IR 05000454/1986047
| ML20215F626 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 12/17/1986 |
| From: | Forney W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20215F612 | List: |
| References | |
| 50-454-86-47, 50-455-86-43, NUDOCS 8612240009 | |
| Download: ML20215F626 (15) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-454/86047(DRP); 50-455/86043(DRP)
Docket Nos. 50-454; 50-455 License Nos. NPF-37; NPF-60 Licensee: Commonwealth Edison Company Post Office Box 767 Chicago, IL 60690 Facility Name: Byron Station, Units 1 and 2 I
Inspection At: Byron Station, Byron, IL l
Inspection Conducted: November 1 - December 1, 1986
l Inspectors:
J. M. Hinds, Jr.
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P. G. Brochman J. A. Malloy J. A. Holmes H
k7 h L M %
Approved By:
W. L. Forney, Chief
/ '/n// fo Reactor Projects Section IA Date
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Inspection Summary Inspection on November 1 - December 1,1986 (Report Nos. 50-454/86047(DRP);
50-455/86043(ORP))
Areas Inspected:
Routine, unannounced safety inspection by the resident inspectors and a region based inspector of licensee action on previous inspection findings; LERs; IEBs; operations' summary; surveillance; maintenance program implementation; maintenance; operational safety; startup testing; fuel loading; Region III requests; IENs; and event followup. Operating License NPF-60 was issued for Byron Unit 2 on November 6, 1986. The license authorizes the loading of fuel and operation of the reactor at power levels up to 5%.
Results: Of the 12 areas inspected, no violations or deviations were identified in 11 areas; one violation was identified in the remaining area:
(failure to accomplish a Technical Specification Action Statement - Paragraph 3.c); one additional violation was 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 a Technical Specification surveillance -
Paragraph 3.b).
The failure to accomplish the actions required by a Technical Specifications Action Statement is of more than minor safety significance.
The inadequate supervision of contractor work activities is also of more than minor safety significance.
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DETAILS 1.
Persons Contacted Commonwealth Edison Company R. Querio, Station Manager R. Pleniewicz, Production Superintendent
- R. Ward, Services Superintendent
- W. Burkamper, Quality Assurance Superintendent
- L. Sues, Assistant Superintendent, Operating
- G. Schwartz, Assistant Superintendent, Maintenance T. Joyce, Assistant Superintendent, Technical Services D. St. Clair, Assistant Superintendent, Work Planning
- J. Woldridge, Quality Assurance 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
- E. Falb, Unit 2 Startup Testing Supervisor
- F. Hornbeak, Technical Staff Supervisor R. Flahive, Radiation / Chemistry Supervisor P. O'Neil, Quality Control Supervisor T. Tulon, Master Mechanic
- J. Pausche, Regulatory Assurance Staff
- W. Pirnat, Regulatory Assurance Staff
- W. Bielgsco, Station Health Physicist
- E. Zittle, Regulatory Assurance Staff
- A. Britton, Quality Assurance Inspector
- W. McNeil, Radiation Chemistry Foreman
- M. Whitemore, Radiation Chemistry Staff The inspector also contacted and inte'rviewed other licensee and contractor personnel during the course of this inspeition.
- Denotes those present during the exit interview on December 1, 1986.
2.
Action on Previous Inspection Findings (92701)
(Closed) Open Item (455/85034-02):
Relocation of fire hose, station K-17.
Each hose station was verified to be as indicated in drawings No. M-52, Revision P; and M-52, Revision V; entitled " Diagram of Fire Protection Manual Hose Station " except hose reel No. 14 which was equipped with 100 feet instead of 75 feet length of hose attached to the stand pipe station. According to the licensee's staff, this hose station and others located on the Unit 2 side of the turbine building had not been turned over to plant operations staff from construction.
During followup of this open item, the licensee indicated to the inspector that the hose stations located on the Unit 2 side of the turbine building
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had been turned'over~to operations.
In addition, the inspector verified that hose reel No. 14 was equipped with a 75 foot hose.. The. inspector toured the 451 level of the turbine building and Auxiliary Building.
Based on this tour, review of licensee's corrective actions and review l
of licensee's diagrams in the fire protection report, this item is considered closed.
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Licensee Event Report (LER) Followup (92700)
(Closed) LERs (454/86027-LL; 454/86028-LL; 454/86029-LL; 454/86030-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 recerrence had been
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accomplished in accordance with Technical Specifications.
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LER No.
Title 454/86027 Reactor Trip due to Damaged Cable in SSPS 454/86028 Manual Reactor trip due to rod drop caused by faulty circuit cards
454/86029 480 V containment electrical penetration overcurrent protective device exceeded Technical a
Specification surveillance interval 454/86030 Technical Specification Action Statement exceeded
for a Radiation Monitor
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No violations or deviations were identified, regarding LER 454/86028.
a.
Regarding LER 454/86027, this LER described an event on
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September 30, 1986, while in Mode 1, in which a reactor trip
occurred due to a turbine trip.
Contractor personnel were working on fire barriers, made of CT
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Gypsum Cement, in the bottom of the Train IB Solid State Protection System (SSPS) Cabinet IPA 12J. This work included the removal of some gypsum to' inspect the dispersion of the gypsum around the cable penetrations.
The gypsum was being removed with a wooden chisel.
a The chisel penetrated the jacket of cable 1EF007. Cable IEF007 is a test cable which connects SSPS cabinet IPA 12J and the slave output
relay cabinet IPA 09J.
Cable 1EF007 contains a 120 V test signal conductor. The penetration exposed the conductors on two circuits which shorted to the 120 V signal.
This caused a turbine trip and feedwater isolation relays to energize. The turbine trip above P-7 (10% power) caused a reactor trip.
i The licensee's investigation indicated that the licensed operators
who approved the start of the work believed that only a visual
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inspection would be performed. However, review of the work authorization for this job, NWR 6AG008, indicated that the
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< contractors were required to irstall or repair penetration seals as required to complete construction. The contractor procedure PSQAP 9.lBY allowed the removal of gypsum to repair damaged seals. The cause of the trip was a failure.to communicate the scope of the work
'to be performed.
The operators who approved the work believed only visual inspection was to be performed; and that if other work was necessary, they would inpose additional controls or the work would be deferred to an outage.
As corrective action the licensee established a Penetration Seal
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Work Permit (WP).
This WP requires review and approval for work on penetration seals in critical locations, such as: Main Control Boards, Remote Shutdown Panels, Diesel Generator Rooms, Vital Switchgear Rooms, or other vital electrical equipment rooms (containing Reactor Protection, SSFS, and control. circuits); or work on any one of 17 critical systems. The WP may also require an operator to be in continual attendance during the performance of the work.
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While no violations or deviations were identified the NRC is
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concerned with licensee management's review and supervision of contractor maintenance activities, and believes that additional attention should be focused there.
b.
Regarding LER 454/86029-LL, this LER described an event from January 4, 1985 to October 22, 1986 when a Technical Specification surveillance for 480 V breaker 1HC22G was not performed, Tect tical Specification 4.8.4.1.a(2) requires that all 480 Volt (V)
containment penetration conductor overcurrent protective devices listed in Table 3.8-la shall be demonstrated operable at least once-per 18 months by selecting and functionally testing a representative sample of at least 10% of each type of 480 V circuit breaker. Table 3.8-la, Section.4, includes breaker IHC22G, which powers a containnent crane.
Prior to the initial startup of Unit 1 the licensee developed a computerized system for tracking surveillance requirements; however, 1HC22G was not included in this list.
This error was identified by the licensee during a review of Technical Specifications in October 1986. As corrective action the licensee added 1HC22G to.he surveillance program and on October 23, 1986 successfq11y tested the containment penetration conductor over current protectisw devices.
The failure to test the containment penetration conductor overcurrent protection devices for 480 V breaker 1HC22G within the required irterval is a violation of Technical Specification 4.8.4.1.a(2) (454/86047-01(DRP). However, it meets the tests of 10 CFR 2, Appendix C, Section V.A; consequently, no Notice of Violation will be issued, and this matter is considered closed.
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c.
Regarding LER 454/86030, this LER described an event from October 23 to October 25, 1986, while in Mode 1, when a Technical Specification Action Statement for a process radiation monitor was not followed.
At 0020 on October 23, 1986 process radiation monitor 1RE-PR002,
" Essential Service Water, Reactor Containment Fan Cooler 1A and IC Outlet Monitor," was declared inoperable. Technical Specification 3.3.9.6 requires that radioactive liquid effluent monitoring
' instrumentation channels be operable at all times or else take the actions shown in Table 3.3-12.
Table 3.3-12, Instrument 2.a(1)(a),
requires that monitor 1RE-PR002 be operable or else follow Action Statement 32. Action Statement 32 requires that with monitor 1RE-PR002 inoperable, effluent releases via this pathway may continue for up to 30 days provided that, at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, grab samples are collected and analyzed.
At 0005 on October 25, 1986, during a discussion between Radiation-Chemistry and Operating Shift personnel they discovered that the realired grab samples had not been obtained and analyzed.
By 0025 on October 25 a grab sample had been obtained and satisfactorily analyzed.
The licensee's investigation determined that grab samples had been taken at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, though not to meet the requirements of Action statement 32; however, the grab samples had not been analyzed. Analysis of these samples on October 25 indicated that no radioactive effluent release limits had been exceeded. The failure to analyze grab samples at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> during a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period is a violation of Technical
. Specification 3.3.3.9.b (454/86047-02(DRP)).
Additionally, investigation determined that the cause of this event was the improper notification of Radiation Chemistry personnel by Operating Shift personnel. As corrective actions, licensee management discussed this event with the personnel involved and issued a daily memo to shift personnel to hand carry Action Statement paperwork to Radiation-Chemistry for implementation of the sampling requirements.
Within the last 23 months there have been 6 previous examples of the failure to obtain and analyze samples. The last of these events was included in a Severity Level III problem for which the NRC took escalated enforcement, including imposing a civil penalty (See Inspection Report 454/85042(DRP)).
As corrective action to avoid further violation, in their response to the previous violation (II.E), the licensee stated, "A Limiting Condition for Operation Action Requirement (LOCAR) tracking program has been implemented which provides a documented means of tracking LOCARs involving a grab sample surveillince.
This program also involves direct interfacing of supervisory personnel on the Radiation Chemistry and Operating Departments to review the status
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and results of the surveillances".
The inspector reviewed LOCAR 180S 3.3.9-la, Revision 52, sheet 3, and verified that it did document the accomplishment of grab sampling and required the signature of a Radiation Chemistry Foreman and a Licensed Senior Reactor Operator (SRO) that these actions were being taken.
Documentation of each sample is logged in Appendix A, Sheet 1 of the LOCAR.
Byron Administrative Procedure (BAP) 335-1, " Operating Shift Turnover and Relief", requires that the Shift Engineer (SE), Shift Control Room Engineer (SCRE), and Shift Foreman (SF) during their turnover discuss the status of all LOCARs and that all LOCARs are listed on the turnover sheets BAPs 335-1T1, 335-1T2, and 335-1T3 respectively. The inspector interviewed a SE and was informed that LOCARs are reviewed every shift and this review included a verification that surveillance requirements were being met. The inspector questioned how six separate turnovers by three different individuals could have been accomplished without identifying the fact that the surveillance requirements for 1RE-PR002 were not being accomplished. The inspector discussed this concern with licensee management and requested that in their response to the violation the licensee address:
(1) the apparent failure of previous corrective action to prevent recurrence; and (2) the apparent failure of multiple shift turnovers to identify that the LOCAR surveillance requirements were not being accomplished.
4.
IE Bulletin (IEB) Followup (92703)
(Closed) IEBs (454/86003-8B; 455/86003-BB):
Potential Failure of Multiple ECCS Pumps Due to Single Failure of Air-operated Valve (A0V) in Minimum Flow Recirculation Line. The inspector reviewed the licensee's response to the IEB which indicates that the minimum flow systems installed in the ECCS at Byron, do not utilize A0Vs for isolation, but rather use motor operated valves (MOVs). These MOVs are used in a scheme so as to prevent pump desdheading. The minimum flow path in the safety injection system is designed with each pump having a motor operated valve which remains energized and open during normal plant operating conditions.
In addition, per Technical Specifications, a common MOV is open and de-energized. All of these valves are designated to fail as is which would prevent the pumps from deadheading should valve motive force be lost. Therefore, the problem identified in the IEB does not exist at Byron Station.
Based on this response the inspector has no further concerns and this Bulletin is considered closed.
No violations or deviations were identified.
5.
Summary of Operations Unit 1 operated at power levels up to 94% for the entire month.
Unit 2 was issued operating license NPF-60 on November 6, 1987, which authorized fuel loading and operation of the reactor at core power levels
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up to 5%.
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Unit 2 fuel loading commenced at 0256 on November 7 and was completed by 0559 on November 12, and is discussed further in Paragraph 11. The unit entered Cold Shutdown (Mode 5) at 1830 on Noveraber 14, 1986. At 1100 on November 20, 1986 an Alert was declared and terminated due to the loss of both trains of Component Cooling water. A manual reactor trip was initiated at'2330 on November 22, 1986 when control rod M-4 differed by more than 12 steps from the position of Control Bank D.
Both of these events are discussed further in Paragraph 14.
Unit 2 remained in Mode 5,
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performing startup testing, for the rest of the month.
6.
Monthly Surveillance Observation (61726)
Station surveillance activities of the safety related systems ar.d components listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures and in conformance 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 interval; testing was accomplished by qualified personnel; test results conformed with Technical Specifications and procedural requirements and were reviewed by personnel other tnan 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 Auxiliary Feedwater pump ASME quarterly test Unit 2 Containment Ventilation Isolation Slave Relay No violations or deviations were identified.
7.
Maintenance Program Implementation (62700)
The inspectors continued a de, tailed review of the maintenance program to determine whether the program was being implemented in accordance with regulatory requirements; to determine the effectiveness of the maintenance program on important plant equipment; and to determine the ability of the maintenance staff to conduct an effective maintenance program. This review is an ongoing inspection and its completion will be documented in a subsequent inspection report.
8.
Monthly Maintenance Observation (62703)
l Station maintenance activities of the safety related systems and
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components listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides
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l and industry codes or standards, and in conformance with Technical Specifications.
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The following items were considered during this review:
the limiting conditions for operation were met while components or systems were removed from and restored to service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemented. Work requests were reviewed to determine the status of outstanding jobs and to assure that priority is assigned to safety related equipment maintenance which may affect system performance.
The following maintenance activities were observed / reviewed:
Fuel Transfer Drive System Shear Pin Replacement Unit 2 Reactor Vessel Head Installation Following completion of maintenance, the inspectors verified that these systems had been returned to service properly.
No violations or deviations were identified.
9.
Operational Safety Verification (71707)
The inspectors observed control room operation, reviewed applicable logs l
and conducted discussions with control room operators during the month of l
November 1986. During these discussions and observations, the inspectors ascertained that the operators were alert, cognizant of plant conditions, attentive to changes in those conditions, and took prompt action when
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appropriate. The inspectors verified the operability of selected I
emergency systems, reviewed tagout records and verified proper return to service of affected components. Tours of th^e auxiliary, turbine, rad waste, and Unit 2 containment buildings were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks and excessive vibration and to verify that maintenance requests had been initiated for equipment in need of maintenance.
The inspectors verified by observation and direct interviews that the physical security plan was being implemented in accordance with the station security plan.
The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls. During the month of November 1986, the inspectors walked down the accessible portions of the Unit 2 Containment Spray (CS) system to verify operability. The inspectors identified two concerns during the walk down:
a.
Drawing M-129, Sheet 1A, indicates that valve 2CS013A should be locked closed. Valve 2CS013A was found to be closed and no locking device was installed.
Valve lineup B0P CS-M2, Sheet 3 specifies
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that position for valve 2CS013A is closed; vice, locked closed.
Valve 2CS013B was not specified as a locked valve in either drawing M-129 or BOP CS-M2.
b.
80P CS-T1, " Containment Spray Check Valve Locations," Sheet 1, included valve 2C5044, which had been removed from the CS system.
The inspector discussed these concerns with the licensee's staff. The licensee agreed to resolve the discrepancy between the drawing and the valve lineup for valve 2CS013A and to revise B0P CS-T1 to delete valve 2CS044. Accomplishment of these actions will be tracked as Open Item (455/86043-01(DRP)).
The inspectors also witnessed portions of the radioactive waste system controls associated with rad-waste shipments and barreling.
Facility operations observed were verified to be in accordance with the requirements established under Technical Specifications, 10 CFR, and administrative procedures.
No violations or deviations were identified.
10. Startup Test Witnessing and Observation (72302)
The inspectors witnessed performance of portions 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.
l 2.32.81,
" Post Core Loading Precritical Test Sequence"
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2.52.81A, " Core Loading. Instrumentation and Neutron Source Requirements, (Prior to Core Load)"
2.52.818, " Core Loading Instrumentation and Neutron Source Requirements, (During Core Load)"
2.52.85A, " Operational Alignment of Excore Nuclear Instrumentation, (Prior to Core Load)"
2.52.85B, " Operational Alignment of Excore Nuclear Instrumentation, (DuringCoreLoad)"
2.61.80, " Reactor Systems Chemical Sampling for Core Load" No violations or deviations were identified.
11. Fuel Load Witnessing (72524)
The licensee entered Mode 6 and began initial core loading of Byron Unit 2 on November 7, 1986. NRC inspectors provided 24 hour-a-day coverage until November 8, 1986.
From November 8,1986, until completion of fuel loading on November 12, 1986, NRC inspectors witnessed fuel loading activities on all three shifts including shift turnovers, fuel handling equipment repairs and fuel loading processes and procedure compliance.
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The inspectors identified all technical specification requirements and l
license conditions applicable for Mode 6 and verified conformance with these requirements on a sampling basis. The inspectors verified that
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startup test precedures were available and in use; prerequisites and
initial conditions required by Byron Startup Test Proceduras 2.32.80,
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" Initial Core Load Sequence" and 2.32.82, " Initial Core Loading" were yndl satisfied prior to execution; nuclear instruments were properly 1.-
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calibrated and operating with a measurable count rate during core 1-
alterations; shift crew requirements specified in the startup test procedures and technical specifications were satisfied; adequate communications were in place; and inverse multiplication plots were
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being maintained in accordance with procedural requirements.
The inspectors performed daily reviews of operating logs, witnessed several shift turnovers, verified that primary coolant system boron
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concentration complied with Technical Specifications shutdown margin s
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determinations (sample analyses), reviewed implementation of personnel access and cleanliness controls in place on the refueling floor, verified
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the use of refueling status boards throughout coreload, and interviewed
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g licensee personnel to determine whether they understood their specific
^i responsibilities. The licensee's performance during the Unit 2 fuel
load was excellent. Management evolvement was evident, and reflected
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the application of the Unit 1 lessons learned program, which resulted
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in achieving a significant reduction in the fuel load schedule time, and problems / equipment failures.
No violations or deviations were identified.
12. Followup of Region III Requests (92701)
a.
The inspector received a request from Region III, memorandum from Charles E. Norelius, dated October 22, 1986, to provide information related to IE Information Notices (IENs) and IE Bulletins (IEBs)
sent for information.
Resident Inspection Reports were reviewed and the information was forwarded to the Region in a memorandum on November 13, 1986.
b.
The inspector received a request from Region III, memorandum from Charles E. Norelius, dated October 28, 1986, to review the licensee's response to IEN 86072 and forward the finding to the Region by November 10, 1986. The licensee's response was forwarded to the Region.
Details of the licensee's response are addressed in Paragraph 13.b.
c.
The inspector received a request from Region III, memorandum from A. Bert Davis, dated November 6,1986, to provide information related to Byron's most significant safety findings and their impact on the licensee over the past six months. Resident Inspection Reports were reviewed for the period requested and the information was forwarded to the Region in a memorandum on November 13, 1986.
d.
The inspector received a request from Region III, memorandum from
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C. E. Norelius, dated October 28, 1986, to obtain information related to the extent of deficient splices involving heat shrinkable tubing at Byron Station. This potentially generic safety issue is the subject of IEN 86053 and inspection guidance has been provided in Temporary Instruction (TI) 2500/17 which has been assigned to the resident inspectors. The licensee's response to IEN 86053 was obtained and forwarded to Region III as requested.
No violations or deviations were identified.
13.
IE Information Notice (IEN) Followup (92701)
a.
(Closed) IEN (454/85053-NN; 455/85053-NN): " Improper installation of Heat Shrinkable Tubing." The inspector reviewed the licensee's response and determined that IEN had been appropriately reviewed for applicability, distributed to the proper corporate and station personnel, and adequate corrective actions taken to address the concerns listed in the IEN. The licensee's response indicated that visual inspections were conducted, on a sampling basis, of both safety and non-safety related applications, verifying that RayChem and Conax Penetration requirements for installation were followed by station electrical maintenance, station instrument maintenance, and construction electrical contractor personnel.
In summary, the visual examinations of all the sampled RayChem heat shrinkable installations found that they were installed to the applicable procedures and were acceptable for all of the inspection criteria.
Based on this response the concerns cited in the IEN do not appear to be a problem at Byron and this IEN is considered closed.
b.
In response to a Region III request, discussed in Paragraph 12.b, relating to an April 14, 1986, 10 CFR 21 report from Valcor Engineering Corporation dealing with Solenoid Valve Spring (17-7pH),
the inspector requested the licensee to provide a response addressing the 10 CFR 21 report concerns and IEN 86072, " Failure 17-7 ph Stainless Steel Springs in Valcor Valves due to Hydrogen Embrittlement" dated August 19, 1986.
The licensee's response indicated that the 10 CFR 21 report as described in IEN 86072 is not applicable to Byron Station due to the fact that the valve in t
question is not installed in Byron systems. The response did, however, indicate that the Reactor Vessel Head Vent Valves RC014A, B, C and D do incorporate a similar 17-7 pH Stainless Steel Spring material which the licensee routinely monitors for degradation with control board alarms and periodic valve stroke surveillances. The ins 51)pector reviewed Byron Annunciator Response (BAR 1-14-E4, Revision which alerts the operator to potential leakage and provides immediate and subsequent actions for correction of the situation.
The inspector also reviewed Byron Valve Surveillance (1BVS 0.5-2.RC.2, Revision 2), " Reactor Coolant System Valve Stroke Test,"
which verifies each 92 days that the RC 014 A-D valves will satisfactorily perform the required stroking.
Based on the licensee's routine monitoring for valve degradation through control board alarm indications and periodic valve stroke surveillance, the requirements of the IEN have been adequately addressed and the inspector has no further concerns. This IEN is considered closed.
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No violations or deviations were identified.
14. Onsite Followup of Events at Operating Reactors (93702)
a.
General The inspector performed onsite followup activities for events which occurred during November 1986. This followup included reviews of operating logs, procedures, Deviation Reports, Licensee Event Reports (where available) and interviews with licensee personnel.
For each event, the inspector developed a chronology, reviewed the functioning of safety systems required by plant conditions, reviewed licensee actf ons to verify consistency with procedures, license conditions and the nature of the event. Additionally the inspector verified that licensee investigation had identified root causes of equipment malfunctions and/or personnel error and had
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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.
Alert Declared for Unit 2 due to Loss of Plant Shutdown Function on November 20, 1986 At 1100 on November 20, 1986, with Unit 2 in Mode 5 (Cold Shutdown),
the licensee declared and terminated an Alert due to the loss of a Plant Shutdown Function.
At approximately 0930 on November 20, 1986 operators were performing Byron Operating Surveillance 280S 3.2.1-841, " Train A Containment Isolation Phase A - Relay K606." This procedure requires that valve 2CC9437A, " Component Cooling (CC) to Excess Letdown Heat Exchanges (EXLDHX) Isolation Valve," be opened. At approximately 1023 the operators started the 2B CC pump and secured the 2A CC pump, for unrelated reasons. At 1026 the 2B pump tripped on low level in the CC surge tank. The 2A CC pump auto started on CC discharge header low pressure and ran for appro'ximately 8 seconds and then also tripped. The cperators beiieved that one of the CC relief valves on the EXLDHX, 2CC9428A or 2CC94288 had lifted and failed to reseat.
The operators shut 2CC9437A and refilled the CC surge tank. The 2A CC pump auto-started as level was being recovered in the surge tank.
The CC system recovery was completed by 1038. By 1100 the licensee determined that the loss of both trains of CC was classifiable as an ALERT under Emergency Action Level (EAL) 12 of the Generating Station Emergency Plan (GSEP).
EAL 12 of the Byron Annex to the GSEP defines a loss of both trains of Component Cooling water as a loss of a Plant Shutdown Function necessary to maintain Cold Shutdown (Mode 5). At 1100 the licensee notified the NRC operations center that an ALERT had been declared and terminated at the same time.
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The licensee believed that one of the two relief valves, 2CC9428A or 2CC94288, had lifted and failed to rescat. The 2B CC pump then pumped water out the open valve to the containment sump, thereby draining the surge tank. The surge tank provides a net positive suction head (NPSH) to the CC pumps and with the loss of the NPSH the 2B CC pump tripped automatically to prevent damage. With the tripping of the 28 pump the discharge header pressure decayed enough to cause the 2A pump to-auto-start.
The 2A pump then tripped
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approximately eight seconds after it started, on low surge tank level.
The CC surge tank has a baffle in its lower section.which separates the tank into two parts. Two separate pipes, on either side of the baffle, connect the surge tank to the suction header for the CC pumps. These two pipee enter the suction header on either side of valve 2CC9459A. Valve 2CC9459A separates the suction of pump 2A from pump 28. With valve 2CC9455A shut the surge tank could only drain down on the non-running side to the level of the baffle.
However, valve 2CC9459A was open, in its normal position.
Therefore, the 2B pump drained both sides of the surge tank. The licensee is investigating why the 2A pump was able to start as both sides of the baffle should have drained to below the low level trip setpoint; thereby preventing the 2A pump from even starting.
The licensee believes that this may have been caused by differences in the setpoints of the two separate level transmitters for the surge tank or dynamic effects associated with the stopping of the 2B pump.
The licensee removed the two relief valves and with a vendor representative present bench tested the valves. Valve 2CC9428A was tested satisfactorily.
Valve 2CC94288 lifted at 175 psig, normal set pressure is 150 psig. Additionally, the blowdown ring was set approximately 100 steps in the wrong direction. The valve was found to be properly lockwired when it was removed from the system. A review of records by the licensee indicated that no work had been performed on the valves by the maintenance department since initial
installation. The licensee's investigation is continuing to determine how the blowdown ring was incorrectly set, if this affected lift pressure, and would tnis allow enough water to pass through the valve to account for the observed response of the CC system.
The inspector identified a concern related to the timeliness of the licensee's identification of the GSEP ALERT. The inspector questioned whether the operators had availed themselves of the guidance and information contained in Byron Abnormal Operating Procedure 280A PRI-6, " Component Cooling Malfunction - Unit 2,"
during this event. 2 BOA PRI-6 provides specific direction to the Station Director to review the EALs of Byron Emergency Plans BZP 200-A1.
The inspector discussed these concerns with licensee management ar.d the licensee agreed to review these questions during the preparation of the Licensee Event Report (LER).
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The licensee's investigation of this event is continuing and the inspectors will review it in a subsequent report, after the LER is issued.
c.
Manual Reactor Trip for Unit 2 on November 22, 1986 At 2330 on Novemb-- 22, 1986, with Unit 2 in Mode 5, the operator manually tripped the reactor when the indicated position of control rod M-4 differed from the Bank Demand position indication of Control Bank D (CBD) by greater than 12 steps during the performance of a Digital Rod Position Indicating system (DRPI) surveillance test.
Byron Technical Staff Surveillance 2BVS 1.3.3-1, "DRPI Operability Checkout," requires that the reactor trip breakers be opened if the disagreement between DRPI and Bank Demand Position Indication is greater than 12 steps. As the rods of CBD were being moved outward, rod M-4 indicated that it had dropped into the core. As this caused DRPI vs Bank Demand to disagree by greater than 12 steps, due to the position of the rest of CBD, the reactor trip breakers were opened by the control room operator.
The licensee's investigation determined that a bad data card in DRPI was the cause of the problem, and that rod M-4 had never dropped into the core.
The bad data card was replaced and the BVS was reperformed satisfactorily.
The inspector will review the LER in a.
subsequent report.
No violations or deviations were identified.
15. 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
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to the NRC, if required; (4) the violation will be corrected, including measures to prevent recurrance, 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 ctrrective action for a previous violation. A violation of regulatory requirements identified during the inspection for which no Notice of Violation will be issued is discussed in Paragraph 3.b.
16. Open Items Open items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both.
An open item disclosed during the inspection is discussed in Paragraph 9.
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17. Exit interview (30703)
The inspectors met with licensee representatives denoted in Paragraph 1 at the conclusion of the inspection on December 1,1986. 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
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documents / processes as proprietary.
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