IR 05000412/1986007
| ML20198K146 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 05/20/1986 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20198K133 | List: |
| References | |
| 50-412-86-07, 50-412-86-7, NUDOCS 8606030350 | |
| Download: ML20198K146 (12) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-412/86-07 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:
April 1, - May 9, 1986 Inspectors:
W. M. Troskoski, Senior Resident Inspector L
J. Pri idy, Resident Inspector Approved by:
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E. Trip 9, Chief, Reactor Projects Section 3A
' D&te Inspection Summary:
Inspection No.- 50-412/86-07 on April 1 - May 9, 1986.
Areas Inspected:
Routine inspections by the resident inspectors (214 hours0.00248 days <br />0.0594 hours <br />3.53836e-4 weeks <br />8.1427e-5 months <br />) of licensee actions on previous inspection findings, preoperational program implemen-tation, reactor coolant system cold hydrostatic test, followup on identified hard-ware problems, emergency diesel generator and high head safety injection pump proof testing, and Quality Control programs during testing.
Results:
No violations were identified.
The RCS cold hydrostatic test was suc-cessfully completed (Detail 5).
RCS and CVCS system cleanliness concerns resulting from the introduction of sheet metal to the 21C reactor coolant pump suction line are discussed in Detail 6.
How the nozzle dam got into the primary system is also of concern to NRC and will receive resident inspctor followup.
8606030350 860523 PDR ADOCK 05000412 G
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DETAILS 1.
Persons Contacted R. Coupland, Director, Site Quality Control C. E. Ewing, Manager, Quality Assurance
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T. P. Noonan, Station Superintendent R. J. Swiderski, Startup Manager D. Williams, Chairman, Joint Test Group
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The inspector also met with other licensee and contractor personnel during the course of the inspection.
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2.
Project Status Summary NRC Special Nuclear Materials License No. SNM-1954 was issued to Duquesne Light Company by letter dated April 9,1986.
It authorizes the receipt, pos-session, inspection and storage of such material contained in fuel assemblies, i
flux mapping moveable incore detectors, neutron detector systems, primary source rods, and various other detectors, monitors, calibration and check sources for eventual use at BV-2.
Construction activities are currently estimated to be 94.6% complete, with 314 of 476 subsystems turned over for flushing and proof-testing.
For soft-
ware, 55 out of 119 preoperational (P0) and initial startup tests (IST) have been approved.
The remainder are in various phases of development.
On April 29, 1986, the station successfully completed the cold hydrostatic test of the reactor coolant system.
Approximate dates for the major project milestones, as currently estimated i
by the licensee are as follows:
Fuel Receipt (Start)
September 1, 1986
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Integrated Hot Functional Test October 20, 1986
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Loss of Power Test February 2,1987-l Integrated Leak Rate Test February 23, 1987
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Fuel Load May 1, 1987
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Initial Startup May 16, 1987
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Commercial Operation August 30, 1987
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Major activities planned for next month include ESF subsystem turnovers for proof and preoperational tests, removal and inspection of 21C reactor coolant pump for possible damage, and cleaning of the reactor coolant system to re-store cleanliness levels.
3.
Inspection Program Status Summary Preoperational Test Program Inspection completion status is approximately as follows:
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AREA
% INSPECTION COMPLETE Overall Program
Procedure Reviews:
Mandatory
Primal
Test Witness:
Mandatory
Primal
Results Review:
Mandatory
Primal
This inspection status is consistent with the applicant's test program pro-gress, At the end of this inspection period, there were approximately 90 open NRC inspection items including 8 bulletins, 6 violations, and 15 construction deficiency reports; the remainder are inspector follow or unresolved items.
Licensee Actions on Previous Inspection Findings (Closed) Unresolved Item (85-16-04):
Review QA involvement in independently assuring that preoperational tests adequately demonstrate the functional capability of safety systems.
Since this item was initially opened, the in-spector has performed a detailed review of the test procedure development program as outlined in the Startup Manual (SUM) and discussed in Detail 7 of Inspection Report 412/86-06.
Also, NRC Inspection Reports 412/86-01, 04 and 06 documented test reviews that have identified no problems in this area in-dicating that the SUM requirements are being implemented and that test accept-ance criteria matches FSAR commitments.
This item is closed.
(Closed) Violation (85-16-01):
Untimely closure of nonconformance and dis-position reports (N&Ds) and construction deficiency reports (CDRs).
In a previous inspection, it was determined that some N&Ds and CDRs issued in 1979 were still open and had not been reviewed by the licensee or contractor to
. assure that they would be corrected in a timely manner.
No program existed to assure that corrective actions required to disposition the N&Ds and CDRs were taken by a specified milestone. As an example, N&D 6758, issued on May 26, 1983, stated that non-approved fluorescent tape which possibly contained chlorides, halogens and sulfur, was applied to the surfaces of stainless steel piping.
N&D 6758 was dispositioned on June 30, 1983, requiring tape removal and pipe surface cleaning.
However, as of July 18, 1985, these corrective actions had not been implemented.
Though the licensee has had programs in place for closure of N&Ds and CDRs, these programs required strengthening as evidenced by the following actions taken in response to this nonconformance.
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The S&W Superintendent of Engineering issued a directive to his personnel
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to identify N&Ds which require expeditious closure to minimize the ad-verse effects of a potentially deteriorating condition.
DLC-SQC will advise S&W Engineering when those N&Ds identified as re-
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quiring expeditious closure have not been closed in a specified time.
These conditions will also be brought to the attention of the DLC-QA Manager.
The Mechanical and Electrical contractors instituted measures to have
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all N&Ds and CDRs reviewed and to have designated personnel expedite N&Ds requiriag timely closure.
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All open N&Ds were being reviewed by the responsible parties to establish priority for closure.
The inspector noted that the above actions have improved the N&D and CDR process.
In discussions with DLC-SQC personnel who track closure of the N&Ds, the inspector learned that a number of old (several years) N&Ds are still open for legitimate reasons but attempts are being made to better define when such N&Ds can be closed.
CDRs are being managed and controlled for closeout on a system and area release basis.
These actions indicate that N&Ds and CDRs are being managed to completion.
The specific N&D 6758 cited by the inspector in Inspection Report 412/85-16 has been satisfactorily closed.
Also, the inspector noted that a separate and recent inspection (Inspection Report 412/86-03) by a region-based inspec-tor reported that a review of selected N&Ds on instrumentation tubing and supports evidenced adequate and timely closing of these N&Ds.
The inspector found these corrective actions acceptable.
This item is closed.
(0 pen) Unresolved Item (84-18-03):
Rigid Sway Strut Functional Interference.
This unresolved item identified a potential interference between a Figure 350 strut paddle and Figure 146 beam attachment on rigid sway strut supports.
The inspector observed a size 40 strut and a size 20 strut in which the de-signed 10 degree movement could not be achieved.
This unresolved item was reinspected in Inspection Report 412/85-09, and left open pending implementa-tion of corrective actions.
The suppler, Power Piping Company (PPCo), performed an evaluation and deter-mined that Figure 146 beam attachments used in conjunction with size 20, 25 and 40 Figure 350 and 360 rigid sway struts manufactur.d between June, 1981 and July 1982, did not meet minimum catalog clearance requirements.
PPCo de-termined that the interference problem could be corrected by chamfering the strut paddle in the area of interference.
The licensee stated that the in-terference problem would be corrected as specified by PPCo, applicable inspec-tion procedures would be revised to include QC inspection requirements, and reinspection would be conducted on all size 20, 25 and 40 strut assemblies.
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4 The inspector examined Inspection Procedure (IP) 7.3.1, " Fabrication and In-stallation of Pipe Supports," dated March 31, 1986, IP 10.5, "Backfit Inspec-
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tion Program - Rigid Sway Strut Installation," dated February 6, 1986, and Specification 2BVS-920, " Field Fabrication and Erection of Piping, ASME Sec-
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tion III, Classes 1, 2 and 3 and ANSI B31.1, Class 4," Addendum 4, dated February 24, 1986.
The inspector verified that IP 7.3.1, IP 10.5 and 2BVS-920 contained minimum clearance requirements for the strut paddle and beam at-tachment, and depicted / described the method in which the paddle is to be chamfered.
However, the inspector concluded that field verification would i
be necessary to determine if the proposed requirements will achieve the 10 degree movement.
The inspector examined a computer printout of all pipe supports for Unit 2.
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The licensee is using this printout to track reinspected pipe supports.
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though IP 10.5-has not yet been initiated, some pipe supports that were re-worked have been QC reinspected under revised IP 7.3.1.
The inspector wanted to field verify several QC accepted chamfered pipe supports; however, the licensee stated that only one pipe support had been reworked and the chamfer-ing operation failed to provide the necessary clearance to ensure the required 10 degree movement.
This size 25, Figure 350 sway strut was located next to 2515-PSSP-444A and B pipe supports as observed by the inspector.
The speci-fied amount of chamfering had failed to provide the needed clearance, but more importantly, this operation was not carried out in accordance with procedures.
Specification 7.4.2(e), Note 1, of IP 7.3.1 states, "The paddle may be cham-fered to full 180 degrees plus 1/2" maximum (past clevis pin cer.terline), to provide the minimum "Y" clearance." Contrary to Note 1, the chamfering was continued at least 1-1/2" past the clevis pin centerline.
This discrepancy i
was brought to the attention of the licensee.
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This item will remain open pending inspector verification that: (1) chamfering specified by the procedure meets the minimum clearance requirements stated
in IP 7.3.1, step 7.4.2(e), (2) maximum chamfering arcs are within specifica-tions, and (3) review of a sufficient number of chamfered sway struts to en-
sure proper disposition in accordance with the current specifications.
(Closed) Unresolved Item (85-13-03):
Inspection of Power Piping Rigid Sway
i Strut Supports.
This unresolved item identified a problem with the locking feature on rigid sway strut supports and a looseness problem between a pipe
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The inspector observed three rigid sway struts in which
the sleeve could be rotated by hand with a resulting dimensional change, and
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a pipe clamp that could be easily rotated about the axis of the pipe, i
Rotation of the strut sleeve was caused by failure to tighten the lock nut sufficiently during strut installation, and the loose pipe clamp was caused by insufficient tightening of the hex nuts.
The inspector reviewed IP 7.3.1,
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" Fabrication and Installation of Pipe Supports," dated March 31, 1986, IP
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10.5, "Backfit Inspection Program - Rigid Sway Strut Installation," dated February 6, 1986, 2BVS-920, " Field Fabrication and Erection of Piping, ASME Section III, Classes 1, 2 and 3 and ANSI B31.1, Class 4", dated February 24, 1986, and FCP-207, " Component Support Control," dated February 7, 1986.
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above procedures now contain new criteria to effectively lock strut sleeves and tighten pipe clamps.
The full effort of a craftsperson is to be applied to the strut lock nut with a wrench to ensure a locked strut sleeve; the old requirement of finger tightening the lock nut was deleted.
Hex nuts on pipe clamps will be tightened until the lockwasher is flat and slack between the pipe and pipe clamp is removed; the nut on the non-load bolt is then turned a minimum 1/2 turns more to ensure tightness.
The inspector concluded that the above requirements should ensure that strut sleeves are locked and pipe clamps are tight.
The inspector selected several pipe supports (UAS-PSST-592 and 598, SWS-PSST-436A and B, SWS-PSST-012A, B and C, and FNC-PSST-902) to verify that the new criteria were being properly implemented.
The as-found conditions of most of the pipe supports were satisfactory; however, the inspector found loose strut sleeves on two pipe supports.
These pipe supports had not yet been accepted by QC and the deficiencies were already noted on DLC/SQC Construction Deficiency Reports.
The inspector concluded that reinspection of all pipe supports under the new criteria of IP 7.3.1 and 10.5, and new installation of pipe supports under 2BVS-920 and FCP-207, should be sufficient to ensure that strut sleeves are locked and pipe clamps are tight.
(Closed) Unresolved Item (85-19-02):
Inspection of Pipe Supports.
This un-resolved item identified cases in which lock washers were not flattened.
Ap-parently, further tightening of the nuts would have caused compression of the clamp ears, possibly damaging the clamp and restricting movement of the eye bolts.
In addition, procedures were not clear in how one should achieve flattened lock washers.
The inspector reviewed IP 7.3.1, " Fabrication and Installation of Pipe Sup-ports," dated March 31, 1986.
Step 7.5.lb of that procedure states, "when lock washers are used, verify washers are completely flattened." The inspec-tion questioned the licensee concerning alternative locking methods that can be used in cases where lock washers cannot be flattened without distorting clamps.
The licensee stated that mechanical contractor personnel have been trained on the requirements and conditions that warrant other locking methods.
The inspector randomly selected several supports to verify that lock washers were completely flattened, or other methods of nut locking were used.
The inspector found no discrepancies.
The inspector concluded that clarifying the inspection procedure in regard to tightening of lock washers and training contractor personnel on the re-quirements and conditions for using other locking methods should prevent nuts from loosenin.
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5.
Reactor Coolant System Cold Hydrostatic Test a.
Preparation:
During a pre-test walkdown of the RCC after system fill and vent, the inspector noted that one of the thr.
afety valve line blank flanges was not flush with the opening.
Tw(
- ats of about 2" in length were found between the flange and the seat % surface acting as a spacer with
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all flange bolts in place.
Initial diNussions with licensee personnel indicated that they were not aware of this temporary opening. The in-spector accompanied Quality Control personnel and observed the flange removal and a boroscope inspection of the safety valve line gooseneck
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to ensure that no loose parts had been introduced into the primary system.
None were found and the flange was reinstalled.
Subsequent discussions with the Station Superintendent indicated that test personnel conducting the fill and vent operation opted to use this additional vent path per instructions in their TOP.
However, they failed to use the administrative controls (Station Work Requests or Work Auth-orization Request) to perform this item.
The inspector was informed that this issue would be reviewed with all test personnel to stress the neces-sity of adhering to plant procedures.
The inspector had no further con-cerns at this time.
d b.
Test Conduct:
The inspectors observed the preparation and conduct of this test (PO-2.06.01) on April 19 thru 20, 1986, from both the Control Room and Con-tainment Building.
All test objectives specified in the FSAR test ab-stract (14.2.12.8.1) were met with the maximum test pressure of 3118 psig for 15 minutes (see NRC Region I Specialist Report 412/86-08 for detailed discussion).
The interface between the Test Director and Control Room Operations Staff was good. Various system evolutions were well controlled by use of approved preoperational test procedures and temporary operating procedures.
The inspector observed that necessary revisions were ob-l tained in accordance with the Startup Manual.
No test program deficien-cies were identified,
c.
Hardware Problems:
Throughout the course of the hydrostatic test, various equipment problems were identified by the Operations staff.
These included items such as RHR bypass flow control valves (butterfly) that were apparently installed backwards, a letdown orifice isolation valve installed without a valve disc, and the failure of an RHR pump suction valve interlock to prevent pump breaker closure.
Since this test was conducted prior to system turnover to the Station, the licensee's corrective action program was reviewed to ensure that the above items receive appropriate attention.
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The inspector met with the test engineer who had the detailed responsi-bility for performing Test Procedure P0-2.06.01.
The test engineer had
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compiled a comprehensive list of mechanical and electrical deficiencies, i
and formally transmitted them to the responsible systems test engineer in the DLC Construction Proof Test organization for corrective action.
The DLC Startup Manual (SUM) contains several procedures which define the necessary actions to correct deficiencies.
These procedures are
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contained in SUM Chapter 4.3, Startup Work Request, and SUM Chapter 7.2, Design Change and Rework Control.
If SUM Chapter 4.3 is used, the Startup Work Request (SWR) is the controlling document which defines the i-work description to be performed by the DLC Maintenance Group.
If SUM Chapter 7.2 is used, the Work Authorization Request (WAR) is the con-trolling document which defines the work description to be performed by the site mechanical or electrical contractor.
For either case, Quality Control (SQC or TQC) must sign the controlling document indicating their review of the work package to determine the necessity of assigning QC
holdpoints.
The key individual in the whole rework process is the DLC Construction Startup Group (CSUG) Systems Test Engineer, since he is the focal point for coordinating the work, tracking it to completion, and ensuring that any necessary retesting is performed.
The inspector met with the Systems Test Engineer responsible for the Chemical Volume and Control System to determine how he was handling the deficiencies identified in his area.
Eight control-type deficiencies had been identified in this system.
The inspector determined that the Systems Test Engineer was cognizant of each deficiency and that each was
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being addressed by either an existing or newly generated SWR or WAR.
The inspector sampled two of the deficiencies as follows:
- 2CHS*LCV115A - Indicating Lights Backward at Control Panel in
Control Room.
WAR 3884 was outstanding for the applicable electrical j
circuit.
The System Test Engineer indicated that he would follow this
corrective action and ensure that applicable retesting was performed.
- 2CHS*M0V2758 - Unable to Open Electrically from Control Room.
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Systems Test Engineer noted that he had opened this valve electrically
subsequent to the RCS hydrostatic test.
This was accomplished by de-pressing the reset button at the motor controller and then operating 2CHS*MOV2758. The Systems Test Engineer suspects an improperly set torque switch.
SWR 4510 was issued to investigate, repair and retest this valve.
The inspector also met with the Residual Heat Removal (RHR) System Test Engineer to discuss followup for the two major deficiencies identified for this system.
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- RHR Pump Vibration.
During the initial pump run, measured vibration was about 2 - 3 mils greater than the maximum level recommended by West-inghouse, the pump vendor.
This appears to be a generic problem ad-dressed by Westinghouse Technical Bulletin 86-02, Vertical Motor Resonant Vibration - RHR Pumps, dated March 26, 1986.
The System Test Engineer informed the inspector that the bulletin had been received on or about April 26, 1986, and that the recommended frequency and spectrum analysis would be performed for the system.
Review of these test results and any bracing or pipe support modifications required to change the natural frequency of the system (and subsequent impact on the seismic analysis resulting from any new loads) will be followed by the inspector during future inspections.
- RHR Flow Control Valves.
These valves exhibited poor flow control below about 2500 gpm.
The heat exchanger bypass flow control valve was disassembled and visually inspected. No seat was found in the valve.
A review of the design specifications indicated that none had been specified in the purchase order.
The Station Superintendent informed the inspector that though this condition is not expected to account for the inability to control flow below 2500 gpm, it is undesirable and would be corrected.
Since no other apparent problem was visible, the System Test Engineer informed the inspector that the system flow control valve, located downstream of the bypass line tie-in, would also be disassembled and inspected.
Final testing per the RHR preoperational test to demon-strate valve operability is yet to be complete.
Based on the procedure review and the sampling of the corrective actions of the identified deficiencies, the inspector concluded that the licensee's ex-isting procedures were adequate and that these procedures were being imple-mented to resolve problems identified during the RCS hydrostatic test.
6.
21C Reactor Coolant Pump Problems During the conduct of the hydrostatic test, system heat was provided with the A and B reactor coolant pumps as the licensee experienced difficulties with a test run of the C pump during RCS fill and vent.
Prior to this run, break-away torque was measured at between 75 to 100 ft.-lb.
After the run, Opera-tions personnel heard an unusual noise during coast down. Breakaway torque was subsequently measured at about 350 ft.-lbs.
After the hydrostatic test, the C pump was again bumped and vibration in excess of 40 mil was measused during the 25 second run.
During the week of April 28, 1986, the licentee drained the loops and a representative of the pump vendor (Westinghouse? per-formed a visual inspection of the pump internals.
Three 1/8" thick staihless steel metal plates were found, two of which were fused to the pump impelier.
Cloth wipe downs of RCS pipe found fine metal slivers from the stainless steel sheet metal, voiding past RCS cleanliness efforts.
The initial inspection conducted by the vendor's representative indicated that damage to the pump impellers appeared to be negligible.
The source of the stainless steel plates was identified as being part of the steam generator
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nozzle dam. This is a temporary structure that is bolted on the steam genera-tor cold leg nozzle line inside the channel head to prevent either loose parts or personnel from entering the cross over section of line that drops 7 feet
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prior to rising to the pump suction bowl.
Through discussions with plant management, the inspector was informed that close out inspection of the reactor coolant system to establish cleanliness requirements was completed on April 4, 1986.
At that time, a plywood cover was bolted to the steam generator manway as an access control. check point prior to installation of the 600 lb. cover.
This final installation was l
scheduled to be completed during the backshift that day, but was delayed after craft personnel were detailed to another job.
The permanent cover was re-installed the following Monday morning, on April 7, 1986, after QC personnel did a quick visual inspection of the steam generator water box, that did not include the cross over section of pipe.
Nothing unusual was observed and the permanent cover was installed.
From the above, it can only be surmised that the nozzle dam was introduced into the suction leg and the plywood cleanliness control cover was reinstalled sometime during the weekend of April 5, 1986.
The inspector was informed that the 21C RCP would be removed and inspected, that the core internals would be removed, the full flow filters inspected, and that various CVCS lines (such as letdown) would also be inspected to re-establish cleanliness requirements.and ensure that no metal shavings from the nozzle dam or other foreign material was present.
Review of licensee actions to re-establish the cleanliness requirement and conduct whatever flushing is necessary on the RCS and the CVCS along with corrective actions to prevent recurrence, will be tracked as Unresolved Item (86-07-01).
7.
Restoration and Review Activities a.
RCS System Restoration At the close of this inspection period, RCS system restoration including reinstallation of the pressurizer safety valves has been delayed due to the foreign material problem.
b.
RCS Hydrostatic Test Data Review and Acceptance The two test gauges used to document RCS primary pressure were calibrated 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to the test and rechecked satisfactorily after test con-duct.
A preliminary review of the test data was conducted by the JTG.
No problems were identified and final test acceptance is expected by the week of May 12, 1986, 8.
Charging Pump Proof Test The inspector observed performance of 2T-CHS-7-2.05, Initial Operation of Charging /High Head Safety Injection Pump 2CHS*P21B, on April 9, 1986.
Pump and motor data were measured by properly calibrated instruments.
Key para-meters such as vibration, lube oil system capabilities and discharge pressure were within the design values.
No concerns were identified.
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This system was subsequently used to support the hydrostatic test.
However, final turnover to the station for preoperational testing, has not yet occurred.
9.
Emergency Diesel Generators The No. 2 EDG field was flashed for the first time on April 10, 1986.
a.
Test personnel immediately shut the diesel down as sparks were observed coming from the generator.
A ferric bolt of the type used on the genera-tor screens was found in the housing.
The vendor's representative stated that an air gap inspection performed just prior to the diesel startup had failed to find any foreign parts.
Damage to the generator was mini-mal; pole faces had superficial damage that was dressed-up and the stator was reinsulated with a Dolph-Spray AC-29-7, as recommended by the vendor.
No windings were damaged.
The repairs were conducted under SWR 4037, which was witnessed by TQC.
Subsequent runs observed by the inspector identified no anomalies with the generator's performance.
b.
During proof-testing of the No. 2 EDG on April 21, 1986, one of the tur-bocharger oil pumps failed.
The test, which had reached the 75% loa 1 plateau, was terminated and a Station Work Request (SWR) initiated.
Upon disassembly of the Brown-Boveri Model VTR400 exhaust gas turbocharp.r, the pump shaft was found gouged.
No foreign material was present 1 the pump housing and the cause of failure was not apparent.
At this point in time, the EDGs have been turned over to the Construction Startup Group for the Phase I proof-test program.
Repair and maintenance activities come under the Testing Quality Control (TQC) Program.
The inspector noted that TQC had been properly notified of the pending tur-bocharger work via SWR 4041 and an inspector was at the job site follow-ing the repair activities.
Discussions with the TQC inspector indicated that he was aware of ongoing station discussions with the vendor to either modify or replace the oil pumps and that appropriate parts docu-mentation would be needed for whichever corrective action was decided upon. The inspector was subsequently informed that the lube oil pump was repaired.
10.
Quality Control Programs During Testing A previous inspector concern centered upon phase out of the construction site QC (SQC) program and phase-in of the Operations QC (0QC) program during startup testing. This follow item (85-16-05) was last reviewed and closed out in NRC Inspection Report 412/86-01.
Since that time, the QA Manager has added a QA Surveillance Group with a subordinate Test QC Department to support the Startup Test Program.
Discussions with the Deputy QA Manager, who heads the QA Surveillance Group, indicated that their Administrative Manual was due to be issued by the end of April, 1986.
This manual would provide the TQC program guidance.
The inspector noted that SQC, TQC and 0QC each have re-sponsibilities during startup that seems to overlap, and could lead to un-necessary confusion.
The QA Manager subsequently issued a policy statement to clearly define the division of responsibilities and authorities between
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the three QC groups that report to him.
This letter is being disseminated to QC personnel, startup test engineers and the Unit 2 Operations group.
This appears satisfactory and the inspector had no further concerns at this time.
11.
Exit Interview.
Meetings were held with senior facility managetant periodically during the course of this inspection to discuss the inspection scope and findings.
A summary of the findings was further discussed with the licensee at the con-clusion of the report period.