IR 05000454/1987002
| ML20211M268 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 02/18/1987 |
| From: | Forney W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20211M194 | List: |
| References | |
| RTR-NUREG-0737 50-454-87-02, 50-455-87-02, NUDOCS 8702270246 | |
| Download: ML20211M268 (19) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-454/87002(DRP); 50-455/87002(DRP)
Docket Nos. 50-454; 50-455 License Nos..NPF-37; NPF-60
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Licensee: Commonwealth Edison Company Post Office Box 767 Chicago, IL 60690 Facility Name: Byron Station, Units 1 and 2 Inspection At: Byron Station, Byron, Illinois Inspection Conducted: January 1 - 29, 1987 Inspectors:
J. M. Hinds, Jr.
P. G. Brochman J. A. Malloy W. J. Kropp D. E. Jones Approved By:
Nrn k
Wi/// 7 Reactor Projects Section IA Date Inspection Summary Inspection on January 1 - 29, 1987 (Reports No. 50-454/87002(DRP);
50-455/87002(DRP)I)
Areas Inspected:
Routine, unannounced safety inspection by the resident inspectors and a region based inspector of licensee action on previous inspection findings; 50.55(e) reports; LERs; operations sumary; NUREG-0737 items; Unit 2 license conditions; training; preparation for refueling; surveillance; maintenance; operational safety; startup testing; initial criticality witnessing; event followup; commissioner's to,ur; and management meetings. Unit 2 achieved initial criticality at 0638 on January 9,1987.
Results: Of the 13 areas inspected, no violations or deviations were identified in 12 areas; two violations were identi.fied in the remaining area:
(failure to restore a radiation monitor to an operable status following maintenance - Paragraph 4.c; failure to properly set the blowdown ring of a Component Cooling safety valve - Paragraph 4.e). Additionally, two violations were also identified in the same area; however, in accordance with 10 CFR 2, Appendix C, Section V.A, a Notice of Violation was not issued (failure to perform post-maintenance testing - Paragraphs 4.a and 4.b).
The first two violations were of more than minor safety significance anu involved the physical inoperability of plant equipment. The second two violations were of minor safety significance.
G702270246 870210 PDR ADOCK 05000454
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DETAILS 1.
Persons Contacted Commonwealth Edison Company
- T. Maiman, Vice President, Manager of Projects
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- L. DelGeorge, Assistant Vice President, Engineering and Licensing
- W. Shewski, Manager, Quality Assurance
- R. Querio, Station Manager
- D.-Farrar, Director of Nuclear Licensing
- K. Hansing, Director of Quality Assurance
- R. Tuetken, Assistant Project Manager
- R. Pleniewicz, Production Superintendent R. Ward, Services Superintendent W. Burkamper, Quality Assurance Superintendent
- E. Martin, Site Quality Assurance Superintendent
- K. Ainger, Nuclear Licensing Administrator
- L. Sues, Assistant Superintendent, Operating G. Schwartz, Assistant Superintendent, Maintenance T. Joyce, Assistant Superintendent, Technical Services D. St. Clair, Assistant Superintendent, Work Planning
- R. Klinger, Project Quality Control Supervisor W. Blythe, Operating Engineer, Unit 0 J. Schrock, Operating Engineer, Unit 1 D. Brindle, Operating Engineer, Unit 2 A. Chernick, Operating Engineer, Rad-Waste M. Snow, Regulatory Assurance Supervisor F. Hornbeak, Technical Staff Supervisor R. Flahive, Radiation / Chemistry Supervisor P. O'Neil, Quality Control Supervisor
- E. Zittle, Regulatory Assurance Staff
- S. Trubatch, Staff Attorney
- A. Britton, Quality Assurance Inspector
- D. Berg, Nuclear Safety
- C. Smith, Regulatory Assurance The inspector also contacted and interviewed other licensee and contractor personnel during the course of this inspection.
- Denotes those present during the management meeting on January 7, 1987.
- Denotes those present during the exit interview on January 29, 1987.
2.
Action on Previous Inspection Findings (92701 & 92702)
a.
(Closed) Violation 455/85027-02(DRS)):
Deficiencies in vendor supplied components. During the Construction Appraisal Team's (CAT)
review of vendor supplied items, four deficiencies were identified:
(A) radiographic film for two components was not readily retrievable
.from a vendor, off-site, storage facility; (B) welds on six components were not of the size specified in the design drawings;
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(C) Some vendor radiographs did not have adequate weld quality nor complete weld coverage; and (D) vendor supplied fasteners did not meet the material specifications of the design documents and drawings.
Items A, B, and D were reviewed and closed in Inspection Report 455/86038(DRS).
Item C was withdrawn in Inspection Report 455/86016(DRP). Therefore, based on the responses reviewed in Inspection Report 455/86038 this violation is considered closed.
b.
(Closed) Open Item (455/86040-01(DRP)):
Inadequate labeling of the SPDS wide and narrow range iconic displays. An audit of the-licensee's SPDS (Safety Parameter Display System) was performed by NRR in September of 1985 and the results transmitted in a letter from B. J. Youngblood to D. L. Farrar, dated October 30, 1985.
Three discrepancies were identified. The second and. third discrepancies were corrected by the licensee and reviewed in Inspection Report 455/86040(DRP). The first discrepancy involved the clear identification of which SPDS iconic display, wide-range or narrow-range, was being shown on the control room TV monitors.
The licensee has added labels to the display and the inspector reviewed the displays and verified that they are clearly identifi-able.
Based on this review the inspector has no further concerns related to this matter, and this item is considered closed.
c.
(0 pen) Violation (454/86040-03(DRP)):
Failure to properly store a safety related component to prevent damage or deterioration. The inspector identified to the licensee that safety related, Class 1-E, battery charger IAF01EA-1 was not stored in an approved location nor was it stored in a manner to prevent damage or deterioration, but was being stored in a contractor eating area.
The licensee removed the battery charger and inspected it for. damage. No visible damage was identified. The battery charger was relocated to its intended location. As corrective action the involved contractor supervisors were retrained to return equipment to its proper storage area if it could not be installed. The inspector verified that the battery charger was installed in its proper location and appears to be free of visible damage. This item will remain open pending the
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inspector's review of the performance testing to be completed on the battery charger as part of the post-modification testing for modification M6-1-85-0060.
d.
(Closed) Violation (454/86040-04(DRP)): Failure to update critical Control Room drawings and failure to perform post-modification testing following installation of a modification to the Auxiliary Feedwater (AF) system.
During a walkdown of the AF system the inspector identified that a modification had been made to the AF system and the system drawing P&ID M-37, which is a critical Control Room drawing, had not been updated to reflect the installation of two new valves. Additionally, the required post-modification testing, a VT-2 visual examination, had not been performed after the new valves and piping were installed. As corrective action for this event the licensee has: updated P&ID M-37 to reflect the as-bult condition of the plant, performed a satisfactory VT-2 examination
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upon the new piping and valves, and revised administrative procedures to ensure that critical drawings are updated prior to performing the post-maintenance test and to ensure that post-maintenance testing is completed prior to returning a system to service. The inspector has reviewed the corrective actions taken and verified they have been implemented. Based on this review the inspector has no further concerns related to this matter, and this item is considered closed.
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3.
10 CFR 50.55(e) Report Followup (92700)
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(Closed)50.55(e) Report (455/85003-EE(DRP)): High Energy Line Break (HELB) concerns in the Auxiliary Building. On May 16, 1985 the licensee notified Region III of a reportable deficiency related to adverse environmental affects of a Steam Generator (SG) blowdown or Auxiliary Steam (AS) pipe break in the Auxiliary Building, which could be classified as a HELB. The licensee submitted a final report of the corrective actions in a letter from A. D. Miosi to J. G. Keppler, dated June 14, 1985. The licensee stated that a temperature monitoring system would be installed at selected locations in the Auxiliary Building.
Receipt of a high temperature alarm would be annunciated in the control room and would cause the automatic actuation isolation valves in the SD and AS systems. There is a SD system for each Unit; however, the AS system is a shared, comon, system. The inspector reviewed the installation and testing of the temperature monitors and automatic isolation valves for the AS system in Inspection Report 454/86018.
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The inspector reviewed the test procedure which tested the Unit 2 SD i
temperature monitors and automatic isolation valves, Component j
Demonstration 2.71.71, Sections 9.18 and 9.19.
Based on this review
the inspector has no further concerns related to this matter, and this item is considered closed.
No violations or deviations were identified.
4.
Licensee Event Report (LER) Followup (92700)
(Closed) LERs (454/86031-LL; 454/86033-LL; 454/86034-LL; 454/86035-LL; 455/86001-LL): Through direct observation, discussions with licensee personnel, and review of records the following LERs were reviewed to determine that the reportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with Technical Specifications.
LER No.
Ti tle Unit 1 454/86031 Failure to Perform ASME Testing on Essential Service Water Strainers
~454/86033 Failure to Perform ASME Testing after Maintenance was Completed on Multiple Components s
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454/86034 Technical Specification Action Statement Exceeded for Control Room Ventilation Monitor 454/86035
.Non-Seismically Qualified Components Installed in 1A, IB, 2A, and 28 Diesel Generator Control Circuits Unit 2
- 455/86001 Loss of Both Trains of Component Cooling Water due to an Improperly Set Safety Valve a.
With regard to LER 454/86031, this LER describes events which occurred from December 21, 1985 to November 21, 1986, while in l
Modes 1, 2, 3, and 4.
On November 21, 1986, the licensee identified that a required post-maintenance visual examination had not been performed following maintenance on Essential Service Water (SX) Strainer ISX01FA which was completed on July 21, 1986.
Technical Specification 4.0.5.a requires that the surveillance requirements for inservice inspection of ASME (American Society of Mechanical Engineers) Code Class 3 components be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda. The licensee has connitted to the 1980 edition of the Code and Winter 1981 Addenda.
Code Section XI, Subsection IWA-5200 requires that a VT-2 visual examination be performed on repaired Class 3 components prior to their return to service. The VT-2 examination is performed to check for leakage at mechanical joints. Essential Service Water System strainer ISX01FA is an ASME Code Class 3 component.
Technical Specification 4.0.3 requires that surveillances be performed within a required interval or else the component is rot operable. Technical Specification 3.7.4 requires two SX systems to be operable in Modes 1, 2, 3, and 4.
With one system inoperable, restore the system to operability within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in Mode 3
[ Hot Standby] within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 [ Cold Shutdown]
within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
Since the required surveillance, a VT-2 visual examination, had not been performed, strainer 1SX01FA was inoperable. With ISX01FA l
inoperable the A system of SX was also inoperable, while in Modes 1, 2,
3, and 4, for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, from July 21 to December 21,
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1986, and the unit was not placed in Mode 5 within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. The failure to perform the required VT-2 surveillance test s
following maintenance on strainer ISX01FA and the failure to place the unit in Mode 5 with the A SX system inoperable is a violation of
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Technical Specifications 4.0.5.a and 3.7.4 (454/87002-01a(DRP)).
A review of records by the licensee indicated that a VT-2 visual
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following repairs on December 21, 1985. Consequently, ISX01FB was inoperable from December 21, 1985 to December 21, 1986. The failure to perform the required VT-2 surveillance test following i
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maintenance on strainer ISX01FB and the failure to place the unit in Mode 5 with the A SX system inoperable is a violation of Technical Specifications 4.0.5.a and 3.7.4 (454/87002-01b(DRP)).
Technical Specification 3.0.3 requires that when a Limiting Condition for Operation is not met, except as provided in the associated action statement, then action must be taken within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place the unit in Mode 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; in Mode 4 [ Hot Shutdown] within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; and in Mode 5 within the subsequent 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Consequently, with both strainers 1SX01FA and ISX01FB inoperable and consequently both the A and B SX systems inoperable, the action statement for Technical Specification 3.7.4 could not be met. Therefore the requirements of Technical Specification 3.0.3 were applicable. With both SX systems inoperable for greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> (5 months) action was not taken to place the unit in Mode 5 within the next 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
The failure to place the unit in Mode 5 within the required time limit is a violation of Technical Specification 3.0.3 (454/87002-01c(DRP)).
The licensee's investigation determined that the cause of this event was personnel errors by licensed and nonlicensed personnel and that post-maintenance testing requirements were not identified on the work request for strainer 1SX01F8. However, the post-maintenance testing requirements for strainer ISX01FA were listed on the work request, but were not performd. When the VT-2 visual tests were performed, no indications of feakage were identified. Nonlicensed operators routinely, once per 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shift, toured the strainer areas during this time period and would have identified any leakage.
As corrective action the licensee has revised administrative procedures to require that the Quality Control department independently review the work request to verify that inservice testing and inspection requirements have been identified for ASME Code Class 1, 2, or 3 components. Additional reviews and signatures have been added to the post-maintenance checklist, BAP 1600-T1, to increase the involvement of the Maintenance departmer.t in identifying work on ASME components, Quality Control department independent review and concurrence, and an Operating department final review. The licensee also performed a random sample of l
completed work requests and a review of all in progress work requests to identify any similar problems. No problems were identified. This violation meets the tests of 10 CFR 2, Appendix
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C,Section V.A; consequently, no Notice of Violation will be issued, and this matter is considered closed, i
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b.
With regard to LER 454/86033, this LER describes events from l
October 31, 1984 to December 9, 1986, while Unit I was in Modes l
1 through 6 and from November 6 to December 9,1986, while Unit i
2 was in Modes 5 and 6.
On December 9, 1986 the licensee's Project Construction Department (PCD) and station Technical Staff identified that required post-maintenance testing had not been l
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performed on~certain ASME (American Society of Mechanical Engineers)
B&PV (Boiler and Pressure-Vessel) Code Class 1, 2, and 3 components following the repair or replacement of these components. When-work was performed.on ASME code components by contractor personnel a Repair / Replacement Report (RRR) was generated. A review of-records indicated that a' total of 315 RRRs did not-indicate final disposition. Of the 315 RRRs, 18 were for Unit 1 or Unit common
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components, the other 297'RRRs were for Unit 2 Components.
Technical Specification 4.0.5.a requires that the surveillance requirements for inservice inspection-of ASME Code Class 1, 2, and -
3 components be performed in accordance with Section XI of the ASME Code and applicable Addenda. The licensee has committed to the 1980 edition of the Code and Winter 1981 Addenda. Code Section XI, Division 1, Subsection IWA-5200 requires that a VT-2 visual-examination be performed on repaired Class 1, 2, and 3 components i
prior to their return to service. The VT-2 examination is-performed to check for leakage, while the component is at system pressure.
The licensee reviewed the 315 RRRs to determine if the required testing had been performed for some other reason, i.e., as part of nonnally scheduled surveillance, following maintenance which was performed subsequent to the original RRR, or the work documented by the RRR had yet to be performed.
If the required testing had not been performed, either the test was accomplished or the equipment was taken out-of-service and the appropriate Limiting Condition for Operation (LCO) was entered. For some equipment in Unit 2 the testing was deferred until the necessary plant conditions could be established.
All the components were tested satisfactorily; therefore, all components were capable of performing their design function if they i
l had been called upon to do so. The cause of the problem was a
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communication error between PCD and the Technical Staff to identify when the work described on the RRRs was completed. The licensee is no longer-using the RRRs. Contractors now use the licensee's standard Nuclear. Work Request (NWR). The NWR form and the procedures controlling it have provision for performance of the required tests.
The failure to perform a VT-2 test on ASME B&PV Code Class 1, 2, and 3 components following repair or replacement is a violation of Technical Specification 4.0.5.a (454/87002-02(DRP);
f 455/87002-01(DRP)). This violation meets the tests of 10 CFR 2,
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Appendix C,Section V.A; consequently, no Notice of Violation (
will be issued, and this matter is considered closed.
I c.
With regards to LER 454/86034, this LER describes an event from December 12 - 15, 1986, with Unit 1 in Mode 1 and Unit 2 in Mode 3, r
l when Main Control Room Outside Air Intake Process Radiation Monitor OPR034J was inoperable and the required Technical Specification Action Statement was not followed.
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. To resolve problems with spurious actuations of Main Control Room Process Radiation Monitors OPR031J - OPR034J the licensee installed a modification to the equipment. This modification consisted, in part. of relocating and relabeling two leads on' terminal board 1 of the radiation monitors. The leads labeled 11 and 12 were relocated to positions 5 and 6 on terminal board 1, and relabeled as 5 and 6.
Procedures were modified to reflect this change to the equipment.
One of the changed procedures was BIS 3.3.1-203, "18 month surveillance calibration for radiation monitors 0PR031J - OPR034J."
On November 3,1986, electrical. noise problems were identified on
. monitor OPR034J. To correct the' problem the leads on positions 5
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and 6, labeled as 5 and 6, were relocated to their original positions of 11 and 12 on terminal board 1.
Highly visible tags were hung on the leads identifying them as a temperature alteration.
.On December 12, 1986, the detector for radiation monitor OPR034J was found to be' defective and was replaced. The calibration procedure BIS 3.3.1-203 required that the leads on. terminals-11.and 12 be-lifted. They were lifted in accordance with the procedure and the detector was calibrated.
The restoration of the monitor was turned over to the next shift.
During the restoration the instrument mechanic (IM) saw the labels on lifted leads (5 and 6) and landed the leads on terminal board 1 positions 5 and 6, rather than positions 11 and 12, which were required by the procedure. An independent verification was then performed which failed to identify this error. An operability check was performed on the' detector and passed and the monitor was declared operable at 1700 on December 12, 1986. Though the detector was operable the monitor was inoperable because its safeguard feature was defeated by the wiring error. At approximately 1600 on December 15, the system engineer was inspecting the circuitry for OPR034J for an unrelated problem when the wiring error was identified. The wires were landed in their correct position by 1615 and the monitor was declared operable. Consequently, monitor OPR034J was inoperable for approximately 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Technical Specification 3.3.3.1 requires that Main Control Room Isolation - Outside Air Intake - Gaseous Radioactivity High -
Monitor OPR034J be operable at all times or else follow' Action Statement 27. Action Statement 27 requires that with OPR034J inoperable, within one hour isolate Control Room Ventilation System OB and initiate operation of the Control Room Make-up System.
The failure to isolate Control Room Ventilation System OB and initiate operation of the Control Room Make-up System within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> with monitor OPR034J inoperable is a violation of Technical Specification 3.3.3.1(454/87002-03(DRP);455/87002-02(DRP)).
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As corrective action licensee management counseled the two IMs involved in this matter and discussed this event with the entire IM department. The NRC are concerned with the failure of the'
Independent Verification program to identify this mistake. This concern was discussed by the inspectors with licensee management at the exit interview. A memo was issued to Station personnel, reiterating the purpose and methods of the independent verification.
Had the error not been found by the system engineer, it would have-been discovered on December 22 during the next routine monthly-surveillance.
No actual high radiation signals occurred during this time period. Based on the corrective actions taken by the licensee the inspector has no further concerns regarding this matter and this item is considered closed; consequently, no reply to this
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violation is required.
d.
With regard to LER 454/86035, this LER describes an event on December 17, 1986, with Unit 1 in Mode 1 and Unit 2 in Mode 3, when it was discovered that non-seismically qualified parts were installed in the Emergency Diesel Generators (DG) for Units 1 and 2.
On December 12, 1986, the Byron Architect-Engineer (AE), Sargent and Lundy, identified two components which were not on the qualified parts list for the DGs. One component was a microswitch which sensed the position of the DG airbox damper. The other component was a pressure switch'which sensed governor air pressure. Both of these devices, when actuated, would energize two relays-12X1 and I?.X2. The energizing of either of these relays would open contacts which would deenergize the emergency run relays and the diesel would stop. These electrical trips are redundant electrical trips to the DG mechanical trips, tripping the airbox and tripping the fuel racks.
All but two of the DG protective trips are bypassed when the DG starts on loss-of-ESF Bus voltage coincident with a Safety Injection.
In a seismic event these two non-seismically qualified devices, three actual components, in two trains, in a seismic event could actuate. The actuation of these devices would prevent the DG from starting or cause it to stop, even if a valid emergency start signal was present. The AE sent this information to the DG vendor, Cooper Industries, Energy Services Group. After reviewing e
this information, on December 17, 1986, the veador informed NRC Headquarters that they intended to submit a 10 CFR Part 21 report on this deficiency.
At approximately 1530 on December 17, 1986, the NRC Resident Inspector's Office was notified by NRC Headquarters that the DG vendor, had identified a problem with the seismic qualifications of three devices in the DG control circuit. The Resident Inspectors transmitted this information to the licensee. The licensee established that all four DGs at Byron,1A,1B, 2A,.and 2B, were affected, but that the licensee's information was insufficient to determine if the DGs were inoperable in accordance with Technical Specification 3.8.1.1.
With both DGs in a unit inoperable,,
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Technical Specification 3.8.1.1.e requires that at least one of the inoperable diesels be restored to an operable status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, or else be Hot Standby [ Mode 3] within the 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Cold Shutdown [ Mode 5] in the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Station management requested the assistance of licensee's corporate engineering department, the AE, and the DG vendor in determining if the DGs were in fact inoperable.
In parallel with those efforts the licensee commenced work to install jumpers in the DG control circuits to defeat these devices.
By 1944 on December 17, the licensee had completed the installation and required testing on the 1A and 2A DGs. At 2000 station management was informed by the licensee's corporate engineering department that these devices did in fact render the DGs inoperable.
The licensee then declared the IB and 2B DGs inoperable.
Technical Specification 3.8.1.1.a requires with one inoperable DG that the DG be restored to operable status within the next 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or else be Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Mode 5 in the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. By 2055 the jumpers had been installed and testing completed for the 18 and 2B DGs, and they were declared operable.
A review of the cause of the design failure which included these devices in the trip circuitry will be accomplished in a subsequent report after the veridor issues the 10 CFR Part 21 report. This review and a review relating to when the licensee was informed by their AE of the problem and a review of the licensee's basis for not declaring the DGs inoperable will be followed as Unresolved items (454/87002-04(DRP); 455/87002-03(DRP)).
e.
Regarding LER 455/86001, this LER describes an event on November 20, 1986, with Unit 2 in Mode 5, when both trains of Component Cooling Water (CC) were lost due to an improperly set safety valve.
As part of a surveillance test, the containment isolation valve for Component Cooling (CC) to the Excess Letdown Heat Exchangers was opened. A subsequent CC system pressure transient caused safety valve 2CC9428B to lift. Valve 2CC9428B failed to reseat and the CC surge tank was drained out the open valve. With the loss of surge tank level the CC pumps tripped resulting in a complete loss of CC.
This event is discussed further in Inspection Report 455/86043. The containment isolation valve was shut isolating the leak and the CC system was restored to operation in 12 minutes. When valve 2CC94288 was removed and bench tested, the licensee discovered that due to the setting of the nozzle ring the valve reseat pressure was below normal system pressure. Consequentl until the system was depressurized (y, the valve would never resect empty). The nozzle ring was found to be set approximately 100 notches in the wrong direction.
10 CFR 50, Appendix B, Criterion V, as implemented by the Comonwealth Edison Company's Quality Assurance Manual, Quality Requirement 5.0, requires that activities affecting quality shall be
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accomplished in accordance with cpproved instructions. Crosby Valve
~ Company's-Test Data Sheet for 3 inch safety valve, style J0-25WR, specifies that the nozzle ring be set at -100 notches. The failure to set the nozzle ring on safety valve 2CC9428B to -100 notches, in accordance with approved instructions, is a violation of 10 CFR 50, Appendix B, Criterion V (455/87002-04(DRP)).
The licensee has accomplished the following corrective actions:
the valve was reset and reinstalled, diagnostic steps were added to the Abnormal Operating procedure B0A PRI-6 to add these safety valves as possible points for inspection in a loss of CC event, revised operating procedures for the CC system to add-precautions about having these valves in service during planned pressure transients, and to inspect all the other safety valves in the
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system to verify that they were set correctly.
Based on the corrective actions taken by the licensee the inspector has no further concerns regarding this matter and this item is considered closed; consequently, no reply to this violation is required.
5.
Summary of Operations Unit 1 continued end-ofa ycle power coastdown in preparation for a c
February refueling and operated at power levels up to 54% for the entire month.
Unit 2 achieved initial criticality at 0638 on January 9, 1987. The unit remained critical performing low power testing until 0342 on January 15, when the unit was manually tripped in accordance with the startup test procedures. The unit was again manually tripped at 0403 on the same day in accordance with the startup test procedures. The unit was again taken critical at 0515 on January 15. At 2240 on January 15, the unit tripped on Over Temperature Delta T due to a failed Resistance Temperature Detector (RTD) [See Paragraph 15.c]. The unit was taken critical at 0005 on January 17. At 1143 on January 17 the unit was manually tripped in accordance with the startup test procedures. The unit was again taken critical at 2317 on January 18. At 2033 on January 19, a normal shutdown was performed. At 0712 on January 23, the unit was taken critical and operated at power levels up to 3% for the remainder of the report period.
l 6.
HUREG-0737, " Clarification of TMI Action Plan Requirements (25401)
a.
I.D.I Control Room Design Reviews License Condition 2.C(5) to NPF-60 requires that the licensee submit a final summary report for the detailed control room design review by December 1, 1986.
The licensee submitted this report in a letter from K. Ainger to H. Denton, dated November 26, 1986. Based on the submission of this report this item is considered closed.
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b.
II.K.3.31 Plant Specific Calculations to Show Compliance With 10 CFR 50.46 The licensee has submitted a memorandum dated December 24, 1986 from S. Hunsader to H. Denton documenting the conservative and valid results of a series of small break LOCA analyses for demonstrating the adequacy of the Emergency Core Cooling System as required by 10 CFR 50.46. This item is considered closed.
7.
Review of Conditions for Unit 2 Operating License NPF-60 a.
(Closed) License Condition 2.C(5) of NPF-60. This item is discussed in Paragraph 6.a and, based on the licensee's report, this license condition is considered satisfied.
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(Closed) License Condit$on C.2 of Attachment 1 of NPF-60. This item discussed in Paragdaph 3, required resolution of concerns about potential high energy line breaks in the Auxiliary Building and, based on the licensee's report and the inspector's review, this license condition is considered satisfied.
8.
Training (41400 & 41701)
The effectiveness of training programs for licensed and nonlicensed-personnel were reviewed by the inspectors during the witnessing of the licensee's performance of routine surveillance, maintenance, and operational activities and during the review of the licensee's response to events which occurred during the month of January 1987. A concern identified by the inspector during this review is discussed below.
The inspector met with licensee management to discuss the training given to test engineers related to what can be used as objective evidence of valve position when the circuit breaker for the valve motor operator is open (See Paragraph 10). The licensee stated that there was no training at present on this matter, but that it was being developed.
The licensee stated this information would also be discussed at the next Technical Staff group meeting. The inspector requested the licensee provide a copy of the training to the inspector for review.
Followup of this review will be tracked by Open Item (454/87002-05(DRP); 455/87002-05(DRP)).
No violation or deviations were identified.
9.
Preparation for Refueling (60705)
The inspector began a review of the adequacy of the licensee's procedures and administrative controls in preparation for the refueling operations which are scheduled to commence in February 1987.
The inspector reviewed the following procedures to verify the licensee's administrative controls over refueling and plant condition during refueling:
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BGP 100-6, " Refueling Outage" BAP 310-3, " Administrative Control During Refueling" BMP 3118-1, " Reactor Vessel Closure Head Removal" BMP 3118-7, " Reactor Vessel Closure Head Installation" The inspector verified that the following items were discussed in these procedures: a clear definition of lines of authority for refueling activities, shift manning requirements, Quality Control inspection coverage, radiation monitoring and radiological control requirements, equipment checkout and dry runs of critical operations, fuel handlers training and maximum overtime allowance, procedures for casualties or abnormal occurrences, requirements for stopping and resuming work, requirements for delays and imposing holds, and Technical Specification requirements for: verifying shutdown margin and baron concentration, radiation and neutron monitoring, water level control for refueling
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cavity and spent fuel pit, decay heat control, communications, ventilation, and containment integrity.
Further inspections in this area will be continued in a subsequent report.
No violations or deviations were identified.
10. Monthly Surveillance Observation (61726)
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Station surveillance activities of the safety-related systems and components listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures and in conformance
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with Technical Specifications.
The following items were considered during this review:
the limiting conditions for operation were met while affected components or systems were removed from and restored to service; approvals were obtained prior to initiating the testing; testing was accomplished in accordance with approved procedures; test instrumentation was within its calibration
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interval; testing was accomplished by qualified personnel; test results d
conformed with Technical Specifications and procedural requirements and were reviewed by personnel other than the individual directing the test; and any deficiencies identified during the testing were properly documented, reviewed, and resolved by appropriate management personnel.
The following surveillance testing activities were observed / reviewed:
IB Safety Injection pump ASME quarterly test 2C Delta T/Tave channel 431 calibration 2B Diesel Generator monthly test
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During the performance of the SI pump test 1BVS 5.2.f.2-2, the inspector identified two problems.
Paragraph F.1.4 of the BVS requires that ISI8802B, " Train B Safety Injection pump to Hot Leg Injection Isolation valve," be verified closed and this fact be initialed on Data sheet 1.
The test engineer was at main control board IPM06J performing the procedure; after the test engineer had signed off paragraph F.1.4 the inspector requested that the engineer identify which valve he had
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verified to be closed. 'The engineer identified the valve indication he had used which was actually valve IRH8702B, "B Train RHR suction isolation valve", not valv-ISI88028. The valves were clearly labeled
and are in different secti>ns of control board IPM06J.
After the inspector pointed out that 1RH8702B was the wrong valve, the engineer observed that tre valve position indicating lights for 1SI8802B were both deenergized, Nt a caution card was hung on the valve switch, which said the valve was shut and the breaker was open. After the engineer again signed cff paragraph F.1.4 the inspector question whether
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a caution tag was objective evidence that the valve was in the closed position.
Valve 1S188028 is 1 of 12 valves which after they are positioned, the circuit breaker for their actuating motor is opened. This is required i
by Technical Specifications and the FSAR to prevent inadvertent operation
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of these valves. With the circuit breaker open, both valve position indicating lights are deenergized. Consequently, no information can be drawn from them as to the position of the valve. Thesinspector questioned if the valve was repositioned and the breaker then reopened
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would an individual have any different indication from that already
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present on IPM06J. The engineer did not know of any. The inspector inquired if the independently powered stem position limit switches or the shiftly, once per eight hours, physical verification of the valve
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position, which is a required entry on the shiftly surveillance, could be used as objective evidence of the valve position. The engineer stated he had not had any training regarding objective evidence to be used to determine the position of these 12 valves.
The engineer then requested the assistance of the unit reactor operator in determining the position of ISI88028.
The reactor operator informed
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the engineer that ISI8802B was in fact closed. The inspector did not
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identify any other problems during the performance of the rest of the surveillance. The inspector discussed these concerns with station management. The concern related to the adequacy of training is discussed further in Paragraph 8.
The engineer was counseled by licensee maragement as to the need for attention to detail.
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No violations or deviations were identified.
11. MonthlyMaintenanceObservation(62703)
i Station maintenance activities of the safety related systems and components listed below were observed / reviewed to ascertain that they '
were conducted in accordance with approved procedures, regulatory
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guides, and industry codes or standards, and in conformance with
, Technical Specifications.
The following items were considered during this review:
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conditions for operation were met while components or systems were removed from and restored to service; approvals were obtained prior
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to initiating the work; activities were accomplished using approved s
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procedures and were inspected as applicable; functional testing and/or
. calibrations were performed prior to returning components or systems
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to service; quality control records were maintained; activities were
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properly certified; radiological controls were implemented; and fire
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prevention controls were implemented. Work requests were reviewed to
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determine the status of cutstanding jobs and to assure that priority.is
assigned to safety-related equipment maintenance which may affect system WQ
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The following maintenance activities were observed / reviewed:
Replacement of Connecting Rod in IA Diesel Generator Modification of Fuel Handling Transfer system Motor 1FH01E Modification of Fuel Handling Transfer system Motor 2FH01E Following completion of maintenance on 1FH01E and 2FH01E, the inspectors
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verified that these systems had been returned to service properly, n
No violations or deviations were identified.
12. Operational Safety Verification (71707)
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The inspectors observed control room operation, reviewed applicable logs
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and conducted discussions with control room operators during the month of
i January 1987. During these discussions and observations, the inspectors
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i ascertained that the operators were alert, cognizant of plant conditions, l
attentive to changes in those conditions, and took prompt action when i
appropriate. The inspectors verified the operability of selected emergency systems, reviewed tagout records and verified proper return to
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service of affected components. Tours of the auxiliary, fuel handling,
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rad-waste, and turbine buildings were conducted to observe plant
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equipment conditions, including potential fire hazards, fluid leaks, 14'
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excessive vibrations, and to verify that'. maintenance requests had been
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initiated for equipment in need of maintenance.
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l The inspectors verified by observation and direct interviews that the physical security plan was being implemented in accordance with the r
l station security plan.
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l The inspectors observed plant housekeeping / cleanliness conditions and
verified implementation of radiation protection controls. The inspectors
also witnessed portions of the radioactive waste system controls associated with rad-waste shipments and barreling. During the month of t~
h January 1987, the inspectors walked down the accessible portions of the AC and DC power systems to verify operability.
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Facility operations observed were verified to be in accordance with the
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requirements established under Technical Specifications, 10 CFR, and j
administrative procedures.
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- 13. Startup Test Witnessing and Observation (72302)
The inspectors witnessed performance of fortions of the following Unit 2 startup test procedures in order to verify that testing was conducted in accordance with the operating license and procedural requirements, test data was properly recorded, and performance of licensee personnel conducting the tests demonstrated an understanding of assigned duties and responsibilities.
2.45.81, "Incore Flux Mapping at Low Power" 2.47.80, " Isothermal Temperature Coefficient" 2.64.83, " Boron Endpoint Determination" No violations or deviations were identified.
14. Byron Unit 2 Initial Criticality Witnessing (72592)
,t Unit 2 entered Mode 2 on January 8, 1987 and achieved initial criticality at 0638 on January 9, 1987. The inspectors provided continuous coverage of startup activities on January 8, 1987 and January 9, 1987 and were present in the control room when initial criticality was achieved.
The inspectors identified all technical specifications and licensee conditions requirements applicable during the initial approach to criticality and verified conformance with these requirements on a sampling basis. The inspectors verified that:
startup test procedures were available, in use, and of the proper revision; prerequisites and initial conditions required by test Procedures 2.32.83, " Initial Criticality and Low Power Test Sequence," and 2.52.82, " Initial Criticality," were satisfied prior to execution; nuclear instruments were properly aligned and operating; shift crew requirements specified in the technical specifications were met; and inverse multiplication plots were being maintained per procedural requirements, i
j The inspectors performed daily reviews of operating logs, witnessed
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several shift turnovers, witnessed several reactor coolant boron l
concentration analyses, reviewed implementation of radiological l
protection and personnel access controls for the Unit 2 containment, i
reviewed inverse multiplication plots, and verified that actual critical conditions agreed with predicted conditions within tolerances.
No..olations or deviations were identified.
l 15. Onsite Followup of Events at Operating Reactors (93702)
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General The inspector performed onsite followup activities for events which occurred during January 1987. This followup included reviews of operating logs, procedures, Deviation Reports, Licensee Event
Reports (where available) and interviews with licensee personnel.
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For each event, the inspector developed a chronology, reviewed the
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functioning of safety systems required by plant conditions, reviewed licensee actions to verify consistency with procedures, license conditions and the nature of the event. Additionally the inspector verified that the licensee investigation had identified root causes of equipment malfunctions and/or personnel error and had taken appropriate corrective actions prior to plant restart. Details of the events and licensee corrective actions developed through inspector followup are provided in Paragraphs b and c below.
b.
Unit 1 Inoperable Diesel Generator At 1337 on January 7, 1987, the licensee received a 10 CFR 21 report from the Emergency Diesel Generator (DG) vendor, Cooper Industries, Energy Services Group. This report stated that a metalurgical problem had been identified with a number of connecting rods, one of which was believed to be installed in the KSV series DGs at Byron, and this connecting rod should be replaced.
Following the catastrophic failure of a connecting rod in a KSV series DG on December 23, 1986 at the Palo Verde Unit 3 Nuclear Generating Station, owned by the Arizona Public Service Company, the vendor identified that the failed connecting rod had been plated with iron and remachined during its manufacture. This manufacturing technique made the connecting rod susceptible to fatigue cracking and is believed to be the cause of the failure of the Palo Verde connecting rod. The vendor identified that four power, master, connecting rods had used this manufacturing technique and that one was believed to be installed in the Byron 1A DG.
The licensee inspected the 1A DG to verify by serial number that the suspect connecting rod was in fact installed. When this was verified, the DG was declared inoperable at 1535 on January 7, 1987 and the licensee commenced work to replace the suspect connecting rod. The suspect connecting rod was replaced, the DG tested, and returned to service on 2150 on January 9,1987. The inspectors observed portions of the maintenance work (see Paragraph 11) during the replacement of the connecting rod.
c.
Unit 2 Reactor Trip on OTDT At 2240 on January 15, 1987, while in Mode 2, the reactor tripped from from below 0% power level with indication of SE-8 amps in the intermediate range, due to a Over Temperature Delta T signal (0 TDT).
The reactor coolant system cold leg (T-cold) resistance temperature detector (RTD) for loop 2C had been drifting and failed low. This caused channel 2C Delta T to indicate high. Which caused channel 2C of 0 TDT to give a high indication and trip. Channel 2D OTDT was already tripped, which was required because Power Range channel N44 was inoperable due to the installation of a reactivity computer.
The reactivity comput;r was installed at channel N44 to support physics testing of the reactor. With both channels 2C and 2D tripped the two out of four coincidence logic was met and a reactor trip occurred.
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After the reactor trip occurred the Control Room operators commenced emergency boration at 30 gpm, charged via the normal path to the reactor coolant system. This was because the shutdown margin was less than 1.3% Delta K/K limit of Technical Specification 3.1.1.1.
The shutdown margin had been reduced to less than 1.3% Delta K/K in accordance with the special test exception of Technical Specification 3.10.1 to perform physics testing of the reactor core, such as rod bank worths and boron endpoints. By 2252 the reactor had been stabilized in Mode 3 [ Hot Standby] with the reactor coolant system borated to the Hot, Xenon Free shutdown margin. All other systems responded normally during the trip.
The licensee disconnected the failed RTD and connected the installed spare RTD to the reactor protection system. The channel was recalibrated and the unit was taken critical at 0005 on January 17, 1987. The inspector will review this event in a subsequent report after the LER is issued.
No violations or deviations were identified.
16. Commissioner's Tour (30702)
On January 6,1987, NRC Chairman Lando W. Zech Jr. accompanied by D. F. Humenansky, Technical Assistant, J. G. Keppler, Region III Administrator, W. L. Forney, Chief, Reactor Projects Section IA, and the Resident Inspector staff met with licensee corporate and station management and toured portions of Byron Unit 2 to review the readiness of Byron 2 for issuance of a full power license.
17. Management Meetings (30702)
On January 7,1987, Mr. A. Bert Davis, Deputy Regional Administrator, and members of the Region III staff met in the Region III office
(Glen Ellyn, Illinois) with licensee management and supervisory personnel j
denoted in Paragraph 1 of this report. This was an enforcement l
conference held to discuss concerns related to allegations concerning quality control problems with work performed on Unit 2 by the electrical contractor, discussed in Inspection Reports 454/86031(DRS)and 455/86017(DRS).
18. Unresolved Items Unresolved items are matters about which more information is rtuired in order to ascertain whether they are acceptable items, items of l
noncompliance, or deviations. Unresolved items disclosed during the l
inspection are discussed in Paragraph 4.d.
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19. Open Items
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Open items are matters which have been discussed with the licensee, which I
will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both. Open items disclosed during l
the inspection are discussed in Paragraph 8.
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20. Violations For Which A " Notice of Violation" Will Not Be Issued The NRC uses the Notice of Violation as a standard method for formalizing the existence of a violation of a legally binding requirement. However, because the NRC wants to encourage and support licensee's initiatives for self-identification and correction of problems, the NRC will not generally issue a Notice of Violation for a violation that meets the tests of 10 CFR 2, Appendix C Section V.A.
These tests are:
(1) the violation was identified by the licensee; (2) the violation would be categorized as Severity Level IV or V; (3) the violation was reported to the NRC, if required; (4) the violation will be corrected, including measures to prevent recurrence, within a reasonable time period; and (
5) it was not a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violation. Violations of regulatory requirements identified during the inspection for which a Notice of Violation will not be issued are discussed in Paragraphs 4.a and 4.b.
21.
Exit Interview (30703)
The inspectors met with licensee representatives denoted in Paragraph 1 at the conclusion of the inspection on January 29, 1987. The inspectors summarized the purpose and scope of the inspection and the findings.
The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection.
The licensee did not identify any such documents / processes as proprietary.
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