IR 05000324/1986025: Difference between revisions

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{{Adams
{{Adams
| number = ML20207B261
| number = ML20212B473
| issue date = 10/31/1986
| issue date = 12/22/1986
| title = Safety Insp Repts 50-324/86-25 & 50-325/86-24 on 860901-1004.Violation Noted:Failure to Establish Adequate Procedure Re Diesel Generator Jacket Water Cooler Svc Water Valve
| title = Ack Receipt of 861126 Ltr Informing NRC of Steps Taken to Correct Violations Noted in Insp Repts 50-325/86-24 & 50-324/86-25
| author name = Fredrickson P, Garner L, 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 = Utley E
| 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 = 50-324-86-25, 50-325-86-24, NUDOCS 8611110556
| document report number = NUDOCS 8612290258
| package number = ML20207B173
| document type = CORRESPONDENCE-LETTERS, NRC TO UTILITY, OUTGOING CORRESPONDENCE
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| page count = 1
| page count = 26
}}
}}


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/arolina C Power and Light Company ATTN: Mr. E. E. Utley Senior Executive Vice President Power Supply and Engineering and Construction P. O. Box 1551 Raleigh, NC 27602 Gentlemen:
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SUBJECT: REPORT N05. 50-325/86-24 AND 50-324/86-25 Thank you for your response of November 26, 1986, to our notice of Violation, issued on October- 31, 1986, concerning activities conducted at your Brunswick facilit 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 inspection We appreciate your cooperation in this matte
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. . UNITED STATES
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o  NUCLEAR REGULATORY COMMISSION g" 3  REGION 88 g,
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  ,j  101 MARIETTA STREET. '*  ATLANTA. GEORGI A 30323
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Report Nos. 50-325/86-24 and 50-324/86-25 Licensee: Carolina Power and Light Company P. O. Box 1551 Ralei 0h, NC 27602
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Docket Nos. 50-325 and 50-324   License Nos. DPR-71 and DPR-62 Facility Name: Brunswick 1 and 2 Inspection Co  October 4, 1986 cte g September 1 Inspectors: C  -
      /0!3/!M g Rulagd
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Cate Signed
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10 3) N
  $ L. W. Garner    IFate 6igned Accompanying Per 1: J. R. Patterson eptember 29 - October.3, 1986)
Approved by: \/. f\)
P. E.'Fredrickson, Section Chief
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      /d!3//M Bate'5fgned DivisionofReactorProjects    -
SUMMARY Scope: This routine safety inspection involved the areas of maintenance obser-vation, surveillance observation, operational safety verification, Engineered Safety Features (ESF) System walkdown, onsite Licensee Event Report (LER) review, in-office LER review, followup on inspector identified and unresolved items, IE Bulletin followup, sequence of events for Unit 1 scram, TMI action items, Site Work Force Control Group meetings, internal exposure control and assessment, plant modifications, and maintenance experience report review,


Results: One violation - failure to establish an adequate procedure regarding a diesel generator jacket water cooler service water valve, paragraph 1 PDR 0 ADOCK 05000324 PDR
Sincerely, ORIGtNAL SMEU "Y DAVID M. VERRELLI David M. Verrelli, Chief Reactor Projects Branch 2 cc: . W. Howe, Vice President Brunswick Nuclear Project
/.R.Dietz,PlantGeneralManager bcc:VNRC Resident Inspector Document Control Desk State of South Carolina 8612290258 861222 DR ADOCK0500g4
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g Pfredrickson DVerrelli 12/15/86 12/(f/86 12/5/86


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REPORT DETAILS 1. Licensee Employees Contacted P. Howe,'Vice President - Brunswick Nuclear Project C. Dietz, General Manager - Brunswick Nuclear Project T. Wyllie, Manager - Ergineering and Construction l G. Oliver, Manager - Site Planning and Control J. Holder, Manager - Outages E. Bishop, Manager - Operations l L. Jones, Director - Quality Assurance (QA)/ Quality Control (QC)
R. Helme, Director - Onsite Nuclear Safety - BSEP J. Chase, Assistant to General Manager l J. O'Sullivan, Manager - Maintenance l G. Cheatham, Manager - Environmental & Radiation Control l
B. Parks, Acting Manager - Technical Support K. Enzor, Director - Regulatory Compliance R. Groover, Manager - Project Construction
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A. Hegler, Superintendent - Operations J. Wilcox, Principal Engineer - Operations W. Hogle, Engineering Supervisor ineering Supervisor l
B. Wilson,I&C R. Creech, Eng/ Electrical Maintenance Supervisor (Unit 2)
l R. Warden, I&C/ Electrical Maintenance Supervisor (Unit 1)
i W. Dorman, Supervisor - QA l W. Hatcher, Supervisor - Security
: R. Kitchen, Mechanical Maintenance. Supervisor (Unit 2)
! C. Treubel, Mechanical Maintenance Supervisor (Unit 1)
l R. Poulk, Senior NRC Regulatory Specialist D. Novotny, Senior Regulatory Specialist W. Murray, Senior Engineer - Nuclear Licensing Unit Other licensee employees contacted included construction craftsmen,
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engineers, technicians, operators, office personnel, and security force member . Exit Interview (30703)
The inspection scope and findings were summarized on October 7,1986, with the general manager. The violation, failure to establish an adequate were
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procedure discussed(paragraph in detall. 10),
Theand an unresolved licensee Item (paragra)h acknowledged the findings10)ithout w
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exceptio The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspectors during the inspection.
 
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3. Followup on Previous Enforcement Matters (92702)
Not inspected.
 
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4. Maintenance Observation (62703)
The inspectors observed maintenance activities and reviewed records to verify that work was conducted in accordance with approved procedures, Technical Specifications (TS), 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 Outstanding work requests were reviewed to ensure that the licensee gave priority to safety-related maintenanc The inspectors observed / reviewed portions of the. following maintenance activities:
MI-03-1BX14 821-PT-N023A, B, C, & D Rosemount Gauge Pressure Trans-mitte MI-10-511A Mechanical Inspection and Lubrication of Limitorque Operators Installed in Q-List Equipment - Unit MI-10-511B Mechanical Inspection and Lubrication of Limitorque Operators Installed in Q-List Equipment - Unit AJUU1 Replace Printed Circuit Board on 23A-2 Battery Charge BHUB1 No. 2 Fuel Oil Tank Level Switch Repai BLZJ1 Maintenance on LPRM 44-37- BMJN2 High Pressure Coolant Injection (HPCI) F008 Valve Spring
,  Pack Inspectio BNAG1 2C Conventional Service Water Pump Motor Oil Cooler Repai BNEG1 Unit 2 Main Steam Line Radiation Monitor D Repai BNJJ1 Unit 1 HPCI Steam Line Outboard Isolation Valve, F003, Yoke Clamp Stud Replacemen No violations or deviations were identified.
 
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5. Surveillance Observation (61726)
The ~ inspectors observed surveillance testing required by Technical Specifi-cations. Through . observation and record review, the inspectors verified that: . tests conformed to TS 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 proper return to service of equipmen The inspectors witnessed / reviewed portions of the'following' test activities:
1MST-APRM23Q Average Power Range Monitor (APRM) C Channel Calibration /
Functional Tes MST-HPCI27M HPCI and Reactor' Core Isolation Cooling (RCIC) Condensate Storage Tank (CST) Low Water Level Instrument Channel, Calibratio .1 Periodic Testing and Control 0perator Daily Surveillance Report - Unit .2 Periodic Testing and Control Operator Daily Surveillance Report - Unit PT-1 Standby Gas Treatment System Operability (Unit 1).
 
During performance of 2MST-HPCI27M, a monthly procedure, the ' inspector observed that step 7.2.25 was misinterpreted. The step states, "Close drain valve on the E41-LSL-N002 and E51-LSL-4464 Instrument Drain Valve, CO-V151."
 
The individual closed C0-V151 instead of closing the drain valve on C0-V15 The drain valve on C0-V151 has no number. Closure of the wrong valve isolated the level device. When the subsequent steps were performed to
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determine the reset of the switches, the-reset value could not be determine The ~ technicians re-aligned the valves and completed the reset check satis-factorily. The item was discussed with the appropriate crew superviso The licensee plans to clarify the procedure step and evaluate the'desira-bility of numbering and tagging the subject valv No violations or deviations were identifie . Operational Safety Verification (71707)
The inspectors verified conformance with regulatory requirements by direct observations 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 TS were met. Control room, shift supervisor, clearance and jumper / bypass logs were reviewed to obtain information concerning operating trends and out of service safety systems to ensure that there were no conflicts with TS Limiting Conditions for Operations (LCO). Direct obser-vations were conducted of control room panels, instrumentation and recorder L
 
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traces important to safety to verify operability and that parameters were within TS limits. The inspectors observed shift turnovers to verify that continuity of system status was maintained. The inspectors verified the status of selected control room annunciator Operability of a selected ESF train was verified by insuring that: each accessible valve in the flow path was in its correct position; each power supply and breaker, including control room fuses, were aligned for components that must activate upon initiation signal; removal of power from those ESF motor-operated valves, so identified by TS, was completed; there was no leakage of major components; there was proper lubrication and cooling water .
available;'and a condition did not exist which might prevent fulfillment of the system s functional requirements. Accessible instrumentation essential to system actuation or performance was verified operable by observing on-scale indication and proper instrument valve lineu The inspectors verified that the licensee's health physics policies /proce-dures were followed. This included a review of area surveys, posting, and instrument calibratio 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 protected area (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; and effective compensatory measures were employed when require The inspectors also observed plant housekeeping controls, verified position of certain containment isolation valves, and verified the operability of onsite and offsite emergency power sources.
 
; Items Noted During Walkdown O'n September 14, 1986, the inspector observed no position indication for the "F" Drywell to Suppression Chamber Vacuum Breake The licensee immediately investigated and found that the close indication light bulb
 
was burned out. The bulb was replaced and the position indication returned to servic On September 23, 1986, the inspector observed that the Unit 1 Local Power Range Monitor (LPRM) detector at position 04-29 level D, showed a downscale indication. Because the reactor had reached approximately 90% of full power after a scram recovery, this appeared abnormal. The licensee investigated the indication and determined that the LPRM was inputing into APRM B correctly and hence, the requirement to have 2 operable detectors at each level (T.S. Table 3.3.1-1, note c), was being me The detector showed an output of 27 watts /cm The set-point for the downscale indication is 5 watts /cmi. The licensee initiated a trouble ticket to correct the downscale indicator circui ,-  .
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On September 26, 1986, theinspectorobservedthaN?-SW-PI-2871,the 2C conventional service water pun 9 lube water supply: pressure indicator, was reading zero. This might .inoicate a lack of lube water to the 2C conventional service water pump motor upper seal oil cooler. The supply- and return lines to the c'ooler also felt abnormally warm, indicating low or no flow to the cooles  BecatGe of the pumps particular piping configuration, it is difficult to determine if flow is discharging from the return line. This condition was reported to the licensee who verified the condition, shut the pump down, and
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initiated a work request, 86-BNAG1, ^to correct tJe problem. The pressure regulating valve contained illt. The cyclorae separator was-cleaned and the lines were flushed before the pump was returned to servic .
p On October 2,1986, a followup inspection of the labe water supply to the 2C conventional service water pump retealed that relief valve, 2-SW-RV11, was partially diverting flow fros the motor cooler. The valve, located between the pressure reducing valve and the motor cooler, was not seated at an indicated prerisure of,16 psig. The normal setpoint is 25 plus or minus 2.5 psig; sThe licensee issued work request 86-BNXAl to correct ths problem. .The inspector also observed that the conduit to the 2C converttional sirvice water pump strainer motor is rusted at the floor level such that the conduit is partially broken and is bent to one side. The_. licensee has issued work request 86-BNWY1 to evaluate the condition, b. Unit 1 Residual Heat Removal (RHN) Room Coolir  -
The licensee isolated the service water to the Unit' 1 south (A) RHR room cooler due to a one-half gallon per minute leak. The north (B)
RHR room cooler was functional. The inspector noted the cooler was isolated during a routine inspection on September 25, 198 '
The coolers are redundant, each ~ capable of cooling the RHR, RCIC and HPCI area The coolers are parteof the reactor. building emergency cooling system, described in FSAR Section 9.4.3. The coolers are designed to keep the Emergency Core Cooling System (ECCS) areas at or below 148 degrees F during an emergency pumping situation. The coolers are thermostatically operated. During normal operation, the A cooler will start if temperature reaches 120 degrees F and an alarm will go
:  off in the control room. At 145 degrees F, the B room cooler will start, but no alarm will soun /
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The licensee had isolated the service water tq the A RHR room cooler on September 24, 1986, and had taken a tracking 1.C0 'o bt on the equipmen A tracking LCO helps the lic~ensee to keep track of TS equipment that is out of servic No ACTION statement has yet been entere The inspector questioned the operability of the affected ECCS systems because a single failure with one cooler out could totally disable cooling to those ECCS system The license.e stated that no LC0 existed because:
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.        t k o analysis shows that room coolers are not needed during the first 10 minutes of an acciden '
o After 10 minutes, the licensee can take credit for operator actio o Annunciators and their associated procedures would direct the operator to send an auxiliary operator to unisolate the A RHR room. cooler if neeoe The inspector plans to - review further the licensee's operation of the RHR room coolers with one cooler isolated. This is an Inspector Followup Item: Review RHR Room Cooler Operation (325/86-24-05).
 
No violations or deviations were identifie . Engineered Safety Features System Walkdown (71710)
The inspectors performed a walkdown of the accessible portions of the Units 1 and 2 RHR. systems to verify system operability. The walkdown  i included the accessi'ile portions of the LW Pre <.sure Coolant Injection 's-(LPCI) mode, the shutdown cooling mode, the suppression pool cooling mode, s s the suppression pool spray piping, the minimum flow and test return lines to the suppression pool, and containment spray piping. Neither the head spray lines . nor the f"el pool cooling to the RHR system cross-connect lines were '
included. The inspectors verified that: hangers and supports were func-tional, valves and pumps were properly maintained, component labeling was correct, instrumentation was properly installed and functioning, valves were in the correct position, power was available to motor-operated valves, and the Division I and Division II cross-tie valves (F010) were closed with power removed as per TS 4.5.3.2. The inspector verified that the system check lists in OP-17, Residual Heat  I Removal System Operating Procedure, Revision 10 for Unit 1 and Revision 66  -
for Unit 2, contained the major system valves as indicated by the RHR piping and instrumentation drawings, D-25025 Sh. lA (Rev. 29), D-25025 Sh.1B  g (Rev. 27), D-25026 Sh. 2A (Rev. 33), D-25026 Sh. 2B (Rev. 31), D-2525 Sh. lA (Rev. 31), D-2525 Sh. IB (Rev. 29), D-2526 Sh. 2A (Rev. 31), and D-2526 Sh. 2B (Rev. 32).    ,
The following items were identified:    iI -
On September 8, 1986, the inspector and a member of the licensee's  [
engineering staff observed that the stem protector for 1-E11-F028B was  ,
missing. The valve is the Unit 1, Division II Suppression Pool Discharge Isolation valve. The valve was last inspected on July 20, 1986, per MI-10-511A, Mechanical Inspection and Lubrication of Limitorque Operators Installed
  'in Q-List Equipment - Unit 1 Reactor. Step 3 of this procedure requires'the removal of the stem protector to allow inspection of the stem. Step 4 requires replacement of the stem protector. The procedure completed in  i July 1986 makes no reference to a missing stem protector. The licensee has verified that no authorized work has been performed on the valve since that  4 time. The only outstanding work request on the valve is one which specifies  ,,
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A L  that the valve needs to be repacked. The Unit 1 mechanical supervisor indi-
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  . cated. that the work crew who last performed MI-10-511A vaguely remember
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finding a valve in the general area without a stem protector;, however, they thought.a work request had been issued to correct the problem. None I can beifound. The licensee installed a stem protector on E11-F028B on
;-  September 10, 1986, per work request 86-BKWU .
t  On ' September 29, 1986, the ' inspectors observed that the stem protector
;  extension for 2-E11-F0478 was unthreaded and laying against the ste This valve is the Unit 2, Division II RHR heat exchanger inlet valv The 2-E11-F004D valve was found with duct tape over the top of the stem protector :instead of. a metal _ cap. In' addition, on September 10, 1986, the
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licensee found 1-E11-F075, the RHR service water inboard injection valve, with no stem protector installed. MI-10-511A had also been performed on i  1-E11-F075 during 1986. The licensee issued work requests to correct the
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  ' deficiencies. The last performance of the similar maintenance instruction on' Unit 2 for 2-E11-F047B and 2-E11-F0040 was not examined by the inspector.
 
!. The licensee has also performed inspections of other accessible Unit-1 valves and,found no additional missing stem protectors. A similar inspection-
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is planned for Unit 2. The licensee stated that in 1984, stem protectors were repla'ced on both 1-E11-F028B and 1-E11-F075 (work request- 1-M-84-4729).
 
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All the above mentioned valves are' considered Environmentally Qualified N (EQ). Failure ,to, have the stem protectors properly installed does not
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render the valves inoperable or violate the EQ status.of the valve actuator The Limit'orque Corporation BWR Qualification Report Addendum A, No. 600376A,
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dated January 1979, states in Section 3.3, paragraph D, that,.
  ...,(ttihy). designed the actuator with the philosophy that the environmental
; s  ambient conditions be permitted to enter the actuator with minimal restric-4 '
tions,' thus insuring a reliable unit that _has .the capability of performing  i its function during an accident." Hence, the missing stem protectors do not
,  effect the EQ status of the valves. A non-conformance report, NCR S-86-045, was issued on October 2,-1986,- concerning stem protector o  The inspector observed on both units that "U" bolts and/or "U" bolt nuts
,  were missing from the RHR discharge header relief valves, F025A and B, discharge lines. The licensee wrote a work request to correct the problem.
 
j  Two snubbers; 1-E11-113SS157 and 2-E11-113SS410, showed early signs of
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corrosion on the shafts. Work request 86-BNLE1 and 86-BNRB1 were' issued to evaluate their condition. The licensee has contacted the vendor to see if
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some protective coating can be applied to prevent corrosion and/or pitting i
of the shaft s The following items on other systems were observed and reported to the licensen: !
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o Unit 1 structural support steel for mark No.1-E51-42SS78 appeared to have only a tack weld. This is not-in accordance with design. drawing-9527-F-12025. The licensee considers the support o issued a site memorandum, BPE-4918, to resolve theas'perable  but- has constructed"
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with the design drawin .
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o Unit 1 RCIC barometer condenser condensate pump discharge .line sway
 
. support between the- E51-F004 ~ and E51-F005 valves was -missing a cotter
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  . pin. Work request 86-BKMH1 issued to correc ;
        ~ ~ Unit 1:RCIC steam line temperature sensor junction box'Q17 had water
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standing on it as a result of condensation of a-nearby steam lea ' Work request 86-BKMS1 issued to correct steam-leak.
 
o ' Unit-1 RCIC snubber 1-E51-42SS75 had low fluid indicatio Licensee refilled snubbe o Unit 1 HPCI outboard steam line. isolation valve,1-E41-F003, was observed on September 30, 1986, to have. nuts on both sides of two studs not fully engaged. This represents 2 out of the 4 studs on the yoke clamp.- The yoke-clamp holds the yoke and actuator assemblies to the      !
;  bonne The licensee installed longer studs on October 1,1986, .in
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accordance' with work request 86-BNJJ1. Review of records indicates      '
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that the valve was last re-assembled on May.23, 1983, per work request
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'  1-M-82-319 The valve is located 'in a high radiation are The licensee reported that the blanket Unit 1 walkdowns had not yet covered this valve or other valves.
 
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o Unit'2 HPCI suppression pool high level switch 2-E41-LSH-N015A (used to transfer' suction from condensate storage tank on high level), was found to have the' adjacent "U" bolt missing on one instrument leg and the adjacent "U" bolt nuts loose on the other instrument' le o The housekeeping was generally good.. However, additional attention was r  needed in less accessible. areas. Trash such as pieces of paper, cloth gloves, rollt ef duct tape, etc. , were seen in cable trays and laying i  on valves _ ano other components on the HPCI roo i
;  The ' inspectors believe that the above-mentioned items, especially .the HPCI
:  : steam valve, the stem protectors, and the 2C conventional service water motor cooler (see paragraph 6), underscores a continuing weakness .on the licensee's part to identify and/or maintain equipment in the designed configuration. A similar problem was identified as a violation in inspec-tion' report No. 325,324/86-01, paragraph 6. The inspectors have been
;  informed that in response to report No. 325,324/86-01 and.their own manage -
ment ' initiatives, more than 700 work requests have been initiated and
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completed to address items in this --area of concern. The inspectors have
;  determined through review of outstanding work requests that the effort is
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ongoing. Additional management attention is needed to further increase plant staff awareness of plant components and their condition. Because of the ongoing efforts in this area with regard to corrective action for the      :
previously discussed violation, no Notice of Violation is being issued; but management needs to reemphasize corrective action in this area to avoid potential future enforcement actio No violations or deviations were identified.
 
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b Onsite Review of Licensee Event Reports (92700)      ,
l  The 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
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have been taken in accordance with existing requirements, licensee conditions    :
and commitments.
 
  (CLOSED) LER 1-85-55, Auto Starting of Emergency Diesel Generators and 4  Primary Containment Groups. 2, 3, 6, and 8 Isolations Resulting from Loss of Emergency Electrical Buses E-1 and 10. While the plant was in mode 5,
!  an inadvertent short occurred during connection of a voltmeter. This resulted in a . trip of unit electrical bus I The unit's emergency AC diesel generators (DG) started and DG No.1 tied on.to E-1 to re-energize the bus. Other equipment isolations and initiations occurred ~as expected.
 
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The subject. plant modification acceptance work procedure was revised to
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change the physical method of- making electrical connections. This should preclude inadvertent shorting between adjacent terminals.
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  -(CLOSED) LER 2-83-08, CST Level Low Instrument Calibration Problem - Vent Partially Blocked. Maintenance has performed 4 annual inspections which
;  found no evidence of organic-deposits or residue. In 1986, the licensee decided further annual inspections were' not necessary. A Task Action Request, TAR 883-221, has been issued by engineering to modify the vent line-
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but the project has not been funded. As an interim measure, the licensee has made a permanent change to MST-HPCI27M, HPCI and RCIC CST Low Water Level Instrument Channel Calibration, to blow compressed air through the vent. This is performed monthly. This has proven sufficient' to prevent recurrence of the problem. LER 2-83-51 also involved a similar e~ vent.
 
j  (CLOSED) .LER 2-83-25, Drywell to Suppression Pool Vacuum Breaker ' Closed
{  Indicator Failed. The inspector reviewed completed work request 2E-83-588,
!  which repaired the subject switc The inspector has no further questions at this time.
 
L (CLOSED) LER. 2-83-29, Missing Latch and Out of Adjustment Seal on Reactor Building Airlock. The items were repaired by work requests 2M-83-534, 555, 578 and 717. The inspector verified that the doors are included in the periodic inspection procedure MI-10-5238, Swinging Door Inspection - Reactor No.-2, Revision 1, dated October 27, 198 '(OPEN)- LER 2-83-33, Main Steam Line Radiation Monitors A and D Out 'of
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Calibration. The subject monitors were re-calibrated. The licensee
!-  reported that an outdated section of the calibration procedure was used for calibration of the D channel. The licensee modified their administrative L  controls concerning. permanent changes when initiated by temporary revision The inspector reviewed the applicable Administrative Procedure, section 5.5, and has no further questions at this tim Because of noise from other
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  ' instrumentation during calibration-and recurring drift problems with the existing instrumentation, the-licensee is evaluating installation. of new monitor drawer These new electronic packages (GE NUMAC), are on site.
 
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Installation of these drawers will first be on the Steam Jet Air Ejector
  '(SJAE) radiation monitors. Installation in the main steam line radiation monitor circuit will proceed if the equipment performs well in the SJAE
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,  service. This item will remain open pending evaluation and' installation of the new equipmen (CLOSED) LER 2-83-50, Remote Shutdown Re'sidual Heat Removal System Flow and Head Spray Flow Indicator Instrument Inadvertently Isolated. The event was attributed to personnel erro The licensee committed to have appropr1 ate plant operations personnel review the LE The inspector verified via the
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training roster. and the certification forms that the subject review was completed by the. majority of licensed operator ,
  (CLOSED) LER 2-83-51,. CST Level Low Instrument Did Not Respond to Test Input Due to Vent Line Blockage. This is a-similar item to that-reported
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in LER 2-83-08. See LER 2-83-08 write-up in this repor ~
!  (CLOSED) -LER 2-83-53, Main Steam Line Radiation Monitor D Out of Calibra-tion. This is similar to LER 2-83-33. See write-up on LER 2-83-33 in this
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report. This item is-being closed for administrative purposes.
 
I  (CLOSED) LER 2-83-56, Control Rod 26-19 Does Not Have Position Indication for Several ~ Notche The problem was corrected in June 1984, by repair of a bent pin in the position indicator probe connecto (CLOSED) LER 2-86-20, Reference Leg Perturbation Initiate Reactor Scra This item is-discussed in paragraph 17 of this repor No violations or deviations were identifie l In Office Licensee Event Report Review (90712)
The 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
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  ' generic problems and the relative safety significance of the even (CLOSED) LER 1-85-23, Primary Containment Group 8 Isolation of Reactor Shutdown Coolin While the unit was in a refueling outage with the reactor cavity flooded and the fuel po~ol gates removed, the residual heat removal
,
system shutdown cooling inboard valve,1-E11-F009, shut. This event was attributed to a spurious interruption of the logic circuitry to the reactor steam dome pressure instrument, 1-B32-PS-N018A- A possible cause was
  ' ongoing work activities in the vicinity of the associated centrol room
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residual heat removal isolation actuation relays. Possible correlation could not be determined. The instrument actuation setpoint was checked and found within required tolerance , --.--,  .., ..
 
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(CLOSED) LER 1-85-52, Primary Containment Group 6 Isolation During Investigation of Alarm Annunciation. A bad solder joint connection caused the event. The connection was repaired and the radiation monitor returned to service within two hour No violations or deviations were identifie . Followup on Inspector Identified and Unresolved Items (92701)
(CLOSED) Inspector Followup Item (325/83-26-03 and 324/83-26-03), Refurbish Fire Pump Diesel Fuel Line Solenoid Valve. The licensee performed an analysis which demonatrated that the subject valve setpoint could not be set such that the intended function could be met. The valve was installed to isolate the line if a break-should occur to prevent a fire from damaging th nearby electric driven fire pump. The licensee submitted on September 19, 1985, a request for relief from this commitment. On September 17, 1986, a letter from E. Sylvester to E. Utley granted _the relief based upon other-measures taken by the license The subject valve has been remove (CLOSED) Unresolved. Item (324/86-22-02), Diesel Generator No. 4 Jacket Water Cooler Service Water Outlet Valve Not Full Open. The inspector had found the above not fully open during a plant tour on August 26, 198 An auxiliary operator had partially closed the DG No. 4 jacket water cooler service water outlet valve (SW-V209) to clear a local low service water pressure alarm. OP-39, Diesel Generator Operating Procedure, Rev. 28, June 25, 1986, Section 8.1, addresses adjusting lube oil and jacket water temperatures. The procedure does not require the operator to manipulate the jacket water cooler service water outlet valves. OP-39, Section 8.1, addresses adjustments of the temperature control bypass valves, the jacket water cooler outlet automatic Temperature Control. Valves (TCV), and the lube oil TCVs. No other procedure addressed how jacket water cooler service water outlet valves should be adjusted when changing jacket water pressure for the DG The operator had adjusted V209 and two other DG jacket water cooler service water outlet valves on August 23, 1986, in response to a local low service water pressure alarm. The annunciator procedure, APP-DG-LP, Annunciator Procedure for Diesel Generator Local Panels, Rev. 0,. April 24,1986, alarm 3-8, low service water pressure does not require the operator to adjust V20 Once the operator manipulated the jacket water cooler service water outlet valve with no governing procedure, there were no administrative controls in place to have the valve position independently verified in accordance with the requirements of TMI action item I. The inspectors concluded that prccedures were inadequate in that no proce-dure . adequately controlled the manipulation of the DG jacket water cooler service water outlet valves during operation of the engine. This is a Violation: Inadequate Procedure to Control DG Jacket Water Cooler Service Water Outlet Valves (324/86-25-01).
 
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:  The; licensee had o'perated the DGs in the past with the cooler outlet valves
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partially. shut. LThe licensee decided to leave the valve normally full ope The license.has concluded that neither valve position would adversely affect diesel generator operability. .The inspector will re-examine this ' area to-verify the '. licensee's conclusions. This is an Unresolved Item: Diesel ,
r Generator Jacket _ Water Cooler Service Water Outlet Valve - Required Position
[  (325/86-24-02 and 324/86-25-02).
 
One' violation and one unresolved item were. identifie . IE. Bulletin Followup (92703)
  (CLOSED) IEB 78-09, BWR Drywell Leakage Paths Associated With Inadequate -
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Drywell Closures, 325/78-BU-09' and 324/78-BU-09. The inspector verified
[  that the licensee maintains and uses procedures ~that control the removal and installation of drywell closures. The licensee,- in MP-08, Shield Block an Reactor Drywell Head Installation and Removal, Rev'.16,. specifies the torquing sequence and verifies that no galling. has occurred by counting flats on head bolt >    .
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The inspector verified that the licansee had adequate procedures in place to rein ~ stall: other bolted. containment closures. The inspector reviewed the following procedures:
  -MP-08  Shield Block and Reactor- Drywell Head Installation and JRemoval,;Rev. 16 MI-16-562- Torus Hatch Cover (Removal and Instal.lation), Rev. ,
  .MI-16-563 CRD Hatch Cover (Removal and Installation), Rev. 3.
 
j-  MI-16-595 Installation of the nrywell Equipment Hatch Cover, Rev. MI-16-596 Installation of the Drywell Equipment / Personnel Hatch Cover,
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MI-16-601 Installation of Drywell Top Head Manway Cover, Rev. I
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  ' The inspector verified that MI-16-563 was used to're-install .the CR0 hatch
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cove The inspector reviewed PT-20.3.3, CRD . Hatch Local Leak Rate Test (LLRT) for~ Containment Isolation, Rev. O,- performed on Unit 2 on June 23, 1986, and on Unit 1 on November 16, 1985. The PT results~show that the CR0
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hatch had been adequately re-installe .~ Sequence of Events for Unit 1 Scram on September 13,,1986 (93702)
I  The inspectors reviewed the post-scram review packa'ge and other documents, i-interviewed plant personnel, and reviewed the diesel generator starting
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logic. with electrical system engineers. The inspectors provided a sequence
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of events to NRR,'IE, and RII to aid NRC review concerning.the event. The inspectors' Sequence of Events (SOE) was based on information provided by e
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    ~13 the licen3ee with selected information verified by the inspectors. The SOE that follows is substantially the same information verified correct by the licensee in a special meeting on September 17, 198 Unit 1 was at 100% power and had been operating for 19 continuous day Initial cycle 5 startup was on October 30,'1985. Refueling outage scheduled to start January 31, 1987. No.other evolutions in progress at the time of the scra Time  Event  Comment
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10:54 Shifted main generator Automatic voltage regulator
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voltage regulator (VR) had been erratic. Planned to manual  to clean auto control :55 Switchyard voltage begins Later found a bad motor-to swing (about 10 KV). operated manual potentiometer -
wear products matter found on wiper to potentiometer fac Operator attempts to transfer VR back to aut Prior to 10:58:57 V buses El and E2 All 6 degraded voltage (ESF Buses) trip on devices trip. 3727 V plus degraded voltage as or minus 9 V with a 10 plus designe Diesel or minus .5 sec. delay (se Generators (D/Gs) 1 and T.S. 3.3.3.5).
 
2 receive a start signa Main steam temperature Deenergization caused by sensor relays deenergize, loss of power source of El causing a group 1 and E2 (ESF Buses) trip isolation (Main Steam' relay Isolation Valve (MSIV)
closure).
 
10:58:57 MSIVs 90% open scra All 4 channel :58:57+ High Pressure Coolant 187" is normal operating Injection (HPCI) and level. MSIV closure caused Reactor Core Isolation level' shrink and pressure Cooling (RCIC) start rise. LL2 signal only when Low Level 2 (LL2) momentary. HPCI did not reached (118"). inject since LL2 was rese F006,HPCIinjectionvalve, was ready to open if neede RCIC was available but did notinjec ,
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Time  Event  Comment
[C55tinued)
10:59:06 Reactor Protection System The power sources of El and Motor Generator (RPS MG) E2 Buses lost power when the sets A and B tri '
undervoltage relays trippe (Refer to FSAR Figure 8.3.1-1.)
 
About 10:59:07 D/Gs 1 and 2 pick up El and E2 (ESF Buses powered from Unit 1).
 
10:59:12 Safety Relief Valves A, C - 1105 setpoint (SRVs) A, C, D, E, D, E - 1115 setpoint and L automatically L - 1125 setpoint open (of 11 SRVs) as Licensee estimates pressure indicated by tailpipe reached 1120 plus or minus 7 temperature Initial psig: thus valves that did 50.72' report indicates not lift are within plus or 8 of 11 tailpipe .
minu~s 1% of setpoin The A temperatures did not sonic detector had slow elevated and all sonic response time. The A sonic indicators memory lights module was' replaced and were li relief valves tested satisfactory. Only actually responded as tail pipe temperature showed indicated by tailpipe that L lifte L sonic temperature The found bad during startup 250 sonic indicator  psig test. (T.S. 3. indications were caused N/A.) License will repair by short-term loss of detecto power to the detector :59:33 Diesel Generators 3 and Start on Unit 1 main 4 star generator primary lockou :00 HPCI and RCIC tripped on As operator attempts to high level, 208 inches, inject HPCI in response to when HPCI F006 valve, vessel level decrease due injection valve, was to SRV lift opened by the operato :01 Operator started to open E0Ps require operator to SRVs A, E, J, B, F & D maintain pressure at S950 as necessar psig using SRVs. (To distribute heat load in torus.)
 
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Time  Event  Comment TCo5tinued)
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11:06 HPCI oscillations occur HPCI system was in automatic during manual restar and being placed in the Condensate Storage Tank (CST) recirculation mod Oscillations stopped when HPCI placed in manua Oscillations caused by inadequate procedural guidanc :06 HPCI tripped on high leve hen the injection valve was open, HPCI quickly fed the vessel, tripping on high leve :10 RPS "A" MG set o RPS "B" Output breaker of "B" MG on alternate power suppl stuck in tripped conditio This is not an Emergency Protective Assembly (EPA)
breaker. Breaker repaire :28 Intermediate Range Monitor IRM F in range 1. Licensee (IRM) F spike, gives half troubleshooting, found cable scra and connector problems on 9/15. Cleaned connections and performed Performance Tests. Started unit with IRM F in bypas :34 SRV Lifts terminate :37 RCIC injecting and HPCI in HPCI used for pressure CST recirculation mod contro :40 HPCI injected for about See 11:06 a.m. entr minute, oscillations occurred but HPCI did not tri :43 MSIVs reopene Re-established condenser as heat sin :48 HPCI and RCIC in standb : 51 One feed pump in service Licensee using feed system for level contro i
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Time  Event  Comment
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12:13 D/Gs 3 and 4 placed in standb :30 Average Power Range 2 Low Power Range Monitors Monitor (APRM) F (LPRMs) failed, noticed upscal A read 20 watts 12-21-A read 40 watts with power in source-rang After routine trouble-shooting, licensee installed pre-approved plant mod to re-assign 2 LPRMs from LPRM group A to_APRM Failure cause unknow APRM F left in bypass during unit restart until modification acceptance test complete Main' steam line rad Detector had been losing monitor B_ failed down- sensitivity but was still'
scal passing weekly surveillanc Replaced detecto :19 .72 phone call.to NR Resident Inspector informed by license :37 Re-energized El and E2 from El and E2 re-energization 1D and 1C, respectivel delayed while investigation Placed D/G 1 and 2 in was complete standb :58 South Residual Heat Sump pumps in RCIC area had Removal (RHR) room been in pull to lock due (RCIC area) high sump to clean up of service level alar (salt) water leak on 9/1 Licensee investigating source of lea :00+ RCIC suction pressure low Licensee looks for lea low alar High point vent shows system is ful RCIC CST suction valve RCIC suction relief valve shu stuck ope Corrosion prevented reseating of valv . _
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Time  Event  Comment
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6:00 RCIC declared inoperable SR0 concerns that RCIC when keepfill vent piping was partially showed system not drained due to relief valve completely fille leak. Valve later repaire :00 Backup Nitrogen (N2) Valve 1-RNA-PCV-5247 had low pressure alar damaged 0-ring and scratched valve seating surfaces.
 
9/15 4:30 Conference call between Region II and CP& /16 1:43 Reactor Critica HPCI tested satisfactory at 165 psig. Further testing to be done at 1000 psi Based on the SOE and additional inspections, several issues arose.
 
4 RCIC Pump Suction Relief Valve
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The RCIC pump suction Relief Valve (RV) was found stuck open due to corrosion buildup. The licensee identified six Unit 1 RVs and five Unit 2 RVs on ECCS systems which are manufactured by Lonegren and are
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in similar applications (ECCS pump suction lines). The valves are:
1-E11-F029,1-E11-F030A, B, C' & D,1-E41-F020, 2-E11-F029, 2-E21-F032A
  & B, 2-E41-F020 and 2-E51-F017. The licensee plans to remove these valves during subsequent scheduled system outages and perform functional testings of the valves using their normal ISI procedure. Based upon the test program, the licensee will evaluate if any further action is warranted. ' This is an Inspector Followup Item: Review of Lonegren RV Test Program (325/86-24-03 and 324/86-25-03). CFR 50.72 Report The inspector listened to a tape recording of the 50.72 report with the acting Operations Manager and the Director of Regulatory Complianc Based on the SOE and the _ tapes, the inspector concluded that the licensee met the reporting requirements of 50.72. However, several items that the licensee omitted were of interest to the NRC. Th licensee made the. red phone report at 1:19 p.m. The licensee failed to mention that:
HPCI flow oscillations had occurre HPCI and RCIC had tripped on high leve . _ . _ _  _ _ ___ - _
 
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Diesel Generators 3 and 4 had starte RPS MG Set B output breaker had stuck in the tripped conditio Problems with nuclear instrumentatio The inspector discussed the reporting requirements with the licensee, placing emphasis on what NRC actions are based on the licensee's report. The licensee acknowledged the inspector's comments. The licensee stated that the report was frank, honest and included those -
items that they felt were relevant to the event. The licensee will, however, evaluate the inspector's concerns with respect to reporta-bility.' The inspector has no further questions at this tim HPCI Oscillations HPCI flow oscillations occurred when the operator shifted the system to the CST recirculation mode. In that mode', the bypass to the CST
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  (E41-F008) is throttled while the injection path is opened, controlling reactor pressure. OP-19, HPCI Operating Procedure, Rev. 7 for Unit 1 and Rev.' 52 for Unit 2, address operation in the CST recirculation mode in Section 8.2. Valve operations are specified in Section 8.2; however, automatic controller operation and methods used to minimize oscillations are not covered in OP-19. Reactor pressure control by HPCI is required
.in the licensee's Emergency Operating Procedures. While the inspector concluded that OP-19 was sufficient to meet regulatory requirements, further procedure enhancements concerning HPCI pressure control operation may aid operators to prevent oscillations. The licensee has committed to include revisions to OP-19 in this area. This is an Inspector Followup Item: OP-19 Revisions for HPCI CST Recirc. Mode (325/86-24-04 and 324/86-25-04). HPCI F008 Torque Switch Settings The licensee found an error in the Unit 1 and Unit 2 valve torque switch settings. To verify that no hardware problem caused the HPCI oscillations, the licensee conducted special procedure 1-SP 86-080 on -
September 20, 1986. F008 and F011, the redundant isolation to the CST, failed to completely close during the test. The licensee tried to shut the valves while flow was returning to the CST. Further licensee investigation showed that:
  (1) The 1-F008 torque switch settings and spring pack were not matche There were two possible spring packs. For the installed spring
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pack, a torque switch setting of 3.5 was required. The licensee found a setting of 2.0 in the fiel (2) 2-F008 torque switch setting had to be increased from 2.25 to (3) 1-F011 torque switch setting had to be increased from 2.0 to _ .
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A higher torque switch setting for a given spring pack increases the torque value that will open the switch, increasing the thrust on the valve before the motor is de-energized. Both the F008 and F011 valves are normally closed and receive a check closed signal upon HPCI auto-initiation. Any previous, safety . concern regarding these valves is therefore smal The inspector questioned the licensee regarding continued operation of the units with possible torque switch setting problems. The licensee stated that there was no immediate concern regarding motor-operated valves because:
  (1) They had no other indication that the problem went beyond the F008 and F01 (2) Most torque switches were bypassed in- the open directio In most cases, the open direction is the safety-related function directio (3) The test schedule and scope for HPCI and RCIC will be resolved as part of IEB 85-0 (4) Certain safety system valves are already in their safety function positio The inspector reviewed the licensee's actions and decisions in this area. While the inspectors have no further comment now, further NRC inspections -in this area will be~ conducted as part of IEB 85-03 follow-up, LPRM Problems Inspectors will continue to followup on long term resolution of detector failure No violations or deviations were identifie . TMI Action Plan Items The inspectors reviewed the licensee's current status of TMI Action Plan Items in order to plan future inspection activitie The following items are still open:
I.C.1. I.C.1. Inadequate Core Cooling / Revise Procedures (Units 1 and 2).
 
The licensee has completed implementation of the upgraded Emergency Operating Procedures (EOP) required by NUREG-0737, Supplement 1, Requirements for Emergency Response Capability (Generic Letter 82-33) through revision 3 of the E0P Revision 4 of the owner's group guidelines have been submitted
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to NRC. Upon approval, the licensee will upgrade the E0Ps to conform to the new guidelines. This item will be inspected after incorporation of the revised guideline I.D. I.D. Install and Implemot the Safety Parameter Display System (SPDS) (Units 1 and 2).
 
This item is c- the lising schedul Unit 1 and Unit 2 completion date - are July 28, 1989 and December 23, 1988, respectivel II.E.4. Dedicated Hydrogen Penetration The licensee installed modifications 80-133 and 80-134 on Unit 1 and Unit 2. The' modifications were declared operable on October 16, 1985, and May 30, 1986 on Units 1 and 2, respectively. Licensee paperwork closeout of this item is in progress. Awaiting inspectio II.E.4. Containment Isolation Dependability - Radiation Signal on Purge Valves (Units 1 and 2).
 
The licensee submitted the design to NRR on August 26, 198 Pending approval, the licensee plans to install the modifi-cations during Refuel 5 for Unit 1 (February to July 1987)
and Refuel 7 for Unit 2 (January to May 1988).
 
II.F.2. Install Level Instruments for Detection of Inadequate Core Cooling (Units 1 and 2).
 
In a letter to NRR dated December 19, 1985, the licensee committed to install two uncompensated condensing chambers in the drywell and route the reference legs outside containmen The licensee plans to start the modifications, 1-86-007 and 2-86-008, during Refuel 6 for Unit 1 (December 1988 to May 1989) and Refuel 7 for Unit II.K.3.16.8 Challenges and Failures of Relief Valves - Modify (Units l'
and 2).
 
The licensee has changed the Safety Relief Valves (SRV) i both units from the three stage Target Rock to the two stage Target Rack. On March 12, 1984, NRR sent to the licensee a generic safety evaluation performed by the BWR Owners Grou This evaluation endorsed three specific modifications along with establishment of an effective Preventive Maintenance (PM) program. The licensee was requested to respond to the evaluatio e-e* .
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In a. letter to the licensae dated November 14, 1984,.NRR concluded that the actions taken or committed to be taken would achieve the objectives of NUREG-0737, Item II.K.3.1 The inspector reviewed the actions. First, an ongoing preventive maintenance program using input from the BWR Owners Group, General Electric, and Target Rcck has been established. All SRVs are being removed and tested during that units refueling outage. The status of the three specific modifications was as follows:
1) E0P-01 has incorporated the manual equivalent of the low-low' set relief concept to achieve the goal of an order magnitude reduction in probability of a stuck open relief valve even This feature lowers the reseat pressure of the SRV. A selected SRV is manually held open by an operator beyond the reclosure setpoint. This results in a longer blowdown, lowered reseat pressure, and reduces subsequent.actuations of SRV ) The SRV simmer margin was increase The simmer margin is the difference between the SRV set pressure and the reactor -operating pressure. This modification will minimize leakage and reduce the potential for ' spurious openin ) The modification to change the main steam isolation-valve closure on low reactor water level from Level 2 to Level 3 was not done. The licensee response. to NRR stated that this modification was being reviewed as part of the ongoing Torus Integrity Program. The inspector requested that the licensee provide the inspector with documentation of the revie II.K.3.18.C Modify Automatic Depressurization System (ADS) Logic (Units 1 and 2).
 
Awaiting NRC inspectio II.K.3.28 Qualification of ADS Accumulators (Units 1 and 2).
 
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The Nitrogen Backup System has been installed on both unit However,. Generic Letter 84-09, Recombiner Capability Require-ments of'10 CFR 50.44(c)(3)(ii), also addresses issues which affect the design of the Nitrogen Backup System. This item will be inspected after NRR approval of the design and any subsequent modification II.K.3.57 Manual Actuation of ADS (Units 1 and 2).
 
Will be resolved as part of the I.C.1 (see above) E0P revie _ -- -. .- -. .
 
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II NUREG-0737 Supplement 1, Final Emergency Response Facility Approva Awaiting Safety Parameter Display System (SPDS) installation completio III.A.1. Modify Emergency Support Facilities (Units 1 and 2).
 
Modifications complete with the exception of the SPD See Item I.D.2. III.A. Installation of Emergency Preparedness Hardware and Software (Units 1 and 2).
 
Awaiting SPDS completion.. See Item I.D.2.2.3.
 
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III.A. Emergency Preparedness - Full Capability for Facilities (Units 1 and 2).
 
Regional inspections have been performed in this are Awaiting.SPDS completio See Item I.D.2. III.D. Control Rocm Habitability Modifications (Units 1 and 2).
 
Awaiting.NRR Safety Evaluation Repor The following TMI Action Items are closed:
II.F.1.2. Implementation of Long-Term Iodine / Particulate Sampling (Units 1 and 2).
 
The licensee has implemented calibration procedures to comply with the current 18 month calibration frequency of TS Table 4.3.5.9. The applicable procedures are Periodic Test PT-71.0, General Atomic Stack Radiation Monitor Channel-Calibration, and PT-73.2, Gene ~ral Atomic Turbine Building Radiation Monitor Channel Calibration. These procedures have been performed during.the last 18 month interva II.F. Containment Pressure Accident Monitoring (Units 1 and 2).
 
Instrument CAC-PI-4176 was declared operational on December 21, 1981 for Unit 1 and 2. The instrument range is -5 to +245 psig. A Safety Evaluation Report (SER) was completed on this item on July 30, 1984, and ~found no outstanding items. PT-56-6PC, Post . Accident Containment Pressure Loop Calibrations, was implemented on April 6, 198 _  _ ._. - .
 
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II.F. Containment Water Level Accident Monitoring (Units 1 and 2).
 
Instrument CAC-LI-2601-1 was declared operational on July 23,-
1983 for Unit 1 and PM-80-078 for Unit 2 on December 21, 198 An SER performed on this item on July 30, 1984, determined this item acceptable with no outstanding item PT-56.2, Suppression Chamber Level Loop Calibration, implements the requirements of technical specification 4.3.5.3-1(3).
 
II.F. Containment Hydrogen Accident Monitoring (Units 1 and 2).
 
The range of the instruments was 30% for hydrogen and 25%
for oxygen concentration. An SER performed on July 30, 1984, concluded there were no outstanding items. Plant Modifica-tion 80-032 placed in operation these instruments on July 22, 1983, for Unit 1 and for Unit 2 .on -October 1, 198 PT-55.4PC-1A, Drywell Hydrogen and Oxygen Analyzer Channel Calibration, implements the technical specification require-ment No violations or deviations were identifie . Site Work Force Control Group (SWFCG) Meetings (62703)
The licensee uses the SWFCG to coordinate various maintenance activities -
corrective, preventive, and surveillance - within system outage windows during plant operation. The SWFCG consists of all site organizations involved in the work control process: operations, maintenance, technical support, fire protection, construction, and ALARA group. The unit- super-visors from these groups submit work activities one week in advance so that all work on a specific system can be accomplished during the same TS LC0 outag The licensee plans to reduce repeated clearances and LCOs with this planning proces The work items have been pre-approved using this proces Work for the following day is submitted to the unit operations engineer who delivers the' work packages to the appropriate operations shift foreman. The package is reviewed and approved. The maintenance individual picks up the approved package the following morning at the control ~ room and starts wor The inspector attended four Unit 2 SWFCG meetings during the week of September 7,198 The licensee gave appropriate attention to safety-related maintenance activities during the meeting No violations or deviations were identifie . Internal Exposure Control and Assessment (83525)
The inspector attended the licensee's respiratory protection class on :
September 12, 1986, at 9:00 a.m. The class saw a videotape, received l standard classroom instruction, and took a short quiz. The inspector '
questioned whether the licensee met a requirement to advise respirator users when they can leave an are CFR 20.103(c)(3) states- !
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The. licensee shall advise each respirator user that the user may leave the _ area at any time for relief 'from respirator use in the event of equipment malfunction, physical or psychological distress, procedural or communication faOure, significant deterioration of operating
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conditions, or any other condition that might require such relie The training film, viewed by the inspector, states:
In fact, at the first sign that you feel nauseous, dizzy, fatigued, or you suspect that jour respirator is not operating properly, leave the area. Remember it is always best to leave the area with your respirator on, but, if you suddenly have difficulty breathing while wearing a respirator, remove it then immediately leave the are The instructor's training guide, E&RC-0220, Respiratory Protection Program, Appendix K, BSEP Respiratory Protection Training, states:
Explain that workers can leave the area anytime breathing resistance is felt, it malfunctions, if. he finds himself becoming nauseous or sick, or if he experiences physical and/or mental discomfor However, the instructor did not discuss the above item in clas Even if the E&RC-0220 statement was read in class, not all the elements contained in 10 CFR 20.103(c)(3) would have been explicitly addresse The licensee issued Operating Experience Report (0ER) 2-86-34 to address the inspector's concern The licensee has placed additional emphasis in the E&RC-0220, Appendix K lesson plan on 10 CFR 20.103(c)(3). A statement of the regulations was added to the back of the quiz sheet for each potential respirator user to read and sign. Also, revisions to the booth fit procedure, E&RC-223, require the instructor to discuss the requirements of the regulation more fully with the use The E&RC manager has issued a memo for all supervisors to discuss the regulation with their employee Based on review of the licensee's actions and interviews with plant personnel, the inspector concluded that licensee respirator users are adequately advised under what conditions they may leave an area for relie No violations or deviations were identifie . Plant Modifications (37700)
The inspector rriewed plant modifications to verify that the changes were made in accordance with TS,10 CFR 50.59, and ENP-03, Plant Modification Procedure, Rev. 32. The inspector verified that: modifications were controlled with approved procedures, drawing change requests were submitted, maintenance procedures were identified for change and, when required, design changes were included in the annual 10 CFR 50.59 report. Post-modification
 
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  . test records -were reviewed to verify that the scope of the testing was appropriate and that test results met previously established acceptance criteria. The inspector reviewed the following plant modifications:
82-079 Unit 1 Standby Liquid Control Heat Trace Operability Monitorin Unit 1 480 V E21-F015A and B Circuit Breaker Changeou Unit 2 Drywell Head Stud Upgrad No violations or deviations were identifie . Review of Maintenance Experience Report Associated with August 23, 1986 Unit 2 Scram The subject scram is described in inspection report No. 324/86-22. Personnel actions involved with the event were investigated and reported in Maintenance Experience Report (MER) 86-023. The report concludes that the technician involved did not perform step F.1 of procedure MI-03-1BX14 before returning the B21-PT-N023B transmitter to service. The step requires adjustment of the pressure source to that of the reactor prior to valving in the-instrumen The' technician omitted the step, thereby causing an instrument reference leg pressure spike and, hence, the scran. The involved individual was counsele The inspector reviewed MERs and LERs issued during 1985 and 1986 to determine if a similar event involving I&C personnel had occurred in the recent pas None was foun Because the inspector believes that this is an isolated event, it is not indicative of a programmatic weakness, no Notice of Violation will be issue No violations or deviations were identified.
 
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Revision as of 17:37, 21 January 2021

Ack Receipt of 861126 Ltr Informing NRC of Steps Taken to Correct Violations Noted in Insp Repts 50-325/86-24 & 50-324/86-25
ML20212B473
Person / Time
Site: Brunswick  Duke Energy icon.png
Issue date: 12/22/1986
From: Verrelli D
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To: Utley E
CAROLINA POWER & LIGHT CO.
References
NUDOCS 8612290258
Download: ML20212B473 (1)
v • d • e


Text

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/arolina C Power and Light Company ATTN: Mr. E. E. Utley Senior Executive Vice President Power Supply and Engineering and Construction P. O. Box 1551 Raleigh, NC 27602 Gentlemen:

SUBJECT: REPORT N05. 50-325/86-24 AND 50-324/86-25 Thank you for your response of November 26, 1986, to our notice of Violation, issued on October- 31, 1986, concerning activities conducted at your Brunswick facilit 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 inspection We appreciate your cooperation in this matte

Sincerely, ORIGtNAL SMEU "Y DAVID M. VERRELLI David M. Verrelli, Chief Reactor Projects Branch 2 cc: . W. Howe, Vice President Brunswick Nuclear Project

/.R.Dietz,PlantGeneralManager bcc:VNRC Resident Inspector Document Control Desk State of South Carolina 8612290258 861222 DR ADOCK0500g4

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g Pfredrickson DVerrelli 12/15/86 12/(f/86 12/5/86

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