the staff's satisfaction by testing and analysis that the interim hydrogen control system will provide with reasonable assurance protection against breach of containment in the event that a substantial quantity of hydrogen is generated.
Moreover, the Tennessee Valley Authority (TVA) must provice on a timely schedule the bases for a Commission determination by January 31, 1981 that an adequate hydrogen control system for the plant is installed and will perform its intended function in a manner that provides adequate safety margins.
22-12 Sequoyah SSER#5/Stahle 1/H
The TVA has installedin Sequoyah, Unit 2 the Interim Distributed Ignition System (IDIS) for hydrogen control in the event of a degraded core accident.
-The IDIS installed at Unit 2 is similar to the system approved for Unit 1.
A discussion of the IDIS for Sequoyah, Unit 1 is contained in Supplements 3 and 4 of the Sequoyah Safety Evaluation Report (SER) (NUREG-011, 0422).
Based on the results of our review of the IDIS for Unit 1 and on the results of our review of a comparable system for the McGuire plant, we find that a distributed ignition system for Unit 2 is acceptable as an interim hydrogen control measure for degraded core accidents.
The evaluation of a deliberate ignition as a technique for hydrogen control is a topic of ongoing investigation by both the industry and the NRC. As a result of this ogoing review, including our work in connection with the McGuire proceeding, the staff has identified a number of issues which we have required TVA to address as part of the licensing action for Sequoyah, Unit 2.
These items include:
- 1) the potential for inerting the lower compartment of the containment and for the combustion phenomena producing a transition to detonation and 2) the effects of a postulated continuous burning in the upper plenum of the ice condenser.
Lower Compartment Inerting Inerting or rendering non-combustible a hudrogen-air mixture in the lower compartment with the addition of sto u or fog is a general concern for several reasons.
First, any mechanism which prevents combustion in the lower compart-ment increases the likelihood of producing coniitions leading to a constant volume combustion process.
As reported previously in Supplement 4 to the Sequoyah SER, the base case analysis performed by TVA for the S 0 transient 2
showed virtually all the hydrogen burning to occur in the lower compartment.
Since the lower compartment is only approximately one quarter of the total containment volume, combustion in the lower compartment involves a small quantity of hydrogen and allows for the expansion of the hot gases into ice bed and the upper containment thereby reducing the pressure.
i 22-13 Sequoyah SSER#5/ Stable 1/H
Another reason for concern' aver inadvertent inerting of the lower compartment is that a highly enriched hydrogen-air mixture may enter the upper plenum of the ice condenser due to steam condensation in the ice bed.
In order for this ot occur, it would be necessary to have coincident large hydrogen and steam fractions in the lower compartment.
If an enriched hydrogen mixture exists in the ice bed or in the upper plenum, there is an increased probability for the combustion phenomena to include a transiton to detonation.
This concern has been stated most notably by the Sandia National Laboratory as previously discussed in Supplement 4 to the SER.
The reason that additional attention to this topic is warranted is twofold.
First, the original base case analysis of the S 0 transient was truncated at a 2
point in time where approximately 80% of the core cladding had reacted.
There was no modeling of the core recovery by injection of water could result in large steam and hydrogen release rates that these releases could produce the lower compartment inerting conditions discussed above.
Thus, while the original analysis shows the lower compartment steam concentration to be less than 30%
over the period of interest, revised analyses might result in a substantially higher fraction.
Secondly, there is a possibility that ignition of hydrogen mixtures in the lower compartment may be suppressed by the presence of a water fog.
A fog is a suspension of liquid water in the form of droplets in the atmosphere. A fog can be created by bulk condensation of steam and the formation of droplets, will suppress the pressure and temperature following combustion is well known and there is evidence that a sufficient fog density may render normally combus-tion is well known and there is evidence that a sufficient fog density may render normally combustible mixtures nonflammable.
The presence of a water fog has been conjectured by several consultants as the explanation for the two anomalous igniter tests previously discussed in Supplement 4.
These anomalous tests, conducted by Lawrence Livermore National Laboratory (LLNL) and identified as tests 34 and 43, involved the initial introduction of steam to a 50% t.oncentration and operation of the glow plug with the steam concentration allowed to fall by condensation on the test vessel walls.
As 22-14 Sequoyah SSER#5/ Stable 1/H
previously noted in Supplement 4, combustion did not occur when expected although a slight pressure rise was recorded for test 34 when a circulating fan was activated. Continued testing of the glow plug igniter in high steam fraction environments is underway and it is the current position of LLNL that the presence of fog is insufficient as the sole explanation for the failure to achieve ignition under the test conditions.
LLNL has noted that tests involving steam addition other than tests 34 and 43, though at an initially lower steam concentration, were parformed using the same procedure and successful ignition was achieved.
LLNL, therefore, concludes that if a fog, of undetermined density and drop sizes, existed in the unsuccessful ignition tests at 50%
steam, it most probably also existed in the successful tests at 40% steam.
Visual observation of nonburning tests with steam injection did confirm that optical obscuraticn does occur and persists for some time after steam injection was terminated.
The staff has concluded that the igniter tests performed at LLNL were more likely to produce fogging as compared to the expected containment-wide conditions in the Sequoyah Nuclear Plant, d e to the test procedure and configuration.
When the various regions of the Sequoyah plant are considered, the LLNL test configuration most closely models the lower cc.npartment.
Since fogging appears to be due to a wall cooling effect, an important parameter is the ratio of wall surface area to atmosphere volume.
A comparison of these ratios between the LLNL test vessel and the Sequoyah plant, considering the surface area of the containment shell, shows that the LLNL test vessel has a much greater ratio of surface area to volume. Thus, the potential and effects of fogging would logically be expected to be greater inside the small vessel than in the Sequoyah containment.
For the moderate release rates of hydrogen associated with small-break, loss-of-coolant accidents, i.e., on the order of 30 lb/ min, it appears that burning can safely occur in other portions of the containment without creating unacceptably high pressures.
Further analysis is needed to confirm the effects of inerting but the staff believes that these may reasonably be deferred until final disposition of the proposed IDIS in January 1982.
[As will be discussed later, the information derived from
)
Duke's contentions on McGuire indicate that the upper plenum igniters will result in the controlled combustion of hydrogen by deflagration and not detonation even in the cases in which the lower compartment may become inerted].
'22-15 Sequoyah SSER#5/Stahle 1/H
TVA, at our request, has considered the potential for inerting the lower compartment with either steam or fog.
In order to address the issue of steam inerting TVA has committed to extend the base case S D scenario to include the 2
recovery phase of the transient.
The results of this analysis will be provided as part of the October 1981 submittal by TVA on the Permanent Hydrogen Mitigation System.
It is also TVA's preliminary judgment that neither a significant release of hydrogen nor lower compartment steam inarting from boiloff of the water supplied by a safety injection pump would occur following S D reflood.
2 The staff's calculations indicate that reflooding without serious hydrogen explusion is feasible during many phases of the period of core uncovery.
Nevertheless, there is a concern that under certain circumstances the hydrogen already accumulated as a bubble in the reactor vessel may be rapidly expelled during reflood together with sufficient steam for temporary inerting.
Because of the limited circumstances under which tnis 7,ituation seems to exist, the staff concludes that final resolution of this matter may reasonably be deferred until January 31, 1982.
Regarding the potential for fog formation TVA has provided arguments S N lar to those offered by the staff regarding the small scale of the test vessel.
Additionally, TVA has noted that during a small break degraded core accident with continuous superheated steam and hot hydrogen injection, there is less tendency for fog formation. This is due to the fact that additional sensible heat must be removed from the atmosphere before condensation can occur.
TVA also identifiad another mechanism, other than the wall cooling effect, by which fog may be formed.
This is at the discharge of the air return fan where colder upper compartment air is injected into the warmer lower compartment.
TVA has argued that in this situation the cooler air frce the upper compartment would tend to sink to the floor placing the cold / air warm air interface rway from the igniters and low in the volume where any fog would rain out to water on the floor.
Furthermore, TVA has concluded that given the hydrogen release rates for the base case S 0 scenario, inerting of the lowar compartment is unimportant since 2
burining in the ice condenser upper plenum would deplete the hydrogen with acceptable consequences.
22-16 Sequoyah SSER#5/Stahle 1/H
The staff concludes that more information is needed to satisfactorily explain the role that water fogging played in some of the LLNL igniter test.s.
Regardless of the outcome of this ongoing investigation we will require that the applicant provide additional information to jusstify the analytical assumptions regarding fog effects on igniter performance prior to concluding our review of the proposed ignition system. This additional information must quantitatively assess the formation of a fog and its effect on efficacy of the deliberate ignition system.
The major concern, as expressed by the Sandia National Laboratory (SNL), over inerting of the lower compartment is that if this occurs coincident with a moderately high hydrogen fraction (approximately 9 v/o) then a potentially detonable mixture would appear in the apper ice bed or upper plenum region.
It is the position of SNL that the effect of inerting in this situation could lead to conditions where combustion, due to the placement of upper plenum ingiters, might result in a transition to detonation.
The general issue of locating igniters in the ice condenser upper plenum was previously discussed in Supplement 4.
Originally there was concern by some consultants that the igniters themselves could initiate a detonation if the hydrogen concentration excetded a limit value of approximately 18 v/o.
Since that time, the staff has concluded based on the assessment of numerous consultants that the proposed glow plug igniter by itself is unlikely to initiate a detonation.
Further developments relating to this issue have occurred since issuance of Supplement 4 based on the Sandia citation of recent experimental combustion data which exhibited large pressures.
The significance of these test data is that obstacles in the path of a flame front tended to accelerate the combustion process dramatically to the point where measured pressures were much greater than would be expected for combustion of a similar mixture in an unobstructed chamber.
The scale of the experimental apparatus (10m x 2.5m) was also larger than much of that used as the basis for detonation theory.
It is the Sandia postulate that these experimental data show that the run-up distance required for a transition to detonation can be markedly decreased in the presence of obstances.
They further contend that obstructions in the ice condenser region of the plant could serve the same function; thus in order to avoid the possibility 22-17 Sequoyah SSER#5/ Stable 1/H
of unexpectedly large pressures, their recommendation is to try to avoid ignition in the ice condenser region.
Sandia, at this point, makes no claims that transition to detonation is likely but rather than the risk imposed by upper plenum igniters is higher than their benefit.
An additional item which the cited experim9ntal sought to address was the potential for detonation initiation by a strong turbulent jet.
This phenomenon has also been identified by Sandia as a possible mechanism for producing a detonation or large over-pressures in the ice condenser region.
f The staff met with Sandia in March 1981 in an attempt to better understand its position and the details of the experimental data.
Sandia, at this meeting, acknowledged tMt there were differencas between the experiments and conditions inside the ira condenser; the most notable being that the experiments were conducted with stoichiometric mixtures of propane and methane.
Sandia acknowledged that no experiments have been conducted with 8-10 v/o hydrogen mixtures and, therefore, it is not known to what extent off-stoichiometric conditions would influence flame propagation. The effec. of inerting the lower compartment would potentially be to release even richer mixtures to the upper plenum.
As a part of the staff's licensing review for McGuire, these items were discussed with the McGuire applicant's combustion consultants.
Their response, after having toured the plant, was that the geometry and flow conditions inside the ice condenser region of the plant simply are not conducive to producing a transition to detonation.
The McGuire consultar.t's view was that, for an S D 2
type scenario, the upper plenum igniters would ignite the mixture as it first becomes flammable, then as a richer mixture is vented to the upper plenum, the igniters will produce a horizontal standing flame.
If the mixture is further enriched then the flame will propagate downward into the ice bed until it settles to an equilibrium point where sufficient steam has been condensed.
In the opinion of the McGuire consultants, even if an inerted mixture with a high hydrogen concentration were introduced to the ice bed, the flame front wuld simply propagate to an equilibrium elevation where sufficient steam was condensed to support combustion.
The point being that the flame propagation will not allow the hydrogen-steam-air mixture to dry out to the point where detonable mixtures would develop.
22-18 Sequoyah SSER#5/Sta.e 1/H
[The testimony of the Duke consultants on McGuire indicate that the upper plenum igniters are of significant benefit in assuring controlled burning even in cases in which lower compartment inerting may occur.]
Continuous Burn ng i
The second general issue that was identified as part of the ongoing review was the item described as continuous burning in the upper ice condenser.
In Supplements 3 and 4 to t'.e SER, we described the CLASIX analyses which showed, for the base case, that virtually all combustion took place in the lower compartment. We also comaented on the advantages of combustion in that region; e.g., avoiding constant volume ?xplosions, and burning of smaller quantities of hydrogen.
I!owever, as a rart of the review uf the hydrogen mitigation system installed in the McGuire plant, the consultants of Duke Power Company presented witnesses at the hearing indicating that far hydrogen relcases calculated for the S D 2
scenario it is likely tabt continuous burning will occur at the top of the ice bed.
Since the hydrogen mitigation system at the McGuire plant is very similar to that installed at Sequoyah, the staff requested that TVA address the likelihood and consequences of continuous burning in the ice condenser upper plenum.
TVA's response to this request was that burning in the upper plenum has been and is considered to be a realistic condition in the containment burning response spectrum. TVA further states that the pattern of burning or the continuous nature of the burn would depend on the assumptions made regarding flammability limits.
TVA concludes that continuous burning in the upper plenum bounds one end of the possible burning conditions and that repeated lower compartment burns bounds the other end.
It appears that the reason significant burning does not occur in the upper plenum is the CLASIX analyses as reported in Supplements 3 and 4 is that the preliminary containment model included the upper plenum as part of the upper compartment volurce. Thus while the upper plenum may have a higher hydrogen concentration, it is in effect diluted by adding in the upper compartment volume and composition.
22-19 Sequoyah SSER#5/Stahle 1/H
A recent revised base case CLAsIX analysis using a separate volume to model the upper plenum does indeed show that semicontinuous burns would occur.
This case produced a peak containment pressure of approximately 24 psia, still well below the containment failure threshold.
The staff has considered this matter and concludes that continuous or near con-tinuous burning in the upper plenum is likely to produce the most benign pres-sure consequences for containment.
Burning in the upper plenum of the ice con-denser has the advaatages of:
- 1) burning a smaller quantity of hydrogen since 3
the upper plenum is a relatively small volume (approximately 50,000 ft );
- 2) combustion products are ventud to the large downstream volume of the upper compartment where they are cooled by the containment sprays; and 3) burning occurs in a region which is distant from most all of the essential equipment.
l While the staff believes that there are advantages to tt.e condition of continu-ous burning in the upper ice condenser section of the containment there is also the necessity to address the temperature effects of sustained burning in that region.
The primary concern over temperature effects is the impact on insulat-ing material in the ice condenser region.
As we discussed in Supplement 4 to the SER, the design of the ice condenser ltilizes polyurethane foam insulation.
When exposed to an external her.t source, the polyurethane foam behind the wall panel will undergo pyrolysis at a rate dependent on the foam temperature.
Pyrolysis or decomposition of the foam produces volatile gases with a heat of c.ombustion corresponding to approximately 12,000 Btu's per pound of foam.
Since the ice condenser contains approximately 30,000 lbs. of foam, it is apparent that large scale decomposition of the foam is unacceptable. We have, therefore, requested that TVA evaluate the themal response of the polyurethane foam for the condition where continuous burning occurs in the ice bed.
TVA in response to our query has referenced the analysis performed by Duke to answer the same question on the McGuire plant.
Since the construction of the ice con-I denser at Sequoyah is essentially the same as at McGuire, TVA concludes and the staff concurs, that the analysis should be equally valid.
The Duke analysis presented at the McGuire hearing assumed a standing flame in the ica bed which persists for 45 minutes, corresponding to the approximate 22-20 Sequoyah SSER#5/Stahle 1/H
duration of hydrogen releases.
The vast majority of the foam is separated from a potential flame by a thermal resistance path consisting of the two air hand-ling ducts, the downcomer and return sections.
At the joint connections between ducts, the foam is separated from the postulated flame by thin metal, but this represents a small fraction of the total foam mass and was accounted for in the Duke analysis. A heat transfer analysis was performed considering the effects of radiation, convection and conduction.
The Duke evaluation conservatively considered that as a result of heat transfer, approximately 250 lbs. of foam could decompose.
The gases thus produced would have a total heat of combustion of 3 x 108 Btu; by comparison to the 80 x 108 Btu associated with the hydrogen burning this incremental energy addition is inconsequential.
The staff has reviewed the analysis performed by Duke and concluded that pyrolysis of foam does not constitute any undue threat to containment integrity.
The staff has also performed confirmatory calculations and verified that the i
mass of foam which undergoes pyrolysis is insufficient to threaten containment integrity.
[These preliminary calculations should, however, be further devel-oped and confirmed as part of the further studies of the igniter system and the containment response.] During the course of its review of this issue the staff identifies that it appeared to be desirable to trip the air handling unit fans when the igniters are actuated.
The air handling unit fans take suction from the upper plenum and circulate the air thru the wall panel ducts.
Removing power from the ice condenser air handling units will eliminate forced circula-tion of potentially hot combustion products, in the event continuous burning occurred in the upper plenum, which would contribute to heat up of the foam.
Furthermore, tripping of the air handling units would reduce the potential for ingestion of hydrogen into the duct system.
In the McGuire proceeding, Duke considered the staff's suggestion, and subsequently committed to modify its procedures.
Accordingly, TVA has also evaluated the merit of this recommenda-tion and will modify its emergency operating instructions for Units 1 and 2 to remove power from the air handling units during hydrogen combustion events.
Prior to concluding its review of the proposed IDIS, the staff will also require that the igniter assemblies be demonstrated by test to perform their function 22-21 Sequoyah SSER#5/ Stable 1/H I
in a continuous burning environment since upper plenum igniters may be exposed to such conditions.
[The survivability of essential equipment in the event of hydrogen burning was considered in Supplement 4 to the SER where the staff concluded that there was reasonable assurance that essentiai equipment will survive repeated hydrogen burns and function properly to mitigate the consequences of a degraded core event and prevent breach of containment.]
[We indicated that further investigations to confirm these results would be provided to the staff in May 1981.
In the interim, in connection with our McGuire work, the staff made some further estimates presented in the McGuire hearings of the effects of burns on equipment survivability.
Using a Barton transmitter as typical of temperature sensitive equipment in the McGuire con-tainment, the staff calculated the temperature reached by the component after a series of 10 burns. This temperature was below 3203F.
This temperature is not significantly different from the maximum temperatures calculated for design basis accidents for McGuire (327 F for MSLB).
Although a repeat of these cal-culations was not done for Sequoyah the results would generally be the same, thus confirming our earlier conclusions in Supplement 4.
However, "" we pointed out in the Sequoyah Supplement No. 4 and in the McGuire proceedint unese esti-mated should be confirmed.]
II.D.1 Relief and Safety Valve Test Requirements Position Corplete Lasts to qualify the reactor coolant system relief and safety valves under expected operating conditions for design basis transients and accidents.
This requirement shall be met by July 1, 1981.
(See NUREG-0578, Section 2.1.2, and Letters of September 27 and November 9, 1979).
22-22 Sequoyah SSER#5/ Stable 1/H
4 Discussion In TVA's letter of December 19, 1980, the applicant referenced the EPRI PWR Relief and Safety Valve Test Program as its response to this requirement for
' Unit 2.
In accordance with NUREG-0737, the generic EPRI PWR RV/SV testing program will test the block valve designs used by the facility by July 1, 1981, and the NRC has established July 1,1932 as the date for verification of block valve functionability. The licensee will be conditioned to require that TVA provide evidence supported by text that the block or isolation valves between the pressurizer and each power-operated relief valve can be operated, closed, and opened for all fluid conditions expected under operating and accident conditions.
We finc TVA's commitment to follow the EPRI PWR RV/S5! test program for Sequoyah Units 1 and 2 to be acceptable to meet full power requirements.
II.E.1.1
$~
II.E.4.2 Containment Isolation Dependability Position Provide (1) containment isolation on diverse signals, such as containment pressure or ECCS actuation, (2) automatic isolation of nonessential systems (including the bases for specifying the nonessential systems), (3) no automatic reopening of containment isolation valves when the isolation signal is reset.
These requirements shall be met before issuance of a full power license.
See NUREG-0578, Section 2.1.4 (Ref. 4), and letters of September 27 (Ref. 23) and November 9, 1979 (Ref. 24).
Discussion In response to the requirement stated in NUREG-0757, TVA provided additional l
information on the Sequoyah containment pressure setpoint.
The Sequoyah contain-ment pressure high setpoint is required to be less than or equal to 1.54 psig 22-23 Sequoyah SSER#5/ Stable 1/H
a 0
by Technical Specification 3.3.2.1, " Engineering Safety Feature Actuation System Instrumentation." It is more than 1 psig above the highest primary containment internal pressure allowed by Technical Specification 3.6.1.4,
" Containment Internal Pressure," however, TVA believes that the present containment pressure high setpoint is adequate.
The reasons are stated below.
The containment pressure high channel actuates safety injection, turbine trip, and feedwater isolation.
Phase "A" containment isolation is actuated from the safety injection logic.
Reducing the containment pressure high setpoint increases the potential not only for inadvertent containment isolation but also inadvertent safety injection and feedwater isolation.
Adequate protection is already provided to prevent the release of radioactive materials following an accident.
Phase "A" isolation, which includes containment ventilation isolation, is initiated Dy diverse signals, including all safety injection actuation channels including low pressurizer pressure, high gaseous or particulate activity in containment, and high activity in the purge air exhaust.
The containment pressure high and high-high setpoints and low pressurizer pressure setpoints are reached almost immediately in large loss of coolant accidents (LOCA).
Lowering the containment pressure high setpoint will not provide any additional safety margin to the accident analyses because of the speed at which the containment pressure rises for large LOCAs.
Two cases for small LOCAs are considered:
those for which the charging system can maintain reactor coolant system inventory and those that cannot.
In the first case, core uncovery will not occur and the radioactivity released is limited to the material contained in the coolant.
Containment vent isolation will occur.
The setpoint for the ventilation isolation signals are set to prevent releases exceeding 10 CFR Part 20 'imits (normal release limits).
Lowering the containment pressure high setpoint will not provide any significant additional safety margin.
22-24 Sequoyah SSER#5/ Stable 1/H
.b In the second case, safety injection will always occur much sooner than core uncovery.
Since phase "A" isolation occurs on safety injection, radioactivity releases prior to isolation are limited to material contained in the coolant.
Containment vent isolation will occur.
Lowering the containment pressure high setpoint will not provide any significant additional safety margins.
Staff agrees that the present containment pressure high setpoint of 1.54 psig is adequate.
Reduction of this setpoint would provide no significant additional safety margin.
II.F.2 Instruments for Inadequate Core Cooling Position Licensees shall provide a description of any additional instrumentation or controls (primary or backup) proposed for the plant to supplement existing instrumentation (including primary coolant saturation monitors) in order to provide an unambiguous, easy-to-interpret indication of inadequate core cooling (ICC). A description of the functional design requirements for the system shall also be included.
A description of the procedures to be used with the proposed equipment, the analysis used in developing these procedures, and a schedule for installing the equipment shall be provided.
Discussion In Supplement Nos. 1 and 2, we stated that TVA would provide the reactor vessel water level instrumentation system by July 1,1982 and would provide a subcooling monitor prior to operation in order to provide an unambiguous, easy-to-interpret indication of ICC.
NUREG-0737 gave further clarification of item II.F.2 by adding Attachment 1,
" Design Qualification Criteria for Pressurized-Water Reactor Incore Thermocouples."
TVA responded to this attachment in their letter of April 13, 1981.
The licensee will submit proposed modifications by June 1, 9181 to the ICC monitoring system in response to attachment No. 1.
The staff's position is as follows:
22-25 Sequoyah SSER#5/ Stable 1/H
1.
The plant computer read-out of the-incore thermocouples are considered the primary display.
2.
The back-up display should be replaced by an indicator capable of temperature indication over the range of 200*F to 2300*F.
'3.
The back-up display should have the capability to read 16 thermcouples (4 per quadrant).
The input to the computer of this group of thermocouples should be through fully qualified isolation devices.
The isolation devices may be implemented by the use of manual switches, electronic or electromechanical multiplexers, or analog to digital converters upstream of the plant computer.
4.
The thermocouples to the back-up display should be separated from the balance of the computer input thermocouples in accordance with Regulatory Guide 1.75.
5.
The back-up display, T/C wiring, and reference T/C junction controls should be upgraded to seismic (Regulatory Guide 1.100) and environmental (Regulatory Guide 1.89) qualification requirements exclusive of those portions internal to the reactor vessel.
6.
The back-up system should be operable from a Class 1E power source or a suitable battery backed instrument bus.
This item is unresolved pending the results of our review of TVA's submittal.
Implementation of a system satisfactory to the staff will be required by June 1, 1982 unless a good course is provided for a delay in schedule.
II.K.2.17 Potential For Voiding In the RCC Ouring Transients Position Analyze the potential for voiding in the reactor coolant system (RCS) during anticipated transients.
22-26 Sequoyah SSER#5/ Stable 1/H
Discussion The Westinghouse owners' group (TVA is a member) is addressing the item. A report describing the results of this effort will be provided by January 1, 1982.
This is satisfactory to the staff.
II.K.2.19 5equential Auxiliary Feedwater Flow Analysis Position Provide a benchmark analysis of sequential auxiliary feedwater (AFW) flow to the steam generators following a loss of main feedwater.
Discussion The Westinghouse owners' group is addressing this matter and they will provide a report by July 1, 1982. This is satisfactory to the staff.
II.K.3.1 Installation and Testing of Automatic Power-Operated Relief Valve Isolation Ssatem Position All PWR licensees should provide a system that uses the PORV block valve to protect against a small-break loss-of-coolant accident.
This system will automatically cause the block valve to close when the reactor coolant system pressure decays after the PORV has opened. Justification should be provided to assure that failure of this system would not decrease overall safety by aggravating plant transients and accidents.
Each licensee shall perform a confirmatory test of the automatic block valve closure system following installation.
Discussion Staff implementation is delayed pending review of the results of II.K.3.2 22-27 Sequoyah SSER#5/Stahle 1/H
II.K.3.2 Report on Overall Safety Effect of Power-0perated Relief Valve Isolation System i
Position I
(1) The licensee should submit a report for staff review documenting the
~
various actions taken to decrease the probability of a small-break loss-of-coolant accident (LOCA) caused by a stuck-open power-operated relief valve (PORV) and show how those actions constitute sufficient improvements in reactor safety.
(2) Safety-valve failure rates based on past history of the operating plants designed by the specific nuclear steam supply system (NSSS) vendor should be included in the report submitted in response to (1) above.
Discussion The Westinghouse owners' Group submitted a report to address the NRC concerns on this item.
(WCAP 9804, dated April 1981)
II.K.3.5 Automatic Triu of Reactor Coolant Pumps During Loss-of-Coolant Accident Position Tripping of the reactor coolant pumps in case of a loss-of-coolant accident (LOCA) is not an ideal solution.
Licensees should consider other solutions to the small-break LOCA problem (for example, an increase in safety injection flow rate).
In the meantime, until a better solution is found, the reactor coolant pumps should be tripped automatically in case of a small-break LOCA.
.The signals designated to initiate the pump trip are discussed in NUREG-0623.
Discussion Westinghouse has prepared a design modification for the automatic RCP trip to the NRC.
If required, TVA committed in their letter of December 12, 1980 to 22-28 Sequoyah SSER#5/ Stable 1/H
any modification prior to startup at the first refueling outage.
This is satisfactory to the staff.
II.K.3.9 PID Controller Modification Position Modify the Proportional Integral Derivative Controller as recommended by
- Westinghouse Discussion TVA has modified the PID as stated in their letters of July 7,1980 and December 10, 1981.
II.K.3.10 Proposed /aticipatory Trip Modification Position The anticipatory trip modi'lication proposed by some licensees to confine the range of use to high power levels should not be made until it has been shown on a plant-by plant basis that the probability of a small-break loss-of-coolant accident (LOCA) resulting from a stuck-open power operated relief valve (PORV) is substantially unaffected by the modification.
Discussion TVA has not proposed this modification; coce aquently no evaluation is needed.
No further action is required.
II.K.3.11 Justificating Use of Certain PORVs 4
Position Justification is needed to use CCI supplied PORVs.
22-29 Sequoyah SSER#5/Stahle 1/H
-Discussion t
Sequoyah Units 1 and 2 are not supplied by CCI; therefore no modifications are required.
TVA response was submitted on June 23, 1980 in their response to NUREG-578.
II.K.3.12 Anticipatory Trio on Turbine Trip i
Position Submit confirmation of anticipatory trip.
Discussion In letters dated July 18, 1980 and December 10, 1980, TVA confirmed that there is an anticipatory trip on turbine trip at Sequoyah Units 1 and 2.
II.K.3.17 Report on Outages of Emergency Core-Cooling Systems License Report and Proposed Technical Specification Changes Position Several components of the emergency core-cooling (ECC) systems are permitted by Technical Specifications to have substantial outage times (e.g., 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for one diesel generator; 14 days far the HPCI system).
In addition, there are no cumulative outage time limitations for ECC systems.
Licensees should submit a report detailing outage dates and lengths of outages for all ECC systems for the last 5 years of operatior.
The report should also include the causes of the outages (i.e., controller /ailure, spurious isolation).
Discussion In their letter of March 1981, TVA submitted a plan for gathering cumulative outage times for ECC equipment and to submit this data.
This requirement has been satisfied.
22-30 Sequoyah SSER#5/Stahle 1/H
o x
.II.K.3.25 Effect of Loss of Alternating Current Power on Pump Seals Position Discussion The TVA letter of December 19, 1980 stated that Sequoyah presently supplies emergency power to the component cooling water pumps through automatic sequencing on to the diesel generators after a loss of offsite power.
In view of this sequencing, TVA is in compliance with this requirement.
II.K.3.30 Revised Small-Break Loss-of-Coolant Accident Methods to Show Compliance with 10 CFR Part 50, Appendix K Position The analysis methods used by nuclear steam supply system (NSSS) vendors and/or fuel suppliers for small-break loss-of-coolant accident (LOCA) analysis for compliance with Appendix K to 10 CFR Part 50 should be revised, documented, and submitted for NRC approval.
The revisions should account for comparisons with experimental data, including data from the LOFT Tast and Semiscale Test facilities.
II.K.3.31 Plant-Specific Calculations to Show Compliance with 10 CFR Part 50.46 Position Plant-specific calculations using NRC-approved models for small-break loss-of-coolant accidents (LOCAs) as described in item II.K.3.30 to show compliance with 10 CFR 50.46 should be submitted for NRC approval by all licenseee Discussion For II.K.3.30 and II.K.3.31 The Westinghouse owrers' group has responded to requirement II.K.3.30.
The group set forth a justification for the acceptability of the existing small break LOCA models. Additional information for model justification is scheduled 22-31 Sequoyah SSER#5/ Stable 1/H
~
for January 1, 1982.
Pending a resolution of II.K.3.30, the need for plant specific analysis is dependent on the outcome of the LOCA models. A plant specific analysis is expected to be completed in the required period (9/1/82).
III. Emergency Preparations and Radiation Protection III.A.1.1 Upgrade Emergency Preparedness Position Provide an emergency response plan in substantial compliance with NUREG-0654, l
" Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants" (which may be modified after May 13, 1980 based on public comments) except that caly a description of and completion schedule for the means for providing prompt notification to the population (App. 3), the staffing for emergencies in addition to that already required (Table 8.1), and an upgraded meteorological program (App. 2) need be provided.
NRC will give substantial weight to FEMA findings on offsite plans in judging the adequacy against NUREG-0654.
Perform an emergency response exercise to test the integrated capability and a major l
portion of the basic elements existing within emergency preparedness plans and organizations.
Discussion Ba ed on our review of the revised (1/2/81) Sequoyah Nuclear Plant Radiologicai Emergency Plan against the criteria of NUREG-0654, we concluded that the Emergency Preparedness Evaluation Report previously described and accepted in Supplement No. 2 in the Sequoyah SER is applicable to the licensing of Sequoyah Unit 2 provided the items are corrected as committed by TVA in letter dated April 16,1981:
i 1.
TVA committed to revise their plan to include a summary of shift manning.
22-32 Sequoyah SSER#5/ Stable 1/H
This c.cmmitment was met by letter dated August 15, 1980 and is included in the revised plan.
(See Section B in Appendix E of SER, Supplement No. 2.)
2.
The NRC staff position is that the pertinent instrument readings, param-eters, and equipment status should be specified in the Emergency Plan itself.
This commitment was met by letter dated August 15, 1980.
(See Section D in Appendix E of Sta,. Supplement No. 2.)
3.
In a letter _ dated August 1, 1980, TVA commits to a prompt notification system having the design objective capability to essentially complete the initial notification of the public within the plume. exposure pathway EPZ within about 15 minutes. TVA will expedite procurement of a prompt notification system to ue installed and operational in accordance with the following estimated dates:
(1) Order equipment (bid award) - November 15 - December 15, 1980 (2) Receive equipment - April 15 - May 15,1981 (3) Install equipment - May 15 - June 15,1981 (4) Operational - July 1, 1981 TVA is on schedule with procurement of equipment and expects the system to be operational on July 1, 1981.
(See Section E in Appendix E of SER Supplement No. 2.)
4.
In letter dated July 28, 1980, TVA agreed to provide an interim operations facility and to revise the TVA Radiological Emergency Plan to include a description of the facillt,y, location, communications, and manning requirements.
This commitment was met when TVA included the appropriate EOF data in the revised plan.
(See Section H in Appendix E of SER Supplement No. 2.)
i 22-33 Sequoyah SSER#5/ Stable 1/H I
5.
TVA committed to provide an upgraded Technical Support Center at Sequoyah Nuclear Plant have the capability of providing real-time meteorological data to offsite locations.
TVA has committed to provide for the remote interrogation of meteorological data by NRC at the Incident Response Center and other emergency organizations that require it.
The Technical Support Center will be upgraded and operational on a schedule consistent with TVA's commitments to NUREG-0737.
(See Section H in Appendix E of SER Supplement No.-2.)
6.
TVA has provided informe. tion on onsite capability and resources to provide initial and continuing assessment throughout the course of an accident in response to NRC lette. dated October 30, 1979, relative to the Lessons Learned Program designated in NUREG-0578. TVA agreed to revise their Radiological Emergency Plan to reflect these capabilities.
7.
In a letter dated August 1, 1980, TVA agreed to provide a more detailed writeup of their recovery operations in the next revision of TVA's Emergency Plan, due January 1, 1981.
An expanded recovery operations section was included in the revised REP.
The evaluation of the State and local emergency response plans around Sequoyah were reaffirmed by the Federal Emergency Management Agency (FEMA) on April 1981, letter attached.
Based on the FEMA findings and our evaluation, we cor.clude Sequoyah meets the emergency response plan requirements for a full power license.
III.A.1.2 Upgrade Emergency Support Facilities l
Position l
Provide radiation monitoring and ventilation systems, including particulate and charcoal filters, and otherwise increase the radiation protection to the onsite technical support center to assure that personnel in the center will 22-34 Sequoyah SSER#5/ Stable 1/H
not receive doses in excess of 5 rem to the whole body or 30 rem to the thyroid for the duration of the accident.
Provide direct display of plant safet) system parameters and call up display of radiological parameters.
For the near-site emergency operations facility, provide shielding against direct radiation, ventilation isolation capability, dedicated communications with the onsite technical support center and direct display of radiological and meteorological parameters.
This requirement shall be met by January 1, 1981, although the safety parameter information requirements will be staged over a longer period of time.
(See NUREG-0578, Sections 2.2.2b and 2.2.2.c, and letters of September 27 and November 9, 1979 and April 25, 1980.)
Discussion TVA will provide a conceptual design description of the emergency support facilities (TSC, OSC, EOF) to the NRC by June 1, 1981.
Implementation of NUREG-0696 recommendations for the upgraded emergtncy support facilities required for Sequoyah cannot be complete by October 1, 1982. A prelindnary schedule shows that the earliest date the necessary equipment could be delivered to the site is August 1982.
Since the construction and installation of the equipment would have to be coordinated with scheduled unit outages, the preliminary schedule shows that an estimated operational date for upgraded emergency support facilities is July 7, 1984. A more specific schedule will be available when the detailed conceptual design has been conpleted.
TVA is investigating comparable alternatives to the NUREG-0696 recommendations which will expedite this schedule. These alternatives will be addressed in the conceptual design submittal by June 1, 1981.
22-35 Sequoyah SSER#5/ Stable 1/H
O e
a Letter
\\
22-36 Sequoyah SSER#5/ Stable 1/H
t Existing Emergency Support Facilities The information provided to the NRC on the response facilities for Sequoyah
. Unit 1 is applicable to Unit 2.
This includes the following:
a.
Technical Support Center (TSC):
A description of the TSC is included in the Sequoyah Nuclear Plant Radiological Emergency Plan.
Location of Technical Support Center
}
i The relay room on elevation 732 in the control building is designated as the site technical support center.
This location was-chosen for the following reasons:
There is sufficient space available to accommodate up to 25 persons.
The habitability system for this area is the same one provided for the main control room.
No added equipment is required.
The air supplied to the room is filtered by an ESF system, and it is monitored for contaminants.
Stay times for this area are the same as for the main control room.
The use of the relay room as the technical support center reduces the cost of providing plant parameter information in the technical support center due to the close proximity of the main control room.
This also has the advantage of allowing technical support personnel access to plant instrumentation that may not have b+an considered necessary during design conception of the technical support center.
The technical support center will have a communications system that will allow it to communicate with control room personnel; but, should it fail, the close proximity of the two areas allows for continued operation.
22-37 Sequoyah SSER#5/Stahle 1/H
- - 1
Staffing of the Technical Support Center The technical support center will be activated in accordance with the Sequoyah Emergency Plan..In the event that the plan is activated during routine work hours for the plant staff, the following personnel will report to and make up the technical support center staff.
Reactor Engineer Mechanical Test and Studies Lead Engineer Chemical Engineer Lead Instrument Maintenance Engineer Lead Mechanical Maintenance Engineer Lead Electrical Maintenance Engineer In the event that the plan is activated at other than rcutine work hours, the Site Emergency Director will make arrangements to staff the technical support center with available onsite personnel or call in offsite personnel.
The technical support center will be manned until the Site Emergency Director determines that it is no longer needed.
Reference Materials The below-listed reference materials will be provided in the TSC, Sequoyah Nuclear Plant FSAR Sequoyah Nuclear Plant Technical Specifications Surveillance Instructions (selected)
Technical Instructions (selected)
Radiological Control Instructions Hazard Control Instructions System Operating Instructions REP Spill Prevention Control Plan Plant Functonal Drawings Abnormal Operating Instructins Emergency Operating Instructions b.
Operational Support Center (OSC):
A description of the OSC is included in the Sequoyah Nuclear Plant Radiological Emergency Plan.
22-38 Sequoyah SSER#5/ Stable 1/H
The role of the Operational Support Center is to provide an assembly area for aperations support personnel during an emergency situation.
The Locker and Lunchroom spce in the powerhouse control bay at elevation-732.0 feet is designated for use as the Operational Support Center.
The Operational Support Center is provided with PAX telephone communications to the main control room.
c.
Emergency Operations Facility (EOF): A description of the TVA program of a centralized emergency operations concept and an interim nearsite EOF is included in the Sequoyah Nuclear Plant Radiological Emergency Plan.
Based on the licensee's descriptions above and in the Sequoyah Nuclear Plant Radiological Emergency Plan of the Technical Support Center (TSC), the Operations Support Center (OSC) and the interim Emergency Operations Facility (EOF), we conclude that the emergency support facilities are acceptable for the interim.
On February 15, 1981, the NRC stated that the permanent emergency support facilities shall be completed and operational by October 1,1982. The facilities design concepts will be reviewed for adequacy when they are submitted on June 1, 1981. Additionally, site specific elements to be addressed by TVA in their submittal were provided by letter of H. G. Parris by D. G. Eisenhut dated March 19, 1981.
i III.A.2 Long-Term Emergency Preparedness Position Each nuclear facility shall upgrade its emergency plans to provide reasonable a
assurance that adequate protective measures can and will be taken in the event of a radiological emergency.
Specific criteria to meet this requirement is delineated in NUREG-0654 (FEMA-REP-1), " Criteria for Preparation and Evaluatica of Radiological Emergency Response I'lans and Preparation in Support of Nuclear Power Plants."
22-39 Sequoyah SSER#5/Stahle 1/H
-e
a Discussion Milestone (1) was met when the licensee submitted an upgraded Radiological Emergency Plan (REP) to NRC on December 31, 1980.
Milestone (2) was met when the licensee provided emergency implementing procedures and descriptions of the methods, systems, and equipment to estimate atmospheric transport and diffusion for use in assessing potential offsite consequences of radiological condition. The licensee has submitted descriptions of meteorological methods, systems, and equipment.
Milestone (3) was met when TVA stated that the REP was implemented to April 1, 1981. TVA letter of April 16, 1981, provided additional information on the implementation of the radiological emergency responsa plan. Acceptance criteria of Appendix 2 to NRUEG-0654, however, has not been fully satisfied.
Compensating actions of NUREG-0737 will be utilized on an interim basi.- for satisfying the criteria of Appendix 2 to NUREG-0654.
Sufficient information has not been provided to determine if Watts Bar is an acceptable alternate data source to represent Sequoyah site characteristics to meet the requirements for compensating actions (i) of NUREG-0737, III.A.2.
For compensating action (ii) the meteorological portions of the dose calculation methodology should be consistent with the Class A model.
TVA has stated that their dose assessment model equals or exceeds the NRC requirements for Class A and Class B models.
Sufficienr. information has not been provided to determine if the transport and diffusion analyses done in the MSECC meet the criteria for Class A model.
Information on the TVA dose assessment will be made available to the NRC during a site visit i.i May 1981.
How the data in the control room are used for the initial dose assessment are not identified in the documentation.
Clarification will be provided during the I
May site visit.
22-40 Sequoyah SSER#5/ Stable 1/H
Remote interrogation of the dose assessments is being addressed by compensating action (iii). The NRC will have direct telephone access to TVA, but it has not been clarified that the NRC will have direct telephone communication with the person doing the dose assessments.
The above three compensating actions are to be completed prior to full power operations.
The licen'ee will be conditioned on this basis.
All the compensating actions can only be used until July 1, 1982.
By July 1, 1981, a functional description of the upgraded programs and schedule for installation and full operational capability shall be provided to meet milestones 4 and 5.
To meet milestone 4 (NUREG-0737, III.A.2), TVA will be required to install a program that meets Appendix 2 to the satisfaction of the staff (except Class B model) by April 1. 1982.
To meet milestone 5 (NUREG-0737 III.A.2) TVA will be required to have the program operational by July 1, 1982.
The licensee will also be conditioned to reflect this position.
22.3 Dated Requirements In Supplement No. 2 to the SER we identified five of the 15 dated items that are delayed until January 1, 1982 which was acceptable to the staff.
The staff noted in several instances that TVA should be allowed to install some of the instruments during the first forced or scheduled outaged of sufficient length to allow installation after delivcary.
NUREG-0737 has changed the installation date for II.B.1 (Reactor Coclant System Vents) to July 1982 instead of January 1,1982. We will reconsider this change for Unit No.1 if good cause is shown and condition the license for Unit 2 to the July 1982.
22-41 Sequoyah SSER#5/ Stable 1/H
e t
24.0 Reactor Safety Study Methodology Applications Program In February 1981, the Sandia National Laboratories, issued the results of a study, entitled, Reactor Safety Study Methodology Applications Program; Sequoyah #1 PWR Power Plant, (NUREG/CR-1659 Volume 1).
This report is the first of several reports to be published by Sandia on the results of analysis performed in the Reactor Safety Study Methodology Application Program (RSSMAP).
RSSMAP analysis utilizes the methodology developed in the Reactor Safety Study to identify the accident sequences that dominate accident risk for a variety of light water reactor power plants aepresentative of the current population of plants.
The Sequoyah analysis by Sandia was conducted primarily with information available from the early versions of the Sequoyah Final Safety Analysis Report, Technical Specifications and selected plant procedures.
It is acknowledged that a substantial portion of the Sandia report was writter prior to the plant modifications and procedural changes which have been impler-ented at Sequuyah as a result of the TMI-2 accident. Also, it is acknowledged that the analysis in the report was not upgraded, to reflect the new efforts in plant reliability analysis by both the nuclear industry and the Nuclear Regulatory Commission.
Nevertheless, tt.e NRC staff, including the Division of Risk Analysis, RES, has concluded that while more rigorous methodologies may provide more detailed information on the causes of system failures, the mest significant conclusions of the Sandia. RSSMAP stud) of Sequoyah Unit No. 1 are accurately summarized in section 4.2 Risk Comparison and Conclusions.
The conclusions stated are listed below:
1.0 An important accident sequence occurring for the Sequoyah plant results from the potential for blockage or closure of the drains between the epper and lower compartments.
This causes a common-mode failure of the ECRS and CSRS when the sump runs dry (sequences S HF and 5 HF).
The 1
2 probability of these sequences could be reduced by improved checking prccedures and improved fault detection capabilities.
,5-1 Sequoyah SSER#5/ Stable 1/K
2.0 Failure of the ECRS alone caused by component failures other than the drains also results in some important accident sequences.
3.0 Sequence V, in which chack valve failt.es cause the high pressure primary coolant to fail the low pressure pipir.J outside containment, remains an important sequence for Sequoyah. This sequence could be improved by a more strategic testing procedure of the check valves over the limited testing capability which now exists.
4.0 Unlike larger containments, core melting caused by failure of ECIS or
.ECRS fail the longer pressure, smaller ice condenser containment by overpressure even though the containment cooling system continues to operate properly. The analysis of accident processes by Battelle Columbus Laboratories revealed that the smaller containment pressure and volume design would not withstand the pressure exerted by the noncondensible gases generated in the core meltdown accidents.
(This result was similar to the RSS findings for the RSS BWR design.)
t 5.0 Sequence TMLB' a, which was important for the Surry plant as analyzed in the RSS, does not appear to be as significant to risk for Sequoyah due to the lower unavailability of on-site ac power.
6.0 Failure of the containment cooling system causing core meltdown following a small LOCA (the S C sequence in the RSS) does not appear to lead to 2
core meltdown at Sequoyah due to the difference in sump water temperature at the time containment failure.
On April 24, 1981, TVA responded to the Sandia RSSMAP report which is provided in its entirety in Appendix F.
The staff concludes that TVA's responses are satisfactory and the remedial measures taken by TVA for Saquoyah in response to the conclusions of this report is acceptable.
_5-2 Sequoyah SSER#5/Stahle 1/X
In particular, responses to Sandia conclusions 1 and 3 have resulted in stringent Sequoyah Technical Specifications requirements. Technical Specification for the potential for. blockage or closure of the drains between the upper and 4
lower compartments (conclusion 1), are:
Each refueling canal drain shall be demonstrated OPERABLE.
a.
Prior to increasing the Reactor Coolant System temperature above 200?F after each partial or complete filling of the canal with water by verifying that the plug is removed from the drain line and that the drain is not obstructed by debris, and b.
At least once per 92 days by verifying, through a visual inspection, that the plug is_ removed and there is no debris that could obstruct the drain.
For Sequence V (conclusion 3) whereby valve failures causes the high pressure primary coolant to fail the low pressure piping outside containment, the Technical Specification limits the leakage to 1.0 gpm from any RCS pressure isolation valve specified in a table.
Surveillance requirements fo these valves are that each valve shall be demonstrated operable by verifying leakage to be within itslimit:
a.
At least once per 18 months.
b.
Prior to entering MODE 2 whenever the plant has been in COLD SHUTDOWN for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or more and if leakage testing has not been performed in the previous 9 months.
Prior to returning the valve to service following maintenance, repair or c.
replacement work on the valve.
d.
Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following valve actuation due to autouatic or manual action or flow through the valve. 3 Sequoyah SSER#5/ Stable 1/K
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No other issues in the Sandia report warrant discussion in the Sequoyah supplementary safety evaluation report.
It is noted, however, that TVA has is progress a full scale nuclear safety and availability analysis being per-formed by Kanon Sciences Corporation.
The study should be complete at the end of 1981. We will add a condition to the SEQuoyah Unit No. 2 license of TVA to submit the results in March 1982.
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. 5-4 Sequoyah SSER#5/ Stable 1/K
APPENDIX A CHRONOLOGY FOR RADIOLOGICAL SAFETY REVIEW August 1, 1980 Letter to TVA forwarding draft NUREG-0696, " Functional Criteria for Emergency Response Facilities."
August 6, 1980 Letter to TVA requesting additional information concerning hydrogen.
August 7, 1980 Letter to TVA forwarding August 4, 1980 report, " Hydrogen Problems in Sequoyah Containment."
August 12, 1980 Letter from TVA regarding NUREG-0588.
August 13, 1980 Letter from TVA forwarding " Secondary Water Chemistry Program:
Sequoyah and Watts Bar Nuclear Plants."
1 August 14, 1980 Letter from TVA regarding interim distributive ignition system.
4 l
August 15, 1980 Letter from TVA forwarding Revision 3 to the Radiological Emergency Plan.
August 15, 1980 Letter from TVA concerning NUREG-0588.
i August 19, 1980 Letter from TVA regarding code requirements addressed in the license application.
I August 19, 1980 Letter from TVA concerning construction completion dates for Sequoyah, Watts Bar, and Bellefonte.
August 28, 1980 Letter to TVA requesting additional information regarding IDIS.
I A-1 Sequoyah SSER#5/ Stable 1/I
August 29, 1980 Letter from TVA forwarding Procedure IP-18, " Plant Release Rate Calculations."
September 4, 1980 Letter to TVA forwarding Supplement 2 to the SER (NUREG-0011).
September 4,1980 Letter from TVA concerning ice condenser insulation materials.
September 4, 1980 Letter from TVA concerning temperature control for main steam valve rooms.
September 4, 1980 Letter from TVA forwarding Annual Financial Report, 1979.
September 5, 1980 Letter to TVA requesting additional information regarding accident evaluation.
September 5, 1980 Letter to TVA forwarding preliminary clarification of TMI action plant requirements.
September 5, 1980 Letter from TVA regarding degraded core training for operating employees.
September 5, 1980 Letter from TVA forwarding " Environmental Radioactivity Levels - Sequoyah Nuclear Plant Annual Report, 1979."
September 12, 1980 Letter from TVA concerning containment steel test reports.
September 15, 1980 Letter from TVA concerning containment steel test reports.
September 16, 1980 Letter to TVA forwarding Supplement 3 to the SER (NUREG-0011).
A-2 Sequoyah SSER#5/Stanle 1/I
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September 17, 1980 Letter from TVA forwarding Revision 6A to the " Physical Security Plan."
September 17, 1980 Letter from TVA regarding replacement schedule for turbocharger drive gear assemblies.
September 17, 1980 Letter from TVA regarding program for resolving ATWS.
Septembar 18, 1980 Letter to TVA forwarding September 8, 1980 ACRS letter regarding ice condenser containments.
September 19, 1980 Letter to TVA concerning preliminary clarification of TMI action plan requirements (September 5, 1980 letter).
September 22, 1980 Letter from TVA forwarding Revision 3 of response to NUREG-0578, "TMI-2 Lessons Learned Task Force Status Report and Short-term Recommendations."
September 30, 1980 Letter from TVA regarding NUREG-0696, " Functional Criteria for Emergency Response Facilities."
i October 1, 1980 Letter to TVA regarding environmental qualification tests on safety-related equipment.
October 3, 1980 Letter from TVA forwarding " Test Report: Verification i
of Adequacy of Calculations for Sequoyah AC Auxiliary Power System."
October 6, 1980 Letter to TVA concerning Unresolved Safety Issue A-12,
" Potential for Low Fracture Toughness and Lamellar Tearing on Component Supports."
October 16, 1980 Letter from TVA concerning masonry walls issue.
October 20, 1980 Letter from TVA regarding lack of dewatering system for seismic Category I structures.
A-3 Sequoyah SSER#5/ Stable 1/I
o October 27, 1980 Letter from TVA concerning security personnel training and qualification plans.
October 28, 1980 Letter from TVA regarding technical support center.
i October 31, 1980 Letter to TVA forwarding NUREG-0737, " Clarification of TMI Action Plan Requirements."
November 4, 1980 Letter to TVA requesting additional information regarding degraded core program.
November 4, 1980 Letter to TVA regarding tiles used in control room ceiling.
November 5, 1980 Letter to TVA requesting additional information regarding reactor coolant system vents.
November 10, 1980 Letter from TVA concerning operator training and qualification programs.
November 10, 1980 Letter from TVA regarding fuel load date for Unit 2.
November 13, 1980 Letter to TVA concerning revised radiological emergency response plans.
November 13, 1980 Letter from TVA forwarding outline to shift technical advisor training and requalification program.
November 14, 1980 Letter to TVA regarding deletion of high pressure blowdown tests.
November 17, 1980 Letter to TVA regarding peak pressure containment integrated leak rate test and full pressure preoperational containment integrated leak test.
A-4 Sequoyah SSER#5/ Stable 1/I
F 0
November 17, 1980 Letter from TVA regarding IE Bulletin 80-09, "Hydramotor Actuator Deficiencies."
November 24, 1980 Letter from TVA forwarding application for amendment to License DPR-77 to authorize storage of low level radwaste.
November 26, 1980 Letter to TVA regarding implementation of guidance for Unresolved Safety Issue A-12, " Potential for Low Fracture Toughness and Lamellar Tearing on Component Supports."
November 26, 1980 Letter to TVA regarding environmental qualifica; ion of i
safety-related electrical equipment.
December 1, 1980 Letter from TVA clarifying TVA's control of construction and preliminary testing.
December 3,1980 Letter to TVA forwarding Appendix R to 10 CFR 50.48 regarding five protection program requirements.
December 5, 1980 Letter from TVA regarding the natural circulation tests performed on Unit 1.
December 9, 1980 Letter to TVA forwarding Revision 1 to NUREG-0654/ FEMA-REP-1.
December 9, 1980 Letter from TVA regarding environmental qualification testing of safety-related equipment.
December 9, 1980 Letter from TVA forwarding planned changes to Chapter 17 of the FSAR for Sequoyah, Watts Bar, and Bellefonte.
December 10, 1980 Letter from TVA forwarding response to Revision 3 of NUREG-0578, "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations."
1 A-5 Sequoyah SSER#5/ Stable 1/I
December 15, 1980 Letter from TVA regarding Item III.D.1.1 of the THI-2 Action Plan.
December 15, 1980 Letter from TVA regarding modifications to containment isolation valves.
December 16, 1980 Letter from TVA regarding Unit 1 special natural circulation test program.
December 17, 1980 Letter from TVA regarding status of emergency plan items.
December 22, 1980 Letter to TVA regarding ceontrol of heavy loads.
Decen;ber 29, 1980 Letter to TVA regarding the resolution of the ATWS issue.
December 31, 1980 Letter from regarding ERCW settlement monitoring.
December 31, 1980 Letter from TVA regarding design details of post-accident sampling system.
December 31, 1980 Letter from TVA regarding barge collision issue.
December 31, 1980 Letter from TVA forwarding revised Radiological Emergency Plan.
January 2, 1981 Letter from TVA forwarding " Westinghouse Reactor Vessel Level Instrumentacion System for Monitoring Inadequate core Cooling (l'pper Head Injection)."
January 7,1981 Letter from TVA regarding NUREG-0737, Items I.C.6, II.E.4.2, II.K.3.1, and II.K.3.2.
January 13, 1981 Letter from TVA regarding cont;ni room habitability.
A-6 Sequoyah SSER#5/Stahle 1/I
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' ^
P January 14, 1981 Letter to TVA regarding hydrogen controi system.
January 14, 7.981 Letter from TVA regarding potential flammability of ceiling tiles in control room.
January 15, 1981 Letter to TVA requesting additional information regarding guard training and qualification plan.
January 15, 1981 Letter from TVA forwarding " Environmental Radioactivity Levels, Sequoyah Nuclear Plant, Annual Report 1979."
January 15, 1981 Letter from TVA regarding modifications to containment boundary components.
January 16, 1981 Letter from WA regarding fuel load date for Unit 2.
February 2, 1981 Letter tram TVA regarding non-reinforced concrete masonry block walls.
February 3, 1981 Letter to TVA forwarding pages omitted from December 22, 1981 letter regarding control of heavy loads.
February 4, 1981 Letter from TVA forwarding revised physical security plan.
February 5, 1981 Letter from TVA regarding environmental qualification of electrical equipment.
February 6, 1981 Letter from TVA forwarding revised physical security plan.
February 12, 1981 Letter from TVA regarding design criteria for effluent monitoring, sampling, and analysis equipment.
A-7 Sequoyah SSER#5/ Stable 1/I
February 12, 1981 Letter from TVA regarding reevaluation of construction -
completion schedule.
t.
t February 17, 1981 Letter from TVA regarding centralized emergency operations I
program.
f i
February 18, 1981 Letter to TVA forwarding Supplement 4 to the SER f
(NUREG-0011).
2 February 20, 1981 Letter to TVA regarding NUREG-0619.
I February 20, 1981 Letter from TVA regarding status of turbine disk inspection, special natural circulation program, verification of adequacy of transformer tap settings, and proposed change to Unit 1 Technical Specification i
o f
3.6.1.9.
l February 23, 1981 Letter from TVA regarding NUREG-0737, Item II.E.4.2.
f February 25, 1981' Letter to TVA regarding capacity to mitigate station
{
blackout event, and promptly implement emergency procedures.
February 26, 1981 Letter to TVA regarding the periodic updating of FSARs.
February 26, 1981 Letter from TVA regarding guard training and qualification plans.
i February 27, 1981 Letter to TVA regarding November 24, 1981 application to amend license to authorize onsite low level j
waste-storage.
March 3, 1981 Letter from TVA regarding implementing procedures for the Radiological Emergency Plan.
A-8 Sequoyah SSER#5/Stahle 1/I
. _ - - - _. - _..,.. ~.. _. _ -..
March 3, 1981 Letter from TVA regarding auxiliary feedwater pump endurance test.
I March 5, 1981 Letter to TVA forwarding NUREG-0696, " Functional Criteria for Emergency Response Facilities."
March 9, 1981 Letter from TVA regarding interim operation of facility during initial criticality until fire protection
{
modifications for ERCW system are complete.
March 10, 1981 tetter to TVA regarding environmental qualification of safety-related electrical equipment.
March 10, 1981 Letter from TVA regarding installation of ignitors in Unit 2 at locations similar for Unit 1.
March 10, 1981 Letter from TVA regarding compliance with NUREG-0737, l
Item II.F.1.
March 12, 1981 Letter from TVA regarding NUREG-0737, Item II.K.3.17.
March 13, 1981 Letter from TVA informing that fuel load date for l
Unit 2 is May 1, 1981.
i March 16, 1981 Letter from TVA forwarding "Research Program on Hydrogen Combustion and Control, Quarterly Progress Report 2."
March 20, 1981 Letter from TVA forwarding "Assessitent of Ultrasonic i
Reflectors in Sequoyah Unit 2 Reactor Vessel Nozzle Bores."
March 20, 1981 Letter from TVA forwarding revisions to Emergency Implementing Procedures I-18.
March 24, 1981 Letter from TVA regarding NUREG-0578, Item 2.1.6a.
A-9 Sequoyah SSER#5/Stahle 1/I
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March 27, 1981 Letter from TVA regarding guard training, qualification plan, and safeguards contingency plans.
March 31, 1981 Letter from TVA forwarding revised Radiological Emergency Plan (Central Files version).
March 31, 1981 Letter from TVA requesting extension of construction completion date.
April 2,1981 Letter from TVA regarding critical systems, structures, and components list.
April 2, 1981 Letter from TVA regarding NUREG-0737, Ite; I.C.6.
April 2, 1981 Letter from TVA regarding evacuation time estimates per NUREG-0654.
April 2, 1981 Letter from TVA regarding report on operating experience of Unit 1 purge / vent valves before startup after first refueling.
April 2, 1981 Letter from TVA regarding AC auxiliary power system testing for Unit 2.
April 2,1981 Letter from TVA notifying NRC that no modifications are required as a result of 10 CFR, Appendix R.
April 3, 1981 Letter from TVA regarding licensing schedule for Sequoyah and Watts Bar.
April 3, 1981 Letter from TVA regarding process control program.
April 3, 1981 Letter from TVA regarding NUREG-0737, Item II.K.3.2.
April 3, 1981 Letter from TVA regarding applicability of December 19, 1981 submittal concerning NUREG-0737 to Unit 2.
A-10 Sequoyah SSER#5/Stahle 1/I
April 6, 1981 Letter from TVA regarding vulnerability of ERCW intake structure to barge collision.
April 7, 1981 Letter from TVA forearding revision to Emergency Plan Implementing Proc' dure I-18 (Central Fil u version).
April 7, 1981 Letter from TVA forwarding revisions to security personnel training and qualification plans, and safeguards contingency plans.
April 7, 1981 Letter from TVA regarding settlement monitoring program of the ERCW.
April 8, 1981 Letter from TVA regarding results of auxiliary building gas treatment system te ;.
April 13, 1981 Letter from TVA regarding startup program.
April 13, 1981 Letter from TVA regarding compliance with NUREG-0737, Item II.F.2.
April 15, 1981 Letter from TVA forwarding page correction to April 13, 1981 letter regarding start up program.
April 16, 1981 Letter from TVA regarding current status of SER open items and NUREG-0737, Items III.A.1.2 and III.A.2.
April 17, 1981 Letter from TVA regarding hydrogen control.
April 17, 1981 Let*.er from TVA regarding preoperational test program modifying reactor coolant system flow measurement test.
April 20, 1981 Letter from TVA regarding centrifugal charging pump miniflow isolation.
A-11 Sequoyah SSER#5/Stahle 1/I
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April 21, 1981 Letter from TVA informing NRC of continued support and participation in hydrology committee of Water Resources i
Council.
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