IR 05000412/1986031
| ML20214H639 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 11/19/1986 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20214H598 | List: |
| References | |
| 50-412-86-31, NUDOCS 8611260489 | |
| Download: ML20214H639 (18) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-412/86-31 Docket No.
50-412 License No.
CPPR-105 Licensee:
Duquesne Light Company Nuclear Construction Division P. O. Box 328 Shippingport, PA 15077 Facility Name: Beaver Valley Power Station, Unit 2 Dates:
October 4 - November 2,1986 Inspectors:
J. E. Beall, Senior Resident Inspector A. A. Asars, Resident Inspector R. J. Urban, Reactor Engineer W. M. Troskoski, Senior Resident inspector, BVPS Unit l'
L. J. Prividy, Resident Inspector H. Wo dard, Reactor Engineer Approved by:
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1. E. Tripp, Chief, Reactor Projects Section 3A
' Uate Inspection Summary:
Inspection No. 50-412/86-31 on October 4 - November 5, 1986 Areas Inspected:
Routine inspections by the resident inspectors (287 hours0.00332 days <br />0.0797 hours <br />4.74537e-4 weeks <br />1.092035e-4 months <br />) of licensee actions on previous findings, site activities, fuel receipt, security,
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auxiliary feedwater system, emergency diesel generators, solid state protection system, reactor trip breakers, reactor coolant system, potential for a High Energy Line Break in the Safeguards Building, and rigid sway strut functional interference.
Results: One violation was identified:
UNR (84-18-03) was changed to a violation for failure to provide appropriate acceptance criteria to QC inspectors and failure to verify conformance with paddle / bracket clearance requirements on rigid sway struts.
8611260489 061117 PDR ADOCK 05000412 G
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DETAILS 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 Construction activities are currently estimated to be 97.3% complete, with 435 of 476 subsystems turned over for flushing and proof-testing.
For soft-ware, about 85 out of 114 preoperational (P0) and initial startup tests (IST)
have been approved.
The remainder are in various phases of development.
Approximate dates for the major project milestones, as currently estimated by the licensee are as follows:
Integrated Hot Functional Test November 15, 1986
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Loss of Power Test February 2,1987
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Integrated Leak Rate Test February 23, 1987
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Fuel Load May 1, 1987 Initial Startup May 16, 1987
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Commercial Operation August 30, 1987
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The IHFT milestone date was changed from October 20 to November 15, 1986.
This change was necessary to account for unexpected delays in prerequisite preoperational testing, i
3.
Inspection Program Status Summary
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Preoperational Test Program Inspection completion status is approximately as follows:
AREA
% INSPECTION COMPLETE Overall Program 35%
Procedure Reviews:
Mandatory 35%
Primal 50%
Test Witness:
Mandatory 15%
Primal 5%
Results Review:
Mandatory 15%
Primal 5%
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This inspection status is consistent with the applicant's test program pro-gress.
At the end of this inspection period, there were approximately 60 open NRC inspection items including 7 bulletins, 10 violations, and 19 construction deficiency reports. The remainder are unresolved items.
4.
Licensee Actions on Previous Inspection Findings (Closed) Unresolved Item (85-25-03): Electrical Rework Control Program.
The inspector had identified several construction deficiency reports (CDRs) in-volving recurring deficiencies in conduit support rework.
This problem was presented to Stone & Webster Construction Management and Sargent Electric Company (SECO) personnel for resolution and corrective action.
The licensee concluded that the recurring deficiencies developed due to a lack of under-standing of the requirements of the governing procedure for the control of electrical rework - Field Construction Procedure 41.1 (FCP 41.1) and that electrical construction personnel (foreman, engineers, coordinators) required specific training to resolve the problem.
This item remained open pending a review by the inspector of the effectiveness of the licensee's corrective actions.
The inspector reviewed CDRs issued in September and October, 1986, and the SQC surveillance results of electrical rework control that was conducted from April thru October, 1986, in accordance with SQC Inspection Plan 8.7.4 (IP 8.7.4)
The inspector determined that SQC conducts a weekly surveillance of the electrical rework control program in accordance with IP 8.7.4.
In general, for each week from April through October, there were few deficiencies except for one week in August, where there were nine deficiencies.
The nine defi-ciencies were all in the Fuel Building area and were attributed to intensive SQC inspection activity (IP 12.3 Area Release - Electrical Inspection) related to Fuel Building turnover to DLC Operations.
These deficiencies were deter-mined not to be symptomatic of an electrical rework control program problem.
They were confined to one activity where clips were removed from cable tray covers and further SQC review concluded that this activity was legitimate in-progress work being conducted per an outstanding Engineering and Design Co-ordination Report.
The inspector identified no deficiencies in the effectiveness of the licen-see's corrective actions and th'is item is closed.
(Closed) Unresolved Item (85-26-02): Maintenance program for lay-up of in-stalled equipment.
Previous inspection determined that equipment not being
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tested or operated, which was turned over to the Startup Group (SUG), was not covered by a lay-up maintenance program.
At that time, the licensee committed to develop such a program.
The inspector reviewed Startup Manual (SUM) Chapter 4.2, " Scheduled Mainten-ance/ Calibration Program." This chapter now requires the assigned SUG System Engineer to initiate a Startup Work Request (SWR) when, in the engineer's opinion, equipment will be in an inactive status and will require lay-up.
Lay-up instructions are provided on the SWR and are based on maintenance ex-
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perience, instruction manuals, vendor recommendations, etc. When the SWR is received by the SUG Maintenance Section, the necessary tasks are implemented.
Periodic checks are entered into the Scheduled Maintenance Program by the system engineer for routine performance once the equipment is placed in lay-up.
The inspector reviewed the lay-up performed on the Main Steam Isolation Valves (MSIVs).
The SWR was properly issued, lay-up instructions were in accordance with the vendor instruction manual, and periodic checks of the MSIVs were entered into the scheduled maintenance program.
Site Quality Control also verified that tasks were performed properly.
The licensee's program for the lay-up of equipment appears adequate.
The in-spector had no further questions and this item is closed.
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(Closed) Inspector Follow Item (86-01-05): Structural integrity of the brush holder arm assembly on emergency AC generators manufactured by Beloit Power.
Systems.
This item concerns a fatigue failure of the brush holder arm as-sembly on AC generators powered from Colt Pielstick emergency diesel genera-tors.
This failure occurred at another site after about 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> of pre-operational testing due to vibration.
A loss of DC field excitation was ex-perienced, rendering the AC generator inoperable.
The licensee contacted Louis Allis (formerly Beloit Power Systems) concerning the above situation.
The supplier stated that the licensee's AC generators have 15 inch brush holder assemblies.
The failure at the other site was on an 18 inch brush holder assembly and was due to a manufacturing defect that was aggravated by increased stress due to a higher resonant value frcm the increased length.
This failure was the only one experienced by the supplier and a 10 CFR 21 report was not required.
The supplier also stated that no special testing was recommended.
The inspector nad no further question,s and this item is closed.
(Closed) Inspector Follow Item (86-04-07): Turbine Driven Auxiliary Feedwater Pumps preoperational test to include provisions to check for possible water hammer in the steam line to the terry turbine.
This item is discussed fn detail 8.B. of this inspection report.
(Closed) Construction Deficiency Report Item (86-00-09): Failure of NAMC0 position indicating limit switcher. mounted on Masoneilan QA Category 1 valves to consistently activate.
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The licensee identified twenty-eight (28) Category 1 valves as having the potential for this actuator switch problem.
The cause of the problem was found to be excessive tolerance in the limit switch actuation linkage.
Move-ment of the valve stem in an axial direction was sufficient to cause the limit i
switch actuator take-off arm (which connects to the valve stem) to rotate and thus fail to engage the limit switch actuating lever.
Lack of alignment ad-justment between the valve stem take-off arm and the limit switch actuating lever contributed to this problem.
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Masoneilan redesigned the limit switch bracket to provide for alignment.
The new bracket also incorporates provisions to prevent the position take-off arm on the valve stem from rotating throughout the valve stroke, thereby main-taining alignment.
Twenty-one of the twenty-three installed valves have been modified.
The balance of the valves, two installed and five spares, are covered by outstanding work requests to complete this modification and resolve this problem.
This item is closed.
(Closed) Inspector Follow Item (86-04-05): Emergency Diesel uenerator (EDG)
connecting rod nuts which were reported to be manufactured incorrectly for similar Colt EDG units at another facility.
The nuts had faces which were not perpendicular to the thread pitch line, resulting in a fitup to the mating surfaces that was not parallel.
Investigation of this problem disclosed that the incorrect nuts were on the Colt Fairbanks Morse opposed piston engine and not on the Colt Pielstick engines that are used on the EDG units at Beaver Valley, Unit 2; therefore, this problem is not applicable.
For additional confirmation, however, the spares were inspected.
No deficiencies were dis-covered as reported in QC General Inspection Report Q-65345.
This item is closed.
(Closed) Violation (82-02-01): Failure to provide quantitative criteria to ensure adequate weld sizes on a suoport.
Stone and Webster standard drawing PS-2A described weld joint details for connecting trunnions to run pipe.
However, previous NRC Inspection Report 50-412/82-02 had identified that welds performed in accordance with and meeting the requirements of PS-2A could have inadequate throat size necessary for structural integrity.
NRC Inspection Report 50-412/85-03 updated this item but lef t it open pending further review to ensure disposition and rework are accomplished in accordance with previous commitments.
During this report period, the inspector reviewed the licensee's final actions on this item.
The licensee evaluated all of the trunnion to run pipe connec-tions that were installed in accordance with PS-2A.
Stone and Webster Engi-neering identified 70 ASME welds and 32 non-ASME welds.
The dispositions to these 102 welds are as follows: 35 welds were redesigned by adding additional trunnion plates, 31 welds were corrected by adding fillet welds, 24 welds re-quired a drawing change to reflect the as-built condition, 7 welds were cor-rected by drawing revisions to require partial penetration welds per PS-4A, 4 welds were voided, and I weld was corrected by removing the trunnion and adding a riser clamp and lugs.
The inspector selected six reworked connections on a sampling basis to verify disposition and rework in accordance with licensee commitments.
All as-built conditions were in accordance with design drawings and were also dispositioned in accordance with applicable standards.
This item is closed.
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(Closed) Inspector Follow Item (86-04-01): Determine the cause of Emergency Diesel Generator (EDG) No. 1 cylinder No. 5 fuel injector pump failure.
This item is being upgraded to an Unresolved Item and is discussed in detail 9.b of this report.
(0 pen) Unresolved Item (86-01-03): Preop program lacks double verification of correct system restoration for mechanical components.
This item is dis-cussed in detail 12.b of this report.
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(Closed) Unresolved item (84-18-03): Rigid sway strut functional interface.
This item has been changed to a violation.
See detail 14 of this report.
5.
Site Activities Throughout the inspection period, the inspectors toured the licensee's facili-ties. General work activities were observed including construction, surveil-lance,, testing and maintenance.
The inspectors also monitored the licensee's houseiceeping, security and preliminary radiation control activities.
During tours of the Safeguards Building, the inspector observed radcon per-sonnel performing calibrations of area radiation monitors.
As this procedure involves the use of radiation sources, it was necessary to establish temporary controlled areas in the vicinity of the monitor.
The inspector noted that rad con personnel effectively limited access to the controlled area to per-sonnel wearing dosimetry and diverted construction activities away from the area.
During another tour in the Safeguards Building, the inspector observed a mechanical snubber that appeared to have been used as a step despite protec-tive wrapping and a posted sign.
The inspector presented his concern to the licensee and they initiated action to investigate the snubber.
In addition, i
the inspector observed blocks of wood underneath a length of low head safety
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injectio'n pipe.
The wood appeared to be supporting the midpoint of a long
horizontal run of this pipe.
Several years ago, the licensee was questioned l
concerning the need to temporarily support piping prior to installing per-l manent pipe supports to preclude possible damage.
However, since it appears l
that all pipe supports have been installed, the inspector questioned the pur-
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pose of these wood blocks.
The inspector will follow this concern in a future inspection.
6.
Fuel Receipt Four fuel shipments of 12 assemblies each were received during the inspection (
period.
The inspectors observed portions of the receipt activities and veri-
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fied adequate coverage by Health Physics technicians and Quality Control in-spectors and adherence to fuel. receipt procedures for fuel unpacking, inspec-tion and placement into the storage racks.
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No deficiencies were identified.
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7.
Security At the beginning of the inspection period, the licensee utilized two separate contractors to provide security on the Beaver Valley site.
Burns International Security Service (Burns) had responsibility for Unit 1 security, while Security Bureau, Inc. (SBI) provided industrial security at Unit 2.
The licensee had selected Burns to provide security for the new fuel including the Unit 2 Fuel Building.
On October 16, 1986, the licensee terminated the Burns involvement on site and SBI assumed all security responsibility for site security.
SBI maintained
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separate organizations for the Unit 2 industrial security and the Unit 1 (plus
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Unit 2 Fuel Building) security program.
The inspectors reviewed the licensee's plans prior to the security force transition, witnessed the guard relief and f
turnover in the Unit 2 Fuel Building, and monitored security activities fol-
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lowing the change.
The transition was orderly and controlled; no deficiencies were identified.
8.
Auxiliary Feedwater System (AFW)
a.
Motor-Driven Auxiliary Feedwater Pump (MAFP) and Controls Test Perform-ance (P0 2.248.01)
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The licensee performed the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> endurance runs for the 23A and 238 MAFPs between October 8 and 10 and October 13 and 15, 1986, respectively.
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This constitutes Part C of P0 2.248.01 which is intended to demonstrate that each MAFP will operate for extended periods with ambient conditions
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not exceeding environmental qualification specifications.
Periodically,
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the inspectors observe,d pump operation and licensee data gathering, and
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walked down portions of the system in use (recirculation path) to iden-tify excessive vibration or leakage.
Specifically, the inspectors ob-served trends in pump operating parameters such as lube oil temperature change across pump bearings, ambient air humidity and temperature changes and actual pump performance in comparison with the acceptance criteria identified in P0 2.24B.01.
During performance of this portion of the test, the licensee plotted the pump head trends for comparison with the design and test curves.
The acceptance criteria identified by P0 2.248.01 require the pump head curve to be within plus or minus 5% of the test curve and plus 10%, minus 0%
of the design curve.
The actual pump head curve for the 23A pump was less than the design curve by about 40 feet of head.
A test deficiency was written and the licensee continued with the MAFP 238 pump endurance run.
The 23B MAFP experienced a similar deficiency in that it also did not meet the design curve.
Pump actual performance fell abcut 60 feet of head short of the design curve.
Currently, the licensee is carrying test deficiencies for both pumps' failure to meet the design curve.
Resolu-tion of these deficiencies will be followed during future inspections.
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During routine observations of the 238 MAFP endurance run, the inspector noted Reject Tag No. 32468 on the pump discharge recirculation check
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valve (2FWE-FCV-1238). ' The reject tag references Nonconformance and Disposition Report (N&DR) No. 12362.
The N&DR was written as a test deficiency for the Phase 1 testing of the 23B MAFP by Startup Group be-cause the valve failed to regulate flow between 25 and 110 gpm.
In actual performance, the valve allowed 125 gpm to be diverted to the re-circulation path when the isolation valve downstream of the check valve was closed. After evaluation, Site QC referred this N&DR to Test QC for reevaluation because the N&DR was written against test procedure require-ments, not a valve design document.
Further discussions with the Phase 1 System Engineer revealed that engineering had reevaluated the recircu-lation flow requirements for that check valve.
Subsequently, E&DCR 1224)
was issued to redefine the flow limits for the check valve under recircu-lation conditions of 100 to 140 gom.
Based on this evaluation, the N&DR
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was voided and the check valve flow is acceptable.
The inspectors also noted several reject tags, QC hold tags and hardware problems involving the AFW' system.
Specifically, there are several QC hold tags associated with piping around the AFW throttle valves and missing and temporary parts in the thrcttle valve operator.
Also, there are reject tags associated with the 23A MAFP high point vent, the 238 suction piping supports and both MAFP motors EQ seals.
In future in-spections, the inspecters will follow the resolution of these items and evaluate their impact on hot Functional Testing of the AFW System.
Section A of P0 2.248.01, MAFP logic and controls testing, was started during the third week of October and is still in progress.
The licensee has encountered several unexp,ected delays involving benchboard control switches and interlocks between the main feedwater pumps and the MAFPs.
The inspector is following test progress.
b.
Turbine Driven Auxiliary Feedwater Pumps (TAFP) Test Procedure Review (P0 2.24B.02)
The inspector reviewed P0 2.248.02 to verify technical adequacy and to ensure adherence to FSAR, TS, Operating Mandal and other applicable guides and standards.
Preoperational testing on the TAFP will begin with
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the controls and logics testing before HFT and will continue through HFT to power ascension testing to verify that the TAFP operates within its
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design specifications.
The inspector'noted that P0 2.248.02 has adequately accounted for the design of the steam line to the TAFP turbine.
The line follows a tor-tuous path from the Main Steam Vault to the Safeguards Building which includes several drip pots connected to the Secondary Drain System (SDS).
The drip pots are installed to collect and discharge condensate which may' form in the line and therefore, are design features intended to pre-vent water hammer.
The condensate is discharged to either the condenser or atmosphere depending on the manual SDS valve configuration.
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2.248.02 requires the SDS discharge to be aligned to atmosphere and also requires vibration monitoring of the AFW lines during pump start and operation.
This adequately satisfies Inspector Follow Item (86-04-07)
and the item is closed.
However, the. inspector noted that the Operating Manual (0M) does not contain provisions for normal operating position of these SDS valves and operation of the drip pots.
The inspector questioned if the drip pot system will be in the same configuration under rormal operating condi-tions as per P0 2.248.02.
The licensee is currently evaluating this matter and the inspector will follow the OM revisions in future inspec-tions.
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9.
Emergency Diesel Generators a.
Air Start System Many of the EDG air start system components were made from carbon steel.
When exposed to normal moisture levels of the comprev.ed air system, rust deposits developed, resulting in several system operational problems that
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included air start check valves sticking open.
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io correct the rust buildup problem, the entire air start system was
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blown down for one week by the construction flush group.
Air dryers were also added to alleviate the moisture buildup.
The inspector reviewed the completed startup proof test 2T-NNS-36B-2.29, Test of EDG Air Dryers, and noted that applicable acceptance criteria had been met; the system was able to maintain the dew point at less than 40 F at 425 psi.
A re-view of OM Chapter 2.36, 4KV Station Service System, indicated that steps to operate the air dryers, including the precautions and limitations contained in the vendor manual, had not been added.
The Station Super-intendent indicated that this would be done.
During a tour of the EDG rooms, the inspector noted that all four air receiver tank access covers were removed and temporary plywood covers installed.
Discussions with the system test engineer revealed that leakage problems had been encountered with the sealing surfaces.
At the conslusion of this inspection period, the covers were reinstalled and the compressor tanks scheduled to be retested.
No unacceptable items were identified.
b.
Fuel The No. 5 fuel injector failed on the No. 1 EDG on September 25, 1986.
This is the third time that a fuel injector in that position has failed on the No. 1 EDG.
The first two times (2/28/86 and 3/3/86) were attri-buted to dirt in the fuel.
After the March failure, the fuel system was cleaned out by flushing the injectors, the nozzles and all of the piping on the skid pad.
Discussions with Startup Engineers indicated that a
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filter between the day tank and the engine header was sized to remove particles greater than 5 microns to preclude the introduction of dirt through that pathway.
After the September 25th failure, boroscope in-spections identified no dirt incide the fuel linas..The injector is currently being shipped offsite for evaluation by the vendor.
This item, being tracked as Inspector Follow Item (86-04-01), is now changed to Unresolved Item (86-31-05).
The EDGs have been run on a routine basis using a temporary operating procedure.
The current OST is being upgraded and will be used by the station to run the diesels once per month to maintain the diesel genera-tor at operating standards.
c.
Building Turnover During this inspection period, the licensee was in the process of com-pleting modifications to the diesel generator building roof that were part of their corrective actions to eliminate the possibility of a fire due to the high temperature of the diesel exhaust (see Inspection Report 412/86-06).
After completion of this work, building turnover is sched-uled to occur.
No concerns were identified.
10.
Solid State Protection System (SSPS)
a.
Phase I Construction Proof Tests The two construction proof tests (2T-RPS-1Al-2.01 and 2.02) were last discussed in NRC Inspection Report 412/86-21, detail 9c.
Since then, 2.02, Functional Test of SSPS Demultiplexer and Output Relays, was re-vised to incorporate many hardware and software changes, including use of the Westinghouse-supplied " sync" and "0R" cables.
The inspector ob-served portions of this test on October 9, 1986.
The proof testing was terminated after it was determined that both SSPS train A and B UV output cards failed; the Darlington pair transistors Q3 and Q4 were burnt out.
Under this condition, the SSPS is incapable of sending a trip signal to the RPS trip breakers.
Previous industry experience in this area is addressed in IE Information Notice E5-18, Failures of Undervoltage Output Circuit Boards in Westinghouse Designed SSPS.
l After spare UV output cards were obtained, the inspector witnessed their
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i replacement during a backshift tour.
The work was performed by two con-tractor technicians under a Startup Work Request (SWR).
A TQC inspector provided coverage of the card replacement, signed the appropriate SWR step, and then left.
The technicians then initiated Construction Proof Test 2.02 until they reached a step where the Train B general warning alarm would not clear.
The UV output cards were swapped for trouble-shooting and were then returned to their original configuration after that attempt failed to clear the alarm.
The technicians then unlocked i
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several SSPS cabinet doors and noted that a universal logic card was missing from Train B.
At that time, the test was terminated and all the cabinet doors were relocked.
On October 10, 1986, the inspector discussed the above problem with the Startup Test Engineer.
When the Train 8 cabinets were unlocked and opened, all the universal logic cards were in place.
Additionally, a DLC I&C technician informed the inspector that foreign material had been found in one of the SSPS cabinets.
The inspector discussed this event with the station superintendent and raised a concern that the station should be able to demonstrate that no unauthorized work was performed in the SSPS racks after proof-testing was completed.
Further investigation of the SSPS problems resulted in issuance of Test Deficiency Report 3435.
It was found that the 15 volt and 48 volt power supply leads had been inadvertently swapped.
As many as 54 SSPS circuit cards were determined to have been damaged.
After repair or replacement, the entire SSPS will have to be retested.
The card failures occurred after the two sync and one OR cables to the Train A and B logic cabinets were plugged in for the.first time. Two conductor pins in the OR Cable and two in one of the sync cables were found reversed.
This resulted in applying 48 volts to circuit cards rated for 15 volts.
The reason the leads were swapped was to correct an apparent error in the color code, when the cables were being shortened for use in BV-2's physical layout.
The technician did not realize that the other end of the connector also had the same color code error.
This coupled with the failure to perform a continuity check allowed the over-
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voltage condition to occur.
The inspector was informed that a Nonconformance and Disposition Report would be issued to evaluate the failure and ensure corrective action.
This item will receive continued inspector followup as Unrcsolved Item (86-31-01).
b.
Phase II Preoperational Tests The inspector reviewed the following tests to ensure technical adequacy, conformance to Regulatory commitments, and proper administrative resiew and approval:
(1) P0-2.01A.01, Reactor Trip Switchgear and Motor Ger'erator Set Test.
(2) P0-2.01A.11, ESF Time Response Summary The inspector noted that all the test commitments referenced in FSAR Section 14.2.12 were met.
For P0 2.01A.01, both the reactor trip breakers and bypass breakers (Westinghouse Model DS 416) are to be tested locally and remotely by removing voltage from the undervoltage coil and energizing the shunt trip coil to verify that either action will trip
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the breakers.
P0 2.01A.10, SSPS and ESF Logic Tests, reviewed in IR 412/86-21, tests this system up to the output of the slave relays.
P0 2.01A.01, will use one automatic reactor trip signal from each train to verify that the automatic signal trip path to the trip and bypass breakers is functional, thereby providing an overlap in testing the RPS.
The motor generator design specifications are tested as well as verifi-cation of flywheel design to provide required generator output voltage upon loss of input motor voltage.
The only concern identified related to a lack of testing of the general warning alarm reactor trip.
This trip is referenced in Section 7.2.2.2.3 of the FSAR and is also discussed in Section 7.2.2. of NUREG-1057, SER for BV-2, Supplement 1.
It provides protection for conaitions under which both trains of the reactor trip system may be inoperable by auto-matically opening all reactor trip breakers and bypass breakers.
The inspector noted that such a test was not performed by P0 2.01A.01, and the Station committed to revising this procedure prior to test perform-ance.
Review of this corrective action will be tracked as Unresolved Item (86-31-02).
11.
Reactor Trip Breakers (RPS) - Generic Letter 83-28 Commitments.
By letter dated June 18, 1985, NRR requested additional information regarding
. the preventive maintenance program for reactor trip breakers and maintenance trending at BV, Unit 2.
This request specifically addressed items 4.1, 4.2.1 and 4.2.2 in Generic Letter 83-28.
DLC responded to this request by letter
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dated November 4, 1985, and committed to performing a preventive maintenance program to include the Group A and Group B activities described in the West-inghouse Manual for the 05-416 Reactor Trip Circuit Breaker, Rev. O, dated October, 1984.
Additionally, the reactor trip breaker monitoring program would trend parameters from maintenance operation and testing that included the following:
1.
Breaker response time for undervoltage trip.
2.
Drop out voltage for undervoltage trip.
3.
Breaker insulation resistance.
4.
Trip force.
The inspector conducted discussions with DLC Electrical Maintenance Engineers and reviewed PMP 2-1-RPS-BKR-TRIP-1E, Reactor Trip Circuit Breaker Inspection.
Revision 1 to the PMP was currently being revised.
Preliminary review indi-
cated that it would incorporate all of the recommended actions in the West-inghouse Maintenar.ce Manual for the DS-416 breakers.
The reason for the cur-rent revision was to include instructions for measuring the breaker trip force.
When this is complete all of the itemt, in the above licensee commitment will be met in this procedure with the exception of the breaker response time for l
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the undervoltage trip, which will be incorporated in MSP 2.14A and B, which is performed by the I&C Department.
The Plant Performance and Testing Group will be tasked with performing the monitoring program, as they are at Unit 1.
The inspector reviewed how those licensee commitments were tracked through the Station's various administrative control programs.
The Regulatory Affairs Division received the request for additional information and tasked the Unit 2 Operations Group with performing a review.
The Operations Group conducted the review in accordance with SUM 2.2 and entered the required action in the Nuclear Operations Unit Routing / Tracking Sheet System.
After the required actions are taken, Operations will then notify the Regulatory Affairs Division of the completed action so that they can close out their open item.
The in-spector noted that all of the required information was present and in the procedure writer's packet for this PMP.
Durihg discussions with plant electrical personnel, the inspector was informed that the Unit 2 reactor trip breakers had been in place for approximately three years without any preventive maintenance performed on them.
The in-spector noted that because of past breaker problems due to inadequate lubri-cation and preventive maintenance, the station should perform the approved PMP prior to initiating the preoperational test on this system.
These com-ments were acknowledged and the inspector was informed that the PMP would be conducted prior to testing.
12.
Reactor Cool' ant System a.
Background Upon completion of extensive flushing to reestablish RCS cleanliness requirements, as discussed in Detail 8 of Inspection Report 412/86-12, the rebuilt C reactor coolant pump (RCP-C) was returned to the site in late Atgust, 1986.
Pump installation was completed during September, 1986, and test run after RCS fill and vent during the week of October 12, 1986.
Discussions with the Station Superintendent indicated that RCP-C performed satisfactorily; RCP A&B would require a minor balancing to further dampen vibration.
b.
RCS Safety Valve Flange Leak Prior to the above evolution, the RCS cold hydrostatic test was performed on April 29, 1986.
Inspector review of the preoperational test noted that it lacked a double verification for restoration of such mechanical components as pressurizer safety valves and safety injection system check valves that were either removed, modified or disabled to support the hydro.
Unresolved Item (86-01-03) was opened to track this concern.
During the fill and vent of October 12, 1986, RCS pressurization had to be temporarily suspended when operators observed three pressurizer safety valves leaking about 1 gpm each, at the flange join _. _
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c.
Administrative Controls The inspector reviewed various administrative control systems that should have ensured correct component configuration prior to this evolution.
It appears that the original QA qualified safety valve bolts were mis-
-placed or lost, and SQC opened N&D 29059 on November 15, 1985, to ensure
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permanent replacement with qualified material.
The safety valves, which were removed in order to conduct the hydro, were not replaced until about August 26, 1986.
After the hydro, SVG Open Items 10123 - 25 were initi-ated to track system restoration.
Both the N&D and SVG open items were left outstanding during the RCS fill and vent process, which was con-ducted by Operations according to several Temporary Operating Procedures (TOPS), as discussed below.
The control room operators were unaware that when the safety valves were reinstalled, temporary nuts were used and consequently, were not properly torqued.
Review of the SUM and discussions with Startup Testing personnel indi-cated that all N&Ds are listed on the Exception Work Tracking System.
Both this system and the SUG Open Item System are sorted by plant system aumber to allow ready reference by the responsible test engineer.
Addi-tionally, plan of the day meetings were conducted as well as a special coordination meeting for the RCS fill and vent.
It appears that the system test engineer was either unaware of the true status of the safety valves, or did not know about the planned system evolution (per TOPS)
and hence, did not inform operations of the deficiencies.
Though no equipment damage occurred, this event highlighted a case of poor coordi-nation of test ana operational activities.
Discussions with the Station Superintendent indicated that this event was discussed with all test engineers to reinforce the need for coordination and control of test activities prior to Hot Functionals.
d.
Temporary Operating Procedures The inspector reviewed the following TOPS used to fill and vent the RCS during October, 1986:
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(1) TOP 6-10, RCS Power Supply and Control Switch List for RCS Fill, performed October 10, 1986.
(2) TOP 6-13, RCS Valve List for RCS Fill, completed October 2, 1986.
(3) TOP 6-14, RCS Fill and Vent, performed October 12, 1986.
Several discrepancies were noted during the procedure review.
TOP 6-10 was missing many of the required signoffs.
TOP 6-14, which was to leave the system solid at 100 - 150 psig with the CVCS in operation, lacked the verification signature from the Phase 1 Primary Component Cooling Water test engineer.
These problems appear to be contrary to SilM 3.4.4, Adherence to Operating Procedures.
This was discussed with Station Management and the inspector raised a concern that Unit 2 Operations ad-
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herence to other TOPS should be reviewed by the station prior to fuel load.
This concern was acknowledged.
Further review of other TOPS, to verify compliance to the intent of SUM 3.4.4, is Unresolved Item (86-31-06).
Review of TOP 6-13 indicated that the pressurizer safety valves (RC551A-C) were on the list and checked as part of the pre-RCS fill system walk-down..The inspector noted that the safety valves were installed in the field and that the bolts in p ace were painted the same color as the safety valve body which when considering the lack of any field tags, would lead an operator to believe that the valves were properly installed.
Although not the primary reason for the failure to ensure correct com-ponent configuration for these valves, it precluded identification of this problem during field walkdowns.
No further concerns were identified.
e.
Safety Valve Restoration The chain of events related to N&D 29059 and final disposition for re-storation of the safety valves was reviewed by the inspector through extensive discussions with Testing, Flushi.ng and QC supervisory personnel and document reviews.
The inspector determined that RCS cleanliness requirements were properly maintained and controlled in accordance with the DLC Cleanliness Verification Program-(SUM 5.11).
Data sheets indi-cated that double verification of cleanliness was provided by the flush group and the SUG fndependent cleanliness verification group.
SQC veri-fied the material used (gasket, bolts).
At the conclusion of this report period, N&D 29059 remained open pending a final decision on gasket and nut replacement.
The inspector was in-formed that the nuts in question had the heat code forged into them for traceability to the vendor's certification.
No concerns were identified
' in this area.
13.
Potential for High Energy Line Break in the Safeguards Building The Safeguards Building contains components of both trains of emergency safety feature systems including the auxiliary feedwater (AFW) pumps, the low head safety injection (LHSI) pumps, and the quench spray (QS) pumps.
The Safe-guards Building has an internal wall which provides physical separation of
"A" train components from "B" train components.
The above pumps of each train are located in the same room (elevation 718 ft) in close proximity to each other.
The design basis environment for these pumps is 220 F and 90% humidity, which is based on the energy sources normally available and the HVAC design
. capacity.
- The turbine-driven AFW pump is located in the same room as the "A" train motor-driven pumps listed above.
The four inch steam line to the turbine-driven pump represents a potential source of high energy fluid.
The licensee's environmental qualification (EQ) analysis assumes the steam line negligible because the steam supply valve is upstream of the piping in the Safeguards
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Building and therefore, the piping is normally cold.
It should be noted, however, that many anticipated events and transients lead to the automatic admission of main steam (from all three steam generators upstream of the main steam isolation valves) to the piping in the Safeguards Building and the tur-bine-driven pump.
These events include main feedwater pump trips and under voltage on the non-safety bus which supplies the reactor coolant pumps.
The effects of a high energy line break (HELB) in the "A" train side of the Safeguards Building might be severe because the EQ limits of the "A" AFW, LHSI and QS pumps might be exceeded such that these components would not be avail-able to respond to a transient or mitigate an accident.
The physical separation of the "A" and "B" trains in the Safeguards Building is designed to ensure that "B" train components would not be affected by fire (or HELB) in the "A" train portion of the building.
If the failure of an active or passive component caused a HELB, the "B" train components would be available to fulfill their safety function.
The inspector conducted an independent review of anticipated transients and design basis events to' determine if a credible scenario existed which could produce a HELB withcut the need to postulate the failure of a safety grade component.
If a credible scenario were identified, then a subsequent single failure (e.g., the "B" train diesel generator) would lead to the loss of func-tion of both trains of AFW, LHSI and QS in violation of General Design Cri-teria 4, 35 and 38 of 10 CFR 50, Appendix A.
Based on events at otner sites, the inspector concentrated on scenarios that had potential for the introduction of water into the AFW turbine driven pump steam supply line during operation of the pump. Water hammer in the steam line or water impingement on turbine blading are potential HELB mechanisms.
The complex inter-relationship of non-safety grade 80P components and steam generator level present possible, but not necessarily credible, scenarios leading to steam generator overfill. The automatic nature of AFW and the absence of a steam generator high level AFW trip indicate that a steam genera-tor overfill could allow a steam-driven water slug to enter the turbine-driven AFW pump steam supply line.
A steam generator tube rupture LOCA is another scenario which has the poten-tial to lead to a steam generator overfill.
Should a tube rupture scenario be determined to.be a credible way to produce steam generator overfill, then the potential HELB would involve a LOCA outside containment (into the Safe-
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guards Building).
The issues involved are very complex and the inspector was not able to deter-mine whether or not the scenarios identified above were credible.
This item is Unresolved (86-31-03) pending further evaluation.
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14.
Rigid Sway Strut Functional Interference Previously, Unresolved Item (84-18-03) identified potential interferences be-tween size 20, 25 and 40 Figure 350 and 360 strut paddles and Figure 146 brackets on Power Piping rigid sway struts.
Certain rigid sway struts were observed in the field in which the designed 10 degree lateral movement could not be achieved due to tight clearance between the strut paddle and bracket.
This item was previously updated in NRC Inspection Reports 412/85-09 and 86-07, but was lef t open pending (1) verification that the sway strut inspected in 86-07 (2 SIS-PSSP-444A/B) meets niinimum clearance requirements, (2) the same strut's maximum chamfering arc is within specifications, and (3) review of a sufficient number of chamfered sway struts to ensure proper dispositioning.
The licensee issued N&DR 33299 reporting that the minimum clearan:e specified in Inspection Procedures (IP) 7.3.1, 10.5 and Specification 2BVS-920 was not met even after perforning chamfering on the strut paddle.
This N&DR was closed and dispositioned " accept-as-is." The engineering justification stated that the strut spans two fixed points and would not be subject to lateral movement.
The inspector reviewed the analysis and identified no deficiencies.
This concern was adequately addressed and the inspector had no further ques-tions.
The licensee initiated N&DR 38854 to investigate excessive chamfering of the same strut paddle.
The NEDR was also closed and dispositioned " accept as-is."
The engineering justification was that the chamfering did not encroach on the minor section of the strut and there was no adverse effect on the integrity of the strut.
In addition, Engir.eering and Design Coordination Report (E&DCR)
2PS-4370 was issued to address the chamfered strut paddle.
The solution was to reissue 2BVS-920 to clarify that the strut paddle may be chamfered the full 180 degrees plus 1-9/16 inch (sizes 20 and 50) or 2-1/16 inch (size 40).
Power Piping Company published these new limitations without changing design drawings c. Specifications.
The chamfered strut paddle as observed by the inspector exceeded the new specification.
The inspector questioned the en-gineer who dispositioned this N&DR and from the discussion determined that the integrity of the strut was not challenged even if chamfered completely around the paddle.
However, if Power Piping were to allow full chamfering in their specifications, changes to design drawings and specifications would be necessary.
The inspector reviewed N&DR 38854, identified no deficiencies, and had no further questions.
The inspector conducted independer.t field verification of chamfered sway struts in the Safeguards and Auxiliary Buildings to ensure proper disposi-tioning.
The inspectv found support 2 SIS-PSST-3024 to be final QC accepted but failing to meet spe ific QC acceptance criteria for paddle / bracket clear-ance as specified by 2BVS-920 and IP 7.3.1 and 10.5.
Upon further review of additional supports, the inspector identified apparent discrepancies in as-found paddle / bracket clearances.
Tre acceptance criteria presented to the QC inspectors were not sufficiently explicit and required QC inspectors to make engineering judgements on acceptability.
When the strut paddle was chamfered, the previous measurement reference point was removed and therefore,
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a new point for movement interference was introduced.
This new point could still prevent the strut from moving 10 degrees laterally.
Some QC inspectors accepted these types of supports, others rejected them, and othets accepted them because they were chamfered, regardless of whether the paddle / bracket clearance was met.
The acceptance criteria presented to QC by Engineering and the backfit program covered by IP 10.5 conducted by QC (both in response to Unresolved Item (84-18-03)) were not sufficient to resolve the strut paddle / bracket clearance deficiency.
This is a Violation (86-31-04).
15.
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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