IR 05000324/1983020
| ML20024F699 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 07/19/1983 |
| From: | Bemis P, Garner L, Myers D, Weise S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20024F677 | List: |
| References | |
| 50-324-83-20, 50-325-83-20, NUDOCS 8309090588 | |
| Download: ML20024F699 (10) | |
Text
. t* " fog UNITED STATES j
.
.
o
.;
NUCLEAR REGULATORY COMMISSION
,
E REGION 11 o
I
.$
101 MARIETTA ST., N.W., SUITE 3100
\\...../
ATLANTA, GEORGIA 30303 Report Nos.: 50-325/83-20 and 50-324/83-20 Licensee: Carolina Power and Light Company 411 Fayetteville Street Raleigh, NC 27602 Docket Nos.:
50-325 and 50-324 License Nos.:
DPR-71 and DPR-62 Facility Name:
Brunswick I and 2 Inspection at Brunsw ck site near Southport, North Carolina b
N/Th Inspectors:
~
a_-
D. Myers, Senior Resid@1t Inspector Date Signed h?
I
[
"f//
SS cn
- -
L.* W. Garner, Resident 6 Inspector Date Signed hY
&
$ /.,1~ S.5
~
-Sr Web, Senior R s'i(TeV ctor, Robinson Date S'igned Approv[dby:
]#, '
L'/
3 C P; Bemis, Sectiopf hi)t Date Signed
~
Division of Project jhd Resident Programs SUMMARY Inspection on May 15 - June 15, 1983 Areas Inspected i
The inspection involved 137 inspector hours on site in the areas of operational safety verification, maintenance, surveillance, independent inspection, review of onsite committees, followup of plant transients and outage activities.
Results Of the areas inspected, three violations were identified in three areas.
(Failure to provide prompt notification, paragraph 8; Failure to have a surveillance procedure paragraph 7; Failure to follow procedure, paragraph 6).
8309090598 830829 PDR ADOCK 05000
.
,
.
.
REPORT DETAILS 1.
Persons Contacted l
Licensee Employees A. Bishop, Manager - Technical Support J. Boone, Engineering Supervisor L. Boyer, Assistant to General Manager - Nuclear Plant T. Brown, I&C/ Electrical Maintenance Supervisor (Unit 1)
G. Campbell, Mechanical Maintenance Supervisor (Unit 2)
- J. Chase, Manager - Operations G. Cheatham, Manager - Environmental & Radiatien Control J. Cook, Senior Specialist - Environmental & Radiation Control R. Creech, I&C/ Electrical Maintenance Supervisor (Unit 2)
- C. Dietz, General Manager - Brunswick Nuclear Project J. Dimmette, Manager - Maintenance W. Dorman, QA - Supervisor
- K. Enzor, Director - Regulatory Compliance
- J. Harness, Manager - Plant Operations W. Hatcher, Security Specialist A. Hegler, Superientendent - Operations R. Helme, Director - Onsite Nuclear Safety - BSEP M. Hill, Manager - Administrative & Technical Support F. Howe, Vice President - Brunswick Nuclear Project L. Jones, Dire:ctor - QA/QC D.' Novotny, Senior Regulatory Specialist G. Oliver, Assistant to Ge eral Manager
"J. O'Sullivan, Maintenance R. Poulk, Senior NRC Regulatory Specialist
- D. Rudolf, QA C. Treubel, Mechanical Maintenance Supervisor (Unit 1)
L. Tripp, Radiation Control Supervisor V. Wagoner, Director - Planning and Scheduling c
Other licensee employees contacted included technicians, operators and engineering staff personnel.
- Attended exit interview 2.
Exit Interview The inspection scope and findings were summarized on June 10, 1983, with those persons indicated in paragraph 1 above.
Meetings were also held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings.
3.
Licensee Action on Previous Enforcement Matters Not inspected, j
,
.
.
.
_
.
.
..
.
-
4.
Unresolved Items Unresolved items were not identified during this inspection.
5.
Equipnient Control (71707/42700/62703)
The inspector reviewed licensee procedures for the removal of safety related equipment from service, performance of maintenance and temporary repairs, tracking of limiting conditions' for operation (LCO), post maintenance testing, and equipment return to service.
Discussions were held with plant operations and maintenance personnel concerning implementation of these procedures.
The following procedures were reviewed:
-
Operating Instruction (01) -04, LC0 Evaluation and Followup, Revision 13 01-10, Operation Work Procedures, Revision 20
+
-
-
01-13, Valve and Electrical Lineup Verification, Revision 2
-
01-16, LCO's on ECCS Equipment, Revision 0
-
Operations Work Procedure (0WP) 17/19, Revision 0 Administrative Procedure, Section 11, Revision 74
-
Engineering Procedure (ENP) -12, Engineering Evaluation
-
Procedure, Revision 3
-
ENP-16, Administrative Control Of In-service Inspection Activities, Revision 10
-
Maintenance Procedure (MP) -10, Preventive Maintenance, Revision 18
-
MP-14, Corrective Maintenance, Revision 16
-
Training Instruction (TI) -104, Revision 4
-
Administrative Operating Instruction (A0I) -45 The inspector identified the following deficiency:
Administrative Procedure (AP), Section 11.5, Clearances, page 11-7, Section 7, requires that, when removing clearance tags and restoring valve and switch positions, independent verification is to be conducted for systems specified in Section 1.3 of TI-104.
TI-104 is not consistant with AP Section 11.8, second Verification of Operability in that TI-104 doesn't require independent verification for the Automatic Depressurization System, Reactor Protection System, Fire Protection System, and the Primary
-
_ _ _ _ _ _ _ _ _ _ _ _ _ _
.
.
..
.
,
Containment Isolation System. Through discussion and document review, the inspector determined that plant practices do include independent checks of the above mentioned systems.
Licensee management agreed to resolve document discrepencies.
(IFI 324/83-20-04).
Of the areas inspected no violations or deviations were identified.
6.
Pre-Startup Valve Lineups (92706)
The inspector reviewed licensee procedures for conducting safety-related equipment valve lineups following a major outage as well a review of the latest completed valve lineup procedures for Unit 2 listed below:
-
Operating Procedure (0P) -17-V, Residual Heat Removal (RHR) System Valve Lineup
-
OP-16-V, Reactor Core Isolation Cooling System Lineup
-
OP-18-V, Core Spray System
-
OP-19-V, High Pressure Coolant Injection System Lineup The inspector also reviewed portions of General Procedure -1 and interviewed selected plant operations personnel. The inspector had the following findings:
a.
The review of the OP-17-V Lineup completed February 9,1983, revealed that all stem leakoff valves for RHR valves in the drywell had been lined up closed instead of open, as required by the precedure.
Operations personnel indicated that stem leakoff valves in the drywell are kept closed to reduce their contribution to reactor coolant system leakage. The inspector questioned if the procedure had been changed to reflect this valve lineup change and determined that no change had been initiated. Administrative Procedures Section 5.3.2 and 5.5.2, require that procedure changes be developed and routed to the Plant Nuclear Safety Committee for Review and approval. Administrative Operating Instruction -45, allows the shift foreman to accept valve lineup deviations without requiring the initiation of a procedure revision.
Failure to implement the Administrative Procedures regarding valve lineup changes is a violation (324/33-20-03).
Further discussion with the Operations Manager, revealed that General Procedure -1, paragraph A.1.1.2.1.1, allows the shift foreman to deviate from valve lineups if system operability is un??fected. This guidance is contrary to the requirements of the Administrative Procedures for procedure revision control. The Operations Manager indicated that corrective action was being initiated to correct GP-1 to ensu e compliance with Admini-strative Procedures and the ascertain all safety related valve lineup changes for which procedure changes have not been initiated.
-_
_
_
.
_-
.
.
, _ _
_ _. _
_
,
.
.. - -
,
.
-
.
..
-
.
General Procedure (GP) -1, does not delineate formal controls for deviations from valve lineup procedures.
Some valve deviations are documented in the comments section of the GP-1 checklist, while others are not.
Discussions with the Operations Manager indicated that licensee corrective actions have been initiated to provide a valve exception form for each valve lineup to identify those valves out of position and the reason for the condition.
Additionally, guidance will be provided to the operators such, that temporary changes to lineups will be required for those valves out of their expected positions which are not controlled by plant operating procedures for mode change and startup or by clearance procedures.
These corrective actions will be inspected in conjunction with the violation noted above.
7.
Surveillance Testing Surveillance tests were analyzed and/or witnessed by the inspecto.r to ascertain procedural and performance adequacy, completed test procedures examined were analyzed for embodiment of the necessary test prerequisites, preparations, instructions, acceptance criteria and sufficiency of technical content.
Selected tests were witnessed and examined to ascertain that current, written approved procedures were available and in use, that test equipment in use was calibrated, that test prerequisites were met, system restoration was completed and test results were adequate.
The inspector employed one or more of the following acceptance criteria for evaluating the above items:
10 CFR
-
-
-
Technical Specifications During the surveillance inspection, the following item was identified.
Review of periodic tests PT-01.1.12P, PT-01.1.12PC, PT-01.1.13P and PT-02.1.20 associated with calibration, functional testing and logic testing of the main steam line radiation monitors revealed that the mechanical vacuum pumps are not verified to shutoff upon a high radiation isolation trip signal as described in FSAR Selction 11.5.
Footnote d to Technical Specification Table 3.3.2.1 item 1.C.1, " Main Steam Line Radiation - High",
states " Trips the mechanical vacuum pumps".
Discussions with licensee personnel confirmed that tripping of the mechanical vacuum pumps is not performed as part of any surveillance procedure.
Review of system and logic diagrams indicated that the system was designed to cause the required trip but apparently an oversite occured during the surveillance procedure preparation.
The licensee promptly developed a
,
procedure to verify the trip actually occurs.
Special procedure, SP-83-047 was performed satisfactorily on Unit 2 to verify mechanical vacuum pump isolation on high radiation.
The licensee has indicated that the special procedure will be performed on Unit 1 prior to restart after the current y"*
r'n-'
~^
p'
'"
e
- " - " * *
P~
W
- -"t4*'-'-
'
.
.
.
.
.
refueling outage.
Permanent procedure PT-02.2.5 is being written to ensure future periodic testing of the system function.
(IFI 325/83-20-04).
Technical Specification 4.3.2.2 requires a logic system function test at least once per 18 months of all isolation actuation instrumentation channels.
Failure to include the mechanical vacuum pump trip as part of the logic test is a violation of that requirement and applies to Unit 1 and 2.
(50-324/83-20-01 and 50-325/83-20-01).
The inspector verified that other actions described by the FSAR and required to be included in the logic test are included in PT-02.1.20.
8.
Untimely 10 CFR 50.72 Notification During Unit No. 2 power operatien at 2330 on May 9, 1983, the duty Shift Operating Supervisor observed that both main condenser steam jet air ejector off gas radiation monitors A and B were not indicating as expected for that power level. An investigation revealed both monitors were inoperable due to closure of the root isolation valves to each monitor, 2-0G-V35 and 2-0G-V36.
The inoperability of these monitors renders the automatic closure capability of the Off-Gas System discharge valve inoperable. Whenever these monitors are inoperable, technical specifications require placing the affecting unit into hot shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the event discovery.
From initial startup.of the main condenser steam jet ejectors to discovery of this event, a total of 25.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> had elapsed.
(Dther details of this event are discussed in IE Report 324/83-17 and licensee special report to the NRC dated May 29,1983.)
During the review of this event, inspectors discovered that the shift fore-man had sufficient information (i.e., that instrument root isolation valves were shut) to allow proper evaluation and identification of the event for 10 CFR 50.72 (Red phone) notification by 0400 on May 10, 1933. However, notification was not made until 0730 on May 10.
This failure to provide l
within one hour of the event, notification of an event which by itself could
!
prevent the fulfillment of the safety function of a system important to
!
safety that is needed to limit the release of radioactive material to acceptable levels or reduce the potential for such a release is a violation of the reporting requirement 10 CFR 50.72(a)(b)(iii) notification of
,
l significant events and applies to Unit 2.
(324/83-20-02).
!
9.
Operational Safety Verification The inspector verified conformance with regulatory requirements throughout the reporting period by direct observation of activities, tours of facilities, discussions with personnel, reviewing of records and independent verification of safety system status.
The following determinations were made:
-
Technical Specifications. 1hrough log review and direct observation during tours, the inspector verified compliance with selected Technical Specifications Limiting Conditions for Operation.
_
-
-
.
.
.-
...
-
.-
.
..
..
~
.
-
By observation during the inspection period, the inspector verified the 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.
-
Control room annunciators.
Selected lit annunciators were discussed with control room operators to verify that the reasons for them were understood and corrective action, if required, was being taken.
Monitoring instrumentation. The inspector verified that selected
-
instruments were functional and demonstrated parameters within Technical Specification limits.
-
Safeguards system maintenance and surveillance. The inspector verified by direct observation and review of records that selected maintenance and surveillance activities on Safeguards systems were conducted by qualified personnel with approved procedures, acceptance criteria were met and redundant components were available for service and required by Technical Specifications.
-
Major components. The inspector verified through visual inspection of selected major components that no general condition exists which might prevent fulfillment of their functional requirements.
Valve and breaker positions. The inspector verified that selected
-
valves and breakers were in the position or condition required by Technical Specifications for the applicable plant mode. This veri-fication included control board indication and field observation (Safeguard Systems).
-
Fluid leaks.
No fluid leaks were observed which had not been iden-tified by station personnel and for which corrective action had not been initiated, as necessary.
-
Radioactive releases.
The inspector verified that selected liquid and gaseous releases were made in conformance with 10 CFR 20 Appendix B and Technical Specification requirements.
-
Radiation Contols. The inspector verified by observation that control point procedures and posting requirements were being followed.
The inspector identified no failure to properly post radiation and high radiation areas.
-
Security. During the course of these inspections, observations rela-tive to protected and vital area security were made, including access controls, boundary integrity, search, escort, and badging.
No violations or deviations were identified.
.
_ -.
__ _
_
,.
.
..
.
.
-
10. Onsite Review Committees
,
The inspectors attended several regular monthly Plant Nuclear Safety Committee (PNSC) Meetings and Several special PNSC meetings conducted during the period.
The' inspectors verified the following items:
Meetings were conducted in accordance with Technical Specification
-
requirements regarding quorum membership, review process, frequency and personnel qualifications;
-
Meeting minutes were reviewed to confirm that decision / recommendations were reflected and follow-up of corrective actions were completed.
No violations or deviations were identified.
11.
Inadvertent Loss of Power to Unit 1 Core Spray Valve On June 2,1983, the licensee reported finding the power to the Core Spray (CS) Injection Valve, F005B, operator off, rendering the B loop of the CS system inoperable. A loop of the CS system was operable at the time of this event. The unit was in cold shutdown at the time of this event.
At 3:00 p.m. on June 2, 1983, the Unit 1 control operator noticed that he had no control board indication for the position of valve F005B. An attempt to regain position indication by changing the indicator bulbs proved un-successful, so an auxiliary operator (AO) was dispatched to the Unit I reactor building to investigate.
The A0 found the breaker, 1-DW6, which supplies power to the valve operator for valve F005B, off.
The breaker was immediately reclosed and the valve successfully stroked.
A complete control board review of vaive positions were performed for Unit 1 ECCS systems with no other discrepancies identified.
Licensee investigation of the circumstances surrounding this event determined that the valve operator power was on at 2:00 p.m.,
one hour prior to its being found off.
The probable cause of the breaker being off has been determined to be the result of inadvertent bumping of the control switch by personnel working in the vicinity of the breaker.
The breaker is physically located about 2 feet above the flocr directly behind personnel manning a desk utilized as a health physics control point.
It is postulated that personnel leaning back in a chair swung the chair top rail into the panel, inadvertently tripping the breaker.
The licensee was able to re-construct the ease with which this could occur.
Immediate action was taken to move this and other work stations from close proximity to motor control centers.
12.
Followup of Plant Transients and Safety System Challenges During the period of this report, a followup on plant transients and safety system challenges was conducted to determine the cause; ensure that safety
F..
,.
-
.
'
systems and components functioned as required; corrective actions were adequate; and the plant was maintained in a safe condition.
On May 16, 1983 at 2108 hours0.0244 days <br />0.586 hours <br />0.00349 weeks <br />8.02094e-4 months <br />, Unit 2 reactor while at 90?4 of full power, experienced a scram due to Average Power Range Monitor (APRM) inoperative trip on channel A concurrent with a Main Steam Line (MSL) radiation high trip on channel B.
A group 1 isolation, closure of mainsteam line isolation valves (MSIV), was received shortly after the trip.
Both High Pressure Coolant Injection System (HPCI) and Reactor Core Isolation Cooling System (RCIC) automatically started but did not inject.
HPCI was utilized for vessel level and pressure control until 2156 hours0.025 days <br />0.599 hours <br />0.00356 weeks <br />8.20358e-4 months <br /> when the feedwater and main condenser systems were placed back into service after the MSIV's were re-opened. All engineering safeguard features performed as expected.
Both HPCI and RCIC did not automatically inject into the vessel because the low low water level produced by the scram swell did not remain for a sufficient length of time to satisfy the injection valves permissive logic. The double low level must still be present when the steam supply valves come full open for the injection valves to receive an open signal.
The cause of the trip was attributed to a noise induced signal in the MSL
. radiation monitor B circuitry when the APRM
'A' mode switch was placed in standby per periodic test PT-01.2.4a.
Placement of the switch in standby initiates a trip of the reactor protection system (RPS) and primary contain-ment isolation system (PCIS) group 1 channel 'A'
logic. The noise in the MSL radiation monitor B tripped the
'B' RPS logic, thereby causing the scram. The group 1 isolation was attributed to the combination of the MSL spurious radiation high trip and the momentary low low water level.
Trouble shooting of the noise problem in between circuits revealed that the circuits required additional grounding. A plant modification has been installed in some of the more susceptible circuits to provide the necessary grounds. The modification utilizes a varistor to ground short lived high voltage pulses which are generated by RF associated with relay contacts opening or closing. It is anticipated that this will prevent a repeat of this event.
On June 2, 1983 at 1833 hours0.0212 days <br />0.509 hours <br />0.00303 weeks <br />6.974565e-4 months <br />, Unit 2 reactor, while operating at 100?4 full power, experienced a turbine control valve (TCV) fast closure scram.
Approximately 45 seconds after the trip, the main steamline isolation valves (MSIV) closed as a result of low steamline pressure while in 'RUN' group 1 isolation signal. No engineered safeguard features (ESF) were required to automatically actuate.
Reactor pressure and level were controlled by manually opening safety relief valves (SRV) and manually starting the Reactor Core Isolation Cooling System (RCIC). At approximately 1915 hours0.0222 days <br />0.532 hours <br />0.00317 weeks <br />7.286575e-4 months <br />, the group 1 isolation was reset and the main condenser and 2A feedwater systems were placed in service for decay heat removal and vessel level control. During the transient reactor pressure did not exceed 1020 psig.
The probable cause of the TCV trip was identified as an out of calibration steam pressure transmitter associated with the power load unbalance turbine protection circuit. The power load unbalance circuit compares the turbine k
i
..
..
.
<
.
power as measured by steam pressure to the generator electrical power. A preset mismatch between these parameters will initiate a turbine trip, thereby protecting the turbine from a potentially damaging overspeed con-dition.
Prior to the scram, the weekly test of the power load unbalance circuit was being performed. Apparently the steam pressure transmitter had drifted just up to the point at which the circuit would trip, 1.95 volts.
When the circuit test button is depressed, the actual trip function is by passed but the logic circuit trips. When the test button in released, the circuit voltage must decrease below 1.90 volts before the circuit resets.
However, with the circuit voltage being between 1.90 and 1.95 volts, no reset will occur.
Thus, when the test button was released, the circuit remained tripped but the trip function bypass associated with the test button was now removed, i.e.,
the turbine trip occurred. The licensee is evaluating modifications to the circuit to allow the operator to determine that such a condition exists and that the test should not be performed until repairs are completed.
Prior to the scram, the High Pressure Coolant Injection (HPCI) System had been removed from service to allow performance of a technical specification required surveillance.
The licensee considers performance of other tests which could reasonably have the potential for initiating a reactor scram while either HPCI or RCIC are isolated as being undesirable.
Hence, administrative controit have been issued to defer such testing when possible.
During the transient recovery, the 2B reactor feedwater pump experienced a high vibration trip while attempting to be started.
No cause for the vibrations could be determined.
Repairs included replacement of the turning gear drive sprocket and reconnection and alignment of several linkages on the feedpump turbine governor.
Power operation was resumed on June 4,1983.
No violations or deviations were identified in this area.