ML20087D003
| ML20087D003 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 12/31/1983 |
| From: | Will Smith, Srensson B, Stietzel J INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG |
| To: | James Keppler NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| References | |
| NUDOCS 8403130259 | |
| Download: ML20087D003 (31) | |
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.D.O N A'L D C.
. COOK
.N'U'C L E A R PLANT
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ANNUAL OPERATING' REPORT 1983 Compiled By:
' ' St$2(el Superintendent Reviewed By:
,4 h B.A.
Svensson Assistant Plant Manager Reviewed By:
My &
E.L. Townley u(P Assistant Plant Manager Approved By: bd-[
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W.G. Smith P M Plant Manager 8403130259 831231
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T-A'B L E OF CONTENTS
~ TITLE ~
pAGE NUMBER 1
INTRODUCTION.
I PERSONNEL', EXPOSURE
SUMMARY
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_, INSERVICE INSPECTION CHANGES TO FACILITY 13 r
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s INTRODUCTION The Donald C. Cook Nuclear Plant, owned by the Indiana and
' Michigan Electric Company and located five miles north of Bridgman, Michigan, consists of two 1100 MWe pressurized water reactors.
The Nuclear Steam Supply Systems for both units are supplied by Westinghouse with a General Electric turbine-generator'on Unit 1 and a Brown-Boveri turbine-generator on Unit 2.
-The condenser cooling method is open cycle, using Lake Michigan water as the condenser cooling source.
The Donald C.
-Cook Nuclear Plant was the first nuclear facility to use-the ice condenser reactcr containment system, which utilizes a heat sink of borated ice in a cold storage compartment located inside the containment.
The architect / engineer and constructor was the American Electric Power Service Corporation.
This repart was compiled by Mr. J.F. Stietzel, with information.
contributed by the following individuals:
D.C.
Palmer Personnel Exposure Summary R.L.-Otte Inservice Inspection Changes to Facility E.A. Abshagen
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1.16 REPORT - WORK FUNCTION CATAGORIES
-Reactor Operations and Surveillance Those activities involved with operating the plant or monitoring it's cperation, including chemistry, performance testing, surveillance testing,
.ete. The plant may be at any power level, including zero, and still have work. falling into this area. Many STP's run during shutdown or refueling may still fall into this ~catagory.
Routine Maintenance All equipment or system maintenance, whether preventative or restorative, which does not involve significant modifications to equipment or r.ystems. In-cludu is C&I repair work, as well as work to adjust operable equipment to improve perfornance (adjusting fan blade pitch, for example).
Inservice Inspection Inspections of equipment and ;ystems to monitor changes that would be detrimental to function or integrity. Also included is all work required to permit such inspections,'such as building required scaffolding, removing or replacing supports or insulation, or disassembly of valves, pumps, etc. Not included are inspections to assess or monitor normal wear, etc.
For example, dissembly of a charging pump to inspect bearing wear would not be Inservice Inspection, but dissembly to inspect for rotor cracking or casing damage would be.. Inspection of-a weld on a newly added line is Special Maintenance, or inspection of a weld repair at a leaking fitting ~is Routine Maintenance.
Special Maintenance All work on equipment or systems performed to make significant modifica-tions. Installation of new systems or equipment, replacement or addition of supports or hangers, addition of new lines or instruments, removal of existing equipment, replacement of existing equipment with significantly different equipment are all Special Maintenance.
For example, replacement of a properly functioning, original equipment pressure transmitter with a different inodel with improved characteristics or certification would be Special Maintenance,
- but replacement of a malfunctioning pressure transmitter with a newer or im-proved model would probably be Routine Maintenance.
Waste Processing r
All work' associated with decontamination of equipment, areas, systems, etc. (if not an integral part of another job, such as pump repair), collec-tion and processing of waste, whether solid, liquid, or gas. Operations in support of waste handling are also included. For example, draining a filter to permit changing it, er venting it after changing are part of Waste Pro-cessing, but valving a clean filter into the system is Reactor Operations.
Repair of the Baler or drumming room crane is Routine Maintenance.
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- Dl.16 Report --Work function Catagories 3
Pag; 2 of 2
-REFUELING
~ ~All work-directly concerned with refueling the reactor, including all 1 support operations, is classified as Refueling. ~ Testing the polar crane or installing the cavity filter rig is part of Refueling, as is cavity decori before or after flood-6p. Changing the cavity fil ter, however, is Waste
- Processing and. fixing the manipulator crane is Routine Maintenance.
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~ ' ANNUAL OPERATING R'EPORTL-RG:1.16 FOR11983.
4 3"
- PERSONNEL')100'mR TOTAL MAN-REM r.
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TSTAT.
UTIL; -CONT.
STATION UTILITY CONTRACT u
!Ieactor 0peratioEs~573urvelilarci-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
~~~~~~~~~~
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- Faintenance personnel 2
0 0
0.868 0.000 0.000 s
Operations Personnel 76' O
O 22.901 0.000 0.000 Health. Physics'Persennel 20 0
48 3.595 0.000 14.832
' Supervisory Personnel-3 0
0 0.584-0.000 0.000
'Ingineering' Personnel 0
0 0
0.000-0.00P 0.000 g hou tine. Main teba rcel
,<Faintenance_ Personnel-100 4'
- 124-276.467 1.199 44.952 iOperations-Personnel 17 0
-6 6.936-0.000 1.055
' J H eal th 1 Physics.;;Personn el 8-0
-14 1.052 0.000 3.102
-Ou~pervisory Personnel 5
0 45-2.623 0.000 0.607 Ingineering Personnel:
7 2
9 2.054 0.342 6.542
- li-Service Inspe'e tio n LPaintenance Personnel-29-3 126 7.324 2.575 72.819 Cperaticns Personnel
- 7 0
7-1.532 0.0P0 7.255 Health-PhysiesLPersonnel
.19 0
36 4.049 0.000 10.620 Supervi.scry. Personnel-1 0
3 0.141-0.000 1.010 LIngineering Per'onnel' 5'
4 5
1.354 0.939 0.760 s
~Specia14Faitterarce-
- Maintenance-Personnel 19 2=
236-6.191-2.826 146.601 Operations Personnel-1
.0 21-0.203 0.000 11.374
> Health.Fhysics Personnel:
0 0
13
~0.000 0.000 2.899-
$upervisory Personnel.
1 1
7 0.111 0.518 5.913
-Ingi' nee ring _ Pe rsonnel 5
4 5
0.854 0.690 1.647 L abtefProcessing W
Paintenance! Personnel 21 1
60 4.660 0.!51 34.128
- 0perationsLPersonnel.
1 0
0 0.142
-0.000 0.000 1HealthEFhysics Personnel.
7 0
18-1.973 0.000 9.817
.: Supervisory Personnel:
3 0
0-3.248 0.000 0.000 (Ingineering_ Personnel 11 0
0 0.508 0.000 0.000 LRefueling
~
6 2-37-2.644 1.174 20.950 brFalntenance Personnel.
9 4
0 8
1.212 0.002 4.182
!P.L0perations Personnel
?H0alth-Ehysics: Personnel-
.0 0
3 0.000 0.000 0.536
" Supervisory?Perscnnel-2 0
1 0.678 0.000 0.147
_Ingineering Personnel 0
0 0
0.000 0.000 0.000 To t'als
- PaintenanceEPersonnel 114 6
439 98.154 7.925 319.450 Operations _ Personnel 94 0
34 32.926 0.000 23.866
> Health Physics Personnel 26 0
74 10.669 0.000 41.806 Suptrvisory Personnel 12.
1 7
7.385 0.518 7.c77 Ingineering Perscnnel 12 7
.19 4.770 1.971 8.949
'G,ra nd 6To t al s.
'258 14 373 153.9J3 10.414 401.748
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STEAM GENERATOR INSPECTIONS The attached report' delineates the complete results of Steam Generator Tube-Inservice Inspections and any resulting plugging performed.during calendar year 1983.
As a result of these
~ inspections, 18 tubes were plugged in Unit 1 and 9 tubes were q
' plugged-in Unit 2.
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-1983-ANNUAL INSERVICE INSPECTION REPORT OF UNIT NO.1
~
- Duringithe Unit liRefueling' Outage which commenced on July 15, 1983, WestinghouseiCorporation performed an 9ddy current examination of all-
~
.four-steam generators.
The-performance of eddy current testing'in the steam generators was not required during~this outage-by--ASME Code ~Section XI, 1974 Edition, 1975 Addenda, Regulatory Guide 1.83 or the-Unit 1
. Technical Specifications.
However, Plant Management and Senior
' ; American Electric Power. Corporation Management had planned an eddy
' :currentiinspection program for the Unit 1 steam generators.
The: scheduled--. steam generator'(S/G) eddy current testing (ECT) on Cook' Unit'1 started July 23 and was. completed August 8.
Two thousand seven
,hundred and forty.(2740) tubes in each S/G were inspected.
Indications of? imperfections;(~20%-through-wall damage), degradation (20-39%
"g
.through-wall damage), and defects ( 40% through-wall damage) were found in.the hot. legs of all four S/G's.-
The-indications can be
' divided into~two groups:
1)'the tube bundle, and 2) those occurring on topjof the tubeEsheet.
In addition to these indications,' tube denting at theLtop-Lof the tube-sheet, primarily in the-sludge pile
' region,.was ' reported. : Totals'for each of the four S/G's and the 1
,remedialtaction'taken.when'necessary are identified in the folJowing data summarization.;
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-Hot Leg Indications Dents s
20%
20-39%
40%
Total.
ll S/G No. 11 31 1
2 34' 127
'S/G~No. 12' 43 8
2 53 153 S/G No.L13
- 22
.32 5
59 233 i
S/G No.i14~
34 8
2.
44 132 Breakdown Of Hot Leg Indications (AVB/TTS*)
20%
20-39%
40%
S/G No. 11-1/30 0/1 0/2
'S/G No. 12 2/41 3/5 0/2
.S/G No.c13.
12/20 32/0 5/0 S/G No'.(14 4/30 3/5 0/2
- Top'of Tubesheet u
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-Designated Tubes Plugged JS/G'No. 11'
~ Indication:
[ Row'18, Column;56 44% H/L - Mechanical Plug - C/L - Mechanical Plug
~
(Row. 2n Column 184
'68% H/L - Mechanical Plug - C/L - Mechanical Plug vS/G No.'12 Indication
' Row 14,: Column'83 i80% H/L - Mechanical Plug C/L - Mechanical Plug
- . ow :13 ;. column; 85 ~
64% H/L - Mechanical Plug - C/L -- Mechanical Plug R
~ Row-14,-Column?82* l20%'H/L - Mechanical Plug C/L - Mechanical Plug S _-
-* Plugged by~ mistake.
S/G~No.'13-Row:'1,? column 19 ~ N/A'H/L - Mechanical Plug - C/L - Mechanical Plug I ~ N/A H/L - Mechanical Plug
-C/L - Mechanical Plug
' Row: 1, Column 60 I
.Rowi 1,~ Column 63 N/A H/L - Mechanical' Plug - C/L - Mechanical Plug
'RowL 1,[ Column ~6'6 N/A H/L Mechanical Plug - C/L - Mechtinical Plug
~
Row 36,' Column 38 l42%"H/L.- Mechanical ~ Plug - C/L - Mechanical' Plug
- Row ~36,; Column;45
51% H/L - Mechanical' Plug - C/L
. Mechanical Plug LRow 41, Column!55 41%'H/L.
. Mechanical Plug - C/L - Mechanical Plug
- RcwL36, Column 62-80% H/L - Mechanical Plug - C/L - Mechanical Plug
' Row 136,. Column.63 54%-H/L --Mechanical Plug-- C/L - Mechanical Plug 1
LPlugged because of unmeasurable indications on inside of tubes 2' Plugged because'of partial restriction
- y iS/G No.'14 Row 12,-Column 17 70% H/L - Mechanical Plug - C/L - Mechanical Plug 1
-Row 21, Column 31*
84%.H/L - Welded Plug-- C/L - Mechanical Plug Row 17, Column 33*
N/A H/L - Welded Plug - C/L - Mechanical Plug Rcm 18, Column 3 3 * '- N/A E/L - Welded ? lug - C/L - Mechanical Plug
- ll61 inches of tube removed from H/L side 1 - Thisitube was initially plugged with a nechanical plug and
- -subsequently with a welde;d plug after tube removal.
- The 11 tubes having through-wall defecus greater than 40% were plugged.
. Additionally, four row 1 tubes in S/G No. 13 were plugged, 3 due to tunmeasurable indications of cracking on the inside of the tube at the
- U-bend hot leg. tangent point and one because of a partial restriction
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- (prob' ably due Jto-ovaling) at the U-bend cold leg tangent point.
- Also, l
jantadditionalEtube was mistakenly plugged by Westinghouse in S/G No.
[12.
A maeting was; held with Westinghouse on August 8 to discuss the results uf?
of-this. eddy curre'nt inspection, particularly the unexpected damage
~
found at the top"ofEthe tube sheet.
In order to evaluate the severity Lof this potential problemLwe removed three tubes"from the hot leg side 3
- of S/G.No. 14'.on1 September 9, 1983'.
-The three tubes were designated'as Row'21 Column 31, Row 17 Column 33 2
and Row 18 Column 33.
'The. tube' designated Row 21 Column 31 was t
Jpreviously plugged because!of a 84% tubesheet indiction.
The plug on i he hotEleg side required' removal' prior to pulling this tube and the t
- plug
- in the' cold leg side remained in place.
The tube removal required thefmechanical pluggingLof'the the' additional two tubes on the' cold leg sideiof theisteam, generator.
7All'three tubes'wereJcut just below the second support plate and then
'were pulled.through:the-tubesheet-opening by means of an integral
' gripper attached'tc~a hydraulic ram system.
.Once the tubes were. removed the tube sheet holes were prepared, and a semi-automatic welding-tool war' installed in the channel head.
The welding tool was remotely controlled from an area away from tne steam generator platform.- The weld plugs were installed in the prepared tube sheet-holes and welded into. place.
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cThe equipment-and procedures were qualified by Indiana and Michigan i
Electric Company Maintenance-personnel and the welding was performed by L
our. Maintenance-personnel with. direction-being provided by Westinghouse personnel.
'1'
- Thel inal step in the process was a visual inspection of the welds by a f
. Westinghouse Quality Assurance. Engineer who-indicated that the welds' were acceptable.
In. addition, the steam generator was filled with water to-45 feet above~the tubesheet and a leak test was performed aroundlthe welded' plugs with no evidence ur leakage noted.
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L1983' ANNUAL INSERVICE INSPECTION REPORT OF UNIT NO.2
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. June 1983 Outage (Unscheduled)
LOn. June 123, 1983',7 Unit 2 was taken out of service due to an indicated
- primary. to Lsecondary leak -in Steam Generator No. 23 of.06 GPM.
A
' defective tube-: Row' 1 Columr. 72 was identified by helium leak testing.
"Allituhes in Rows ~l'and:2 were: individually tested by'the helium method!and a' scan'was made of the rest'of the' tubes. 'Only the one tube 1wasJfound::to-be defective, and it was verified by eddy current 5 testing.and' mechanically plugged.
The tubes surrounding Row 1 Column 72Ewere.alsofeddy current tested.with no defects found.
The unit was iparallel July'9,-1983 at.2130 hctrs.
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JOctober 1933' Outage (Unscheduled):
A-
- On.0ctober?15,.1983,-Unit 2fwas taken out of service due to an' 1 indicated primarycto secondary leak occurring in-Steam Generator No's.
21,f22:and 23.
~
- The; unit was' drained'to half-loop and the primary side of the steam
- generators was^openedion' October 21 and helium leak cesting was started
-fon Octobe:424.
.The following. tubes were identified as leakers by ihelium testing:
- S/GE No; -- 21 ~
- S/G No. 22
- S/G No.-23
-Row,.1, Column 84-Row 1, Column 73 Row 1, Column 24
-Row?1,LColumn 88 Row 1, Column 25
.As verifications of'the helium testing, Westinghouse performed eddy current testing (ECT) on the. leaking tubes and.all tubes adjacent to
.theJ1eakers.
ECT confirmed inside diameter indications in the U-Bend.
region'of each of1the leakers.
None'of the other tubes tested showed indications. 'ECT results1were as follows:
Tube No.
Defect Location
'S/G1No. 21' Row-1,gColumn 84 U-Bend, Hot Leg Tangent Point S/G No. 21-
~ -Row 1,1 Column 80 U-Bend, Apex L
lS/G No.:22~
Row 1, Column 73 U-Bend,' Cold Leg Tangent Point b
.S/G No.f23 Row.1, Column 24 U-Bend, Cold Leg Tangent Point
- S/G No. 23
. Row 1, Column-25
- U-Bend,. Cold Leg Tangent Point
'The above:five tubes were mechanically plugged by Westinghouse on October 26 and 27.
1The Unit went critical at 0544 hours0.0063 days <br />0.151 hours <br />8.994709e-4 weeks <br />2.06992e-4 months <br /> and' entered Mode 1 at 0643 on
~
- Novemberf7, 1983. ' Steam Generator No. 21 still showed some activity
.followingjtube' plugging..
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- The Unit was. brought out of service again, on November 7, 1983, at 2128 i
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' hours after reaching an. indicated primary to secondary leak rate of
,approximately.293 GPM in Steam' Generator No. 21.
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c.c The primary manway was reopened and a visual examination of the tubesheet was performed with the steam generator full of water.
The visual examination identified a positive leaking tube on the hot leg side in Row 16, Column 40.
Temporary plugs were inserted into the leaking tube, both hot and cold leg tubesheets, so that the steam generator secondary side could be pressurized with helium.
Twenty-four stubes surrounding the known leaker were tested with no signs of leakage, also Row 1 and 2 tubes and a complete scan of the tubesheet was inspected with no indiction of leaking tubes.
After completion of helium testing,- the steam generator.was degassed and temporary plugs removed.
Eddy current testing commenced on November 12, 1983, to identify the
. mechanism and location of the known failure.
An eddy current
' inspection of a 5 x 5 tube grid around-the leaker showed that all tubes in the test _ area were dented at the top of the tubesheet on the hot leg side and two of the tubes had pluggable indications just above the tubesheet (Row 14, Column 40 and Row 14, Column 41 - both 87% defects) along with the Row 16, Column 40 throughwall defect.
'Although eddy current testing could not positively identify the tube degradation mechanism, stress corrosion cracking (or a similar corrosion phenomenon) is believed to be the probable cause.
Since tube identing is considered a precursor to corrosion-induced tube degradation, the Eddy Current Inspection Program was expanded to include all dented tubes'in the' sludge pile region of Steam Generator
-No.
21.
Additionally, when a review of Steam Generator No. 21 eddy current data from April, 1981, showed that all three of the pluggable tubes had previously exhibited a " suspect" or " unidentified" tubesheet
. signal similar to that now seen on other Steam Generator No. 21 tubes, a complete review of recent ECT data ~for Steam Generator No. 23 (1982) and No. 24 (1981) was initiated to see if similar signals were present.
Eddy current testing of the pertinent areas of Steam Generator No. 22 had not been performed since 1979, so it was decided to open Steam Generatnr No. 22 for a limited ECT inspection.
A careful review of new and previous data by both the on-site Zetec Data Analyst and by Westinghouse Steam Generator Technology Division personnel resulted in the discovery of numerous suspect ECT signals in all four Unit 2 steam generators.
However, the final conclusion was that suspect tubesheet-signals cannot be definitely linked to tube degradation at this time.
Westinghouse recommends performing metallographic analysis of tube samplas, during the upcoming Unit 2 refueling outage tentatively scheduled during the first quarter of 1984, to properly characterize these signals and determine their
-impcctance.
On-Steam Generator No. 21, a total of 728 tubes in the sludge pile region were inspected full length.
Hot leg side dents were found at the top of the tubesheet in 388 tubes, but no tube degradation other than the three previously mentioned defects were found.
The three defective tubes were mechanically plugged on both the hot and cold legs.
i 11 i
On Steam Generator No. 22, a total of 572 tubes in the sludge pile L
region were inspected full length.
Dents were found at the top of the tubesheet on the hot' leg side of 19 tuben.
The only incidence of tube degradation was a 39% (non-pluggable). indication at the No. 4 anti-vibration bar intersection of Row 10, Column 31.
Additionally, all Row 1 tubes on. Steam Generators No. 21 and 22 not previously plugged were eddy current tested through the U-bend region, with no indications being found.
Designated Tubes Plugged
.S/G No. 21 Indication Rcar 1,' Column 84 100% H/L - Mechanical Plug - C/L - Mechanical Plug Row 1,_ Column 88 100% H/L - Mechanical Plua - C/L - Mechanical Plug Row 14, Column'40 87% H/L - Mechanical Plug - C/L - Mechanical Plug Row 14, Column 41 S7% H/L - Mechanical Plug - C/L - Mechanical Plug Row 16, Column 40 100% H/L - Mechanical Plug - C/L - Mechanical Plug S/G No. 22 Row 1, Column 73 100% H/L - Mechanical Plug - C/L - Mechanical Plug S/G No. 23 Row.
1, Column 24 100% H/L - Mechanical Plug - C/L - Mechanical Plug Row 1, Column 25 100% H/L - Mechanical Plug - C/L - Mechanical Plug
-Row-1, Column 72 100% H/L - Mechanical Plug - C/L - Mechanical Plug l-
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1983' ANNUAL INSERVICE INSPECTf0N' REPORT OF UNIT NO.1 AND UNIT 2 PORVs TheLfollowing is a. list' of. Unit 1 and: Unit 2' Pressure Operated Relief
, ValvesLchallenged during the 1983 calendar year-
- VALVE NO'.'
DATE CHALLENGED STROKE TIME j
t NRV-151L
_ July 16, 1983 3.94 sec.
November 23, 1983 4.47 sec.
1-NRV-152 July 1 16, 1983
-4.59~sec.
November.23, 1983 3.05 sec.
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1-NRV-153 July 16', 1983-3.39 sec.
~ November 23,.1983 2.55 sec.
. ( NRV-151-January 14, 1983 4.6 sec.
- July 3, 1983 4.7 sec.
November.3, 1983-4.7 sec.
2-NRV -152 January 14, 1983 4.3 sec.
July-3, 1983 4.6 sec.
l November 3, 1983 5.5 sec.
- - 2 -NRV-15 3 -
January 14,-1983 5.8 sec.
' July 3, 1983 5.7 sec.
November 3, 1983 6.3 sec.
The. valves lis'ted.above'wer'e challenged in.accordance with the
' Inservice Inspection Valve Program and successfully passed there
. operational test. ' Documentation is maintained in the D.C. Cook Plant s Information and-Records' Center vault.
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CHANGES TO FACILITY Brief descriptions and summary safety evaluations for design changes (RFC's) made to the facility as described in the Donald C. Cook Nuclear Plant Final Safety Analysis Report (FSAR) are presented in this section.
These char.3es were completed pursuant to the provisions of Title 10, Code of Federal Regulations subsection 50.59(a).
DC-12-1614 (Unit #2 Only)
The 3-vay modulating glycol valves on the Ice Condenser Air Handling Units were replaced on Unit #2 of the Donald C. Cook Nuclear Plant. These valves were replaced with a 2-way (on-off) solenoid valve. The valves were replaced for two reasons:
- 1) Replacement.3-way valves are no longer avail-able, and 2) As described in our response to Question 022.11 in the Unit #2 Appendix Q to the FSAR (prior to submittal of the Updated FSAR) the 3-way valves were being operated as 2-way valves because of the problems asso-ciated with the valve actuators.
The AHU's are categorized as Seismic Class II components and are re-quired for the proper operation and maintenance of the ice condenser system.
The ice condenser is a very important design safeguard relied upon to miti-gate the consequences of several design base accidents. Operability of the ice bed, mandated by the Technical Specifications, requires implicitly the function of the AHU's to keep the temperature of the ice bed at or below 27 F.
Thus, this RFC is considered safety related.
The change is not considered to be an unreviewed safety question in accordance with 10CFR50.59 (a) 2; and, in fact, will improve the overail reliability and operability of the AHU's.
This RFC will not adversely affect the health and safety of the public nor create a substantial safety hazard.
DC-12-1742 (Unit #1 Only)
An air operated containment isolation valve (PCR-40) and a check valve were installed on the containment penetration for the Plant Air System of
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- 14 Unic #1 of the Donald C. Cook Nuclear Plant. The air operated valve which is located outside containment and the check valve which is located inside containment fulfill the requirements for double isolation for containment penetrations. The air operated valve can be operated from the Control Room and is designed to close upon a containment Phase A isolation signal.
Prior to the modification, the system was required to be isolated by the installation of a blind flange prior to the Reactor Coolant Sy. stem entering Mode 4 (Hot Shutdown). This modification will allow remaining maintenance activities requiring the use of the Plant Air System to con-tinue during primary system heatup following a cold shetdown or refueling outage.
This RFC is considered safety-related because it involves modification of a containment penetration and its corresponding isolation system. The planc service air line is presently a Class E containment isolation syrtem which includes a closed manual valve and a membrane barrier (such as a blind flange). The proposed system which is comprised of a check valve and an automatic valvs will be a Class A containment isolation system as defined
-in FSAR Chapter 5, Section 5.4.
This is consistent with the licensing basis of the Cook Plant which differs somewhat from current NRC criteria such as GDC-56. We are not required at the present time to comply with CDC-56 and as such this RFC is acceptable.
This safety review is conducted on the RFC compliance of containment integrity under various plant conditions and it indicates that the proposed changes do not create substantial safety hazard nor involve an unreviewed safety question as defined in 10CFR50.59.
DC-12-1765 (Unit #1 Only)
An intern diate low load trip circuit was installed on the Manipulator Crane in Unit #1 Containment. This modification allows the setting of a weight-loss trip limit on the manipulator crane to prevent fuel assembly damage during core alterations. The circuitry will prevent travel of the hoist when a loss of weight (approximately 300 lbs.) occurs in any posi-tion other than the down-direction of the gripper tube in the core and transfer areas.
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The manipulator crane is a Class 111 system. This RFC is safety-interface, however since it must be assured that this modification will not result in any adverse interactions with the fuel.
PCC DC-12-1765 does not constitute an unreviewed safety question as defined in 10CFR50.59, nor does it compromise the health and safety of the general public.
DC-12-1814 (Unit #1 Only)
The interlock system on the Unit #1 Containment personnel airlocks was replaced with a new quick acting interlock system to eliminate frequent pro-blems with the latch operated interlock system.
The new system consists of a new cam and cam follower that replaces the latch operated interlock. The cam is attached to the opening turning gear and.the follower interlocks the opposite door by means of a ratchet and pawl.
During the door opening cycle, the door latching pins actually extend slightly before they begin to retract.
It is during this period of slight extension and retiaccion to the original closed position that the mechanical interlock-ing of the opposite door takes place. Therefore complete interlocking of the opposite door is assured well in advance of the parting door seals.
This RFC is classified as safety interface as its function is to help maintain containment integrity. The doors can only be opened manually and failure of this mechanism is always in the safe mode in that it would not open the personnel airlocks.
This new interlock system improves the performance of the airlock sys-tem and reduces the possibility of breaking containment integrity.
Imple-mentation of RFC DC-12-1874 does not create any safety hazards nor con-stitute an unreviewed safety question as defined in 10CFR50.59.
DC-01-1940 A third source vange channel consisting of a spare source range detec-tor, preamp and instrumentation drauer was installed in Unit #1 of the Don-aid C. Cook Nuclear Plant. This modification was required because the place-ment of irradiated sources on the core periphery for Cycle 8 was expected to produce non-conservative 1/M plots. The " shine" from the irradiated sources
.t' e '-
16 was expected to mask core neutrons and as a result the existing source range 1
detectors might not provide the accurate /M plot", necessary to monitor the core during,startup.
Installation of an extra source range detector in a spare detector well located 900 from the current detector locations was re-1g/
quired to remove this source " shine" effect and to produce the type of plots presently seen during startups. This third sourcc range channel was installed for indication purposes only and provides no protective functions.
The detector was-installed in the spare detector well located at the 270 position of the reactor. The preamp is located in the reactor cable tunnel. The source range drawer was seismically mounted in the Nuclear Instrumentation Cabinet III located in the Control Room.
Existing spare cabling was used to connect the detector to the preamp and the preamp to the instrumentation drawer.
In order to be bounded by an FSAR analysis, the worst possible reac-tivity addition rate due to operator inability to assess criticality during i.
i -
Unit #1 Cycle 8 initial criticality must be less than or equal to 75 pcm/sec.
(Section 14.1.1 of the FSAR analyzes the consequences of an cccident with a reactivity insertion rate of 75 x 10-5 AK /sec, or 75 pcm/sec.)
K Assuming criticality is approached by deboration, and assuming a conservative boron reactivity worth of 15 pcm/ ppm, the boron dilution rate of 5 ppm /sec, is set as the maximum allowable rate.
3 Review of the FSAR shows an RCS total inventory of 11,780 ft, and 3 sec.
Assuming RCS
/
a maximum CVCS charging rate of 300 gpm =.0668 ft boron of 3,000 ppm, and charging of unborated water, the ma-imum physi-cally possible boron dilution rate is.21 ppm /sec.
Therefore, the worst uncontrolled reactivity addition rate due to opera-
, tor unability to assess criticality is easily _ bounded by the FSAR uncontrolled rod withdrawal analysis.
Based on the above, it is believed that the initial approach to criti-t cality, as planned, will not create any substantial safety hazard, nor will it constitute an unreviewed safety question as defined by 10CFR50.59 or adversely affect the health and safety of the public.
17
_yL;,-
.DC-12-2448-(Partial)
This RFC was initiated to; upgrade the Radiation Monitoring System in order to comply with the requirements of NUREG-0578 and 0737. The follow-
. ing paragraphs identify the' changes that have been completed:
'1)-
.Two (2);Victoreen Post Accident High Range Containment Area Moni-
~
each containment. The upper volume moni-tors were installed in tcrs are designated VRA-1310 (Unit #1) and VRA-2310 (Unit #2).
They are lecated near the 180 mark in the containment at an elevation ofy559'-7 ". The lower containment monitors are desig-nated VRA-1410 (Unit #1) and VRA+2410 (Unit #2). They are lo-cated near.the 00 mark in the containment at an elevation of 618'.- The upper volume monitors are powered from a Train A source and.the lower volume monitors are powered from a Train B source. The monitors have a range of 10 to 107 R/Hr (gamma) which ueets the requirements of Table II.F.1-3 of NUREG-0737.
2)-
An Eberline.Model SPING-3 high range noble gas monitor was in-stalled on the common discharge header from the Steam Jet-Air p'
Ejectors..The monitors SRA-1900 (Unit #1) and SRA-2900.(Unit #2) have a range of'10-7 to 10+3 yci/cc noble 1 gases to cover normal
_ operation and' post accident conditions.
' 3)
-An Eberline Mddel;SPING-3 high range noble gas monitor was in-
. stalled on the Turbine Gland Steam Condenser Vent Line. The monitors SRA-1800 (Unit #1) and SRA-2800 (Unit #2) have a range of 10-7 to 10+3-pei/cc noble gases to cover-normal operation and post _ accident conditions. The design basis maximum 1 range of the moaitor is. acceptable based on the belief that the gland steam exhaust is'somewhat analogous to the "PWR steam safety valve discharge" which has a design basis 3
maximum range to 110.pci/cc noble gas.
D4)-
Eberline Noble Cas monitors were installed upstream of the
' Safety' Valves.and Power _ Operated Relief Valves on each steam generator. : The detectors for these monitors are located in the Main Steam Enclosures and are identified as follows:
s Unit #1 Unit #2 S/G #1 MRA-1601-MRA-2601-S/G #2
-MRA-1701 MRA-2701 S/G #3 MRA-1702-MRA-2702
'..S/G #4 MRA-1602 MRA-2602 These monitors have a range of 10-4 to 10R/Hr gross gamma.
In
=accordance with clarification (3) of Item II.F.1, Attachment 1, externally mounted monitors viewing.the main steam line upstream
'of.the SV/PORV's-are~ acceptable with procedures to correct for the low energy gammas ~thatLthe external monitors would not detect.
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An Eber11.1e model SPiNG-4 high-range noble gas,oparticulate p
and iodine monitor was installed in the unit vent.
The moni-I tors VRS-1500 (Unit #1) and VRS-2500 (Unit #2) utilize several overlapping detectors in order to cover normal operation and post accident conditi The design basis maximum range ofthemonitor,opto10+gns.p ci/cc noble gas, meets the require-ments of Table II.F.1-1 for monitoring " diluted containment
. exhaust gases" and auxiliary building ventilation system dis-
-charge.
t The incorporation of extended range particulate and radio-iodine sampling capability into VRS-1500 and VRS-2500 ful-fills the requirements of 1:em II.F.1, Attachment 2 and Table i:
11.F.1-2 regarding the ability to obtain a sample of plant gaseous effluents for analysis of post accident releases of
[
radioactive iodines and particulates.
The following is an overview of the Radiation Monitoring System:
GENERAL All radiation measurements are made with a standard Eberline detector
. combination which is served by a local processor (field unit). The local processor performs background subtraction, applies conversion factors, and
- retains the data from cach detector channel in history files consisting of the last 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of ten-minute averages, the last 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of one-hour averages and the last 24 days of one-day avereges. Each local processor is AC operated with 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of battery backup.
Bi-directional communication is provided between all local processors and two central control terminals.
Provisions exist to access each local processor with a portable control ter-minal to conduct calibration and service functions at the local processor's
' location.
Each local processor with its detectors is optically isolated from the rest of the system. Failure of a local processor or its detector (s) will have no effect on any other portion of the system.
Each locat processor communi-cates with two (redundant) control terminals via two (redundant) communica-L tion interfaces. Because the local processors are completely self-support-ing for the performance of their tasks, even simultaneous po+.cr failures at both control terminals do not result in any loss of data accumulation or storage in the local processor.
LOCAL PROCESSOR The local processor performs the tasks of data acquisition, history management operational status and alarm determinations and communications with the Control Room Control Terminals. A microcomputer supports up to E
nine detector channels which are present in the local processor.
h History files are maintained on each channel (detector) in three time details. These files are (a) 23 each 10-minute intervals, (b) 24 each 1-hour intervals and (c) 24 each 1-day intervals. The data presented for any inter-val are the average of the data a cumulated during that interval. Trend, alert and high alarm data are included in the averages. Any of the history
-files may be requested for printout from the Control Tarminal.
19
}
.,e AIRBORNE MONITORS These radiation monitors collect and measuru particulates and Iodine 131, and measure the amount of noble gas in the passing airstream. The particulate channel uses a fixed collection filter, monitored by a beta scintillation detector from one side and a solid state alpha detector (for background sub-tract purposes) on the other side. The Iodine 131 channel uses a charcoal cartridge for collection and is monitored by a gain-stabilized (to mini-mize the effects of drift caused by fluctuations in temperature and/or aging) 2s. inch x 2-inch NaI(TI) gamma scintillation detector. The effects of a fluctuating noble gas measurement is performed by several detectors viewing a sample volume.
Low and medium range noble gas detectors view the same sample volume. A high range noble gas detector utilizes a sec-tion of one-inch stainless. steel tubing as the sample volume. Ranges of Ci/cc; the three noble gas detectors are:
Low range, 1E-7 pCL/cc to 4E-2 p i
Medium range, 2.5E-2 pCi/cc to 1E3 pCi/cc; High range, 1 pCi/cc to 1ES pCi/cc.
BACKCROUND SUBTRACTION Each detector channel has the capability to compensate for background contributions by subtracting signals which are related to background inter-ferences as determined by any two of the other detector channels in the local processor.
For example, the beta particulate monitor response could be affected by a combination of ambient gamma radiation and radon-thoron daughter beta decay products. All background subtraction must be performed by detectors in the local processor. No background subtrnction input can be accepted by one local processor from another local processor.
Similar capabilities exist for any monitoring channel.
In addition to variable contributions, the count rate of a channel can be affected by non-time dependent factors such as fixed contamination in the sample shield.
'Each channel, therefore, has the ability to reduce its count rate by a fixed number. The end result of background subtraction is to produce a net count which is as close to the actual desired response as is possible.
SPING SAMPLC SYSTEM DESCRIPTION The sample enters the front tube ;,nd is drawn through the particulate filter. The filter is held in position by the RDS-1 alpha radon detector and is in a fixed geometry between the RDS-1 and the RDA-3A beta scintill-ator.
The sample exits the particulate filter and is drawn into the iodine sampling station. There, it passes through a charcoal cartridge which la viewed by a RDA-2A gamma scintillation detector. The cartridge is held in place by a removable cartridge holder and is in a fixed geometry with the RJA-2A.
The sample exits the iodine charcoal cartridge and is drawn into the noble gas sampling station. This is a fixed, cylinder-shaped volume viewed at one end by a RDA-3A beta scintillation detector. The other end of the
?Lf:
20 cylinder is a lead plug which supports the mid-range noble gas detector.
This detector is located on the center-line of the gas volume cylinder and is F ' ' rounded by the sample.
The sample then exits The low and mid-range noble gas chamber.
It con-tinues to a flow metering orifice, pressure gauge, high range noble gas moni-tor, sample pump, and returns to the process flow.
The subjec.t RFC calls for exteasive modifications of and additions to the. Radiation Monitoring System (RMS). These modifications are intended to assure compliance with the requirements of NUREG-0737 Item II.F.1 - Attach-i6 ments 1, 2, and 3 and fulfillment of our commitments made to the NRC in this area.
Portions of this RFC involve Electrical Class 1E equipment and components requircd to perfora post-accident monitoring functions. These functions are considered to be safety related as per the provisions of Procedure No. NSL/7.
The following items were considered durint,the safety review of this
.RFC:
(a)
No aluminum or mercury is being introduced into the con-tainment under this RFC.
(b)
The number of cabling runs made for installation is apprxoimately 400 which are routed both in the cable tray and conduits. This item pertains to Fire Pro-tection concerns and we find it acceptable that it be addressed as part of the Appendix "R" review.
(c)
Verification of Seismic acceptability of the Victorcen high-range area monitors car; be found in Victoreen Qualification Test Report No. 950.301.
(d)
The RMS contract C5252 shows compliance with the over-all f., tent of the separation criteria for Class 1E circuits on the non-class 1E portions of the RMS.
The Hi-range in-containment area monitor is the only portion of the RMS which is required by NUREG-0737 to be Class 1E.
This monitor was designed to meet these requirements.
(e)
The. hest tracing provided under this RFC is of the appcopriate classification to ensure proper opera-tion of the detectors.
(f)-
The classification of the alarms, annunciators, and the CRT as safety-related by Nuclear Safety & Licens-ing does not constitute imposition of any design re-quirements such as the requirements for Class 1E cir-
21
?
i cuits.
(e.g. IEEE-279, IEE-344, etc.)
Rather, the classification of these items as ' safety-related' re-
'flects Nuclear Safety & Licensing's belief that these devices would provide important inforaation to the
. operator following an accident. The digital display provided in the control room for the Victorcen area monitors is the sole Class 1E display device provided under this RFC.
' Nuclear Safety & Licensing has concluded that implementation of this F,FC'does not constitute an unreviewed safety question as defined in 10CFR50.59 and will not adversely af fect the health and safety of the general public.
LC-12-2524 An Uninterruptible Power Supply was installed to provide the Technical Support Center (described in Chapter 12.3 of the FSAR) with the transient free, goality power source necessary for computer based loads. NUREG-0696 states, " circuit transients or power-supply failures and fluctuations shall not cause a loss of stored data vital to the Technical Support Center func-tions.
Suff; lent alternate or bacPup power sources shall be provided to maintain continuity of Technical'bupport Center functions and to immediately resume data acquisition, storage, and display of Technical Support Center data if loss of the primary Technical Support Center power sourc s occurs."
The Uninterruptible Power Supply provides a continuous source of power with a sufficient level of reliability to meet this requirement.
t.
The Interruptible Power Supply consists of a battery, two battery chargers (one in service, one installed spare), static inverters and their associated static transfer switches. The 125V battery is rated at 725 amps for a 30-minutc. period and consists of 60 lead calcium cells. The battery
. chargers provide 125V 700 amp DC output from a 575V, 3-phase AC input. Two (2) 40KVA and'one (1) AOKVA (installed spare) single phase inverters provide 120V.AC output from a 125V DC input. All inverters are equipped with zero-4 break static transfer switches and maki-before-break manual bypass switches.
The normal source of AC power to t he Uninterruptible Power Supply and Technical Support Center is the 600 volt balance of plant bus through a 80KVA, 600V primary, 120V secondary single phase regulating transformer.
If the normal AC source is lost, the automatic transfer switch aligns the in-service and reserve battery chargers to the 600 volt security bus, which is energized by the security diesel.
If this energy source is subsequently lost, the battery will supply the inverters for a minimum of 30 minutes.
If after 30 minutes the normal and bs:kup sources are still unavailabic, the static traasfer switch will automatically align their reep<ctive Tech-nical Support Center loads to the 600 volt saiory bus fed from the Unit #1 CD Emergency Diesel Generator. A cross-tie between the Uninterruptible Power Supply room and the Security Uninterruptible Power Supply room enables the spare 60 KVA inverter to service both Uninterruptible Power Supply rooms.
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22 1The.Uninterruptible Power. Supply Room is located on the Auxiliary Building roof above the Unit #1 Control Room. - The Uninterruptible Power
. Supply Room is designed to withstand all environmental conditions in-cluding earthquakes. Anchorinr,of the roc.m is designed to meet Seismic Class I criteria even though it.is not required.
f
. RFC DC'-12-2524 is safety interface-since the Uninterruptible Power
- Supply will-insure the continuous availability of1 technical data to aid Technical Support' Center personnel in handling emergency conditions and since it is. connected.co a. backup tource of power from a 600 volt safety bus.
Electrical Engineering has determined that the addition of this non-
. safety related. load will not overload the Emergency Diesel Generator. The 225A Motor Control Center Breakers and the 600/120 transformer provides adequate protection against the poss?bility of a failure propagating from the Uninterruptible Power Supply system to the Emergency Diesel Generator.
The Design Division has're-analyzed the seismic response of the auxi-liary building roof with the additional loads-introduced by Uninterruptible Power Supply RoomTand concludes that the Uninterruptible Power Supply' Room will not degrade the function of the auxiliary building roof nor will the
' method of attachment.
RFC DC-12-2524 does not constitute an unreviewed safety question as de-
. fined in 10CFR50.59 and will not adversely affect the health and safety of the public.'
~
DC-12-25258
'The Control' Room Ventilation Systems for both units of the Donald C.
Cook' Nuclear Plant were modified to fulfill the requirements for Control 2 Room Habitability specified in Item III.D.3.4 of NUREG-0737. The follow-ing itens were included in this modification:
- 1). Weatherstripping was adoed to the Control Room doors, the ' door to the Control 11oom Machine Room and the hatches between the Control Rooms and the Control Room Cabic Vaults. This weatherstripping was added to seal the doors and hatches against an internal control room pressure differential of up to h" water.
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2)
Isolation dampers ACRDA-2 and ACRDA-3 were reset to
. limit makeup air flow through ACRDA-2 to-less than 80 CFM fo11c91ng a control room isolation signal re-sulting from a LOCA. This makeup air is sufficient to pressurize the Control Room to 1/16" water differ-ential between the Control Room and out-of-doors when one of the filter system fans is running.
3)
The fresh air supply (via the normal air conditioning system) was balanced to 570 CFM.
4)
The logic for Control Room. isolation was modified to automatically start the lead fan on each unit upon receipt of a Phase A signal.
5)
The control switr.hes for isolation dampers ACRDA-1,
-2,
-3 and -4 (Unit-#1) and ACRDA-1, -2 and -3 (Unit #2) were relocated from the ACRA-1 and ACRA-2 air conditioning subpanels in the Control Room Machine Room to the "VS" pancis in the Control Room.
6)
A chlorine detection alarm system was installed to alarm in the Control Room upon sensing 5 ppm chlorine at the fresh air intake of the Control Room Pressuri-zation system.
RFC DC-12-2528 proposes certain modifications to the Control Rooms to s
meet the habitability requitements derived from our review of NUREG-0737, Iten 111.D.3.4.
The modifications involve safety systems (Item 4 in parti-cular) and, therefore, this RFC is considered safety related.
These proposed modifications have been reviewed conceptually by the NRC and found to be acceptable. -After the installation of the modifica-tions, they must be thoroughly tested to ensure that the operability re-quirements for air flow and pressure predicated in AEP:NRC:0398C are met.
The subject RFC has been reviewed and found to be acceptable.
It does not constitute an unreviewed safety question as defined in 10CFR50.59 and will improve the occupational safety for the plant operators.
DC-12-2578 (Unit #2 Only)
The Westinghouse Upper Containment Area Radiation Monitor VCR-302 (R-2) was replaced with two independent Eberline Area Monitor Channels (VRS-2101 and VRS-2201). The range of these channels is the same as before: 0.1mR/hr to 10R/hr.
r 24 Each area monitor channel is electrically Train oriented and is capable of automatically isolating seven of the following containment ventilation valves through the Containment Ventilation Isolation circuit.
1)
VCR-101, -201 Instrument Room Purge Supply 2)
VCR-102, -202 Instrument Room Purge Exhaust 3)
VCR-103, -203
',wer Containment Purge Sunply 4)
VCR-104, -204 eer Containment Purge Exhaust 5)
.VCR-105, -205 Upper Containment Purge Supply 6)
VCR-106, -206 Upper Containment Purge Exhaust 7)
VCR-107, -207 Containment Pressure Relief The Train A device (VRS-2101) is capable of isolating the seven valves located inside containment (VCR-101, 102, 103, 104, 105, 106 and 107).
It is located on the 650' elevation near the refueling upender console.
The Train B device (VRS-2201) is capable of isolating the seven valves located outside containment (VCR-201, 202, 203, 204, 203, 206 and 207).
It is located approximately 35 feet above VRS-2101 and is mounted on the crane wall.
A meter, lights an annunciator horn are mounted locally near each de-tector. The meter indicates the current radiation level at that location.
The blue light indicates a detector or cable failure. The red light and horn indicate that the High Alarm setpoint has been reached or exceeded.
This R7C is considered to be safety related as per the provisions of Procedure No. NSL/7.
The equipment installed as part of the permanent modification will be seismically and environmentally qualified in accordance with IEEE-344-1975 and IEEE-323-1974 and the new " system" will be installed in accordance with IE standards. This permanent revision will fulfill our commitment made to the NRC in our letter No. AEP:NRC:0295B dated March 25, 1980.
Nuclear Safety & Licensing has reviewed the information contained in the RFC Packet, the documents listed on Form 7-1 (The "NS&L Checklist"),
and the Indiana and Michigan Electric Company drawing numbers 1-98816-0, 1-98304-6, 2-98816-0 and 2-98304-3 and has discussed the proposed modifi-cation several times with the RFC Lead Engineer and other involved parties.
As a result of these reviews and discussions, Nuclear Safety & Licensing has concluded that implementation of this RFC does not constitute an un-
- reviewed safety question as defined in 10CFR50.59 and will not endanger the health and safety of the general public.
Implementation of the proposed modifications will fulfill the commitment made in our AEP:NRC:00642 letter dated December 7, 1981.
DC-12-2605 Debris screens were installed over the return air duct outlets of the Ice Condenser panels in each unit of the Donald C. Cook Nuclear Plant. The screens were fabricated from.063 inch diameter galvanized carboa steel wire
R 1
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.y d;:
,~
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. mesh'with.'5624' inch _ openings. This wire mesh.has an approximate free area L
1 ofr80.9%. The screens are installed on the top of the supply headers along i the containment and crane walls and under the subway grating at the end walls.
The screens were required to prevent debris from talling into the return duct and interfering with the. air flow through'the Ice Condenser Panels.
'This change' involves a modification to a Class I stracture, and be-4
~
'cause there is the' possibility of the screens falling off and prohibiting
.~ normal _ air flow through the. ice condenser panels, the change is considered
- .b safety interface. Normal air. flow is necessary to maintain the proper ice weight.in the. ice condenser required by Technical Specification 3.6.5.1.
The Nuclear Safety & Licensing Section require that the proper engineer-Ling judgment be used when anchoring the screens to make sure that they will not. loosen during normal operations, during an accident conditions (LOCA),
nor.during a design basis earthquake (DBE).
-This RFC does not create any substantial safety hazards, nor does it
-constitute an unreviewed safety question as defined in 10CFR50.59, nor will zit adversely affect-the health and safety of the public.
-DC-12-2637
'( Un'i t #1 Only)
~
2 A redundant gripper' tube' full-up safety circuit in the form of a geared limit Twitch was added to-the' Manipulator Crane in Unit #1 Containment. The existisd Proximity switch for gripper tube full-up light was replaced with a geared limit' switch. Activation of both the geared limit switches are now requirad for' lateral-movement of the bridge and trolley.
Prior to~these modifications the activation of the gripper tube full-up light was all that was-required for crane movement. These modificetions assure that~ fuel assemblies are fully retracted into the gripper tuSe by preventing bridge or trolley mcvement of the crane if the inner mast is below the full-up position.
'The manipulator crane system is Class 11I equipment. This RFC is safety-interface,;however, since it must be assured that the proposed modifications
.will not: result in any adverse-fuel interactions.
Conversations with'the: Lead Engineer have indicated that these modifi-cations.should prevent fuel assembly damage, such as that which occ'trred during the 1981 Unit #1. Refueling Outage, since two different geared limit switches must.now be actuated. While we can not obtain a guarantee of this from Stearns-Rogers, the new safety circuit will decrease the possibility of "this type event from occurring.
-It must be assurcd that the installation s
~
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26
. - o and attachment of this equipment to the Manipulator Crane system will not result in the generation of any loose parts during normal operation or during the Design Basis Earthquake (DBE).
RFC DC-12-2637 does not constitute an unreviewed safety question as defined in 10CFR50.59 nor does it compromise the health and safety of the general publir..
DC-12-2662 This modif(cation involved draining the water seal from the loop seals upstream of the Pressurizer Safety Valves (SV-45A, -45B, -45C) on both units of the Donald C. Cook Nuclear Plant. A drain was provided at the bottom of the U-bend of the loop seal to remove possibic water accumulation due to condensation inside the loops. The drairs (h-inch tubing) from the indivi-dual loop seals are connected to a commor header (3/4-inch pipe) which in turn is connected to the lower connectior. of pressurizer level instrument NLI-151.
Prior to the modification the loop seals contained comparatively cold water (150 F +).
A thermal-hydraulic analysis performed in compliance with NUREG-0737, Item II.D.1 indicated potential overstressing of the Safety Valve piping system caused by the slug of cold water as it passes through the piping system.
It was decided to drain the loop seals to eliminate the cold water and allow only steam to pass through the system.
DC-12-2662 proposes modifications to the existing loop seals of the Pressurizer Safety Valves.
Since this modification involves a Seismic Class I system which is part of the primary pressure boundary, the subject RFC is classified as Safety-Related.
The Safety Valves at the Cook Plant are spring loaded Crosby Valves type 6M6.
In the full scale tests conducted by EPRI in compliance with NUREG-0737, Item II.D.1, it was observed that the valve disc exhibits measurable lift at the setpoint pressure, oscillatory behavior (chattering) during the loop seal water bleed off, and pop-opening on steam.
Follow-ing opening, the system blows down until the valve closes. The Crosby valves were not sensitive to back pressure. The chattering that was observed is attributed to two-phase " flashing" of water /steata flow through the valve.
During tests conducted without the water loop seals, dry tests, the valves opened at the set pressure with steam discharge only and did not exhibit chattering.
During one dry test, the Crosby 6M6 valve chattered following closing. However, the valve performed stably without chattering at blow-down pressures.
The as-built piping analysis being performed to determine the safety valve transient loads and the effect of water slug discharge through the valve and piping has shown that for Emergency Conditions the inlet and outlet piping loads are higher than allowable va'.ues.
These higher loads
27 Le
- J o-could overstress the dischart.3 piping system. The hydraulic forcing func-tions on the piping system during a transient without the water seal were s
. rubstantially lower than'those with the' water loop seal. Therefore it was-decided to drain the water.from the Safety Valve Loop seals.
In the Cook: Plant.the Safety Valve setpoint pressure is 2485+1% PSIG.
, In some FSAR analyses,the overpressure transient is mitigated by the blow-down through the safety valves and will result in steam discharge through
.the' safety valves. Continuous water discharge enrough.the safety valves during the Feedwater Line Break accident is not predicted for the Cook Plant.with a water-solid pressurizer.
If during the unlikely event of a Safety-Valve transient, the discharge piping is overstressed because of the a,
- seal' water discharge, this could conceivably result in a failure of the piping and a LOCA (6" diameter). Under the condition of full rupture of the 6" line, the break area will be less-than 1.0ft2 (approximately 0.2ft2), and can be classified as a small break.
Small break accidents have been analyzed for both units and the details of the most up-to-date analyses are given in FSAR Section 14.3.2.3 (Unit #2) and in Attachment E to our letter No. AEP:NRC:0745C.
' The worst brsak size is 'a indh diameter break.
For the 6-inch break, the depressurization transient and the extent to.which the core is uncovered are shown in figures 14.3.2-10 and 14.3.2-12 of the FSAR, respectively. The FSAR analysis of the small break LOCA concludes that the high head portion zof.the Emergency Core Cooling System, together with the accumulators w!.11
. provide sufficient core flooding to keep the Calculated Peak Clad Tempera-tures below the' required limits of 10CFR50.46 and that, hence, adequate protection is. afforded by-the ECCS in the event of a small break LOCA.
Additional concerns raised by the NRC on the small break LOCA analyses in
.NUREG-0611 and NUREG-0737 are presently un' der study by the Westinghouse Owners Group.
-The-subject RFC DC-12-2662 has been reviewed and found to be accept-able as not_ constituting an unreviewed safety question as per 10CFR50.59 and the proposed modifications will not aoversely affect the health and safety'of the public.
DC-01-2716-A flow reducing orifice plate was installed in the discharge piping of the Unit #1 East Centrifuga1' Charging Pump.
The " thick orifice plate was. installed between the pump discharge flange and the pipe flange in order to1 reduce the flow rate at runout conditions.
Duritig recent flow balancing of the. Centrifugal Charging Pumps through
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_ the' Emergency Core. Cooling System, the East pump exceeded the single pump
- runout flow rate of 4/0 GPM.(excluding 80 CPM to the Reactor Coolant Pump S ea ls'). ' The total flow via the Boron Injectica Tank to the cold legs was measured'at 499 GPM'thus exceeding the maximum rate as stated in the Plant Technical-Specifications.
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In order to. reduce the increased capacity exhibited by the East pump,
- -it was recommended lby both Pacific Pumps and Westinghouse to install an
- orifice plate'in,the pump discharge.. The added res; stance provided by this orifice' plate reduced the flow and allowed the pump to' operate at the desired value. Pacific Pumps-has manufactured and successfully tested
' orifices for:the 2 -RLIJ Model pump in question to meet the design runout
- flow rate'for other' companies.
- 3-The'RFC has been classified as Safety-Related because the modification involves the discharge line of the Centrifugal Charging Pump which is a Seismic _ Class _I System.,The fundamental safety issue with regard to this
.-change is_that it brought the flow of both pumps within the required tech-nical specification limits. This'in fact has been accomplished.
-Nuclear Safety and_ Licensing has reviewed the. modification performed
- as1per-the review criteria in NS&L Procedure No. 7.
As a result of the review,1the modifications performed were found to be acceptable. As part of ou'r review process we locked in some detail at the orifice plate pro-curement and installatian. Although this activity performed under normal company procedures, this was a routine independent review tr assure the effectiveness of the procedure. with regard to safety related components.
- As'.a-result of that-review we found the orifice plate is made up of
.SA-182-316 stainless steel'and has' been procured and installed as ner i
the procedures applicable to the safety related systems. The required seismic review has been performed and found to be acceptchie.
The purpose of this' review isifor procurement, design, and instalia-tion.~
With~this in mind, it is concluded that this RFC does not c nsti-
- tute an unreviewed safety question' as defined in 10CFR50.59, nor does it
- create a substantial hazard to the health and safety of the public.
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,,,_ IN0/ANA & M!CHIGAN ELECTRIC COMPANY 31R^
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v DONALD C. COOK NUCLEAR EL Ni AN P.O. Box 458, Bridgman, Michigan 49106
- lO MMA (616) 4654 901 PA0 iCS isA lsF File duC' February 29, 1984 Mr. J.G. Keppler, Regional Administrator United States Nuclear Regulatory Commission Region III 799 P.cosevelt Road
-Glen Ellyn, IL 60137 Donald C. Cook Nuclear Plant Docket Nos. 50-315/50-316 License Nos. DPR-58/DPR-74
Dear Mr. Keppler:
Two copies of the 1983 Annual Operating Report for the Donald C.
Cook Nuclear Plant are being transmitted to you under this cover letter.
The information contained in this report covers the activities delineated in Appendix A (Section 6.9.1.5) of the Donald C. Cook Nuclear Plant Technical Specifications, and the
. requirements of 10 CFR 50.59.
Additional copies of this report have been transmitted to the I
Office of Inspection and Enforcement and the Office of Manegement Information and Program Control of the United States Nuclear Regulatory Commission as specified in Regulatory Guide 10.1.
Sincerely, ti(![b.
W.G.' & N Y Smith, Jr.
Plant Manager
/ bah Attachments cc:
John E. Dolan M.P. Alexich R.W. Jurgensen R.F.
Kroeger
- J.G. Feinstein d
G. Charnoff, Esq.
R.C. Callen, MPSC 3g J.M. IIennigan gg R. O. -: B r u g g e e, EPRI J.F.
Stietzel Dir., IE
' Dir., MIPC
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