IR 05000324/1989005: Difference between revisions

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{{Adams
{{Adams
| number = ML20244C982
| number = ML20245F745
| issue date = 04/06/1989
| issue date = 06/13/1989
| title = Insp Repts 50-324/89-05 & 50-325/89-05 on 890201-0315. Violations Noted.Major Areas Inspected:Maint Observation, Surveillance Observation,Operational Safety Verification,Esf Sys Walkdown & Onsite Licensee Event Repts Reviews
| title = Ack Receipt of Informing NRC of Steps Taken to Correct Violations Noted in Insp Repts 50-325/89-05 & 50-324/89-05
| author name = Dance H, Levis W, Madden P, Nelson D, Ruland W
| author name = Verrelli D
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
| addressee name =  
| addressee name = Eury L
| addressee affiliation =  
| addressee affiliation = CAROLINA POWER & LIGHT CO.
| docket = 05000324, 05000325
| docket = 05000324, 05000325
| license number =  
| license number =  
| contact person =  
| contact person =  
| document report number = 50-324-89-05, 50-324-89-5, 50-325-89-05, 50-325-89-5, IEB-88-007, IEB-88-7, NUDOCS 8904210087
| document report number = NUDOCS 8906280231
| package number = ML20244C969
| title reference date = 05-15-1989
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| document type = CORRESPONDENCE-LETTERS, NRC TO UTILITY, OUTGOING CORRESPONDENCE
| page count = 25
| page count = 1
}}
}}


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NUCLEAR REGULATORY COMMISSION    '
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Report >o. 50-325/89-05 and 50-324/89-05 Licensee: Carolina Power and Light Company P. O. Box 1551 Raleigh, NC 27602 Docket No. 50-325 and 50-324  License No. DPR-71 and DPR-62 Facility Name: Brunswick I and 2 Inspection Conducted: February 1 - March 15,1989 Inspectors: (- '
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Date Signe'd Approved By: b dNL  ,/N Fl. C. Daned, Section Chief  Dat6 Signed Division of Reactor Projects SUMMARY Scope: This routine safety inspection by the resident inspectors involved the areas of maintenance observation, surveillance observation, operational safety verification, Engineered Safety Feature System walkdown, onsite Licensee Event Reports review, in office Licensee Event Reports review, handling of emergency diesel generator fuel oil, implementation of requested actions of NRC Bulletin 88-07, installation and testing of modifications, drawing system verification, and action on previous inspection finding Results: In the areas inspected three violations were identified. The first violation involved the hanging of an improper clearance on certain Unit 1 SLC valves, which led to the inadvertent draining of the SLC tank. Accordingly, increased management attention is required over clearance control, paragraph 12.g. The second violation, which is not being cited, involved a failure to document a valve position change (locked open to open) on an exception form. The third violation resulted from failure to adequately verify correct pressure in stored pressure dry chemical fire extinguishers, 8904210087 890406  ^
PDR ADOCK 05000324 Q  PDC
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paragraph All three violations occurred in the operations area, indicating that continued management attention is required over that work grou The licensee made an interpretation of the definition of " core alteration" that is not supported by the current language of the Technical Sepcification The licensee plans to submit an amendment request to NRR, paragraph Housekeeping remains a strength. However, system walkdowns still show that minor leaks and other discrepancies are not being documented and corrected by the plant staff, paragraph The licensee satisfactorily implemented Bulletin 88-07, but certain discrepancies still require resolution, paragraph Plant drawings satisfactorily supported operations in the control room and technical support center. A previous problem with timely delivery of aperture cards to the control room was resolved through third party /QA in"olvemen P&ID hard copies in the control room were well controlled with virtually no plant modification outstandin The licensee's complete yearly ' inventory of CR/ Operations drawings should keep the aperture card file updated. Two system descriptions were not adequately maintained curren Excessive plant modifications remained outstanding against two SDs, paragraph 1 _
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l REPORT DETAILS Persons Contacted        j Licen see . Employee s
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    *K. Altman, Engineering Supervisor      i W. Biggs, Engineering Supervisor      i
    *F. Blackmon, Manager - Operations J. Brown, Resident Engineer
    *S. Callis, On-Site Licensing Engineer T. Cantebury, Mechanical Maintenance Supervisor (Unit 1)
    *G. Cheatham, Manager - Environmental & Radiation Control    i
    *M. Ciemnicki, Security R. Creech, I&C/ Electrical Maintenance Supervisor (Unit 2)    ;
    * Dorman, Supervisor - QA      i
    *K. Enzor, Director - Regulatory Compliance      i R. Groover, Manager - Project Construction
    *V. Grouse, Employee Relations
    *J. Harness, General Manager - Brunswick Nuclear Project W. Hatcher, Supervisor - Security a. Hegler, npervisor - Radwaste/ Fire Protection Helme, Manager - Technical Support J. Holder, Manager - Outages      -l L. Jones, Director - Guality Assurance (QA)/ Quality Control (QC)
M. Jones, Director - On-Site Nuclear Safety - BSEP      )
R. Kitchen, Mechanical Maintenance Supervisor (Unit 2)
G. Oliver, Manager - Site Planning and Control
    *J. O'Sullivan, Manager - Training
    *B. Parks, Engineering Supervisor
    *M. Pastva, Senior Specialist R. Poulk, Project Specialist - NRC
    *J. Smith, Director - Administrative Support      j S. Smith, I&C/ Electrical Maintenance Supervisor (Unit 1)    '
    *R. Starkey, Project Manager - Brunswick Nuclear Project    ,
    *R. Warden, Manager - Maintenance      i'
B. Wilson, Engineering Supervisor
    *T. Wyllie, Manager - Engineering and Construction Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, office personnel, and security force member * Attended the exit intervie Note: Acronyms and initialisms used in the report are iisted in paragraph 1 l l
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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 codes and ~ standard 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 hold points were adequate and observed; adequate post-maintenance testing was performed; and independent verification requirements were implemented. The inspectors independently verified that selected equipment was properly returned to servic The inspectors observed / reviewed portions of the following maintenance activities:
87-AGDD1 Diesel Generator Centrol Panel Termination Connection Inspection and Repai AXGN1 Service Water Valve SW-V18 Replacement of Valve Actuator Greas BFMA1 Replacement of Emergency Control Room Ventilation Fan Motor    !
Bearing AAWJ1 RSCS Card Inspectio AfiIR1 Diesel Generator Building Basement Fire Retardant Cable Coating ]
89-ADKE1 Diesel Generator No. 1, No. 7 Cylinder Valve Cover Gasket Replacemen AFQC1 HPCI Injection Valve Testin DBF011 Breaker Compartment Inspection for 2-E11-F016 No violations or deviations were identifie . Surveillance Observation (61726)
i The inspectors observed surveillance testing required by Technical    l Specification Through observation, interviews, and record review, the    i
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inspectors verified that: tests conformed to Technical Specification requirements; administrative controls were followed; personnel were    l qualified; instrumentation was calibra;ed; and data was accurate and    l complete. The inspectors independently verified selected test results and    I proper return to service of equipmen l
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3-The inspectors witnessed / reviewed portions of the following test activities:
1MST-BATT14W Batteries, Spare, Weekly Operability Tes IMST-PCIS24M PCIS High Condenser Pressure Trip Unit Channel Calibratio MST-APRM21Q APRM A and LPRM Group A Channel Calibration Functional Tes MST-RHR27R RHR and CS Time Delay Relays Channel Calibratio OI-3.1- Unit 2 C0 Daily Surveillance' Requirement PT-14.1.29 CRD System Charging Water Check Valve C11/C12-115, Operability Tes SRM Channel Functional Test Adequacy AsL detailed' in inspection rsport 89-02, the inspector' questioned the adequacy Lof the licensee's channel functional test performed on the SRMs-prior to core alterations. Specifically, the inspector questioned why the licensee's ' test did not detect a preamplifier problem on one SRM and a control room-indicator problem on another SRM which occurred shortly after commencing core loa Channel Functional Test is defined in the Technical Specificai"sns as "the' 1 injection of a simulated signal into the channel as close to the primary sensor as practicable to verify OPERABILITY, including alarm and/or trip functions." The- licensee used 1/2 MST-SRM11W, SRM Channel Functional Test, to meet this requiremen In the test, a square wave output is
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supplied from a ' function generator to the SRM input signal cable at the SRM drawer. A counter is also connected to the drawer to measure the-count rat The frequency of the function generator is varied to obtain the necessary count rates to check the alarm and trip functions of the SR The associated count rate for the alarm and trip function is  !
measured and recorded from the counte With this test configuration, the problems with the preamplifier and the  i
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control room log count rate meter would not be detecte However, the channel functional test does comply with the Technical Specification requirements. A ~ simulated signal is inserted into the channel and- the alarm and trip functions are verifie The preamplifier and log rate count meter are verified on another surveillance test which is verified to be current prior to core alterations. Also, after loading fuel around the SRMs to establi sh sufficient' count rate, the licensee checks the discrimination circuitry and high voltage power supply. The licensee has agreed, however, to perform a two point check of their control room log L
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l l    rate count meter during their channel functional tes The test signal I
will be supplied from a function generator and will check two points to
    . ensure that the -control room indicator is' tracking properl The' .
inspectors had no further questions concerning this issu No violations.or deviations were identifie . Operational Safety Verification (71707)
The inspectors verified that Unit I and Unit 2 were operated in compliance with Technical Specifications and other regulatory requirements by direct observation of activities, facility tours, discussions with personnel, reviewing of records and independent verification of safety system statu The' inspectors verified that control room manning requirements of 10 CFR 50.54 and the Technical Specif. cations were met. Control operator, shift 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 Technical Specification Limiting. Conditions for Operations. Direct observations were conducted of control room panels, instrumentation, and recorder traces important to safety in order 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 maintaine The inspectors also verified the status of selected control room annunciator Operability of a selected Engineered 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 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 availabie; and a condition did not exist which might prevent fulfillment of the system's functional requirement Instrumentation essential to system actuation or performance was verified operable by observing on-scale indication and proper instrument valve lineup, if accessibl Tha inspectors verified that the licensee's health physics poiicies/ procedures were followed. This included observation of HP practices and a review of area surveys, radiation work permits, postings, and instrument calibratio The inspectors verified that; the security organization was properly I 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
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! PA; persons within the PA displayed photo identification badges; personnel in vital areas were authorized; and effective compensatory measures were employed when required.
 
i The inspectors also observed plant housekeeping controls, verified l position of certain containment isolation valves, checked several clearances, and verified the operability of onsite and offsite emergency  !
power source Shutdown Margin and Core Alteration Requirements    l
 
During a tour of the control room, the inspectors noted that the licensee was removing Unit 1 control rods one at a time in order to  4 rebuild the associated control rod drive. Technical Specification 3.9.10.1, states the requirements that the licensee must meet. to remove a single control rod evolutio Some of the requirements are:
SRMs are operable per TS 3. '
Shutdown margin specified in TS 3.1.1 satisfie l All other rods are inserted or have adjacent fuel remove Surrounding rods in a 5 x 5 matrix electrically disarme The inspector questioned whether the SDM requirements were satisfied since the core had been recently refueled and no SDM demonstration specified by TS 3.1.1 had been performed. The licensee stated that the SDM requirements were satisfied by analytical means and referenced their Cycle 7 Core Management Report dated January 3, 1989, which  1 calculated a SDM of 1.89% delta K/K. The licensee did suspend all further rod withdrawal until the question was resolve The inspectors examined Technical Specifications of other BWR facilities and discussed the SDM requirement and core alterations definition with regional and headquarters personne The inspectors determined that NRC has accepted a calculation of SDM as an adequate means of determining SDM at other facilities under certain circumstance However, the inspectors could find no information to support the licensee's interpretation of core alteration During the inspection, the inspectors learned that the licensee did not consider the insertion or withdrawal of control rods by their normal means as a core alteration. Technical Specifications states that " CORE ALTERATION shall be the addition, removal, relocation, or movement of fuel, sources, incore instruments, or reactivity controls in the reactor core with the vessel head removed and fuel in the vessel. Suspension of CORE ALTERATIONS shall not preclude completion of the movement of a component to a safe, conservative location."
 
The licensee felt that their definition was justified since the original Unit 2 Technical Specifications specifically stated that  ;
movement of control rods by normal means was not a core alteratio Clearly, the current Technical Specifications have no such provisio l t
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The inspector found that no t tolation of Technical Specifications occurred as a result of the licensee's incorrect definition of core alterations. The inspector examined the time pe.riod .that the shorting links were ~ installed during this reporting period. -
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The f:    inspector. noted - that, during this time, control rods were being
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    . withdrawn, their: respective control ' rod drive removed, rebuilt and -
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reinserted, and the rod was timed to verify proper operation. These actions were performed in accordance with procedure 0WP 7/1, Rev. 3, Control Rod Drive Mechanism Removal With Fuel.in Vessel, and met ~th requirements of.TS 3.9.10.1. The inspector found no cases where the-licensee violated TS 3.9.2 governing core alterations. during this reporting. period as a result of their definition of core alteration .The licensee: plans to submit a TS amendment request to clarify the definition of core ' alterations, and the SDM requirement The licensee will also submit a letter to NRR. explaining their position on SDM and .the' adequacy of a calculation to' satisfy TS requirements
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    .for single or multiple control rod withdrawal and removal. This will be an Inspector Followup Item:  Submission and Approval of Clarifi-cation of SDM and Core Alterations Amendment ' Request, (325/89-05-04 and 324/89-05-04). Undercharged Fire Extinguishers The inspector informed the control room of two fire extinguishers that were inadequately ' charged on February 27, 1989. The two dry chemical fire extinguishers were located on elevation 23' of the Control Building, in the Unit 2 cable spreading room at fire extinguisher station CB-2-2, and in the ' Unit 2 Reactor Building on elevation - 80', west, at fire extinguisher station RX-2-26. On March 8, 1989, the inspector found the undercharged extinguishers still in place., Additionally, the inspector noted that the extinguisher in the Unit 2 cable spreading room, according to the inspection tag on the extinguisher, was inspected on March 8,1989, and found to be acceptable in its' current under pressurized conditio Surveillance procedure OPT-34.11.2.1, Portable Fi re Extinguisher Inspection . Reactor Building 1 and 2, Revision 6, section 6, acceptance criteria 6.0.1.7 requires, for hand held stored pressure dry chemical extinguishers, that the pressure gauge indicator must fall within the acceptable range and, for those extinguishers that do not meet this criteria, that they be replaced. The licensee did not fully implement the requirements of this procedure and, therefore, this is identified as a Violation: Inadequate Surveillance of Stored Pressure Dry Chemical Fire Extinguishers (324/89-05-03).
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The licensee replaced the extinguishers on March 8, 198 RHR Valve Not Adequately Controlled During a walkdown of the -17' elevation of the Unit 2 Reactor
  ' Building on March'14, 1989, the' inspector,1at 11:45 a.m., noted that'
  -the.RHR pump D minimum flow isolation valve E11-F018D had the locking chain and locking seal removed for maintenance without a clearance being issued. No work was:in progress and the . work, replacement. of the handwheel, appeared complete. The inspector. notified the control room that the valve should be locked ope Since the valve was not under a clearance and was not in the locked open position required by the system operating procedure, the position of.this valve should be controlled under 01-13, Revision.29, Valve and Electrical Lineup Administrative. Controls. The shift    .
i foreman -indicated that a valve lineup exception form was not initiated as required by 01-13, section 4. The licensee subsequently locked the valve in the open positio This is identified as a Violation:  Failure to Complete Valve / Breaker Exception Form for an Unlocked Valve (324/89-05-02).
 
This violation meets the criteria specified in Section V of the NRC Enforcement Policy for not issuing a Notice of Violation and is not
  ' cite Two violations were identifie . Engineered Safety Feature System Walkdown (71710) Duplex Strainer Position During a walkdown of the Emergency Diesel Generator fuel oil system,    ,
the inspector found the selecting lever on fuel oil discharge duplex strainer mispositioned. The selecting lever can be placed in one of three positions; to place either strainer element in service or to place both in servic Interruption of flow is not possible, however, by use of the selecting lever alone. The inspector found    j both elements in service, which defeats the purpose of a duplex    j strainer. No . element is kept clean to permit cleaning of a fouled    i element. With both elements in service, both would become fouled and    -i interruption of flow would be necessary to clean the strainer and    {
return it to servic )
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The inspector notified the licensee of this condition. The licensee agreed that a single strainer element should be in service and returned the duplex strainer to the correct position. The licensee could not determine when the incorrect lineup was mad This
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condition had no effect on EDG operability since the strainers were not fouled. The inspector verified correct strainer alignment on the remaining EDGs. The licensee determined that a misaligned strainer could occur elsewhere in the plant because these strainer levers are not identified on system drawings or by taggin The licensee initiated Surveillance Field Report 89-010 to address this concer The inspectors will review the licensee's actions during future routine inspection b. Core Spray System Walkdown The inspectors conducted a detailed assessment of the Unit 1 and Unit 2 Core Spray Systems. The assessment included a review of outstanding work orders, plant walkdowns to verify valve positions and material conditions, and a check of selected core spray surveillance procedures to determine their adequac Physical verification of local and remote valve positions revealed no discrepancies with actual position versus the required valve position operating procedure valve lineup. However,'a review of the operating system valve lineup for the Unit 2 A loop, OP-18, Revision 35, showed three valves in a different position than shown on the P&ID, D-02524, Sheet 2, Revision 2 The discrepancies are shown below:
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E21-V4 indicates closed on P&ID, open on OP-18 valve lineu E21-V72 and E21-V81, indicate open on P&ID, closed on OP-18 valve lineu Physical inspection of the core spray systems revealed numerous material deficiencie None of the items found by the inspector posed an operability concern. However, these type of items should be detected and corrected by existing licensee program Examples of items found by the inspector for which no existing trouble ticket or work order could be found include:
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Fluid leaking  from low pressure      vent fitting from 2-E21-FS-N006 Small grease leak from 2-E21-F031A, F031B, and 1-E21-F031B motor actuator E21-F030 leakin Pipe caps missing f rom 2-E21-IV-783, IV-728, IV-726, IV-781, F0218, V12, V1 Junction box located behind pump 2A not secured (screws not tightened) and upper conduit fitting taped to junction bo l
. Docket Nos. 50-325;-50-324 License Nos. DPR-71, DPR-62 j
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Carolina Power and Light Company ATTN: Mr. Lynn W. Eury Executive'Vice President-Power-Supply.
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P..O. Box 1551-Raleigh, NC 27602 Gentlemen:
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SUBJECT: ;NRC INSPECTION REPORT N05. 50-325/89-05 AND 50-324/89-05 p.
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Thank you for your response of May 15, 1989, to our Notice of Violation issued
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: on April 6,.1989, concerning activities conducted at your Brunswick facility.
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2-E21-V13 mi ssing handwh'e el .
Grease leaking from.1-E21-F001 Packing _ leak from 1-E21-F004 Grease ' dripping from motor T ' drain for 1-E21-F004B, _ and 2-E21-F001 Small oil leak at the bottom fill connection'for all four pump These and other discrepancies were discussed with the system et.ginee The system engineer inspected the items 'and initiated work requests as necessary to correct the discrepancie The licensee continues to develop the system engineers and organiza-tional changes are. still in progres Based on a comparison of the Core Spray inspection and the RHR inspection in November, 1988, no changes have occurred relative to system conditions. The inspectors
          ' will continue to inspect safety systems to monitor ' the licensee's progres The inspector also checked PT-7.1.8, . Core Spray System Component Test, - to determine its adequac The inspector noted that ' the  4 minimum flow valve, F031A(B), a valve in the flow path that is not    1
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locked, sealed, or otherwise secured in position, is not checked i its . proper position as required by TS 4.5.3.1.6.2. This valve is normally open during no flow or low flow conditions and shuts when core spray flow reaches a -specified value. The licensee stated that this valve is not included in the PT because the position noted during standby operati.on (0 pen) differs from the valve ' position    i expected when the core spray system operates! (Closed). When core spray is injecting to the vessel, the minimum flow valve is a flow-path boundary valve. The licensee also stated that the valve position indicator on the RTBG is checked during shift turnover. The inspector concluded that this valve position should - be checked as part of the monthly PT. The issue of what constitutes a flow path valve was raised in inspection report 88-38 and resulted in URI 325, 324/88-38-0 This item will be referred to the Region /NRR for further clarificatio This issue, the requirement to check the position of the F031A(B) during the monthly PT, will be included with the previous unresolved ite I No violations or' deviations were identifie ; Onsite Review of Licensee Event Reports (92700)
We have' evaluated your response and found that it meets the requirements of 10 CFR 2.201.
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,
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'We. will examine the implementation of your corrective actions -
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during' future inspections.-
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We appreciate your cooperation in this matter.
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existence of potential generic problems, and the relative safety significance of the even Onsite inspections were performed and concluded that necessary corrective actions have been taken in accordance with existing requirements, license conditions, and commitment ,
    (CLOSED) LER 1-88-07, Primary Containment Group 1 Isolation Following Reset of Main Turbine Trip Signa The licensee revised Operating Procedures 1-0P-26 and 2-0P-26, Turbine Operating Procedure, to require that the "All Valves Closed" and the " Emergency Trip Reset" push buttons be pushed and held until the mechanical and emergency reset lights come o This prccedural action should preclude the changing of the main turbine speed logic selection from " Valves Closed" to "1800 RPM" whenever the main turbine trip signal is reset. The inspector reviewed the licensee's corrective ' actions associated with this event and found them appropriat (CLOSED) LER 2-87-10, Inoperability of Reactor Building Fire Hose Station    !
2-RB-23 Resulting from Personnel Error During/Following Fire Dril The inspector reviewed the licensee's corrective actions associated with this even The licensee revised operating instruction OI-36, Shift Fire Drills, to require that the equipment utilized during the drill be identified on the drill evaluation sheet and verified that the equipment is restored to an operable status. In addition, real time training on this event was conducted for the radwaste/ fire protection operating shift The inspector verified 0I-36 had been appropriately revised and that the training was conducted as a part of the fifth quarter fire brigade training session, course No. 88-1-5, completed on February 15, 1988. Based on the inspector's review of this event and the licensee's corrective actions,  the inspector found the licensee's response satisfactor (CLOSED) LER 2-88-07, Pinhole Leaks and Linear Indications in the Insert    ;
and Withdraw Lines of Unit 2 Control Rod Drives. The licensee, during the Unit 21988 refueling outage, conducted a visual and liquid penetrant inspection of the control rod insert / withdraw lines. The licensee found pinhole and linear indications on 21 lines. The licensee replaced
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sections of 11 withdraw and 4 insert lines and performed a base metal repair to one insert lin The remaining seven lines with indications were evaluated and found acceptable by the licensee per the guidance of    4 ASME, Section X1 requirements. The licensee performed the inspection and    !
repairs under plant modification PM-87-128, Unit 2 Refueling Outage Weld    l Overlays, Field Revisions 30, 31, 32, 35 and 3 In addition, the licensee inspected the withdraw and insert CRD lines on Unit I under    1 PM-88-040, CRD Pipe Repairs. No unacceptable indications were identified    !
using visual and liquid penetrant inspection techniques. The inspector    j reviewed the licensre's corrective actions associated with the repairs made on Unit 2 and the results of the CRD line inspection conducted on Unit 1 and found them acceptabl .
 
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  (CLOSED) LER 2-88-12, . Inability of High Pressure Coolant Injection System Auxiliary 011 Pump Motor Termination Splices to Meet Environmental Qualification Criteria. The inspector reviewed the documentation package
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and other inspection reports' dealing with the :HPCI Auxiliary 011 Pump Mctor Splice Previous insoection in this . area are documented in inspection reports 88-24 and 88-39. Based on these previous inspections and the information provided in the- LER, the inspector had ro further question No~ violations or deviations were identifie . In Office Licensee Event Report Review (90712)
The below listed LER was reviewed to verify that the information provided
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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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  (CLOSED) LER 1-88-21, Primary Containment Group 6 Isolation, Reactor  i Building Ventilation Isolation- and Standby Gas Treatment  System Auto-Starting During Cancellation of 48 VDC Battery Clearanc No violations or deviations were identifie . TI 2515/100 (25020)
  (OPEN) TI 2515/100, Proper Receipt, Storage and Handling of Emergency Diesel Generator Fue, 01 Events at other operating reactor sites involving problems' with DG fuel oil and fuel oil systems prompted the NRC to issue the above Temporary Instruction. This TI provides inspection guidance to NRC . inspectors to evaluate the likelihood of similar events occurring at individual reactor sites. The inspector conducted a portion of this TI during this reporting perio This inspection consisted of collecting specific information regarding the licensee's diesel fuel oil system with emphasis on fuel oil sampling and analysis. The inspector noted discrepancies between NRC Regulatory Guide 1.137, Revision 1, Fuel Oil Systems for Standby Diesel Generators, an FSAR commitment, and actual programs and practices of the licensee. For example, the licensee is not cleaning and inspecting all fuel oil storage tanks at a 10 year minimum interval per Regulatory Guide 1.137. These discrepancies were also noted by the licensee's site QA/QC and are being dispositioned in accordance with the licensee's-QA/QC program. None of these discrepancies appear to affect the operability of the Emergency Diesel Generators. However, the inspectors will monitor the licensee's action to ensure all issues are properly resolve _ __ _ - - _  -  -_ - -
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The inspector also noted a problem with a fuel oil system strainer that
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may be generic to many strainers / filters at the site. This is. discussed '
in detail in paragraph'5.a of this repor No violations or deviations were identifie . TI.2515/99 (25599)
  (CLOSED) TI 2515/99, Implementation of Requested Actions of NRC Bulletin 88-07, Power Oscillations in Boiling Water Reactor The Bulletin describes a double recirculation pump trip event at 'LaSalle Unit 2 where significant thermal-hydraulic instabilities occurred in the reactor. . After the recirculation pumps tripped, feedwater heating automatically isolated and core flow was due to natural circulatio Under those power to flow conditions, peak-to peak oscillations were from
  . 25?; to 50?4 power every two to three seconds as indicated on the. Average Power Range Monitor Seven minutes after the dual pump trip, the unit scrammed automatically on high neutron flu The Bulletin - and its supplement requests BWR licensees, including Brunswick, to take certain actions in response to the LaSalle even The inspector interviewed personnel, reviewed procedures and training materials, and examined instrumentation ' to verify that the license completed the committed actions from the Bulleti Briefing on LaSalle Event The inspector interviewed 12 operations personnel (SR0s, R0s, STA),
about the LaSalle even Twenty-five percent of the operators interviewed recalled. few event details. All operators interviewed recalled the new procedural required actions for thermal-hydraulic instabilit Procedure Changes l    The inspector verified that the licensee revi scri the appropriate procedures to:
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Require a manual scram if both recirculation pumps trip when the mode switch is in RUN (A0P-4.3, Rev. 8, February 6,1989, Recirculation Pump Trip and Others).


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Require a manual scram, if region A of the power to flow map, was entere Require a manual scram if indications of instability occu Identify indications of thermal-hydraulic instability - 10% peak to peak APRM oscillations or LPRM upscale-downscale alarm I L
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The inspector reviewed . the below listed procedures, which also
    .contain revised-guidance per above, for thermal-hydraulic instability:
0-A0P-4.0,' Rev. 6, Recirculation Flow Control Failure - Decreasing
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Flow 0-A0P-4.1, Rev. 4, Recirculation Flow Control. Failure - Increasing Flow
    .1/2-0P-02, Rev. 17 & 62, Reactor Recirculat' ion System Operatin Procedure GP-04', Rev. 14, Increasing. Turbine Load to Rated Power GP-05, Rev. 30, Unit Shutdown 1-APP-A-06, Rev. 6,' Annunciator Response Procedure 2-APP-A-06, Rev. 7, Annunciator Response Procedure The inspector.noted these problems:
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In the above annunciator procedures, window 1-7, LPRM Downscale, requires a reactor scram if power is i 15%. This criterion differs from the 10% peak to peak ( Sis) interim , corrective actions published by.GE. All other procedures used the 10f, peak-to peak criterion as require During a procedure walk through using A0P-4.3 with a control operar.or, the inspector noted.that the procedure caution refers to the 8094 rod line but the power to flow map with the rod line is not included with the procedur No guidance for using Select Rod Insert on Unit 2 was provided i
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to the operators, either in procedures or training. The . SRI button allows, on Unit 2 only, the operator to scram pre-determined rods to rapidly reduce power. A0P-4.3 instructs the operator to use SRI if above 5094 power, if desire $
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Most operators interviewed did not completely recall the pro-hibitions in OP-2 not to intentionally enter thermal-hydraulic j instability regions A&B,  J I
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1/2-APP-A-06, window 1-7, refers the operator to Technical i Specifications, but not the AOPs, which require operator actions sooner than T _ _ _ _ _ _
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14 Instrumentation The licensee verified that'LPRM/APRM instrumentation had no filtering that could mask thermal-hydraulic instabilitie All APRM chart recorders in the control room were checked by the licensee to verif .that the full scale deflection setting was one second. Maintenance did find one recorder set at 5 second ' full scale deflection and corrected it. The inspector reviewed the procedure . revision request-88-2094 for new procedure OPIC-UR008, which will incorporate . the maintenance requirement to verify the setting of recorder response tim ~
The licensee identified no deficiencies- in instrumentation that-required procedural. compensatio * Technical Specifications The ' licensee addressed thermal-hydraulic instability in TS .3.4. through amendments 114. and 142.-approved December 30, 1987. Those amendments incorporated the recommendations of GE Service Information Letter SIL-380, Rev. 1, dated February 10,.1984. Current procedure are more restrictive than the TS, thus the procedures are consistent-with TS'.
  , Training Programs The licensee has integrated thermal-hydraulic instability and the LaSalle event into their licensed operator training progra The inspector reviewed updated training materials and observed a simulator exercise to verify implementatio The simulator staff demonstrated their simulation of instability using their current BWR model.during a dual recirculation pump trip. LPRM indication did not show the swings as soon as expected. APRM response was all in unison and the indicators moved in a jerky fashio In spite of the indi. cation-problems, the inspector believes that the general behavior of the reactor during conditions of instability was reasonably demonstrated to the operator The licensee does not . routinely demonstrate instability to all operators during training. No specific training syllabus requires simulation to the operators of instability. under 2 pump, single pump, and natural circulation condition The inspector concluded that the licensee's response to the bulletin was sati sf actor However, the problems found by the inspector require resolution by the license No violations or deviations were identified.
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1 Installation and Testing of Modifications (37828)
The licensee is currently implementing on Unit 1 a HPCI Reliability Improvement Plant Modification, PM-88-05 The purpose of this modification is to improve system reliability by: (1) the addition of an oil bypass line around the Woodward EGR Actuator; (2) rerouting tubing between the Woodward EGR Actuator and the remote servo; (3) deletion of the opening rate control valve and bypass tubing on the HPCI Turbine Stop Valve (E51-V8), and; (4) the addition of a 10 second time delay to the low suction pressure pump tri The EGR bypass portion of this modification allows hydraulic oil pressure developed from the auxiliary oil pump to move the control valve prior to HPCI turbine startu This, in conjunction with a reduced idle voltage setting on the ramp generator signal converter, will allow the control valve to open, then partially close prior to the opening of the stop valve. Thus, this portion of the modification, along with the rerouting    ,
of the tubing between the EGR actuator and the remote servo, will allow the control valve to absorb the majority of the initial steam differential pressure during the turbine quick start transient, reduce the initial quick start turbine speed peak, and reduce the turbine exhaust line pressure transien In addition, the licensee, under this modification, installed a 10 second time delay relay in the low pressure pump suction logic. The intention of    l this delay is to prevent the pump from tripping due to pressure spikes experienced during pump startu The licensee had confirmed that a low suction pressure trip was the cause of a Unit 2 HPCI turbine trip on November 16, 198 (see inspection report 88-39), by conducting a full flow injection test on January 28, 1989. The test showed that a turbine low suction pressure alarm occurred upon initial HPCI injection into the reactor vessel . Since the low suction pressure trip had been previously bypassed, HPCI did not tri The. inspector reviewed the licensee's HPCI Reliability Improvement Plant Modification, verified that the specified suction pressure trip time delay relay was installed and wired into the HPCI logic in accordance with the drawings and instructions provided in the modification package, and confirmed that Acceptance Test No. 6 of the PM properly tested the changes to the suction pressure trip logic. However, the inspector found that the PM did not identify that u revision to MST-HPCI41R was require Currently MST-HPCI41R, Revision 5, Section 7.0, Step 7.8.124 tests the low pressure suction trip function. However, the procedure was not revised to test and calibrate the time delay function of the circuit. The licensee said they will issue a field revision to the PM to include a draf t revision to MST-HPCI41 I i
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In addition, the licensee plans to perform a HPCI vessel injection test  )
upon Unit I restart to evaluate the improvements in system reliabilit l The test results, the licensee's evaluation of these test results, and the  i overall assessment of the improvements in reliability will be evaluated during a subsequent NRC inspectio No violations or deviations were identifie . Drawing System Verification (71707)    a
The inspector conducted a review of the licensee's drawing control in the control room arid Technical Support Center. The review attempted to determine whether the licensee's drawing control efforts and programs satisfactorily supported operators in a meaningful way. The inspection included review and verification of a biased sample of drawing The inspector reviewed about 30 control room / operations aperture cards and drawings, over 30 hard copy Unit 1 P& ids, and about 30 aperture cards in the TSC. That review included verification of:
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Drawings present where distribution require Drawing or aperture card legibilit Drawing list revision number matched drawing revisio No outstanding plant modifications against the drawing that made the true status of a system difficult to determin The inspector found:
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Six missing drawings:
FP-55109, SH 1, 7, 8, Primary Containment Isolation System elementary logic, located in the Operations aperture collection in the back panel area of the control roo (Those same drawings were in the control room aperture card file.)
FP-F5109, SH 12, PCIS elementary logic, located in the control room aperture collectio FP-50015 SH 1, Reactor Protection System, Unit 2, in the TS D2020, SH 1, a Unit i hard copy drawing that was non-safety relate FP-55109, SH 12, Operations - was difficult to read. (Note that the j  same sheet was missing from the control room.)
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D-7029, SH 2A, Unit 2 Instrument Air System P&ID, was still stamped as requiring an update per PM-82-288F The inspector and an operator walked through the drawing verification process using this drawin The drawing had already been updated and thus was incorrectly marke l
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Two binders of hard copy P& ids were in the training library. The    i library becomes part of the TSC when an alert or higher is declare The Accident Assessment Team uses the information in the library to evaluate an event. No uncontrolled documents should be available for their us Less than 1% of hard copy P& ids for Unit I had outstanding plant modifications against them, thus requiring little additional work by the operator Other observations:
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Per 0I-29, Operations Internal Audit, the licensee had just completed (early 1989) a complete inventory of all control room operations aperture cards and hard copy P& id Several lists of missing drawings were sent to document control to complete the control room collection. The licensee had not, by the close of the inspection, verified whether the missing drawings identified by the inspector had also been identified by the operations staf The inspector also found that certain System Descriptions, or SDs, had too many plant modifications not incorporated in the documen Specifically, 50-18, Rev. 12, Core Spray System, had 8 plant modifications not incorporated and SD-19, Rev. 12, HPCI System, had 5 plant modifications not incorporate While the SDs are not operating procedures, they do describe the system and are available in the control roo The licensee corrects drawings using ENP-25, Rev. 6, Plant Drawing Correction Procedure. The procedure controls any corrections to drawings and requires a technical review of the drawing change with project engineer approval. The appropriate engineering document for safety reviews, an EER, is referenced in ENP-2 A previous audit by a third party found that as-built P& ids had not been available to operations prior to, nor at the time the plant    ]
modification was declared operable. It took about two weeks before    1 the updated aperture card was transmitted and made available to    {
operations. QA issued SFR-88-042 on September 26, 1988, to track the    l resolution of the issu By meno, on March 14, 1989, the licensee  ]
intends to issue a second " original" aperture card drawing directly to operations as an advance copy prior to declaration of operabilit l
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A P&ID comparison was made with the as-built plant condition as par of module 71710 (see paragraph 7 of this inspection report for Core Spray and paragraph 6 in inspection report' 88-38 for RHR). The plan configuration matched the P& ids. However, as noted, the operating procedure did not- match the P&ID indicated position , in rare instances. The OP governs valve position at Brunswick. However, the licensee still plans to correct the drawing The . inspectors concluded . that -the system for maintaining control room drawings was satisfactory and usabl No violations or deviations were identifie . Action on Previous Inspection Findings (92701) (92702) (CLOSED) Violation 325/86-11-03 and 324/86-12-03, Failure to Install Standby: Liquid Control Relief Valves With Discharge . Flooded. The licensee. has co'mpleted a plant modification that installed vent valves in the SLC relief valve discharge piping. Appropriate changes were made to, operating procedure OP-5, SLC System, to provide for-filling and venting the discharge piping. The inspector reviewed the procedure and inspected the vent valve They cbtermined to be  y adequate .to ensure' that the discharge piping is flooded to prevent  i boron precipitation within the valves, as . committed" to in FSAR  !
Section 9.3.4.2. Additionally, the licensee reviewed the i FSAR - to  I-ensure that plant procedures properly implement other =FSAR  ;
commitments for the SLC system. No additional discrepancies were  .i foun I (CLOSED)- Violation (325/87-02-05 and 324/87-02-05), Failure to Follow Maintenance Procedure When Installing Motor-0perated Valve Anti-Rotation Devices. The inspector reviewed the results .of; the licensee's anti-rotation device inspection which they . conducted .in'
response to this violation. This inspection was conducted under  4 Special . Procedure SP-87-002, . Inspection of Anchor Darling    i Anti-Rotation Devices. The licensee inspected 41 pressure seal-globe  '
valves on Units 1 and 2. They found six valves with problems associated with the installation / maintenance of the anti-rotation devic Based on this review, the inspector determined that the  1 licensee's assessment as to the cause of this violation is correc I To prevent recurrence, the licensee revised the applicable procedure to require that the lead mechanic sign off on the data sheet that the work has been done properl The inspector. reviewed corrective procedure CM-VGB509, " Anchor Darling Pressure Seal Globe Valves",
Revision 0, dated September 27, 1988, and verified that section 7.9.2'
and 7.9.3 requires that the lead mechanic verify and sign off on the data sheet that the anti-rotation device installation / maintenance work activities were performed in accordance with the procedur This had also been inspected in inspection report 88-0 ,
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  - (CLOSED)- Violation 325/88-14-03, ~ Failure to Perform 10 CFR 50.59
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Evaluation on~ Service Water System. .The inspector. reviewed the circumstances of the event and the licensee's response-to the. Notice of.' Violation dated June 3,1988. The inspector verified that the actions committed to by the licensee were' accomplishe The inspector did note that the licensee missed' the commitment date of .
September 1,1988, for the. development 'of improved policy guidance concerning conditions which constitute-potential deviations from the facility as described in the FSA The. failure to meet this commitment date was identified by .the licensee and result.ed in the issuance.of an.NCR. The guidance was subsequently provided. in .a memorandum dated September 7, 1988.'
d .' -(CLOSED) Unresolved- Item 325/87-36-05 and 324/87-37-05.- MSIV Pit Openings Not on Q-List; Reactor Building EQ Envelope May be Affecte This issue involved the potential for unsealed penetrations from'the'
MSIV pit'to the Reactor Building which, in the event of a MSLB in the .
pit, could possibly result.in higher peak temperatures and pressures l in the. Reactor Building than previously. analyzed in the licensee's EQ ,
program. The largest of the penetrations, one ventilation exhaust .
line and two ventilation supply lin~ es, are designed to automatically close in the event of a MSLB due to the pressure surg However,
  .these' dampers are not on the Q-List and, therefore, no credit can be taken for them to perform their safety functio The licensee performed an initial assessment - of the issue and concluded that continued operation of both units was justified. This conclusion was reached principally upon a comparison of the energy releases into the general areas of the Reactor Building associated with the previously analysed 10" HPCI DEGB versus that from the various postulated short lived MSL critical crack / double ended ..
f guillotine scenario Subsequent to the initial assessment, the licensee has performed additional analysis to show that the harsh environment in the Reactor Building (excluding the MSIV pit) due to a ,
MSLB in the pit, is bounded by their previous Reactor Building  j analysi The additional analysis was presented in EER 89-0020, dated January 24, 1989. The evaluation uses Reactor Building temperature /
pressure response data from UE&C Study Report 7992-303-S-W-048, dated January 31, 1989. The report evaluated certain break sizes, time response and damper positions, and the effect on the EQ envelop '
The evaluation further states that a DEGB was not considered because stress analysis results and the configuration of pipe whip restraints preclude an assumption of a DEGB in the pit I
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  ,The. pressure and ' temperature transients resulting from. each of the -
cases examined, show that'the licensee's previous Reactor Building-environmental profile is still the limiting case for'all-' areas in the Reactor Building except for: the MSIV. pit. 'The previous MSIV peak-temperature was '297 degrees F. The 'new profile, based on case 1 above, . shows a peak temperature of ' 375 degrees. F. The licensee evaluated this condition and concluded that this profile did not
,  impact on the qualification of FQ equipment' installed in the MSIV pi This conclusion was based on the short lived nature of the profile and that the EQ equipment located in the pit had been previously -qualified for conditions ' representative of drywell accident environments. Although the licensee considers this new profile to be acceptable for existing equipment in the pit, they will update their Reactor Building environmental report to snow these new parameter (CLOSED) Unresolved Item 325/88-18-06 and 324/88-18-06, Control Room Fire Detectors' Affect on CBEAF Operabilit In response to the inspection item, the licensee re-examined the operability' of CBEAF with the loss of the automatic initiation function due to smoke detection in the control room area. The licensee determined that the smoke detection function was required for. the CBEAF system to be considered operable. To clarify this information for the operators, a Memorandum, BSEP/89-0110, was sent to the operations manager explaining - the requirement for the . smoke detection function for CBEA In addition, the licensee has modified PT-34.4.1.3 Control Building Fire Detection Instrumentation Operability Test, .to discontinue the use of the disconnect switc The inspector then reviewed completed copies of PT-34.4.1.3, to determine if any violations of the plant's TS occurred. The time that' the disconnect switch for the alarm panel was taken to disconnect was not recorded during the performance of the test, however, a caution was placed in the procedure which requires that the system be aligned for normal operation if a break of greater than 15 minutes were to oct.ur during the performance of the test. Based on this information and the inspector's observation during the performance of the test, the TS time limit was not exceede (OPEN) Unresolved Item 325/88-38-02 and 324/88-38-02, Failure to Include All LPCI and Suppression Pool Cooling Flow Path Boundary Valves in Their Surveillance Program. Further questions were raised by the inspectors concerning flow path boundary valves and the necessity to verify their valve position as part of the required monthly surveillance chec Specifically, the core spray minimum l  flow valve, F031A/B, is not checked monthly for proper position, The 1  licensee has stated that this valve is not in the flow path when core spray would be performina its safety function, namely, injecting l
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'?' '(CLOSED) . Unresolved Item 325/89-02-03, Inadvertent Draining' of SLC Tank. The inspector reviewed the' licensee's operability assessment of the -SLC system during the inadvertent draining even The licensee concludedLin their evaluation that the SLC remained operable during the' time that water Ws inadvertent 1y' drained from the SLC tank through the F010/F014 valve bonnets. The licensee's conclu,lon was based on the volume / concentration of the tank at the time of toe event, the leak rate caused by the work, the injection requirements of SLC had it been required, and the NPSH'available to'the SLC pump The inspector had no other questions concerning the operability of the SLC system.
,  As noted in inspection report 89-02, the lean from the SLC tank resulted from inadequate clearance / work control:,. The work involved repairs to valves .the F010 and F014 which were contributing to demineralized water leakage into the SLC tank. The-clearance which established the work boundaries was not adequate for work on the F010 and F014 valves. Even if the work had been only on the F010 valve as thought-by the SF authorizing the clearance, the boundary still would'
not .have been sufficient; however, no leakage would have occurre Maintenance personnel also removed the locking devices'-from both the valves (with operation's permission), operated the' valves, and then proceeded to loosen the bonnet bolts. The manipulation of valves by maintenance personnel is permitted by- plant procedures proviaed the
  ~ valves are within the established work boundaries and the valves are listed in Attachment C, BSEP. Clearance Tag Sheet. Attachment C of clearance 1-189A,. which established the boundaries, did not list the F010 or .the F014 as valves to be manipulated. The inspector also noted that the maintenance personnel had accepted clearance 1-189A,
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signifying that they agreed the clearance was adequate for the work.
I  The failure of plant personnel to follow plant procedures concerning equipment clearances. is listed as a Violation:  Failure to Follow Equipment Clearance Procedures (325/89-05-01).
One violation was identified, l 1 Exit Interview (30703)
The inspection scope and findings were summarized on March 15, 1989, with those persons indicated in paragraph 1. The inspectors described the  i areas inspected and discussed in detail the inspection findings listed  '
below and those addressed in the report summary. Dissenting comments were l  not received from-the licensee. Proprietary information is not contained in this report.
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  -Item Number  Description / Reference Paragraph 325/89-05-01 VIOLATION - Failure to Follow Equipment Clearance Procedures, (paragraph 12.g).
324/89-05-02 VIOLATION - Failure to Complete Valve / Breaker Exception Form for an Unlocked Valve, (paragraph 4.c).
324/89-05-03 ;IOLATION - Inadequate Surveillance of Stored Pressure Dry Chemical Fire Extinguishers, (paragraph 4.b).
325, 324/89-05-04 IFI - Submission and Approval of Clarification of SDM and Core Alterations, (paragraph 4.a).
1 List of Abbreviations for Unit 1 and 2 AI Administrative; Instruction A0 Auxiliary Operator AOP Abnormal Operating Procedure APRM Average Power Range Monitor ASME American Society for Mechanical Engineers BSEP Brunswick Steam Electric Plant BWR Boiling Water Reactor CBEAF Control Building Emergency Air Filtration C0 Control Operator CP Corrective Procedure CR Control Room      I CRD Control Rod Drive CS Core Spray DEGB Double Ended Guillotine Break DG Diesel' Generator EDG Emergency Diesel Generator EER Engineering Evaluation Report ENP Engineering Procedure EQ Environmental Qualification ESF Engineered Safety Feature F Degrees Fahrenheit FSAR Final Safety Analysis Report HP Health Physics HPCI High Pressure Coolant Injection I&C Instrumentation and Control IFI Inspector Followup Item IPBS Integrated Planning Budget System LER Licensee Event Report LPRM Local Power Range Monitor MSIV Main Steam Isolation Valve l
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MSLB Main Steamline Break-MST' Maintenance Surveillance Test
Sincerely, ORIGN AL SIGNED PV DAYlp M. VERRELLI David M. Verrelli, Chief Reactor Projects Branch 1 Division of Reactor Projects cc:
.NC .Non-Conformance Report NPSH- Net. Positive Suction Head-
R. B. Starkey, Jr., Manager Brunswick Nuclear Project J. L. Harness, Plant General Manager State of North Carolina bec: NRC Resident Inspector Document Control Desk RII R1 RCarroll HDanc 06/$/89 06/g/89 I O 8906280231 890613 PDR ADOCK 05000324 L
'NRC Nuclear Regulatory Commission 0I Operating Instruction 0F Operating Procedure-OWP Operations Work Permit P&ID Piping & Instrumentation Data PA Protected Area PCIS Primary Containment Isolatien System
G PNU CEO/
'PM . Plant Modification PNSC : Plant Nuclear Safety Committee PT- ' Periodic Test-QAL . Quality Assurance QC- Quality Control RHR Residual Heat Removal RPS Reactor Protection System RSCS Rod Sequence Contro1' System
'RTGB Reactor Turbine Gauge Board SD System Description SDM' _ Shutdown. Margin SF Shift Foreman SIL Service Information Letter SLC Standby Liquid Control SRI Select Rod Insert SRM Source Range Monito STAE Shift Technica1' Advisor ETI . Temporary Instruction TS Technical Specification TSC . Technical Support Center UF&C United Engineers & Constructors
.URI' Unresolved Item VDC Volts Direct Current
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Latest revision as of 02:28, 2 December 2024

Ack Receipt of Informing NRC of Steps Taken to Correct Violations Noted in Insp Repts 50-325/89-05 & 50-324/89-05
ML20245F745
Person / Time
Site: Brunswick  Duke Energy icon.png
Issue date: 06/13/1989
From: Verrelli D
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To: Eury L
CAROLINA POWER & LIGHT CO.
References
NUDOCS 8906280231
Download: ML20245F745 (1)
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. Docket Nos. 50-325;-50-324 License Nos. DPR-71, DPR-62 j

Carolina Power and Light Company ATTN: Mr. Lynn W. Eury Executive'Vice President-Power-Supply.

P..O. Box 1551-Raleigh, NC 27602 Gentlemen:

SUBJECT: ;NRC INSPECTION REPORT N05. 50-325/89-05 AND 50-324/89-05 p.

Thank you for your response of May 15, 1989, to our Notice of Violation issued

on April 6,.1989, concerning activities conducted at your Brunswick facility.

'

We have' evaluated your response and found that it meets the requirements of 10 CFR 2.201.

'We. will examine the implementation of your corrective actions -

during' future inspections.-

We appreciate your cooperation in this matter.

-

Sincerely, ORIGN AL SIGNED PV DAYlp M. VERRELLI David M. Verrelli, Chief Reactor Projects Branch 1 Division of Reactor Projects cc:

R. B. Starkey, Jr., Manager Brunswick Nuclear Project J. L. Harness, Plant General Manager State of North Carolina bec: NRC Resident Inspector Document Control Desk RII R1 RCarroll HDanc 06/$/89 06/g/89 I O 8906280231 890613 PDR ADOCK 05000324 L

G PNU CEO/

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