IR 05000324/1989026
| ML19332C730 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 11/06/1989 |
| From: | Dance H, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML19332C725 | List: |
| References | |
| 50-324-89-26, 50-325-89-26, NUDOCS 8911280480 | |
| Download: ML19332C730 (18) | |
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- /*"'8u9 UNITED STATES
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NUCLEAR REGULATORY COMM'SSION
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REGION ll
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ATLANTA. GEORGI A 30303
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i Report Nos.: 50-325/89-26 and 50-324/89-26 l
i Licensee: Carolina Power and Light Company P. O. Box 1551 Raleigh, NC 27602
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Docket Nos.:
50-325 and 50-324 License Nos.:
DPR-71 and DPR-62 Facilit.y Name:
Brunswick 1 and 2 Inspection Conducted:
September 1 - October 1, 1989 Inspector:
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///[/89 W.11. Ruland g
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~Date'51gned Other Inspectors:
W. Levis D. Nelson D. Carpenter L. Trocine R. Marston S. Shaeffer Approved by:
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// 6 89 Hugh C.[) Projects Section IA Dance, CMief ^
Da'te Signed Reactor 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, small sump lubricating oil, onsite Licensee Event Reports review, in office Licensee Event Reports review, Hutricane Hugo, and loss of annunciators
- Unit 2.
Four regional inspectors augmented the resident staff to monitor the licensee's actions during Hurricane Hugo.
Results:
In the areas inspected, two violations were identified.
A repeat violation occurred involving failure to complete a valve exception form for a valve with a position different than the operating procedure valve lineup.
A violation also occurred when an operator removed a clearance tag on the main control board, without independent verification, and re-hung it on the wrong control
. switch. Both of these violations point to a continuin discipline regarding clearances and valve positions (g problem with operations
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paragraph 4.a and 4.b, respectively).
i B911200490 891106
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PDR ADOCK 05000324 G
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Main control board temperature indicators for the core spray rooms were not maintained calibrated.
These indicators could be used for entry into the secondary contair. ment control emer This problem was considered a program weakness (paragraph 4.c)gency procedure.
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The Unit I drywell was well maintained except a repeat problem occurred with insulation damage to the SRV acoustic monitor cables.
A small amount of peeling paint was noted on piping in the drywell.
This item, while not a safety issue now, was referred to a regional specialist for future followup (paragraph 4.d).
An NRC inspector found three off-color oil sight bulbs during a routine plant tour.
The licensee found that a CRD pump bearing had the wrong oil for almost one year and a RHR SW pump was declared inoperable due to a broken bronze oil flinger ring. This problem was deemed a program weakness (paragraph 5).
The licensee's responses to Hurricane Hugo and a separate Alert were reasonable andprudent(paragraphs 8and9).
An underwater TV camera was pulled into a Unit 2 recirculation loop suction nozzle when the refueling crew attempted to install a plug in the wrong loop.
Further inspection is planned when the licensee issues their incident report (paragraph 4.e).
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REPORT DETAILS 1.
Persons Contacted Licensee Employees i
K. Altman, Manager -Engineering Projects F. Blackmon, Manager - Operations
- S. Callis, On-Site Licensing Engineer T. Cantebury, Manager - Unit 1 Mechanical Maintenance
- G. Cheatham, Manager - Environmental & Radiation Control
- M. Ciemnicki, Security R. Creech, Manager - Unit 2 I&C Maintenance W. Dorman, Manager - 0A
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- K. Enzor Manager - Regulatory Compliance
- J. Harness, General Manager - Brunswick Nuclear Project
- K. Harris, Senior Specialist - Regulatory Compliance W. Hatcher, Supervisor - Security
- A. Hegler, Supervisor - Radwaste/ Fire Protection
- R. Helme, Manager - Technical Support J. Holder Manager - Outage Management & Modifications (0M&M)
- M. Jones, Manager - On-Site Nuclear Safety - BSEP R. Kitchen Manager - Unit 2 Mechanical Maintenance
- J. Moyer, Technical Advisor to Plant General Manager
- J. O'Sullivan, Manager - Training
- D Pate, Shift Operating Supervisor R. Poulk, Project Specialist - NRC W. Simpson, Manager - Site Planning and Control
- J. Simon, Shift Operating Supervisor S. Smith, Manager - Unit 1 I&C Maintenance
- R. Starkey, Project Manager - Brunswick Nuclear Project
- R. Warden, Manager - Maintenance B. Wilson, Manager - Nuclear Systems Engineering Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, office personnel, and security force members.
- Attended the exit interview Acronyms and abbreviations used in the report are listed in paragraph 11.
2.
Maintenance Observation (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
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codes and standards. The inspectors also verified that:
redundant components were operable; administrative controls were followed; tagouts were adequate; personi.cl were qualified; correct replacement parts were used; radiological controls were proper; fire' protection was adequate; i
quality control hold points were adequate and observed; adequate
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post-maintenance testing was performed; and independent verification
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requirements were implemented. The inspectors independently verified that selected equipment was properly returned to service.
Outstanding work requests were reviewed to ensure that the licensee gave
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priority to safety-related maintenance.
The inspectors observed / reviewed portions of the following maintenance activities:
MI-10.4C CRD Solenoid Operated SCRAM Pilot Valves, Core, Diaphram, and Gasket Replacement PM-026 Weld 2-SW-4934, ' Liquid Penetrant Inspection per NDEP-201 89-ATGF1 Torque and Limit Switch Adjustment for 2-SW-V10 89-ATWZ1 Diesel Generator No. 3 Speed Droop Adjustment 89-AUZM1 Annunciator Troubleshooting / Testing
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Violations and deviations were not identified.
3.
SurveillanceObservation(61726)
The inspectors observed surveillance testing required by Technical Specifications.
Through observation, interviews, and record review, the inspectors. verified that:
tests confc,rmed to Technical Spedt1:ation requirements; administrative controls were followed; personnel were qualified; instrumentation was calibrated; and data was accurate and complete. The inspectors independently verified selected test results and l
proper return to service of equipment, l
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The inspectors witnessed / reviewed portions of the following test
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activities:
IMST-DG13R Diesel Generator Loading Test L
IMST-HPCI23M HPCI Turbine Exhaust Diaphragm High Pressure Instrument Channel Calibration l
2MST-DG13R Diesel Generator Loading Test-PT-16.0-1 CAM System Valve Operability Test Violations and deviations were not identified.
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Operational Safety Verification (71707)
The inspectors verified that Unit 1 and Unit 2 were operated in compliance with Technical Specifications and other regulatory requirements by direct observations of activities, facility tours, discussions with personnel, reviewing of records and independent verification of safety system status.
The inspectors verified that control room manning requirements of 10 CFR 50.54 and the Technical Specifications were mat. Control operator, shift supervisor, cicarance, 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 Technical Specification Limiting Conditions for Operations.
Direct observations were conducted of control room panels, instrumentation and recorder traces important to safety to verify
- operability and that ' operating parameters were within technical-specification limits.
The inspectors observed shift turnovers to verify that continuity of. system status was maintained. The inspectors verified the status of selected control room annunciators.
Operability of a selected Enginecred Safety Feature division was verified weekly by ensuring that:
each accessible valve in the flow path was in its correct position; each power supply and breaker was closed for l
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
lubrice. tion and cooling water available; and a condition did not exist which might prevent fulfillment of the system's functional requirements.
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Instrumentation essential to system actuation or performance was verified
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operable by observing on-scale indication and proper instrument valve lineup, if accessible.
The inspectors verified that the licensee's health physics policies / procedures were followed.
This included observation of HP practices and a review of area surveys, radiation work permits, posting, and instrument calibration.
The inspectors verified that:
the security organization 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 identification badges; personnel in vital areas were authorized; effective compensatory measures were employed when required; and security's response to threats or alarms was adequate.
L The inspectors also observed plant housekeeping controls, verified position of certain containment isolation valves, checked a clearance, and i
verified the operability of onsite and offsite emergency power sources.
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Valve Out of Position On September 15, 1989, while flooding up the reactor cavity to support upcoming refueling outage operations, the licensee experienced water leakage into the ncrth RHR sump area.
Further licensee investigation showed that valve 2-G41-F021, the Reactor Well Drain to Dirty Radwaste, was open instead of closed, as required by its operating procedure valve lineup.
This allowed water to drain from the reactor well area to the notth RHR sump.
The valve was
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closed and the leakage stopped.
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The F021 valve had been opened on September 10, 1989, to allow for the draining of the reactor well area following decontamination work.
Initial attempts to drain the reactor well to the hotwell in accordance with section 8.7 of OP-13, Fuel Pool Cooling and Cleanup System Operating Procedure Revision 31, were unsuccessful. The F021 valve was ~ throttled opened with SF permission as an alternate drain path.
No valve exception form was filled out as required by 01-13,
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Valve and Electrical Lineup Administrative Controls, Revision 25.
i This form is filled out for any valve that is out of its normal
operating procedure valve lineup and not controlled by a procedure or clearance.
Instead, the draining of the well to the NRHR sump was noted only on the A0's turnover sheets for September 10 through 12,
1989. - On September 12, the draining evolution was secured in
accordance with section 8.7 of OP-13.
Since the F021 valve was not
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included in this procedure, the valve was left in the throttled position.
q Prior to the reactor cavity flooding evolution, the C0 instructed the i
A0 to verify certain valve positions in the fuel pool cooling system.
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Although not on the list to check, the A0 noted that the F021 valve-was in the throttled position and requested that the C0 verify its i
required position.
The C0 mistakenly identified the valve in the
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valve lineup sheet as V21, a normally open valve, instead of F021, and directed the A0 to fully open the valve.
The cavity fill
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evolution commenced at 7:15 p.m. on September 15, 1989. Leakage.into
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the NRHR sump was identified at 8:00 p.m.
The F021 valve was found open at 10:50 p.m.
Besides the failure to control the position of valve 2-G41-F021 by the use of an 01-13 exception form, the inspector noted other weaknesses:
No procedure existed to drain the reactor well to the NRHR sump.
- The discovery of the F021 valve in the throttled position was still not the correct valve position for the valve, V21, that the CO had mistakenly identified in the valve lineup.
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A proper valve lineup required by the prerequisites to the cavity flood procedure would have detected the valve out of position.
The failure to adequately control the position of valve 2-G41-F021 is a Violation:
Fuel Pool Cooling and Cleanup System Valve Out of Position,(324/89-26-01).
This is' a repeat violation.
Report' No.
89-05 documented the failure to fill out an 01-13 valve exception form for the 2-E11-F0180 valve which was in the open vice locked open position as required by its OP valve lineup.
Based also on last month's inspection report findings (see inspection report 89-20),
control of valve position at Brunswick continues-as a program
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l This event singularly had little safety significance.
The operator found the mispositioned valve within four hours, and no chance.
existed at that time to uncover fuel.
Defueling operations had not-yet started, b.
Misplaced Danger Tap During a routine control board walkdown at approximately 7:00 a.m.,
on September.21, 1989, the inspector found a misplaced danger tag.
Tag No. 6 of Clearance 2-1149 was annotated for valve 2-E11-F070,
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Service Water Injection, control switch, but was attached to an-
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adjacent switch for 2-E11-F073, Service Water Injection.
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inspector informed a control operator who ininediately moved the tag i
to the correct switch.
Both valves were in the correct position (shut) and were under clearance for other work.
Therefore, the i
misplaced-tag resulted in no safety significance.
The. tag had been j
hung only several hours earlier; however, control board walkdowr, by an on-coming control operator had been completed without detecting the error.
l When Danger Tags are hung, Al-58, Equipment Clearance Procedure, step l
5.3.7.3, requires " independent" verification - two persons verify i
that each tag is properly hung.
The licensee determined that this l
occurred in this case.
Subsequent to being properly hung, the operators saw that the above mentioned tag and others associated with the same clearance had not been dated. The undated tcgs were removed.
lJ dated, and rehung without independent verification.
During this process, the tag on valve 2-E11-F075 was rehung on valve 2-E11-F073.
l Since independent verification was not perforr:ed the second time, the L
error went undetected.
Upon discovery of the problem, the tag was K
moved = again without independent verification, although observed by E
the inspector. These actions are not in accordance with AI-58. This L
constitutes a Violation of Technical Specification 6,8.1:
Failure to L
Follow Procedure, (324/89-26-02).
This is not classified as a repeat violation since the previous clearance violations involved inadequate clearance boundaries, not inadequate clearance implementation.
Still, the licensee's problems
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with clearances show a certain lack of discipline within the
licensee's staff, c.
Temperature Control Indicators During a. control room board walkdown, the inspector noted that the temperature for the Unit 2 north and south core spray rooms indicated 108 degrees F and 112 degrees F, respectively, as read from 2-VA-TI-1603 and 2-VA-TI-1604 The inspector questioned the licensee's technical support staff concerning these temperatures and-their effect on the qualified life of EQ components located in these areas.
The licensee's EQ program assumes 104 degrees F as the
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maximum ambient temperature for these areas.
The licensee determined that the temperatures in the vicinity of the EQ components in the core spray rooms was less than 100 degrees F.
Further investigation revealed that the temperature indicators in the control room for Unit 2, 2-VA-TI-1603/1604, have never been
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calibrated.
The instruments had been added to the licensee's PM program in 1986 with a stated calibration frequency of 18 months.
The indicators were due for calibration in November 1988.
The work was not performed and the calibrations exempted due to emergent work.
Plant maintenance procedures allow this practice if other more important higher priority work must be accomplished.
L These temperature indicators are used in the licensee's E0Ps as an p
E0P entry condition for secondary containment control. Specifically,
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. E0P-03-SCCP, Revision 0, requires that this E0P be entered if area
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l temperatures in either core spray room exceeds 120 degrees F.
E0P
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actions at this point require that the licensee's engineering staff evaluate the effect of this higher temperature on the operability of the EQ equipment in these areas while operations attempts to lower
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Decisions regarding scramming the reactor and
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l depressurizing the reactor result from the evaluations performed and I
the maximum temperatures experienced.
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The inspector is not aware of any regulatory requirements
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to calibrate these instruments.
These items are not a Regulatory Guide 1.97 variable and are not included on the licensee's EQ list.
The inspector was also not aware of any event in which the actions specified in the E0Ps, namely reactor scram or depressurization, would not have already occurred with the temperatures excecding the limits specified in the E0Ps.
Nevertheless, these indicators provide information to the operator concerning the status of the plant and are variables on which potentially important decisions are based.
Consequently, the indicators are deserving of more attention than they have received.
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The inspector reviewed ENP-33.4, Identification of Regulatory Related Instruments for Periodic Calibration, Revision 3.
Among the
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instruments the procedures specify to be - on the list include non-safety instruments with limited Regulatory. requirements.
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Examples of such instruments include Regulatory Guide 1.97 and fire
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protection instrumentation.
These particular instruments are
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classified as non-safety and are not included on the RRIL.
The-maintenance personnel were not sensitized as to the importance of these instruments.
Consequently, when other seen.ingly more urgent work was required, these instruments were exempted from calibration.
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This is an Inspector Followup Item:
E0P Instruments Not on RRIL,
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In particular the inspectors will evaluate specific measures taken to ensure periodic calibration of the temperature indicators and their associated instrument loops,
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possible inclusion on the RRIL, and assessment of other instruments designated as non-safety and used in similar applications.
The licensee has issued NCR S-89-90 as a result of this issue.
The response to the NCR will be reviewed during the followup of this item.
d.
Unit 1 Drywell Walkdown The inspector found two items of interest during the drywell tour conducted on September 25, 1989.
The licensee shutdown the unit in accordance with their emergency ) procedures at the approach of Hurricane Hugo (see paragraph 8.a.
The inspector found the cable for SRV E acoustic monitor, 1-B21-FT-4161, adherin9 to the SRV tailpipe.
The insulation had partially melted, sticking to the pipe.
The licensee replaced the cable and detector for FT-4161 and FT-4164, which had the same problem. That work was performed under WR/J0s 89-AWFX1 and 89-AWFY1.
A previous problem found in the drywell with these instruments (see inspection report 89-07, paragraph 8.b(1)) was cracking of the cable insulation.
The inspectors noted no problem with the above
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The inspectors and the licensee
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L intend to carefully follow any further problems with these l
instruments during future drywell entries.
l-The inspector also noted peeling paint on an SRV tailpipe near snubber support 1-B21-56SS296.
The inspector was shown EER 84-333, dated July 25, 1984, which answered an NCR (S-84-039) on the same issue.
Several plant modifications inside both drywells performed during 1983 and 1984 were completed using procedures not in accordance with Regulatory Guide 1.54 June 1973 and ANSI N101.4-1972, Quality Assurance Requirements for Protective Coatings Applied to Water Cooled Nuclear Power Plants.
Apparently, an FSAR commitment existed then to that Regulatory Guide. Now, the licensee has deleted
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I their commitment to the Regulatory Guide in FSAR section 1.8 per change 4 to the FSAR.
- Regardless of the commitment, the licensee reviewed the plant modifications performed with the existing coatings under the above EER.
They concluded that "no significant or detrimental effects" existed from the previously applied coatings.
This conclusion was
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based on:
Estimated amount of paint used (worst case - about 36 gals. in
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Clogging of ECCS screens would not occur due to high specific
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gravity of paint used.
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Clogging of ECCS spray nozzles would not occur due to suction
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screen size.
No significant additional combustible gas generation based on
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amount and material.
Also, the licensee stopped all painting in the prinary containment for subsequent plant modifications effective August 1984 The resident inspectors have no further questions about this issue now.
This issue will be referred to.a regional specialist inspector
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for routine followup.
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Unit 2 Recirculation Suction Nozzle Plug The refuel bridge crew was lowering an underwater camera to examine a recirculation loop suction nozzle when the camera was pulled into the recirculation loop.
The crew was attempting to position the nozzle.
plug on September 17, 1989 at about 9:00 p.m., when the camera was
lowered.
The refuel floor Test Director (TD) called the control room -
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The control room reported no flow in the B loop but the TD and shift foreman then determined that the loop the camera entered was the A loop.
Shutdown cooling was secured for 5 minutes and the camera and nozzle plug retrieved.
The licensee stopped all work on the refuel floor on September 18, at 6:30 a.m., for 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> while the licensee determined why the refuel crew was plugging the wrong nozzle.
The inspector reviewed the initial corrective actions initiated by the licensee and had no concerns for work restart.
The licensee is writing an incident report,89-028, on the event.
The inspector will review the report when issued to determine any future NRC followup.
Two violations and no deviations were identifie F
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Small Sump Lubricating 011 (62703)
During a routine Unit 2 Reactor Building tour on August-28, 1989, the inspector noted:that the visual condition of the oil in the oil sight
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bulbs on the bearings of three different pumps was inconsistent with-that of other pumps.
The pumps and the observed condition were as follows:
2A CRD Pump Outboard Bearing Clear Red Color 2B RHR SW Pump Cloudy Grey / Amber Color 2D RHR SW Pump Cloudy Amber Color
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The normally observed oil condition on these and other pumps is clear-amber. The 2A CRD pump inboard bearing sight bulb, as well as the bulbs on the 2B CRD pump and 2B and 2C RHR SW pumps were normal.
The inspector notified the licensee and oil samples were drawn for analysis at the Harris E&E Center.
The analyses were completed on August 31, with the following results:
2A CRD Pump Outboard Bearing Incorrect oil in use. Viscosity equal to 36.9 centistokes.
Correct viscosity is 60.8 centistokes i
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for new replacement oil.
2B RHR SW Pump High particulate count.
5 994 020 particle counts per 100 ml (5 - 10 micron). ASTM Class 6 specifi-i cation is 128 000 counts per 100 ml-(5 - 10 micron) for new oil.
Particulate matter was primarily copper.
2D RHR SW Pump Moderate particulate count.
l 469 776 counts per 100 ml (5 - 10-I micron).
i The licensee determined that the incorrect oil was placed in the 2A CRD i
pump during a routine oil change in September 1988.
Subsequent to the l
analysis, the oil was replaced with oil of correct viscosity.
No regulatory issue exists due to the non-safety function of this pump.
However, the CRD pumps can provide high pressure injection water to the
reactor if needed during a small break LOCA. Thus, the CRD pumps serve as I
a backup to HPCI, ADS, and RCIC and should be properly maintained.
The moderate particulate count of-the 20 RHR SW pump was deemed acceptable by the licensee.
The licensee stated that non-filtered oil, such as that in the RHR SW pumps, is expected to display elevated particulate counts.
However, the very high particulate count of the 2B RHR SW pum.n was unacceptable to the licensee.
The pump was declared inoperable and dismantled for investigation.
One of two bronze flinger rings was found broken and deteriorated.
The high copper content of the oil corroborated the as-found condition of the flinger.
It could not be determined how
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long this condition-had existeo.
However, bearing damage was not evident.
Since,the flinger was no longer performing its function (i.e., to provide lubricating oil to one set of bearings), continued pump operation could have resulted in failure of the bearings.
The pump was last rebuilt in-
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November 1986.
During the inoperability of the 2B RHR SW pump, the remainirg pumps were OPERABLE, thus meeting TS requirements.
Licensee maintenance personnel conduct daily rounds to check on lubrication of equipment in accordance with OPM-LUB-500, Plant Equipment Lubrication Schedule.
There are specific requirements to check for oil levels and external leaks in that schedule.
No specific guidance or acceptance criteria is given for the visual condition of oil in sight t
bulbs. ~ The licensee stated, however, that the abnormal oil conditions discovered by the inspector should have been noted by the mechanics who perform the daily inspections.
The licensee does not have a program for periodic sampling of oil in equipment with small (i.e.,
10 gallons) sumps.
Instead of sampling, maintenance changes oil on a_ periodic basis.
The licensee has chosen a preventative vice predictive maintenance approach regarding small sump oil.
The inspectors consider the licensee's failure to detect these oil problems indicative of a program weakness.
The licensee stated that, as a result of these problems, an oil sampling program is being considered for
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implementation.
The licensee's final action in this area will be reinspected under Inspector Followup Item:
Small Sump Lubricating 011
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Change / Sample, (325/89-26-04 and 324/89-26-04).
Violations and deviations were not identified.
6.
Onsite Review of Licensee Event Reports (92700)
The below listed LERs were reviewed to verify that the information provided met NRC reporting requirements.
The verification included adequacy of event description and corrective action taken or planned, existence of potential generic problems and the relative safety significance of the event.
Onsite inspections were performed and concluded that necessary corrective actions have been taken in accordance with existing requirements, licensee conditions and commitments, a.
(OPEN)
LER 1-88-02, Auto-isolation of Reactor Water Cleanup System Inlet Outboard Isolation Valve; Spurious' Actuation of Steam Leak Detection.
This LER reported an isolation of the RWCU containment isolation valve 2-G31-F004, due to a spurious signal from the steam leak detection system instrumentation logic.
This spurious signal apparently came from a Riley Corporation temperature switch which is in the electrical circuit and was generated when the circuit was reenergized after electrical maintenance work on the system.
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The switches are also in circuitry for RCIC and HPCI systems.
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switches give spurious signals when powered-by AC. The problem with'
l these switches was addressed in GE SIL No. 416 issued January 14 1985, and in Information Notice 86-69.
IN - 86-69 was originally
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evaluated by the licensee.as not yet a problem at Brunswick.
When
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Brunswick had this problem, they committed in the LER to look for'a
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permanent fix for the problem.
The study has been completed by
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Project Identification PID-2300A and submitted for the 1990 budget approval.
The licensee plans to install one second time delays in
'the circuit to give the switch time to settle out prior to providing the safety signal.
This item will remain open until the fix is installed.
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(CLOSED)
LER 1-88-32, SBGT Inoperability While Sipping Irradiated Fuel Due to Inlet Valves Not Being in the Full Open Position.
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corrective actions specified by the licensee in their LER dated January 13, 1989, and its supplement dated April 28,1989, were verified by the inspector during the closecut of Violation 325/88-45-01, as-documented in inspection report 89-20.
The inspector has no further questions.
Violations and deviations were not identified.
7.
In Office Licensee Event Report Review (90712)
The below listed LERs were reviewed to verify that the information provided met NRC reporting requirements.
The verification included adequacy of event description and corrective action taken or planned,
. existence of potential generic problems and the relative safety significance of the event.
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LER 1-89-13. RWCU Isolation Due to Suspected High Discharge Temperature from Non-Regenerative Heat Exchanger.
(CLOSED)
LER 2-89-10. Group 1 Isolation While Attempting to Equalize Around and Open the MSIVs.
(CLOSED) LER 2-89-11, Division 1 Primary Containment Group V Isolation of the Reactor Core Isolation Cooling System As a Result of Personnel Errors During Surveillance Testing.
Violations and deviations were not identified.
8.
Hurricane Hugo (93702)
Hurricane Hugo missed the Brunswick site and struck Charleston, S. C.,
about 120 nautical miles away. The hurricane caused no significant damage to plant systems or structures.
The skirting of some temporary trailers within the protected area were dislodged but were not separated from the bottom of the trailers.
Maximum onsite sustained wind speed, as measured L
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NRC-monitored and evaluated the licensee's action throughout the event.
The resident inspectors. reviewed the licensee's hurricane response procedures and preparations in accordance with A0P-13.0, Operation During Hurricane, -Tornado, or Flood Conditions, Revision 3, prior to projected i
hurricane landfall.
Four regional inspectors arrived onsite the afternoon and evening of September 21 to observe and evaluate the licensee's actions.
A regional emergency preparedness inspector, onsite for a routine inspection, also assisted the senior resident inspector with the NRC's onsite hurricane response.
A communications specialist from the U. S. Department of Interior, Bureau of Land Management, Boise Interagency Fire Center, arrived onsite with an L-Band Satellite Communications set.
The set was successfully tested and could have provided backup phone communications to NRC HQ/RII if all other phone lines-went dead.
NRC Region II manned the Incident Response Center in Atlanta continuously while the storm threatened Brurswick.
The licensee and Region II maintained an open phone line while the licensee manned the Technical Support Center.
The inspectors concluded that the licensee's hurricane preparations, readiness, and actions were reasonable and prudent.
Based on the damage caused to Charleston, however, the inspector believes that a loss of offsite power would have been likely at Brunswick had the stonn hit directly.
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During a conference call between NRC and the licensee, both parties recognized that the wind speeds used for entry conditions for an Alert and Site Area Emergency in the Brunswick emergency procedures could not be read by existing instrumentation.
The anemometer at the meteorological
- tower could only read a maximum wind speed of 100 mph.
The licensee's procedure, PEP-02.1, Revision 25, Initial Emergency Actions, requires the declaration of an Alert at " Hurricane winds near design level." The FSAR, section 2.4.5.1, defines the Probable Maximum Hurricane' as having maximum 10 minute average 30 feet overwater wind speed of 128 mph.
Further, PEP-02.1 requires declaration of a Site Emergency if hurricane winds exceed 130 mph at 30 feet or 180 mph at 300 feet.
Location is also not specified in PEP-02.1.
The licensee agreed to either alter the emergency procedures or instrumentation to correct the above problem. The NRC will review the licensee's corrective action prior to next hurricane season.
This is an Inspector Followup Item: Hurricane Emergency Declarations Not Consistent with Anemometers, (325/89-26-05 and 324/89-26-05).
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Chronology-
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September 20 6:48 p.m.
Unusual Event declared.
Hurricane watch was -issued for site area.
Unit 1 at 100 percent power, Unit 2 in refuel with vessel head removed and cavity flooded.
The fuel pool gate was removed.
September 21
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6:00 a.m.-
Hurricane warning issued 12:45 p.m.
Licensee commenced power reduction on Unit 1 4:40 p.m.
Unit 1 main generator separated from grid 7:00 p.m.
Technical Support Center manned, still in UE
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10:00 p.m.
Highest winds on-site 10:35 p.m.
Manual Scram after RSCS declared inoperable Operational condition 3 September 22 12:33 a.m.
Unit 1 in shutdown cooling B loop 2:00 a.m.
Unit 1 in cold shutdown, operational condition 4 2:30 a.m.
TSC secured 6:00 a.m.
Hurricane watch and warning secured.
UE secured.
Violations and deviations were not identified.
9.
Loss of Annunciators - Unit 2(93702)
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The licensee declared an Alert at 8:45 a.m.. on September 21, 1989, when the shift operating supervisor, as Site Emergency Coordinator, determined
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that a total loss of annunciators occurred on Unit 2.
The unit was in l
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cold shutdown with an Unusual Event declared due to Hurricane Hugo (see paragraph 8).
With the loss of annunciators, additional operators were stationed at the control boards and the TSC was activated at 9:45 a.m.
Maintenance found a short in an annunciator reset / acknowledge joystick on 1-the main control board panel P603.
The actual problem had been a loss of audible annunciation only.
The short was removed and the joystick
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replaced. The Alert was terminated at 10:53 a.m., the same day.
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The three resicent inspectors and a regional emergency planning specialist observed and et aluated the licensee's actions during the Alert.
These
observations ircluded control room, TSC, and maintenance activities. The inspectors cons,1uded that the licensee's actions were prudent and proper.
Specifically, update notifications.to off-site agencies were made from the control room, as required, something that had been missed during previous events and drills.
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Violations and deviations were not identified.
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10.
ExitInterview(30703)
The inspection scope and findings were summarized on October 1, 1989, with those persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail the inspection findings listed below.
Dissenting comments were not received from the licensee.
Proprietary information is not contained in this report.
Item Number Description / Reference Paragraph 324/89-26-01 VIOLATION - Fuel Pool Cooling Valve Out of Position,(paragraph 4.a).
324/89-26-02 VIOLATION - Failure to Follow Procedure.
paragraph 4.b).
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325,324/89-26-03 IFI - E0P Instruments Not on RRIL, (paragraph 4.c).
325,324/89-26-04 IFI - Small Sump Lubricating Oil Change / Sample.
(paragraph 5).
325,324/89-26-05 IFI - Hurricane Emergency Declarations Not Consistent with Anemometers, (paragraph 8),
t 11. Acronyms and Abbreviations L
AC Alternating Current AI Administrative Instruction l
A0 Auxiliary Operator-A0P Abnormal Operating Procedure ASTM American Society for Testing Materials BSEP Brunswick Steam Electric Plant BWR Boiling Water Reactor CAM Containment Atmospheric Monitoring C0 Control Operator CRD Control Rod Drive DG Diesel Generator E&E Energy & Environment ECCS Emergency Core Cooling System
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j EER Engineering Evaluation Report ENP-Engineering Procedure-
.E0P Emergency Operating Procedures EQ Environmental Qualification ESF Engineered Safety Feature F
Degrees Fahrenheit FSAR Final. Safety Analysis Report n
GE General Electric HP Health Physics HQ Headquarters HPCI High Pressure Coolant Injection I&C Instrumentation and Control IE NRC Office of Inspection and Enforcement IFI Inspector Followup. Item
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IN Information Notice IPBS Integrated Planning, Budgeting and Scheduling LER Licensee Event Report LOCA Loss of Coolant' Accident MI Maintenance Instruction
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mph Miles Per Hour MSIV'
Main' Steam Isolation Valve NCR Non-Conformance Report NDEP Non-Destructive Examination Procedure NRC Nuclear Regulatory Commission NRHR North Residual. Heat Removal
Operating' Instruction OP Operating Procedure OPM Operating Procedure Manual PA Protected Area PEP Plant Emergency Procedure PID Project Identification PM Plant Modification PNSC Plant Nuclear Safety Committee PT Periodic Test QA Quality Assurance QC Quality Control RII Region II
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RCIC Reactor Core Isolation Cooling
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RHR Residual Heat Removal RRIL Regulatory Related Instrument List RSCS Rod Sequence Control System RWCU Reactor Water Cleanup SBGT Standby Gas Treatment SF Shift Foreman SIL Service Information Letter SRV Safety Relief Valve STA Shift Technical Advisor l
TD Test Director TS Technical Specification
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UE Unusual. Event
URI-Unresolved item
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Work Request / Job Order i
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