IR 05000387/1982032
| ML20069N803 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 11/03/1982 |
| From: | Chung J, Mccabe E, Mccann J, Rhoads G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20069N796 | List: |
| References | |
| 50-387-82-32, 50-388-82-05, NUDOCS 8212070158 | |
| Download: ML20069N803 (17) | |
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i U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
50-387/82-32 Rsport No. g0.199/a9.05
1 Docket No. 50-387 (RAT Ri; 50-388 (CAT A)
NPF-14 License No. CPPR-102 Priority Category l
Licensee:
Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 l
Facility Name: Susauehanna Steam Electric Station Inspection At: Salem Township, Pennsylvania l
l Inspection Conducted: September 8 - October 19, 1982 Inspectors:
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( o J 14 f1 L I
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I Gary GWRhoads date
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/ * / s, / s 1.
n F. McCann date
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. Z "Chung dati Approved y:
d-4. h d*4e se (3let Ebe C. McCabe, Chief, Reactor Projects date Section 28, DPRP Inspection Summary: September 8 - October 19,1982 (Combined Reports 50-387/82-32, 50-388/82-05).
Routine resident (171 hours0.00198 days <br />0.0475 hours <br />2.827381e-4 weeks <br />6.50655e-5 months <br /> Unit 1, 41 hours4.74537e-4 days <br />0.0114 hours <br />6.779101e-5 weeks <br />1.56005e-5 months <br /> Unit 2) and regional inspection (68 hours7.87037e-4 days <br />0.0189 hours <br />1.124339e-4 weeks <br />2.5874e-5 months <br /> Unit 1) of: Preoperational test results review; Startup Test results review; Startup test witnessing; Licensee event followup; Welding activities; Technical Specification Compliance, Open items and Plant status.
Two violations were identified pertaining to Unit 1; security violation pertaining to vehicles in pro-tected area, and licensee not meeting requirements for operable fire protection equipment.
One violation was identified pertaining to Unit 2; Improper storage of safety-grade pipe.
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Region I Form 12 (Rev. Februar/- 1982)
8F212070158 821123 DR ADOCK 05000
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DETAILS 1.
Persons Contacted Pennsylvania Power and Light Company R. Beckley, Resident NQA Engineer S. Denson, Project Construction Manager M. Detamore, Plant Engineering Supervisor A. Dominguez, Sr. Project Engineer F. Eisenhuth, Sr. Compliance Engineer R. Featenby, Assistant Project Director E. Figard, ISG Supervisor J. Green, Supervisor, Operations Quality Assurance M. Johnson, Record Control Group Supervisor H. Keiser, Superintendent of Plant G. Kuczynski, Electrical Maintenance Supervisor B. Lloyd, Mechanical Maintenance Supervisor R. Matthews, Sr. Analyst - NQA R. Sheranko, Startup & Test Field Engineer J. Zentz, Test Coordinator Bechtel Corporation G. Bell, Project QA Engineer N. Covington, Assistant ISG Supervisor H. Foster, San Francisco Home Office - QC G. Gelinas, Project Field QC Engineer A. Konjura, Lead Quality Assurance Engineer
, T. Minor, Prcject Field Engineer W. Mourer, Field Construction Manager
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l 2.
Licensee Action on Previous Inspection Findings (Closed) Inspector Followup Item (387/82-16-01) Correct LLRT Results a.
for 45 PSIG.
The correction factor was small, and only a small numoer of LLRT's were
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conducted below 45 psig, and the uncorrected value of total LLRT leak-age results were well below the acceptance criterion of 0.6 La.
The in-
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spector determined that the fir.al corrected results met the acceptance I
criterion.
This item is considered closed.
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(0 pen) Unresolved Item (387/82-16-02) Correct ILRT Results for CRD Headers Not Vented and Safety Analysis of CRD Line Breaks.
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During the ILRT, only one of the four non-seismic headers of CRD piping system, namely CRD charging header, was vented which resulted in liquid leakage of approximately 2.5 gpm.
The other three non-seismic headers (cooling water, drive water, and exhaust) were not vented during the
test due to an oversight.
The licensee had agreed to correct the ILRT results for CRD headers not vented and evaluate the matter for potential safety significance.
See Inspection Report 387/82-16, Paragraph 4.5 for details.
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After the ILRT, with containment at pressure, the renmining headers were
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lent to 0.006 wt. %/ day). vented and the liquid leakage increased by ap i
Licensee concluded that the venting of these remaining headers did not cause gross leakage and did not significantly affect ILRT results.
Report, May 1982, Section 3.5.4, for details.See Reactor Containment Build
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l However, the above report did not contain an evaluation of CRD line breaks for potential safety significance. Pendin i
is considered unresolved and remains open.g this evaluation, this item (Closed) Construction ~ Deficiency (388/81-00-35) Oversize Hole in Power c.
Head of Cooper Energy D/G.
This problem was reviewed during NRC inspection 387/82-03; 388/82-02 and closed for Unit 1.
The diesels are a common system and therefore this problem is also closed for Unit 2.
d.
(Closed? Construction Deficiency (388/82-00-03?' Inconsistencies in
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Vertica'
Dynamic Model for Reactor / Control Bui' ding.
This issue was closed during inspection 387/82-19 for Unit 1 only, but should have been closed for both Units, (Closed) Part 21 Report (388/82-88-01)~ Goldfish in Spray Pond May Plug e.
Heat Exchangers.
This item was closed for Unit 1 only during inspection 387/82-19 The spray pond is a comon system, therefore this item is closed for Unit 2.
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(Closed) IE Circular 78-17 (388/78-CI-17) Inadequate Guard Training /
Qualification and Falsified Training Records.
This item was closed for Unit I in NRC inspection 387/82-05.
Since the same licensee security force will be used for Unit 2. this item is also closed for Unit 2.
g.
(Closed) Unresolved Item (388/79-13-04) Procedures for Solid Waste Dis-posal.
This item is comon to Unit I and 2, and should have been closed for
i both units during inspection 388/80-18.
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3.
Plant Tours The inspector conducted periodic tours of accessible areas in the plant during normal and back-shift hours.
During these tours the inspector observed housekeeping and cleanliness controls, construc-tion work in progress, testing, maintenance, in-plant storage and protection of equipment, security measures, and proper equipment line-up.
On October 7, 1982 the inspector found inadequately protected piping material stored outside the back of the piping combination shop.
Bechtel Field Procedure FP-G-11, Revision 23, " Procedure for Storage, Protection, Maintenance and Lay-Up", paragraph 2.3, requires that specified caps, plugs or closures be kept in place on all piping and pipe fittings, and that stainless steel piping stored outside be covered with approved tarps with adequate air circulation. The in-spector found internally rusted carbon steel piping without protective caps or closures, and stainless piping which was uncapped and not covered with a tarp. Some of this piping was color-coded for safety related use.
This problem was immediately brought to the attention of the licensee for prompt correction.
On October 15, 1982, the inspector noted that the piping behind the piping combination shop was properly protected from the weather.
Failure to properly protect stored piping materials is a violation of the licensee's PSAR Appendix D pertaining to Unit 2. (388/82-05-01)
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4 Initial Start-Up Activities associated with initial startup were reviewed to ensure that Technical Specifications and other license conditions were met, that adminis-trative requirements and procedures were adequate and in use, and that test results were properly documented and evaluated.
Rod withdrawal began at about 9:06 P.M. on September 10, 1982 and criticality was achieved at 11:17 P.M. on September 10.
Conditions during the startup were as expected. At about 11:58 P.M. a reactor scram occurred when the operator inadvertently switched to a lower range of the Intermediate Range Monitoring System (IRM) while still above the upscale trip set-point for that range, The cause of the error was an incorrect indication on the video display of IRM level. The incorrect indication was later found to be a computer software problem. Conditions during the shutdown were as expected.
The startup activities were also reviewed by a region-based inspection team are reported in NRC Inspection Report No. 387/82-37.
Connissioner Visit
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Consnissioner Victor Gilinsky visited the site on September 13, 1982 to review plant readiness for operation.
The trip included a plant tour and discussions with the resident inspector and senior licensee management.
Principle areas of interest were TMI action plan items, operator training and experience, senior licensee management experience, current enforcement activities, control room characteristics, the Mark II Containment program, and emergency procedures and facilities.
Preoperational and Startup Test Exceptions, The inspector met with the Integrated Startup Group (ISG) Supervisor and his staff to discuss preoperational and acceptance test exceptions still outstanding.
With the exception of P100.1, Cold Functional Testing and A85.2, Freeze Protection, all other test exceptions were transferred to Plant Staff to be resolved. The remaining exceptions of P100.1 are in the pro-cess of being resolved by the modification and changes being made to the r
Emergency Service Water System, to eliminate the water hammer problem en-
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countered during operation and testing. A85.2 testing is now in progress for freeze protection requirements.
I The inspector discussed the exceptions to the following tests, with cogni-zant members of plant staff:
P34.1 RBHV A32.5 SCCHV P45.1 FW A39.1 CD P55.1 CRDH A41.1 CT P56.1A RMCS A65.2 RWBFW P79.2 STBVS A67.1 VLPM P79.2D OGT A69.2 LRWO P81.1 FHSE A76.2 PS P83.1A ADS /SR A85.1 CP A98.1 MGE l
A99.1 P A99.4 RMD
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Findings Disposition and resolution of exceptions to the list of completed tests is
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in progress and will be followed up by the inspector for final resolution and completion as part of the routine inspection program.
7.
Quality Assurance Audit of Test Program At the request of PP&L, Gilbert Associates Inc. performed a quality assurance review to determine that test comitments established in the FSAR were ade-
quately incorporated in the acceptance criteria for the preoperational l
testing of Unit I systems and components. The inspector reviewed the Gil-bert report and licensee response and noted the following:
a.
The reviewers encountered discrepancies between FSAR testing comit-ments and the specific preoperational test acceptance criteria.
Although the PP&L response verified that the testing was performed in either a component test or in the body of the preoperational test it was recomended that for Unit 2 the preoperational test acceptance criteria be expanded to better equate with FSAR comit-ments.
b.
In several cases Design Change Packages had been performed on sys-
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tems without making an appropriate change to the FSAR to reflect the Design Change Package.
This made FSAR testing requirements ou-dated.
It was recommended that an administrative system be imple-mented.to ensure that before a Design Change Package is closed out, any required FSAR changes are submitted, c.
Two specific instances of differences between FSAR test comitments and preoperational test acceptance criteria required resolution.
In one instance testing was performed to acceptance criteria dif-ferent from the FSAR. In the second instance preoperational test acceptance criteria addressing an implied FSAR test comitment were not included.
These differences were resolved and the required testing was completed, t
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Gilbert Associates determined that with the exception of the two
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instances noted above, and within the constraints of the scope of the Gilbert Associates review, the preoperational test acceptance criteria for SSES Unit I systems and components, and the explana-tions provided by PP&L, adequately addressed the implicit and ex-plicit test comitments contained in the FSAR through Revision 29 The inspector concluded that the Quality Assurance Review conducted by Gilbert Associates was adequate and had no further questions on their findings.
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8.
Safety Related Pipe Welding The ilupector observed the preparation and welding of two safety related pipe joints to determine if the following conditions were met:
The work was conducted in accordance with a weld data sheet, fcrm
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WR-6, and the appropriate QC sign-offs were completed.
The welding procedure specification assignment is in accordance
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with applicable ASME code requirements.
The base metals, welding filler materials and gases were of the
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specified type and were traceable to test reports or certifications.
The welders were currently qualified for the process and were
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identified on the weld data sheets.
Welding equipment including power cables and gas lines were in
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serviceable condition.
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Weld joint geometry was as specified and the surfaces to be welded
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have been prepared, cleaned and inspected.
fack welds were made by qualified welders and were ground out as
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required.
Pre-Heat and interpass temperatures were controlled as required.
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Interpass cleaning and grinding were properly perfonned.
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l The welds observed were Field WeM No. 14 on SP HCB209, a butt weld in a wetwell atmosphere sampling line, and Field Weld No. 35 on SP HCB205-1, a butt weld to the suction valve of the 'B' standby liquid control pump.
The inspector also examined welding material control at the disbursal points on the 719' elevation of the Unit 2 reactor building and in the piping combination shop to verify that:
Welding material was preperly heated and that the ovens were properly
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calibrated.
l Welding material was properly segregated.
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Welding material is only issued to properly qualified welders for
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the weld process.
No unacceptable conditions were identified.
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As a result of previous NRC inspector concerns about the experience of two Bechtei radiograph reviewers, PP&L Construction Quality Assurance re-examined 67 weld radiography packages (29 Unit 1, 38 Unit 2).
Three Unit 2 welds were determined to need further evaluation and are documented on Bechtel Non-Confonnance Report (NCR) 9692. As a result of these PP&L findings, Bechtel Management Corrective Action Request (MCTR) No.1'.-83 was issued to examine 10% of the weld radiocrophy packages reviewed by the individuals who's experience was questioned by the NRC inspector, and 20 weld packages from each of the other reviewers.
This sample consisted of 673 welds (267 Unit I and 406 Unit 2).
Seven welds were determined to need further evaluation. Three of these were for Unit 2 and are documented on Bechtel NCR No.'s 9776 and 9822.
The status of four Unit I welds identified as needing further evaluation is described below:
Weld Location Discussion DLA-101-1; FW5 Feedwater System This radiography package was missing; the weld was re-radiographed and found acceptable.
DLA 101-1; FW7 Feedwater System Linear indications were seen in a 1979 radiograph near the edges of the film. The weld was re-radiographed with the suspected area in the center of the film and no indications were
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seen. They were apparently slight
surface defects which were removed l
when preparing the weld for Ulta-sonic testing.
(PP&LNCRNo.212)
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DBB 102-1; FW10 Main Steam The reviewer felt the weld may be (Outside Isolation less than minimum required wall Valves)
thickness. This was documented on PP&L NCR No. 207.
It was found that the weld thickness was less than 87%
of the manufacturers minimum wall thickness, but well in excess of the design minimum wall thickness. Accep-tability of the weld for use as-is will be determined by the licensee after review of radiographs scheduled for October 21, 1982.
DBD 105-1; FW4 Startup flow con-A surface gouge was found and ground trol piping in out. This is documented in PP&L
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Main Feed (Not NCR No. 189.
ASMECodeWeld)
The inspector will continue to follow the resolution of Unit 2 weld questions identified in Bechtel NCR Nos. 9692, 9776, and 9822.
(388/82-05-02)
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9.
Fire Protection On October 12, 1982 the inspector noted an entry in the control room Limiting Conditions for Operations Log (LCO Log) dated October 10, 1982 which stated that certain fire detectors in Fire Zone 1-7A required by Technical Specification were not in the Fire Zone.
The inspector then questioned the Plant Fire Protection Engineer who stated that although the Technical Specifications required nine ionization detectors, and two photo-electric detectors in Zone 1-7A, it had been found during surveillance testing that there were actually thirteen ionization detectors and no photo-electric detectors.
The inspector then asked why this discrepancy had not been found during initial surveillance testing. The Fire Protection Engineer stated that pre-operational testing had been used as the basis for determining initial operability of the ionization and photo-electric detectors in lieu of the actual surveillance test. Apparently the discrepancy had been missed when reviewing the preoperational test for surveillance confirmation.
The inspector next reviewed surveillance data sheets for functional testing of the fire protection instrumentation.
The following problems were identi-fied:
Surveillance data sheets for functional testing of fire protection a.
heat detectors (SI-13-201) completed on July 24 and July 30 did not include testing of the heat detectors in Fire Zone 0-27E.
TheinspectorthenreviewedWorkAuthorization(WA)S28045com-pleted on July 30, 1982 which documented maintenance on the heat detector circuitry. Although the WA recommended functional testing of the heat detectors circuitry as part of the WA closecut, the licensee could not verify that the testing had been completed.
On October 15, the licensee delcared the heat detectors in Zone 0-27E inoperable, and performed appropriate surveillances, b.
On October 14, 1982 the licensee determined that Fire Zone 1-7B did not have any ionization detectors even though two were re-
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i quired by Technical Specifications.
The licensee commenced a fire watch of this area of the Reactor Building. The licensee had previously declared this zone operable by testing two ioniza-tion detectors which were actually located in Fire Zone 1-7A, not 1-7B.
On October 18, 1982 the inspector infonned the Superinten-dent of Plant that not having operable ionization detectors in Fire Zone 1-7B and not having documentation to show the heat detectors in Fire Zone 0-27E were operable was a violation of Technical Specification 3.3.7.9.
(387/82-32-04)
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On October 15, 1982 the licensee initiated a system walkdown to locate all fire protection detectors in the plant.
The following additional dis-crepancies were noted:
a.
Fire Zone 1-4B (TIP Room) has only one ionization detector, and three photo-electric detectors.
Technical Specification table 3.3.7.9-1 states that there are two ionization detectors and no photo-electric detectors in this zone.
The Technical Specifica-tion states that a minimum of one ionization detector in this area is required to be operable. The inspector verified that surveillance had been completed on the one ionization detector and that it was operable.
b.
The review determined that the Technical Specification table 3.3.
7.9-1 entries for Fire Zones 0-25A and 0-25E were reversed for heat detectors.
The table stated 26 heat detectors existed in Zone 0-25A and 20 in Zone 0-25E. Actually 26 detectors exist in 0-25E and 20 in 0-25A. The inspector confirmed that the minimum required heat detectors were operable in both zones.
c.
Many areas of the plant were determined to have more detectors than stated in Technical Specifications.
The inspector discussed these discrepancies with the Assistant Superin-tendent of Plant on October 18, 1982.
The inspector stated that the dis-crepancies with the Technical Specifications should be reconciled. The licensee's actions will be reviewed during a subsequent NRC inspection.
(387/82-32-05)
10.
RPS Cable On October 6,1982 the Assistant Superintendent of Plant informed the Resident Ins System (RPS)pectors that the licensee had discovered Reactor Protection l
l cabling which was not properly grounded in the upper and lower relay rooms.
He stated that the licensee intended to ground the cables during the present outage. This item had been previously considered closed by the licensee as documented in NRC Inspecticn Report 387/82-19, based on
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documentation of properly grounded cabling in Quality Control Inspection Reports (QCIR) NSSS-25676 and NSSS-25675.
During subsequent licensee inspections of the RPS panels it was noted that although ground wires were connected to the flexible conduit of certain RPS cables, they were not connected to a grounding bus bar.
On October 13 1982 the Resident In-spector discussed the QCIR with the responsible Bechtel Quality Control (QC)
Inspector, who could offer no explanation for the discrepancy. The in-spector then discussed this issue with the licensee's Nuclear Quality Assurance Manager, and Resident Quality Assurance Er.gineer stating that this discrepancy in conjunction with other recent Quality Control inade-quacies in the small and large pipe hanger program indicated a need for increased licensee attention in this area.
Licensee actions will be re-viewed during a subsequent NRC inspection.
(387/82-32-06)
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Additionally the licensee determined that a revision to the General Electric Field Deviation Disposition Report (FDDR)-607 (Revision 4), which was issued to the licensee in August, 1982, ir.ficating additional RPS cables to be grounded had not been completed, but was also scheduled for this outage.
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OnAugust13,thelicenseedirectedtheNuclearSafetyAssessmentGroup(NSAG)
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to investigate the sequence of events on the modification to ground the RPS cable and to determine why the modification had not been properly completed even though it was a license condition to do so. The licensee also performed a 100% re-inspection of RPS cabling to assure that all RPS cables were
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properly grounded on October 16 and 17, and identified four additional cables wMch were not grounded. The NSAG report and licensee corrective actions will be reviewed by the NRC during a subsequent inspection.
(387/82-32-07)
11.
Fire in'ESW Pumphouse On September 22 at 9:35 a.m. the licensee declared an Alert Condition in t
accordance with their Emergency Plan when an electrical fire broke out in electrical panel 08-517 in the Emergency Service Water System (ESW) Pump-house. The Resident Inspector observed licensee actions in the Control
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Room and the Technical Support Center from the time the licensee made the Emergency Notification System (ENS) call to the NRC until the Alert was
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l downgraded.
The event was terminated at 10:35 a.m.
The fire rendered in-
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operable the RHR servicewater bypass valve for the A loop which also made
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automatic initiation of the ESW system inoperable. The event was started when a Bechtel electrician dropped a ground cable across one phase of the incoming power to panel 0B-517, and resulted in the melting of bus bars in the panel.
The fire was put out by opening the supply breaker to the par.el and spraying the panel with dry chemical fire extinguisher. The licensee has determined that the electrical distribution system worked as designed and is investigating to determine if the fire protection system was adequate.
The licensee completed restoring the electrical panel on September 23, 1982 Two Region I inspectors investigated the event on September 23 and 24. No
unacceptable conditions were noted. A review of the licensee's investiga-tion of fire p(387/82-32-08)quacy will be reviewed during a subsequent NRC rotection ade inspection.
On September 27, 1982 the inspector discussed the event with the on-duty Luzerne County Civil Defense Supervisor. The Supervisor stated that com-munications of the incident with the licensee were ) roper and adequate and that no serious communications problem occurred wit 1 local community comunica-
, tions. No unacceptable conditions were noted.
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12.
Heatup Phase Low Power Tests The inspector reviewed test results and licensee evaluation of tests to verify that:
Tests were conducted in accordance with Administrative Control
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Procedures;
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Test changes were identified and implemented without changing the
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basic objectives of the test in accordance with station procedures and Technical Specifications (TS);
Test deficiencies and exceptions were identified, documented and
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reviewed;
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Deficiencies and exceptions were resolved, and retest requirements
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had been coripleted; Verification steps and data sheets of "As-Run" test procedures were
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properly initialed and dated;
"As-Run" data were recorded, where required, within acceptance
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tolerances, and met acceptance criteria; Cognizant engineer evaluated test results and;
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Review of tests results were properly documented,
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a.
Low Power Average Range Monitor (APRM) Calibration Low power APRM calibration was performed on September 18, 1982, using procedure ST12.1, Revision 0, March 29, 1982,
APRM adjustment factors were calibrated against Core Thermal Power (CTP), which was calculated from the core enthalpy balances.
The inspector verified that the adjusted final APRM readings were above zero and less than 0.5% power for all six channels, within tolerance for the heat balance of CTP of 0.573% (18.88 MWT).
No unacceptable conditions were identified.
b.
Selected Control Rod Drive (CRD) Scram Time Test The inspector reviewed scram time test data and selected re-corder traces performed September 8, 1982. The test was con-ducted using procedure ST5.5 for selected B-2 sequence rods at 1,0% rated power, and the reactor pressure and core flow
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were 920 psig and 33.28 x106 lbm/hr. respectively.
The inspector verified that the test results were all within acceptance criteria, and no unacceptable conditions were identified.
c.
Main Steam' Isolation Valve (MSIV)
Procedure ST25.1, Revision 1, was used to perform MSIV closure time tests on September 21 - 23, 1982.
The procedure requires that the time delay between the closure initiation signal and the extrapolated initial valve movement from 100% open position is equal to or less than 0.5 seconds. However, Appendix 25.1-A data sheet indicated that the delay time of MSIV IF0288 was 0.522 seconds, exceeding the acceptance criterion.
Yet, "As-Run" procedural step 25.1.4.6 was signed off, indicating that all delay time measurements were within the acceptance criteria.
No test exception report (TER) was issued.
The inspector expressed concern regarding this irregularity in data review.
During subsequent discussion, the licensee acknowledged the concern, and TER No. 086 was issued on October 6, 1982 to repeat the delay time test.
No unacceptable con-ditions were identified, d.
Plateau 2' Review The inspector attended a portion of integrated technical review meeting for plateau 2, held on October 7,1982. The following Startup Test Change Notices (STCN) and TER's were reviewed:
-- TCN Nos. 83, 84, and 118.
-- TER Nos. 30, 37, 43, 49, 56, 57, 71, 75-80, 86, and 119.
No unacceptable conditions were identified.
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13.
Licensee Events a.
Manual Scram on Loss of Control Rod Drive Pumps At about 9:05 a.m. on September 16, 1982, the operators manually
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scramed the Unit I reactor from less than 1% power during startup testing because both control rod drive (CRD) hydraulic supply pumps had tripped on low suction pressure. Conditions on the scram here normal. The cause of the low suction pressure trip of the CRD pumps was laer determined to be cycling of a flow control valve in the condensate return line because of the relatively low condensate re-turn flow. The CRD hydraulic pumps take a suction from this line.
The problem was corrected by closing the valve at very low power operation.
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b.
Inadequate Pipe Support in Residual Heat Removal System On October 6 the licensee reported a potentially defective pipe sup-
port in the RHR systern. Because of concerns generated during the independent design review requested by NRR, the licensee re-examined 20 additional pipe supports and found 19 satisfactory.
The other, an anchor for a 6 inch Residual Heat Removal System line, tras found to have an inadequate weld (about one-third the specified length).
The licensee initially concluded that this support would be over-stressed by a factor of 4 under design conditions, that failure of the support would overstress a containment penetration, and that further pipe support adequacy assessment is needed before power i
operation above 5 percent is undertaken.
The operating license limit is 5 percent until the NRC Commissioners approve higher power opera-t (
tion. At the licensee's request, further NRC Comissioner considera-
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tion of that authorization has been postponed.
The licensee will review an additional 300 as-built hanger design reconciliations to determine if inadequate engineering judgement was applied by Bechtel in accepting as-built conditions.
Further detailed analysis by'Bechtel of the particular RHR anchor involved indicates that the as-built condition may have been accep-table, however such a determination would require more documentation
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than was originally provided.
The licensee increased the length I
of the weld to ensure that the support would not be overstressed.
c.
Low Water Level Scram On September 20, 1982 the reactor tripped from four percent power on l
low reactor water level.
The cause of the low level was due to the I
one operating feed pump ("C") tripping on low suction pressure. The low feed water suction pressure was caused by the on-service condensate demineralizer being isolated. A plant operator had just previously i
taken a demineralizer out-of-service, and put a new demineralizer on-l
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service when the event occurred.
Before the operators could get a i
reactor feed pump back on line the water level reached the scram set
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point (level 3).
No ECCS systems were challenged.
On October 4, X
the inspector reviewed circuitry drawings with the Plant Engineer responsible for detemining why the demineralizer isolation valves
had closed. The licensee had not concluded whether a logic problem
existed in the condensate demineralizer isolation valves circuitry.
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The licensee's followup action to this trip will be reviewed during a subsequent inspection.
(387/82-32-09)
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l 14.
HPCI Lube Oil Modification The inspector reviewed the modification package for HPCI turbine lube oil piping changes completed on August 17, 1982.
The HPCI auxiliary oil pucip (AOP). suction line was originally installed with 1 " pipe, which did not meet the design limit of the AOP suction vacuum.
This was identified in Field Deviation Disposition Request (FDDR) KR1-213-0, July 10, 1980, and a subsequent FDDR Work Authorization was issued on August 11, 1982.
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However, a non-Q listed 2" pipe was temporarily installed to replace the 1 " piping, as documented on Nonconformance Report 82-820.
A Work Authorization WA #5-25161 was issued on July 16, 1982, one day be-
fore the issuance of the Operating License (OL), to replace the non-Q listed piping with Q-listed, schedule #80, 2" pipe.
The inspector further noted that the change Committee (PORC) package was neither reviewed by the Plant Operations Review
, immediately following plant turnover, nor subjected to l
the 10CFR50.59 review procedure. The work was completed on August 17, 1982.
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The inspector detemined that the engineering decision for the disposition of the NCR was performed prior to issuance of the Operating License and was therefore not subject to 10CFREO.59 requirements for the NCR. The inspector had a generic concern on PORC review of dispositions of NCR's which result in modifications to the plant.
Nuclear Department Instruction (NDI)-QA-8.1.4 Revision 0, titled "Non-Conformance Control and Processing" discusses disposition requirements of NCR items, but does not require the disposition to be reviewed by PORC.
The Operations Quality Assurance Super-
,
l visor stated that NCR's would be carefully screened to assure that the Technical Specification requirements were being met, and that any necessary
'
I changes to NDI-QA-8.1.4 would be completed by March 1, 1983. This item will I
be reviewed during a subsequent NRC inspection.
(387/82-32-03)
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16.
Exit Interviews During the course of this inspection, meetings were held with facility
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management to discuss the inspection and findings identified. Those personnel attending these meetings are indicated in Section 1 of this re-port, t
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