IR 05000412/1987047
| ML20236L630 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 07/30/1987 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236L602 | List: |
| References | |
| 50-412-87-47, NUDOCS 8708100312 | |
| Download: ML20236L630 (13) | |
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j U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-412/87-47 Docket No.
50-412 License No.
NPF-64 Licensee:
Duquesne Light Company Nuclear Group
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P. O. Box 4 Shippingport, PA 15077 Facility Name: Beaver Valley Power Station,-Unit 2 Dates:
May 28 - July 10, 1987 Inspectors:
J. E. Beall, Senior Resident Inspector L. J. Prividy, Resident Inspector S. M. Pindale, Resident Inspector, Unit 1 D. F. Limroth, Project Engineer A. A. Asars, Resident Inspector, Haddam Neck Approved by:
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f 7 50/87
.. E. ~ Trfpp, Chief, Reactor Projects Section 3A Date
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Inspection Summary: Inspection No. 50-412/87-47 on May 28 - J0ly 10,1987 Areas Inspected: Routine inspections by the resident inspectors (497 hours0.00575 days <br />0.138 hours <br />8.217593e-4 weeks <br />1.891085e-4 months <br />) of licensee actions on previous findings, site activities, preoperational and startup test program implementation, initial fuel loading, cable storage, and recirculation spray system and diesel ' generator lube oil repairs and retesting.
Results: During the inspection period, the licensee received a low power license, conducted initial fuel loading, and remained in cold shutdown (mode 5).
Repairs and retesting were completed for the Recirculation Spray System heat exchangers (detail 7), prior concerns pertinent to the storage of Category I cable were ad-dressed and resolved (detail 8), and modifications were made to both diesel gene-rators to add another lube oil strainer (detail 6).
Two unresolved items were identified concerning the potential modification of a safety injection transfer circuit (detail 5.2) and the use of carbon steel instead of stainless steel for valve CHS-FCV-160 (detail 10).
There were no violations.
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DETAILS
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1.
Persons Contacted During the report period, interviews and discussions were conducted with mem-bers of the licensee's management and staff as necessary to support inspection activities.
2.
Project Status Summary During the inspection period, the licensee received a low power license (May 28, 1987), completed initial core load (June 1, 1987), and entered Mode 5'
(June 6, 1987).
The licensee was preparing to heatup above 200 F thus enter-ing Mode 4 at the close of the inspection period.
Additional information is provided in detail 5.
Approximate dates for power ascension testing, as last announced by the lic-ensee are listed below.
It should be noted that as of the end of the inspec-tion period, that the licensee was between 1 and 2 weeks behind the published schedule.
Enter Mode 4 July 6, 1987
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Enter Mode 3 July 8, 1987
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Initial criticality (Mode 2)
July 20, 1987
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Full Power License (>5%)
July 23, 1987
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100% Power August 27, 1987
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l Plant Trip from 100% Power September 4, 1987
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Achieve Commercial Operation September 9, 1987
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3.
Inspection Program Status Summary The preoperational test program inspection is essentially complete with only the review of the results of certain tests and retests remaining.
Inspection of the licensee's startup and power ascension program began with procedure development and preparations to load fuel (Inspection Reports 50-412/87-27,
-31, -37, -40, and -43).
The current inspection status is consistent with the applicant's startup pro-gram progress.
At the end of this inspection period, there were approximately 25 open NRC inspection items as listed below:
NO. OF OPEN INSPECTION ITEMS TYPE OF ITEM END OF THIS PERIOD END OF LAST PERIOD Bulletins
1 Violations
4 Deviations
0 Construction Deficiency Reports
10 Unresolved
26 TOTAL
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4.
Licensee Actions on Previous Inspection Findings (Closed) Violation (86-29-01): Inspection Report 50-412/86-29 forwarded a Notice of Violation citing the licensee's failure to adequately describe cor-rective actions taken and to provide sufficient information to permit analysis and evaluation of corrective actions or to notify the NRC in accordance with 10 CFR 50.55(e) in conjunction with Temperature Channel Test (NIC) and Loop Power Supply (NLP) circuit cards installed in Beaver Valley, Unit 2.
The inspector reviewed reports of corrective action with respect to the material deficiencies and the licensee's response of permanent corrective actions.
No discrepancies were noted. This item is closed.
(Closed) Construction Deficiency Report (87-00-07): On March 23, 1987, in compliance with 10 CFR 50.55(e), the licensee reported that high head safety injection pump (charging pump 2CHS*P21C) was operating below the minimum de-fined operating curve.
The pump rotating assembly was replaced with the spare rotating assembly and was satisfactorily tested.
Manufacturer's re-test of
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the original assembly indicated that the decrease in output could be attri-buted to excessive wear ring clearance and difference in measurement instru-mentation and location.
The inspector reviewed the retest results and has no further questions.
This item is closed.
(Closed) Construction Deficiency Report (87-00-13): On April 15, 1987, in compliance with 10 CFR 50.55(e), the licensee reported that ten gate valves, normally shut but required to open under accident conditions, could experience differential pressure locking and/or liquid entrapment which could prevent their opening.
The condition was corrected by modifying the upstream disk to provide a pressure relief path.
The inspector reviewed the documentation associated with this modification and no deficiencies were noted.
This item is closed.
(Closed) Construction Deficiency Report (87-00-14): On October 20, 1986, as updated on May 28, 1987, reported an unjustified assumption in the design basis of the outside containment flooding analysis.
The licensee's subsequent revised analysis identified that the resulting flood height in the Service Building may affect floor mounted vital switchgear that is necessary for safe shutdown of the plant.
The licensee initially proposed modifications (flood barriers) to the Service Building upper level (elevation 780') vent floor duct penetrations and 480 Volt vital switchgear cabinets on elevation 730'.
How-ever, further evaluations demonstrated that, provided operator action is taken within 10 minutes following the assumed feedwater system pipe break, the flood barriers would not be required.
The proposed operator action was to terminate all main feedwater flow upstream of the feedwater isolation valves by tripping the main feed pumps if a steam /feedwater flow mismatch is the cause of the reactor trip.
The inspector verified that the associated station Emergency Operating Procedures have been modified to reflect the above requirements.
Additionally, FSAR Section 3.6, Internal Flooding, has been updated to provide the basis for Service Building maximum calculated flood heights, including the 10-minute operator response time to trip the main feedwater pumps to ter-minate the event.
Other planned corrective actions included the installation
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of gaskets on four Service Building doors and flush mounting of the blowout
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panel on elevation 780' of the Service Building (previously required for en-
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vironmental considerations following a main steam line rupture).
The inspec-tor verified the installation of the above.
This item is closed.
i (Closed) Construction Deficiency Report (87-00-15): Failure of main steam
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valve area supply fans.
This item concerned the main steam valve area fans which would not start automatically on a diesel sequence loading signal be-cause their associated dampers, which must be open before the fans will start, would not open automatically if the fans had been running and a loss of power occurred.
The inspector verified that the necessary engineering instructions to revise the control circuitry for the fans concerning proper automatic starting have been implemented.
Also, the inspector verified that these fans performed satisfactorily during the loss of offsite power test that was con-ducted on May 16 and 17, 1987.
This item is closed.
(Closed) Unresolved Item (87-18-01): Containment sump screen corrosion.
This item concerned the 1/4-inch diameter threaded studs which secure the screen assemblies in the Recirculation Spray System (RSS) sump.
These studs were made from A36 carbon steel material and found to be rusting by the inspector.
The licensee replaced the studs with those of 304 stainless steel material.
The inspector witnessed the stud replacement.
While making this followup inspection the inspector noted to the licensee that the RSS sump screens should be final cleaned since construction debris had become lodged at various portions of the screen mesh.
Construction performed a final cleaning of the screens.
This item is closed.
(Closed) Construction Deficiency Report (87-00-16): Improper installation of BISCO LOCA-seals in conduits.
On May 18, 1987, the licensee reported that BISCO LOCA-seals had been improperly applied in 19 resistance temperature detector (RTD) and 27 Target Rock solenoid operated valve (S0V) installations.
Further investigation by the licensee indicated that the RTD installations were satisfactorily applied.
The inspector reviewed the reports of the SOV rework, and observed selected field installations.
No deficiencies were noted.
This item is closed.
(Closed) Construction Deficiency Report (87-00-17): Improperly sealed conduit connections on reed switches.
On May 18, 1987, the licensee notified the NRC that four conduit connectors on reed position switches on two power operated relief valves were not considered qualified due to lack of QC verification during installation.
Repairs were made to qualify the connectors until not later than the first refueling outage.
This item is being tracked by the licensee as a maintenance item to be accomplished during the first refueling outage.
The inspector had no further questions.
This item is closed.
(0 pen) Unresolved Item (86-13-03): Ultrasonic examination report form did not specify the acceptability of the inspected weld.
This item was previously discussed in NRC Inspection Reports 50-412/86-13 and 87-29.
The licensee has
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revised the ultrasonic examination report form to require the examiner to document weld acceptability by determining if any indications require further evaluation, checking a yes/no box, and identifying the questionable indicatio _ _ _ _ _
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The inspector reviewed this new form, however, the licensee has not yet re-vised General Procedure 101, Requirements for Data Recording, Revision 2 to implement the change.
This procedure is planned to include the usage of this yes/no box.
This item will remain open pending revision of this procedure.
(Closed) Violation (87-18-03): Cable tray hold down clamps.
This item con-cerned the incorrect installation of cable tray hold-down clamps at curved sections of cable tray.
Specifically, several clamps had been installed such that the clamp orientation with respect to the cable tray side rail was not parallel.
Applicable construction drawings and SQC inspection plans were revised to clarify the requirement for the installation of the hold-down clamps to be parallel to the cable tray side rail for all cable tray configu-rations.
The inspector verified these procedure changes and also verified that the specific deficiencies identified by the inspector had been corrected.
This item is closed.
(0 pen) Unresolved Item (87-03-03): Differences between Station Administrative Procedure (SAP) 10, Onsite Safety Committee (OSC), and the proposed Technical Specifications (TS) in the area of OSC review of procedure changes.
This item was previously discussed in NRC Inspection Report 50-412/87-03.
Currently, the OSC reviews all changes to procedures in accordance with the guidance specified in TS 6.5, 6.8, SAP 10 and SAP 11, Procedure Changes.
The licensee is undergoing changes to the procedure change program as a result of Amendment 110 (dated June 23, 1987) to the Unit 1 TS.
This amendment included a caveat inserted into TS 6.8.2 which permits non-intent procedure changes to be re-viewed by a qualified independent reviewer and a supervisor instead of the OSC (see NRC Inspection Report 50-334/87-11).
With this amendment implemen,
tation there will be SAP changes which are expected to clarify any misrepre-sentations of the TS requirements for procedure review by the OSC.
The in-spector noted that the licensee is expecting to receive in the Unit 2 full
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power TS a caveat similar to that of Unit 1 TS 6.8.2.
This item will remain I
open pending issuance of the Unit 2 full power TS and the necessary changes to the SAPS to verify that they correctly represent the TS requirements.
(Closed) Violation (87-18-02): Inadequate design control measures caused the Containment Isolation Phase B (CIB) timers to be powered by an interruptible power source.
This issue was originally identified by Significant Deficiency Report 87-08, CIB-Initiated Timers for Control Room Emergency Pressurization Fans.
The licensee's June 8, 1987 response stated that an error was made in interpretation of the system operational requirements which caused the incor-rect power source to be assigned.
The licensee has reviewed the engineering procedures and the activities associated with this design modification and determined that this is an inadvertent human error and not a procedural de-ficiency.
To correct this error, the licensee issued Engineering Design and Coordination Report D-5169-506.
The inspector verified that the modification was made and ratested; this item is closed.
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5.
Site Activities Throughout the inspection period, the inspectors toured the licensee facili-i ties.
General work activities were observed including construction, surveil-lance, testing and maintenance.
The inspectors also monitored the licensee's housekeeping, security and preliminary radiation control activities.
In par-ticular, the inspectors monitored the licensee's progress towards meeting the prerequisites to ascend in operating modes.
5.1 The licensee was issued a low power license on May 28, 1987, and began to load the first fuel assembly at approximately 5:00 a.m. on Friday, May 29, 1987.
The fuel load activities proceeded relatively smoothly through the weekend and the last fuel assembly was loaded at 3:30 a.m.
on Monday, June 1, 1987.
Inspection coverage for the fuel load activi-ties was provided on an almost continuous basis over the weekend includ-ing the back shifts.
No deficiencies were identified.
Additional in-spection details are provided in Inspection Report 50-412/87-43.
Fol-lowing the completion of the fuel loading activities, the upper internals, reactor vessel closure head and the remaining head area items were in-stalled.
The closure head was bolted into place on June 6, 1987, when the plant was placed into Mode 5.
5.2 On June 29, during the performance of preoperational test P0-2.21A.03, Main Steam Isolation and Bypass Isolation Valve Operability Test, a low pressurizer pressure safety injection actuation signal was generated.
As a result of the actuation, the No. 2 emergency diesel generator auto-matically started and containment isolation phase A valves cycled to their appropriate ESF positions.
No water was injected into the reactor coolant system because the SI pumps were in pull-to-lock; the normal configuration for mode 5.
Additionally, the reactor trip breakers were open with all control rods fully inserted.
The safety injection signal was subsequently reset and blocked, and plant systems were returned to normal alignments.
The-inspector observed portions of the event response and attended the licensee event critique.
The licensee made the required notifications on June 29.
Train B of the solid state protection system (SSPS) was placed in the
" inhibit" mode for conduct of the test.
Plant testing personnel trans-ferred the steam line safety injection block / reset control to the emer-gency shutdown panel (ESP) for logic and continuity testing per PO-2.21A.03.
Transfer of this signal also transfers the low pressurizer pressure safety injection block / reset control.
Subsequent to the com-pletion of the test, the reactor operator was instructed by operations personnel to return the SSPS to normal.
The operator was informed that the necessary channels were blocked so that Train B of SSPS could be reinstated.
However, when SSPS, Train B was returned to normal, a low pressurizer pressure safety injection actuation occurred, i
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During followup activities, the licensee determined that the associated transfer contact was a break-before-make type contact.
This type of contact automatically resets the block / reset signal when transferred.
The licensee subsequently determined that the circuitry should be modi-fled such that a block signal would remain blocked upon the-transfer.
The licensee verified that the current system configuration is per design requirements.
Additional reviews are planned by the licensee to inves-tigate similar circuits, and modify them as necessary.
Pending licensee completion of these reviews and the modification for the safety injection transfer circuit, this is Unresolved Item (87-47-01).
5.3 On July 1,1987, while in Mode 5 (Cold Shutdown), there was an inadvert-ent automatic start of the No. 1 emergency diesel generator (EDG) due to an accidental bump of a relay which tripped the feeder breakers to the 4 kV "AE" emergency bus.
At the time, the No. 1 EDG was the non-priority train and was in the process of being tagged out to support maintenance.
The No. 1 EDG output breaker did not close since it had been racked out.
Approximately 15 minutes later, the No. 1 EDG was secured and normal power was restored to the "AE" emergency bus.
The No. 2 EDG and its associated 4 kV "DF" emergency bus was the priority train at this time and was not affected.
The licensee determined that the cause of this event was personnel error.
The plant response was as designed.
The licensee plans to caution sta-tion personnel concerning work and/or movement near relay panels and its associated impact on plant equipment.
The implementation of this action will be reviewed through routine resident inspection.
5.4 An inadvertent low-low steam generator level reactor trip signal occurred on July 4 while in mode 5.
Two of the three level channels had been jumpered with " dummy" level signals to inhibit a reactor trip signal.
The third channel showed actual steam generator level (0%).
Instrumen-tation and Control technicians were working on the primary process rack in which the steam generator " dummy" level signal jumpers were installed.
One of the jumpers for the "B" steam generator was accidentally bumped by a technician, which resulted in the loss of that level channel.
Con-sequently, a reactor trip due to low-low level on 2 out of 3 channels on the "B" steam generator occurred.
The reactor trip breakers opened as designed.
All control rods were fully inserted prior to the reactor trip.
Immediate ccrrective actions taken by the licensee were to tie the cables carrying the " dummy" signals to the racks to prevent further incidents.
Additionally, the licensee recommended the use of signal cables that are less bulky so that the process rack doors could be closed.
No additional concerns were identified.
l 5. 5 On June 28, a reactor trip occurred while in mode 5 (cold shutdown) due
to the loss of vital bus No. 2-1.
The loss of the vital bus produced reactor trip signals due to nuclear instrumentation system (NIS) source range high neutron flux and steam generator 21C low-low level.
The vital bus was on alternate feed (from motor control center, MCC-ES) for inver-
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t ter troubleshooting.
Steam generator level channels Nos. I and II had
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" dummy" signals inserted (indicating 40% level) to allow closing of the
reactor trip breakers for time testing, while channel III showed actual j
steam generator level (0%).
When vital bus 2-1 was lost (on overcurrent),
l steam generator level channel I dropped to 0% level, and the two-out-of~
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three logic for the steam generator low-low level reactor trip was satis-
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fied.
An NIS source range high neutron flux trip signal was also gene-i rated as a direct result of the loss of its power supply (vital bus 2-1).
The overcurrent condition on MCC-E5 was subsequently reset in about 10
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minutes, and power to vital bus 2-1 was restored.
All control and shut-down control rod banks were at 5 steps prior to the trip.
Plant systems functioned as designed.
The licensee has determined that the overcurrent condition on MCC-E5 was caused by excessive leakage from the silicon controlled rectifier (SCR) on the output of the associated power shield.
The failure mode of the SCR was further determined to be a random com-ponent failure.
The licensee replaced the SCR and performed satisfactory post-maintenance testing on July 7,1987.
No further problems were en-countered.
6.
Emergency Diesel Generator Lube Oil System Onsite emergency AC power is provided by two independent emergency diesel generators.
The diesel generators were manufactured by Colt Industries, Fairbanks Morse Power System Division, and are Model Pielstick PC2, Type V.
The skid-mounted lube oil system provided by the vendor included a full flow simplex oil strainer.
Clogging of the simplex strainer would reduce lube oil flow such that diesel generator failure would eventually occur.
Licensee procedures direct the engine operators to monitor lube oil strainer differ-ential pressure (dp) for indications of strainer clogging.
Due to the simplex design of the lube oil filter, the diesel must be shut down and the lube oil system secured in order to clean or replace the strainer elements.
Initial load testing of the diesels was marked by high dp across the lube oil strainers.
The licensee initially attributed the strainer clogging to the plating out of system preservatives not yet completely flushed out of the i
engine.
This lube oil strainer problem was discussed in Inspection Report 50-412/86-38.
Further diesel engine testing continued to demonstrate in-creased strainer dp and data extrapolation by the licensee suggested that the maximum time either diesel generator could run continuously at load was be-tween three and four days (see Inspection Report 50-412/87-48).
At that time each diesel would need to be secured for one to two hours for strainer element cleaning or replacing.
The licensee collected samples of the material on the strainers for analysis.
The sample results were negative in that no foreign material or contaminants were present.
Discussions between licensee and vendor personnel, engine per-
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formance data, and the strainer sample results all indicated that 3-4 days
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of continuous run was the realistic maximum for the vendor provided design even with the relatively new and thoroughly flushed hardware.
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The licensee elected to modify the lube oil systems for both diesel generators to increase their reliability.
A second full flow simplex strainer was in-stalled in parallel with the original.
Isolation valves were added to allow either strainer to be cleaned while the other str'.iner was in use. 'The modi-fication was completed for the #1 diesel at the end of the inspection period and in process for the #2 diesel.
Post-modification testing of the #1 diesel demonstrated the ability to switch lube oil strainers during diesel generator operation.
Licensee actions to eliminate potential impact on diesel generator operability and improve the reliability of onsite emergency power are considered 3 strength.
No violations were identified.
7.
Recirculation Spray System Heat Exchangers Throughout the report period, the licensee conducted extensive repairs and testing to the four recirculation spray system (RSS) heat exchangers.
These repairs and testing were required to remove foreign material and to correct tube wear and two tube failures that were experienced during flushing and preoperational testing.
The RSS heat exchangers are vertical, counterblow, shell and tube type heat exchangers with 37-foot tubes (1200 tubes per heat exchanger) made of Type 304 stainless steel.
A description of the general activities conducted is as follows:
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Prior to any repairs, eddy current testing was conducted on all tubes.
l Vibration testing was conducted over the range of expected RSS flows (500-3500 gpm) on the "C" heat exchanger which experienced the most l
damage.
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The two damaged tubes were plugged.
Also, based on the tube inspections
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conducted, additional tubes were plugged with the final tube plugging i
count as follows:
"C" = 17, "D" = 14, "B" = 10, "A" = 8.
The licensee's original safety analysis indicated that a maximum of 25 tubes could be plugged per heat exchanger.
A sub m.luent refinement of this analysis j
justified plugging 75 tubes.
In addition to plugging the tubes, the l
majority of the tubes plugged had full length steel rods inserted in the tubes prior to plugging to assist in minimizing vibration.
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RSS piping at the RSS heat exchangers' inlet and outlet was cut to insert i
flanged spool pieces which would facilitate heat exchanger cleaning and
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flushing.
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Approximately 20 holes (1-inch) were drilled in the RSS heat exchanger shell at locations above the internal baffle plates.
Temporary piping was installed at these locations to facilitate removal of debris from the baffle plate area by flushing.
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Temporary equipment was pro'vided to chemically clean the RSS heat ex-changers with a caustic solution.
Subsequent to the chemical cleaning, a temporary flushing pump and piping was provided to permit preliminary recirculation flushing at flows of approximately 3000 gpm prior to re-storing the'RSS piping to normal.
A hydrostatic test was conducted and'
final acceptance flushing was performed using the RSS pumps.
The licensee is compiling a detailed report on this major work effort.
The best estimate of the cause of the tube wear and tube failures has been attri-buted to the coincidental start of the RSS pump and high flow (greater than 4000 gpm).
There were a high number of start /stop cycles on the RSS pumps early in the original flushing operations where such high flows existed.
However, the most recent vibration testing on the "C" heat exchanger produced
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less than 5 mils of tube deflection which appears satisfactory since 187 mils deflection is required to achieve tube-to-tube contact.
The inspector will review the licensee's planned report during a subsequent routine inspection.
The inspector closely monitored the licensee's activities concerning the RSS heat exchanger especially since the repair activities were key to the licen-see's original schedule to enter Mode 4 on June 19, 1987.
The inspector noted several concerns which were satisfactorily addressed by licensee personnel.
The inspector questioned if any detailed calculations had been performed to verify that the Safeguards roof structure was adequate to handle the loads'
caused by the temporary flushing equipment which included a large pump and motor (dry weight.7645 lbs) and several tanks.
The licensee performed a.de-tailed calculation'to confirm that there was not a problem.
Also, the in-
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spector noted that certain safety related cables in the "D" RSS cubicle were
possibly water damaged.
SQC reviewed this area and issued Nonconformance. arid Disposition Report 59002 to address this problem by routine site procedures.
Another inspector item concerned a heavy duty fiber sling that was being used for temporary rigging and found wrapped around a safety related conduit in-the "D" RSS cubicle.
This condition gave the appearance that the safety re-lated conduit was possibly used as a tie off point for temporary support.
The inspector advised DLC testing personnel of this item and the sling was removed from the conduit. The conduit was not damaged and no other instances were observed where conduit was used for temporary support.
The inspector had no further concerns.
At the end of this report period, all four RSS heat exchangers had been satis-factorily flushed and accepted in accordance with the flush acceptance cri-teria of ANSI N45.2.1-1973.
No violations were identified.
8.
Cable Storage
Licensee records indicate that over seven and a half million linear feet of cable has been installed in Unit 2 with a rough average of 3000 linear feet of cable per reel.
This means that the licensee has handled some 2500 reels
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of cable.
Early in the project, the licensee elected to procure all cable to Category I specifications to avoid the possibility of inadvertently in-stalling.non-Category I qualified cable in a safety related application.
During the period of-bulk cable installation, the licensee's practice was to release whole vendor supplied reels to the field for the needed cable lengths to be pulled from the reel'at the job location.
The licensee's procedures required documented QC coverage of these activities when the cable was used for Category I applications.
The licensee's practice changed near the end of the construction phase such that individual cable lengths would be cut from the parent reel at a cable storage area and the cable then taken to the job location and installed.
Some concerns were. identified with respect to the storage of the Category I cable in Inspection Report 50-412/86-47.
The inspector noted that there were reels in the cable storage area which contained individual cable lengths rather than continuous cable.
Further inspection revealed that these reels were being generated within the cable storage area by cable lengths which had been cut for a particular job, taken to the field, pulled into place, later removed, brought back to the storage area, and re reeled. -The use of locally-generated cable reels meant that some Category I cable pulls would come from
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cable already taken to the field and returned and not just from reels which i
came directly from vendor facilities.
QC inspection coverage for Category I cable installation monitors and docu-ments several important aspects of cable handling including maximum pull ten-sion, minimum bending radius and allowable unsupported length.
Cable returned-from a non-Category I pull would not have had QC coverage during installation and therefore, would not be appropriate for subsequent Category I use.
The inspector observed that some of these reel record cards were marked for non-Category I use only but that other reel record cards were not.
The current QC inspection documentation was developed during the bulk cable installation period and was not revised to reflect the change in installation practices and the existence of reels containing returned cable.
In response to the inspector's concerns, the licensee conducted an extensive i
document review and cable storage area walkdown.
A total of 256 reels were
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identified as being potentially non-vendor reels.
Some vendor reels had been reassigned numbers at the storage area to avoid duplication of identification numbers.
Other reels were also determined to be original vendor reels such that a total of 93 reels remained as being generated by returned cable.
A total of 79 of the site generated reels were designated for non-Category I
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use only and the record cards showed only non-Category I pulls had been taken from the reels.
The inspector reviewed the material receipt records and the applicable reel record cards and identified no deficiencies.
Of the remaining 14 reels,11 had been used for Category I pulls.
QC inspec-tion records clearly demonstrated that these 11 reels had all been generated by cable returned from previous Category I applications which had themselves l
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received proper QC coverage.
Documentation for the last 3 reels was not con-J
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clusive but no Category I pulls had been made from these reels at the time of this inspection.
The licensee immediately labeled these reels as for non-Category I use only to preclude their use in safety related applications.
No violations were identified; the licensee committed to revise the applicable QC inspection procedures so as to require an evaluation of any non-vendor reel before using it for a Category I application.
This procedure revision will be reviewed in a later inspection.
9.
Condensation on Safeguards Building Pipes During a routine site tour, the inspector noticed significant quantities of condensation dripping from Quench Spray System (QSS) piping (i.e., pipe sweating) in the lower level of the Safeguards Building near the Refueling Water Cooling (RWC) pumps.
All of the QSS piping in this area associated with the two RWC pumps were sweating.
For example, the 6-inch pump suction and discharge piping (line numbers 2-QSS-006-9-4 and 2-QSS-006-11-4 respectively on the QSS RM-858 flow diagram) were involved.
Upon further investigation, the inspector noted that the suction lines for the "A" and "B" QSS pumps and the Low Head Safety Injection pumps was also sweating.
The inspector noted these conditions to the licensee and expressed the fol-lowing concerns:
A near term potential problem existed due to the Inoisture dripping onto a.
the electrical motor connection boxes for the "B" QSS pump and the "A"
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and "B" LHSI pumps.
While these connection boxes had rubber gasketed closures, the inspector concluded after visual inspection that the boxes may not be waterproof and could fill partially with water since no bottom weep holes existed on the boxes.
Moisture was also observed to be drip-
ping onto the motor cover for the "B" LHSI pump.
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b.
A long term potential problem exists in that the floor in the lower level of the safeguards building is constantly wet.
This condition presents a general safety hazard for the operator and would tend to promote con-tamination problems in the future unless the pipe sweating condition is corrected..
In response to the above concerns, the licensee noted that anti-sweat insula-tion should have been called out for the piping associated with the RWC pumps.
l The inspector noted that the licensee was installing anti-sweat insulation on all affected piping at the close of the inspection period.
No violations were identified.
10.
Fill Header Flow Control Valve - 2CH&' 3-160 I
The reactor coolant system (RCS) design for BV-2 includes isolation valves
on each of the three RCS loops.
The purpose of these large valves is to allow
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maintenance on an isolated loop without requiring defueling and/or lowering i
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l overall RCS level.
The isolated loop would be refilled, heated up as neces-sary, and returned to service.
The flow path to refill a loop of the RCS includes two check valves and a flow control valve.
The internals of the flow control valve (2CHS-FCV-160) were found to be damaged during preoperational
{
i testing and were replaced.
The FSAR (Section 9.3.4.2) states that the valves which handle radioactive liquids or boric acid solutions are stainless steel.
The Technical Specifi-cation identify 2CHS-FCV-160 as a containment isolation valve in Table 3.6-1.
The licensee is not presently authorized to isolate a lcop of the RCS while not defueled such that operation of the valve is not possible.
The licensee elected to replace 2CHS-FCV-160 but was unable to obtain a stainless steel valve; one was ordered but delivery is not expected for about 13 months.
In the interim, the licensee replaced the valve with a carbon steel valve.
The licensee has performed a review and determined that the substitution is acceptable until a stainless steel replacement is available.
This item is considered Unresolved (87-47-02) pending NRC review of the lic-ensee's technical justification for deviating from the FSAR and the replace-ment of 2CHS-FCV-160 with a stainless steel valve.
11.
Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings.
A summary of inspection findings was further discussed with the licensee at the conclusion of the report period.
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