ML20245L585
| ML20245L585 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 03/22/1989 |
| From: | Saporito T AFFILIATION NOT ASSIGNED |
| To: | Stello V NRC OFFICE OF THE EXECUTIVE DIRECTOR FOR OPERATIONS (EDO) |
| Shared Package | |
| ML20245B529 | List: |
| References | |
| 2.206, NUDOCS 8905080080 | |
| Download: ML20245L585 (2) | |
Text
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-g 4-Mr.' Victor Stello. Jr.
March 22. 1989 I
Executive Director for Operations U.S. Nuclear Regulatory Commission FAXED & CERTIFIED Washington. D.C. 20555 (P 982 346 223)
RE: 10 CFR 2.206 TURKEY POINT NUCLEAR STATIONS DPR-31 & DPR-41 Please be advised and officially informed as this letter represents a formal request to your office in regards to your. licensee, (Florida Power Light Company),
(Turkey -Point Nuclear Station), located in Homestead, Florida for actions by your office as specified below and l
pursuant to (10 CFR 2.202).
Specific Request:
1.
Immediately cause enforcement action resulting in the issuance of a Notice of Violation with an Imposed and ESCALATED Civil Penalty.
2.
Immediately cause enforcement action resulting in the immediate suspention of your licensee's operating licenses (DPR-31 & DPR-41).
3.
Take immediate actions for determination of the revokation of your licensee's operating licenses (DPR-31 & DPR-41).
Basis and Justification:
1.
As evidenced by the enclosed Preliminary Notification of Event or Unusual Occurrence (PNO-II-89-05) on 1/7/89, your licensee misinterpreted and failed to follow EMERGENCY PLAN PROCEDURES' requiring the declaration of an alert for abnormal RCS (Reactor Coolant Leakage) greater than (50 Gallons Per Minute). Although your licensee later reported the event, after violating the aforementioned procedure, your licensee continues to depart from plant safety procedures, a
re-occurring violation which has previously been the subject of enforcement action and significant concern by the NRC.
2.
As evidenced by the enclosed (LER) Licensee Event Report (89-01) dated January 10, 1989, your licensee placed the
'B' Emergency Diesel Generator out of service for load operability testing. Additionally, your licensee placed the (3A Intake Cooling Water Pump) out of service by opening it's associated feeder breaker.
These actions by your licensee removed the ability for the Unit 3 Residual Heat Removal (RHR) system to provide cooling for the Unit 3 Reactor's Core in the event that the plant lost offsite power.during the (6) hours that both of the aforementioned' systems were out of service. Additionally, your licensee failed to take appropriate corrective actions as the corrective actions taken as documented by your licensee on the (LER) do not address the EVENT of having the
('B' EDG) and the (3A ICW pump) taken out of service overlapping a common (6) hour interval of time. Furthermore, I l'
believe that ' root cause' evaluation of this event will evidence that a procedure violation occurred.
8905080080 8904i4 PDR ADOCK 05000250 H
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Basis and Justification:
l 3.
As evidenced by the enclosed (LER) Licensed Event Report (89-030) l dated 12/02/88, Instrument Loop Error and Installation Error Caused Accumulator Level Instrumentation Inability to Assure Technical Specification Limits Met. Your licensee states in the (LER) corrective actions statement
- 4 that "In 1986 a
standard engineering design procedure was developed to control the manner in which plant modifications are written and implemented through the use of a Standard Engineering Design Package."
Your licensee concludes this corrective action statement by stating "By standardizing the format, content, review
- process, and approval mechanisms for both plant modifications and calculations, the potential for design changes to have adverse effects has been reduced."
Your licensee should initiate corrective actions to ensure that the potential for design changes to have adverse effects has been eliminated and not merely reduced. Additionally, Quality Control and Quality Assurance personnel had to accept the (PCM) upon installation.
A paper trace could identify a potential ' root cause' of the event.
How many other safety related systems have installation errors lending to possible Tech.
Spec. violations or
)
improper operation of the equipment for it's intended safety function ?
j 4.
As evidenced by the enclosed (LER) Licensed Event Report (89-02) dated 1/16/89, Reactor Cooldown Required by Technical Specifications due to Small Unisolable Leak of Reactor Coolant System at Seal Table, the integrity of the RCS was breached by metal failure. Your licensee documents the cause of the event as chloride contamination, however the source of the chloride contamination was not identified nor was the cause of the weepage from the E-5 conduit fitting specifically identified.
Failure of your licensee to identify and resolve the ' root I
cause' of primary RCS leakage prior to restart of Unit 3 is most unsettling and lends to the continued crisis management practices of your licensee resulting in a
concern for power generation in a non-conservative, unsafe maintenance practice.
5.
As evidenced by the enclosed (LER) Licensed Event Report (89-03) dated 1/24/89, Automatic Isolation of Control Room Ventilation System During Channel Check of Air Intake Radiation Monitor, your licensee's control room sustained air recirculation from 1/24/89 (0025) to 1/26/89 (2115).
Although your licensee took corrective actions addressing this
- event, it should be noted that the overall plant radiation monitoring equipment is quite old and is constantly under repair and because of poor circuit design., the equipment calibrations frequently drift. Your licensee should focus resources into replacing a worn out system.
Summary:
This current documented behaviour and conduct by your licensee is consistant with prior sited violations and therefore, your departments immediate responce to this petition will be greatly appreciated and most assuring.
Thomas J.
Saporito, Jr.
Sincerely, 1202 Sioux Street Jupiter, Florida 33458 v/
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PREL:MINAR( NOTIFICATION OF EVENT OR UNUSUAL OCCURRENCE PNO-II-89-05 This -preliminary notification constitutes EARLY notice of events of POSSIBLE safety or public interest significance. The information is as initially received without verifi-cation or evaluation, and is basically all that is known by the Region II. staff on this date.
FACILITY: Florida Power & Light Company Licensee Emergency Classification:
7 Turkey Point Unit 3 Notification of Unusual Event j
Docket No. 50-250 X Alert l
Homestead, Florida Site Area Emergency l
General Emergency Not Applicable
SUBJECT:
RCS LEAK > 50 GPM FROM RHR SYSTEM DO NOT CIRCULATE On 1/7/89, at '8:10 a.m., while shutdown and in Mode 5 and in the process of removing a clearance order from the 38 residual heat removal (RHR) pump, the Unit 3 reactor operator (RO) noted a decreasing pressurizer level.
The level loss was later calculated to be approximately 50- to 70 GPM. At 8:15 a.m., the Licensee determined that the leak was originating from the non-running 3B RHR pump discharge line drain isolation valve ~
(3-767B).
The valve was immediately closed and the leak secured.
Preliminary investigation by the Licensee determined that the valve was improperly labeled as 3-898N at the remote or reachrod location in the room above the RHR room.
The desired valve to be operated per the clearance order was the 3B RHR suction valve disc equalizing valve (3-898N).
Root cause is under investigation.
The Licensee's emergency plan requires the declaration of an alert for abnormal RCS leakage greater than 50 GPM.
Because of the short duration of the event and after notifying the senior resident inspector (SRI), the Licensee decided against declaring an emergency and unnecessarily activating state and local officials.
Due to a mis, interpretation of Emergency Procedures the Licensee assumed that the event was not reportable.
However, af ter discussions between the plant manager and the site operations staff, it was determined that the event was reportable.
The State of Florida has been notified by the Licensee.
Issued for information only.
Resident inspector staff to follow up on mislabeling of valves.
Unit 3 is currently scheduled for heatup later today, with restart scheduled for 1/12/89.
Unit 4 is currently in a refueling outage.
The NRC received initial notification of this event by telephone f rom the Licensee at
- 1:28 a.m. on 1/8/89.
This information is current as of 1/9/89.
j CONTACT: R. V. Crienjak - 242-5097
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20555 Gentlemen:
Re:
Turkey Point Unit 3 Docket No. 50-250 Reportable Event:
89-01 Date of Event:
January 10, 1989 3A Intake Cooling Water Pump Declared Out of Service While Performina Operability Test of "B" Emercency Diesel Generator The attached Licensee Event Report (LER) is being submitted pursuant to the requirements of 10 CFR 50.73 to provide notification of the subject event.
Very truly yours, NWwr W.
F.
Co 'n'ay Senior Vice President - Nuclear i
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On January 10, 1989, at 0250, with Unit 3 in cold shutdown, the "B" Emergency Diesel Generator (EDG) was undergoing an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> full load operability test, and therefore, was out of service. At that time, the 3A Intake Cooling Water (ICW) pump was stopped due to a high pitched whine and observed shaft wobble. At 0345 the pump motor breaker was l
racked out to allow trouble shooting. With the 3A ICW pump out of service and the "B" EDG out of service, there would be no ICW pump available to support the Unit 3 Residual Heat Removal system in the event of a loss of offsite power. The "B" EDG successf ully completed its operability test, and at 0945 was declared back in service. The 3A ICW pump was checked for motor current, vibration and shaft breakaway torque.
Troubleshooting did not identify any failure of the pump or motor. At 1842 the 3A ICW pump was declared back in service. The 3A ICW pump was monitored for motor current and motor bearing temperature on a regular basis from January 11, 1989 through January 30, '. 9 8 9. In addition, vibration measurements were taken on 11 occasions during the period January 10 through January 23, 1989. This monitoring did not identify any unacceptable pump operation, and it was concluded that the pump was operable and capable of perf orming its saf ety function, except curing the time that its breaker was racked out.
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=ac r mm nn DESCRIPTION OF EVENT On January 10, 1989, at 0250, with Unit 3 in cold shutdown, the "B" Emergency Diesel Generator (EDG) (EIIS:EK, Component:DG) was undergoing an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> full load operability test following preventative maintenance. Because of this test, the "B" EDG was out of service. At that time, the 3A Intake Cooling Water (ICW) pump (EIIS:BI, Component:P) was stopped due to a high pitched whine and observed shaf t wobble. This condition was discovered by a utility non licensed operator. The pump was declared out of service and at 0345 the pump breaker was racked out to allow troubleshooting.
At Turkey Point Unit 3, the ICW system provides cooling for the Component Cooling Water System, which in turn provides cooling for the Residual Heat Removal System. Three ICW pumps are provided. If emergency power is required, the 3A ICW pump is powered by the "A" EDG, while the 3B and 3C ICW pumps are powered by the "B" EDG. Therefore, with the 3A ICW pump out of service and the "B" EDG out of service for testing, there would be no available ICW pump in the event of a loss of offsite power.
The test of the "B" EDG was successfully completed, and at 0945 on January 10, 1989 the "B" EDG was declared back in service. Troubleshooting of the 3A ICW pump did not identify any problems with the pump or motor. Troubleshooting included vibration readings, pump motor current readings and a measurement of shaft breakaway torque. At 1842, on January 10, 1989, the 3A ICW pump was returned to service. On January 11, 1989, the Maintenance Department initiated shiftly monitoring of the 3A ICW pump motor current and motor bearing temperature. Through January 30, 1989, this monitoring did not identify unacceptable pump operation.
In addition, vibration measurements were taken on 11 occasions during the period January 10, 1989 through January 23, 1989, and again on January 27, 1989. These measurements did not indicate unacceptable vibration during this period. Because the pump and motor parameters have not degraded, it was concluded that the pump was operable until the time that it was removed from service to allow troubleshooting.
CAUSE OF THI EVENT The "B" EDG was out of service because of scheduled operability testing required by Technical Specifications. The 3A ICW pump was taken out of service because of a perceived shaft wobble and high pitched noise emanating from the motor lower bearing. However, it was later concluded that there was no shaft wobble (based on the vibration measurements perf ormed), and that the high pitched whine was caused by air flow through the pump motor and housing (based on the acceptable motor bearing temperatures and motor current).
It is therefore concluded that the 3A ICV pump was operable and capable of performing its safety function, except during the time its breaker was racked out.
ANALYSIS Throughout this event, offsite power was available, and cocling was provided f or the Unit 3 core by the Residual Reat Removal (RRE) system.
If offsi:e power
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If this event had occurred, restoration of ICW cooling could have been i
accomplished by tacking in the breaker for the 3A ICW pump motor and starting the pump. Unit 3 had been shutdown for approximately three months prior to this event, therefore the decay heat level was low, and adequate time would have been available to rack in the breaker for the 3A ICW pump motor.
CORRECTIVE ACTIONS 1)
The operability test of the "B" EDG was completed satisf actorily, and the "B" EDG was returned to service at 0945 on January 10, 1989.
2)
The 3A ICW pump was checked for shaft break away torque, motor current and vibration. These checks did not yield unacceptable results, and the pump was returned to service at 1842 on January 10, 1989.
3)
The 3A ICW pump was monitored for motor current and motor bearing temperatures approximately once per shift from January 11, 1989 through January 30, 1989. The data gathered did not identify unacceptable pump operation.
4)
The 3A ICW pump was monitored for vibration on 11 occasians during the period January 10, 1989 through January 23, 1989, and again on January 27, 1989. The data gathered did not identify unacceptable pump vibration.
ADDITIONAL INFORMATION Similar events: LER 250-88-007 describes an event involving similar circumstances, however the cause of the event was dif ferent.
The 3A ICW pump is manuf actured by Johnston Pumps, model no. 33 CMC.
The 3A ICV pump motor is manuf actured by Louis-Allis, model no. 2450 M.
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JANUMY 3 1989 L-88-545 10 CFR 50.73 b
U.
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Nuclear Regulatory Commission Attn:
Document Control Desk Washington, D.
C.
20555 Gentlemen:
l Re:
Turkey Point Units 3 and 4 Docket Nos. 50-250 and 50-251 Reportable Event:
250-88-30 Date of Event:
December 2, 1988 Instrument Loop Error and Installation Error Caused Accumulator Level Instrumentation 1
Inability to Assure Technical Specification Limits Met _
l The attached License Event Report (LER) is being submitted pursuant l
to the requirements of 10 CFR 50.73 to provide notification of the subject event.
Very truly yours, s
~ (A! VIYUi4 '
SeniorVich'A W.
F.
Conv President - Nuclear WFC/RHF/gp Attachment cc:
Malcolm L. Ernst, Acting Regional Administrator, Region II, USNRC Senior Resident Inspector, USNRC, Turkey Point Plant
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On Decembe r 2,1988, it was de te rmined that the Unit 3 Safety Injection Accumulator Level Technical Specification (TS) limits may have been exceeded during operation. TS 3.4.1.3 requires "Each accumulator shall... contain 875 - 891 enM e f s s t of water...." An analysis indicated that the basis used to scale the accumulator level indication transmitters was incorrect. An installation error also contributed to the level transmitter errors.
Based on Unit 3 data, the errors ranged f rom a potential for an error of 0.41 inches (2.5 cubic feet) more than the maximum allowed volume, to an error of 0.30 inches (1.8 cubic f eet) less than the minimum allowed volume. While it cannot be positively determined that the TS limits were exceeded, it was possible to operate outside these limits without alarm or other indication. The root causes of this condition were the two errors in the design which installed the transmitters in 1982, as well as installation errors in that some transmitters were not installed in accordance with the 1982 design package. Unit 4 conditions are believed similar to those found in Unit 3, and are being investigated. The transmitters are being replaced with a narrower span model to improve instrument accuracy.
l Calculations are being performed to verify the loop errors and ability cf the system to assure cocpliance w1:h TS. The installation error is l
beinz corrected through an improved mounting method.
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.an w me % mm nn Event Description On December 2, 1988, the Turkey Point onsite engineering organization determined that the Unit 3 Safety Injection Accumulator Level (EIIS system code BP, component code TK) Technical Specification limits could have been exceeded during operation without alarm or indication.
The Turkey Point Technical Specification 3.4.1.3 requires, "Each accumulator shall be pressurized to at least 600 psig and contain 875 - 891 cubic feet of water with a boron concentration of at least 1950 ppm, and shall be isolated." The 875 - 891 cubic feet of water corresponds to limits of 6544 - 6664 gallons in each accumulator.
An engineering analysis indicated that the basis used to scale the accumulator level indication transmitters was incorrect. The narrow Technical Specification band (120 gallons) exacerbated this, since minor variations could cause a Technical Specification limit to be exceeded.
Based on Unit 3 data, the worst case total error with regard to maximum l
Technical Specification required volume, occurred on transmitter 3-LT-926 where an error of 0.41 inches level could correspond to 18.5 gallons more than the allowable volume of 6664 gallons.
i Similarly, the worst case total error with regard to minimum Technical Specification required volume occurred on transmitters 3-LT-920 and 3-LT-924, where an error of 0.30 inches level could correspond to 13.5 gallons less than the allowable volume of 6544 gallone.
Due to the nature of the errors, it cannot be positively determined that the Technical Specification limits were exceeded. However, it was possible to receive a high or low level alarm that may have corresponded to an actual accumulator level outside the allowable Technical Specification operating band. Therefore, it was possible to operate outside the Technical Specification limits without alarm or other indication. The significance of operating in this condition is discussed in the Analysis of Event section of this LER.
An investigation into the cause for the condition indicated that the transmitters were installed in 1982 as plant modifications to address Regulatory Guide 1.97, and replaced the existing accumulator level transmitters.
The new transmitters g
were specified and installed to address the need for indication of tank discharge,
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through use of a wide range level transmitter. During this modification, the need
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to maintain the water level in the accumulators within the narrow band required by l
the Technical Specifications was identified.
An alternate method of verifying accumulator discharge was devised (i.e. accumulator tank pressure,) and the new transmitter spans were adjusted to monitor the required narrow range.
i The calce:ations perforced in support of the 1982 modification erroneeus;y assumed a loop error fro = the original design.
Also, the span I
calculation for the 1982 modification contained a mathematical error.
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or Tort w aM==== a w -,. ass-w anc w amew nn Recently, the installed configuration was examined, and some transmitters were not installed in accordance with the 1982 design. The transmitter height relative to the tap from the accumuistor varied by as much as an inch from the design.
These three errors, improperly assumed instrument loop error; mathematical error in span calculation; and the improper installation elevation, contributed to the instrument inaccuracies.
The conditions and potential inaccuracies applicable to Unit 4 are under investigation and if not bounded by the conditions discovered in Unit 3, a supplemental LER will be submitted.
l Root Cause The root causes of this condition were the two errors in the design which installed the transmitters in 1982, as well as installation errors in that some transmitters were not installed in accordance with the 1982 design package.
Analysis of Event l
The condition described was analyzed with assistance from Westinghouse, and the analysis demonstrated that the results and conclusions of the LOCA related accident analyses used to license the current operation of Turkey Point Unit 3 would have remained acceptable even with operation outside of the Technical Specification limits on accumulator volume.
The Westinghouse safety evaluation examined the affect of the accumulator water level deviations identified above. The results of the safety evaluation are summarized below:
Large and Small Break LOCA - No adverse ef fects on the FSAR peak cladding temperature calculation, maximum cladding oxidation or maximum hydrogen generation. Compliance with 10 CFR 50.46b (1-3) is maintained.
Hydraulic Forcing Function - No adverse effect on the Vessel and Loop LOCA hydraulic forcing functions.
Post-LOCA Lengterm Core Cooling - The affect on the post-LOCA sump boron concentration is insignificant. Compliance with 10CFR50.46b(5) is maintained.
Hot Leg Switchover to Prevent Potential Boron Precipitation - Post-LOCA hot leg switchover time remains bounding.
Steam Generator Tube Rupture - Compliance with 10 CFR 100.11 offsite radiation dose limits are maintained.
Eased on the above results, this condition had no adverse effect on the health and safety of the public.
The Unit 4 deficiencies are under investigation and if not bounded by the Unit 3 analysis, a supplemental LER will be submitted.
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l Corrective Actions 1)
The conditions which existed in Unit 4 are being investigated to determine the instrument inaccuracies which may have existed, and determine the safety significance of the condition. The results of the investigation will be reported in a supplement to this LER if the results are not bounded by those l
identified in this LER.
2)
The transmitters installed in 1932 are being replaced with units with a narrower span. This will improve the instrument accuracy, and assure l
margin between alarm setpoints and Technical Specification limits. The replacement transmitters are being mounted using an improved method. Calculations in support of the replacement transmitter installation include correction of the mathematical error in the original span calculation. They also contain loop and component specific calculation of the instrument loop inaccuracy. The unit 3 transmitters have been replaced, and the unit 4 transmitters will be replaced prior to restart following the current refueling outage.
3)
Similar process instrument loops which were modified to meet Reg. Guide 1.97 requirements will be reviewed for technical adequacy.
This work is forecast to be completed prior to April 1, 1989. The need for additional corrective actions will be evaluated following completion of these reviews.
4)
In 1986 a standard engineering design procedure was developed to control the manr.er in which plant modifications are written and implemented through the use of a Standard Engineering Design Package.
Procedural guidance provides direction for design considerations including instrumentation and controls requirements (e.g. type of instrument, range of measurement, accuracy, and location of instrument). Engineering procedures require the performance and issuance of calculations in support of design modifications. Where appropriate, ins t rume nt setpoint and loop error calculations are performed to adequately support the modifications.
In addition, a calculation standard format procedure was approved and implemented in 1986.
These procedures provide formalized methods which assure verification, checking, and i
approval of design, including calculations. By standardizing the format,
content, review process, and approval mechanisms for both plant modifications and esiculations, the potential for design changes to have adverse effects has been reduced.
Other Information The accumulators were supplied by Westinghouse as a part of the NSSS, and the instrument level transmitters installed in 1982 were supplied by Rosemount Instrument Corp., Model Number 1153DD4 The replacement transmitters are also supplied by Rosemount, Model Number ll53DD3.
A simi?.ar even was reported in LEF. 251-86-001.
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Nuclear Regulatory Commission Attn:
Document Control Desk Washington, D.
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20555 Gentlemen:
Re:
Turkey Point Unit 3 and 4 Docket Nos. 50-250 and 50-251 Reportable Event:
250-89-02 Date of Event:
January 16, 1989 Reactor Cooldown Required by Technical Specifications due to Small Unisolable Leak of Reactor Coolant System at Seal Table The attached Licensee Event Report (LER) is being submitted pursuant to the requirements of 10 CFR 50.73 to provide notification of the subject event.
Very truly yours,
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Senior Vice' President - Nuclear WFC/RHF/cm Attachment cc:
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On January 16, 1989, at 1915, with Unit 3 in Hot Standby (mode 3, 547F.
2325 psig) and Unit 4 defueled, a normal cooldown of Unit 3 was initiated due to a small pressure boundary leak of the Reactor Coolant System (RCS).
The leak was identified while performing an overpressure leak test of the RCS.
The leak (approximately 12 drops per minute) was emanating from a crack in the flux mapping system thimble guide tube J-12.
In addition, weepage was evident from guide tube J-7 and and from the high pressure seal at E-5. Unit 3 reached cold shutdown at 1050 on January 17, 1989. Liquid penetrant (PT) examination was perf ormed on all of the guide tubes above the seal table for both Unit 3 and 4.
These examinations identified several other indications. All of the guide tubes with unacceptable l
indications have been repaired or replaced. Two guide tube segments that were replaced were sent to an offsite materials laboratory. Based on the evaluations performed, it was concluded that the two cracks in those guide tubes were caused by transgranular stress corrosion cracking. The defects initiated from the outer surface of the tubes. FPL will reinspect the Unit 3 and 4 guide tubes using PT.
This reinspection will be performed for Unit 3 during its next refueling outage and for Unit 4 during its l
next refueling outage.
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.,,-c,-, m..o m DESCRIPTION OF THE EVENT On January 16, 1989, at 1915, with Unit 3 in Hot Standby (mode 3, 547F, 2325 psig), a normal cooldown of Unit 3 was initiated due to a small pressure boundary leak of the Reactor Coolant System (RCS) (EIIS: AB). At 1516 on January 16, 1989, a leak test of the RCS pressure boundry was commenced in accordance with procedure OP 1004.1, " Reactor Coolant System - System Leak Test Following RCS Opening". At approximately 1648 the leak inspection team reported to the control room a leak of approximately 12 drops per minute at incore flux mapping system guide tube J-12.
The leakage was emanating from a crack between the guillotine isolation valve and the Reactor Vessel, and was therefore, unisolable.
In addition, weepage was evident from guide tube J-7 and from the high presbure seal at E-5.
Technical Specification 3.1.3.a states, "If reactor coolant leakage exists through a fault in the system boundary that cannot be isolated (ex.
vessels, piping, valve bodies) the reactor shall be shutdown, and cooldown to cold shutdown shall be initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />." At 1824 the Plant Supervisor -
Nuclear instructed the Reactor Control Operator to prepare for RCS cooldown. At 1915 a normal cooldown of the RCS was initiated in accordance with plant procedures. Unit 3 reached cold shutdown at 1050 on January 17, 1989 without further incident.
Following cooldown, all of the Unit 3 guide tubes above the seal table were inspected using liquid penetrant examination (PT). Indications were present in the following guide tubes:
J-7, J-12, H-4, M-3, N-12.
The weepage from E-5 was originating from a Swagelok fitting located above the guide tube.
Following examination of the Unit 3 guide tubes, the Unit 4 guide tubes were examined by PT.
Guide tube conduit H-1 contained rounded indications similar to some of those in Unit 3.
CAUSE OF THE EVENT Metallurgical examinations were perf ormed on sect.'ons of the J-7 and J-12 guide tubes. Eased on the results of the evaluations perf ormed, it is conclude (. hat the cracks / indications in the guide tubes were caused by transgranular stress corrosion cracking. The def ects initiated f rom the outer (OD) diameter surf ace of the tubes and most likely resulted from chloride contamination. The source of the presumed chloride contamination is not known at this time.
The cause of the weepage from the E-5 conduit fitting was not specifically identified.
ANALYSIS The amount of leakage from the guide tubes was very small and well within the capabilities of the normal makeup system. Unit 3 was cooled down in a normal manner without further incident. Based on this, the health and safety of the pur.ic was not affected.
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1 Following Unit 3 cooldown, the affected sections of the leaking guide tubes J-7 and J-12 were removed and sent to an of f site materials laboratory for l
evaluation. Based on the results of the evaluations it was concluded that indications on the guide tubes were caused by transgranular stress corrosion cracking. The defects initiated from the OD surface of the tube and most likely I
resulted from chloride contamination. Since maintenance activities are l
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perf ormed f requently above the seal table but not below the seal table, it believed that the presurned chloride contamination is limited to above the seal table. The evaluations performed also indicated that detection of the defects can be accomplished using PT examinations.
CORRECTIVE ACTIONS 1)
Unit 3 was cooled down, and all of the guide tubes were examined by PT.
These examinations revealed five guide tubes with unacceptable indications on the tube.
2)
A plant modification was performed to replace the af fected sections of guide tubes J-7 and J-12.
3)
The indications on guide tubes H-4, M-3 and N-12 were removed with a burr or hand file. Following removal of the indications, wall thickness verifications were performed on the tubes. The areas were then examined b)
FI to ensure the indications were completely removed.
4)
The Swagelok fitting at E-5 was disassembled and reworked. The fitting l
exhibited no leakage when returned to service.
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5)
The Unit 3 guide tubes were verified to be leak free at full pressure.
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6)
The guide tubes above the seal table in Unit 4 wetr examined by PT.
indications at locatian H-1 will be removed prior to Unit 4 entering mode 4.
7)
Plant procedures require that the seal table area be visually inspected for leakage following an opening and reclosing of the RCS.
In addition, FPL will reinspect the guide tubes between the seal table and the high pressure fitting for Unit 3 and 4 using FT. This reinspection will be performed for Unit 4 during the next refueling outage for Unit 4, and for Unit 3 during l
the next ref ueling outage f or Unit 3.
I 8)
The guide tubes between the seal table and the high pressure fittings will be cleaned with an appropriate solvent to remove any residual chlorides on the guide tubes. This action will be completed prior to entering mode 4 for Unit 4 and during the next refueling outage for Unit 3.
9)
FPL will attempt to identify the source of the presumed chloride c ntamination. Additional corrective actions to prevent recurrence will be taken, as appropriate, depending on the results obtained.
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ADDITIONAL INFORMATION Although Turkey Point has had RCS leaks in the past, no LER's were identified that describe a similar event.
The guide tube material is ASTM A213, 304 SS, cold drawn and heat treated.
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P x 14000, Juno Beach,FL 33408 04?0 I; A; FEBRUARY 2 2 1989 L-89-61 10 CFR 50.73 U.
S.
Nuclear Regulatory Commission Attn:
Document Control Desk Washington, D.
C.
20555 i
Gentlemen:
Re:
Turkey Point Unit 3 and 4 Docket Nos. 50-250 and 50-251 Reportable Event:
250-89-03 Date of Event:
January 24, 1989 Automatic Isolation of Control Room Ventilation System l
Durino Channel Check of Air Intake Radiation Monitor The attached Licensee Event Report (LER) is being submitted pursuant to the reg'airements of 10 CFR 50.73 to provide notification of the subject event.
Very truly yours, M
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W.
F.
Cpjnway Senior Vice President - Nuclear WFC/ RET /cm l
Attachment cc:
Malcolm L.
Ernst, Acting Regional Administrator, Region II, USNRC Senicr Resident Inspector, USNRC, Turkey Point Plant
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On Jantlary 24, 1989, at 0025, with Unit 3 in cold Shutdown (mode 5) and l'ni t 4 defueled, the Control Room Ventilation System (CRVS) shif ted to the recirculation made during conduct of a c.9nnel check of the channel B Air Intake Radiatfon Monitor, RII 6642. At the time of the event, the redundant channel A (RAI 6643) was out of se rvice, therefore, the CRVS was left in the recirculation mode until 2115 on.Tanuary 26, 1989, when both channels were declared operable. The actuatian occurred when the Reactor Control Operator released the control swit *.h f rom the check source position. The cause of tt? actuation is a flaw in the design of the radiation monitor circuit module which can allow the duration of the residual signal to exceed the trip setpoint longer than the duration of the internal blanking circuit.
In addition, the duration of the residual signal can vary depending on the accuracy of the calibration perf ormed and the length of time the switch is held in the check source position.
l Tne work instruction for calibration of the radiation monitor was revised to ensure that the duration of the residual signal is 6 seconds or less.
In+ w rk instruction will be further revised in order to provide a more a: urate calibration.
In addition the time delay relay between the n.;ule and the a:tuated device was adjusted to 12 seconds.
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~ ucr.manumm DESCRIPTION On January 24, 1989, at 0025, with Unit 3 in Cold Shutdown (mode 5), and Unit 4 defueled, the Control Room Ventilation System (CRVS) (EIIS: IV) shifted to the recirculation mode during conduct of a channel check of the Channel B Air Intake Radiation Monitor, RAI 6642 (EIIS: IL) following installation of a plant modification to the system. At the time of the event, the redundant channel A (RAI 6643) was out of service. Therefore, the CRVS was left in the recirculation mode until 2115, on January 26, 1989, when both channel A and B were declared back in service.
The actuation occurred when the Reactor Control Operator (RCO, licensed utility employee) released the control switch for RAI 6642 from the check source position. In the check source position, the detector is exposed to an internal radiation source and sends a signal to the circuit module. While the switch is in the check source position, the actuating relay internal to the module is maintained energized (untripped) by a 15 Vdc source across the coil. The module contains an internal blanking circuit that inhibits the trip function (when the switch is released from the check source position) for approximately 2 seconds while the residual signal voltage decays. The circuit module has a time constant (RC) of 0.033 minutes for the 1 to 10 mR/hr portion of the circuit. Due to this time constant, it takes approximately 6 seconds for the residual voltage in this portion of the circuit to decay to the alarc trip setpoint of 2 mR/hr.
This amour.t of time can vary from approximately 4 to 10 seconds, depending on the accuracy of the calibration and the length of time the switch is held in the check source position. Troubleshooting efforts determined that the duration of the residual signal was approximately 10 seconds when this event occurred.
This event occurred during post insts11ation testing following a m, edification intended to alleviate this problem. A time delay relay had been installed between the circuit module and the actuated device. However, this relay was set to provide only a 2 second time delay. With the duration of the residual signal greater than approximately 4 seconds, the 2 seconi blanking circuit in conjunction with the 2 second time delay relay will not prevent an actuation. The 2 second time delay relay setting was based on discussions with the vendor.
CAUSE OF THE EVENT l
The cause of the event is a flaw in the design of the circuit module which can allow the residual signal to exceed the trip setpoint longer than the duration of the internal blanking circuit. This information is not apparent in the vendor manual for the radiation monitor and was determined during troubleshooting ef f orts by utility Instrument and Control personnel.
The method of calibration contributed to this event in that the accuracy of the
- alibration can rer 1: in <sriation in the duration of the residual signal.
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ANALYSIS Upon receipt of the spurious signal, the CRVS shifted to the recirculation mode as designed. The redundant channel RAI 6643 was out of service at the time of the event, therefore, the CRVS was left in the recirculation mode. Based on the l
above, the health and safety of the public was not affected.
CORRECTIVE ACTION 1)
Troubleshooting efforts were undertaken to identify the cause of the problem, as discussed above.
2)
The work instruction for calibration of the radiation monitor was revised to ensure that the duration of the residual signal is 6 seconds or less. This change was made by an On-The-Spot-Change to the work instruction. The work instruction will be further revised in order to provide a more accurate calibration. This action will be completed by March 31, 1989.
3)
The external time delay relay was adjusted to 12 seconds. This change was made by a Change Request to the Plant Change / Modification package which installed the relay.
ADDITIONAL INFORMATION i
LER 250-88-028 and LE". 250 88-020 discuss similar events.
The radiation monitor is manufactured by General Atomics, model number RP-1A.
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