IR 05000324/1990037
| ML20058B066 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 10/18/1990 |
| From: | Carroll R, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20058B054 | List: |
| References | |
| 50-324-90-37, 50-325-90-37, NUDOCS 9010290377 | |
| Download: ML20058B066 (23) | |
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UNt?[D STATES a
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'o NUCLEAR nEGULATORY COMMISSION
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g 101 MARIETTA ST REET,N.W.
- t ATLANT A, GEORGI A 30323
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RepWL* No. 50-325/90-37 and 50-324/90-37 i
Licensee:
Carolina Power and Light Company.
P. O. Box 1551 i
Raleigh, NC 27602 Docket Nos. 50-325 and 50-324 License No. DPR-71 and DPR-62 Facility Name:
Brunswick 1 and 2 Inspection Conducted:
September 8 - October 1, 1990 l
1nspector:
WA&n A_
/C//B/fo R. L~ Prevatte g/
/
Date Signed Accompanying Personnel:
W. Levis D. J. Nelson M. C. Shannon
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/0M8!fo Approved by:
k C
b R. Carrpril, Acting Section Chief Date 54gned Division of Reactor Projects SUMMARY Scope:
This routine safety inspection by the resident inspectors involved the areas of maintenance observation, surveillance observation, operational safety verifi-cation, Engineered Safety Feature system walkdown, onsite Licensee Event Report review, non-routine reporting program, and action on previous inspection findings.
Results:,
i Lin the areas inspected, a licensee-identified non-cited violation involving reversed local-power range monitor connector cables was identified, paragraph x
- 4.a. _ An _ unresolved item involving the apparent failure to maintain access control'to a ' locked high radiation area was also identified, paragraph 6.a...
Additionally, a weakness involving operator knowledge of the proper use of the intermediate range monitor bypass switch was identified, paragraph 4.b.
Unit 'I was o]erated at 100 percent power until shutdown on September 27, 1990, for a:22 weee refueling outage. After the unit was separated from the grid, a reactor scram occurred, paragraph 4.c.
Unit 2 was operated at 100 percent power until a reactor scram occurred on September 27, paragraph 6.b.
The 9010290377 901018 PDR ADOCK 05000324 O
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- resident' inspectors observed the' trip-on Unit 2 from the control room and noted
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~ that'-the operators responded well-to this event.- During the trip review,' it
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. was notedithat.the chairman and four other members of the licensee's Scram
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m LIncident:-Investigation Team had not received root cause training.
Unit-2 was
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- restarted-on September 30, 1990.
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REPORT DETAILS 1.
Persons Contacted Licensee Employees
- K. Altman, Manager, Regulatory Compliance F. Blackmon, Manager, Radwaste/ Fire Protection
- S. Callis, On-Site Licensing Engineer
- G. Cheatham, Manager, Environmental & Radiation Control
- J. Harness, General Manager, Brunswick Steam Electric Plant
- W. Hatcher, Supervisor, Security
- R. Helme, Manager, Technical Support
- J. Holder, Manager, Outage Management & Modifications (OM&M)
- M. Jones, Manager, On-Site Nuclear Safety - BSEP
- B. Leonard, Manager, Training
- J. Moyer, Technical Assistant to Plant General Manager J. Simon, Manager, Operations Unit 2
- W. Simpson, Manager, Site Planning and Control
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R. Starkey, Vice President, Brunswick Nuclear Project
- R. Tart, Manager, Operations Unit 1
- R. Warden, Manager, Maintenance
- K. Williamson, Manager, Engineering Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, office personnel, and. security force members.
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- Attended the exit' interview Acronyms ' and-initialisms used in the report are listed in the last paragraph.
-2..
~MaintenanceObservation(62703)
The. inspectors observed maintenance activities, interviewed personnel, and reviewed records to verify.that work was conducted in accordance with
. approved procedures, Technical Specifications, and applicable industry-codes 'and-standards. The inspectors also verified that:
redundant'
components were operable; administrative controls _were followed; tagouts.
- were adequate; personnel. were qualified; correct replacement parts were used; radiological controls were proper; ~ fire protection was adequate; quality control holdJpoints were adequate 'and observed; adequate post-maintenance testing was performed; and independent _ verification require--
ments were, implemented.
The inspectors independently verified that selected equipment was properly returned to service.
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Outstanding work requests were reviewed to ensure that the licensee gave
priority to safety-related maintenance.
The inspectors observed / reviewed i
portions of the following maintenance activities:
90-ANRT1 2A Conventional Service Water Pump 90-AMIP1 Calibration Check of level Transmitter 1-821-LTM-N024B-1-1 i
90-AQBD1 SLC Pump 1A Discharge Check Valve
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On September 12, 1990, Maintenance personnel removed one of the doors to i
the control room to replace its hinge. This door is a CBEAF boundary and j
TS fire door.
Removing the door renders CBEAF inoperable, as well as g
removing the fire barrier.
At the time, an appropriate fire protection j
LC0 was in place, but an LC0 had not been established to recognize the
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impact on CBEAF.
The WR/J0, 88-APIA1, was initiated to correct door frame interference when the door closes.
The initial scope of work was for hinge screw tightening only (no door removal), therefore, the initial
shift foreman review did not result in an LC0 for CBEAF.
Subsequently.
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the work scope was changed to include door removal, but the WR/JO was not resubmitted for additional Shift Foreman review as required by Maintenance procedure MMM-03, Corrective Maintenance.
The WR/JO was resubmitted, however,. to the Radwaste/ Fire Protection Shift Foreman and the fire l
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protection LC0 was generated. When the door was subsequently removed, the Unit 2 SCO heard the work taking place and investigated.
At that point, l
the lack of a CBEAF LC0_was discovered and initiated.
No safety signifi-
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cance exists 'since. the maintenance was completed prior to exceeding the i
CBEAF,LCO.
No TS violation occurred.
The inspector concluded that this event was another example of the licensee's previously identified weakness in work control.
This case illustrates the importance, of intergroup
communication and the reat,on for the' MMM-03. requirement for re-approval-
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for WR/JO-scope ~ changes.
The control room ~ door is one of the dual function doors (i.e., TS and fire.
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barrier) that have been the subject of previous fire-protection violations.
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'In'those cases the TS LCOs were accommodated, but the fire protection LCOs
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were missed.
The example discussed above indicates that the licensee has
.j been successful in ensuring that fire protection administrative controls l
are met.
Violations and deviations were not' identified.-
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3.
Surveillance.0bservation(61726)'
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The inspectors observed surveillance testing required by TS.
Through
' observation, interviews, and record review the inspectors verified that:L
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tests conformed to TS requirements; administrative controls were followed; personnel-were qualified; instrumentation was calibrated; and. data was-
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accurate and complete.
The inspectors independently verified selected
test results and proper return to service of equipment.
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The inspectors witnessed / reviewed portions of t"
following test activities:
1-MST-RCIC15M RCIC Steam Leak Detection Channel Functional Test 1-MST-RPS11W Main Steam Line High Radiation Channel Functional Test 2-MST-RSDP21Q RSDP and RTGB Panel Reactor Water Level Indication Channel Calibration 1-MST-PCIS29M PCIS Reactor Water Level LL2 and LL3 DIV 11 Trip Unit SP-90-027 Stroke Testing Core Spray Valves Under Differential Pressure and Flow Conditions for NRC GL 89-10 Unit 1 experienced a reactor scram from approximately 20 percent power on September 27, 1990.
(Details of the scram are discussed in paragraph 4.)
The scram was caused during the performance of PT-40.2.10, Turbine Control /Stop Valves Tightness Test.
This test determines the' presence of turbine control and stop valve leakage with the generator separated from the grid, and is not required by TS.
The test had never been performed on Unit 1 and only once before on Unit 2.
The portion of the test.which caused the scram involved stop valve
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.. tightness, in which all stop valves are shut and the control valves are fully open.
This is not a normal configuration for the stop/ control valves and is achieved by placing a jumper in the EHC circuitry to cause
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the stop valves to close-and control valves to fully open.
Prior to this, reactor pressure was controlled automatically by the turbine bypass
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- valves, bypassing steam to the condenser in conjunction with rolling the turbine with the generator disconnected. When the stop valves closed, the
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bypass valves accommodated the decreased flow to the turbine.
When~the t
control, valves fully opened, the EHC system responded by partially. closing
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the bypass valves to maintain the maximum combined allowed steam. flow at
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the value determinedL by the maximum combined flow limiter (i.e., ' set at
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110 percent).
The fully open control-valves represented 100 percent steam-flow to the EHC system although no steam flow was actually present because-of the shut stop valves.
The maximum combined flow limiter caused the
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- bypass valves to shut.to the remaining 10 percent value of the 110 percent limit.
Since reactor power was at approximately 20 percent, an excess steam supply of approximately.10 percent.was present, causing reactor:
pressure to increase. The pressure increased for approximately one minute'
until the high pressure scram occurred.
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- The inspector reviewed the test precedure and determined-that it did not include instructions to raise the maximum combined flow limiter to a value
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high enough to accommodate the existing reactor power.
For 20 percent
- reactor power, the limiter needs to be set to at least_120 percent..The
' limit is easily adjusted by a potentiometer on the control-board.
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The licensee stated that the test procedure was developed based on a GE recommended procedure GEK-25406A, Valve Tightness Test, and a corre-sponding fossil plant procedure.
The inspector reviewed the GE procedure
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and noted that the maximum combined flow limiter is not addressed.
The licensee suspects that the stop valve load limit switches should have prevented the control valves from going full open, thereby eliminating the maximum combined flow limiter from use.
The GE procedure states, however, that the control valves will fully open. This was still under investiga-tion at the close of the reporting period.
The licensee's Silt investigation was still in progress at the close of the reporting period.
Further inspection will be conducted pending its completion.
Violations and deviations were not identified.
4.
Operational Safety Verif tation (71707)
The inspectors verified that Unit I and Unit 2 were operated in compliance with TS and other regulatory requirements by direct observations of activities, facility tours, discussions with personnel, review of records,
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and independent verification of safety system status.
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The inspectors verified that control room manning requirements of 10 CFR 50.54 and the TS were met.
Control operator, shif t supervisor, clearance, STA, daily and standing. instructions, and jumper / bypass logs were reviewed to obtain information concerning operating trends and out of service safety systems to. ensure.that there were no conflicts with. TS LCOs.
Direct observations; of ' control room panels and instrumentation and recorder traces important to safety were conducted to verify operability and that operating parameters were within-TS limits.
The inspectors observed shif t. turnovers to verify that system status continuity was maintained.
The inspectors verified the status of selected control room
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Operability of a selected ESF division was verified weekly by ensu'ing tlat: each accessible valve in the flow path was in its correct porition; each power supply and' breaker was closed.for components that must activate upon initiation signal; the RHR subsystem cross-tie valve for each unit was closed with the power removed from the valve operator;- there' was.no leakage - of major components; there,was ' proper lubrication and cooling water available; and conditions did not exist which could prevent fulfill-ment of the system's functional requirements.
Instrumentation essential to system actuation or performance was verified operable by observing-on-scale indication and proper-instrument valve-lineup, if accessible.
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The inspectors verified that the licensee's HP policies / procedures were i;
followed.
This included observation of HP practices and a review of area surveys, radiation work permits, postings, and instrument calibration.
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j The inspectors verified by general observations that:
the security organizatio') was properly manned and security personnel were capable of
performing their assigned functions; persons and packages were checked prior to entry into the PA; vehicles were properly authorized, searched and escorted within the PA; persons within the PA displayed photo identi-
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fication badges; personnel in vital areas were authorized; effective compensatory measures were employed when required; and security's response to threats or alarms was adequate.
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The inspectors also observed plant housekeeping controls, verified position of certain containment isolation valves, checked clearances, and verified the operability of onsite and offsite emergency power sources.
a.
Crossed LPRMs The inspector reviewed Plant Incident Report 90-041 dated July 25, 1990, which described the details and circumstances surrounding the discovery of some incorrect LPRM-inputs to the APRMs.
On June 19, 1990, the system engineer, while reviewing S/U data, noted that two LPRMs had inconsistent readings when compared to other LPRMs in the.
same vicinity. LPRM configuration was then checked by moving control rods in the vicinity of the detectors.
LPRM response indicated that the two LPRMs had their cables reversed.
The LPRMs were then bypassed and WR/J0s initiated to correct the problem.
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As a result, the licensee reviewed other startup data for both units i
and performed an LPRM configuration verification by performing-
As a result of these reviews and testing, a total of
eight LPRMs were found with their cables possibly reversed.- Six of these LPRMs were on Unit 1 and two on Unit 2.
The licensee theorized that these cable reversals occurred during their cable replacement j
which occurred! in 1986.-
The licensee concluded this, based on
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additional review of S/U data.
No anomalies were found prior to the j
~ cable replacement.
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The licensee evaluated the affect of these reversals on thermal
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limits.during the subsequent-fuel. cycles and determined that there was no - adverse impact on thermal limits.
The licensee further l
concluded that the APRMs would have been able to perform their safety l
l function because at least one APRM in each RPS trip system was not affected by' the swaps.
Further analysis on the operability of the APRMs is'being conducted by= General Electric.
Corrective actions for _
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the event include installation of tags on the LPRM cables,
-strengthening procedures for-independent verification for undervessel l,
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work, and the development and implementation of a procedure to verify LPRM detector configurations after each refuel outage when work has
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been performed that could affect the configuration of the LPRMs.-
The licensee's identification and resolution of this issue was good.
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One weakness noted Lwas. that the -TS operability regarding the: number of LPRM inputs to the APRMs was not addressed.
TS table 3.3.1-1
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requires eleven total LPRM inputs to a channel and at least two per level.
Furthermore, at least two APRMs per channel are required for the APRM portion of RPS to be operable.
After questioning by the inspector, the licensee checked the operability of the APRMs regarding TS input requirements.
Consequently, it was found that APRM A and F on Unit 1 were inoperable and-APRM C was inoperable on
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Unit 2.
The licensee is investigating further to determine if there were any times when less then two per channel were operable.
The failure to install the LPRMs to the assigned APRM channe.1 and the failure to report the event to NRC within the required 31 day time period via LER is a Violation:
LPRM Cables Reversed, 325,324/
90-37-02.
However, this licensee identified violation is not being cited because criteria specified in Section V.G.1 of the NRC Enforcement Policy were satisfied.
b.
APRM Downscale Trip On September 14, 1990, the inspector questioned the Unit 1 SF concerning actions taken concerning the inoperability of IRM H.
This IRM channel had been declared inoperable the previous day due to a power supply problem. Tracking 1.C0, TI-90-1815 was initiated and the IRM function switch was taken to " STANDBY" to ensure that the APRM downscale with companion IRM upscale trip function required by TS 3.3.1 remained operable.
In addition, the SF had the IRM " BYPASS" selection switch on the RTGB taken to " BYPASS."
The inspector reviewed the logic ' diagram and determined that by taking the selection switch to " BYPASS" he had negated the previous actions taken to ensure that'the APRM downscale trip was operable.
During'this time, the required number of APRMs per trip system were operable.
Therefore, no violation of TS 3.3.1 occurred.
However, this event did demonstrate a lack _of knowledge on the operator!s part in the logic of the APRMs.
The inspector also noted that no pro-cedural guidance existed to detail operator actions when an IRM was inoperable.
The licensee initiated a Plant Event Incident Report to further determine the cause 'along with the. recommended corrective actions, c.
Unit 1; began a controlled shutdown for its refueling outage on September 26, 1990.
At'3:48 a.m.,-on-September 27, a reactor scram occurred. from 22 percent power due to reactor high pressure.
The generator had already been separated from the grid at the time'of the
. scram.
Periodic Test PT-40.2-10, Turbine Control /Stop Valves Tight-
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-ness Test, was'being performed to test the main turbine control and.
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stop. valve steam shut off capabilities.
The reactor high pressure l
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was caused by the EHC system causing the turbine bypass valves to
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partially close during the PT; The details-of the tast are discussed in paragraph 3.
All cods inserted a.: required.
The highest indi-cated reactor pressure was 1037.3 psig.
The TS required scram
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setpoint is less than 1045 psig.
The lowest reactor level reached-
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was 167_ inches (normal 182 to 192).
No other ESF or ECCS actuations occurred.
The licensee made a proper NRC notification of the event in accordance with 10 CFR 50.72.
The licensee's Silt had.not con-
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cluded their investigation of the event at the close of the inspec-tion period.
Further NRC review will be conducted upon receipt of I
the licensee's LER.
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One non-cited violation was identified.
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5.
ESFSystemWalkdown(71710)
The CAD system was reviewed in detail to determine the overall material
condition of the system and assess its ability to perform its design
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function. Outstanding WR/J0s were reviewed along with OP valve lineup and
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surveillance testing requirements. Accessible portions of the system were walked down.to verify valve positions.
Portions of this inspection, which l
included a review of the design of the system and FSAR commitments, were
performed and documented in Inspection Report 90-26.
This repo t noted
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single failure-concerns, 'one valve not in its proper OP lineup, and two other valves where the 0P lineup differed from the PalD.
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The inspector noted that the licensee has made progress in correction of-previous CAD deficiencies.
System leaks were found with the use o' leak detection equipment which allowed the vacuum of the system to be brwght within specification.
As part of the improvement plan, a test of the CAD i
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system demonstrating the ability to inject. nitrogen is scheduled tenta-tively for the end of November 1990.
The inspector noted'that the name plate loading pressures _ indicated ~ for the FCVs differed for the two valves.
FCV-2717 indicated a loading pressure of 5 pounds and FCV-2720
indicated-a loading pressure of 35 pounds.
The licensee was evaluating q
which pressure - was correct, if either.
The technical manuali for the
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system does' not specify the correct pressure.
These apparent pressure
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problems do not affect the' operability. of the valves, as they are cycled j
on a periodic basis and because the licensee demonstrated that they could j
. manually operate the. valves.
The inspector noted that the licensee does not enter' the TS Action Statement for the CAD system when a containment vent valve is inoperable.-
TS 3.6.6.2.a requires that the CAD system have an operable flow-path capable of supplying. nitrogen to the drywell. The inspector reasoned that
a vent path must exist'for an injection path to be operable to ensure.that=
an overpressurization condition does not occur. The inspector also noted
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that NUREG-0737, l_ tem II.E.4.1 states that the. CAD system-is considered.to J
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be a purge system. _.The -licensee is evaluating their position on this issue.
4 Resolution is' currently scheduled for_ November 8, 1990.
li Violations and deYiations' were not identified.
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6.
Onsite Follow-up of Events (93702)
a.
Unlocked High Radiation Area Door On September 21, 1990, at 9:44 p.m., the licensee discovered that locked high radiation door, Unit 2 turbine building 70 foot elevation northeast entrance, was not locked as required by 10 CFR 20.203, TS 6.12.2 and E&RC-Procedure 0040, High Radiation Area Key Control.
The area was then searched for personal and locked as required.
An investigation into the event revealed that the locking mechanism was faulty and mechanical binding of the door to door frame would result in having to apply more than normal force to open the door.
Further investigation by the licensee additionally revealed that Operations (radwaste) personnel had previously entered the space to
= perform a routine test on fire protection valves.
Upon leaving the space, they had closed the door and, due to the binding, thought it -
was locked. ' This condition was discovered approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
'later by HP personnel during their routine tour of spaces.
This has been a recurring problem.
Similar events with locked high radiation doors being left open were identified on April 20,'1989, July 20, 1989, October 7,1989, January 5,1990, January 20, 1990, and August 3, 1990.
After the first five events and the issuance of violation 325,324-90-06, the licensee provided additional training to
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Operations and E&RC personnel, improved the maintenance on.the affected doors, and revised E&RC Procedure 0040 to provide cen-tralized control over the issuance of keys to locked high radiation areas.' This is the second identified occurrence of this type since
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implementation of the above measures.
Based on the above, it appears that the licensee's corrective actions may not have fully resolved this problem.
This is identified-as a URI:
Apparent Failure to Control Access to A High Radiation Area, 324/90-37-01.
Further follnw-up of.this item will be performed by Regional HP specialists.
-After identification of.this event, the plant manager directed that entry to high radiation areas requires the presence of E&RC personnel to ensure that the spaces are relocked af ter entry. ' Discussion with NED by the= inspector indicates that they are. preparing to. issue a modification to structurally upgrade the access door for the affected high radiation areas. This work will be performed by-PCN No. B0050A.
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b.-
Unit 2 Scram'of September 27, 1990-Unit 2 tripped on September 27, 1990, at 8:30 a.m.,-from 100 percent power due ~ to. generator load reject' caused by loss of excitation to the main generator.
The unit had been experiencing problems with erratic voltage regulator output approximately two hours prior to the trip.
The electrical perturbations experienced at the time of-the trip also caused some group isolations and certain equipment-to-trip on undervoltage. 'SRVs A and B lifted' automatically and SRVs E and F
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were lif ted manually to help maintain pressure.
Because some questions existed concerning SRV performance, an Unu.,dal Event was declared at 8:53 a.m.
The event was terminated at 10:02 a.m. after the MSIVs were reopened, thereby establishing normal pressure control.
Licensee investigation after the event concluded that peak pressure during the event was 1112 psig and that the SRV performance was satisfactory.
The inspectors were present in the control room during the trip and observed that the-operators performed well.
They were properly focused on important plant parameters and demonstrated the ability to operate the necessary plant systems to respond to the event.
E0P usage was good and the proper classification and reporting of the event was accomplished.
This performance was an improvement to the
. operator response following the August 19, 1990 scram of Unit 2.
The licensee was continuing their investigation into the cause of the trip at the end of the inspection period. The licensee believes that an-improperly adjusted or faulty voltage regulator was the reason that the generator lost excitation.
The inspector will review the cause of the trip and actions of the licensee's SIIT following the issuance of the LER.
The licensee's SIIT is normall'y composed of ten members.
The inspector noted that half of the team members investigating this event, including the team chairman, had not received root cause training.
The inspector considered this to be a weakness.. If an investigation team is to be effective they should receive all avail-
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able training and have access to all available information.
This-weakness of the SIIT.- was discussed with _ plant management who
- acknowledged the inspector's' comments, but did not necessarily agree.
The.-licensee = felt that the members of,the team were adequately trained and could perform their job: properly.
Violations and deviations were not identified.
7.
- 0nsiteReviewofLicenseeEventReports(92700)
The below listed LERs were reviewed = to verify that the information
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-provided met NRC reporting requirements.
The verification included
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adequacy of event description and corrective action taken or planned, existence of potential generic problems and; the. relative safety. signifi -
cance cf the event, _0nsite inspectiors were performed and' concluded that
,1(necessary corrective : actions have been takenlin -accordance with existing-
' requirements, license conditions, and commitments, unless otherwise.
stated.
- a.
(CLOSED)
LER 1-88-02, Auto-Isolation of RWCU System Due to' Spurious Actuation of the 1 Steam Leak Detection Instrumentation.
This LER
. discussed the auto close of one-RWCU system valve when a circuit
. breaker was closed to restpply the Unit 1, steam leak detection
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system. The licensee implemented Operations standing instruction No.
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88-20 to inform the operators of the potential for actuations following re-energization. The licensee has also scheduled modificc-
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tions to both units during 1990, to install time delays to prevent.
spurious actuations.
b.
(CLOSED)
LER 1-88-04, Primary Containment Group 3 Isolation While Placing RWCU System Filter /Demineralizer in Service.
This LER
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discussed the Group 3' isolation caused by a flange leak.
The licensee inspected and replaced several flange gaskets. The licensee also inspected the piping supports and repaired three displaced rigid struts and one snubber, c.
(CLOSED)
LER 1-88-05, Limiting Condition for Operation for Primary Containment Oxygen Concentration Exceeded.
This item detailed the r
licensee's failure to meet a TS LC0 required plant shutdown time
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requirement.
Deinerting of the Unit 1 primary containment was in progress in support of a scheduled shutdown.
Oxygen concentration reached 4 percent and shutdown of the Unit was subsequently initiates as required by TS, but problems with the rod sequence control system
~
delayed shutdown past the specified TS time limits.
The inspector had no further concerns,,therefore, this item is considered closed.
d.
(CLOSED)
LER 1-88-06, Bolt Head Failures of 5/16 Inch x 1/2 Inch Silicon Bronze Carriage Bolts in Bus /Bar Connections of Electrical Switchboards.
This LER detailed the multiple failures of silicon bronze carriage bolts that provided bus /bar connections. The inves-tigation of 'the bolt failures indicated that the failures were caused by stress corrosion cracking.
Sampling of the various electrical
~ panels.could not find any indications of an associated corrosive
,
material-'in the ' air.
Stress on the -bolt head could have been from the nanufacturing : process or from overtorqueing of.the bolts when-initially-installed or replaced.
Both.tafety and non-safety-related plant -MCCs and switchboards. have Lbeen inspected and all accessible silicon bronze carriage bolts were replaced with medium carbon steel bolts.
The silicon bronze bolts not accessible' were evaluated by the licensee and found to be
<
- acceptable..
.
e.
(CLOSED)
LER 1-88-14, Non-Conservative -Setpoints of Steam Leak Detection Instrumentation for RCIC and HPCI.. This LER discussed the non-conservative setting of the steam line high; flow actuation instrumentation' setpoints.
The setpoints were-recalculated and recalibrated.with the correct values.
An additional problem of one t
'
'
instrument being. connected -improperly was also discussed.
The high and. low taps were' properly connected and the instrument was returned to service.
H
_ CLOSED)
LER.1-88-17, Inoperability of High' Pressure Coolant (
f..
Injection System Due to Failure of the' Steam Inlet Isolation Valve.
L i.-
_ _ _ _ _ _ _ - _
._
f4
,.
)
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This LER detailed the failure of the HPCI steam isolation valve to open on demand and the resulting failure of the motor windings. The j
motor operator was replaced, the actuator gears were modified and a
'
larger power supply cable was installed.
Due to the potential for thermal binding of the HPCI steam inlet isolation valve during the first two hours after system warmup, appropriate operating procedures j
for Units 1 and 2, OP-19, and test procedures for Units 1 and 2,
'
PT-9.2 and PT-9.3, have been revised to include a four hour minimum warmup.
This LER was. investigated further by the licensee to determine any
'l generic concerns with DC M0V operators.
Corrective actions were completed following the investigation and these included by-passing various starting resistors, relocation of valve operators, replace-ment of valve operators with higher capacity motors, and evalua+1on of design operating margin.
Further evaluations and testing will be completed as required by NRC Generic Letter 89-10, Safety-Related Motor-Operated Valve Testing and Surveillance.
.g.
(CLOSED)
'LER 1-88-23, Reactor Scram Due to High Reactor Level Resulting from a False Low Reactor Level Signal to the Reactor Master Controller.
This LER discussed a high level reactor trip caused by corroded ~ contacts in the feedwater master control circuit.
The corroded relay contacts were analyzed and recommendations-are in place if further relay failures occur.
Also, during the plant
-
recovery, IRM. C, D, and H failed to drive in on demand.
Trouble shooting and. repairs were completed on all IRMs during the November 1988 refueling outage.
h.
(CLOSED)
LER 1-88-25, Failure to Meet Local Leak Rate Testing Technical Specifications.
This LER discussed several valves that failed to meet the leakage requirements of the TS. All of the valves were initially repaired, in some cases with the assistance of a
,
vendor representative.
Valves that have had a history of repetitive failurcs were further evaluated for application and proper material, and were modified.as needed..Some of the valves were replaced during the recent Unit 2 outage and others are scheduled to be replaced during the present Unit 1 outage..
i.'
(CLOSED):
LER 1-88-28, Pipe Crack Indications Revealed Through
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Generic Letter 88-01 Testing.
This LER discussed. the 238 crack indications found during ultrasonic examinations of the reactor coolant system. piping.
The cause for the crack ' indications was
,
attributed.to intergranular stress corrosion cracking.
Initially,
<
weld overlays were performed and the units were operated for one cycle. _ Unit 2-has replaced the cracked piping ~ and Unit 1 plans to replace the affected piping during the present outage.
J.
(CLOSED)
LP,1 A8-33. Ciu2 ion of Valve Body Internal Areas in Residual Heat Removal System Isniation Valves Due to Throttling Below r
m
[,'
%
,j
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,
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the Design Flow Range.
This LER detailed the flow erosion of four RHR isolation valves.
The affected valves were repaired during the Unit 1 1988 outage.
A Special Procedure SP-89-025 was performed to determine if a throttled position would reduce or eliminate the flow cavitation in the valve.
It was determined that cavitation always i
!
occurred.
s b
The system engineer was given the task to monitor the operating hours
,
on the affected valves and to determine future surveillance require-ments.
The affected valves had no previous history of erosion and the associated Unit 2 valves had not experienced the same erosion problem, k.
-(CLOSED)
LER 2-88-01, Manual Reactor Scram Due to Decreasing Main
'A Condenser Vacuum and Failure of Primary Containment Group 2-Valve to Close on an Isolation Signal.
This LER documented the failure of four primary containment Group 2 valves to close on demand.
The j
investigation of the-ASCO solenoid indicated that the failure to J
stroke could have been a catalytic reaction between the solenoid seating ~ material and copper valve body which was accelerated at high temperatures.. High temperatures are generated with valves that are
continuously energized.
The ASCO solenoids susceptible to this
'
failure were modified wtth different seating material per EER 90-76, 1.
(CLOSED)- LER 2-88-04, Unplanned Automdtic Starting of Standby Gas i
Treatment and Automatic Isolation of Reactor Building Ventilation During Surveillance Testing.
This item detailed a blown fuse event attributed to accidental shorting of test equipment.
The fuse was replaced, equipment was returned to service, and technicians were
counseled on awareness and control of test equipment, j
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m.
(CLOSED)
LER 2-88-14 PCIS Group 5 Isolation of RCIC Inboard Steam
Supply Isolation Val /e During Monthly Operability Test.
This item j
detailed a Group 5 isolation signal generated from an I&C tech-
.l nician's error while hooking up test leads. This error was discussed
during real time training sessions and the licensee has implemented a
. program to. install banana plugs per EER-89-0186.
,
i n.-
(CLOSED)
LER 2-88-15, Failure to Meet Limiting Conditions for
'
Operations.
This LER discussed the entry into mode 2 by placing the i
mode switch in startup although various LCOs, required for entry into'
mode 2, had not been met. The licensee initiated a standing.instruc-i tion (88-42) for proper operation of the mode switch, provided real
'
time training to the operations staff which detailed this event, and
',
revised various startup and operating procedures to provide better
. guidance for mode switch changes..
- o.
(CLOSED)
LER 2-88-16, Division 11 Service Water Vital Header Leak Resulting in a Manual Isolation of the Associated Header.
This LER detailed the failure, due to corrosion, of a-carbon. steel flange and the resulting manual isolation of the associated header.
A copper
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nickel - flange was installed to replace the failed flange.
The licensee also reviewed plant records to verify proper material usage, performed inspections for _ leaks on the system, has a QC inspection function in place to identify incorrect material replacement, and has replaced portions of the vital service water header and valves per
Modification 87-240, p.
(CLOSED) LER 2-88-17, ESF Closure of a HPCI Vacuum Breaker Isolation Valve During a Channel Calibration.
This item detailed the HPCI vacuum breaker closure caused by a dropped test ' equipment lead,
-The licensee has implemented a program to install banana plugs, for o
test equipment, as deemed necessary.
To date, 86 banana plugs have been installed per EER-89-0186.
q.
(CLOSED)
LER 2-88-18, Reactor Scram Due to Turbine Control Valve Fast Closure on High Level Turbine Trip Caused by Loss of Power to Feedster Control Logic.
~This LER detailed the loss of a topaz inverter which resulted in a loss of power to the feedwater control logic which caused excessive feedwater flow and ultimately a high level turbine trip.
The topaz inverter failed due to the high input
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voltage trip setpoint drif ting down to the equalizing voltage
'
setpoint of=137V DC.
In the future, spare units will be powered-up to provide a_ longer burn in period prior.to installation.
Following the trip, the HPCI pump tripped on low suction header pressure.
The HPCI low suction header trip has been removed due to spurious'actuations during subsequent pump testing.
,
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Also. the MSIV limit switch was reset to provide valve closure indication and the reactor vessel drain line was unplugged during the i
Unit 2-1989 outage by using Special Procedure 89-041 for hydrolasing,
- which will reduce the lower head cooldown rate.
r.-
(OPEN)
LER 2-90-04, Manual Reactor Scram'Due to Failure of SRV '?G".
'
to Close During Startup Testing.
This event occurred on March 13,.
1990, and was initially discussed in Report 325,324/90-11.
The suspect air operator solenoid assembly _was sent to Wyle' Laboratory.
for: investigation =by Target Rock', the valve manufacturer. - Dirt and
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debris' of unknown material and origin was found imbedded in the solenoid valve's soft seating material of:its back seat.
This
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condition caused misalignment which allowed the solenoid valve,to remain partially open when de-energized.. This condition enabled the pneumatic supply.to continue to provide pressure to the air operator allowing the SRV to remain open.
.
-The dirt and det ris was.not analyzed prior to being discarded.
The licensee suspects' that the foreign material came from the-pneumatic nitrogen / instrument air system.
No other solenoid failures have occurred since this failure including manual SRV cycles associated with Unit'2 reactor scrams of August,19 and September 27, 1990, and
'
during testing of all Unit'2 SRVs following setpoint verification n-
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subsequent to the August 19 scram.
The licensee is considering inspection of SRV nitrogen supply tubing during the current Unit 1 outage to assess the cleanliness of the system.
The licensee has extended the LER Supplement issue date to March 19, 1991.
Violations and deviations were not identified.
8.
Non-Routine Reporting Program (90714)
This inspection reviewed the licensee's procedures for compliance with NRC
!
reporting requirements as specified in 10 CFR 50.72 and 50.73.
The inspector reviewed the licensee's procedures for review and evaluation of off normal events, maintenance activities, testing, and outage activities which included:
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Al-65 Incident Reporting and Control, Rev. 6 01-51 NRC 1-Hour, 4-Hour, and 24-Hour Reporting Requirements, Rev. 5 01-56 Operations Conditions Adverse to Quality Process, Rev. O PLP-04-Corrective Action Program, Rev. 3
.
MMM-003 Corrective Maintenance (Automated Maintenance Management
System), Rev. 6 I
ENP-20 Engineering Work Request, Rev. 11 Responsibility and administrative controls for the prompt review and evaluation of off normal events to assure. identification of safety-related-
- events,' was ' detail'ed in Operating Instruction ~ 01-51.
Engineering work requests receive an Linitial review for reportability by the' assigned Technical.. Support supervisor per Engineering ' Procedure ENP-20. -Main-tenance work requests' require an LC0 checkoff and a subsequent report--
ability review by the shift foreman, per the Maintenance Management Manual
Procedure MMM-003.
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Administrative controls for reporting safety-related events : internally and to.the NRC were detailed in Administrative Instruction Al-65 and Operating Instruction 01-51.
Administrative controls for completion of corrective' actions were detai' icd
<
in Operating ~~ Instruction 56 and Plant Program Procedure PLP-04.
. Vendor Bulletins and Circulars were reviewed by the Onsite Nuclear Safety cGroup and distributed as appropriate.
I Violations and deviations were not identified.
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9.
Action on Previous inspection Findings (92701)
a.
(CLOSED)
Unresolved Item 325,324/90-26-02, CAD System Does Not Meet Single Failure Criteria, in restonse to this issue, the licensee has prepared three EERs.
EER-90-0174, dated July 27, 1990, addressed problems with the Unit 2 V49 valve and its as',ociated ground.
The EER concluded that -the valve was operable Mtb the known ground subject to periodic testing.
Subsequent to the issuance of the EER, the junction box containing the terminations for this valve was cleaned and moisture removed causing the ground cordition to clear.
EER-90-0182, dated August 21, 1990, addressed deficiencies with respect to the system failing to meet separation criteria for-selected CAD components.
Plant Modification 90-051 was developed and implemented to resolve concerns with the proper separation of CAD components at the local station.
The EER concluded that the discrepant condition was acceptable and that the valves would still
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perform their design function.
'
EER-90-0170, dated August 2 1990, addressed single failure concerns that were noted in - Inspection Report 90-26.
The EER concluded
~ that the system-would be operable if it could be demonstrated that the system could be manually operated locally to inject nitrogen to the drywell.
The system-has no automatic initiation features and is
. required to be initiated 45 days into the accident to maintain oxygen concentration less than 5 percent in the drywell.
2-SP-90-024 was-developed and performed.
This test simulated a loss of E-6 and demonstrated that the system could be operated manually at the local
. station to control nitrogen flow to the-drywell. Long term fixes for the single failure ~ problem are currently under review. The licensee has also revised E0P-01-SEP-05 to require that HV11 or HV12 be opened to place the pressure control station in service.
Based on-the-inspectors review of the EER's, SP and PM, the inspector
~l concluded that the CAD system was opedle and' could perform its design' function even with the noted design deficiencies.
LER 1-90-13
.was issued by the licensee to address the deficiencies.
The final J
._ corrective actions to resolve these deficiencies will be inspected during the LER' closeout.
b.
-(CLOSED)
Unresolved Item 50-325/87-36-02 and 50-324/87-37-02
"
Additional EQ ltemsi Allen-Bradley Nylon 6 Terminal' Block '(TBl;
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Collier PVC Wire; GE CR151 TB; Old Marathon TB; and Additional q
Whitney Blake Wire.
NRC Inspection Report.50-325,324/87-22 J
identified several examples of EQ-violations for unqualified' wire and terminal blocks installed in EQ Limitorque_ Motor -Operators.
The corrective action taken by the licensee was toLinspect all but 33 valves (15 Unit 1 valves and 18 Unit 2-valves).,- The basis for these tvalves not being inspected was that they had been recently-replaced
.with new operators.
During the inspection of the original sample of
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EQ operators, the licensee identified other problems such as additional examples of unqualified wires and terminal blocks, missing T-drains and grease reliefs.
The wire and terminal block problems were identified and tracked by NRC as the above unresolved item.
This item was examined during NRC Inspection 50-324,325/89-24 and the inspector expressed a concern that adequate documented evidence was not available to show that the 33 exempted valve operators are configured with functional T-drains and grease reliefs and that internal wiring is not in close proximity or touching the limit switch compartment heaters.
These operators are inaccessible during operation so the licensee - proposed to inspect during the next refueling on each unit. The licensee has informed the inspector that the 18 valve operators on Unit 2 have been inspected and any deficiencies noted-have been corrected.
The Unit 1 valves have been included in the maintenance outage scope for the present refueling.
The licensee also indicated that the internal tracking and closeout of this item will be recorded under FACT 89-B-076.
This item is now considered closed, c.
(CLOSED)
Inspector Followup Item 325,324/88-14-04, Correction of CAD System Hardware Problems.
The. inspector verified through review of-documentation and physical inspection, that the deficiencies noted were corrected. The inspector also noted that the licensee has a CAD upgrade program in effect.
This program has focused primarily on correcting problems in maintaining vacuum in the tank, The licensee has been successful in finding the source of the leaks.
The leaks have been fixed on a short term basis with the use of a sealant.
A permanent fix, which will include replacemenc J several "0'? rings, is scheduled for November 1990. 0ther information concerning the CAD system is discussed in paragraph 5.
d.
.(CLOSED)
Inspector Followup Item 325,324/89-34-11, Followup on
'
Implementation and Effectiveness of Communications Strategy in IAP ltem ' A1.
Licensee. management has. developed and. implemented a strategy to improve: communications with their employees.. This strategy includes communication on. both a formal and.an' informal basis. ' Communication is via oral, video, and through the print media.
Emp.loyees, supervisors, and managers are being given-training-in Managing Relationships at Work and Making Things-Better.= Super-
.
visors are being given training in leadership.
Goals, priorities,
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and: expectations have been developed and issued which tie the goals
.of..the various plant sections to the corporate goals for achieving success.
The use of Total Quality Teams, which encourage employee-involvement :have been continued and enhanced.
A program for moni-toring performance against goals has been established and feedback on erformance 'is-being provided to-employees.
An employee. newspaper p(Monday Memo). is' issued weekly which provides useful information to
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employees concerning current events at the plant and also recognizes.
employees' for special achievement.
Senior managers hold working
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lunches with employees and conduct frequent plant tours.
Feedback is continually-requested from employees'via surveys on problem areas and i
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I on the success of these initiatives.
All of these actions are in addition to the normal meetings and documentation required to connunicate information to run the units.
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Changing the environment in which communication was ineffective, entails a long term process.
The inspectors' determined, from a review of the above initiatives coupled with interviews of licensee personnel, that satisfactory on-going initiatives were being implemented to adequately address the concerns identified in the DET.
This item is closed.
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e.
(OPEN)
Inspector followup Item 325,324/89-34-35, Followup on.
I implementation and Effectiveness of Actions Taken to Ensure Overall
'
IAP Improvements are implementtd/ Adjusted and Performance Monitored as in IAP ltems El and E2, (Both items were previously discussed in InspectionReport90-11.)
LAP ltem E1 - (See discussion of goals in IFl 325, 324/89-34-11 l
above.)
,
IAP ltem E2 - This IAP item was established to assure that improvement programs were properly implemented and monitored.
The licensee's commitments included:
i (1)
Identify programs / initiatives requiring completion at
!
Brunswick.
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.(2) Designate-a project. manager for each project.
l (3): Establish a completion plan for each project.-
(4)
Establish a tracking mechanism for each project.
Inspector review of this IAP item determined that the !.ensee had identified the projects and assigned a project manag-for each I
project as committed.-
However, several projects wert. not being l
adequately tracked to completion as required.
The IAP item,is j
statused as complete by the licensee. The status of each project is -
discussed below.
- Impell FSAR Study
'
f The FSAR' change required to correct the items in this study was n
issued June 1, 1990.. Details concerning the Impell items and a l
listing of the FSAR changes are filed with the IAP item. One item-on i
this study remains outstanding concerning lack of automatic isolation
,
of control room dampers-(reference Design Change 90-36, NCR A-90-007,
.and LER 1-90-07).
The Impell study is considered closed and the
control room damper item will be tracked under LER 1-90-07.
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HPCI SSfl'
b This project is three to four years old.
Nine items still t emain to be corrected.
!
Systems Engineering Training:
This item is reported and tracked as complete by the licensee due to the fact that the project has been identified, a project manager has
been assigned, and the tra'ining program ha; been established.
However, very few systems engineers are fully qualified to the plan.
A one month training status tracking system has been implemented to track this training.
The item will be reviewed in March 1991, to determine the status of training.
EDBS Completion The plan for this project in the IAP file is incomplete in that it does not provide all of the milestones to complete the project.
Action items on the plan are past their completion dates and there is no indication whether the items were completed on schedule.
Very little detail concerning the scope of the project is included in the IAP file.
Clearance Improvement Project Documentation in the IAP file reports this project as complete.
However, the same memo that-closes out the project discusses several items related to clearance control, which are apparently still being worked. This item will be reviewed further in March, 1991.
Technical Staff / Manager Training A manager has been assigned to this project.
The training program for technical staff and technical staff managers was accredited by INPO on July 18, 1990.
The file is not complete.
This item will be reviewed further in March, 1991.
Service Water SSFI This project is being managed and statused correctly.
Thirty one items remain unresolved.
Extensive work is scheduled to be accomplished on this system during the current refueling outage.
This item will be reviewed again in March, 1991.
I Commercial Grade Procurement This project is reported as complete and the documentation to support closecut is filed in the IAP file, s
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(OPEN)
Inspector Followup Item 325,324/89-34-39, followup on Implementation and Effectiveness of Actions to Resolve People issues in IAP ltem Gl. The licensee's action has been further delayed. The
_
corporate program under development with Brunswick as the pilot has a new established completion date of December 31, 1990.
g.
(CLOSED)
Inspector Followup Item 325,324/89-34-40, followup on Implementation and Effectiveness of Total Quality Process initiatives
.:
in IAP ltem G2.
A communication program was established by the t
licensee that included infonning all TQ steering consnittee members of available resources, use of site newsletter and the new video bulletin board.
Included in the program was use of an opinion poll
'_
and subsequent employee meetings.
The results of this poll indicate that twenty percent of the employees felt that the work situation following the OA was unchanged, eighteen percent felt overworked or shorthanded, sixteen percent believed another 0A would prompt future n
y layoffs, and indecision about serving on a TQ team was high among u
respondents who had never been on a TQ team.
Also noted in the conclusions was a positive attitude about CP&L's TQ program from
'
I those who had attended TQ courses, " Managing Relationships at Work l:
and Making Things Better." The most positive change was noted in the area of communication flow.
The licensee has scheduled a future
&
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course for the employees and plans to use another poll in the spring of 1991.
The inspectors reviewed the individual problem statements and results
-
from the nine TQ teams that were recently recognized for their i
achievements on September 10, 1990.
Each group provided satisfactory results for their identified problems.
The licensee's TQ program appears to be adequately administered, providing positivt. benefits towards cost savings, safety, and morale.
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Violations and deviations were not identified.
10. Exit Intervf a (30703)
The inspection scope and findings were sumarized on October 1,1990, with g
those persons inclicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail the inspection findings listed
.
below. Proprietary information is not contained in this report.
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ltem Number Description / Reference paragraph
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324/90-37-01 URI - Apparent Failure to Control Access to a High Radiation Area, Paragraph 6.a.
326,324/90-37-02 NON-CITED VIOLATION - LPRM Cables Reversed.
Paragraph 4.a.
The licensee disagreed with the inspectors' stated observation of a weakness in the area of root cause training for SIIT members, stating that
- _ _ _ _ _ _ _ _ _....
a
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e p
e
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sufficient members of the team had received root cause training and that it was not needed by the entire team.
Additionally, the licensee
-
disagreed with the analysis that the apparent failure to control access to a locked high radiation area may be due to inadequate corrective action since this event was more characterized by defective equipment rather than personnel error as identified in the six previous events.
The licensee felt that issuing a v-6 ion on this event could result in personnel not a
reporting future +
ye es.
The inspectors acknowledged the licensee's
. comments.
11. Acronyms and Initiali ms Al Administrative Instruction A0 Auxiliary Operator APRM Average Power Range Monitor ASCO Automatic Switch Company BSEP Brunswick Steam Electric Plant CAD Containment Atmospheric Dilution CBEAF Control Building Emergency Air Filtration DC-Direct Current DET-Diagnostic Evaluation Team ECCS Emergency Core Cooling System EDBS Engineering Data Base System EER Engineering Evaluation Report EHC Electro Hydraulic Control ENP Engineering Procedure E0P Emergency Operating Procedure ESF Engineered Safety Feature F-Degrees' Fahrenheit FCV-Flow Control Valve
,
-FSAR Final Safety Analysis Report GE General Electric GL Generic Letter HP Haalth Physics HPCI High Pressure Coolant Injection IAP.
Integrated Action Plan 1&C Instrumentation and Control
~1E NRC Office of Inspection and' Enforcement IFl li spector Followup Item-INP0 In titute of Nuclear Power Operations-IPBS Integrated Planning, Budgeting and Scheduling IRM Intermediate Range Monitor-LC01 Limiting Condition for Operation
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LER-
= Licensee Event Report.
LPRM Local Power Range Monitor i
MCC Motor Control Center MMM Maintenance Management Manual-F MOV-Motor Operated Valve mrem Millirem MSIV-Main Steam Isolation Valve-NED Nuclear Engineering Department o
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n-l l-
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(
P-
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i NRC Nuclear Regulatory Commission i
NUREG Nuclear Regulation OA Organizational Analysis i
Operating Instruction OP Operating Procedure l
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P&lD Piping & Instrumentation Data PA Protected Area
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F PCl$
Primary Containment Isolation System
PCN Plant Change Notice
.
PLP Plant Procedure PM Plant Modification
PNSC Plant Nuclear Safety Committee
,
PSI Pounds per Square Inch t
PSIG Pounds per Square Inch Gauge L~
PT-Periodic Test
QA Quality Assuraace r
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QC Quality Control
RCIC Reactor Core Isolation Cooling i
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RSDP Remote Shutdown Panel RTGB Reactor Turbir.e Gauge Board RWCU Reactor Water Cleanup SF'
Shift foreman SIIT Scram Incident Investigation Team l-SP :-
Special Procedure
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SSFI-Safety System Functional Inspection
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S/U-Startup
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E TQ Tothi Quality i
L TS.
Technical, Specification-i L
URI Unresolved. Item i
Vf Volt
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WR/J0; Work Request / Job Order',
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