ML20137L275
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..c MRG. D From:
William Miller [Fre.Jrichron, NRc' T2.$
To:
ATP1. PEF [
Date:
12/16/96 5:15pm
Subject:
St. Lucie -Forwarded
- Paul, During my assignment at St Lucie this summer, I worked on two issues which were tumed over to John York for additional follow-up. These issues involved the use of a temporary fire pump without an evaluation and the construction of an enclosure for the control rod drive electronic equipment within the cable spreading room without an appropriate evaluation.
The temporary fire pump was 750 gpm and replaced a 2,500 gpm fire pump. No evaluation had been made to determine if this pump met the required fire flow. The control rod drive enclosure had not been properly evaluated resulting in the requirement for the installation of additional seismic restraints.
Today, I learned that both of these items which were initially identified as apparent violations were dropped and classified as not being a violation to the NRC requirements.
I was not consulted on this matter. I agree that these issues may not warrant escalated enforcement but they do appear to be violations of NRC requirements.
Please provide me with guidance as to how I should address this issue.
Thanks for your help.
Bill 97o4070187 970325 PDR FOIA BINDER 96 485 PDR
..o ST. LUCIE SECURITY EVALUA TION A.
Assetement: Overall, site security has been adequate. Licensee management aggressively pursued a tempering event, which occurredin August, to determine the cause. However, prior events leading to this tampering event should have had more indepth review by the kcensee to determine if tempering was the cause.
B.
Basis:
The Econsee failed to report the confirmed tempering event within one hour, which resultedin a violation.
Prior to the tempering event in August, two events in May andJune related to valves, were documented by the Mcensee as tempered or unauthorized work. Licensee management failed to notify security of these events.
The FFD program was transferred to the site. Numerous problems discovered by a QA audit determined the program to be week.
Training and Qualification noted as a strength.
C.
MANS:
INSPECTION REASON One core 81700 One reactive followup on tampering event /FFD implementation
____m
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I SALP INPUT FEEDER FORM i
ISSUE EIAMPLES DATE REFERENCE MRC ASSES $NENT t
CONTACT i
i 1.
SECURITY Document reviews, interviews and 5/10-14/93 93-14: 2.f TILLMAN Security training Training & Qualification observations of security force 6/20-24/94 94-14: 2.f STANSBERRY function was performance of duty indicated training excellent.
was per the Trng. & Qual. Plan. New firing range with aggressive tactical response training aids and a new training l
bldg. at the range were completed.
Trainers were knowledgeable and dedicated, and equipped with an extensive array of training material and epulpment.
l 2.
SECURITY Two Physical Security Plan changes 5/10-14/93 93-14: 2.a TILLMAN Security, Contingency, Security Plans, Procedares submitted and approved without 6/20-24/94 94-14: 2.c STANSBERRY Training and Adherence anti Changes complication.
Qualification Plan, and Implementing Procedures were i'
current and adequate.
3.
SECURITY One violation was due to problem with 5/10-14/93 93-14: 2.c TILLMAN Access controls were Access Controls Corporate HQ's processing access 6/20-24/94 94-14: 2.b STANSBERRY proactive and information; access granted before B/l exceptional.
was completed. Hand geometry access
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control equipment has been installed.
One of the first licensees to install i
this within the US.
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4.
SECURITY NOT INSPECTED'DURING SALP PERIOD Access Authorization and Safeguards Information Controls 4
1 5.
SECURITY (Report pending) 6/26-94-15:
TOBIN f
Fitness For Duty 7/1/94 l
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2 6.
SECURITY No items on the Open items List, downward 6/20-24/94 94-14: 2.b STAN5 BERRY Onsite management's Effectiveness of Management trends in the Security Incident Tracking effectiveness was Controls and Trending Program and low number of good.
Items logged in the Safeguards Nonreportable Incident Log. Testing and maintenance of security equipment support also assisted in low log entries and influencing the downward trending of hardware errors.
7.
SECURITY Licensee has improved assessment 6/20-24/94 94-14: 2.a STANSBERRY Assessment Aids were Assessment Aids capabilities by installing the latest outstanding.
model of Video Capture. This reduces the nuisance and false alarm responses by the security force.
8.
SECURITY OA Audit personnel were appropriatel.
5/10-14/93-93-14: 2.a TILLMAN Spirit and innovative Audits & Corrective Action trained and motivated. Annual QA Audit perspective of the war thorough, producing one Finding; audit team was appropriate corrective action was taken comiendable.
to resolve the Finding.
9.
SECURITY NRC Headquarters evaluation re;ulted in 6/20-24/94 94-14: 2.b STAN5 BERRY Licensee's response to Other-Operational four concerns, no regulatory violations.
OSRE report was Safeguards Response Concerns involved responsiveness and responsive and Evaluation (OSRE) equipment allocation.
adequate.
Licenseeh'acility:
Notification:
Florida Power & Light Co.
MR Number:
2-96-XXXX Saint Lucie 1 Date:
01/25/96 Fort Pierce. Florida SRI Dockets: 50-335
'PWR/CE Sub.iect:
EXCESSIVE BORON DILUTION Discussion:
At approximately 0220 on January 22, 1996. the Unit 1 control board Reactor Controls Operator (RC0) observed that T had decreased from 549 F (normal 100%
power value) to 548.7 F.
At 0225. he began a manual dilution to the RCS by aligning the Primary Makeup Water (PMW) system directly to the suction of the IB Charging Pump (approximately 44 gpm capacity). He intended to dilute by adding i
between 25 and 40 gallons of PMW.
Moments after beginning the dilution. the board RCO saw the desk RCO return from the kitchen. He requested tnat the desk i
l RCO relieve him so that he could prepare his lunch. During the relief, there was I
no discussion of the dilution in progress. The Nuclear Plant Supervisor (NPS).
who was at the desk RC0 station, was not aware that a dilution was in progress.
The Board RC0 returned between 5-10 minutes later and immediately recognized his error. He was securing the dilution when the control room annunciator M-16 "RCP CONT BLDOFF PRESS HIGH" alarmed due to a higher than normal VCT pressure caused by hign VCT level (a result of the charging pump taking suction from PMW instead of the VCT). The NPS directed the ANPS take charge and begin a manual boration.
Unit 1 briefly entered TS LCO Action Statement 3.2.5 for T greater than 549 F.
c The maximum T obtained was 549.9 F at 100.2% reactor power.
c The licensee has the root cause under investigation.
l Reaional Action:
l A three member inspection team consisting of two resident and one region-based l
inspector is onsite investigating this event and evaluating the licensee's I
corrective actions.
Contact:
K. Landis (404)331-5509 M. Miller (407)464-7822 R Schin (404)331-5588
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- y FLORIDA POWER & LIGHT COMPANY T"i t
ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-1200051 REVISION 17 1.0 TiTW:
NUCLEAR AND DELTA T POWER CAllBRATION 2.0 REVIEW AND APPROVAL:
Reviewed by Plant Nuclear Safety Committee 5/11975 Approved by K. N. Harris Plant General Manager 5/19 1975 Revision 17 Reviewed by Facility Review Group 8/29 1995
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Approved by J. Scarola Plant General Manager 8/29 19 95
3.0 PURPOSE
To provide detailed instructions for the adjustment of Nuclear and Delta T Power to agree with the thermal energy balance calculation.
I 4.0 PRECAUTIONS AND LIMITS:
4.1 Perform calibration on only one channel at a time.
l 4.2 If a pre-trip alarm is received on a powe'r range safety channel being adjusted, i
stop adjustment. Verify proper test switch lineup and if test line up is correct, request I & C recheck channel pre-trip and trip setpoints.
i 4.3 If steady state equilibrium power level conditions change from time of l
completing a plant calorimetric and completion of this procedure, a new calorimetric must be performed prior to performing channel adjustment, unless a monitor of reactor power deemed acceptable by the ANPS/NPS is available, in no case is a change in reactor power of 22% acceptable.
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4.4 Notify Reactor Engineering of a deviation in excess of 5% between Calorimetric and NI indicated power prior to performing channel calibration.
j 4.5 T should be constant and consistent with the T, e
present during the calorimetric calculation.
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4.6 Power level should remain constant during calibration.
DATE DOCT PROCEDURE DOCN 1 1200051 j
SYS ops EOP. IN!E,# fdi.,F. ~)N Cr(. 'f COMP COMPLETED I7 This oocumerit c ot c,nte yg.4, M... ;,-
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8 ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-1200051, REVISION 17 i
NUCLEAR AND DELTA T POWER CAllBRATION 5.0 RELATED SYSTEM STATUS:
5.1 Power level is being maintained constant through the completion of this l
procedure.
l
6.0 REFERENCES
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6.1 Guideline NT-PY-4, Appendix H, Nuclear and Delta T Calibration t
6.2 Technical Manual 8770-7120, Reactor Protective System, Volume I i
l 6.3 St. Lucie Unit 1 Technical Specifications, Table 4.3.1 i
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7.0 RECORDS REQUIRED:
7,1 A signed and dated copy of this procedure shall be maintained in the plant l
files in accordance with Ol 17-PR/PSL-1, " Quality Assurance Records."
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ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-1200051, REVISION 17 NUCLEAR AND DELTA T POWER CALIBRATION
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8.0 INSTRUCTIONS
NOTE At times during core cycle a known hot leg swirl effect may be encountered indicating that flow stratification is occurring. This effect may cause a slight rise or fall in one or both hot leg indicated temperatures. When this occurs a similar change in Delta T power may be seen in any of the four RPS channels. When this phenomenon is recognized as occurring, Appendix A should be performed.
NOTE Perform calibration on only one channel at a time.
8.1 Calculation of Calorimetric Power 1.
Demand a DDPS calorimetric and record the value of reactor power.
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2.
Request T cold from ERDADS Cold Leg Temperature display (screen number CLT) and record T cold.
5% A 'F 3.
Calculate primary system power in accordance with OP 1-3200020 and record the value of reactor power.
CY\\. u-NOTE For this procedure, use DDPS power as the reference power unless there is a i
2% deviation between the DDPS and manual calorimetric values, in which case use the higher value as reference power.
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4.
If the power values recorded in Step 8.T 1 and 8.1.3 differ by more than 2%, notify I & C as soon as possible.
8.2 Proceed with the following instructions for Channel A of the Reactor Protection System.
8.3 If adjusting Delta T Power calibration and/or Nuclear Pwr Calibrate potentiometer, Then use keys 81,87,88 and 90 from the ANPS key locker to bypass the Hi Power, TM/Lo Press, Loss Load and Loc Pwr Den Trips (Bypass Switch 1,7,8 and 10, located on the Trip inhibit Switch Panel) and verify that the respective indicator lights illuminate.
/R17
Pags 4 of 10 ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-1200051, REVISION 17 NUCLEAR AND DELTA T POWER CALIBRATION
8.0 INSTRUCTIONS
(continued) 8.4 Record the Delta T Pwr Calibration potentiometer dial setting.
POT SETTING A
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8.5 Position the meter input switch to the Delta T PWR position and record the DVM reading.
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\\O0 8.6 While monitoring the DVM indication, disengage the locking device on the Delta T Power Calibration potentiometer and slowly begin adjusting for a DVM indication equal to that of the plant calorimetric. Engage the locking device on the Delta T Power Calibration potentiometer and verify the DVM indication equals the plant calorimetric value.
8.7 Record the new Delta T Power Calibration potentiometer setting.
POT SETTING A
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~ 7-4 ST. LUCIE UNIT 1
.C OPERATING PROCEDURE NO. 1-1200051, REVISION 17 NUCLEAR AND DELTA T POWER CAllBRATION
8.0 INSTRUCTIONS
(continued) 8.8 Record the DVM Delta T Power value.
A
\\CC B
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C
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\\C C 8.9 Record the Nuclear Pwr Calibrate potentiometer dial satting.
POT SETTING A
958 B
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8.10 Position meter input switch to Nuclear Pwr position and record the DVM i
i reading.
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\\CC 8.11 Whiie monitoring the RPSCIP Nuclear Pwr - Delta T Pwr deviation meter, disengage the locking device on the Nuclear Pwr Calibrate potentiometer and slowly begin adjusting for a meter indication equal to zero. Engage the locking device on the Nuclear Power Calibrate potentiometer and ecerify the Nuclear Pwr - Delta T Pwr meter indicates zero.
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t ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-1200051, REVISION 17 NUCLEAR AND DELTA T POWER CAllBRATION 4
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8.0 INSTRUCTIONS
(continued) 8.12 Record the new Nuclear Pwr Calibrate potentiometer setting.
1 POT SETTING i
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l 8.13 Record the RPSCIP Nuclear Pwr - Delh T Pwr deviation meter reading.
f DEVIATION (%)
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8.14 Record the O-Power meter reading located on RTGB-104.
O-POWER (%)
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\\CC 8.15 Clear all trips and alarms, if used, remove trip bypass keys 81, 87, 88 and 90 and verify that the respective indicator lights extinguish.
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ST. LUCIE UNIT 1
. si OPERATI'NG PROCEDURE NO. 1-1200051, REVISION 17
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NUCLEAR AND DELTA T POWER CAllBRATION
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8.0 INSTRUCTIONS
(continued)
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8.16 Complete steps 8.3 through 8.15 for Channel B, C and D of the Reactor Protection System.
8.17 Retum keys 81,87,88 and 90 to ANPS key locker.
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- Satisfactory performance of all the above asterisked steps assures conformance with applicable Technical Specifications.
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TASULAR TRENS REPORT TREMS N 1
PAGE 25 BATE
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TIME 0A0033-1 000035-1 22 JAM SS 2:23:30 545.59 548.55 22 JAM 95 2:24:30 545.68 545.51 22 JAM 95 2:25:39 549.50 548.50 22 JAM SS 2:25:30 545.53 548.46 22 JAM 95 2:27:30 548.59 545.37 22 JAM SS 2:28:30 545.55 548.50 22 JAM 95 2:29:30 549.50 548.51 22 JAM 95 2:38:30 549.50 148.51 22 JAM SS 2:31:39 548.59 545.45 22 JAM 95 2:32:39 548.83 545.55 22 JAM SS 2:33:36 549.88 548.84 22 JAM 94 2:34:30 548.88 545.79 l
22 JAM 95 2:35:39 549.97 548.93 22 JAM 95 2:34:30 549 11 549.02-22 JAM SS 2:37:39 549.97 549.07 22 JAM 95 2:38:30 549.25 549.25 I
22 JAM 95 R:39:30 549.35 549.40 22 JAM 95 2:40:30 549.49 549.35 I
22 JAM SS 2:41:30 549.58 549.44 22 JAM 95 2:42:30 549.55 549.44 22 JAM SS 2:43:30 549.44 549.35 22 JAM 95 2:44:30 549.44 549.25 22 JAM 95 2:45:30 549.44 549.25 22 JAM 95 2:45:30 549.21 549.12 22 JAM 9S 2:47:30 549 30 549.15 22 JAM 95 2:45:30 549.25 549.15 i
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PAGE 25 DA7E
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TIME GROO23-1 OROO35-1 22 JAM 96 2:27:40 548.45 547.47 22 JAN SE 2:28:40 543.37 547.38 22 JAN 95 2:29:40 548.41 547.47 22 JAN 96 2:30:40 543.41 547.47 22 JAM 95 2:31:40 548.37 547.47 22 JAN 96 2:32:40 543.65 547.55 22 JAN 95 2:33:40 548.59 547.71 22 JAN 95 2:34:40 548.74 547.75 22 JAM 96 2:35:40 548.84 548.04 22 JAM 95 2:3E:40 548.98 547.99 22 JAN SG 2:27:45 549.02 548.15 22 JAN 95 2:38:40 549.15 548.13 22 JAN 95 2:39:40 549.30 548.35 22 JAN 95 2*40:40 549.35 548.41-22 JAN SS 2:41:40 549.35 548.46 22 JAN 95 2:42:40 549.35 543.50 22 JAN SE 2:43:40 549.44 543.35 22 JAN SS 2:44:40 549.39 548.27 22 JAN 96 2:45:40 549.12 549.22 22 JAN 95 2:46:40 549.21 548.27 22 JAN 95 2:47:40 549.12 548.27 22 JAN 95 2:49:40 549.15 543.22 22 JAN 95 2:49:40 549.07 548.27 22 JAN 95 2:50:40 549.16 548.13 22 JAN,95 2:51:40 545.93 545.13 22 JAN 95 2:52:40 549.07 548.22 22 JAN SS 2:53:40 543'.98 543.13 22 JAM 95 2:54:40 548'.95 548.03 22 JAN SS 2:55:40 549.02 545.04 22 JAN 95 2:55:40 549'.84 548.04:
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j Page 7 of 10 ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-3200020, REVISION 23 PRIMARY SYSTEM MANUAL CALORIMETRIC DATA SHEET 1 (Page 1 of 3) JAN 2 2 35 LW Date: / / Time: t^C :O ( PM 1. ENTER MAIN STEAM PRESSURE ENTER FEEDWATER FLOW I PI 8013A ESO ' /R23 FR-9011 < bl X 10' lb/hr /R23 j PI-8023A 910 /R23 /R23 l Pl-8013B SLC PI-80238 %C FR-9021 . % X 10' lb/hr /R23 /R23 PI-8013C '4.3C /R23 PI-8023C MC O My= M9 X 10' lb/hr ~ PI-8013D '5(oC i PI-8023D' 4C 1 Average Steam Pressure = LA We divided by 8 = 'a,> T-TOTAL AVERAGE ENTER FEEDWATER TEMPERATURE Speedomax Pt.1 41% 'F Pt.2 H T H 'F ~ l Average Feedwater Temperature WS divided by 2 = 4h l TOTAL AVERAGE i I l From a set of steam tables, enter the enthalpy of the steam pressure: h, = \\FI <5A BTU /lbm S10PS DATE9 6 012 2V Calculate the heat output due to steam flow (O. ): i DOCT PD&DUPf DOC W a mo si ss.\\ n 'N E6 ot#. E6 tutni. m E6 BTU /hr g g h, x [M M,3] O=am = m COMP \\c k ITM 24
I PGge 8 of 10 y ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-3200020, REVISION 23 PRIMARY SYSTEM MANUAL CALORIMETRIC DATA SHEET 1 (Page 2 of 3) From the steam tables, enter the enthalpy of the feedwater at the average feedwater temperature: i m g BW hm, /bm Calculate the feedwater heat input (Om): ~ ( a w x ios) x (m K ). 4m.a) x 10e BTU M h Qm hr m m Circle the total blowdown flow from the S/Gs and the corresponding heat output: (Interpolation is not required, circle the ciosest blowdown flow below) Total blowdown flow Mass flow Heat output from (both steam generators) of blowdown M,o blowdown Oy 40 GPM .019799 E6 lbm/hr 9.660 E6 BTU /hr7 80 GPM .039599 t:5 lbm/hr 19.320 E6 BTU /h ' 20 G'PM .059398 E6 lbm/hr 25.981 E6Mr 160 GPM .079198 E6 lbm/hr 38.641 E6 BTU /hr 200 GPM .098997 E6 lbm/hr 48.301 E6 BTU /hr 240 GPM .118797 E6 lbm/hr 57.961 E6 BTU /hr i Calculate the heat output from the core: [ men u _ w,ict.,sne _ 47.23 ] X 105 BTU, ce s atX 105 BTU O O Go C hr O ons hr srew m e oraen c Calculate percent core power: Manual 5 5 Core Power ='m e,0X 10 divided by (92.143 X 10 ) = CA Vi % Calorimetric O one Power c 4 9 e
V Pega 9 of 10 ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-3200020, REVISION 23 PRIMARY SYSTEM MANUAL CALORIMETRIC DATA SHEET 1 (Page 3 of 3) i ( Record DDPS Calorimetric Power (Point 32), (Point ID 31 should be used below if the { reactor has not been in a stable power configuration for at least 10 minutes): l DDPS Calorimetric Power = \\CC C NOTE Calculated power in percent must be within 2% of DDPS calorimetric power. If not, noti 9 the ANPS/NPS. U 2. Every Monday complete Data Sheet 2. Initial Dvt 7 AN#S/NPS ~- RCO t i 9 o
Page 10 of 10 9 ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-3200020, REVISION 23 PRIMARY SYSTEM MANUAL CALORIMETRIC DATA SHEET 2 (Page 1 of 1) NOTE This data sheet will compare feedwater temperature inputs into DDPS calorimetric with feedwater temperature indications used in manual calorimetric. 1. Record feedwater temperature inputs from DDPS. PT 30f 4% 5' l PT 302 Hu 1 PT 303 'nh e Compare pts 301 through 303 to be within 2*F, if greater than 2 F notify I&C. PT 304 _HWN PT 305 'GLI PT 306 4% A Compare pts 304 through 306 to be within 2*F, if greater than 2 F notify I&C. 2. Record feedwater temperatures from DDPS and from Speedomax. DDPS PT 389 9% 0 'Speedomax PT 1 41% Ensure feedwater temperatures to be within 5*F or notify I&C'and ANPS. DDPS PT 390 %^ Speedomax PT 2 'M Ensure feedwater temperatures to be within 5'F or notify I and ANPS. RCO EN ANPS, l l
l( Resprnse to NRC Questien Regsrding 50.59 Screening cf TC 1-96-017 to OP l-0250020, j Boron Concentration Control-Normal Gperation - l l The question reised is witli respect to the makeup water flow path. The " normal" method of 3 adjusting boron concentration involves directing the makeup water to the VCT. The subject 3 procedure permits directing flow to the charging pump suction header, downstream of the VCT. Thus, the question is raised if this procedure constitutes a change to the facility or procedures as described in the UFSAR. (Note: The TC involfed did not establish the option of directing flow i directly to the charging pump suction header, this option existed in the previous revision of the procedure.) j 'Ihe flow path in question is via existing system piping and valves. The sole purpose oflines 3-CH-640 and 4-CH-639 is to provide for direct introduction ofmakeup wcter and/or boric acid solution { to the common charging pump suction header. Thus, no change to the facility as described in the UFSAR has been introduced by this procedure. i As described in the UFSAR, there are several different modes ofoperation for controlling RCS boron concentration, including the manual mode. When operating in the manual mode the makeup flow can l either be directed to the RCS via the VCT or it can be supplied directly to the charging pump suction j j header. Both of these flow paths are shown on UFSAR figure,9.3-5. By bypassing the VCT and j feeding directly to the charging pump suction header, the effects of the addition on RCS boron concentration occur more rapidly. I i The boron dilution events of UFSAR section 15.2.4 were reviewed. As discussed in section i 15.2.4.2.1, each of the six different events analyzed assumed that boron dilution resulted from the direct injection of unborated demineralized water into the RCS at the maximum rate possible (132 4 gpm = 3 d.i ing pumps). As such, the UFSAR analysis does not assume that makeup flow is being directed through the VCT, since any flow via the VCT would result in a mixing of the makeup flow with the borated contents of the tank. The only means of direct injection of unborated makeup would - be through the subject lineup. j i The UFSAR chapter 15 analysis notes "Because of the procedures, involved and the numerous alarms and indications available to the operator, the probability of a sustained or erroneous dilution is very j low." This statement is valid for all modes of operation of the makeup system. The subject plant procedure provides sufficient controls to ensure proper operation and control of boron concentration. In addition, there are numerous alarms and indications available to operators for any mode of j operation. i In conclusion, the subject procedure is consistent with system design and operation as provided in 1 the UFSAR. i i 3
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o ST. LUCIE PLANT NP-700 PROBLEM REPORT 96-008 I. EVENT TITLE High Reactor Coolant Temperature and Power Due To Excess Dilution IL INITI AL PLANT CONDITIONS Unit I was at 100% power, steady state operations. III. EVENT SEOUENCE At approximately 0220 on January 22,1996 reactor fuel bumout resulted in an indicated reactor coolant cold leg temperature of 548.7F by the digital meter on Reactor Turbine Generator Board (RTGB)-104. The board Reactor Control Operator (RCO) decided to dilute the Reactor Coolant System (RCS) in order to restore cold leg temperature to programmed level of 549.0F. He commenced manual dilution in accordance with OP 1-0250020 " Boron Concentration Control - Normal Operation" Section 8.5, with Primary Makeup Water (PMW) directed to the suction of the IB charging pump at approximately 0225. Shortly after, the board RCO left the RTGB area and went to the kitchen located adjacent to the control room to retrieve his meal. A few minutes later, the board RCO returned to the RTGB area, set his meal on the desk and heard the PMW integrator " clicking". He realized that he was still diluting the RCS and immediately secured the evolution. The RCO commenced borating in accordance with OP l-0250020 to the suction of the charging pump for a total initial addition of approximately 26 gallons. He simultaneously informed the desk RCO and the Assistant Nuclear Plant Supervisor (ANPS) of his actions. At approximately 0235 annunciator M-16 "RCP CONT BLDOFF PRESS HIGH" alarmed, due to a higher than normal VCT pressure caused by letdown flow aligned to the VCT with charging pump suction aligned to PMW. Indicated RCS cold leg temperature was approximately 549.6F. The ANPS entered a two hour Action Statement to restore RCS cold leg temperature to less than or equal to 549F in accordance with Technical Specification Limiting Condition of Operation (LCO) 3.2.5. At approximately 0242 RTGB-104 indicated RCS cold leg temperature reached its highest value of 549.9F. Indicated plant Megawatt (MW) reached 885, approximately 4 MW higher than before the dilution, and indicated average reactor power was approximately 100.2% These levels were sustained for less than four minutes and then reduced as boration affected reactivity. 'At 0314 indicated cold leg temperature was 549F, and the LCO Action Statement was exited. All other parameters of reactor power and MW reached normal levels concurrently.
i \\ l IV. CAUSE OF TIIE EVENT The cause of this event was cognitive personnel error due to lack of attention to detail by the board RCO performing the dilution. He left the RTGB area with a reactivity { evolution in progress. f Additional Ddficiencies Noted:
- 1) The RCO performing the dilution left the RTGB area and did not inform the desk RCO or the ANPS that he was diluting the RCS. The "Short Term Turnover" process was less than adequate.
- 2) Expectations for reactivity control for dilution evolutions were not adhered to by the RCO.
- 3) The expectation for natification of Operations Management and Plant Management was not adhered to.
V. CORRECTIVE ACTIONS
- 1. A self critique was conducted by the control room crew immediately following the
- vent,
- 2. An independent investigation team led by the Assistant Operations Supervisor gathered all facts associated with the event.
- 3. The RCO responsible for initiating the dilution was removed from licensed duties based on the results from the fact finding team.
- 4. The Site Vice President, Plant General Manager and Operations Manager conducted crew meetings with each of the operating crews to ensure all crews are aware of the Unit I dilution event. Additionally, excerpts from Zack Pate's "The Control Room" and site management's expectations with respect to conservative operation were discussed. These briefs were completed Friday morning, January 26, 1996.
- 5. An industry survey was conducted at 9 other nuclear facilities to determine the controls in place for reactivity additions to the reactor coolant system.
- 6. The " Conduct of Operations" procedure was revised to require direct supervision of reactivity changes by a Senior Reactor Operator which involve dilution to the reactor coolant system and the operation of Chemical Volume and Control System ion exchangers. Also required is a control board walkdown as part of the "Short Term Turnover" process.
's -
- 7. The Condition Report from the 1993 Turkey Point Plant dilution event was reviewed for lessons learned.
- 8. Operations Management will personally re-enforce the expectation of communicating required plant events as required by the " Conduct of Operations" procedure. J. West - STAR 960146A - Due 1/30/96
- 9. The implications of this event will be reviewed by a team for applicability to other operation's activities both inside and outside the control room. J. West - STAR 960146B - Due 2/15/96
- 10. Plant Management will review its expectations for command and control using information obtained from other sites including Turkey Point. J. West - STAR 960146C - Due 2/15/96
- 11. St. Lucie's training program will be reviewed for adequacy in the area of reactivity management. W. Bladow - STAR 960146D - Due 1/29/96
- 12. An HPES evaluation of this event was conducted. A. Locke - STAR 960146E Complete
- 13. Quality Assurance will conduct an assessment of reactivity management at the St.
Lucie Plant. W. Bladow - Complete
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1;'g i St. Lucia Unit 1 Documsnt No. RPS-1 4 REACTOR PROTECTION SYSTEM Revision O 10 Design Basis Document Page 29 j This AOO is comprised of the four possible events which can affect a single l steam generator: I Loss of load to one steam generator i Excess load to one steam generator
- Loss of feedwater to one steam generator j
Excess feedwater to one steam generator Each of these events has the potential for creating temperature differences j between the four cold legs. This inlet temperature asymmetry would cause radial peaking and corresponding reductions in DNB and centerline to melt j (CTM) margins. Of the four possible events the loss of load to one steam j generator is the limiting asymmetric event. The loss of load would be caused j by closure of a single MSIV. Pressure and temperature in the isolated steam generator rapidly increase to the opening pressure of the steam line safety valves. The turbine control system reacts to maintain speed by drawing more j steam from the intact steam generator which leads to decreasing temperature and pressure. The asymmetric steam generator protective trip (ASGPT) is the primary means of mitigating this transient. The low steam generator level trip l serves as a backup to ASGPT for this AOO. l The ASGPT function was added as part of the 2700 mW. stretch power j license amendment. A separate bistable trip unit (BTU) is not provided for this i function. The ASGPT is processed.via the TM/LP BTU. Whenever the pressure i difference between the two steam generators exceeds 135 psi, the variable i low pressure trip setpoint input signal to the TM/LP BTU is automatically j increased to 2500 psia. This will result in an immediate trip since pressurizer pressure will be less than the trip setpoint. a i
Reference:
St. Lucie Unit 1 UFSAR, Section 15.2.2 2 5.1.3 Boron Dilution N oro dilution events are postulated to occur during all six operational modes. From modes 3-6 the time to achieve criticality due to boron dilution is dependent on the initial and critical' boron concentrations, the boron reactivity worth and the dilution rate. From modes 1 and 2 the reactivity insertion rate due to boron dilution is dependent on the boron worth and rate of dilution. The dilution rate is a function of both the boron concentration and the rate at which domineralized water is being injected. The analysis assumes the maximum possible charging rate of 132 gpm with a corresponding letdown flow. For dilution events postulated to occur from subcritical initial conditions all CEAs are conservatively assumed to be withdrawn thus resulting in minimum shutdown margins and time to criticality. One other key assumption is that the boron concentration remains uniform throughout the RCS, and in particular through the core. This assumption is based on the solubility of boric acid, and
4 St. cie Unit 1 Document No. RPS-1
- 3 REACTOR PROTECTION SYSTEM Revision O
{ l Design Basis Docurnent Page 30 l the mixing provided by either the shutdown cooling flow or the reactor coolant pumps. I i For the suberitical boron dilution events the analysis demonstrates that there is sufficient time to criticality for the operator to recognize and take action to 1 terminate the event. The Standard Review Plan identifies the minimum l acceptable time to criticality for refueling events as 30 minutes and 15 minutes for dilution events occurring during all other modes. For the at power boron dilution events the maximum reactivity insertion rate is small relative to the CEA withdrawal event. The VHPT provides adequate 2 protection for the SAFDLs. Due to the slow rate of power increase the TM/LP i trip may occur before the VHPT setpoint is reached. The low steam generator level and LPD trips rovide backup protection. I i
Reference:
St. Lucie Unit 1 UFSAR Section 15.2.4 i 5.1.4 Loss of Coolant Flow Two reactor coolant pumps (RCPs), one per steam generator, are powered from each of the two 6.9 kV buses. In the event of a turbine generator trip, each 6.9 kV bua fast transfers to the corresponding startup transformer. Loss of more than two RCPs is unlikely. None the less a simultaneous loss of all. four RCPs is postulated as the limiting case loss of coolant flow accident. The seized RCP shaft case is analyzed as a separate event and is discussed under the postulated accidents section. A reactor trip on loss of coolant flow is initiated by the steam generator differential pressure transmitters. The rate at which core coolant flow decreases is a critical factor in maintaining an j acceptable DNBR margin. A gradual flow coastdown is supported by the high rotational inertia of the RCPs. A time delay of approximately two seconds occurs between loss of RCP power and when the low flow trip setpoint is reached. Protection against exceeding the DNBR limit for this event is provided by the initial steady state thermal margin maintained by compliance with the DNBR related technical specification LCOs, and the low flow reactor trip.
Reference:
St. Lucie Unit 1 UFSAR, Section 15.2.5 5.1.5 Loss of Load During a lo'ss of load event the rapid reduction in the rate of heat rermval from the steam generator initially causes a rapid increase in secondary side temperature and pressure. Primary to secondary heat transfer decreases as the temperature differential decreases. Within the first second of the event the RCS cold leg temperature begins to increase with corresponding sharp increases in pressurizer level and pressure. A reactor trip on high pressurizer pressure is generated within the first three seconds, and the safety valve -}}