IR 05000324/1998006
| ML20236N955 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 07/06/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20236N933 | List: |
| References | |
| 50-324-98-06, 50-324-98-6, 50-325-98-06, 50-325-98-6, NUDOCS 9807160076 | |
| Download: ML20236N955 (58) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-325. 50-324 License Nos: DPR-71. DPR-62 Report No: 50-325/98-06, 50-324/98-06 Licensee: Carolina Power & Light (CP&L)
Facility: Brunswick Steam Electric Plant. Units 1 & 2 Location: 8470 River Road SE Southport. NC 28461 Dates: April 26 - June 6.1998 l
1 Inspectors: C. Patterson, Senior Resident Inspector l E. Brown. Resident Inspector E. Guthrie. Resident Inspector J. Coley Reactor Inspector (Sections M2.1-M2.2 M8.3)
J. Lenahan. Reactor Inspector (Sections E1.1-E E2.1-E2.2. E8.5-E8.7)
N. Merriweather. Reactor Inspector (Sections E1.1-E1.3. E2.1-E2.2. E8.5-E8 7)
E. Testa. Health Physics Inspector (Sections R ,
R1.2) l D. Thompson. Safeguards Inspector (Section S1.2) l Approved by: M. Ernstes. Acting Chief. Projects Branch 4 I Division of Reactor Projects l Enclosure 2
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9007160076 9so706 PDR G ADOCK 05000324 PDR l
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EXECUTIVE SUMMARY Brunswick Steam Electric Plant. Units 1 & 2 NRC Inspection Report 50-325/98-06, 50-324/98-06 This integrated inspection included aspects of licensee operation maintenance, engineering, and plant support. The report covers a 6-week period of resident inspection: in addition. it includes the results of a maintenance, engineering, health physics. and safeguards inspections by regional inspectors.
- Doerations l . 0]erator briefings, plant control, and response during the Unit 1 slutdown for the refueling outage were effective (Section 01.1).
. The core alterations conducted during the Unit 1 Refueling Outage were generally conducted according to procedure. had adequate communications, and were effectively controlled. However, the inspector noted that one fuel movement occurred without the required communications: this deficiency was promptly corrected by a licensed operator in the Control Room (Section 01.2).
. Drywell housekeeping was effective in maintaining areas free of foreign material. Electrical and mechanical components were secured to support plant restart (Section 02.1).
. The torus was very clean, with only minor foreign material present: this material was removed during the licensee's closeout inspection. No deficiencies were identified during the torus suction strainer modification installations (Section 02.2).
. The loss of the Supplemental Spent Fuel Cooling System on May 7.1998, resulted in a 9.5 degree Fahrenheit increase in fuel pool temperatur Eight to nine trips of the system occurred within a 3-week period (Section 02.5).
. The restart affirmation conducted by the Plant Nuclear Safety Committee was a satisfactory evaluation of the overall site organization's readiness to restart Unit 1 (Section 07.1).
. A Non-Cited Violation was identified for missed operator rounds (Section 08.1).
Maintenance
. The technicians performing the High Pressure Coolant Injection Valve Local Leak Rate Testing were knowledgeable of the test parameter criteria, and equipment used (Section M1.1).
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. Inservice Inspection (ISI) activities were conducted in an excellent manner by examiners and analysts who were very knowledgeable and skillful in their use of the examination methods. Enhanced inspection techniques were very effective in thoroughly examining and evaluating the quality of welds (Section M2.1).
. The torus, ring header, and vent lines were well-maintaine The completed weld repairs observed and the applicable documentation were found to be in accordance with procedures and specifications (Section M2.2).
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For the most part. Foreign Material Exclusion controls were implemented satisfactoril However, a lack of control of material in the fuel pool led to a thermocouple wire being inadvertently placed on top of the reactor vessel core. Also, spent fuel pool inventory and control was considered a weakness (Section M2.3).
. ;outdown margin testing was completed satisfactorily and in accordance '
with the Technical Specifications (Section M3.1).
. The cross-connection of multiple phases of a breaker compartment l resulted in a brief " fireball". No adjacent personnel or equipment were I damaged and reactor make-up and control was maintained at all times. An Unresolved Item was identified for further review of this item and other related maintenance and test configuration issues (Section M4.1).
. The effectiveness of licensee controls over their ISI vendor and in identifying, resolving and preventing problems was excellent. This was demonstrated by integrity of the vendor oversight: the conduct of a thorough assessment (B-0M-98-01) to determine the effectiveness of preoutage preparations in support of the outage: and the effective investigation documented in Condition Report 98-0424 of discrepancies in .
inspection coverage and defect length sizing on Unit 1 ' 2 core shroud I welds (Section M7.1).
Engineering l
. After resolution of the inspectors' review comments, the Qualification Data Packages reviewed met the requirements of 10 CFR 50.4 The effect i of beta radiation on Environmental Qualification (EO) cable splices was evaluated in accordance with the requirements of 10 CFR 50.49 (Section -
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l . The licensee had adequately modified electrical terminal boxes l l containing E0 equipment to prevent the accumulation of moisture and had
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addressed the effects of moisture on E0 components in accordance with I the requirements of 10 CFR 50.49 (Section E1.2). !
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The licensee was making adequate progress in resolving and closing CRs identified by the E0 group. However. engineering failed to recognize that a repair should be made to the Okonite T95 taped splices on the drain wires for two Containment Atmosphere Resistance Temperature Detectors to prevent multiple grounds in the circuit. This was considered a weakness (Section E1.3).
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Inspection testing, and repair of Service Water (SW) piping com)onents were completed satisfactorily. Licensee inspection determined tlat the material condition of these components was satisfactory (Section E1.4).
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The licensee's actions to repair the pinhole leaks in the Unit 1 Standby Liquid Control (SLC) flexible piping were performed in accordance with good engineering practices and NRC requirements (Section E2.1).
. The licensee's operability evaluation of bolted connections for reactor pressure vessel pipe supports was completed in accordance with the guidance specified in Generic Letter 91-18 (Section E2.2).
. The inspector concluded that the same excellent planning and decision- l making which was implemented during the Unit 2 Emergency Core Cooling System (ECCS) strainer modifications led to the successful completion of the Unit 1 ECCS strainer modification (Section E2.3).
. A change to the Diesel Generator load test was made, which altered the test loading profile. The use of a temporary change to alter the intent of the test load procedure was identified by the inspector as a violation (Section E4.1).
Plant Sunoort
. Radwaste material was labeled in accordance with requirements and appropriately stored. Radiation and High Radiation Areas were properly posted and controlled. Personnel dosimetry devices were worn properly by workers. Contamination control was effective in containing high levels of contamination in appropriate areas (Section R1.1).
. The inspector identified one violation for a failure to perform nine radiation surveys (Section R1.1).
. The licensee met regulatory requirements for limiting radiation dose to individual members of the public as promulgated in 10 CFR 20.1301.1302 and maintained sufficient information in records required by 10 CFR 20.2107 (Section R1.2).
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. The licensee failed to take prompt action when a continuous air monitor I and an additional sample indicated abnormal airborne activity. As a result, five workers were present in an area of airborne radioactivity levels greater than 0.25 DAC (Derived Air Concentration), without !
appropriate radiation work permits. A violation was issued for the failure to properly im)lement and establish procedures that outlined those actions to be ta(en in the event of survey results indicating abnormal airborne activity (Section R1.3).
. The Health Physics staff response to a Scram Discharge Volume header leak of several gallons was prompt and effective (Section R1.4).
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The licensee continued to revise their severe weather procedures to keep current. The inspector noted that severe weather 3 reparations were
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being implemented during the inspection period suc1 as ordering sand bags and staging temporary storm drain pumps (Section Pl.1).
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Staffing for alternative safe shutdown procedures was not implemented in l accordance with procedures. The failure to maintain adequate Alternate Safe Shutdown (ASSD) staffing was identified as a violation. A violation was also identified for the failure to retain documents i requested during this inspection (Section F1.1). l
. The procedures for maintaining minimum staffing for ASSD during a fire l were determined to be inconsistent with 10 CFR 50 Appendix R. 10 CFR 50 Appendix R requires that all personnel needed for ASSD be onsite at all times. However, the procedures for ASSD staffing allowed less than minimum staffing for 14 days. A violation was issued for the failure to properly establish fire protection procedures in accordance with 10 CFR 50 (Section F3.1).
. The inspector determined through Access Authorization procedures and records review that the licensee had established adequate procedures as required by 10 CFR 73.56 for the review of a denial or revocation by the licensee of unescorted access authorization, at the request of an affected employee (Section S1.2).
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Report Details Summary of Plant Status Unit 1 was shut down on April 25, 1998, to begin a scheduled 35 day refueling outag The unit was taken critical on May 23, 1998. Power was increased to 20 percent until problems with the number three bypass valve developed. The unit was shut down on May 26, 1998. Repairs to the bypass valve were completed and the reactor was taken critical on May 26, 1998. The unit was connected to the grid on May 28, 1998, ending the refueling outage in 33 day Unit 2 operated continuously during this report period. At the end of the report period the unit had been on-line continuously for 227 days. Unit 2 developed indication of leaking fuel on March 14, 1998. Two control rods were inserted to suppress power around the leaking fuel assembly. On May 29, 1998, a condenser circulating water leak developed on the debris filter at the inlet to the condense A conservative decision was made to shut down the unit to preserve the condenser as a heat sink for plant cooldown. At 30 percent power, a temporary repair was made to stop the leak. The unit was returned to j full power on May 30. 199 j
I. Ooerations 01 Conduct of Operations 01.1 Observation of Unit 1 Shutdown Inspection Scone (71707)
The inspector observed a portion of the Unit 1 plant shutdown on April 25, 1998. This shutdown was conducted for the purpose of a refueling i I
outag l Observations and Findinas The inspector observed the Unit 1 shutdown from about 62 percent reactor power until after the reactor was scrammed. The inspector observed evolutions such as securing a Reactor Feed Pump Turbine. separation from the electrical grid, control rod movement, and the scramming of the reactor. The inspector observed clear, thorough briefings for the a3propriate evolutions. Good operator response and control was evident t1roughout the observed portion of the Unit 1 shutdown. No deficiencies were noted by the inspecto Conclusions 0]erator briefings, plant control, and response during the Unit 1 '
slutdown for the refueling outage were effective.
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2 01.2 Observations of Core Alterations Insoection Scooe (71707)
The inspector observed Unit 1 core alterations, which occurred during the refueling outage, on several occasions in the Unit 1 Control Room and from the Unit 1 refueling floor. The inspector observed the-evolution-for procedural compliance, communications. and effective control-of the evolutio Observations and Findinas The inspector attended one of the refueling briefings given to those
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personnel' who would be involved in refueling evolutions on April 2 '
1998, and found the briefing to be thorough.with active participation-from attendee The ins)ector- found that, generally the core alterations during the Unit 1 Refueling Outage were conducted according to procedure, had adequate communication, and were effectively controlled. However, during the. core offload evolution on April 30. 1998, the Refuel Floor Senior Reactor Operator (SRO). who was in charge of refueling !
activities, performed a. fuel movement without performing the required i communications per the Refueling procedure FH-11. The procedure recuired that a verification be performed between the Refuel Floor SR0 anc the . licensed operator in the Control Room. verifying the step number revision. and issue number of the Core Component Sequence Shee as'well as the component and coordinate before latching to the com)onent. After the completion of each step it was also required that eac1 step be verified completely between the Refuel Floor and the Control Room. The Control Room identified that the Refuel Floor SRO had not performed these communications when too much time seemed to have passed since the last movement and a normal expected alarm associated with refuel bridge movement occurred. .This alarm indicated to the control room staff that fuel movement occurred without the proper. communications.
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The Control. Room immediately asked the Refuel Floor SR0 what fue activity was being performed. At that moment, the Refuel Floor SRO L realized that the communications were missed. The inspector noted that L . the Control Room operator promptly verified the required information
'with the Refuel Floor SRO. No other errors associated with.this movement were noted by the inspecto Conclusions-The core alterations conducted during the Unit 1 Refueling Outage were generally conducted according to procedure. had adequate communication .and were effectively controlled. However, the inspector noted that one
' fuel movement occurred without.the required communications: this deficiency was promptly corrected by a licensed operator in the Control Room.
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02 Operations Status of Facilities and Equipment 02.1 Drywell Closecut Inspection Scone (71707)
On May 20, 1998, an inspection of the Unit 1 drywell was performed in preparation for closeout of the drywel Observations and Findinas The inspector toured all elevations of the drywell to verify that the material condition of the drywell supported plant startup. Each downcomer connecting the torus and drywell was inspected. Each downcomer was found clean, with the exception of one plastic tiewrap about one foot long. The tiewrap was removed from the drywel .
J Several safety relief valves were inspected to verify that bolts were lock wired, detector cables were in good condition, and all fastener s were connected. Electrical junction boxes were checked to verify that covers were in place and fastened. General area housekeeping was good and the drywell was found free of foreign materia ; Conclusions Drywell housekeeping was effective in maintaining areas free of foreign material. Electrical and mechanical components were secured to support plant restar .2 Torus Closeout Insoection ; Insoection Scooe (71707)
On May 9, 1998, the inspector examined the Unit 1 torus in preparation for torus closecu Observations and Findinas i The inspector toured the Unit 1 torus while it was dry. The torus had been drained for modification work to install new suction strainers on the core spray (CS) and residual heat removal (RHR) systems. Each strainer modification was inspected with emphasis on support clearances, fastener attachments, and general support welding and coating conditio No deficiencies were foun The inspector checked the torus for foreign material and found three l small items including a small ball of tape, a piece of wire, and a piece of string. The overall condition of the torus was clean and dry. The licensee manager accompanying the inspector expressed that the torus would be inspected again since some material was found.
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The inspector observed the inside of several torus-to-drywell vacuum 1 breaker valves for foreign material and found non Conclusions
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The torus was very clean, with only minor foreign material present; this material was removed during the licensee's closeout inspection. No deficiencies were identified during the torus suction strainer modification installation .3 Containment Atmospheric Control (CAC) Taaout Insoection Scooe (71707)
The inspector reviewed a tagout on the Unit 2 Gaseous Analyzer 2-CAC-AT-1260 on May 27. 1998. The inspector observed the removal of the tagout from the equipment-on the same da Observations and Findinas The inspector reviewed and observed a tagout on the gaseous analyzer for adecuacy of isolation and for procedural compliance. The tagout was usec to change the oil in the analyzer's vacuum pum The inspector found the tagout isolation boundaries to be satisfactor The special instructions for the tagout were found to be accurate. In addition, operations personnel involved with the removal of the clearance were knowledgeable and professional. A satisfactory briefing was conducted prior to tag removal and was given by a Control Room Operato The brieting was thorough in that it covered the correct sequence for tag removal, actions for system restoration, and contingencies if problems occurred. A review of the paperwork by the inspector, following removal of the tagout. showed no deficiencie Conclusions The tagout used on the Unit 2 Containment Atmospheric Control Gaseous Analyzer was implemented satisfactorily. Those portions of the tagout process observed by the inspector were performed satisfactoril .4 Standby Gas Treatment (SBGT) System Walkdown Insoection Scooe (71707)
The inspector conducted a walkdown of the accessible portions of the Unit 2 2A and 28 SBGT systems on May 12. and May 18. 199 b. Observations and Findinas i The inspector found that the SBGT system lineups were correct on the control boards in the control room and a spot check of valve status in the Reactor Building (RB) found no valves out of position. Generall I i
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l the material condition of both trains was good: however, the inspector i noted oil drops from several motor-operated valves (MOV) in both l
systems. The drops of oil were noted on the electrical power cable couplings that were fixed to the MOV electrical contactor assembly housings. It aapeared to the inspector that the oil was coming from inside the MOV lousing and leaking out of the conduit coupling. The inspector brought the leaks to the licensee's attention and questioned
' whether these conditions were of concern for Environmental Qualification (EQ) or MOV operabilit Plant staff observed each oil leak and inspected one of the electrical conduits by removing an access cove The licensee determined that the oil was primarily coming from leaking gaskets and seals located on the MOV Following inspections and engineering reviews by both E0 and MOV engineers, they determined that no operability concerns existed, nor were there EQ concerns due to the leaks. The licensee's ba 6 for this determination was the lack of a driving head to displace encugh grease and oil from the greased portions of the MOV to affect the contactor assembly located in the MOV housing. According to the licensee MOV operability concerns and E0 concerns would be valid only if the contactor assembly was affected by the grease or oi The inspector was informed that a few of the valves that were leaking oil were within their preventive maintenance time period. One of the valves that had oil on an electrical line had preventive maintenance recently performed on it. Licensee staff believed that this oil had not been wiped off of the area after maintenance, but they stated that they would monitor the valve for further leakage. The inspector found the overall material condition and housekeeping for both systems to be satisfactor Conclusions The inspector found that the SBGT systems were able to perform their intended safety function, though there was some discussion with the licensee regarding small oil leaks on several MOVs. The SBGT systems were found to be in a correct standby lineup. and material condition and housekeeping were found to be satisfactor .5 Multiole Trios of Suoolemental Soent Fuel Pool Coolina Insoection Scooe (71707. 37551)
The inspector reviewed the circumstances surrounding multiple trips of the Supplemental Spent Fuel Pool Cooling (SSFPC) System during the Unit 1 Refueling Outage from April 24 through May 28. 1998. In particular, the inspector reviewed the May 7-8. 1998, multiple trips which resulted in a 9.5 degree Fahrenheit ( F) increase in fuel pool temperature.
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b. Observations and Findinas The SSFPC was designed by the licensee to assist in fuel pool cooling during a full core offload. This supplementary system was necessary due
- to the inability of the permanently installed Fuel Pool Cooling (FPC)
System to handle the decay heat in the fuel pool with 100 percent of the l core offloaded immediately after shutdown. The SSFPC system was physically se)arate from the FPC System and consisted of two loo)s. The
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primary loop lad two centrifugal pumps arranged in )arallel whic1 circulated the fuel pool water from the pool throug1 the tube side of the heat exchanger and back to the 200 The secondary loop contained l two centrifugal pumps in parallel w1ich recirculated the shell side heat
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exchanger water through two cooling towers located external to the RB.
l The system was powered by a temporary power feed from the offsite Southport feeder. The Southport feeder was not a part of the plant '
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offsite power distribution syste During a routine review of operating logs, the ins)ector'found that on 1 l May 7, 1998. Unit 1 was completely defueled with t1e SSFPC system as the _{
l primary means of fuel pool cooling. The FPC system was the back-up !
l means of fuel pool cooling. At 6:00 pm, the fuel pool temperature was l
indicated as 100 F. which is normal. At 9:15 pm, the "A" secondary SSFPC pump was found tripped. During attempts to restart the "A" secondary pump, the "B" secondary pump trip)ed. Fuel pool temperature
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was logged as 105.1 F and rising slowly. T1e "A" secondary pump was restored at 11:11 pm and the "B" secondary pump at 11:30 pm. At 11:50 pm, the SSFPC system tripped again due to perturbations on the Southport l feeder resulting from severe weather. The logged fuel pool temperature was 107 F. The system was restarted at 1:02 am on May 8, 1998. The system triaped again at 2:45 am. The "B" secondary pump was started at 3:30 am, w1ile troubleshooting continued on the "A" secondary pump. The inspector noted that approximately a 9.5 F increase in fuel pool temperature was observed during two of the May 7 trips. -Condition Report (CR) 98-1130 Trips of SSFPC, documented the May 7-8 trips plus five other identified trips since the beginning of the outage on April 25, 199 Unit 1 1998 Refuelino Outaae SSFPC Trios Date Cause April 25 Plant Breaker Trip April 26 Loose Tri) Panel Connector April 27 Operator Error April 30 Southport Feeder Perturbation May 2 (twice) Flow Oscillations from air in the flow indicator May 7-8 (at least three times) Southport Feeder Perturbations
/ Auxiliary contact problems
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The ins)ector reviewed the following items: operating and outage logs; i applica)le CRs: ESR 93-630,- Supplemental Spent Fuel Pool Cooling System:
and ESR 97-728. Evaluation of Spent Fuel Pool Cooling for 8112R1 Outag In addition, the inspector reviewed the Maintenance Rule re) ort for the SSFPC System. The Maintenance Rule report indicated that t1e SSFPC had l.
E been ) laced into a(1) status as a result of multiple. failures during the
'1996 Jnit 2 outage. These failures were described in Inspection Report (IR) 50-325(324)/96-04 and' included freezing of the instrument sensing lines and various errors in assembly and operation. The SSFPC System was removed from a(1) status after satisfactory performance during the 1996 Unit 1 Outag .{
ESR 93-630 stated that tte system had sufficient redundancy and was powered from a " reliable" source. As a result of the noted history of ,
this system and. inspector questions concerning the ability of the system '
l to perform.its intended function as a result of the unreliable system
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. performance and corrective actions for the trias, these concerns.were
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identified as an Inspection Follow-Up Item. T1is Ins ection Follow-Up-Item is identified as IFl 50-325(324)/98-06-bi. Multi le Failures of SSFP ! .The inspector noted that the.SSFPC System tripped again on May 19, 199 The trip was attributed to inadequate air-supply 3ressure for the return 1
' valves. This. trip was recorded in CR 98-1327. SS PC Secondary Side Trip. The CR also. included a recommendation to change the Maintenance i Rule status of the system to a(1). Additionally, issues regarding the '
reliability of this system were discussed in the May 21, 1998 Unit 1 ,
I- startu PNSC meeting.. The analysis presented stated that the decay heat j
~remova function was adequately maintained, despite 8 to 9 trips in the course of three weeks.
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' Conclusion The loss of the Su)plemental Spent Fuel Cooling System on May 7, 1998 resulted in a 9.5 : increase in fuel pool temperatur Eight to nine trips of the system occurred within a 3-week perio Operations Organization and Administration
.07.1 Startuo Plant Nuclear Safety Review Meetina
. Insoection Scooe (41500) l The inspector observed startup assessment activities for the Unit I refueling outage which began on April 25, 199 . Observations and Findinos On May 21, 1998, the inspector observed the Startup Plant Nuclear Safety Committee-(PNSC) review meeting for Unit 1. The rea h ss of each organization to support restart activities was discussed oy +he PNSC and affirmed by the appropriate supervisor. Areas addressed during the
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meeting were completion of regulatory compliance items, and outstanding engineering service requests. Any activities not ready for restart were flagged as exceptions and a duration for resolution was discussed. The meeting generated five exception items for completion. The meeting also addressed other outage-related issues such as the results of the E0 repairs and closure of the associated justification for continued operations (JCOs) for Unit 1. The local leak rate test results were reviewed as was the reliability of the S$FPC after multiple trips during this outage. The inspector determined that the meeting was adequate to assess restart readines Conclusions i The restart affirmation conducted by the PNSC was a satisfactory i
evaluation of the overall site organization's readiness to restart Unit Miscellaneous Operational Issues (92901)
08.1 Operator Rounds The NRC completed its review of an event concerning missed operator rounds. A violation of NRC requirements was identified. Specificall CFR 50.9 (a) states that information provided to the Commission by an applicant for a license or by a licensee or information required by statute or by the Commission's regulation orders, or license conditions to be maintained by the applicant or the licensee shall be complete and accurate in all material respects. In addition. TS 6.8.1 requires, in part, that written procedures shall be established, implemented, and maintained covering, equipment control, log entries and record retention. 0)erating Instruction 001-03.4 Outside Auxiliary Operator Daily Check Sleets, required that periodic inspections of the Diesel Generator Building be performed. The checksheets are required to be maintained for a period of 5 years in accordance with Procedure OAP-00 Rev. O. However, an inspection of certain areas of the Diesel Generator Building was not performed during the night shift on August 11 and 1 . In addition, the Outside Auxiliary Operator Daily Check Sheets (Nightshift). indicated that the four-day tank room and the Diesel Generator Building Basement had been inspected when in fact, it had no The NRC Office of Investigations (OI) investigated this issue and concluded that the o)erator deliberately failed to conduct the inspections and deli)erately falsified the inspection check sheet. The NRC recognizes that the licensee identified this issue, communicated it to the NRC. and took substantial disciplinary action against the individual. Therefore, this non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation (NCV).
consistent with Section VII.B.1 of the NRC Enforcement Policy. This is identified as NCV 50-325(324)/98-06-02. Missed Operator Round _ _ _______- ___- _
II. Maintenance M1 Conduct of Maintenance M1.1 High Pressure Coolant In.iection (HPCI) Valve Local Leak Rate Testina (LLRT) Insoection Scope (61726)
The inspector observed performance of LLRT for the HPCI 1-E41-F00 Steam Supply Inboard Isolation Valv Observations and Findinas On April 29, 1998, the inspector observed LLRT for the Unit 1 HPCI Steam Supply Inboard Isolation Valve. Upon completion of the testing, the test director determined that the leakage was measured at 62.2 standard cubic feet per hour (scfh), which did not meet the test acceptance criteria of 10 scfh. The test was declared unsatisfactory. Trouble-shooting was conducted as directed by the applicable procedure and work request / job order (WR/J0) 98-ACHB1 was initiated for the packing of the 1-E41-F002. Repairs to the valve Jacking were performed and the valve passed subsequent testing with leacage of 9.60 scf The inspector verified that measuring and test equipment was within the proper calibration period. The testing was performed in accordance with the applicable section of Periodic Test OPT-20.3. Local Leak Rate Testing. Applicable portions of the procedure were present and properly veri fied. Adequate communication between technicians was maintained throughout the duration of the testing. The technicians were knowledgeable of the test activit'ies performed and the equipment use Conclusion The technicians performing the High Pressure Coolant Injection Valve local Leak Rate Testing were knowledgeable of the test parameters, criteria. and equipment use M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Inservice Inspection (ISI) Inspection Scooe (73753)
The inspector examined inservice inspection work activities consisting of in-vessel visual examinations of portions of the jet pumps, inlet riser piping welds and core spray downcomer piping welds, as well as an automated ultrasonic examination of the reactor feedwater safe-end and
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10 Observations and findinos The Unit 1 Spring 1998 outage (8112R1) was the last outage in the third period of the second 10-year inservice inspection interval. On May 1 . Unit 1 started its third 10-year inservice inspection interva Therefore, examinations performed during this outage completed the second interval as well as started the third interval inspection requi rements. The applicable code for the second interval examinations was the 1980 edition and addenda thru Winter 1981 of the American Society of Mechanical Engineers Boiler and Pressure Vessel (ASME B&PV)
Code. The third 10-year inspection interval requirement was the 1989 edition of the ASME B&PV Code with no addend In addition to the above l inspection requirements, the vessel internals were examined visually by utilizing the BWR Vessel and Internals Project (BWRVIP) and the BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines (BWRVIP-18)
for the core spray downcomer piping, and the BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines (BWRVIP-41) for the jet pump riser piping and jet pump assembly components. The reactor vendor was contracted by the licensee to perform the ISI examinations. For the examinations of the reactor feedwater piping welds, the vendor used the Smart 2000 automated ultrasonic system. The remote modified VT-1 visual examinations were conducted from the bridge crane platform utilizing a color camera. The calibration sensitivity for the modified VT-1 examinations was a 1 mil wir The inspector observed ultrasonic examiners acquire data for the circumferential scans on Feedwater Weld No. 1821N4A-2-SW2-3 and the axial scans on Weld No. 1B21N4A-2FWNA45- In addition, ultrasonic data for reactor feedwater dissimilar metal welds Nos. 1821N4B-3-SW2- N4A-2SW2-3, 1821N4A-2-SW1-2 and 1B21N4B-3-SW1-2 were analyzed with the vendor's level III analyst to determine if the ultrasonic technique would penetrate the inconel butter weld in the weld joints and whether the analyst could clearly identify sound redirect, weld interface, weld discontinuities, and weld joint configuration conditions. The vendor's ultrasonic examination personnel were knowledgeable of the examination method and operation of the test equipment. The level III analyst also compared recorded indications with previous examination data to determine whether there were any differences in the inspection result The inspector observed visual examiners on the refueling floor acquiring data and performing real-time analyses of piping and component weld Portions of examinations for the core s] ray downcomer welds at 190 and 350 degrees were observed as well as t7e examinations of jet pump riser elbow and piping welds for the N2A riser and the RS1 weld on riser elbow ,
for N20. During examination of the N2D riser elbow (Weld No. RS1). GE discovered a 1-8 inch crack in the weld heat affected zone (HAZ) on the intrados of the elbow. In addition, during the inspection of the N2A riser piping two small bolts and other small metallic debris were found in the bottom of the annulus at jet pump No. 2. Inspection tables in BWRVIP-41 required the licensee to examine an initial inspection sample of 50 percent for the jet pump riser pipe and elbow welds this outag However, the discovery of the crack in the N2D riser elbow (Weld N ___ - _ _ _ - _ _ _ - - _ _ _
RS1) required the inspection sam)le to be expanded to include 100 percent of all jet pump riser el]ow welds. During the remote visual examinations, the inspector noted that in-vessel camera work activities, including camera positioning, resolution of the examination surface, and calibration verifications, were performed in an excellent manner. The inspector was notified that during the examinations of the expanded jet pump riser piping sample, the vendor discovered a 5-3/4 inch crack in the intrados of the elbow on riser N2G and a 1-1/8 inch crack on the intrados elbow on riser N2 The vendor stated that they would disposition all three cracks using fracture mechanic Conclusions l Inservice Inspection (ISI) activities were conducted in an excellent manner by examiners and analysts who were very knowledgeable and skillful in their use of the examination methods. Enhanced inspection techniques were very effective in thoroughly examming and evaluating the quality of welds, as revealed by the discovery of cracks in weld RS1 for risers N20. N20. and N2 M2.2 Insoection of Containment Structures (Unit 1) Insoection Scone (62003)
An inspection of the Unit 1 torus suppression chamber, the ringheader, downcomers, and vent lines was aerformed by the inspector to verify the material condition of each of t1ese components ana to observe a recent v.' eld repair in the vent line at 90 degree Observations and Findings CR 98-01051 had reported six areas of corrosion in the ring header vent line at 90 degrees. One of these areas was found to have a remaining wall thickness below the minimum design thickness for the vent lin Because photographs taken of material conditions in the ring header, downcomers. and vent lines by the licensee during performance of visual examinations using Periodic Test OPT-20.5.1. Rev.7 Primary Containment Inspection, were inconclusive to the ins)ector as to the actual material condition, the inspector conducted a wal(down inspection of these components. The inspector also reviewed the completed corrective WR/JO 98-ACHK1 to determine if the grindout and weld repair in the vent line at 90 degrees met the requirements delineated in ASME B&PV Code Section XI. Article IWE 1992 Edition with the 1992 Addenda. The walkdown inspection revealed that the reported corrosion which caused the weld repair was an extremely isolated condition and did not typify the material condition of the torus, ring header or vent lines, which were well-maintained. For exam)le, the paint in the Unit 1 torus was in excellent condition. even 3elow the waterline. Though small isolated
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I areas of discrepant paint were seen by the inspector, they were subsequently found to have already been identified by the licensee in the paint analysis for the i.oru .
12 Conclusions The torus, ring header, and vent lines were well-maintaine The completed weld repairs observed and the applicable documentation were found to be in accordance with procedures and specification M2.3 Soent Fuel Pool Eauipment Inventory and Foreian Material Exclusion l Controls i
! Insoection Scope (62707)
The inspector reviewea Foreign Material Exclusion (FME) controls associated with the Unit 1 Refueling Outage particularly regarding a thermocouple wire which was inadvertently introduced into the vessel during refueling preparation operation Observations and Findinas On April 28, 1998, the refueling crew noted a 30 to 50 foot long serpentine object on the top of the fuel in the reactor vessel. The object was seen immediately after turning on the lights which were placed in the core area to facilitate core alterations. The steam separator unit had been removed just prior to placing the lights in positio The licensee initiated CR 98-01015. FME on top of fuel, on April 2 . Additionally, the licensee conducted a root cause investigation and sent the object to an offsite vendor for analysis to determine its origin. The licensee, at the time of the event, was not aware of where or how the object could have been introduced into the reactor vessel area. The analysis and root cause investigation determiried that the object most likely was introduced to the reactor vessel area when the lights were placed in the vessel. The lights were stored in the fuel pool and the object was determined to be a thermocouple wire used during initial startup testing on Unit 1. The root cause stated that the thermocouple wire became entangled in the vessel lighting wires while in the spent fuel pool. The wire then fell off when the lights passed over the core are The thermocouple wire was not listed on the fuel pool inventory lis SFP inventory was maintained by procedure OAI-112. Control of Materials in SFP. The inspector noted upon review of 0AI-112 that the procedure had a caution statement referring to the possibility of an object being in the pool which was unidentified. D.? procedure stated ". . .the
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possibility of unidentified items 1cated in remote or difficult to !
access areas of the pool remains.' l The licensee's root cause investigation assigned a corrective action to perform a detailed fuel pool inspection to verify that no additional material was subject to inadvertent transfer to critical areas during routine activities. By the time this corrective action was assigned, the licensee had completed an inventory of " accounted for" materials in
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the pool: this inventory was used to fulfill the corrective action specified in the root cause investigation. However, this inventory did not attempt to identify unknown or ~ unaccounted for" materials in the poo Thus, the failure of the licensee's corrective action to address
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the root cause of this event was identified as a weaknes The inspector found that, generally. FME controls were conducted satisfactorily throughout observed activities during the Unit 1 refueling outage. The inspector noted no instances of material going into or out of the FME controlled are Conclusions
7 For the most part. Foreign Material Exclusion controls were implemented J satisfactorily. However, a lack of control of material in the fuel pool led to a thermocouple wire being inadvertently placed on top of the reactor vessel core. Also, spent fuel pool inventory and control was considered a weakness.
} M3 Maintenance Procedures and Documentation M3.1 Shutdown Marcin Test Insoection Scoce (61726. 37551)
The inspector observed the performance of the insequence critical shutdown margin (SDM) calculation during startup activities for Unit Observations and Findinas On May 23, 1998. Unit I was in Mode 2 and pulling rods to bring the reactor critical. The inspector observed restart activities and monitored the performance of Periodic Test OPT-14.3.1. Insequence Critical Shutdewn Margin Calculation. U)on the unit going critical at 8:26 pm, the nuclear engineer obtained t1e required data from the reactor operator and the plant process computer (PPC). The inspector verified that the test was completed satisfactorily and in accordance with the arccedure. Licensee calculations derived the percent SDM as 0.900. T1e inspector confirmed that the test results met TS 4.1. which required the test be conducted during the first startup after core alterations and the SDM determined to be equal to or greater than 0.38 percent delta k/ Conclusions Shutdown margin testing was completed satisfactorily and in accordance with the TS _ - - - - - - l
M4 Maintenance Staff Knowledge and Performance M4.1 Reactor Water Clean-Un (RWCU) Breaker Fire Insoection Scope (62707)
The inspector reviewed the circumstances surrounding a minor fire in a Unit 1 480 volt (V) motor control center (MCC) compartmen Observations and Findinas On May 1.1998, around 2:45 pm, the fire brigade was called to respond to a brief " fire ball" in a MCC compartment on the 20 foot elevation of the Unit 1 RB. At the time of the event. RWCU was out of service and reactor make-up and control was being maintained by the Fuel Pool Cooling System. The " fire ball" was observed while an instrumentation and control (I&C) technician was reinstalling the 1-G31-F001 control breaker after completion of preventive maintenance (PM) activities. The compartment was for the 1-G31-F001. RWCU Inlet Inboard Isolation Valve, located on MCC 1XC. No damage to the valve actuator was experienced due to the motor connections being disconnected. The fire alarm was sounded and the fire brigade responded promptly. The fire brigade remained in the area to ensure that the fire was out. Security personnel restricted access to the area until the power to the entire MCC could be turned off. As a result of proper implementation of site safety precautions, no personnel injuries occurred. The cause was attributed to a jumper being left on the breaker after testing was performed during the PM. CR 98-1077. MCC 1XC breaker flash, was initiated to describe this even The inspector responded to MCC 1XC and observed ongoing activities. The site safety representative was present as well as various member's of the maintenance organization. After the MCC was deenergized, the breaker was removed by plant staff. The inspector observed the removal of the breaker and investigation of the cubicle. No other compartments on the MCC appeared to have been affected. Reactor make-up and control was maintained throughout this even During review of this event and other observations, the inspector noted a negative trend in maintaining control of test and maintenance activities. This trend was made evident by several events, recorded in the following root causes:
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98-0789. Inadvertent 8 scram: '
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98-1077. MCC 1XC breaker flash:
. 98-1104 Valve Out of Position (1-E41-V159. HPCI Pump Discharge Line Check Valve):
. 98-1219. 1-E51-F029 Clearance problem:
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98-1220. Torus Master Clearance:
. 98-1280. Unexpected Rod Bloc Based on the need for further review of the licensee's root cause investigation for this event, as well as the need to fully evaluate the similarities of this issue to other issues identified during this period regarding the control of test and maintenance activities. this item is unresolve This Unresolved Item (URI) is identified as URI 50-325(321)/98-06-03. Configuration Control of Test and Maintenance Activities, Conclusions The cross-connection of multiple phases of a breaker compartment resulted in a brief " fireball". No adjacent personnel or equipment was damaged, and reactor make-u) and control was maintained at all times. A URI was identified for furtier review of this item and other related maintenance and test configuration issue M7 Quality Assurance in Maintenance Activities M7.1 Effectiveness of Licensee Controls Insoection Scone (73753)
The effectiveness of the licensee's controls over ISI vendor activities, and their ability to identify. resolve, and prevent problems were examine The irspector observed licensee personnel performing oversight of ISI vendor work activities, and reviewed current assessments and condition reports addressing ISI activities or problems.
, Observations and Findinas During this outage. the licensee assigned an experienced ISI reactor internals project specialist to oversee the remote visual examinations on the refueling floor. Surveillance inspections of the remote automatic ultrasonic examinations were conducted by an experienced licensee nondestructive test technician. Licensee level III examiners were overseeing vendor analysis and manual ultrasonic examination l activities. The inspector observed the individuals overseeing the I j ultrasonic data analysis activities and the reactor internals visual
- inspections on the refueling floor. The individuals were extremely proactive in assuring that quality work was performed. A draft Nuclear Asse.ssment (B-0M-98-01) was also reviewe This assessment covered IS in-service testing (IST), erosion / corrosion, repair and replacemen i welding. 3ressure testing and vessel internals activities. In the area !
of ISI. t7e assessment revealed very good findings, such as: 1) the need for the proper protection of calibration standards and for locked storage of those standards (CR 98-00795). 2) inadequate program notebooks, and 3) unclear Flow-Accelerated Corrosion (FAC) coordinator training requirements. The assessment also verified that the 10-year l
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ISI program and applicable inspection procedures had been updated to the third interval inspection requirement In addition, the ins)ector reviewed CR 98-00424 which was an expanded investigation of t1e vendor ultrasonic tool positioning errors documented in CR 97-03902 for the Unit 2. H6B core shroud weld. CR 98-00424 looked at all other shroud welds on Unit 1 and Unit 2. Five Unit 1 core shroud welds were identified which had tooling position errors resulting in insufficient i inspection coverage and/or flaw length errors. One core shroud weld on Unit 2 other than H6B was found to be affected by these errors.
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l c, Conclusions l The effectiveness of licensee controls over their ISI vendor, and in l identifying, resolving, and preventing problems, was excellent. This L
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was demonstrated by integrity of the vendor oversight observed: the conduct of a thorough assessment (B-0M-98-01) to determine the l effectiveness of preoutage preparations in support of the B112R1 outage; and the effective investigation documented in CR 98-00424 of discrepancies in inspection coverage and defect length sizing on Unit 1
& 2 core shroud weld M7.2 SDecial UFSAR Review
A recent discovery of a licensee o)erating the facility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compares plant practices, procedures, and/or parameters to the UFSAR descriptions. While performing the inspections discussed in this re] ort, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures, and/or parameter The inspector reviewed 3.4.1. Protection from External Flooding, and verified that the plant was operating according to UFSAR descriptions.
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The inspector found that ]lant instrument setpoints were configured according to the TS and t1e IIFSA M8 Miscellaneous Maintenance Issues (92902)
M8.1 LClosed) Deviation DEV 50-325(324)/96-08-01: Failure to Complete Maintenance Procedure Backlog l
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The licensee responded to this deviation on August 19, 1996, admitting the deviation. The corrective action for the deviation was to be completed September 1, 1997. The inspector reviewed the licensee's closure Jackage for this item. In addition, the inspector performed a random cleck of 20 procedures from the original list of procedures which needed to be upgraded in the technical library. All procedures had been upgraded. This deviation is closed.
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M8.2 (Closed) Violation VIO 50-325/97-13-03: Failure to Note Abnormal TS Surveillance Values The licensee responded to the violation in a letter dated February 23, 1998. The inspector reviewed the licensee root cause, which indicated that "[1] implementation of Rev 57 to 101-03.1 was not adequate to ensure compliance.. 0perations did not exhibit proper sensitivity about continuing long term operation with an out-of-specification reading.. 0perations personnel fully understood plant conditions and actions being taken to correct the out-of-specification parameters "
The inspector reviewed the associated corrective actions, and determined that none of the actions prescribed in the root cause adecuately addressed the identified failure to comply with the procecural requirements. However. CR 97-4136. Daily Surveillance Report and the associated failure mode determination adequately addressed the lack of
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procedural compliance through counseling of those individuals involved and communication of this event throughout the shifts. Based on satisfactory revision of the affected procedures, counseling of the staff involved, and the addition of abnormal surveillance values to the morning report, this item is close I M8.3 (Ocen) Inspection Followuo item IFT 50-325(324)/96-15-04: Material Condition of Remote Shutdown Panel This open item was examined by the inspector and although some of the material conditions previously reported were corrected, other material condition items were noted. Items identified this inspection included loose material such as dirt, fuses, screws washers, flaking paint, water corrosion, rust on unused terminals, and tarnished fuse cap ends at location 'BV' Therefore, this item will remain ope M8.4 (Closed) Licensee Event Report LER 50-325/98-001-00: Reactor Building Roof Vent Noble Gas Activity Monitor Surveillance Deficiency.
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On April 16, 1998, the licensee identified that the Unit 1 RB Roof Vent I
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Noble Gas Activity Monitor (1-CAC-AQH-1264-3) alarm setpoint was set at a value above the required TS value specified in TS 3.3.5.9. Radioactive Gaseous Effluent Monitoring Instrumentation and TS 3.11.2.1. Gaseous Effluents. The condition was identified during a channel functional test of this monitor. The licensee determined that this condition had existed since January 27. 1998. when the monitor was last calibrate The maintenance procedure, which was used on January 27. 1998, to calibrate the monitor, had been revised in July 1997. The licensee's !
root cause investigation into this condition found that procedure Maintenance Surveillance Test (MST) OMST-RGE25R. Revision 0. RGE Reactor Bldg Roof Vent Mon Channel Calibration, was deficient. The root cause was determined to be inadequate procedure development and review during the development of the procedure revision. The procedure failed to provide the necessary steps to reset the monitor to the required allowable setpoint value following a calibration check. On January 27, 1998, the alarm setpoint was not required to be reset because the
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account for this scenario and thus left the monitor with an alarm setpoint value above the allowed TS value. This procedure was not used on Unit This ventilation monitor provided an indication and alarm function only.
l In this case the alarm was inoperable but the indication and chart recorder functions were o)erable. Sampling and analysis by the licensee l of effluint- release data Jetween January 27 and April 16. 1998.-
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confirmed that the effluint noble gas releases were well below the Offsite Dose Calculation Manual (ODCM) calculated setpoin On April 16,1998. the licensee calibrated the monitor and the monitor alarm setpoint was reset to be within the allowable values prior to returning the monitor to service. The monitor's incorrect alarm setpoint was a violation of TS 3.3.5.9 and'TS 3.11.2.1. This non-repetitive, licensee-identified and corrected violation is being treated as a NC consistent with Section VII.B.1 of the NRC Enforcement Policy. This is
, , identified as' NCV 50-325/98-06-04 Non-Conservative Alarm Setpoint on
. Roof Vent Noble Gas Activity Monito III. Enaineerina r
L E1- Conduct of Engineering l
El.1 Environmental Qualification (EO) of Electrical Eauioment
'a , Inspection Scoce (92903)
The inspectors reviewed the licensee's corrective actions for the E0 L Program, in respomt to findings identified during Self.-Assessment numbers 95-0041 ane 96-0271 and the violations identified in NRC IR 50-325(324)/96-14. The~ inspectors reviewed the qualification data package
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(ODP) for 3M Scotch 23 taped splices and the licensee's written responses to the NRC comments on a draft of QDP-49. NAMCO EA 180 Limit u Switches. Revision 4. The inspectors also reviewed the projected L accident beta radiation doses for the drywell and RB which were used in the evaluations of EQ equipment.
l1 Observations and Findinas
. Review'of ODP for 3M Scotch 23 Taoe L The qualification for 3M Scotch 23 taped splices was addrersed i Qualification Data Package 0DP-20. Miscellaneous Cable Splices. Revision 1.-dated March 30, 1998. The file was intended to demonstrate generic qualification for the 3M Scotch 23 taped salices for various areas in the drywell and the RB. The qualification ) asis was the DDR Guideline The licensee attempted to show qualification for the 3M Scotch 23 taped splices based on similarity to Okonite T95 and Scotch 130C insulating tapes which-had been type tested. The inspectors found that the fil lacked adequate. detail on how 3M Scotch 23 tape was similar to tapes
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manufactured by Okonite (i.e.. T95 and T35). In addition, it lacked adequate detail on how Scotch 23 tape was chemically similar to Scotch 130 C irisulating tape and/or Bishop 44 jacketing tape. Furthermore, the file did not have a correlation between the tested taped splices (i. Okonite T95/T35 and Scotch 130C/ Bishop 44) and the way the tape was installed in the plant. The inspectors informed the licensee that a similarity evaluation that involved a different manufacturer's product such as the one involving the Okonite T95 and 3M Scotch 23 tape was unacceptable as a qualification basis. The DOR Guidelines state in part. that a type test should only be considered valid for ecuipment that is identical in design and material construction. Basec on the above, the inspectors concluded that qualification had not been established for the Scotch 23 tap The licensee performed a review of the historical and current j installation procedures and the E0 walkdown data to determine if Scotch j 23 tape was used or installed in any E0 applications. Based on this review, the licensee concluded that there were no current E0 a)plications identified that used Scotch 23 tape. However, historically t1e licensee determined that Maintenance Instruction MI-16-007. Large 480V and 4KV Taping Procedure. Revision 0 dated November 21, 1978, allowed the use of Scotch 23 tape as an acceptable alternative to Okonite T95 tape up until April 12. 1985, when Revision 7 was issued to the procedure. The licensee reviewed the maintenance work history and determined that prior to April 12. 1985, this 3rocedure had been used five times in rework activities that replaced E0 splices on equipmen The affected plant equipment, rework activity number using MI-16-007 and subsequent rework activity number which replaced a taped splice were:
'1) 1-E11-C0028-M. Motor for RHR Pump 1B: WR/JO 1-E-84-1682 (April l 1984): WR/JO 89-ANDR1 (June 20. 1989). ,
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2) 1-E11-C0010-M. Motor of RHR SW Pump 10; WR/JO 1-E-82-2534 (January 20. 1983): PM 92-091 (June 21. 1993).
3) 2-E11-C001C-M. Motor for RHR SW Pump 2C: WR/JO 2-E-82-2673 (June 28, 1982): PM 92-092 (October 5. 1992).
4) 2-E11-C002B-M. Motor for RHR Pum) 2B: WR/JO 2-E-84-2054 (August 10. 1984): WR/JO 89-ASRQ1 (Novem)er 27, 1989).
5) 2-E11-C002C-M. Motor for RHR Pump 2C: WR/JO 2-E-83-2931 (August ): WR/JO 89-ASDR1 (January 25. 1990).
Based on the above, it can be assumed that at least five E0 components l
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could have been installed with Scotch 23 taped splices prior to 198 However, the records also showed that the splices were subsequently reworked using qualified splice materials. Splices performec after i April 12. 1985 were required to be performed in accordance with 3rocedures which did not allow the use of Scotch 23 tape until 1997 when ,
)oth Procedure OSPP-CBLOO3 and Specification 048-012 were revised to permit the use of Scotch 23 in Non-E0 taped electrical splices.
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The E0 walkdown inspections identified six suspect E0 splices in the RB that had a jacketing tape which was different from the expected Okonite T35 jacketing tape. The tape was determined by the licensee to be Scotch 88 jacketing ta)e. The problem was documented in Condition )
Report CR 97-02859. T1e splices were found on terminations affecting !
the R. G. Laurance solenoid valves 2-E11-F079 and 2-E11-F079B: ITT Barton Differential Pressure Switches 1-CAC-PDS-4223. 2-CAC-PDS-422 and 2-CAC-PDS-4223: and ASCO solenoid valve 2-SW-V128-SV3. The licensee had initially assumed that all six splices wt 3 constructed of Scotch 23 ta)e because the outside tape was Scotch 88 Jacketing tape. However, su) sequent review of installation records for the six installations i demonstrated that this was not the case. The actual insulation tape was
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Okonite T95. The splices had either been replaced or determined to be acceptable to "use-as-is." The licensee informed the inspectors that based on their review. since Scotch 23 tape was not used in any current E0 applications. ODP 20 will be removed from the list of active QDP However, to support past qualification the licensee indicated that they had located information in their files from the manufacturer (3M) that would su) port a similarity analysis between Scotch 23 and Scotch 130C j tape. T1e inspectors noted that the current revision of ODP-20 i discusses test results from E0 testing of Scotch 130C tape to the Brunswick Nuclear Plant environment. The inspectors determined that the file deficiencies in ODP 20 described above constitute a violation of j minor significance and are not subject to formal enforcement action, j l
Effects of Beta Radiation on the Qualification of E0 Solices
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The 00Ps for Scotch 23 and Okonite T95/T35 tapes (i.e.. ODP 20. Revision 1 and ODP 16. Revision 3. respectively) were reviewed to determine if ;
beta radiation effects had been adequately addressed in the evaluation j The inspectors noted that both ODPs took credit for a reduction in the beta dose based on the splices being located in enclosures (e.g., J j
terminal boxes). The basis for taking the reduction was engineering i service request (ESR) 96-00619 and the E0 walkdown inspections on splices. ESR 96-00619. Revision 0 determined the beta acciaent doses both in the drywell and the RB due to a design basis accident (DBA). It also provided beta reduction factors to be used in evaluating the qualification of E0 equipment for beta radiation effects. The inspectors found that beta doses had been reduced in both ODPs based on a reduction factor of 65 which related to the splices being located in l an enclosur The inspectors reviewed the ESR and confirmed that a reduction factor of 65 was acceptable for splices located in an enclosur However. ESR 96-00619. Revision 0 stated that splices were also located in cable trays or raceways.
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l The inspectors questioned whether there were any E0 splices in l cable trays and whether these splices were examined as part of the walkdowns. The licensee performed a detailed review of E0 circuit interconnecting diagrams to determine if E0 splices were located in cable trays in the Unit 1 or 2 drywells. The inspectors reviewed ESR 98-00224 Cable Tray Splices in Areas Subjected to Significant Beta, which documented the results of the review. The
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conclusions of the ESR were that no E0 circuits contained splices in cable trays located in the drywell. The ESR also evaluated the acceptability of E0 splices located outside of enclosures in the RBs, Based on the test data, the licensee concluded that E0 splices located in cable trays in the RB meet the requirements of 10 CFR 50.49. The inspectors concurred. The inspectors walked down the Unit 1 drywell and examined accessible cable trays. The inspectors verified that there were no splices on E0 cables in the drywell. However, during the walkdown inspection, the inspectors identified several cables which had an approximate 6-inch length with an outer covering of ta)e. Licensee engineers determined from review of the cable num)ers that only one of the cables affected E0 equipmen The outer covering of tape was determined to be re) airs to the cable jacket and not a cable splice. Based on the a)ove review. the inspectors concluded that the licensee had adequately addressed the effect of beta radiation on E0 cable splice Review of Licensee Written Responses to NRC Comments on ODP 49. Revision 4 NAMC0 EA 180 Limit Switches ODP-49 is the qualification file for the NAMCO EA 180 Limit Switche The NRC had previously reviewed a Draft copy of Revision 4 of this ODP and had provided several comments which were documented in IR 50-325(324)/97-13. The licensee provided written responses to these comments. The inspectors reviewed these responses and found all but one to be acceptable. The inspectors questioned the technical basis for not selecting the lowest activation energy number in the qualified life calculation for the NAMCO EA 180 limit switch. The licensee provided a reasonable justification for not selecting the lowest activation energy number for the gasket material of 0.8 electron volt (eV): however, the response did not address why the next lowest activation energy number of 0.836 eV was not selecte The 0.836 eV activation energy number was ;
for the glass filled phenolic contact block / contact carrier material RX865. The licensee provided the inspectors additional information to support their conclusion that the RX865 material was essentially age-insensitive for its installed service conditions at BNP. This information was reviewed in detail by the ins)ectors with subsequent questions being identified and addressed by t1e licensee. The licensee was able to provide adequate information to show that their selection of an activation energy number of .99 eV. which was used in the analysis to l establish a qualified life for the limit switches, was conservativ Based on this review, the inspectors concluded that ODP-49 adequately demonstrated qualification for the NAMCO EA 180 limit switche c. Conclusions After resolution of the inspectors' review comments, the ODPs reviewed met the requirements of 10 CFR 50.49. The effect of beta radiation on E0 cable splices was evaluated in accordance with the requirements of 10 CFR 50.4 !
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E1.2 Modifications to Terminal Boxes to Resolve E0 Moisture Issues Insoection Scope (92903)
The inspectors examined modifications made to electrical terminal boxes to prevent accumulation of moisture in boxes containing EQ equipmen Observations and Findinas The inspectors, accompanied by licensee E0 engineers, performed )
walkdown inspections in the Unit 1 drywell and examined i modifications to electrical terminal boxes to address moisture j intrusion issues identified in CR 97-02408. The modifications involved drilling of weepholes in the terminal boxes to preclude the possibility of excessive moisture from accumulating in the boxes during various accident scenarios. The inspectors examined accessible electrical penetration terminal boxes and verified that the weep holes had been drilled per design requirements. The inspectors also examined the conduits located at radiation monitors and verified that they had been sealed to prevent intrusion of moisture from the drywell spray headers. In addition, the inspectors also walked down the Unit 1 Main Steam Isolation Valve pit and examined E0 equipment installed in this area. The inspectors verified wee) holes were present in terminal boxes for the E0 equipment, with t1e exception of the boxes for the ASCO solenoid valves, which were sealed in vendor-supplied boxes per the requirements of ODP 3 Conclusions The licensee had adequately modified electrical terminal boxes containing E0 equipment to prevent the accumulation of moisture and had addressed the effects of moisture on E0 components in i accordance with the requirements of 10 CFR 50.4 E1.3 Review of Environmental Qualification Condition Reports i 1 Insoection Scooe (92903)
The inspectors reviewed CRs initiated to document and disposition discrepancies involving environmental qualification issue Observations and Findinas The inspectors reviewed the licensee corrective actions performed to disposition the CRs listed below. These CRs were initiated by l
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the licensee to document and disposition nonconforming items which were identified during the ongoing E0 reconstitution project. The nonconforming items were identified as a result of E0 equipment walkdowns review and updating of E0 equipment ODPs. examination of omitted items from the original program, or review of changes to the operating environment. The CRs reviewed were as follows:
CR 98-00172 was initiated to document the existence of local temperature " hot spots" in some plant areas which had the potential to affect qualification of some E0 equipment. The licensee prepared ESR 9800032 to address these areas and updated DR-227. Environmental Qualification Service Conditions. to Revision 4. dated February 2.1998 to address evaluation of the local high temperatures. Equipment qualified under nine ODPs was affected by hot spots. The licensee determined that three ODPs may require revision to consider the affects M 1m hot spots, while the remaining six were acceptable. The oca.see will install temperature monitoring equipment in affected areas by June 17, 1998, to obtain additional temperature data in the " hot spot" areas. The additional temperature data will be evaluated by November 30, 1998. The inspectors questioned licensee engineers regarding the existence of radiation " hot spots" which could also-impact the ODPs. In response to these questions, the licensee provided a report titled, drywell Radiation Monitoring, which was prepared to respond to CR 96-02149. Action items 4 and 7. Review of the report disclosed that the radiation dose test value used in qualification testing of E0 ecuipment was in excess of 250 percent of the )rojected drywell accicent environment. Based on this data, t1e licensee concluded that it was not necessary to monitor for radiation " hot spots" The inspectors concurre CR 98-00306 was initiated to investigate Jossible discrepancies in qualification of PTK control switches. T1e concern was that some new re)lacement switches stored onsite may have been different than t1ose qualified under ODP - 61. The inspectors reviewed ODP-61 during the inspection documented in IR 50-325(324)/98-04. This CR was initiated in response to questions raised in ESR 960041 Further review of this issue disclosed that an Engineering Evaluation Report. EER 87-0532. had been issued in 1987 to identify critical characteristics in non-metallic components in the switches which could affect environmental qualification of the switches. In 1996, the licensee central receiving dedication facility (CDRF) issued ESR 9600418 for the E0 grou) to review and identify the critical components in the switches w11ch were i critical to environmental qualification. The pur)ose of the ESR was to confirm the previous EER results because t1e CDRF had identified some differences between switches in storage and ODP-61. EER 87-0532 had identified these same differences as non-critical per E0 The ESR confirmed the results of the previous
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24 i EE No new switches had been' purchased for use onsite since 1987. CR 98-00306 was closed based on the fact that no corrective actions were required to resolves the issues. The inspectors concurred with closure of the C CR 98-01013 was initiated on. April 28, 1998. to document deteriorated splices. The licensee's E0 walkdown inspections of shield wires 1-0C9-T68 and 1-0C9-TX4 (for containment atmosphere resistance temperature detector [RTD] splices 1-CAC-TE-1258-24 and 1-CAC-TE-1258-20. respectively) identified that the T95 taped splice had deteriorated to the Joint where bare conductor was exposed on each splice making t1e splice unqualified. The inspectors questioned the licensee about this issue to determine what corrective actions were planned. The licensee stated that no corrective actions were necessary because the wires with the degraded T95 tape were uninsulated drain wires that do not require an E0 splice. The licensee also stated that a qualified E0 splice could not be'made on these bare wires. The inspectors informed the licensee that typically instrument circuits such as these RTD circuits are grounded at one. end, but not both ends of the circuit to limit noise on the circuit. Therefore failure to repair the insulation over the drain wire could allow a ground.at an interim point in the cable routing and thus was a poor engineering practice. The~ inspectors requested additional information about how the licensee handles grounding of instrument circuits. The licensee concluded from this review that the electrical notes and details in Specification 048-12 only address a thermocouple splice and not the specific RTD splices that were in question. In addition, the licensee determined that Specification 048-004 requires that instrument circuits be grounded at one point. The licensee then informed the inspectors that the electrical notes l and details and plant maintenance procedures would be revised accordingly to address the RTD splice configuration and that the T95 tape on the drain wires would be repaired. The inspectors considered this item to be open Sending review of the licensee's completed corrective actions. T1is item is identified as
- Inspection Followup Item IFI 50-325(324)/98-06-05. Repair of RTD Drain Wire c. Conclusions The licensee was making adequate ]rogress in resolving and closing CRs identified by the E0 group. iowever engineering failed to
! recognize that a repair should be made to the Okonite T95 taped splices on the drain wires for two Containment Atmosphere RTDs to L prevent multiple grounds .in the circuit. This was considered a
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E1.4 Service Water Insoectinn Insoection Scone (37551. 62707)
The inspector monitored and reviewed those activities associated with the inspection of the Unit 1 Conventional and Nuclear Service Water (SW)
l headers and related A loop RB piping.
' Observations and Findinas The licensee performed disassembly. eddy current testing visual inspection and repair of SW piping and components. The licensee conducted visual inspections of both the nuclear and conventional SW l
headers. Eddy current testing was conducted satisfactorily on the 1A RHR heat exchanger. Four leaks were identified. Two of the leaks had been previously identified and ASME code relief had been obtained ]er 10 CFR 50.55(a) for leaks located in the vital header downstream of t7e 1-SW-V132 and for a weld for a connection off the nuclear header. The i leaks were satisfactorily repaired. Overall, the sections of the SW system tested and inspected were found to be satisfactor ,
i Conclusions Inspection. testing, and repair of SW piping components were completed I satisfactoril Licensee inspection results determined that the I material condition of these components was satisfactor E2 Engineering Support of Facilities and Equipment i
E2.1 Followuo on Reoairs to Flex Pioina on SLC System Insoection Scope (37550)
The inspectors reviewed the licensee's corrective actions to repair leaks in the flexible piping in the Unit 1 standby liquid control (SLC) syste Findinos and Observations During pest-maintenance testing, the licensee identified small leaks in a section of flexible piping located on the suction lines to the SLC pump This problem was documented in CR 98-0131 The licensee performed NDE testing (licuid penetrant exams) on the flexible piping and identified four indications. The licensee !
initiated weld repairs in accordance with the ASME Section IX l repair / replacement 3rogram. The repairs were performed in accordance with CP&_ welding procedure specification (WPS) 0820 Following completion of the weld repairs. a hydrostatic pressure test was performed on the piping. One small leak was identified at one of the repair areas. Additional liquid penetrant testing was performed which resulted in identification of a small indication at the end of the weld repair which had been observed
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to be leaking during the hydrostatic test. The inspectors
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witnessed performance of the ND The indication was repaired using WPS 0820 Following completion of the repairs another hydrostatic pressure test was performed which showed that the piping was successfully repaired. The inspectors reviewed the
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records documenting the final weld repairs and hydrostatic testing which was performed under WR/JO 98-ACPA c. Conclusions The licensee's actions to repair the pinhole leaks in the Unit 1 SLC flexible piping were performed in accordance with good engineering practices and NRC requirement E2.2 ivaluation of Bolted Connections for Reactor Pressure Vessel (RPV) Head
->ioe Sucoorts Insoection Scooe (37550)
The inspectors reviewed the licensee's operability evaluation of
)ipe supports attached to the Unit 2 refueling seal plate with
)olts tightened to a " snug tight" condition, Observations and Findinas
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During removal of the Unit 1 drywell dome at the start of refueling operations. pipe support 1821-701PG173 was damage This problem was documented on CR 98-00981. This support plus some others, are removed each refueling outage in accordance with
! procedure OSPP-RPV501 and reinstalled after refueling is completed l per procedure OSPP-RPV502. ESR 98-00207. Pipe Support Repair, was
! issued to design a repair to the damaged support. During preparation of the repairs to the support, it was discovered that there were no torque requirements in procedure OSPP-RPV502 for reinstallation of the supports. From inte Niews with craft
, personnel, the licensee determined that bolts in the structural l connections for the reinstalled supports were tightened to a " snug i tight" condition. CR 98-01301 was initiated to document and resolve this issue. Corrective actions included revision of procedure OSPP-RPV502 to incorporate the torque criteria for installation of structural bolts in accordance with Specification 248-107. The Unit 1 supports were reinstalled in accordance with the revised procedur The licensee prepared ESR 98-00268. Evaluation of Bolted 1 Connections for RPV Head Pipe Supports, to evaluate operability of 4 the Unit 2 pipe supports installed with bolts tightened to a " snug !
tight" condition. as well as the past operability of the Unit 1 i sup) orts. The ins)ectors reviewed the ESR, calculation numbers '
PS- 321-032 and PS- 321-532, and the pipe support sketches for the ;
six affected Unit 1 and five affected Unit 2 support Review of these documents showed that the bolted connections were lightly
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loaded and that the supports are not affected by vibration. The inspectors concurred with the licensee's conclusion that the Unit 2 supports were operable until the next refueling outage. and that past operability of the Unit 1 and 2 supports was not affecte Conclusions The licensee's operability evaluation of bolted connections for RPV pipe supports was completed in accordance with the guidance specified in Generic Letter 91-1 E2.3 Unit 1 Emeroency Core Coolina System (ECCS) Suction Strainer Modi fications Insoection Scope (37551)
The inspector reviewed the project activities associated with the installation of new RHR and CS system strainer Observations and Findinas The same strainer modification was completed on Unit 2 during its last refueling outage. The excellent planning and decision-making implemented during that modification was present during the Unit 1 modification. This resulted in the successful completion of the Unit 1 strainer modification. The modification was performed with no di fficultie The inspector observed the installation of the strainers in the torus as discussed in Section 02.2 of this repor Conclusions The inspector concluded that the same excellent planning and decision-making which was implemented during the Unit 2 ECCS strainer modifications led to the successful completion of the Unit 1 ECCS strainer modificatio E4 Engineering Staff Knowledge and Performance E4.1 Diesel Generator (DG) Load Test Insoection Scope (37551. 61726)
The inspector reviewed the adequacy of a temporary procedure change for ;
Maintenance Surveillance Test 1MST-DG11R. DG-1 Loading Tes l Observations and Findinas On May 21. 1998. Unit I was in mode 4 and Unit 2 was operating at 100 percent power. Temporary change 98-045 was made to 1MST-DG11R to substitute the 1-1VA-1D-SF-CB. Unit 1 Control Building Control Room
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Supply Air Fan for the 2-VA-2D2-SF-DW. 2D drywell Cooling Unit Supply Fa The inspector questioned Operations personnel as to the j acceptability of this substitution without an Engineering Support l Request (ESR) demonstrating equivalent loading. The inspector was '
concerr.ed with the DG load profile being maintained during the load test. The licensee informed the inspector that the change did not affect the intent of the procedure and was performed in accordance with
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i Administrative Procedure 0AP-004. Temporary Changes to Procedures, and IMST-DG11 t The inspector reviewed Updated Final Safety Analysis Report (UFSAR)
Table 8.3.1-6. Design Basis Automatic Loading Sequence For Diesel-Generator Units. Ste at 50 horsepower (hp)pStep
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5 of7. the table included the of 1MST-DG11R states starting
"WHENof 10 Spray Core MDVs Pump 1A starts. START both supply fans of drywell Cooling Unit 2D AND VERIFY both fans are running (simulates a 10 MDV start)." The ins)ector reviewed drawings F-03049 and F-30053. These drawings described t1e 480 ,
volt (V) distribution for several motor control centers (MCCs) connected 1 to the E5 480V bus. The E5 bus is powered during an emergency by DG- I Drawing F-03049 indicated that the 2-VA-202-SF-DW was a 50 hp motor; while drawing F-30053 indicated that the 1-1VA-10-SF-CB was a 25 hp moto The inspector noted that based on the differences in size, the 1-1VA-1D-SF-CB was not a "like-for-like" replacement: therefore, the lower horse)ower motor would affect the load profile for that step. In addition t1e load test operating range would be altered. The intent of the procedure was to verify that the DG rating would be maintained during the shedding and resequencing of necessary loads identified by the test procedur TS 6.8.2 states that temporary changes to procedures or proposed tests may be made provided that the intent of the original procedure is not altered. 0AP-004 section 3.2. considers a change an intent change if required operating parameter ranges are altered or deleted. Thus, the use of a temporary change by the licensee, which altered the intent of a DG test loading configuration, is a violation of TS 6.8.2. This violation is identified as 50-325/98-06-06. Intent Change Established as Temporary Chang c. Conclusions A change to the Diesel Generator load test was made, which altered the test loading profile. The use of a temporary change to alter the intent of the test load procedure was identified by the inspector as a l violation.
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E8 Miscellaneous Engineering Issues E (Closed) Licensee Event Report LER 50-325/97-13-00: Reactor Core ?
Isolation Cooling System Procedure Inadequacy During the licensee's review of surveillance tests aerformed in accordance with GL 96-01, the licensee identified t1at a procedure -
change had resulted in the failure to test the electrical continuity between instrument racks 1-H12-P017 and 1-H12-P03 The inspector reviewed the associated CR (97-2556. RCIC Isolation Logic) and the associated root cause investigation. That licensee's investigation found that the Maintenance Surveillance Test 1MST-RCIC1R. Reactor Core Isolation Coo' ling (RCIC) Auto-Actuation and Isolation Logic System Functional Test was revised without an adequate review due to personnel dose concerns. As corrective actions for this issue, the licensee revised Maintenance Surveillance Test. 1MST-RCIC230. RCIC Turbine j Exhaust Diaphragm High Pressure Instrument Channel Calibration to assure !
that the continuity between the P017 and P037 instrument racks was verified. This event was reviewed with the procedure writers, and counseling was conducted for those individuals involved. Based on completion of the items identified and review of the adequacy of procedure writer guidance for the maintenance of logic testing overlap, this item is close E8.2 (Closed) LER 50-325(324)/97-011-00: Simultaneous Drywell and Sup)ression I Chamber Valve Lineups Result in Unanalyzed Pressure Suppression 3ypass Flow Path.
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A review of industry events related to primary containment pressure l suppression bypass paths determined that plant operating procedures allowed simultaneous inerting/ purging /deinerting of the drywell and suppression chamber.. This condition allowed for an external pressure suppression bypass path between the drywell and suppression chamber air spaces. With this condition established it was determined that design l
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drywell pressures could be exceeded during certain Loss of Coolant Accident scenarios. It was additionally determined that this previously unanalyzed condition had existed since construction of the facilities.
! A 10 CFR Part 21 report was issued on October 15. 1997. Suppression Pool i
Bypass Leakage Due to Postulated Standby Gas Treatment System Failur l Upon notification of this condition, the licensee took prompt action to ensure that the bypass path could not be established by implementing f
administrative control Initially, a standing instruction was implemented to prevent the drywell and suppression chamber from being inerted/ purged /deinerted simultaneously. Revisions were made to the operating procedures, emergency operating procedures, design basis documents, and the Updated Final Safety Analysis Report to prevent a bypass condition from being established and to reflect the design issues associated with this previously unanalyzed conditio l
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The licensee's root cause investigation determined that there was a failure in the original and subsequent design analyses to identify the bypass path between the drywell and suppression chamber during routine inerting/ purging /deinerting evolutions. In addition to the administrative controls which were implemented, the licensee conducted a review of every penetration that exists in the drywell and suppression chamber to determine if any other bypass path could be established. The licensee reported that no other bypass paths existed. All of the corrective actions identified were completed.
l Because the licensee was still evaluating the option of installing l mechanical (as o) posed to administrative) barriers. such as interlock to prevent this )ypass flow 3ath and because of the generic ramifications associated wit 1 this issue described in the 10 CFR Part 21 Report, the inspector opened IFI 50-325(324)/98-06-07 Generic Issued Resolution of Containment Pressure Suppression Bypass, to track the resolution of this condition. This LER is close E8.3 (Closed) Violation VIO 50-325(324)/97-15-04: No CRs for Plant Process Computer Failures The failure to initiate CR's for functional failures of the PPC was cited as a violation. This licensee responded to this violation in a letter dated April 1. 1998. The inspector reviewed the violation response, associated root cause analysis and prescribed corrective actions. Action Item 5 to CR 98-313. PPC/ CAPS Compliance, required training to be conducted on the Maintenance Rule basis and reportin The inspector verified that the training had been conducted on March 4 1998. The inspector noted that one of the instructors had been identified in the root cause as needing training on the Maintenance Rule. The inspector questioned the adequacy of the implementation of the training. The licensee indicated that the training provided was a review of the errors made in setting up the performance criteri Subsequently on June 4.1998, the licensee provided retraining, performed by the Maintenance Rule group for the PPC system enginee The inspector verified the completion of ESP training for the PPC system engineer. Based on satisfactory completion of training and of the other prescribed corrective actions, this item is close E8.4 (Closed) 1.ER 50-324/97-002-00: Core Spray System Minimum Bypass Flow Motor Operated Valve Inoperability The core spray (CS) system minimum flow bypass valve. which also provides a manually initiated primary containment isolation function, was declared inoperable. This occurred following a reduction of the calculated motor torque below the required amount to be able to cycle the valve under all conditions. With the new motor torque calculated values and the torque switch settings, which existed at the time the valve could have failed (stalled) in a not fully closed position. Two
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31 conditions were necessary for the valve to fail: if both a maximum differential pressure across the valve was established and a degraded voltage existed on the power supply to the valve motor. This condition was identified by the licensee during an ongoing review of their MOVs 4 against revised design criteri I The licensee took prompt action to declare the valve inoperable and close the valve since it was not able to perform its primary containment isolation function. This action was required by TS 3.6.3. Primary Containment Isolation Valves. The 2B CS loop was declared inoperable in accordance with TS 3.5.3.1 Low Pressure Cooling Systems. The licensee took_3rompt action to restore the CS system and the CS system minimum flow )ypass valve by implementing a revised torque switch setting. The licensee has planned modifications to enhance existing margins on this valve. These modifications were being tracked as part of their
@signated MOV Improvement Pla This condition was determined by the licensee to be of minimal safety significance based on three factors: 1) The unlikelihood that both a maximum delta pressure and a degraded voltage condition would exist at the same time when receiving a closure signal 2) the minimal consequences of a failure of the primary containment isolation function of the valve. .and 3) the continued ability of the CS system to perform its intended safety functio The CS system minimum flow bypass valve inoperability resulted in a condition prohibited by TSs. The primary containment isolation function of this valve was inoperable for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> without meeting the appro)riate TS 3.6.3 action statement. This was a violation of TS 3.6.3. T1is non-repetitive, licensee-identified and corrected violation is being treated as a NCV. consistent with Section VII.B.1 of the NRC Enforcement Policy. This NCV is identified as 50-324/98-06-08. Core Spray System Minimum Flow Bypass Valva Inoperabilit E8.5 (Closed) Violation VIO 50-325(324)/97-09-01: Failure to Consider EQ Requirements in Engineering Evaluations The licensee responded to this violation in a letter dated October 15, 1997. The cause of this violation was the failure of individuals responsible for implementing changes to 3rocedures and design to ensure that the changes were reviewed by t1e EQ discipline engineer The licensee's corrective actions included re emphasis by management to site personnel of the need to perform discipline reviews when procedures are changed and when plant modifications are developed. The inspectors reviewed a memorandum from the plant manager to all site personnel, dated October 20, 1997, Subject: Technical Discipline Reviews for Proposed Procedure
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Changes..which specified the requirements for performance of the discipline reviews. Additional corrective actions included revision of procedure OAP-003. Procedure Preparation. Review, and Approval. to add emphasis on technical discipline reviews for l areas such as EQ and seismic requirements. ihe inspectors
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reviewed Revision 11 of 0AP-003 dated April 17. 1998, and verified that it contained the requirements for performance of discipline reviews. The inspectors reviewed ESRs 97-00435 and 98-00061, which documented the qualification of the Hinds-Crouse fittings, and Revision 7 of ODP-67, General Electric Company IC Series Motor Control Centers (MCCs), dated March 30, 1998. The inspectors verified that environmental qualification of the Hinds-Crouse fittings was incorporated into environmental qualification of the MCC E8.6 (Closed) Violation VIO 50-325(324)/97-09-03: Deficiencies in Preparation of Qualification Data Packages The licensee responded to this violation in a letter dated October 15, 1997. The cause of the violation was attributed to personnel erro The licensee's corrective actions included resolution of open items in ODP-67 and DR-227, and revision to ODP-67 to address evaluation of )
.onormal temperatures. The inspectors examined the current revisions of '
ODP-67 (Revision 7) and DR-227 (Revision 4) and verified that open items against these documents had been resolved. The inspectors also reviewed the evaluation of abnormal temperatures on the environmental qualification of the MCCs and verified that the effect of the abnormal temperatures complied with the requirements of 10 CFR 50.49. The evaluation of temperature effects on the MCCs had been previously reviewed by the inspectors during the. inspections documented in NRC Inspection Report Nos. 50-325(324)/97-09 and 50-325(324)/97-1 E8.7 (Closed) Insoection Followuo Item IFI 50-325(324)/97-13-06: Revisions to l Procedure EGR-NGGC-0153
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l Review of procedure EGR-NGGC-0153. Engineering Instrument t
Set)oints. Revision 3. identified several questions concerning met 1Ldology to establish instrument setpoints. The licensee issued Revision 4 to the procedure on April 30. 1998. The i inspectors reviewed Revision 4 of the procedure and verified that i the questions / inconsistencies documented in IR 50-325(324)/97-13 l had been resolved. In addition, the inspectors noted that drawing
- D-03056, Service Environment Chart Normal and Accident Conditions, l had been revised in Revision 6 to reference DR-227 as the source for drywell and RB environmental dat E8.8 (Closed) Escalated Enforcement Item EEI 50-324/96-15-05: Operation In Excess of Licensee Thermal Power Limi This item was re) laced by Violation (VIO) 50-324/96-442 in a Notice of Violation dated Jecember 13, 1996. but was not specifically closed at that time. This item is now close _- - _ _ _ - _ - _ _-
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l E8.9 (Closed) Escalated-Enforcement-Item EEI 50-325(324)/97-12-07: Failure
'to Take Corrective Action for High Drywell Temperatures and Torus
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Bypas ThisLitem was replaced by Violation (VIO) 50-325(324)/97-520 in a Notic of' Violation dated December 23, 1997, but was not specifically closed at
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that time. This item is now close '
E8.-10 (Closed) Escalated Enforcement Item EEI 50-325(324)/97-12-09: USQ on Spent Fuel Cask Movemen This item was adequately addressed in a letter to the licensee granting enforcement discretion, dated December 10, 1997. This item is now closed, l IV. Plant Sucoort '
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R1 Radiological' Protection and Chemistry Controls' l R1.1 Radiological. Protection and Chemistry. (RP&C) Controls Insoection Scooe (83750)'
The inspector reviewed implementation of selected elements of the licensee's radiation protection program. The review included observation of~ radiological posting. labeling, and area _ controls:
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ins)ection of material free release practices; evaluation of radiation worter 3ractices: and review of personnel dosimetry, exposure control Jand ALARA program details, implementation, and goal b. Observations and Findinas Radiological Postina. Labelino. and Area Controls l Radiologically controlled areas including RMSAs. High Radiation Areas, and Locked High Radiation Areas were appropriately posted and radioactive material was appropriately stored and labeled. As a i followup to Condition Report 98-00423. the inspector looked for ;
. protective clothing laundry or used scrubs stored outside the RCA during the site tours The inspector did not find any laundry or scrubs in ;
unauthorized . location 'The inspector requested verification that the key for the Very High l Radiation (VHR) Area lock was appropriately controlled and that the ;
correct revision for the lock cores was in-service. The licensee !
demonstrated control and operability of the VHR key located in the Work Control Center in locks for the Unit 2 TIP Room and the Unit 2 drywel The ins)ector, during tours, took smears to verify contamination control in the.18. Turbine Building. Radwaste processing area. RMSAs. various storage areas. on the refueling floor, and around the Unit 1 drywell control point. All smears were counted and determined to be within
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- established' plant limits. -The inspector also walked along posted control boundaries with a survey meter.on the refueling floor and in various storage areas and determined that the radiation levels were all consistent with the most recent survey . The inspector reviewed the Contaminated Square Footage Data. At.the time of the inspection, the licensee was tracking approximately 47.600 square feet (sq. ft.), or approximately 6.8 percent of the accessible area-(699.669 sc . ft.) as contaminated. The licensee has established the contaminated square footage target of approximately 7 percent (48,976 sq. ft.).
Material Free Release Practices-The inspector toured the waste segregation facility located outside of the protected area fence but within the owner controlled area and
- inspected the equipment used to free release dry active waste. The
. inspector also reviewed a contractor report titled " Evaluation of the Radiological Monitoring Program for Clean Solid Waste." Brunswick Steam Electric Plant. Southport. North Carolina. dated July 12. 1995: the 10
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. CFR 61 Waste Analysis Summary (Plant'ID.No. 97-5366); and a waste characterization analysis for used laundry dated March 4, 1998. The contractor report stated that " Records from.the Plant Shipping {
Department indicate that as much as 80 percent of the activity in the '
dry waste is Fe-55, with Co-60 providing approximately 15.to 20 percent
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of the total-activity," A review of the' data for the other two analyses L
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. indicated an Fe-55 activity content of approximately 47 percen The inspector reviewed procedure OE&RC-0217. Calibration and Operation of. Clean Trash Vault Monitor. Revision 12. dated March 1. '199 Discussion'with' licensee personnel and review of procedures used by the licensee to calibrate and source check the instruments revealed that the survey and monitoring equipment used to free release the dry active
[ waste would detect beta-gamma emitters such as Co-60 and Cs-137, but were:not efficient for detection of Fe-55. Based on discussions with licensee personnel, the inspector concluded that no evaluation had been
- documented of licensee survey methods to ensure that radioactive material in the form of Fe-55 was not being inadvertently released off the site. In addition, a check of the clean trash monitor by the licensee at the time of the inspection revealed that the effective alarm level was 7163 dpm. This value was higher than the target value of 5000 dpm due to the level and variations in the backgroun Step 6.1.9 of procedure OE&RC-0217 states " Clean trash destined for burial, incineration, or release shall have no detectable activity as discussed in OE&RC-0216." Further, procedure step 10.0 (5) states tha .for volumetric materials. "In addition to gamma counting , the presence of difficult lto measure nuclides (eg.. H-3, Am-241. Sr-90) must be evaluated."
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1 The licensee was informed that the issue of monitoring for Fe-55 would be unresolved pending additional NRC evaluation. The licensee took immediate compensatory measures and stopped the free release activities pending an evaluation of the system detection capabilities. This item is identified as Unresolved Item URI 50-325(324)/98-06-11. Evaluation of Detection of Fe-55 Concentrations or Quantities of Radioactive Material and Calibrate Instruments for Radiation Monitore Radiation Worker Practices The inspector reviewed operational and administrative controls for entering the RCA and performing work. These controls included the review of radiation work permits (RWPs) by workers prior to entering the RCA. The inspector reviewed selected RWPs for adequacy of the radiation protection requirements based on work scope, location, and condition For the RWPs reviewed, the inspector noted that appropriate protective clothing, and dosimetry were indicated. During tours of the plant, the inspector observed the adherence of alant workers to the RWP l requirements. The inspector found tlat personal dosimetry was being '
worn in the appropriate locatio The inspector observed workers using friskers (i.e. , Sancake Geiger-Mueller survey instruments) at the exit location of t1e RCA and observed workers exiting the 3rotected area through the exit portal monitor The inspector also caserved friskers in use at various locations in the turbine building, on the refueling floor, and in the RB. The inspectors verified that health physics technicians were available to respond and
' assist workers should the Small Article Monitor (SAM) alarm. Guidance for the use of the SAM and expected response by the worker to alarms were prominently posted on the front of the instrument door. The inspectors observed workers using the instrument and HP's responding to instrument alarm Personnel Dosimetry. Exoosure Controls. and the ALARA Proaram
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The inspector toured-the health physics facilities. RB (including the i refueling floor), Turbine Building, outside radioactive. material storage areas (RMSAs), radwaste 3rocessing area, and the Unit I drywell health l physics control poin rom records review, the inspector determined that the licensee was tracking and trending personriel contamination events (PCEs). As of May 16. 1998, the licensee had tracked approximately 44 PCEs for the Unit 1 refueling outage, which included both skin and clothing contaminations. In addition, the licensee was also tracking 62 evaluated risk personnel contamination events, which are contamination events where dose is assigned. Of the tracked PCEs, j approximately 18 were in designated clean area The inspector reviewed selected survey records as listed in Procedure OE&RC-0100 Routine /Special Dose Rate Survey, Revision 26, dated July 23, 1997. Attachment 1 of the procedure lists the Normal Minimum Frequency and Area. A review of the records revealed that at least nine of the required radiation surveys (in various plant areas) for March and April, t
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1998 were not performe The inspector informed the licensee that the failure to perform nine procedurally required routine monthly surveys was a violation of TS 6.11.1, which requires, in part, that procedures for personnel radiation protection be adhered to for all operations involving personnel radiation exposure. This violation is identified as VIO 50-325(324)/98-06-09, Failure to Perform Procedurally Required i
Survey The inspector noted that the background radiation level at the site was
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two to three times that of similar plants. The plant background is greatly affected by the amount of Nitrogen-16 (N-16) in the Turbine Building steam lines and other components. The amourit of this N-16 varies directly with the hydrogen injection rate into the primary coolant. As part of a plant ALARA initiative. Unit 2 hydrogen injection had been reduced from approximately 37 standard cubic feet per minute I- (scfm) to approximately 20 scfm to help reduce the background during the Unit 1 outage. Although this initiative reduced the background somewhat, the inspector found that several plant friskers remained between 250 and 300 counts aer minute, making the detection of low level contamination difficult. T1e high background also affected the ability I' of the exit portal monitors to detect low levels of contamination from I personnel passing through them to exit the site. The licensee had l written CRs 98-00383, 98-00426, and 98-00427 dated February 20 and 2 j 1998 to follow up on the elevated background radiation levels and the i potential inability to detect low levels of radioactivity. The l l
inspector discussed the high background with HP management, as well as '
its effect on the plant's exit portal monitors. The inspector also discussed the potential for undetected radioactivity to leave the site on workers' scrubs due to the elevated background dose rate Licensee staff stated that they were evaluating the need for additional shielding 1 to reduce the background radiation on the friskers and exit portal j
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monitors to make the instruments more sensitiv The licensee was 4 informed that this issue would be tracked as an IFI. This item is I I
identified as IFI 50-325(324)/98-06-10. Review the Licensee Resolution of the Elevated and Variations of Background on Friskers and Exit Portal Monitors.
! The inspector discussed Unit 1 outage dose goals, site ALARA goals, and 1-annual exposures with licensee management. The calendar year 1998 site exposure goal had been set at 324 person-rem. At the time of the inspection, the accrued site person-rem was about 239 person-rem. The
, Unit 1 outage dose goal was 205 person-rem with approximately 197 l person-rem measured as of May 19, 1998. This outage personnel dose was l the lowest person-rem oose to date for a refueling outage at Brunswic The inspector also found that the organizational structure and l individual responsib111 ties for the ALARA staff members were clearly define _ _ - _ _ -
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37 Conclusions
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Radwaste material was labeled in accordance with requirements and appropriately stored. Radiation and High Radiation Areas were properly 1
)osted and controlled. Personnel dosimetry devices were worn properly
]y workers. Contamination control was effective in containing high levels'of contamination in appropriate areas. The inspector identified one violation for a failure to perform nine radiation surveys. In l addition, the plant's high background dose rates called into question the sensitivity of radiation survey instruments and exit portal monitors and resulted in the opening of an Inspection Followup Ite R1,2 Miscellaneous Radietion Protection and Chemistry Issues Insoection Scone (83750)
Licensee records and files showing the radiation dose for individual !
members of the public were reviewe Requirements are in 10 CFR l 20.1301. 10 CFR 20.1302 and 10 CFR 20.210 ' Observations and Findinas The inspector reviewed the data to evaluate whether a member of the public could exceed the 10 CFR 20 limits from onsite exposure. The inspector determined that controls had been established to ensure that licensee and site visitor exposures were controlled and evaluate Postings at various plant locations reminded staff and visitors of their dosimetry and access requirement During walkdowns, the inspector did not observe any individuals without dosimetr )
The inspector reviewed the actions taken to close CR 98-00037. dated January 9. 1998, and also reviewed the response to action item task ID (1). The inspector found that the area outside of the protected area but inside the owner controlled area is periodically patrolled by the site security force, which has the authority to remove unauthorized persons in this area. Use of the controlled area for recreational purposes is limited to fishing by badged employees. The licensee had calculated a worst-case scenario that an individual would have to be present for 62.4 minutes / day every working day of the year at the erst ,
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location (400 pR/ hour) to receive 100 mr/ year. The inspector reviewed l and evaluated the assumptions used in this analysis, as well as the Area i TLD Monitoring results for 1997 and the first two quarters of 1998, and
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concurred that licensee actions adequately restricted members of the general public so that their doses would be much lower than the worst-case scenario and therefore would meet the 10 CFR 20 regulatory requi rement :______ .__ __ _
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38 o C_onclusions The licensee met regulatory requirements for limiting radiation dose to individual members.of t* public as promulgated in 10 CFR 20.1301.1302 and maintained sufficia information in records required by 10 CFR 20.210 R1.3 Airborne Radioactivity Durina Unit 1 Shutdown Inspection Scope (71750)
The inspector reviewed the actions taken upon indications in the Unit 1 Control and Turbine Buildings of a airborne radioactivity concentration of greater than 0.25 Derived Air Concentration (DAC) during shutdown activities which began-the Unit 1 planned refueling outag J Observations On April 25. 1998, during the 6:30 am meeting to update the status of the Unit I refueling outage. the licensee announced that a sample taken in the Unit 1 Turbine Building measured 0.27 DAC due to iodine isotope The inspector discussed the results and the compensatory measures to be 3
taken with the licensee at that time. The licensee indicated that the increased airborne radioactivity was expected, that the area had been posted, that access to the Unit 1 Breezeway and the Turbine Building (TB) was restricted. and that additional samples would be taken. The Breezeway is a section of the Control Building which connects the RB and the TB, and provides the primary means of egress from both building !
The inspector proceeded to the door of the Unit 1 Breezeway and observed a posting through the window of the door indicating that the area was an-airborne radioactivity area. Plant workers attempting to enter the Breezeway were observed to obey the posting. However, at 6:55 am, the .
ins)ector observed five individuals exiting the Unit 1 Breezeway. The I worcers informed the inspector that the airoborne radioactivity limit on their RWPs was 0.25 DAC, that they had not seen any posting in the breezeway indicating an airborne hazard, and that they were unaware that I the breezeway had been designated as an airborne radioactivity area by i the plant. In addition. the workers indicated that no announcement over ,
the plant paging system had been made to notify workers of the airborne !
hazard or of alternative means to exit the Unit 1 RB. since their RWPs did not allow entrance into a posted airborne area. The inspector reviewed the worker RWPs and confirmed that the airborne concentration limit was 0.25 DAC.
L The ins)ector proceeded to the Control Room around 7:00 am and discussed
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these observations with the Unit 1 Senior Reactor Operator (SRO). The SR0 contacted Health Physics, who informed the SR0 that a sample indicated a level of 0.27 DAC for iodine in the Unit 1 Breezewa Section 9.1.8 of HPS-NGGC-0003 required posting of airborne areas at concentrations greater than or equal to 0.25 DAC. The inspector noted, after review of the sample results. that the total DAC level was 0.2946
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with 0.27 OAC attributed to iodine. At 7:15 am, an announcement was made over the plant paging system that access was restricted to the Unit 1 TB and Breezeway, and that egress from the Unit 1 RB was through the 50 ft. elevation airloc By 8:40 am, samples taken indicated a DAC of 0.0817 DAC and access to the Unit 1 TB and Breezeway was restored.
} The licensee indicated that the initial sample was taken as a result of an alarm from a continuous air monitor (CAM) located in the Unit 1 Breezeway directly across from the primary site dress-out area at around 3:45 am on April 25, 199 Despite indications of elevated iodine from the CAM and the sam)le, the Health Physics (HP) Supervisor did not notify the Control Room of elevated iodine in the Breezeway. The licensee indicated that the HP Supervisor was not confident of the results due to the sample duration time, despite the sample being taken in accordance with Environmental and Radiation Control 0E&RC-12 Routine /Special Airborne Radioactivity Survey. The inspector questioned the licensee concerning notification of the Control Room, timely entrance into Abnormal Operating Procedure 0A0P-5.0. Radioactive Spill High Radiation, and Airborne Activity, and notification of plant
} personnel of the change in posting for an area used for primary egress from the Reactor. Control and Turbine buildings. The licensee indicated that the notification of plant personnel was not timely, the necessity of entering into 0A0P-5.0 would be reviewed, and a CR would be initiated. The inspector verified that CR 98-975. OE&RC-0120. was initiated to address the inspector's observation regarding the timeliness and appropriateness of the actions taken in response to this even The inspector reviewed 0A0P-5.0. OE&RC-0120, Nuclear Generation Group Procedure HPS-NGGC-0003. Radiological Posting. Labeling and Surveys: and the applicable operator logs. E&RC procedure OE&RC-120 was determined by the inspector to be inadequate. This determination was made due to the lack of guidance for the communication of abnormal sample results for the Turbine and Control Buildings. The inspector noted that the procedure did require communication of abnormal sample results if taken from the RB. In addition, the inspector observed no tie between the OE&RC-120 procedure and 0A0P-5.0. Prompt communications with the Control Room would have given the operators adequate time to assess the need to take actions in accordance with 0A0P-5.0. 0A0P-5.0 contains actions to prevent the spread of high airborne activity including the evacuation of unnecessary personnel, the control of access to the affected area, and the securing of ventilation for the are The inspector noted that the operational guidance in 0A0P-5.0 was not taken for almost 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> until prompted by the inspector. The inspector located applicable entry condition (s) into 0A0P-5.0 in Section Symptom Symptom 6 was the alarming of a CAM and Symptom 7 was
"[r]outine surveys indicate high radiation. contamination and/or airborne activity." Subsequent discussions with Operations personnel indicated that had the change in the airborne levels been communicated during the condition. 0A0P-5.0 would probably have been entered. TS 6.8.1.a. requires that written procedures shall be established, implemented, and maintained covering the activities in Appendix "A" of I
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Regulatory Guide (RG) 1.33. November 197 RG 1.33 requires procedures for abnormal releases of reactivity. The failure of procedure OE&RC-0120 to require appropriate action when a CAM alarmed and survey results indicated abnormal airborne levels, is a violatio This violation is identified as the first example of VIO 50-325(324)/98-06-12. Failure To Properly Implement and Establish Abnormal Airborne Guidance.
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In revier of this event, the inspector questioned the licensee's root
! cause determination that the HP Supervisor's lack of confidence in the initial sample results was the reason for the delay in reporting the results. Additional inspector questioning of the HP personnel involved revealed that the HP su)ervisor was aware that the sample taken was greater than 0.25 DAC. Jut did not notify the Control Room upon the CAM alarm, or initial count result In addition, after sending the sample to Chemistry to be gamma scanned (in accordance with E&RC-0120), the results of that scan were not promptly communicated by Chemistry to the appropriate personnel. The inspector determined that as a result of inadequate communications by several individuals, approximately three hours from the initial alarm passed before Operations was notifie TS 6.8.1.a requires that written procedures shall be established, implemented, and maintained covering the activities in Appendix "A" of Regulatory Guide (RG) 1.33. November 197 RG 1.33. requires procedures for surveys and monitoring. Due to the lack of guidance for the determination and timely communication of abnormal sample results, areas where not promptly posted as airborne areas in order to notify affected personnel of the abnormal airborne concentrations. The licensee failure to properly establish those actions required to be taken, when abnormal airborne activity was identified as a result of a survey was identified as a violation. This violation is identified as the second example of VIO 50-325(324)/98-06-12. Failure To Implement and Establish Abnormal Airborne Guidanc Conclusion The licensee failed to take prompt action when a continuous air monitor and an additional sample indicated abnormal airborne activity. As a result, five workers were present in an area of airborne radioactivity levels greater than 0.25 DAC, without appropriate RWPs. A violation was issued for the failure to properly implement and establish procedures that outlined those actions to be taken in the event of survey results indicating abnormal airborne activit R1.4 Health Physics Resoonse to Scram Discharae Volume Leak Insoection Scope (71750)
The inspector observed Health Physics personnel respond to a several-gallon leak from the Scram Discharge Volume (SDV) header on May 26, 199 _ __ _ _ _ Observations and Findinas The inspector observed Health Physics personnel establish a contaminated area. including pestings, and respond to contaminated water which sprayed out of a flange connection located on the SDV header in the Unit 1 RB located on the 20 foot elevation. The leak occurred during a Unit 1 scram. Health Physics personnel were already present at the scene taking routine radiological surveys during the scram when the leak occurre The inspector noted prompt response to the leak by personnel, including setup of a contaminated area, as well as donning of protective clothing to clean up the spill. The inspector reviewed the radiological survey results and paperwork. including atmospheric air sample results, and found no deficiencies. The inspector found the plant response to be satisfactory to this event. The inspector determined that this event was not repo-table and the SDV remained operabl The leaking flange was subsequently repaire Conclusions The inspector found the Health Physics response to a SDV header leak of several gallons to be satisfactor P1 Conduct of EP Activities Pl.1 Brunswick Hurricane Preparations Inspection Scooe (71750)
During this inspection period the inspector reviewed the status of hurriccne preparations at the Brunswick sit Observations and Findinas The inspector reviewed Plant Emergency Procedure (PEP) PEP-02.6. Severe Weather: PEP- 02.1. Initial Emergency Actions: Abnormal Operating Procedure (AOP) 0A0P-13.0 Operation During Hurricane, Flood Condition Tornado or Earthquakes; and Administrative Instruction (AI) 0AI-6 Brunswick Nuclear Plant Response to Severe Weather Warning The inspector reviewed TS 3/4.7.3 Flood Protection and section 3.4.1 of UFSAR, Protection from external flooding. These reviews were conducted to verify Brunswick's preparedness for hurricane season and to verify that the procedures were current after last years hurricane seaso l The inspector found that the procedures were current. 0AI-68 was the only procedure that had not been revised within the last six months. but was in the process of revision and was to be implemented soon. The licensee had ordered more sandbags, which would allow them to have more than the procedurally required 700 bags, at the time of this revie The licensee sponsored severe weather meetings with other utilities to enhance their preparedness and others as well.
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The inspector discussed hurricane simulator training exercises with Brunswick training aersonnel. The inspector noted that hurricane simulator training lad not occurred since 1996. Brunswick severe weather procedures only required that hurricane simulator training occur just prior to a hurricane hitting the area. The simulator training department informed the inspector that they were going to schedule a hurricane training exercise for all of the control room watch teams to occur on crew training weeks and that ali of the crews would have the exercise by the August time frame.
i The inspector noted that required preventive maintenance had occurred on flooding protection components. A visual inspection of flood protection doors found no deficiencies. The inspector noted that temporary sump pumps were installed at the site storm drain basin to assist in water removal during severed weather. This was implemented as a lesson learned from previous hurricane experience Conclusions The inspector found that the licensee was continuing to revise their severe weather procedures to keep current. The inspector noted that severe weather preparations were being implemented during the inspection period such as ordering sand bags and staging temporary storm drain pump F1 Control of Fire Protection Activities F1.1 Aooendix R Staffina Insoection Scoce (71750. 71707)
The inspector reviewed the adequacy of site staffing for those positions required to safely shutdown either unit in the event of a fire as required by 10 CFR 50 Appendix b. Observations and Findinas On April 20. 1998, during routine review Of the operating logs, the inspector noted that a fire protection impairment had been initiated due the absence of the outside auxillary operator (AO). This A0 had been sent approximately 30 minutes away to Caswell Beac Caswell Beach is the location of the non-safety related Circulating Water Ocean Discharge (CWOD) pumps. The inspector reviewed the operating logs for the periods from March 15 to April 21, 1998 and identified six separate occasions where Alternate Safe Shutdown (ASSD) minimum staffing was not me Date _ Time Imoairment March 27 -28 11:58 pm - 3:17 am 98-361 l April 3 12:36 am - 5:10 am 98-384 April 18-19 8:24 pm - 7:00 am 98-455 April 19 10:30 am - 1:40 pm 98-456
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April 19 2:40 pm - 3:33 pm 98-457 April 20-21 9:02 pm - 7:34 am 98-462 The inspector requested copies of the ASSD staffing roster which was Attachment 1 to Alternate Safe Shutdown Procedure OASSD-00. User's Guide, for the dates indicated above. The licensee provided copies of the staffing rosters for the night shift on April 3 and 18 and the day and night rosters for April 19. The rosters for April 3 and 18 during the day and March 27-28. 1998. were not able to be locate Subsequently the licensee initiated CR 98-1006. Missing records, which determined that "not all of the comaleted rosters" could be locate These records were " identified in t1e hequired Records List database as a OA document with a retention period of 5 years. (Ref. 0AP-009)." The inspector reviewed Administrative Procedure 0AP-009, Records Management Program, and the Required Records List and verified that Attachment 1 to 0ASSD-00 was required to be retained as a Quality Assurance (0A)
document for five years. Nuclear Generation Group Manual NGGM-PM-000 Quality Assurance Program Manual, required in section 15.15 that
"[t] hose records required to verify compliance with criteria of the Fire i Protection Program shall be identifiable and retrievable and shall be l assigned retention requirements". The failure to maintain Attachment 1 to 0ASSD-00 for March 27-28. April 3 and 18, 1998, during the day was a violatio This violation is repetitive in that similar deficiencies were identified in NRC IR 50-325(324)/97-13 and were cited in VIO 50-325(324)/97-13-01. Failure to Retain TS-Required 0A Records. This violation is identified as VIO 50-325(324)/98-06-13. Failure to Retain ASSD Roste The inspector questioned the appropriateness of initiating an impairment for the failure to meet requirements. The licensee stated that the impairments were acce within in two hours. ptable in the event The licensee that staffing indicated that thiswas position not restored was consistent with Plant Program Procedure OPLP-1.5. Alternate Shutdown Capability Controls. The inspector reviewed OPLP-1.5. 0ASSD-00, the UFSAR. Generic Letter (GL) 86-10, and the A)ril 6,1979, supplement to an NRC Safety Evaluation Report dated Novem)er 22. 1977. Section 6. of 0ASSD-00 stated that "[t]he ASSD staffing composition may be less than_the minimum requirements for a period of time not to exceed two hours in order to accommodate unexpected absence of on-duty shift crew members 3rovided immediate action is taken to restore requirements to within t1e minimum requirements of the Shift ASSD Staffing Roster. If the ASSD staffing composition is not restored to within the minimum required in two hours establish an Alternative Safe Shutdown Impairment in accordance with PLP-1.5. Alternative Safe Shutdown Cenability Controls, and FPP-020, System Impairment Notification." Out of six '
impairments identified by the inspector, only Impairment 98-361 met this criteri Impairment 98-361 was initiated when a unit SR0 became il The SR0's position was not filled for approximately three hours. The
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other five were initiated due to either the absence of an A0 to go 30 minutes from the site to Caswell Beach to perform activities rolated to the CWOD pumps or were attributed to "manpowor shortages " none of the impairments indicated an unexpected absence or immediate actions to o .-. _ - - _ _ _ _ _
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l restore minimum staffing requirements within two hours. The inspector determined that of the six impairments. the licensee had filled the vacant ASSD position within two hours only once (Impairment 98-457).
TS 6.8.1.f requires that written ]rocedures shall be established, implemented, and maintained for t1e Fire Protection Program. On five separate occasions identified by the inspector on the following dates:
April 3. A)ril 18-19. and April 20-21. 1998, the licensee failed to maintain t1e minimum staffing requirements. The failure to maintain minimum staffing requirements in accordance with 0ASSD-00 is a violation. This violation is the first example of violation VIO 50-325(324)/98-06-14 Failure To Maintain Adequate Appendix R Staffin Conclusion Staffing for ASSD procedures was not implemented in accordance with procedures. The failure to maintain adequate ASSD staffing was identified as a violation. A violation was identified for the inability to locate documents requested during this inspectio F3 Fire Protection Procedures and Documentation F3.1 Adecuacy of ASSD Procedure Insoection Scone (71750)
The inspector performed a review to determine the adequacy of the guidance provided in Alternate Safe Shutdown Procedure OASSD-00, with the requirement in 10 CFR 50. Appendix R.Section III.L. 10 CFR 50 Appendix R.Section III.L.4 requires equipment and systems be capable of maintaining hot shutdown / standby until cold shutdown can be achieved in the event of damage from fire. The number of operating shift, personnel, exclusive of fire brigade members, required to operate such equipment shall be on site at all time Observations and Findinas Section 6.1 of 0ASSD-00 stated that '[t]he number of operativ shift personnel. ' exclusive of fire brigade members. Required to opM ate safe shutdown equipment and systems shall be on site at all times (10CFR5 Appendix R. L.4)." However. Section 6.3.5 of 0ASSD-00 stated that
"[t]he ASSD staffing composition may be less than the minimum requirements for a period of time not to excee1 two hours in order to accommodate unexpected absence of on-duty shift crew members 3rovided immediate action is taken to restore requirements to within t1e minimum requirements of the Shift ASSD Staffing Roster. If the ASSD staffing composition is not restored to within the minimum required in two hour establish an Alternative Safe Shutdown Impairment in accordance with OPLP-1.5. Alternative Safe Shutdown Capability Controls. and FPP-020 System Impairment Notification.~ OPLP-1 5. includes personnel as ASSD equipmen Section 6.1.3.1 requires the restoration of unavailable equipment within 14 day ___ _ _
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As a result of the nonconformances identified in Section F1.1 of this report the licensee performed a cursory review of the fire protection impairments from January through April of 1998. The licensee identified 10 instances in addition to those identified by the inspector, where impairments were used when minimum staffing requirements where not me Due .to inconsistencies in the method that the impairments where maintained, the actual duration and the reason for many of the impairments could not be discerned. Some impairments indicated minimum staffing was not met due to a " manpower shortage."
The inspector reviewed the applicable 3rocedures, regulatory requirements including GL 86-10 all t1e fire impairments for 1998, Inspection Report 50-325(324)/89-10 which reviewed the licensee's compliance to Appendix R. and reviewed the operator logs for 1998. The inspector confirmed the 10 additional instances identified by the licensee. The inspector noted that most of the impairments indicated that ASSD staffing was permitted to be less than required for 14 day The inspector determined that the guidance provided in Section 6.3.5 of 0ASSD-00 was contrary to the requirements of 10 CFR 50, Appendix R, Section III.L.4, in that minimum staffing requirements were permitted by 0ASSD-00 and OPLP-1.5 to be less than required for 14 day TS 6.8.1.f requires that written 3rocedures shall be established, implemented, and maintained for t1e Fire Protection Program. 10 CFR 50 Appendix R.Section III.L.4 requires equipment and systems be capable of maintaining hot shutdown / standby until cold shutdown can be achieved in the event of damage from fire. The number of operating shift, personnel, exclusive of fire brigade members, required to operate such equipment shall be on site at all times. OPLP-1.5, section 6.1. permitted personnel needed for the performance of alternate safe shutdown activities to be unavailable for 14 days before any actions were taken. The failure to properly establish and maintain fire protection requirements in accordance with regulatory requirements is a violation. This violation is identified as the second example of 50-325(324)/98-06-14 Failure To Maintain Adequate Appendix R Staffing, c. Conclusions The procedures for maintaining minimum staffing for ASSD during a fire were determined to be inconsistent with the 10 CFR 50 Appendix R. 10 CFR 50 Appendix R. required that all persnnel required for ASSD be onsite at all times. The procedures for ASSD staffing allowed less than minimum staffing for 14 days. A violation was issued for the failure to proprly establish fire protection procedures in accordance with 10 CFR 50 Appendix _-_--_-- --__-- __ - - - _-__ -
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F8 Miscellaneous Fire Protection Issues F (Closed) Violation VIO 50-325(324)/97-11-01: Failure to' Initiate ASSD Impairmen During inspection activities discussed in IR 50-325(324)/97-11. the inspector noted the inoperability of the breaker handle for the 1-E11-
- F006A. Residual Heat Removal (RHR) Pump 1A Shutdown Cooling Suction valve, The inspector determined that the valve was -required for ASSD
]rocedures and should have been under a fire, protection impairmen Review of the impairments, revealed that an impairment had not been issued. The failure was identified as a violation. The licensee responded to this violation issued in IR 50-325(324)/97-11. in a letter dated November 26. 1997, and again on January 30, 1998. The January 30, 1998. reply stated that the applicable procedure and computer database were adequate to determine ASSD ecuipment operability. The licensee
, determined that inadequate knowlecge of the ASSD procedure by the on-shift personnel instead of procedural inadequacy contributed significantly to this event.
l The inspector reviewed both violation responses, the associated CR. and
! -root cause analysis. The inspector concurred that inadequate knowledge l concerning the ASSD program was a significant contributor to this event.
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Based on adequate completion of those actions prescribed, this item is close SI- Conduct of Security and Safeguards Activities S1.2 Access Authorization (AA)
a-. Insoection Scooe (81700)
' The inspector verified that the licensee had adequate procedures for the
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review of a denial ~or revocation for unescorted access authorizatio The inspector verifled that procedures provided for an employee to be informed of the grounds for access denial or revocation. The inspector reviewed procedures-that allowed an employee an opportunity for'an objective review-of the information on which access denial or revocation was base Observations and Findinas I- The ins thatth!ectorreviewedAArecordsofselectedindividualstodetermine licensee had adequately implemented the AA requirements which ;
. ensured that individuals who were granted unescorted access were trustworthy, reliaale, and did not constitute an unreasonable risk to .
the health and safety of the publi The requirement for the licensee *.s AA program were set forth in 10 CFR 73.56. In publishing the Access Authorization Rule (AAR)(56 Federal Register 1997, April 25. 1991). the NRC stated that the rule did not preclude a licensee from denying access to an employee for reasons other a I
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than those addressed in the AAR and that the ultimate responsibility for-granting unescorted access rested with the licensee, provided NRC requirements were me '
'10'CFR 73.56(e) requires, "Each licensee implementing an unesco'rted AA program under the provisions of this section shall include a procedure for the review, at the request of the affected employee, of a denial or revocation by the licensee of unescorted access authorization of an employee of the licensee, contractor, or vendor, which adversely affect employment. The procedure must provide that the employee is informed of'
the grounds for denial or revocation and allow the employee an opportunity to provide additional relevant information, and provide an opportunity for an objective review of the information on which the denial or. revocation was based."
The' licensee implemented 10 CFR 73.56 through several procedure Standard Procedure, SEC-NGGC-2101, Nuclear Worker Screening Program For Unescorted Access, Revision 5 dated November 15, 1996. Paragrap .10.1, requires. "The worker will be informed of the basis for denial or revocation of unescorted access authorization." The same procedure in paragraph 9.10.2 requires. "The worker must submit a request for review in writing to the Access Authorization Program Administrator through Plant Access Authorization within 15 working days of the initial denial or revocation or within 15 working days of the receipt of a certified letter of notification from Plant Access Authorization."
Additionally, Carolina Power and Light Company Procedure. NGGS-SEC-101 Denial of Unescorted Access. Revision 0, dated June 30, 1997, Paragraph 9.1, requires. "When a nuclear worker is denied unescorted access. interview the worker and _ review interview findings with CAA."
Adjudication guidelines are contained in Denial Criteria for Unescorted
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Access Authorization in SEC-NGGC-2101. Nuclear Worker Screening for Unescorted Acces During the May 14. 1998. visit to the Corporate Security Office to review AA appeal cases. the inspector noted that the licensee had fully described in the appeal letter to the employee the specific cause for proposing denial of unescorted access. In one other case the licensee
- did not provide adequate information for an appeal. The inspector determined: however, that- the information to justify denial in accordance with the licensee's procedures, was made available to the individual during the process of completing the second Personal-History Questionnaire and through subsequent discussion with the licensee's
- investigator. Additionally, the licensea's records revealed that the l .individualfwas made' aware of the cause 1 r denial during subsequent L ' telephone conversations with the Corporate AA staff. Also, the L licensee *s records indicated that the employee requested information H
concerning the reason for access denial and that the information had been provided to the individual by facsipile on the same day as requeste During review of the other appeal letters detailing the reason for a denial, the inspector noted that sufficient information was provided to' enable an individual the opportunity to appeal. The single case in which sufficient details were not provided to the employee, d
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appears to be an anomaly, and based on the information available. the individual was aware of the licensee's concern prior to departing the sit c. Conclusions Based on review of the AA procedures and records the inspector determined that the licensee had established adequate procedures for the review of a denial or revocation by the licensee for unescorted access authorization. The procedure also provided for an employee to be informed of the grounds for denial or revocation and allowed an employee an opportunity for an objective review of the information on which the denial or revocation was base V. Manaaement Meetinas XI Exit Meetina Summary
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The inspector presented the inspection results to members of licensee management at the conclusion of the inspection on June 12. 1998. Post- .
inspection briefings were conducted on May 1. 8.12. and 22.1998. The licensee acknowledged the findings presente J j
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PARTIAL LIST OF PERSONS CONTACTED Licensee G. Attarian, Manager. EQ Task Force A. Brittain Manager Security M. Christinziano. Manager Environmental and Radiation Control W. Dorman. Supervisor Licensing and Regulatory Programs
, N. Gannon, Manager Maintenance J. Gawron, Manager Nuclear A.ssessment Section S. Hinnant, Vice President. Brunswick Steam Electric Plant L. Illy, EQ Technical Advisor, Design Control K. Jury, Manager Regulatory Affairs B. Lindgren. Manager Site Support Services J. Lyash, Plant General Manager S. Melton Manager, Design Control G. Miller. Manager Brunswick Engineering Support Section R. Mullis. Manager Operations S. Tabor . Regulatory Affairs Other licensee employees or contractors included office, operation, maintenance, chemistry, radiation, and corporate personnel l
NRC i E. Brown J. Coley E. Guthrie J. Lenahan N. Merriweather C. Patterson !
E. Testa '
O. Thompson j I
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INSPECTION PRDCEDURES USED IP 37550: Engineering IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensee Controls in Identifying. Resolving. and Preventing Problems IP 62003: Inspection of Steel and Concrete Containment Structures IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 73753: Inservice Inspection IP 81700: Physical Security Program for Power Reactors IP 83750: Occupational Radiation Exposure IP 92901: Followup - Operations IP 92902: Followup - Maintenance IP 92903: Followup - Engineering ITEMS OPENED. CLOSED, AND DISCUSSED Coened 50-325(324)/98-06-01 IFI Multiple Failures of SSFPC (Section 02.5)
50-325(324)/98-06-02 NCV Missed Operator Rounds (Section 08.1)
50-325(324)/98-06-03 URI Configuration Control of Maintenance and Test Activities (Section M4.1)
50-325/98-06-04 NCV Out of Calibration Roof Vent Gas Activity Monitor (Section M8.4)
50-325(324)/98-06-05 IFI Repair of RTD Drain Wires (Section E1.3)
50-325/98-06-06 VIO Intent Change Established as Temporary Change (Section E4.1)
50-325(324)/98-06-07 IFI Generic Issue Resolution of Containment Pressure Suppression Bypass (Section E8.2)
50-324/98-06-08 NCV Core Spray System Minimum Flow Bypass Valve Inoperability (Section E8.4)
50-325(324)/98-06-09 VIO Failure to Perform Procedurally Required Surveys (Section R1.1)
50-325(324)/98-06-10 IFI Review the Licensee Resolution s the Elevated and Variations of Background on Friskers and Exit Portal Monitors (Section R1.1)
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50-325(324)/98-06-11 URI Evaluation of Detection of Fe-55 Concentrations or Quantities of Radioactive Material and Calibrate Instruments for Radiation Monitored (Section R1.1)
50-325(324)/98-06-12 VIO Failure To Properly Implement and Establish Abnormal Airborne Guidance (Section R1.3)
50-325(324)/98-06-13 VIO Failure to Retain ASSD Roster (Section F1.1)
' 50-325(324)/98-06-14 VIO Failure to Maintain Adequate Appendix R Staffing (Sections F1.1 and F3.1)
Closed 50-325(324)/98-06-02 NCV Missed Operator Rounds (Section 08.1)
50-325(324)/96-08-01 DEV Failure to Complete Maintenance Procedure Backlog (Section M8.1)
50-325/97-13-03 VIO Failure to Note Abnormal TS Surveillance Values (Section M8.2)
50-325/98-001-00 LER Reactor Building Roof Vent Noble Gas Activity Monitor Surveillance Deficiency (Section M8.4)
50-325/98-06-04 NCV Out of Calibration Roof Vent Gas Activity Monitor (Section M8.4)
50-325/97-13-00 LER Reactor Core Isolation Cooling System Procedure Inadequacy (Section E8.1)
50-325(324)/97-011-00 LER Simultaneous Drywell and Suppression Chamber Valve Lineups Result in Unanalyzed Pressure Suppression Bypass Flow Path (Section E8.2)
50-325(324)/97-15-04 VIO No CRs for 'iant Process Computer Failures (Section E8.3)
50-324/97-002-00 LER Core Spray System Minimum Bypass Flow Motor Operated Valve Inoperability (Section E8.4)
50-324/98-06-08 NCV Core Spray System Minimum Flow Bypass Valve Inoperability (Section E8.4)
50-325(324)/97-09-01 VIO Failure to Consider EQ Requirements in Engineering Evaluations (Section E8.5)
50-325(324)/97-09-03 VIO Deficiencies in Preparation of Qualification Data Packages (Section E8.6)
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50-325(324)/97-13-16 IFI Revisions to Procedure EGR-NGGC-0153 (Section E8.7)
50-324/96-15-05 EEI Operation In Excess of Licensee Thermal Power Limit (Section E8.8)
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50-325(324)/97-12-07 EEI Failure to Take Corrective Action for High Drywell Temperatures and Torus Bypass (Section E8.9)
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50-325(324)/97-12-09 EEI US0 on Spent Fuel Cask Movement (Section E8.10)
50-325(324)/97-11-01 VIO Failure to Initiate ASSD Impairment (Section F8.1)
Discussed 50-325(324)/96-15-04 IFI Material Condition of Remote Shutdown Panels (Section M8.3)
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SYNOPSIS
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The U.S. Nuclear Regulatory Commission, Region II, Office of Investigations, initiated this investigation on September 24, 1997, to determine if a Carolina
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Power and Light Company Brunswick Steam Electric Plant employee deliberately
,," failed to perform an inspection of the diesel generator building as required by procedures. Additionally, this investigation was initiated to determine if this employee deliberately falsified the inspection repor The evidence developed during this investigation substantiated that this employee deliberately failed to perform the inspection of the diesel generator building as recuired by procedures. Specifically, this employee failed to inspect the 4-cay tank room and the diesel generator basement. Also, this individual deliberately falsified the inspection report, claiming those ereas had been inspecte I i
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p gp pcca wqcet M 8 WOT FOR PUOLlC OlCCLOCURE WlTllOUT APPROVAL Or riELO OrriCE Ol RECTOR, OIIlCE Or lNVESTlGATIONG, REGION li--
Case No. 2-97-024 1 Enclosure 3
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