IR 05000369/1989006
| ML20244D934 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 04/10/1989 |
| From: | Shymlock M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20244D932 | List: |
| References | |
| 50-369-89-06, 50-369-89-6, 50-370-89-06, 50-370-89-6, NUDOCS 8904240212 | |
| Download: ML20244D934 (55) | |
Text
{{#Wiki_filter:-_ _ _ ---______--_ _ __ _ e- '~ ,[.4 Kreug*o, NUCLEAR REGULATORY COMMISSION UNITED STATES , ',, +, [[ REGION il n 3 -~ j 101 MARIETTA STpEET, N.W.
- t ATLANTA. GEORGI A 30323
[. %n.,.....$ l l . Report Nos.: 50-369/89-06 and 50-370/89-06 Licensee: Duke Power Company 422 South Church Street Charlotte, NC 28242 Docket Nos.: 50-369 and 50-370 License Nos.: NPF-9 and NPF-17 Facility Name: McCuire Nuclear Station Units 1 and 2 Inspection Conducted: March 8-11, 1989 Team Members: S. Adamovitz, Senior Radiation Specialist J. Bongarra, Human Factors Specialist, Human Factors Assessment-Branch, NRR ' D. Hood, Licensing Project Manager, NRR L.-Lawyer, Reactor Engineer C. Liang, Senior Nuclear Engineer, Reactor System Branch, NRR W. Orders, Senior Resident Inspector, Catawba C. Rapp, License Examiner R. Shortridge, Radiation Specialist AWhv d/h/ddfA9 Team Leader: M. ShymToc:k{fhief 7 Date Signed l Reactor Projects Section 3A Division of Reactor Projects i 8904240212 890410 {DR ADOCK 05000369 i PDC _j _ _ _ _ _ _ _ ___
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t TABLE OF CONTENTS 1. INTRODUCTION - FORMATION AND INITIATION OF AUGMENTED INSPECTION TEAM (AIT) A.
Background...................................................
B.
Formation of AIT.............................................
C.
AIT Charter - Initiation of Inspection.......................
D.
Description of Operations Shift Staffing at the Time of the Event..........................
E.
Design Descriptions..........................................
F.
Persons Contacted..........................................
II. DESCRIPTION OF EVENT A.
Overvi ew of Event for McGui re Uni t 1.........................
1.
I n i t i al Co nd i ti on s.....................................
2.
Event Description.......................................
B.
Detailed Sequence of Events..................................
C.
Radi ol ogi cal Rel ea se s........................................
,
l 1.
I n i t i a l Re l e a s e.........................................
2.
S/G B Blowdown Release.......
......................... III. SUBSEQUENT LICENSEE ACTIONS A.
Emergency Re sponse and Reporti ng.............................
B.
Evaluation of Operator Actions and Procedural Adequacy.......................................
, C.
Use of the Condensate System to Cool Down....................
l i 1.
Blowdowns to Condensate Polisher........................
2.
Crosstie of Unit I and Unit 2 CST.......................
- 3.
Use duri ng Bac kfill Cooldown............................
. D.
Radiological Aspects of Event................................. 19 { t 1.
Release Pathway Summa ry................................
i 2.
Release Pathway Details...............................
3.
Sample Collection and Counting...... .....
........... , 4.
Environmental Sampling..............................
J IV. EQUIPMENT STATUS, FAILURES / MALFUNCTIONS AND ANOMALIES A.
Blowdown Recycle System............................
B.
S/G B PORV..........................
.................... C.
NV-2, Letdown Isolation Valve..........................
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D.
NC-243, Pressurizer Vent Valve Leakage....................... 25 E.
ND-32, ' A' ND Heat Exchanger to Letdown Heat Exchanger.......
F.
Radiation Monitor on S/G Blowdown............................
G.
S/G B T ube Le a k Ra te......................................... 26 H.
EMF Monitors.................................................
1.
S/G B Performance History...................................
1.
Maintenance History 2.
Minor Tube Leak in S/G B V.
FINDINGS OF THE AIT.............................................. 27 ' A.
Radiological Consequences....................................
B.
Operational and Procedural.................................
VI.
ROOT CAUSE DETERMINATION.......................................... 29 VII. CONCLUSIONS.......................................................
l VIII. PRE-EXIT INTERVIEW...............................................
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l APPENDICES AND FIGURES I ACRONYMS AND ABBREVIATIONS APPENDIX 1 - , APPENDIX 2 - DESIGN DESCRIPTIONS j a.
Chemical and Volume Control System (NV)- ' b.
Condensate and Feedwater System (CM and CF) c.
Steam Generator Blowdown System (BB) I ' d.
Condenser Steam Air Ejector System (ZJ) e.
Auxiliary Feedwater System and Secondary Steam Relief System (CA and SV) PERSONS CONTACTED APPENDIX 3 - Pressurizer Level Curve Figure I - Primary Pressure and S/G B Pressure Figure II - Figure III - S/G B Wide Range Level Figure IV Curies Released Graph - Figure V Procedure Usage Flow Chart - Figure VI - Condensate Polisher System Figure VII - Release Pathway Figure VII.a - Release Pathway Xenon Method Leakrate Figure VIII - Figure IX - Corrected Xenon Method Leakrate Figure X - Safety Injection System Figure XI - S/G Blowdown Recycle System
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REPORT DETAILS I.
INTRODUCTION - FORMATION AND INITIATION OF AUGMENTED INSPECTION TEAM (AIT) A.
Background l McGuire Units 1 and 2 are westinghouse (W), four loop, PWRs with ice ' condenser containments. Unit 1 employs model D2 steam generators and , Unit 2, Model D3s.
The facility is located 17 miles north of I Charlotte, N.C.
Unit I received a low power operating license June 12, 1981, went critical on August 8, 1981 and was declared commercial on December 1, 1981.
At 11:40 p.m. on March 7,1989 McGuire Unit 1 experienced a primary to secondary coolant leak in S/G B.
The appropriate notifications were made, with the NRC resident inspectors receiving notification at 12:10 a.m. March 8, some 25 minutes after the event, and the NRC Operations Duty Officer being notified at 12:44 a.m.
The first NRC resident inspector arrived on-site at 12:45 a.m.
B.
Formation of AIT On the morning of Wednesday, March 8, 1989, the acting Regional Administrator, af ter further briefing by the regional and resident staff and consultation with senior NRC management, directed the , ! dispatch of an AIT headed by a Region II Section Chief. The Regional team was augmented by Office of Nuclear Reactor Regulation participation.
C.
AIT Charter - Initiation of Inspection The AIT members arrived at the McGuire site on March 8, 1989 and the special inspection commenced with an entrance meeting and briefing by licensee management at 6:30 p.m.
The Charter for the AIT specified the following: 1.
Develop and validate a detailed sequence of events associated with the primary to secondary coolant leak in the 'B' steam generator (S/G) on March 7, 1989 and subsequent shutdown of i McGuire Unit 1.
2.
Evaluate operator actions during the event and subsequent recovery and assess operator use and adequacy of procedures including Emergency Operating Procedures and Abnormal Operating Procedures.
3.
Evaluate the significance of the event with regard to radiological consequences, safety system performance, and plant proximity to safety limits as defined in the Technical Specifications.
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4.
Evaluate the accuracy, timeliness, and effectiveness with which information on this' event was reported to the NRC.
.I 5.
For. each equipment malfunction, to the extent practical,_ l determine:
- 1 a.
Root'cause; b.
If the equipment was known to be deficient prior to the event; c.
If equipment history would indicate that the equipment had either been historically unreliable or if maintenance or modifications had been iccently performed; d.
Any equipment vendor involvement prior to or after the event; e.
-Pre-event status of surveillance, testing and/or preventive l maintenance; and l f.
.The extent to which the equipment was covered by existing corrective action programs and the implication of the failures with respect to program effectiveness.
6.
Identify any - human factors / procedural deficiencies related to the event.
7.
Through operator and technician interviews,' determine if any of the following played a significant role in each failure: plant material condition; 'the quality of maintenance; or the responsiveness of engineering to identified problems.
8.
Evaluate management involvement during the Unit I shutdown and the subsequent recovery from the event.
9.
Provide a Preliminary Notification upon initiation of the inspection and an update on the conclusion of the inspection.
10.
Prepare a special inspection report documenting the results of the above activities within 30 days of the start of the inspection.
D.
Description of Operations Shift Staffing at the Time of the Event Control Room shift staffing, at the time of the event, consisted of i three. licensed R0s, one on Unit 2 and two on Unit 1 serving as ' control room operators. In addition, four licensed SR0s were serving as shift supervisor, two unit supervisors and a shift manager.
Additional SR0 licensed operations department personnel were available on shift.
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Abbreviations for the principal operations staff are used for convenience throughout the report.
The following brief explanation of each position is provided: i SS Shift Supervisor - A Senior Reactor Operator (SRO) responsible for both Unit 1 and Unit 2 operations.
US Unit Supervisor - The SR0 on the shift responsible for operation of one unit.
SM Shift Manager - The person responsible for advising the SS/VS on matters pertaining to the engineering aspects of eet" 'ag safe operations of the plant. This person also functions as the STA.
CR0 Control Room Operator - A licensed reactor operator responsible for the operation of an assigned unit.
NE0 Nuclear Equipment Operator - A nonlicensed operations department individual trained in the location, operation, and safety significance of plant equipment in the assigned work area. This person reports to one of the CR0s or supervisors described above.
These and other acronyms and abbreviations used in this report are identified in Appendix 1.
E.
Design Descriptions Design descrii :ons for the major equipment and systems discussed in the report are provided in Appendix 2.
F.
Persons Contacted Those persons contacted by the AIT are identified in Appendix 3.
II.
DESCRIPTION OF EVENT A.
Overview of Event for McGuire Unit 1 1.
Initial Conditions On March 7,1989, McGuire Unit I was operating at 100% rated power.
The unit had been on line since January 1,1989, when the unit had returned to power following the completion of a refueling outage which began on October 12, 1988.
Unit 2 was also operating at or near 100% rated power.
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< i 2.
Event-Description ll On ' March. 7, 1989 at.11:40 p.m. - the Unit 1 B main -steam line radiation monitor,1-EMF-25, alarmed and could not be reset.
Control room operators noted. a' substantial and' continual ' decrease in pressurizer level and.S/G B feedwater ' flow.
The operators immediately began reducing' plant load,-placed the idle Train A, NV (charging /high hesd SI) pump in service (see Appendix 2.a), and reduced letdown flow to 45 gpm suspecting a S/G tube leak.
Pressurizer level recovered momentarily then resumed its decrease.(See Figure I).
The operators manually initiated a reactor trip causing a turbine trip, and aligned NV pumps to their high head safety injection flow path to recover pressurizer. level. The S/G PORVs for A, C and D opened .momentar.ily on high steam generator pressure immediately following the turbine trip (See Appendix 2.e).
S/G B PORV'had been previously isolated for maintenance with its block valve locked closed.
None of the S/G code safety relief valves.
lifted.
The operators manually shut S/G B MSIV and started a - plant cooldown to equalize NC (reactor coolant) and S/G B pressures to reduce-the leak rate. An emergency classification of Station Alert was declared, based upon a reactor coolant leak-estimated to be above 50 gpm, and all a'pplicable offsite notifications were made.
Following the turbine trip, S/Gs A, C and D were used to cool down the primary and secondary, by steaming through the steam dumps to.the condenser.
From licensee data curves the' AIT determined that by 12:25 a.m. on March 8,1989 NC pressure was approximately 1080 psig and S/G B pressure approximately 1050 psig.
NC pressure' was then maintained around 1000 psig until 5:00 a.m. at which time S/G B pressure was approximately 820 psig (See Figure II). Also during this time period S/G 'B' was blown down through the S/G blowdown connection to the condensate polisher system.
AIT calculations indicated about 46,000 gallons of primary coolant passed through the break into the secondary system.. S/G B blowdown was terminated at 5:45 a.m.
and backfill cooling was started at 10:15 a.m. (See Figure III).
The unit entered Mode 4, at 10:22 a.m.
Train B of ND (residual heat removal) was placed in service at 3:20 p.m.
The unit entered Mode 5 at approximately 5:44 p.m.
The Alert emergency classification was terminated at 6:15 p.m. on March 8, 1989.
B.
Detailed Sequence of Events MCGUIRE UNIT 1 - S/G B TUBE FAILURE The following sequence of events is a literal translation of logs and records.
Where conflicts exist the AIT has not attempted to reconcile them in this section of the repor.__ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ . _ -~ m , J ..,.- .... - p = '
1 March 7, 1989 Time (EST H_ou,rj Data Source Item
11:40 p.m.
CR0 Log.
Received 1-EMF-25, B steam . US Log, SM Log line, Trip 2 alarm; Alarm, ? '! would not reset; pressurizer level and feedwater flow to S/G B decreasing; S/G B level remained constant; started decreasing T/G load at ~30 MWe/ min; Entered AP-10.
11:41 p.m.
0AC Log The activity level for i ' 1-EMF-36, Unit Vent Gas monitor, began increasing.
j 11:42 p.m.
0AC Log Reduced letdown to 45 gpm and started pump A NV.
11:45 p.m.
CR0 Log Pressurizer level continuing to decrease; Estimate primary to secondary leakage to be H ! about 150 gpm. Declared a - Station Alert.
11:46 p.m.
0AC Log Manually tripped reactor causing turbine trip'. 11:47 p.m.
0AC Log Opened NI-9 and NI-10; swapped NV pumps suction to the FWST; PORVs for S/Gs A, C, and D opened.
! 11:48 p.m.
0AC Log PORVs for S/Gs A, C, and D , closed.
11:49 p.m.
0AC Log Closed S/G B MSIV and J ' SRO Log started cooldown to 507 degrees; depressurizing to equalize pressure between primary and secondary.
0AC Log PORV for S/G A opened.
) OAC Log The activity level for 1-EMF-36, Unit Vent Gas monitor peaked.
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l Time { (EST
Hours) Data Source Item i (cont'd) l 11:50 p.m.
0AC Log PORV for S/G A closed.
HP Technician Interview Secured all S/G blowdown.
11:58 p.m.
0AC Log Manually blocked SI between 11:59 p.m. and 12:03 a.m.
March 8, 1989 12:05 a.m.
SRO Log NC temperature 507 F and continuing depressurization to equalize S/G B pressure to l primary pressure.
12:10 a.m.
SRO Log S/G B and NC system pressure equalized.
(AIT review indicates that NC and S/G B pressure not yet equalized).
Awaiting info from TSC as to means of cooldown of S/G B l and primary.
Referring to OP-02 procedure for unit shutdown.
12:12 a.m.
0AC Log Closed NI-9 and NI-10.
12:14 a.m.
0AC Log Secured pump A NV.
12:30 a.m.
SM Log On excess letdown due to NV-2 not opening.
I 1:32 a.m.
TSC Log TSC activated.
Unit I status: (update as made to TSC personnel).
- 11:45 Alert declared.
- 100 gpm primary to l secondary leak S/G B, reached 150 gpm.
l l - manually tripped unit.
- conditions stable.
- leak stcpped.
- NV-2 (letdown isolation valve) would not reopen.
- turbine building sump isolated.
- PORV (S/G B) not lifted.
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Time (EST Hours) Data Source Item l (cont'd) 1:40 a.m.
0AC 1-EMF-36, decreased to slightly above background.
1:45 a.m.
SM Log Control Room notified that TSC has assumed control.
2:30 a.m.
RES Log NC system temp: 492 F; press: " 00 psig.
Primary boron st..ple 1306 ppm thought not enough to allow continued cooldown. (OP-02 required 1% shutdown margin for cool down below 200 F; Operations concluded insufficient boron for continued cool down.)
3:00 a.m.
SR0 Log Attempted to re-establish normal letdown and charging but NV-2 would not open.
TSC Log Decision per TSC manager to blow down S/G B.
RES Log Cross tied CSTs due to water inventory problems on Unit 2.
3:05 a.m.
SR0 Log Back to normal charging with FWST suction still open, but NV-2 closed.
3:12 a.m.
0AC Log First blowdown for S/G B started.
The activity level for 1-EMF-36 began increasing.
3:20 a.m.
RES Log Boron sample results 1309 ppm; located procedure step in OP-02 to allow cooldown (to an intermediate temperature).
3:25 a.m.
RES Log Boron sample 1316 ppm; started cooldown (planning to go to 400 F) by steaming S/Gs A, C & __ _ _ - _ - _ _ _ _ _ - _ .
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Time (EST Hours) Data Source Item (cont'd) 3:40 a.m.
RES Log NC system temp: 481 F; press: 1000 psig.
3:45 a.m.
0AC Log First blowdown.or S/G B terminated.
3:50 a.m.
RES Log Boion sample 1371 ppm.
4:00 a.m.
RES Log Cooldown rate reported at 40*C/hr; NC system at 464 F.
4:05 a.m.
SRO Log NV-2 has been opened (normal letdown established).
4: 10 a.m.
0AC Log Second blowdown for S/G B started.
4:30 a.m.
SRO Log Notified by TSC to use blowdown as the cooldown method for ruptured S/G; referring to EP-4.3.
4:45 a.m.
RES Log NC system temp: 440 F; press: 1000 psig; discovered note in OP-02 (shutdown procedure) that allowed reducing primary pressure to 750 psi before reaching 425 F with SS approval.
Curve 1.5 of the curve book did not contain this information.
5:15 a.m.
RES Log NC system temp: 421 F; 800 psig in primary and secondary; pressures equalized.
5:40 a.m.
RES Log Started motor driven auxiliary feed pump and fed S/G B.
5:43 a.m.
0AC Log Second blowdown for S/G B terminated and CA pump
secured.
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i i l Time (EST Hours) Data Source Item (cont'd) 6:00 a.m.
RES Log S/G B isolated; Secured cooldown per TSC.
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' 7:15 a.m.
SE Log S/G tube leak rate at time of reactor trip calculated to be approximately 500 gpm.
7:17 a.m.
TSC Log Indicated higher leakage rate, may be high enough for Site Area Emergency.
7.:40 a.m.
0AC Log The activity level for 1-EMF-36 decreased to about 0.5 decades above background.
7:40 a.m.
RES Log Crisis Management Center (corporate office) activated.
7:45 a.m.
TSC Log Beyond makeup capacity of our pumps is why we were in Site Area Emergency.
8:35 a.m.
AIT Review of S/G B and NC pressure data Graphs equalized.
9:00 a.m.
TSC Log (TSC to CMC) if had known this info (500 gpm) would have been in Site Area Emergency.
10:15 a.m.
SR0 Log Commenced cooldown using backfill method; reference EP-4.2.
10:27 a.m.
R0 Log Enter <:d mode 4.
11:03 a.m.
R0 Log Made up boron necessary to assure 180 ppm above required SDM per EP-4.2.
3:20 p.m.
SRO Log ND train B in service.
3:45 p.m.
TSC Log NC pump B of = - - _ _ _ . _ _.. _ _ _ _. J J.
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I l' I Time ' (EST Hours) Data Source Item (conPd)- 4:20 p.m.
TSC Log Both ND pumps on.
5:44 p m.
RO Log ' Entered mode 5.
6:15 p.m.
SR0 Log Emergency classification terminated.
C.
Radiological Releases 1.
Initial Release The' primary to secondary leak in S/G B resulted in an initial gaseous release (first release) of radioactive materials to the environment (See Figure IV). The released activity was measured by the Unit Vert Gas radiation monitor, 1-EMF-36. This monitor tracked an ircrease in effluent activity beginning March 7, 1989, at 11:40 p.m. and ending March 8,1989, at approximately 1:40 a.m., when ' monitor readings returned to slightly above background levels'of 60-80 cpm.
The quantity of the release was increased because the isolation of S/G B took 3-4 minutes due to opening of the MSIV bypass prior to closing the MSIV.
After the MSIV was closed, the bypass was closed.
The licensee calculated the total gaseous release to be 12.6 curies and the highest hourly dose rate of 0.045 mrem per hour to the whole body.
Also, during this release an additional release of gaseous radioactive material may have occurred due to the lifting of S/Gs A, C and D PORVs. The PORVs lifted twice during the event for a one minute duration each time. The first release included S/G A, C and D PORVs and occurred from 11:47 p.m. to 11:48 p.m.
on March 7, 1989.
The second release from S/G A PORV only occurred from 11:49 p.m. to 11:50 p.m. The licensee calculated the total dose from both PORV releases to be 0.0004 mrem to an adult whole body and 0.014 mrem to a child's thyroid at the site boundary.
These releases were calculated and added with the first release as indicated in Figure IV, 2.
S/G B Blowdown Release The licensee blew down S/G B twice to the BB System in order to cool down and decrease its water inventory (See Appendix 2.c).
These actions resulted in two additional releases of gaseous radioactivity to the environment.
The first blowdown (second <
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! l release See Figure IV) began March 8, 1989, at 3:12 a.m. and readings for the 1-EMF-36 monitor for gaseous effluent activity correspondingly began to increase. This blowdown was secured at 3:45 a.m. and the 1-EMF-36 reading peaked and then began to
, decrease. A second blowdown (third release See Figure IV) was
' initiated at 4:10 a.m. and secured at 5:43 a.m.
j l The 1-EMF-36 monitor also recorded an increase in effluent I l activity during this time period. During the first S/G blowdown (second release), the licensee calculated that a gaseous release of 11.0 curies was released from 3:10 a.m. to 4:10 a.m., and a highest hourly whole body dose rate of 0.042 mrem / hour.
During the second S/G blowdown (third release), the licensee calculated a gaseous release of 14.8 curies and a highest hourly dose rate of 0.040 mrem / hour.
Af ter 6:00 a.m., readings from 1-EMF-36 decreased to approximately 300 cpm and continued a slow decline until reaching a background level of 68 cpm on March 9, 1989 at 8:00 a.m.
The licensee attributed these slightly elevated readings to degassing of the contaminated secondary system through the steam jet air ejectors.
The licensee calculated total gaseous activity released and doses at the site boundary for the time period from the initial tube failure through the two S/G blowdown releases.
From l Marc' /, 1989, at 11:40 p.m. to March 8,1989, at 7:40 a.m., a totai of 43.5 curies was released.
The adult whole body dose and child thyroid dose for this time period were determined to be 0.015 mrem and 0.016 mrem, respectively, at the site boundary.
The continued degassing of the secondary system from March 8, 1989, at 7:40 a.m. to March 9, 1989, at 8.00 a.m., resulted in an additional release of 28.53 curies and a whole body dose of.019 mrem.
The Technical Specification quarterly dose limit from noble gases is 5 mrad gamma and 10 mrad beta and from Iodine 131 and 133, tritium and all radioactive materials in particulate form with half-lines greater than 8 days is 7.5 ] mrem whole body and 15 mrem organ dose.
Additionally the l Technical Specification annual total dose commitment to any
member of the public due to releases is 25 mrem whole body and - 75 mrem thyroid.
The whole body and thyroid doses from this event were a small fraction of the Technical Specification limits.
I A licensee news release on March 8, 1989 at 11:00 a.m. described I the radioactive release as follows: I 11:37 p.m. Steam generator tube leak occurred l l _ _ _ _ - _ _ _ _ - _ -.
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l l 11:41 p.m.
Release of radioactivity began.
A later estimate indicated that total exposure from this time until 8 a.m., March 8 would have been 0.01 mrem at the plant boundary. As of 8 a.m., a field monitoring team reported no radiation levels above normal background at the' plant boundary.
11:45 p.m. Duke Power declared Alert at McGuire Unit 1 11:46 p.m. Operators safely shutdown the unit 11:49 p.m. Release of radioactivity ends The 8 minute time for the release covers the initial release until the time when S/G B was isolated. In fact, some release continued to occur as a result of the event although the amount was of the order of normally occurring releases from the plant.
III. SUBSEQUENT LICENSEE ACTIONS A.
Emergency Response and Reporting The event was reported to state and local officials within the required 15 minutes and updates were given every hour until the Alert was downgraded.
As required a written report of the event was presented -to state and local officials within 8 hours of de-escalating the Alert.
The NkL resident inspectors were notified of the event approximately 25 minutes after the Alert was declared at 11:45 p.m.
and the 10 CFR 50.72 report was made within the 1 hour time requirement.
The NRC Resident Inspector responded to the site at 12:45 a.m.; the Senior Resident arrived on-site at 1:20 a.m. and the Catawba Resident Inspector arrived on-site at 3:00 a.m.
The licensee procedure for Alert requires activation of the TSC and the OSC upon declaration of the Alert.
The licensee requires activation to be completed within 1 hour and 15 minutes. This was not completed until 1:32 a.m. _(1 hour, 47 minutes) although the TSC and OSC were both functioning prior to that time.
The delay was primarily caused by inclement weather.
Some communication weaknesses were observed by the NRC residents between the control room and the TSC. At about 2:30 a.m. operations personnel were ready to steam S/G B to the condenser in accordance with their procedure but without an offsite dose assessment or monitoring.
However, the TSC informed operations to delay the - _ - _ _ _ _ _ _ _ _ _ _ -
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cooldown using this method. Also, approximately. 5:43 a.m. the TSC directed the blowdown of S/G B be secured. The Control Room thought that the TSC said for cooldown to be stopped. This was subsequently resolved.
At approximately 7:15 a.m.
the TSC reviewed the pressurizer level curve from the transient monitor and determined that the leak rate ' prior to reactor trip was 540 gpm. A discussion between the TSC and E0F began as to whether the site should have actually been in a Site Area Emergency.
Further review also indicated the leak, after the cooldown was initiated, to be 400 gpm versus 150 gpm as initially indicated.
Information relayed to the TSC apparently only indicated : the total amount of water being charged to the NC system though the normal charging header, which was 150 gpm. The licensee criteria for an Alert from an NC leak is "NC leak greater than 50 gpm" and for a Site Area Emergency is "NC Leak greater than makeup pump capacity".
In the context of the licensee procedures, makeup pump capacity should include' total capacity of the high head (charging) pumps and intermediate (safety injection) pumps.
The licensee initially thought charging pumps. only were to be considered and they were not keeping up with the leak prior to the trip.
Prior to the event the licensee was in'the process of clarifying this classification criteria. The specific. criteria for a S/G tube leak required the event to be classified as an Alert.
Therefore, classification of this event was correct.
B.
Evaluation of Operator Actions and Procedural Adequacy The control room operators responded to this event by utilizing several procedures.
Through interviews, review of logs and procedures the AIT evaluated operators actions and procedural adequacy. The Procedural Usage Flow Chart in Figure V is provided to assist the reader. With a few exceptions, the operators accurately performed the selected portions of the procedures.
These operator actions and their use of procedures are described in more detail below.
Upon receipt of an alarm on the B steamline radiation monitor, 1-EMF-25, the reactor operator at the controls verified the validity of the alarm before checking other parameters. He then checked the pressurizer level, reactor coolant makeup flow, steam generator levels and main feedwater regulator valve positions. In addition to all these indicating a condition that the shift referred to as the
. . . __ ___ ____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___ __
, . i .. .
" classical S/G tube leak symptoms", the " condenser air ejector exhaust high gas radiation" annunciator alarmed. The unit supervisor concluded that the unit was experiencing a S/G tube leak and directed that AP-10 be implemented. Two of the four symptoms listed in that ' procedure were received: steam line high radiation and air ejector i high gaseous radiation. However, the symptoms identified in AP-10 do l not include increasing S/G 1evel, decreasing feedwater flow ' or l feedwater valve position, although the shift crew. stressed during interviews that these indications were' the deciding parameters. The definitive SGTR symptoms which the operator relied on to determine which AP to use, feedwater flow and steam generator level, are included in step 6 of AP-10, well into the procedural instruction.
Although this event fell within the intended beundaries of the Westinghouse Owners' Group guidelines for procedures, it was handled by independent operator diagnosis and resultant direct usage of a nonemergency operating procedure.
One of the immediate operator actions after identification of the incident and entry into AP-10 was to reduce electrical load by reducing main generator power.
AP-10 does not give direction to accomplish this task.
The operators stated that they knew from training that this action should be performed. They did not use any procedure for this action and, therefore, had to ask the unit supervisor to determine the rate at which he wanted the load reduced.
The needed rate of load reduction was analyzed and determined by the unit supervisor.
This analysis placed additional burden on this individual during response to the event.
The operators performed tha immediate " response-not-obtained" actions of AP-10 as directed by that procedure, then proceeded to the CAUTION under subsequent actions. That caution would have required manual SI if the pressurizer level had dropped to less than five percent and was decreasing. Pressurizer level was not at less than five percent and decreasing, therefore, following AP-10 the reactor was manually tripped (which caused the turbine to trip), INI-9A and 10B (NC cold .l eg injection from NV) were opened, and the NV pump suction was shifted to the FWST in accordance with AP-10, step 2, RNO.
The operators considered initiating SI.
They concluded however, it would not be advantageous if SI were initiated.
Additional CR0 manpower would be required to monitor the successful initiation of SI.
In addition, the operators were uneasy regarding the depend-ability of the RN supply to the unaffected unit due to logic wiring - - .u_______ - - _. _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ . _ -. _ _ ---
_.
. - _ _ _ _ _ _ _ _ O ' . f.-
1' problems experienced in the past. They also considered SI, when not I mandatory, to be an unnecessary challenge to safety related equipment (i.e.,. containment isolation and diesel generator start).
This preference not to manually initiate SI is reflected both in their AP L and.in their training.
l ' In ' the "immediate actions" section of AP-10, " response not obtained" for the step that requires the operator to manual'y initiate SI, ! there is. no guidance to the operator on where to enter the procedure < for SI.
While the operating crew was utilizing AP-10 - to mitigate the , accident, an ' additional SRO who entered the control room was asked by the unit supervisor to perform the immediate actions of AP/1/A/ ' 5500/01, " Reactor Trip".
, Step 3 of AP-10 directed determination of whether S/G blowdown isolation was required based solely on whether 1-EMF-34 (blowdown sample high rad alarm) was lit.
Since.it was not lit the operator did not verify S/G auto isolation nor manually isolate blowdown from any of the generators.
AP-10 step 3 uses 1-EMF-34 as the sole determinant of whether S/G blowdown isolation is required. Then, in step 7b, after identifying the affected generator, the procedure does not isolate blowdown on the affected generator as part of the generator's isolation. This is similar to McGuire's EP-04 where, after identifying the ruptured generator in step 1, the subsequent steps isolate main steam to the ruptured generator but does not isolate blowdown.
This is a significant safety-related deviation from the Westinghouse Owners' i Group guideline E-3, SGTR, which requires, after identifying the ruptured generator, that 4ts blowdown be isolated.
Early in the implementation of AP-10 the shift manager (STA) entered the control room and began monitoring the critical safety functions of SPDS.
This was an appropriate action but not specified by the procedure. Also, although the licensee has indicated that they have a fully operational SPDS, there were two parameters that were inaccurately displayed by SPDS during the event because of faulty computer logic.
NC integrity was being displayed as a " red path" (extreme challenge to this safety function; immediate operator action is required) and, core cooling was being displayed as a " yellow path; indicating that this critical safety function was in an off-normal state and might require operator attention.
The AIT was informed that there were several software problems with the SPDS.
At step 7 of AP-10 the operator was directed to " shut down and cooldown the unit using 0P/1/A/6100/02, Controlling Procedure for Unit Shutdown", in conjunction with the remaining steps of AP-10.
This OP is about 50 pages long, yet no direction is given to the operator in AP-10 regarding which page or section of the 0P to enter. Thus, the operator entered the procedure where he felt it was appropriat. . %.
.. .
) After the unit was off line, AP-10 directed the operator to isolate .t e affected steam. generator.
Ap.1n at step 7b, directs the h operator to "Close (main steam) iv.'ation and ':ypass valves".
By training and convention the operator knew this meant to open the by pass,. close the MSIV, then slowly clo~se the' by pass to prevent a pressure transient.
J Near. the end of AP-10, the operator was directed to " dump steam to l condenser by slowly opening steam isolation bypass valve on ruptured generator".
Due to.the brevity and lack of ' specificity of this instruction the operator opted to reference EP-4.1 where there was more detailed guidance. One of the difficulties of this procedural transition (or parallel usage) is that the two types of documents may not have a consistent set of definitions. For example, AP-10 step 7d refers to "... faulted S/G pressure.." when referring to the generator with the tube leak and at point 7f of the same page refers to the " ruptured" generator as the one with the tube leak. The EPs carefully. use these terms to indicate a generator with a secondary leak as " faulted" whereas " ruptured" is used to refer to a generator with a primary to secondary leak through one or more tubes. Also, the concurrent use of procedures increases the physical and mental burden of the US who performed as the " Procedure Reader."
Step, 7.f.1 of AP-N, listed an alternative to dumping steam from the ruptured generator to the condenser.
That alternative would be blowing down through the BB recycle system.
Due to the operators lack of confidence in the BB recycle system's Hx integrity they chose to dump steam to the condenser.
Step 7.f.1, unlike the step in EP-4.1, makes no reference to performing an offsite dose calculation prior to dumping steam from a ruptured generator to the condenser.
EP-4.1 contains a caution indicating that such a calculation should be done.
The shift supervisor indicated at the time that he did not intend to have the I dose calculation performed prior to steaming because EP-4.1 stated "should" and therefore was not a requirement.
Plant personnel knew what operation they needed to perform and knew which procedures contained the actions or steps.
After some delay, the TSC directed the Control Room not to use EP-4.1 guidance but rather to substitute EP-4.3 guidance.
This latter procedure cools and depressurizes the intact generators by steam dump to the the condenser and the affected generator by draining it usirg blowdown.
Cooldown. per OP-02 was delayed initially since primary boron sample results were not available until 2 hrs and 44 minutes after the trip (2:30 a.m.). The Boron sample concentration was not high enough to .. .. -__-
_ _ _ _ _ _. _____ . . - .. ,
allow cooldown below 200 F so cooldown was not resumed.
Boron concentration was high enough to initiate cooldown to an intermediate temperature but the operators were unaware of this option unti.1 3 hrs - 34 min after the trip.
Cooldown was started 5. minutes after this option was realized.
Early in the event, the operations group complained of slowness in receiving NC boron sample results. The AIT discussed -this problem with the chemistry supervisor who indicated that only one chemistry person was available.on backshift ut the initiation of the event.
Also, the Auxiliary Building elevator was out of service and some minor equipment problems were experienced.
The first sample took over an hour to complete Later in the event, additional chemistry personnel were called in and sampling time was reduced to between 30 and 45 minutes.
After the reactor trip, primary system pressure was maintained above 1000 psig while S/G B pressure decreased to approximately 800 psig.
This continued for 4 3/4 hours. This was because step.2.33 of C,-02 and the cooldown curves require primary system temperature to be below 425 F prior to decreasing pressure below 1000 psig (LOCA FSAR requirement).
The operators did not become aware of a note immediately before step 2.33 allowing pressure to be reduced to 750 psi with shift supervisor approval under extenuating circumstances, i Prior to commencing cooldown using S/G backfill (10:15 a.m.), the SRI asked the reactor engineer if shutdown margin projections had been made due to the impending dilution.
The engineer indicated that operations personnel had indicated they did not need one but he thought it was a good idea. He then provided the information.
The procedure finally selected by the TSC to depressurize the NC Systerr and S/G B was EP-4.2, "SGTR Cooldown Using Backfill". Step 9 of EP-4.2 (checking for void in upper head) contains a sub step (b) that requires the operator to continue monitoring for upper head void while going on to the next step in the procedure.
This does not assure that attention is given to monitoring for voids while going on to another major action (i.e. NC system depressurization).
Based on a review of the sequence of events, operator and plant personnel interviews, and a control room walkthrough with members of the operating crew, the AIT concluded that considering the training and procedure impediments the operating crew performed adequately in mitigating this particular event.
The crew followed steps prescribed in the station procedures, however, the procedures, were found to have significant weaknesses which could result in unnecessary - _ _ _ _ _ _ _ _ _ -. -_
- - _ _ _ _ _ - _ - _ -
, > ~ - .. l
l releases of radioactivity to the environment should future SGTR events occer. The mitigative strategy which McGuire used for coping with this e/ent deviated substantially from the Westinghouse Owners' Group Emergency Response Guidelines.
C.
Use of the Condensate System to Cool down j 1.
Blowdown to Condensate Polisher l Following the reactor / turbine trip, S/G B passed steam to the ' condenser through the steam dumps (See Appendises 2.b and 2.c).
This continued for approximately 4 minutes until S/G B was isolated.
However, when the trip occurred the _ condensate polisher bypass valve (item A in Figure VI) opened due to a high differential. pressure.
This allowed contaminated condensate from the condenser to ' bypass the condensate polishers.
The condensate polisher was used for CF system decontamination.
Condensate continued to bypass the condensate polisher until'the bypass valve was closed approximately 2 hours after the reactor trip. This delay (caused by operator action not by procedures) in closing of the bypass valve increased the amount of conta-mination to the facility and increased the radioactive release.
After the bypass valve was closed, the S/G Blowdown System was placed in service to control level in S/G B and maintain water quality in S/Gs A, C and D.
S/G B was later blown down and CA used to maintain level during cool down.
2.
Crosstie of Unit 1 and Unit 2 CSTs CF was used instead of CA to maintain S/G A, C and D water level. Following the reactor trip, Unit 2 steam was aligned to drive the Unit I turbine driven CF pumps through an auxiliary steam system crosstie and the pumps turbine discharge returned to the U1 UST and CST. The crosstie from Unit 2 steam to Unit I caused Unit 2 UST and CST levels to decrease while Unit 1 CST level increased and eventually overflowed through the CST vent.
This was because condensate from the Unit 2 steam was not pumped back to Unit 2.
The UST supplies NPSH to the CF pumps.
In order to maintain acceptable NPSH for the Unit 2 CF pumps, the Unit 1 CST was cross tied to Unit 2 CST to restore level. This allowed the UST to be refilled and supply adequate NPSH for the Unit 2 CF pumps. However, this crosstie of Unit 1 CST to Unit 2 allowed contaminated water from Unit I to enter and contaminate j the Unit 2 CF system.
{ l 3.
Use during Backfill Cooldown S/G B cooldown using the backfill method was commenced about 10 hours after the reactor trip. This was accomplished by lowering NC system pressure to below S/G B pressure which allowed water in S/G B to flow back into the NC system. As S/G B water level l ---_ __ _ ----____ -- _ - -
_ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ '.. . , f.
- .
j l
decreased, level was maintained by using a CA pump and/or CM booster pump.
The water from S/G B diluted the boron concentration of NC. NC boron concentration was increased to account for this dilution and to maintain adequate shutdown f margin in accordance with EP-4.3.
D.
Radiological Aspects of Event
1.
Release Pathway Summary i Figures VII and VII.a depict 5 pathways that resulted in either l releases.or contamination or both during the event.
Pathways 1 and 2 would each result in monitored discharges to the atmosphere ~ at the point on the TB roof where the atmospheric relief valve tailpipes discharge.
Pathway 3 terminates at five points. One is a monitored gaseous release.
Its discharge point is on the roof of the auxiliary - building.
A second is a contamination pathway, monitored by frisking, and terminating in the auxiliary building at the sample sink.
The remaining three are liquid - pathways; two l terminate after monitoring at high integrity container tanks and the third would only exist if there were a leak in the BB Recycle system heat exchanger.
Thus a leak in this heat exchanger would be an unmonitored release to the lake through the RN system.
Pathway 4 terminates at seven points; five of these are liquid discharge pathways and are monitored by. grab samples from the TBS, one is a monitored gaseous discharge terminating at the vent stack on the auxiliary building roof and the last.has a gaseous discharge point at the top of the condensate storage tank.
Periodic liquid samples of the CST are monitored and would infer any gaseous activity.
The remaining pathway, pathway 5, terminates in a high integrity contained-tank (Unit 2 FDT) but has the potential for contaminating floors, sumps and drain tanks in both Unit I and Unit 2.
Detailed descriptions of the pathways involved in this event can be found below.
2.
Release Pathway Details I Plant HP was notified that mainsteam line monitor 1-EMF-25B had alarmed, could not be reset and that there was an approximate 100 gpm loss of reactor coolant inventory.
The HP supervisor notified HP management of the event in progress.
Twelve HP personnel, managers, supervisors, scientists, and technicians ! -
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i i reported to the site by 1:30 a.m. to staff the TSC and support radiological operations. Assessment.of radiological conditions commenced with the implementation of HP Procedure HP/0/B/1009/18, "HP Response to Indication of a Primary E to Secondary Leak."
HP commenced radiological surveys of the event by taking a gas - grab sample at 12:08 a.m.'un March 8, 1989, in response to vent
. alarm 1-EMF-36-Sampling of the vent gas monitor was continued . at frequent intervals until the unit was placed in Mode 5, cold-shutdown.
The licensee had originally provided the NRC a. plot'of 1-EMF-36 cpm versus event time. This. graph did not correct the _ monitor values ' for varying air flow though the unit stack and also did not explain that plotted cpm numbers were average cpm valQes over a 10 minute period.
Changing air. flow through the stack altered the' activity levels detected by 1-EMF-36 since the amount of dilution air flow changed. Decreased air flow through the' stack would result in higher cpm readings.
Effluents' from the unit. stack were monitored by' 1-EMF-35, -36 and -37 for particulate, gases and iodines, respectively. The reading for 1-EMF-35, was connected to tne unfiltered air exhaust from the Auxiliary Building.
A high alarm on the 1-EMF-35 would auto-matically secure the unfiltered exhaust fans. The unfiltered exhaust was. vented to the unit stack for final release-This . flow contributed approximately 30% to the total air flow from the unit stack. Computer printouts of unit' vent flow during the event showed that stack flow decreased when the unfiltered exhaust fans were isolated.
The curie-values plotted on Figure IV have been calculated using the actual effluent flow at the time.
During the initial phase of the event, water from the Unit 1 TBS was being discharged to WC. Upon receiving a 1-EMF-31 alarm on the TBS in Unit 1, HP directed that the water be diverted to RC.
Hourly grab sampling was commenced at 12:25 a.m. on March 8, 1989 and continued until 7:30 a.m. the same day for the TBS. At that point, sampling frequency was reduced to every four hours and continued until 10:00 a.m.
on March 13, 1989.
Normal 12-hour sampling frequency was reinstated after 10:00 a.m. that day, All effluent water samples from the TBS during the event - ' were withir the release limits of Technical Specification 3.11.1.1 (1 MPC) and the release limits of 10 CFR 20, Appendix B, Table II, Column II concentrations.
At approximately 2:30 a.m., on March 8, 1989, HP was notified of personnel contamination in the CT laboratory.
Two laboratory technicians' clothing became contaminated when a piastic sample tube became detached.
The technicians attributed the event to excessive pressure from the blowdown of the steam generators.
As a result of the spill, both technician's clothing and shoes
were contaminated with levels of 15,000 to 25,000 dpm/100 cm, .. ..- .. ~. '. - . .+
HP surveyed the technicians and found no skin contamination.
Air samples in the area were clean, however, the floor in the
spill area. was contaminated up to 15 mrad /hoijr/100 cm. HP barricaded and posted the area properly and provided the l technicians with paper suits. The technicians received whole l body assay and the results showed no internal contamination. HP noted while surveys were being performed to determine the extent of contamination of the CT laboratory, background radiation - levels-in the general area were increasing. This was attributed to increasing radiation levels on the condensate polishers located adjacent to the CT laboratory, and was the first , indication to HP of the expanded radiological consequences of ! the event.
) Surveys made between 3:00 a.m. and 4:00 a.m. on March 8, 1989, showed increases in radiation levels in the Unit 1 Turbine Building.
HP. posted the condensate polisher room as a high radiation area based on radiation levels on the 1B, IC and ID condensate polishers that ranged from 5 mrem /hr to 375 mrem /hr.
Later readings revealed contact. radiation levels up to 700 mrem /hr. The BB Blowoff Tank on the mezzanine floor had contact readings from 100 to 250 mrem /hr, with general area readings to 120 mrem /hr. This area was also barricaded and posted as a high radiation area.
Extensive areas of the Turbine Building were barricaded during the initial stages of the event until contamination surveys could be taken to better define radiological conditions.
The highest activity noted on surveys for contamination in the
Turbine Building was 6,419 dpm/100 cm. This was due to a leak from valve.SA-49, a Main Steam Isolation Valve to the Auxiliary Feedwater Turbine from S/G B.
During the event, the U1 CST overflowed to the Unit 1 TBS as a result of Unit 2 supplying auxiliary steam to Unit I without returning its condensate.
The containment water was pumped to the Unit 2 Floor Drain Tank, instead of the RC system which i discharges directly to the lake.
This was to allow time to assess an effluent release to the lake.
During the transfer operation, ~a strainer in the floor drain transfer line became clogged and water backed up in the Unit 2 floor drain piping resulting in contamination of the auxiliary building.
It was this. transfer which caused the Unit 1 TBS to overflow and . ' contaminate the Ammertap pit.
Due to the problems with the drains being clogged and the TBS overflowing, HP directed that the water be pumped to the RC system.
Because of these ! problems, approximately 5,780 ft2 of the Auxiliary Building and j approximately 2,000 ft2 of the Turbine Building were conta-
minated.
l During the recovery phase of the event on March 10, at approxi-mately 1:00 a.m., the licensee performed two backwashes of the condensate polishers, discharging resin and water to the BRT.
In preparation for this transfer, HP placed high efficiency _ _ _ _ _ _
_.
_-_ _ - _ - _ _ _ ' . . l .. .-
J particulate filters on both the BRT overflow and vent. lines as a ' precaution to contain any potential airborne radioactivity release. The resin was then.to be transferred to high integrity containers for dewatering and subsequent offsite shipment.
After the second discharge from the condensate polishers to the U BRT, a 2 hour settling period was required to prepare the water for decanting.
During this time, HP observed water coming out of the high efficiency particulate filter attached to the overflow on the BRT.
This overflow was due to incomplete closure of a pneumatic valve,1-CM-486, polishing demineralized 1C backwash drain valve. Surveys were initiated and - the area was barricaded and properly posted.
The floor area was contaminated to levels of 4 mrad /hr.
Radiation levels in the BRT reached 3 rem /hr on contact and 600 mrem /hr at 18 inches.
The floor was subsequently decontaminated.
The Unit 1 Turbine Building radiation areas were properly posted and surveys of the areas were adequate to assess the radiolo-gical conditions.
The Turbine Building radiological conditions were not a hazard to the public.
During the event, and subsequent operations, airborne radioactivity did not exceed the maximum permissible concentration levels as defined.in 10 CFR 20, Appendix B.
However, radiation levels increased significantly in the Unit 1 Turbine Building secondary system components as a result of cleanup of the S/G blowdown.
3.
Sample Collection and Counting Chemistry personnel were responsible for inplant sample collection and preparation, and Health Physics personnel were responsible for operation of the plant's Count Room. The count room sample log showed that 143 samples had been logged for analysis between 12:14 a.m.
and 11:50 p.m.
on March 8, 1989.
The chemistry manager was notified of the event at 12:08 a.m., and he and a chemistry technician reported to the site by 1:00 a.m.
Additional chemistry personnel were called in at 2:30 a.m. to provide support for the chemistry technician and secondary chemistry technician on duty. Some delay was incurred in getting out initial sample results due to an elevator being out of service and the contamination event involving the technicians in the CT laboratory.
The AIT reviewed a series of analysis reports which indicated that most samples were analyzed within 1 to 3 hours after collection.
Sample log-in included completion of a sample record sheet and assignment of a priority rating for immediate or delayed analysis.
High priority sauples were often counted within I hour of collection.
' - - - - _ - _ _ _ _ _ - - _ - _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ - - - - _ _ _ _ _ _ _ _ - _ - _ - _ _ _. _ _ - - _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ -. _ _ _ _ _ _ _ _ _
_ . % - ... .
At the beginning of the tube rupture event, a S/G B liquid sample was collected at 11:50 p.m.
on March 7, 1989 and delivered to the Count Room within 20 minutes.
Initial analysis of the sample showed a detector dead time in excess of 10% which invalidated the count.
HP personnel requested Chemistry to prepare a dilution of the original sample.
The diluted sample was counted at 2:36 a.m. and recounted at 8:07 a.m.
Information was ave.ilable to the Technical Support Center from the 2:36 a.m.
count.
4.
Environmental Sampling A series of environmental samples were collected March 8,1989, within a 3-mile radius of the plant in order to monitor offsite releases. The licensee collected a variety of samples which included vegetation, water, sediment, air, and smears.
The samples were analyzed at the licensee's environmental , laboratory.
All results showed less than detectable or normal background levels of radioactivity.
IV.
EQUIPMENT STATUS, FAILURES / MALFUNCTIONS AND ANOMALIES l A.
Blowdown Recycle System l During May 1988, operations suspected a tube leak in the Blowdown Recycle System Hx (See Appendix 2.b).
The Hx was disassembled and eddy current test,ed in May 1988.
Due to the unusual support foundations of the Hx, a special method tube plugging system was purchased which allowed plugging the tubes. This had to be evaluated due to design approval of this tube plugging method. Also, a hydro system had to be developed which allowed a test of the individual plugs. In January 1989, tube plugging was performed; however, it was decided that a method of stabilizing the severed and near severed tubes was necessary.
The equipment to do this was not available on the market. The Hx's leaking tubes (2) were plugged and a method of stabilizing the tubes was being developed by a tube plug manufacturer.
During the Hx repair, an investigation of the cause of the vibration which damaged the tubes was begun.
It was discovered that clamps which were installed on the shell and associated piping expansion joints by the manufacturer were never removed. These clamps were to l prevent movement of the joints (and subsequent damage) during transportation and installation. They also prevented the shell from expanding with the heated tubes and thus placed the tubes in compression, possibly changing their vibrational frequency or bowing them and possibly caused the vibration damage.
The clamps were l removed.
Unit 2's Hx was inspected and no similar clamps were found.
l l I l
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .. _ _ _ _ _ . _ _ _ _ _ _ _ _ __ _j
.____ . D . ... .
It was also found that the RN flow control valve which supplies the shell side of the Hx had failed open during previous use. This valve failure could have caused the flow to exceed design flow to the shell side of the cooler and could have caused the vibration damage.
This valve was repaired.
Current plans are to request a design study to place flow restrictions on other Hxs to prevent excessive flows if l similar control valves fail open.
On February 22, 1989 the Hx was returned to service with the two leaking tubes plugged, the clamps removed, and the control valve repaired. A work request was written to install stabilizer bars and plug all tubes showing greater than 50% wall damage once stabilizer bar development had been completed by the plug manufacturer.
However, the support staff was not sure of the length of service before a tube leak would occur in the Hx, since no stabilizer bars were yet installed on the leaking or worn tubes. These concerns w'ere passed on to operations with a caution that extended use could result in additional tube leaks.
When it was discovered that a SGTR had occurred, the licensee decided to reopen the Hx and plug all tubes showing severe vibration damage.
This was a precaution in the event the Hx may be needed. This would reduce the risk of another tube leak with the Hx in service.
The AIT determined that RN cooling water to the Hxs does not have a radiation monitor on the return side to the lake.
Therefore, if there were any leaking tubes there would be an unmonitored release path to the environment.
B.
S/G B PORV S/G B PORV was removed from service on January 17, 1989 to allow for valve packing repairs.
At the time of the event, the PORV block valve was locked closed and the PORV actuator was removed.
This prevented S/G B PORV from operating when S/Gs A, C, and D opened on high S/G pressure.
No code safety relief valves lifted.
C.
NV-2, Letdown Line Isolation Valve l This valve closed on low pressurizer level (17%) following the manual reactor trip. Subsequently, when control room operators attempted to return normal letdown to service, this valve would not reopen.
! Control room operators placed excess letdown in service and dispatched a NE0 to enter containment and manually open NV-2.
When , NV-2 was opened, control room operators completed the valve lineup
for normal letdown and secured excess letdown. Maintenance had been performed on this velve on December 9,1988 to tighten valve packing.
<
_ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___ - _ - ___-_ _ _ ___ - p . I g, .,7 , ..
b
l l
The valve was suc:sssfully stroke tested and returned to service. No history 'f past failures to open were identified by the licensee. At the time the AIT left the site the. licensee had not determined the cause of this failure.
D.
NC-243 Pressurizer Vent Valve Leakage ,
! When Unit I was restarted following the refueling outage,- 1-EMF-39 indicated abnormal amounts of radioactive gas in upper containment.
l The licensee entered containment and found boron crystallization on l NV-243. A continuous purge on the pressurizer was initiated through
the pressurizer vapor space sample line to reduce the amount of i radioactive gas in the upper containment. This purge was aligned to , the VCT which is continuously vented to the Waste Gas system. This I continuous purge caused boron to stratify in the pressurizer.
l Technical Specifications limit the boron concentration difference
between the pressurizer and the NC system to 50 ppm. To insure this Technical Specification limit was not exceeded, a group of pressurizer backup heaters was manually energized to increase NC pressure. As NC pressure increased above normal operating pressure, pressurizer spray valves opened to return NC pressure to normal.
This provided a circulation flowpath between the NC system and pressurizer liquid space.
If tube leakage increased, pressurizer level would decrease causing a decrease in NC pressure. Since the NC pressure decrease would be greater than the pressurizer level decrease, the pressurizer backup heater group would cycle to recover NC pressure.
Pressurizer pressure was in fact increasing when the tube failure occurred. The continual operation of the pressurizer backup heater group could have masked indications that tube leakage was increasing shortly before the event.
E.
ND-32, 'A' ND Heat Exchanger to Letdown Heat Exchanger At approximately 3:20 p.m.
on March 8, 1989 as the operators were attempting to place A train of ND in service valve 1-ND-32 would not remain open.
The purpose of this valve is to allow initial pressurization of the ND system, using the Letdown Pressure Controller, to NC system pressure before opening the NC suction valves to the ND system. After the ND system is pressurized and the NC system suctions are opened, this valve is closed. Investigation by IAE (instrument and electrical) technicians found the close contact was sticking shut which caused the valve to close af ter it had stroked full open.
Operations personnel were able to pressurize the ND system using the B train of ND and initiated NC system cooldown. It was necessary to place both trains of ND in service to obtain the desired NC system cooldown rate.
Failure of 1-ND-32 did not affect the ability of A train of ND to remove decay heat.
I _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ - - - _ _ _ _ _. - __-___ _ _ _ _. _ _ - _ _ _ - _ _. _-_ _.
_ _ _ - _ -
-. . _ _ _ _ _ . % - .. .
F.
Radiation Monitor on S/G Blowdowns l The S/G blowdown sample line monitor, 1-EMF-34, which would cause auto isolation of all S/G blowdown on high radiation, failed to alarm. During the event, control room operators isolated blowdown for all four S/Gs by 11:50 p.m.
The regular midnight check of flow through the monitor erroneously indicated flow was available when it had been isolated. When blowdown for S/G B was initiated at 3:12 a.m.,1-EMF-34 did not indicate any increase in radioactivity. As a result of the inoperable monitor, S/G blowdown continued for about 15 minutes after the tube rupture and caused increased contamination of the secondary system.
Following the AIT inspection, the licensee determined that 1-EMF-34 did not see an increase in activity due to an incorrect valve lineup. The licensee stated that prior to the event the 1-EMF-34 was calibrated. After calibration, the technician ! failed to secure a 2.5 gpm flow of demineralized water to th~e ' monitor. The demineralized water was used to assure a background level was seen by the monitor for calibration purposes. This caused the monitor to be inoperable.
G.
S/G B Tube Leak Rate When the tube failed at 11:37 p.m.
on March 7, 1989, pressurizer level decreased rapidly from its normal value of 61%. The initial decrease was linear, corresponding to a primary-to-secondary leak of about 490 gpm.
However, because a centrifugal charging NV pump was operating during this period, the actual leak rate is estimated to be about 600 gpm. The decrease was temporarily slowed after the second NV pump was started.
The flow from the second NV pump included borated water from the FWST which resulted in a decrease in primary temperature and pressure, and hence, resumption of the rapid decrease in pressurizer level. The reactor was manually tripped at 11:46 p.m.
and pressurizer level decreased from 30% to a minimum value of 8%. H.
EMF Monitors The AIT reviewed a calibration log of EMF monitors, concentrating on process and effluent monitors involved in the event. All monitors checked showed current calibration dates. The team also reviewed an out-of-service log for the EMF monitors and noted that one monitor, 2-EMF-31 was inoperative at the time of the event.
2-EMF-31 is the Unit 2 monitor for the TBS discharge which can be aligned to the WC or RC system. This monitor was declared inoperative at 10:25 a.m. on February 27, 1989, due to an inoperable flow indicator. The licensee was collecting samples every four hours to compensate for the out of-service monitor.
This inoperable monitor did not affect monitoring capability during the SGTR.
i m_____ _ _ _ _ _ __ _ _ _ J
. _ _ _ _ _ _ - _ _ _ _ _ ... ,. I % '
.. I - 27-J l I.
S/G'8 Performance History 1.
Maintenance History During the October 1988 refueling outage of Unit 1, maintenance activities were performed on all four S/Gs including tube plugging and inspection.
There ' were no special conditions identified that would suggest S/G B had potential tube integrity problems. There were no additional maintenance activities on Unit 1 S/Gs after restart following the refueling outage.
2.
Minor tube leak in S/G B Shortly after the restart of Unit I following the refueling outage, a small primary to secondary leakage of less than 5 gpd was found in S/G B.
The leak rate increased in a week to approximately 13 gpd.
This identified S/G tube leakage was monitored by the licensee in accordance with the guidelines provided in NRC Generic Letter 88-02. Three different methods were used for estimating the primary to secondary leakage in S/G B.
They were the Xenon method, the I-133 method, and radiation counts from 1-EMF-33. Figure VIII and IX present data from the S/G B leak rate estimates.
The licensee asserts that the data plotted on between February 5 and Februray 18 for Xenon method were unreliable due to a malfunction of the off gas flow measurement device at the discharge of the condenser air ejector.
This flow measurement device was repaired and the correct. data since is indicated in Figure IX.
Except for the above described off normal data, the licensee estimated the leak rates from all three different monitoring methods consistently indicate there was no indication of increasing S/C B tube leakage prior to the March 7, 1989 S/G B tube failure. The AIT could find no evidence or reason to suggest that the failed tube was related in any way to the prior minor tube leak in S/G B.
V.
FINDINGS OF THE AIT A.
Radiological Consequences The SGTR and subsequent increase of radioactivity in related - components did not result in any radiological hazard to the public or any radiological releases to the environment that exceeded regulatory limits.
Radioactive releases and subsequent exposures within the plant - environment did not exceed regulatory limits of 10 CFR 20.
A potential unmonitored release pathway to the environment - existed through the Hx of the S/G blowdown recycle system.
. _ __ _ _ _ _. _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ .___ __ _ _ __ ___ - _ ___ _ _ - _ _ _ _ a
- _ _ _ _ - - _ - _ _ - - - _ _ - _ __ _ _ _ ___ ---, ] . ..
- .,
.
- ' The S/G sample line monitor,1-EMF-34, which would isolate S/G blowdown on a high alarm, was nonfunctional and did not alarm.
. As a result S/G blowdown continued for a short time after the .I tube rupture and contributed to the contamination of - the secondary system.
l The Unit 2 secondary system became contaminated when the Unit 1.
- CST was' cross-connected with the Unit 2 CST.
The condensate polisher bypass valve-remained open for an - extended time and caused additional contamination of the Unit 1 . secondary system.
! - Health Physics and chemistry personnel were knowledgeable of technical aspects of radiological control.
Delays were noted in providing operations with sample analysis.
- B.
Operational and Procedural The operating crew performed adequately in mitigating this - event despite procedural weaknesses which caused the operator to select portions of additional procedures that contained more detailed guidance.
- Operators failed to promptly identify the magnitude of the reactor coolant leak, to cooldown and to equalize pressure.
- Procedures and training discouraged operators from safety injecting.
Although SI was not needed in this event, procedures and training should be reviewed to assure operators will SI when appropriate in the future.
Operators lacked confidence that certain systems would function - following an SI, also considered unnecessary challenge to safety related equipment.
The McGuire stategy for copying with this event deviates from - the WOG guidelines in several significant aspects.
Overall it addresses to an accident which is within the scope of the WOG E0Ps.
Guidelines for emergency operating procedures _ as an abnormal event rather than an emergency.
Some important operator actions required to mitigate the event - are not specified in AP-10. Among these are reduction in load, monitoring of critical safety functions, isolation of the affected generator, depressurization by dumping steam to the condenser and offsite dose calculation prior to dumping steam to the condenser from the affected generator.
1 _ _-_- -- - i
...____ ____._____ ___ _ _ _ . . : - ..
I'
The transitions from AP-10 to other procedures are lacking in - - detail or not identified at all. Among these are: AP-01, "Rx Trip" Procedure - OP-02, " Controlling Procedure for Unit Shutdown" EP-4.1, "SGTR Cooldown Using Steam Dump" EP-4.2, "SGTR Cooldown Using Backfill" EP-4.3, "SGTR Cooldown-Using Blowdown" AP-10 and EP-4.3 contain steps directing the operator to use the - Blowdown Recycle System which. could potentially result in " . establishing an unmonitored release pathway.
AP-10 does not require an assessment of offsite dose prior to - dumping steam from the affected generator to the condenser.
Operations and chemistry failed to effectively communicate the - need for and.results of boron sampling, resulting in a delay in cooldown from 2:30 a.m. to 3:25 a.m.
System crossties caused increased radiological problems.
- Operators were not knowledgeable of two important provisions for - cooling down and depressurizing in unusual situations.
Specifically, these were: (1) boron concentration required for intermediate temperature cooldown and, (2) procedural option to depressurize to 750 psi before cooling down.
- EP-04 does not isolate blowdown on the ruptured generator. This is a significant safety-related deviation.
' - The overall mitigative strategy used to deal with this >500 gpm tube rupture deviates substantially from the WOG Emergency Response Guidelines.
VI.
ROOT CAUSE DETERMINATION The station staff has formulated a group with the specific charter to investigate thoroughly and determine the root cause of the tube rupture incident which is the subject of this AIT.
For this reason and - to expedite this report, this AIT did not analyze root cause.
The NRC will monitor the conclusions of the plant staff in this regard.
VII. CONCLUSIONS - The operating crew performed competently in mitigating this event.
The event did not result in exceeding a Technical Specification - Safety Limit.
e__-______-_____-____--____________--_ _ _ _ _ _ _ _ ._-_ __ ______._ . _ _ - _. _ _ - _ _
_ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _.. _ _ _. _ _ - _ _ . _ _ . _ _ _ _ _ _ _ _ ____ -_ _____ _ _ _ _. _ _ _ _ _ _ _ _ _. __ . % . ., i
30
- Radiological releases were below the limits specified in 10 CFR.
I Part 20.
Use of the BB recycle system as directed by procedure could have - resulted in a direct and unmonitored radiological release to the environment.
' - Under the procedural guidance used, radiological releases, although low, were larger than necessary.
- Failure to use the McGuire Emergency Procedures delayed recovery and , ' extended the duration of the reactor coolant leak.
VIII. PRE-EXIT INTERVIEW The preliminary findings of this special inspection were discussed 'on March 11, 1989, with those persons indicated in Appendix 3.
No dissenting comments were received. The final exit with the licensee is scheduled for April 11, 1989.
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__ -_-_ - .- - _ _ _ _ _ _ _. . _ _ - . . .. < ~, .. I APPENDIX 1 ACRONYMS AND ABBREVIATIONS 'AIT Augmented Inspection Team -- Abnormal Operating Procedure A0P - Abnormal Operating Procedure AP - Auxiliary Sterm AS - BB.
- S/G Blowdown BRT - Backwash Receiver Tank CA - Auxiliary Feedwater CF Feedwater - CFR - Code of Federal Reguitions em - Centimeter CM - Condensate Crisis Management Center CMC - cpm - Count Per Minute CR0 Control Room Operator - CS - Condensate Storage ! Condenser Steam Air Ejector CSAE - CST' -Condensate Storage Tank - CT Conventional Sampling System - dpm Disintegrations Per Minute - EMF - Electrical Monitoring System - Radiation EP - Emergency Operating Procedure FDT - Floor Drain Tank FSAR Final Safety Analysis Report - FWST - Refueling Water Storage Tank gpm Gallons.Per Minute - Health Physics HP - Hx - Heat Exchanger Loss of Coolant Accident LOCA - Maximum Permissible Concentration MPC - mrad /hr - Millirad / hour mrem /hr Millirem / hour - MSIV - Main Steam Isolation Valve MWe/ min Megawatts Electric Per Minute - NC - Reactor Coolant NE0 - Nuclear Equipment Operator , ND - Residual Heat Removal NI - Safety Injection System j NPSH Net Positive Suction Heau
- Chemical and Volume Control NV - OAC.
Operator At the Controls - OP Operating Procedure - OSC Operations Support Center - PGP-Procedures Generation Package - Power Operated Relief Valves PORV - ppm Parts Per Million - i u___________________._.__
_-- _ -- _ _ _ - - _ _ .- ! .
.. Appendix 1
psi - Pounds per Square Inch psid Pounds per Square Inch Differential - psig Pounds Per Square Inch Gage - PWR - Pressurized Water Reactor RC Condenser Circulating Water System - RES Resident Inspector - RN Nuclear Service Water System - ltNO Response Not Obtained - RO Reactor Operator - SA Main Steam to Auxiliary Eauipment - SDM - Shutdown Margin SE Shift Engineer - S/G Steam Generator - SGlR Steam Generator Tube Rupture - SI Safety Injection - SM - Shift Manager SPDS Safety Parameter Display System - SRI - Senior Resident Inspector SR0 - Senior Reactor Operator SS Shift Supervisor - STA - Shift Technical Advisor Secondary Steam Relief System SV - Turbine Building TB - TBS - Turbine Building Sump T/G - Turbine Generator Technical Support Center TSC - US - Unit Supervisor UST - Upper surge tank W Westinghouse - Conventional Waste Water Treatment System WC - Westinghouse Owner's Group WOG - ZJ - Condenser Steam Air Ejector System l , h-
. _ _ _ _ _ _ - . . - ., . APPENDIX 2 - DESIGN DESCRIPTIONS a.
Chemical and Volume Control System (NV) System Function l NV (See Figure X) is responsible for maintaining the proper water iriventory in the Reactor Coolant System-(NC) and maintaining water purity and the proper concentration of neutron absorbing and corrosion inhibiting chemicals in the reactor coolant. The makeup function of the NV is assumed to be required to maintain the plant in a long-term hot shutdown condition.
The centrifugal charging pumps
also operate as part of the ECCS in the event of a LOCA.
' System Definition NV providts a means for injection of chemical poison in the form of boric acid solution, chemical additions for corrosion control, and reactor coolant cleanup and degasification. This system also adds makeup water to NC, recycles water that is letdowa from NC, provides seal water injection to the reactor coolant pump seals, and performs the high pressure emergency core cooling function.
NV consists of several subsystems; the charging, ietdown, and seal water system, the reactor coolant purification and chemistry control system, the reactor makeup control system, and the boron thermal regeneration system.
The functions of NV are performed by the following components - the charging pumps, (two centrifugal, one positive displacement), boric acid transfer pumps, volume control tank, boric acid tanks, and various heat exchangers and demineralizers.
A simplified drawing of NV is shown in the Figure X System Operation During normal plant operation, one centrifugal charging pump is running with its suction aligned to the VCT. The letdown flow from a NC cold leg is cooled in the regenerative Hx then directed to the VCT. The reactor makeup system maintains a desired level in the VCT.
The bulk of the charging flow is pumped back to the NC system through the regenerative Hx via two charging lines.
Some of the charging flow is directed to the reactor coolant pump seals.
The charging system can be aligned as en auxiliary source for pressurizer spray.
The centrifugal charging pumps also provide high-head injection as part of the ECCS. When an SI signal is generated, NV is isolated except for the centrifugal charging pumps and the safety injection flow path. The pumps take suction on the FWST and inject into all four cold legs.
Each NV pump has a design flow rate of 150 gpm at 2235 psig and are rated 100% capacity.
l L % _
R ' ... .. .. ... Appendix 2
b.
Condensate and Feedwater Systems'(CM and CF) System Function . The ' Condensate and Feedwater Systems are designed to return ! condensate from the condenser hotwells through the condensate polishing demineralizers and the regenerative feedwater heating cycle to the S/Gs while maintaining proper water inventories throughout the cycle.
The entire Condensate System is nonsafety-related. The portions of l-the Feedwater System that are required to mitigate the consequences of an accident and allow safe shutdown of the reactor are safety- .related.
System Definition The Condensate System consists of the following: Three 50% capacity hotwell pumps and strainers - Five 25% capacity. condensate polishing demineralizers and - associated regeneration equipment.
Two stages of low pressure feedwater heaters (F and G) - Three 50% capacity condensate booster pumps - Three stages of intermediate pressure feedwater heaters (C, D, - and E) - Piping, valves, and instrumentation.
The Feedwater System consists of: - Two 50% capacity turbine driven S/G feedwater pumps Two stages of high pressure feedwater heaters (A and B) - Piping, valves, and instrumentation.
- System Operation The hotwell pumps take suction from the condenser hotwell.
During normal operation, two hotwell pumps will be operating with the third on standby.
The condensate flows through the condensate polishing demineralizers which purify the water. A demineralized bypass value will automatically bypass the resin beds if a high inlet temperature (>120 F) exists, a high differential pressure (>15 psid) or if satisfactory inlet water conditions are present.
These latter conditions are sensed on the demineralized inlet, and bypass will occur providing that sodium and conductivity are low. Downstream of the condensate polishing demineralizers, the condensate is divided equally between the three air ejector condensers where it is used as coolant. All three air ejectors are normally in service removing noncondensable gases from the condenser. After the air ejectors, the - _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _
_-__ - _ _ _ - _ _ ._.
_ ..m.
.. o... . Appendix'2
. condensate flows in parallel through the gland; steam condenser and the blowdown recovery Hxs.
The condensate then passes.through two stages. of low pressure feedwater heating to the suction of the condensate booster pumps.
During normal operation', two condensate. booster pumps will be in cperation-with the third on standby.
Downstream'of the condensate booster pumps, the concensate passes through intermediate prcssure feedwater heating before combining with the C heater drain pump flow
and discharging to the suction of the feedwater pumps.
Normally, both feedwater pumps will be operating. Downstream of'the feedwater pumps, the feedwater passes through high pressure feedwater heating to. a feedwater header where feedwater temperature is equalized. The feedwater is then admitted to the S/Gs through four J steam generator feedwater lines.
Feedwater flow to the individual steam generators is controlled by a feedwater control system using feedwater flow, steam generator water level, and main steam flow as. control parameters for S/G feedwater control valves.
c.
Steam Generator Blowdown Recycle System (BB) 'ydlem Function The S/G Blowdown System (BB) (see Figure XI) is used in ennjunction with the Condensate System (CM) to maintain proper. secondary side water chemistry. Nonvolatile solids resulting from corrosion, steam generator tube leaks, or condenser tube leaks tend to concentrate in the S/G. The BB System i designed to control the concentration of-these impurities by cont'"uously removing a portion of fluid from the shell side of the S/G.
System Definition
i The BB System consists of the following: l ! a.
.One S/G blowdown blow off tank b.
Two S/G blowdown blow off tank pumps.
c.
One S/G blowdown recovery Hx.
d.
One S/G blowdown tank.
e.
Two S/G blowdown pumps.
f.
One S/G blowdown recycle demi ars 'zer, g.
Piping, valves, and instrumem ati n.
The BB is designed to operate manually and on a continuous basis as required to maintain acceptable 'S/G secondary side water chemistry.
All blowdown lines are auton.atically isolated on a containment isolation signal and auxiliary feedwater automatic start signal.
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, l
_
Appendix 2
.i BB is designed to prevent radioactive discharge to the environment i from the blowdown liquid.
During times of abnormally high primary-to-secondary leakage, blowdown is terminated by radiation monitors.
Normal System Operation Blowdown flow is discharged from all S/Gs to a common pipe line. A continuous sample of the blowdown is taken from the common pipe and transported to the Nuclear Sampling System.
The S/G blowdown tap penetrates the secondary shell of the S/G and runs to the center of the tube bundle. The flowdown line, external to the S/G, exits the containment building.
Containment isolation valves are installed on each side of the building penetration. After exiting the containment building, the blowdown may take one of two paths; a 2-inch line to the blowdown recycle Hx inlet header; or' a 4 inch line to the blowdown blowoff tank located in the Turbine Building (which is the normal path). Throttle valves in the lines between the S/Gs and the blowdown flash tank control flow between
about 5 and 75 gpm per generator. Water from the S/G enters the flash tank and a large portion of this water flashes to steam. This concentrates the blowdown fluid impurities. The steam (25%) from the blowdown flash tank is vented to the shell side of the low pressere heaters.
The flowdown flash tank liquid (approximately.75%) containing concentrated impurities, is pumped by the blowdown pumps to the inlet header of the condensate demineralized where the water is purified.
Detection of high radioactivity in the combined blowdown sample by 1-EMF-34 c.auses the isolation valves to close terminating blowdown.
After this has occurred the operator may determine the origin of the high radiation by monitoring each blowdown sample individually on the nuclear sample panel.
Operation with Steam Generator tube leakage would result in blowdowr, high radiation levels.
! d.
Condenser Steam Air Ejector System (ZJ) System Function ZJ is designed to remove noncondensable gases and air inleakage from the steam space of the main condenser.
System Definition ZJ consists of three CSAE. Each CSAE has two 100% capacity two stage jets.
L.
_ _ _. _ _ _ _. _ _ _ _.. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
- - - _- . - _ _ _ _ _ - _ _ a- ,
'. H ;,, ... Appendix 2
System Operation Normally each CSAE draws the noncondensable gases and water vapor mixture from the main condenser to the first air ejector.
The mixture then flows to the intercondenser where it is cooled to condense the water vapor and motive steam. The second air ejector stage draws the uncondensed portion of the cooled mixture from the intercondenser and compresses it further.. The compressed mixture-then passes through the aftercondenser where it is cooled and more water vapor and motive steam are condensed.
The intercondenser drains back to the main condenser and the aftercondenser drains to the condensate storage tank.
The CSAEs discharge to the unit vent.
Radiation monitors on the CSAE discharge and on the unit vent alert operators to the discharge of radioactivity.
e.
Auxiliary Feedwater System And Secondary Steam Relief System (CA and SV) . System Function CA provides a source of feedwater to the S/G to remove heat from the reactor coolant (NC) when the main feedwater system is not available, and NC pressure is too high to permit heat removal by the residual heat removal (ND) system. SV provides a steam vent path from the S/G to the atmosphere, completing the heat transfer path to an ultimate beat sink when the main steam and power conversion systems are 'not available.
Together, SV constitutes an open-loop fluid system that provides for heat transfer from NC following transients and small-break LOCAs.
System Definition CA consists of two motor-driven pumps and one turbine-driven pump.
Water is supplied from several sources on a priority based on water quality.
These sources include Upper Surge Tanks, Auxiliary feedwater Condensate Storage Tank, Condenser Hot Well, and Nuclear Service Water Systems.
System Operation During normal operation CA is in standby and is automatically actuated on a low-low S/G 1evel, a safety injection signal, a loss of main feedwater, or a loss of offsite and station normal auxiliary power.
The system also can be manually started from the control room.
The turbine-driven CA pump is capable of providing 900 gpm. This pump is capable of supplying its own cooling and lubrication independently of AC power. The two motor-driven CA pumps are capable of providing 450 gpm each.
They require RN for cooling.
v
_ - _ _ _ _ - _ _ ,
- ., . Appendix 2
The preferred suction sources include the auxiliary feedwater l condensate storage tank, upper surge tank, and condenser hotwell.
) Redundant flow paths from these sources meet at a common header which l supplies all three pumps. No single valve can block the flow path.
Motor-driven pump A normally supplies two S/Gs while pump B supplies the other two. Two normally closed valves may be opened manually to allow the motor-driven pumps to feed.any of the S/Gs.
The turbine- - driven pump may supply all of the S/Gs. The turbine ariven pump is supplied.with steam from S/Gs B and C and discharge directly to the atmosphere. No radiation monitoring or auto isolation of these steam supplies is provided.
l l ! i l ! k___________
, L._ . , m - ..
i APPENDIX 3 PERSONS CONTACTED J. Blanton, Associate Scientist M. Bridges, General Chemistry Supervisor W. Brown, Operations Group B. Byrum,-Supervising Scientist, Health Physics M. Cashion, 0perations' Group J. Culp, Operation Coordinator J. Foster, Station Health Physicist M. Funderburk, Chemistry Manager B. Hamilton, Superintendent of Te-Snical Services L. Haynes, Associate Scientist, Health Physics D. Hyde, Integrated Scheduling Group J. Iddings, Operations Group G. Long, Specialist, Health Physics
- T. McConnell, Plant Manager E. McCraw, Project Services Engineer C. Martinec, Scientist, Health Physics R. Pierce, Instrumentation and Electrical Engineer M. Rains, Project Services Engineer J. Reeside, McGuire, Safety Review Group E. Reeside, Operations Group J. Rumfelt, Operations Group M. Sample, Superintendent of Maintenance
- R. Sharp, Compliance Engineer H. Sloane, Scientist, Health Physics R. Smith, Assistant Scientist G. Swindlehurst, Engineering Supervisor B. Travis, Superintendent of Operations
- Attended Pre-Exit Interview l
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