IR 05000324/1981002
| ML19347E831 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 03/11/1981 |
| From: | Dante Johnson, Julian C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML19347E827 | List: |
| References | |
| 50-324-81-02, 50-324-81-2, 50-325-81-02, 50-325-81-2, NUDOCS 8105130465 | |
| Download: ML19347E831 (14) | |
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O[ *s u ireosrares 7, -
NUCLEAR REGULATORY COMMISSION g
a REGION 11
101 MARIETTA ST., N.W., SUITE 3100 g
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o ATLANTA, GEORGIA 30303
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Report Nos. 50-324/81-02 and 50-325/81-02 Licensee: Carolina Power and Light Company 411 Fayetteville Street Raleigh, NC Facility Name: Brunswick Docket Nos. 50-324 and 50-325 License Nos. DPR-62 and DPR-71 Inspection at Brunswick site near Wilmington, NC Inspector:
f-h D. F. JohMon, Senior Rg61 dent Inspector Date Signed Approved by:[ '
, Acting Section Chief, RRPI Division M88 C. Jul tah Date Signed SUMMARY Inspection on January 1-31, 1981 Areas Inspected This routine inspection involved 156 resident inspector-hours on site in the areas of plant operations; operational safety verification; observation of physical security; review of operational events; observation of an emergency drill; review of monthly reports; followup on headquarters requests; followup on IEB's; plant tours; and independent inspection effort.
Results Of the 10 areas inspected, no violations or deviations were identified in 9 l
areas; 2 violations were found in one area (Failure to adhere to Technical Specification Limiting Condition for Operation and appropriate action statements, paragraph 7.b; Failure to submit a timely written report, paragraph 7.c.)
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DETAILS
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1.
Persons Contacted Licensee Employees D. Allen, QA Supervisor J. Brown, Manager, Operations
- C. Dietz, Gene:al Manager, Brunswick L. Eury, Vice President, Power Supply B. Furr, Vice President, Nuclear Operations Department J. Jones, Senior Executive Vice President and Chief Operating Officer M. Hill, Maintenance Manager R. Morgan, Plant Operations Manager D. Novotny, Security Specialist G. Oliver, E & RC Manager A. Padgett, Director of Nuclear Safety R. Pasteur, E & C Supervisor R. Poulk, Regulatory Specialist
- A. Tollison, General Manager, Brunswick (Former)
L. Tripp, RC Supervisor W. Triplett, Administrative Supervisor W. Tucker, Technical and Mministrative Manager E. Utley, Executive Vice President, Engineering and Construction L. Wagoner, Engineering Supervisor Other licensee employees contacted included numerous technicians, operators, security force members and office personnel.
- Attended exit interview 2.
Exit Interview The inspection scope and findings were summarized on February 2,1981, with those persons indicated in Paragraph 1 above. Meetings were held with senior facility mansgement periodically during the course of this inspection to discuss the inspection scope and findings.
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3.
Licensee Action on Previous Inspection Findings Not inspected.
4.
Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable or may involve noncompliance or deviations.
New unresolved items identified during this inspection are discussed in paragraphs 7 and 9.
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5.
Review of Plant Operation - Plant Inspections a.
The inspector reviewed plant operations through direct inspection and observation throughout the reporting period. The following areas were inspected:
(1) Control Room (Daily)
(2) Service Building (3) Turbine Building (4) Radwaste Facility (5) Diesel Generator Rooms (6) Intake and Discharge Canals (7) Reactor Buildings (8) Vital Switchgear Rooms (9) Control Points (10) Site Perimeter-(11) Physical Security (12) Service Water Buildings
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b.
The following determinations were made:
Monitoring instrumentation: The inspector verified that selected
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. instruments were functional and demonstrated parameters within
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Technical Specification limits.
Valve positions. The inspector verified that selected valves were
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in the position or condition required by Technical Specifications for the applicable plant mode. This verification included control board indication and field observation of valve position (Safeguards System)
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Radiation Controls. The inspector verified by observation that
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control point procedures and posting requirements were being followed. The inspector identified no failures to properly post radiation and high radiation areas.
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Plant housekeeping conditions. Observations relative to plant housekeeping identified no unsatisfactory conditions.
Fluid leaks. No fluid leaks were observed which had not been
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identified by station personnel and for which corrective action had not been initiated, as necessary.
Piping vitration. No excessive piping vibrations were observed
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and no adverse conditions were noted.
Control room annunciators. Selected lit annunciators were
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discussed with control room operators to verify that the reasons for them were understood and c~
,etive action, if required, was being taken.
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By frequent observation through the inspection, the inspector
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verified that control room manning requirements of 10 CFR 50.54(k)
and the Technical Specifications were being met. In addition, the inspector observed shift turnovers to verify that continuity of system status was maintained.
The inspector periodically questioned shift personnel relative to their awareness of plant conditions.
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Technical Specifications. Through log review and direct
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observations during tours, the inspector verified compliance with selected Technical Specification Limiting Conditions for Oparation.
Security. During the course of these inspections, observations
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relative to protected and vital area security were made, including access controls, boundary integrity, search, escort, and badging.
No notable conditions were identified.
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No unacceptable conditions were identified.
6.
Plant Transients During the period of this report a followup on plant transients was conducted to determine the cause; ensure that safety systems and composants functioned as required; corrective actions were adequate; and the plant was maintained in a safe condition.
a.
On August 27,1080, Unit 2 was in startup mode with the reactor in the following conditions:
Critical
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0% Power
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Pressure 4.58 PSIG
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Vessel Level 35"
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Temperature 229 F
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(1) A reactor startup was in progress and at 1610 hours0.0186 days <br />0.447 hours <br />0.00266 weeks <br />6.12605e-4 months <br /> No.1A Control Rod Drive (CRD) Pump tripped. Attempts were made to start the No.
18 CR0 Pump but were unsuccessful due to low suction pressure as a result of a low level in the condensate storage tank (CST) of approximately 10'6".
(2) The reactor was manually ;crannsi by the operator in accordance I
with Emergency Instruction EI-3.4, Inability to Move Control Rods.
(3) CST level at the initiation of the startup had been 11'6".
(4) Water was transferred from the makeup demineral'izer tank (MUD) and l
No. 1 CST to No. 2 CST and the CRD Pump was restarted at
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approximately 1840 hours0.0213 days <br />0.511 hours <br />0.00304 weeks <br />7.0012e-4 months <br /> l
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Review of applicable procedures, drawings and interviews held with
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licensee personnel resulted in the following findings:
Operating procedures were clear and concise;
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Operator's actions were proper and expeditiously initiated, as
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required by procedures;
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Initial evaluation does not indicate any loss of scram capability as a result of this event.
The inspector had no further questions relative to this event.
b.
On December 16, 1980, at 0955 hours0.0111 days <br />0.265 hours <br />0.00158 weeks <br />3.633775e-4 months <br /> with Unit 2 at 76% power, a power reduction was initiated to remove "B" steam jet air ejector (SJAE) from service and place "A" SJAE to full load. Bus No. E-4 tripped due to operator error causing a scram and group I isolation signal due to the loss of an RPS MG set. SJAE's also tripped. The diesel generator started and picked up the E-4 loads. All trips were reset, but the
steam supply valve to the B JAE did not reopen. Recirculation flow
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was ramped to minimum, but due to a slight delay in manually opening
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the steam supply valve to the SJAE, low vacuum tripped the turbine
causing a reactor trip. All systems functioned as designed with no L
initiation of ECCS.
The inspector had no further questions relative to this event, c.
On December 26,1980, at 1026 hours0.0119 days <br />0.285 hours <br />0.0017 weeks <br />3.90393e-4 months <br /> No. 2A reactor feed pump (RFP)
tripped. The unit 2 reactor tripped on low water level, received a group I isolation, and HPCI and RCIC started.
HPCI tripped and isolated on high exhaust pressure. The operators restarted HPCI, carried out emergency procedure EI-31 (Reactor Scram), and regained normal water level. Cause of RFP trip was undetermined, but the cause of the HPCI trip was determined to be presence of a water slug in turbine exhaust line resulting from filling of a steam line drain pot.
The water slug in the HPCI turbine exhaust line resulted in damage to pipe support hangers and snubbers. Increased surveillance of blowdown (
of HPCI and RCIC steam line drain pots was specified on control s
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operators' daily check sheet to preclude recurrence. The HPCI exhaust line was inspected for damage and cracks. Damaged spring hangers and snubbers were repaired and functionally tested.
The RFP was operationally tested and performed satisfactorily. The cause for the trip could not be determined.
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The inspector had no further questions relative to this event
d.
On January 3,1981, a Unit 1 startup was in progress with the reactor at 5% power, reactor pressure at 735 PSIG and No. lA RFP in service.
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Reactor water level increased at a fast rate and No. IA RFP tripped on high level in conjunction with HPCI and RCIC.
Reactor pressure and temperature decreased rapidly, safety relief valve 13G lifted and
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reseated, and pressure went from 717 PSIG to 465 PSIG in four minutes.
At 1946 hours0.0225 days <br />0.541 hours <br />0.00322 weeks <br />7.40453e-4 months <br /> the reactor tripped on low level.
HPCI and RCIC were started manually and water level returned to 60".
Pressure stabilized at approximately 200 PSIG. The unit was cooled down and placed in cold shutdewn for inspection of the safety valve. A faulty pilot valve was identified as the problem. The pilot valve was replaced and the safety valve functionally tested and proved satisfactory. An inspection was performed in the drywell and there was no apparent damage to any of the pipe supports and snubbers surrounding the lifted safety valve.
The inspector had no further questions relative to this event.
e.
On January 7,1981, with Unit 2 at 90% power, No. 2 "A" RFP tripped, the recirculation pumps ranback and reduced power. Level continued to decrease and at 0738 the reactor tripped on low level, A group I isolation occurred, therefore, preventing feeding with the
"B" RFP.
hPCI and RCIC were manually initiated and level returned to normal.
Group I isolation was reset and level control was maintained with the
~"8" RFP. Subsequent investigations could not determine the cause for the "A" RFP trip.
The inspector had no further questions relative to this event.
f.
On January 20, 1981, with Unit 1 at 100% power, reactor water level instrument N0048 was discovered to be reading off scale on the high end with a slowly increasing level on R608.
Reactor water level was increasing with decreasing feed water flow. At 1120 hours0.013 days <br />0.311 hours <br />0.00185 weeks <br />4.2616e-4 months <br /> power was reduced with rec.irculation pumps and rods to approximately 90%. At 1122 hours0.013 days <br />0.312 hours <br />0.00186 weeks <br />4.26921e-4 months <br /> the feed pumps tripped on high level, and at 1144 hours0.0132 days <br />0.318 hours <br />0.00189 weeks <br />4.35292e-4 months <br /> the
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reactor tripped on low level. HPCI and RCIC initiated, to maintain reactor vessel level.
Subsequent investigation revealed that the variable leg to the reactor water level instrumentation was isolated due to the closure of a containment isolation valve in the line. No cause for the valve closure could be found.
The inspector concluded that all appropriate corrective action had been
taken.
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On January 30, 1981, with Unit 1 at 97.7% power, a RFP "A" MGU under-
voltage alarm was received.
"A" RFP tripped, recirculation pumps l
ranback, level continued to decrease and at 0347 hours0.00402 days <br />0.0964 hours <br />5.737434e-4 weeks <br />1.320335e-4 months <br />, the reactor t
tripped on low level. A group I isolation occurred, recirculation l
pumps tripped, HPCI and RCIC initiated and restored level. A faulty trip coil was identified as the cause for the undervoltage condition.
The coil was replaced and the breaker tested and functioned satisfactorily.
The inspector had no further questions reletive to this even.
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7.
Licensee Event Follow-up Through direct observations, discussions with licensee personnel, and review
of records, the following events were reviewed to determine that reportability requirements were fulfilled, immediate corrective actions were accomplished, and actions taken were in accordance with Technical Specification Requirements.
a.
Failure to Continuously Monitor Gaseous Releases to the Environment and Failure to Report and Review an ' Environmental Event.
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(1) On December 22,1980, during the performance of routine weekly-surveillance for inspection and replacement of main off gas vent (st ack) filters,' it was discovered that the-stack monitoring pump was not operating. Subsequent investigation by review of recorder time charts and pump time integrator data, it was determined that the pump had stopped at 1736 hours0.0201 days <br />0.482 hours <br />0.00287 weeks <br />6.60548e-4 months <br /> on December 16, 1980.
Indications available in the control room to detect the loss of the monitoring pump consisted of two audible and visual annunicator alarms, and a dual pen recorder of stack activity.
The inspector's review of applicable records, and interviews held with licensee personnel regarding the above event,-resulted in the following findings:
(a) Recorder readings before, after and during the period of time'
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that the sample pump was inoperable, were readily. discernible
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in the control room, but, operators failed to recognize' the apparent symptoms that indicated problems with the stack activity, i.e., count rates are approximately 450 to 600 counts /second during normal plant operation.
The recorder trace followed a downward trend on December 16, 1980 when Unit No. 2 tripped and again indicated proper operation when Unit 2 returned to service. However, following this event, the dual pen readings decreased to 70 c/s and 10 c/s, respectively, and remained at these extreme low levels for
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several days with no change. Operating instructions require control room operators to initial these readings on a once a
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shift frequency.
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(b) The annunciator alarms associated with the stack sample pump that would have alerted the operators, did not function. The licensee is currently investigating to determine the cause for the inoperable alarms on both Unit 1 and Unit 2.
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(c) On December 22 at approximately 1700 hours0.0197 days <br />0.472 hours <br />0.00281 weeks <br />6.4685e-4 months <br />, canclusive
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l evidence was present to confirm that the sample monitoring
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pump had been inoperable for at least six days, resulting in
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a loss of continuous monitoring capability for gaseous releases from the stack during this period of time.
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licensee did not provide a written report to the NRC, as required, by L. ironmental Technical Specifications, nor was this evant reviewed and evaluated by the Plant Nuclear Safety Committee, as required, by Environmental Technical Specifi-cations.
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(2) On December 15, 1980, at 1119 hours0.013 days <br />0.311 hours <br />0.00185 weeks <br />4.257795e-4 months <br />, during routine surveillance, it was discovered that the particulate filter for the Unit 1 Reactor Building Exhaust Ventilation Monitor,1 CAT-AT-1264 was not installed properly, thereby rendering the monitor inoperable.
An investigation revealed that the particulate filter had not been reinstalled properly during a routine weekly filter replacement at 0836 hours0.00968 days <br />0.232 hours <br />0.00138 weeks <br />3.18098e-4 months <br /> on December 11, 1980, due to a personnel error.
Thi s event resulted in loss of continuous monitoring capability during this period of time.
The inspector veri'ied by review of applicable records' and interviews held with licensee personnel, that during the loss of nionitoring cap-ability in both the events described above, no abnorreal radioactive releases occurred.
f The entire area of monitoring of radioactive gas releases to the environment from the reactor building vent and the main off gas vent (stack) is being reviewed by Region II health physics inspectors. The above apparent violations will be included in their final report.
(Unresolved Item 325/81-02-03 and 324-81-02-05)
b.
Failure tc Adhere to Technical Specification Limiting Condition for Operation and the appropriate Action Statements.
At 1420 hours0.0164 days <br />0.394 hours <br />0.00235 weeks <br />5.4031e-4 months <br /> on December 9, 1980, with unit 2 in cold shutdown the conventional and nuclear service water systems were secured to repair the 2A conventional service water pump discharge check valve. Primary coolant temperature at this time was less than 120 degrees F.
At 1615 hours0.0187 days <br />0.449 hours <br />0.00267 weeks <br />6.145075e-4 months <br />, RHR pumps ("A" loop) were secured to reduce coolant heat input from the p'~ps.
Primary coolant temperature at this time was approx-imately 150 d_grees F.
Due to unexpected problems, repairs to the valve took longer than anticipated. At 2015 hours0.0233 days <br />0.56 hours <br />0.00333 weeks <br />7.667075e-4 months <br />, the conventional and nuclear service water systems were returned to service following the check valve replacement. Primary coolant temperature at this time, as read at the vessel bottom head drain, was 147 degrees F.
At 2033 hours0.0235 days <br />0.565 hours <br />0.00336 weeks <br />7.735565e-4 months <br />, shutdown cooling was in.itiated with the "B" loop of RHR and the coolant temperature indicated a maximum of 256 degrees F. Primary containment could not be quickly established due to cables going through the personnel access hatch and the torus hatch being removed.
The reactor head vents were open during this time with zero pressure in the reactor vessel. No evidence of steam exhausting from the vent was observed. Primary coolant temperature was reduced to normal levels by 2336 hours0.027 days <br />0.649 hours <br />0.00386 weeks <br />8.88848e-4 months <br />.
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During the time from 1420 to 2015 hours0.0233 days <br />0.56 hours <br />0.00333 weeks <br />7.667075e-4 months <br />, all service water pumps were inoperable. This is contrary to Technical Specification 3.7.1.2.b., in that the LPCI system, the core spray system and the diesel generators were not declared inoperable, which exceeds the Limiting Condition for Operation.
Failure to verify the operability of at least one LPCI subsystem within four hours violates the appropriate action statement requirement. Exceeding the Limiting Condition for Operation and not satisfying the action statement is a Violation (324/81-02-01).
Technical Specification 6.9.1.8 requires that the type of event listed c.
below shall be reported within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by telephone and confirmed by telegraph, mailgram, or facsimile transmission to the Director of the Regional Office no later than the first working day following the event.
Technical Specification 6.3.1.8.b. states, " Operation of the unit or affected system when any parameter of operation subject to a limiting condition for operation, is less conservative than the least conser-vative aspect of the limiting condition for operation established in the Technica' pecifications."
Contrary to the above, the event described in paragraph b, above was reported by telephone via the NRC emergency notification system and to the Region II office but, the follow-up confirmation by facsimile, was not transmitted until December 22, 1980.
The failure to submit a timely written report is a Violation. (324/81-02-02).
8.
Operational Safety Verification
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The inspector observed control room operations and conducted discussions with control room operators on a daily basis during the months of December, 1980 and January,1981. The inspect r verified the perability of selected emergency systems. Tours of vital areas included the reactor buildings, service water building and diesel buildings.
During routine tours of the plant, the inspector noted that lead shielding was used to reduce radiation levels in certain areas of the plant.
The inspector inquired as to whether any controls or procedures are used to ensure lead shielding was not hung on safety grade piping.
The inspector was informcd -that there were no formal controls or procedures but that a survey had been performed to identify and remove any lead shielding installed on safety grade piping. This survey was completed on December 23, 1980.
In addition, the licensee has committed to establish' and issue procedures for the control and installation of lead shielding by January 16, 1981.
This is an inspector follow-up item (325/81-02-01, 324/81-02-03).
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9.
Observation of Emergency Drill a.
The licensee conducted an emergency drill on January 27, 1981. The drill simulated a reactor trip due to a gross fuel failure. The drill was classified as a General Emergency VI. Active participation was limited to site personnel. The local, state, federal and CPL Corporate
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participation was limited to telephone ' notification.
The drill
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involved a complete site evacuation.
i b.
The inspector attended the pre-critique session on January 27, 1981 that provided the details for the drill scenerio.
The inspector observed the emergency drill from the control room and the technical support center.
c.
The inspector attended the post-critique sessien January 28, 1981 and provided -the following comments to licensee management based on the limitea observation of the activities observed.in and around the control room area.
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(1) The Emergency Coordinator (Shift * Supervisor)
is directly responsible for site activities during an emergency.
His responsibility is for overall management and coordination of activities to terminate, contain, or minimize the consequences of the accident.
He should not be directly involved in any one operation to the degree that the overall plant conditions and operations might be overlooked and jeopardized.
The inspector noted that, from the very beginning of the drill, the emergency coordinator manned the phones in the control room, made necessary notifications and relayed information to the
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technical support center. He never left the phone during the i
entire drill.
Activities were being performed without his knowledge, and the shift foreman was making decisions and directing operator activities without consulting the emergency coordinator.
The emergency coordinator must have the overall picture of what plant conditions are in order to make proper decisions.
He was receiving information simultaneously from several sources and appeared unable to clearly perform his function.
The emergency coordinator must be free to act as a manager and not be parforming as a phone talker.
(2) Major prcblems existed in the inability to effectively communicate between the environmental monitoring teams, the radiation
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monitoring teams in the field and the control rcam and technical
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support center.
(3) The drill was no surprise n wst of the operators, as'well as supervision, were aware of the approxirnate time and nature of the
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drill.
The shift foremaa had all the necessary graphs end materials for running isopleths on his desk prior to the commencement of the drill. This pre-information created a very
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unusual situation in that they took the drill to a premature ending without reacting to the plant condtti'ons' being presented to them. A site emergency and evacuation were conducted without any existing conditions to warrant such actions.
Total overaction i
resulted in operators not verifying alarms and not taking proper actions as would occur in an actual incident.
Emergency procedures were not followed because everything was wrapped up prematurely.
The inspector stated the need. to limit the number of people involved in pre-knowledge of planned drills and to maintain better security in order to create more realistic performance from shift
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personnel.
(4) Emergency kits stored in the Emergency Operations Center containing TLD's and dosimeters, also contained an unshielded calibration source that resulted in pre-exposure of TLD's and off
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scale readings on dosimeters.
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(5) In summary, overall communications throughout the drill were poor, the drill was not well coordinated and organization response was l
not crderly and timely.
(6) The licensee's critique held on January 29, 1981, shortly following the drill, resulted in several additional deficiencies requiring. corrective actions.
The inspector will follow-up on
these items as well as the items described above.
This is an Unresolved item pending action by the licensee (325/81-02-02 and 324/81-02-04).
10.
Organization and Administration l
Mr. A. C. To111 son, General Manager, Brunswick Electric Steam Plant, has been assigned by Carolina Power and Light Company to the Institute of
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Nuclear Power Operations (INPO) through the Loaned Employee Program. Mr. C.
R. Dietz assumed the position of General Manager, Brunswick Electric Steam Plant effective January 26, 1981.
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11.
IE Bulletin Followup For the IE Bulletins listed below, the inspector verified that the written i
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response was within the time period stated in the bulletin, that the written l
response included the information required to be reported, that the written
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re:ponse included adequate corrective action commitments based on infor-l mation presented in the bulletin and the licensee's response, that licensee
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management forwarded copies of the written response to the appropriate onsite management representatives, that information disc'ussed in the
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l licensee's written response was accurate, and that corrective action taken by the licensee was as described in the written response.
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IEB - 80-01 Operability of ADS Pneumatic Supply, January 11, 1980
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IEB - 80-24 Prevention of Damage Due to Water Leakage Inside Containment (October 17, 1980. Indian Point 2 Event)
November 21, 198U No violations were identified.
12.
Verification of Emergency Procedures Adequate to Respond to ATWS Events (TI-2515/46)
The inspector reviewed the following procedures:
EI-2
" Loss of Control Rod Shutdown Capability" Revision 5, 10/30/80 EI-49
" Anticipated Transients Without Scram" Revision 2, 1/2/81 EI-3.4
" Inability to Move Control Rods" Revision 3, 6/23/78 EI-5.1
" Loss of Primary Containment" Revision 7,7/13/80 EI-5.2
" Loss of Primary Containment" (Accident Conditions)
Revision 3, 9/27/78 EI-31
" Reactor Scram" Revision 17, 12/6/80 EI-40
" Safety / Relief Valve Fails Open" Revision 12,7/18/80 OP-5
" Standby Liquid Control System" Revision 7, 11/9/80 OP-17
" Residual Heat Removal System" Revision 30, 1/8/81 01-4
"LC0 Evaluation and Followup" Rev.sion 5, 11/23/80 01-12
" Scram Discharge Volume Vent and Drain and Main Steam
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Bypass Valve Reportability Requirements" Revision 1, 7/13/80 A-5, Window 2.5
" Scram Discharge Volume Vent Drained" Revision 2, 9/30/80~
l A-2.3.
" Discharge Volume High Water Level Channel Functional Check" Revision 11, 8/26/80 l
The inspector verifiad by review of the above procedures, that the following i
criteria are addressed adequately.
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Failure to scram when required.
t Failure to complete scram when initiated automatically or manually.
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Inability to move or drive control rods.
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Failure to automatically scram when a parameter exceeds its trip value.
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Criteria for use of Standby liquid Control System or Emergency Boration
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Reactor trip or scram.
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Anticipated transient without scram.
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Authorities and responsibilities of operators governing the use of the
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Standby Liquid Control System.
If -recirculation pumps do not automatically trip, procedures must
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require the operator to do this quickly following an ATWS condition.
Acceptance Criteria
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IE - Bulletin 80-17, Action No. 4.
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The inspector had no further questions in this area.
No violations were identified.
13.
Security Workshop
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The resident ir.spector attended tie following meeting on December 12, 1980.
The agenda and discussion items are listed below:
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Overview of Regulatory Requirements and description of the BSEP -
Security System.
Discussion of Coat.ingency Events which may require local law enforce-
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ment agency assistance.
Plant Tour.
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Attendees:
(ATF - Alcohol, Tobacco &
Firearms Div.)
Robert C. Bowen Special Agent ATF - U. S.
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l William D. Gentry Special Agent ATF - U.S.
l Con R. Carlisle Special Agent ATF --U.S.
Constance White B.C.S.D Deputy Sheriff Howard Lee Policeman Southport PD Bill Coring Chief of Police Southport, NC Don Johnson Senior Resident Inspector U.S. NRC
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l Mike Nickol Reg. Sales Mgr.
Burns Int'l Maxie T. Gowen Reg. Mgr.
Burns Int'l Jesse D. Powell Reg. Nuclear Coord.
Burns Int'l James R. Vaughan Security Chief-Burns Int'l John B. Walker, Jr.
Project Specialist Security CP&L Dennis E. Novotny Senior Specialist - Security BSEP CP&L The discussions above resulted in areas of responsibility not being clearly defined in the event of a civil disorder. The licensee plans to have a future meeting to better clarify individual responsibilities between Federal and Local Law Enforcement Agencies in conjunction with CP&L's Security Orgtnization.
The inspector had no fur,er questions in this area.
14.
Review of Periodic Reports The insps.ctor reviewed the following '. icensee reports:
Brunswick Steam Electric Plant, Units Nos.1 and 2, Monthly Operation
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Reports for November and December, 980.
The-inspector verified that the information reported by the licensee is technically acequate and satisfies applicable reporting requirements established in 10 ';FR 50, and Technical Specifications.
The inspector had no further questions in this area.
No violations were identified.
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