IR 05000317/1981002
| ML20004A038 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 03/10/1981 |
| From: | Architzel R, Callahan C, Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20004A027 | List: |
| References | |
| 50-317-81-02, 50-317-81-2, 50-318-81-02, 50-318-81-2, NUDOCS 8105110603 | |
| Download: ML20004A038 (23) | |
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50317-80-06-24 50317-81-01-11
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50317-80-11-12 50317-81-01-14
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50317-81-01-16 50317-80-12-25
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50317-81-01-09 50318-81-01-18 U.S. NUCLEAR REGULATORY C0!1 MISSION OFFICE OF IliSPECTION AND ENFORCEMENT Region I
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50-317/81-02 Report No. 50-318/81-02 50-317 Docket No. 50-318 DPR-53 C
Category C
License No. DPR-69_
Priority
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i Licensee:
Baltimore Gas and Electric Comoany P. O. Box 1475 Baltimore, Maryland 21203 Facility Name:
Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection at:
Lusby, Maryland
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Inspection Conducted: January 5 - February 1, 1981 OC Ik O h b.
3lIo H Inspectors:
R. E. Architzel, Senior Resident date signed Inspector
? e IL &A h L
3lsulst C. J. Callahan, Resident Reactor date signed Inspector Approved by:
P & k 0~Ol h
3 /'; El E. C. McCabe, Jr., Chief, date signed i
Reactor Projects Section, 2B Inspection Summary:
Inspection on January 5 - February 1,1981 (Combined Report Nos. 50-317/81-02 and 50-318/81-02)
Areas Inspected: Routine, onsite regular and backshift inspection by the resident inspectors (54 hours6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br />, Unit 1, 55 hours6.365741e-4 days <br />0.0153 hours <br />9.093915e-5 weeks <br />2.09275e-5 months <br />. Unit 2). Areas inspected included the control room and the accessible portions of the auxiliary, turbine, service, containments, and intake buildings; radiation protection; physical security; fire protection; plant operating records; IE Bulletins; ATWS procedures; licensee action on previous inspection findings; Unit 1 Plant Trip; maintenance; completion status of TMI -
Action Plan Items.
RCS corrosion; survey of explosive detectors; and reporting to the NRC. Noncomoliances: One (Classification of H2 Analyzer as non-safety-related,.
paragraph 2).
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Details 1.
Persons Contacted The following technical and supervisory level personnel were contacted:
E. R. Bauer, Modifications Supervisor G. E. Brobst, General Supervisor, Chemistry (Acting)
A. A. Barth, Quality Assurance Specialist R. P. Bassett, Mechanical Foreman J. T. Carroll, General Supervisor Operations J. T. Carlson Foreman, Radiation Safety G. Crush, Industrial Safety Engineer J. A. Crunkelton, Supervisor, Electrical Maintenance R. E. Denton, General Supervisor, Training / Technical Services S. M. Davis, Senior Engineer, Operations C. L. Dunkerly, Shift Supervisor W. S. Gibson, General Supervisor, Electrical and Controls J. E. Gilbert, Shift Supervisor D. E. Huseby, Engineering Technician S. Hager, Vender Representative, Combustion Engineering J. R. Hill, Shift Supervisor R. P. Heibel, Senior Engineer L. S. Hinkle, Supervisor, Instrument Maintenance M. Konya, Fuel Management Engineer, Combustion Engineering C. Key, Engineer, Electrical Engineering J. F. Lohr, Shift Supervisor D. W. Latham, Principal Engineer, Plant Engineering Nuclear R. O. Mathews, Assistant General Supervisor, Nuclear Security P. E. McGrane, Technical Librarian
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M. J. 'Miernicki, Senior Engineer,. Plant Engineering, Nuclear N. L. Millis, General Supervisor, Radiation Safety E. T. Reimer, Plant Health Physicist J. E. Rivera, Shift Supervisor P. G. Rizzo, Assistant General Foreman, Maintenance B. Rudell, Engineer, Technical Services L. B. Russell, Plant Supbrintendent T. L. Sydnor, General Supervisor, Operations QA l
K. G. Tietsen, Technical Specialist i
J. A. Tiernan, Manager, Nuclear Power Department l
R. L. Wenderlich, Engineer, Operations l
M. J. Warren, Engineering Technician l
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W. L. Whitaker, Assistant General Foreman D. Zyriek, Shift Supervisor C. C. Zapp, Senior Licensed Operator J. M. Yoe, Instructor, Training R. W. Talley, Assistant General Foreman, PMD Other licensee employess were also contacted.
2.
Licensee Action on Previous Insoection Findinns (Closed) Unresolved Item (317/80-08-03; 318/80-08-03) Duties and Responsibilities of the Reactor Operator. This item had been re-addressed in Inspection Report 317/80-16 and 318/80-15 and left open pending procedure revisions specifying/ clarifying the duties and responsibilities of the Shift Technical Advisor and Senior Control Room Operators in addition to the Reactor Operators.
The licensee has issued (new) procedure CCI 140, Shift Staffing, Revision 0, on December 30, 1980 which addressed the duties and responsibilities of the Reactor Operator, Control Room Operator, Senior Control Room Operator (STA), and Shift Supervisors Assistant. During review of this procedure the inspector noted that the Control Room area defined (for the presence of an SLO) included the cable spreading room and Technical Support Center.
This area is considerably larger in sco which encompasses the Shift Supervisor'pe than the NRC's clarifications Office ad The licensee revised CCI 140(A), January 28, 1981 to reflect the NRC position regarding SLO presence in the control room.
(Closed) Unresolved Item (317/78-38-07 and 318/78-34-06); Qualifications of Technicians to ANSI 45.2.6 versus ANSI 18.1.
The insoector reviewed 0AP-20, " Training," Revision 10, dated April 22, 1980,and noted that the section on Technician qualification allows use of either ANSI 45.2.6 or ANSI 18.1-1971.
The inspector emphasized that Technical Specification requirements for Facility Staff must be satisfied.
This item is closed administratively and will be re-examined in conjunction with inspection followup on licensee actions to correct the item of noncompliance for not having Facility Staff qualified in accordance with ANSI 18.1-1971 (317/80-16-01; 318/80-15-01).
(0 pen) Unresolved Item (318/80-22-01):
Deactivation of Control Room Annunciator Windows.
The Unit 1 Annunciator status log was reviewed on January 21, 1981.
Four annunciators were deactivated without documentation.
Discussion with the Manager, Nuclear Power Department and the Plant Superintendent resulted in accurate maintenanca of the annunciator status log for the remainder of this inspection period. The licensee had not issued written procedures for maintaining and documenting annunciator status as of the end of the inspection period.
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(0 pen) Unresolved Item (317/80-26-03; 318/80-22-02): Classifications of Safety Related Instruments Used to Provide Indication to the Control Room Operator. The inspector reviewed the licensee's list of Safety Related Items (Q-List) Classification numbers 593 through 755.
Items of a nature which may not be in accord with current NRC positions were selected for additional NRC review.
Classification Number 718, dated December 4,1978 downgradett the Hydrogen Analyzer System from safety related to non-safety related.
This instrument analyzes and records containment hydrogen concentrations.
The licensee's justification was that the Analyzer was not part of the Technical Specification Table 3.3.10.for post accident monitoring. The inspector noted that two analyzers are required for operation in modes 1 and 2, although operation can continue for 30 days with only one (T.S.
3.6.5.1).
In addition the system detects containment hydrogen concentrations so that measures can be taken to reduce the concentration before flammable limits are reached.
This minimizes the potential for an explosion or burn which could be destructive to the containment and result in an undue risk to the health and safety of the public. The inspector stated that this system was clearly safety related, or Q, even by the licensee's classification guidelines and that removal from the Q-list was an item of noncompliance (317/81-02-01;318/81-02-01).
(Closed) Unresolved Item (317/80-16-09; 318/80-15-08), Upgrade Emergency Support Facilities.
The inspector verified that jacks had been reinstalled for the three commercial telephones committed for the Technical Support Center.
3.
Review of Plant Operations a.
Plant Tour At various times the inspector toured the facility, including the Control Room, Auxiliary Building (all levels, no High Radiation Areas),
j Turbine Building, Outside Peripheral Area, Security Buildings, Health
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l Physics Control Points, Diesel Generator Rooms, Service Building, Intake Structure and both Containments.
Sampling checks of the following were made.
Radiation controls established by the licensee, including posting
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of radiation areas, conditions of step-off pads and disposal of protective clothing.
Control Room manning, including observation of shift turnover and t
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l panel walkdowns.
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Systems and equipment checks for fluid leaks or abnormal
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piping vibration.
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Seismic restraint and hydraulic snubber checks to verify adequate installation and fluid levels.
Plant housekeeping conditions, including general cleanliness and
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storage to preclude safety or fire hazards.
Control Room and local monitoring instrumentation for various
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components and parameters were observed, including reactor power level, CEA positions and safety-related valve position indication.
Whether proper access controls were established.
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Status of Control Room Annunicators.
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During a tour of the Central Alarm Station the inspector noted that a NRC Health Physics Network telephone had been installed there instead of the EOC (South Service Building). The inspector made arrangement with the NRC Region I Emergency Planning Officer to have the phone properly relocated.
No unacceptable conditions were identified.
b.
Review of Operating Logs, Records Logs and records were reviewed to identify significant changes and trends, to assure required entries were being made, to verify Operating Orders conform to the Technical Specifications, to verify proper identification of abnormal conditions, and to verify conformance to reporting requirements and Limiting Conditions for Operation. The following records were reviewed for the report period:
Shift Supervisor's Log
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Unit 1 Control Room Operator's Log
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Unit 2 Control Room Op(rator's Log
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Nuclear Plant Engineer - Operations Notes and Instructions Unit 1 and 2's Control lloom Daily Operating Logs (sampling review)
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Service Building Operatar's Log No unacceptable conditions were identified.
4.
Review of Events Requiring One Hour Notification of the NRC_
The circumstances surrounding the following event requiring prompt (one hour) notification of the NRC via the dedicated telephone (0PX-line) was '
reviewed.
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At 11:10 a.m. on January 16,1981, No.12 Feedwater Regulating Valve inadvertently closed, causing a Unit 1 Low Steam Generator Level trip.
Subsequent troubleshooting identified the cause to be a loose lead in the circuitry which initiates Feedwater Regulating valve closure (No.12 FW Regulating Valve) on Turbine trip.
Rr. start was accomplished on the swing shift. The inspector observed post '. rip actions in the control room.
Additional items reviewed included charts of steam generator water level, pressurizer pressure, the computer alarm tripper printout and Post Trip Log.
ENS notification was completed as required. No unacceptable conditions were identifie *
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THIS PAGE INTENTIONALLY LEFT BLANK, IT CONTAINED 2.790 INFORMATION, NOT'FOR PUBLIC DISCLOSURE.
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6.
Plant Maintenance During the inspection period, the inspector observed various maintenance and problem investigation activities. The inspector reviewed these activities to verify cocoliance with regulatorf requirerents, including those stated in the Technical Specifications; compliance with the administrative and maintenance procedures; compliance with applicable codes and standards; required QA/QC involve ent; proper use of safety tags; prcper equipeent alignment and use of ju=cers; personnel qualifications; radiologi. cal controls for worker protection; fire protection; retest requirements and to ascertain reportability as required by Technical Specifications. The following activities were included during this review:
Control Room Maintenance Request Files were spot checked to deter =ine
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if the maintenance requests referenced by active out of service tags were on file.
The inspector reviewed Maintenance Request 0-80-6093 which was issued
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to linit the caximum travel of Unit 1 Auxiliary Feedwater Control
.v lves to 75% open. The purpose was to prevent pump runcut upon a
' failure of control air. This nodification was required to support cocoletion of Facility Change Request 79-1060 and 79-1035 issued for installation of a auxiliary feedwater puro autonatic start feature.
The maintenance request form was cocoleted in accordance with Calvert Cliffs Instruction 2000, Change 1. Although this action modified the systen flow path, the senior control room operator did not require an operational test to determine if the mininum specified auxiliary feedwater ficw requirements were satisfied.
This area is addressed in detail in paragraph 9.c.
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7.
Coroletion Status - TMI-2 Action Plan Iters a.
References 1.
NUREG-0737, Clarificaticn of TMI Action Plan Requirements, D.G.
i Eisenhut letter dated October 31, 1930.
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Response to NUREG-0737, BG&E letter dated December 15, 1980, A.
E. Lundvall, Jr. to D. G. Eisenhut.
3.
Response to NUREG-0737, BG&E letter dated December 30, 1980, C.
H. Poindexter to D. G. Eisenhut.
b.
The inspector ascertained the completion status of selected NUREG-0737 items as committed by the licensee in the references. This determination did not involve (in all cases) a physical verification / determination cf technical adequacy.
The following table lists the items included in this review:
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ITEM ACT10N STATtlS Conmi t ted Scheduled Completion Completed Completion Reason Not Da te Yes/,No Qte Completed /Coninents II.K.3.9 plD Controller... Mod accomplished None NA Not applicable
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II.K.3.22a RCIC Suction
... procedure imple-None NA Not applicable
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!!I.D.3.3 Inplant Rad per1 grade 12 monitor
...lfp 12/15/80 YES
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Monitors Ca t. "9" NOTE II.E.4.2(6) Cont, purge Valves tinit 1 - A pressure regulator has been installed in the air operating supply limiting maximum
vTilve opening to valve suppIters limit (outboard 400; inboard 45 ).
As such the Staff
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interim operability position has been satisfied and the licensee considers that the valves can be opened at any tine; within the constraints of limiting purging to 90 h'ours per year.
tinit 2 - pending installation of the pressure regulators to limit valve travel, the licensee requires the purgi valves be closed, solenoid leads lifted, and air supply isolated during modes 1-4.
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ITEM ACTION STATUS Conmitted Scheduled Ccmpletion Completed Completion Reason Not Da te Yes/No Date Completed /Conments I.A.1.1 STA
... training program 12/12/80 YES implemented 50Ls perform function
... degreed engineers None NO NA per 12/14/79 ltr
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on shift I.A.I.3 Shift Manning... overtime limits 2/1/81 N0 2/1/81 Draft Procedure implemented I.A.2.1.(4)
R0 & SR0 Trng.... implementation No exceptions YES
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Program taken to 3/28/80 Denton ltr I.C.5 Feedback of
... procedure 1/1/81 YES (Comment: procedure Operation implemented revision to be
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issued by 1/23/81 clarifyingrequirements)
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I.C.6 Verify
... procedure 1/1/81 Partial Never Exception taken to
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Performance implemented (clarification)
second verification of Operating (3)
12/15/80 ltr.
Activities II.E.4.2.(Sa) Cont. Pressure...setpoint 7/1/81 NO Commitment date Setpoint adjusted in future II.E.4.2.(6)
Cont. Purge
... valves closed and No exception Unit i Valves surveillance imple-taken to YES mented NUREG-0737 Unit 2 Unit 2 See Note No 1/16/81
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The inspector questioned the licensee's implementation of item I.C.6, Verify Performance of Operating Activitieg NUREG-0660 requires that licensees review and revise procedures e3 necessary to assure that an effective system of verifying the correct perfonnance of operating activities is in place. NUREG-0737 issues clarifications to these positions and states that an acceptaole program for verification of these activities includes, in addition to other provisions, the following clarifications:
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Except in cases of signficant radiation exposure,
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a second qualified person should verify correct implementation of equipment control measures such as tagging of equipment.
(4)
Equipment control procedures should include assurance that control-room operators are informed of changes in equipment status and the effects of such changes..."
The licensee has taken exception to clarification (3) (Reference 2).
Justification included requirements that a senior licensed individual verifies the adequacy and correctness of tagouts and an operator accompanies the job supervisor to the equipment location prior to removal from service for the purpose of identifying boundaries and equipment.
The licensee has implemented clarification (4) by requiring the senior control room operator to initial Maintenance Requests following granting of permission by the Shift Supervisor, thus indicating that he has been informed t'1at equipment is out of service for maintenance.
The inspector stawd that he thought the licensee's system to be inadequate for assuring that control room operators were aware of equipment status.
Although selected equioments out of service require control l
room log book entries (those which place the plant in degraded modes of the Technical Specifications) most maintensnce actions are only brought to the attention of one shift.
The status of the various maintenance actions are maintained in various work groups. Some of
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l these are filed chronologically and some are filed by system number.
l Only the Operations Maintenance Group Log is available in the Control Room.
The following is a list of those work centers which maintain Maintenance Request Logs:
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NUCLEAR POWER DEPARTMEfE
- Electrical Maintenance
- Instrument Maintenance (Unit 1 & Unit 2)
- Computer Maintenance
- Test Equipment
- Modifications (NPD)
Operations Chemistry Radiation Safety Nuclear Fuel Management Administrative Services Technical Support PRODUCTION MAINTENANCE DEPARTMENT
- Unit 1
- Unit 2
- Modifications
- Modifications Engineering-Nuclear Reserved for Special Projects
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- Also maintains incoming MR log.
To be sure of a particular equipment's current status would require an examination of seventeen different work center's logs located in
various plant and area locations.
The inspector questioned the acceptability of this method of tracking system status in view of the clarification requirement to " assure control room operators are informed of changes in equipment status and the effects of such changes".
The licensee's implementation of NUREG-0660 Item I.C.6 as clarified by NUREG-0737 is unresolved and will be addressed in future NRC inspection reports (317/81-02-02; 318/81-02-02).
8.
IE Bulletin Followup l
l The inspector reviewed licensee actions on the following IE Bulletins l
(IEBs) to determine that the written response was submitted within the required time period,'that the response included the information required including adequate corrective action connitments, and that licensee management had forwarded copies of the response to responsible onsite management.
The review included discussions with licensee personnel and observations and l
review of items discussed below.
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Bulletin 80-15, Possible Loss of Emergency Notification System with
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Loss of Offsite Power. The licensee responded to this Bulletin in letters dated August 21, 1980 and October 31, 1980. The inspector reviewed the results of loss of power testing (September 26,1980)
discussed the modification to the power supply to battery backup with a C&P telephone repainnan, and verified that CCI 118D, Reporting Requirements, Change 2 dated October 31, 1980 had been revised to include a requirement to notify the NRC Operations Center within one hour of ENS phone impairment.
Bulletin 80-24, Frevention of Damage Due to Water Leakage Inside
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Containment.
Calvert Cliffs does not use open systems as defined in the bulletin so that parts 1 and 2 were not answered. The inspection involved review of the response (dated December 31,1980), review of maintenance records, discussions with plant personnel, and FSAR review.
AVERAGE LEAKS / YEAR Closed System Wet Spots Drips Streams Deluces Method Unit 1
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Observation in containment Component Cooling
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Observation in containment Compnent Cooling f
Bulletin 78-12, 12A, and 12B, Atypical Reactor Vessel Weld Material.
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The inspector reviewed the licensee's responses to this Bulletin dated l
November 17, 1978 and March 27, 1979. These responses documented that Combustion Engineering would supply a generic report to the NRC addressing l
this Bulletin. The inspector also reviewed a memorandum dated December 4,1980, from G. B. Georgiev, Division of Resident and Regional Inspection, IE to R. T. Carlson, Chief, RC&ES Branch NRC Region I.
This memorandum documented NRC review of the subject documentation submitted by Combustion Engineering in response to IE Bulletin 78-12, 12A and 128.
Based upon i
the information contained in the submittal the NRC concluded that all
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weld material used in the subject vessels met the applicable acceptance criteria.
No atypical weld material was found.
The owners of reviewed reactor vessels documentation included Baltimore Gas and Electric.
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Bulletin 80-19, Failures of Mercury Wetted Relays.
Licensee actions
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in this area had been inspected-prior to the licensee's response (Inspection Report 317/80-14;318/80-13). The licensee committed (response dated October 30,1980) to perfom the relay surveillance at the prescribed (10 day) frequency by perfoming STP-03 weekly.
In addition, the licensee committed to following the Combustion Engineering recomendation to replace the mercury wetted relays on an as failed basis with in kind replacements until qualified dry contact relays are available for direct replacement, anticipated early 1981.
Bulletin 80-23, Failures of Solenoid Valves Manufactured by Valcor
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Engineering Corporation.
The inspector reviewed the licensee's response to this Bulletin dated January 8,1981 stating that no Valcor Engineering Company solenoid valves with part numbers V70900-21-1 or 3 were in use or on order at Calvert Cliffs.
The inspector reviewed the instrument indices and did not identify any of the subject solenoids.
9.
Review of Licensee Event Reports (LERs)
a.
The inspector reviewed LERs submitted to the NRC:RI office to verify that the details of the event were clearly reported, including the accuracy of the description of cause and adequacy of correction action.
The inspector determined whether further information w:ts required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LERs were reviewed:
LER No. (Unit No.)
LER Date Event Date Subject 80-067/03L (1)
1/20/81 12/21/80 Reactor Protective System Channel l
B Trip Units Bypassed to Repair T-cold Input 80-071/03L(1)
1/19/81 12/20/80 No. 12 Auxiliary Feedwater Pump Inoperable Due to Failed Turbine High Dres:;ure Bearing 80-060/03L (2)
1/26/81 12/26/80 Containment Air Particulate Detector Inoperable Due to Bad Connector l
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LER No. (Unit No.)
LER Date Event Date Subject 80-069/03L (1)
1/21/81 12/22/80 No. 12 Steam Generator Pressure ESFAS Channel ZD Setpoint Drift
- 81-005/01T (1)
1/29/81 1/18/81 PORV ERV 404 opened while in cold shutdown, pressure trans-mitter failed high 80-059/03L 1/26/81 12/26/81 Containment Air Particulate and Gaseous Monitors Inoperable Due
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to Inadvertent Closure of Sample Valves
- 81-001/01T (1)
1/20/81 1/14/81 Reactor Power Indicated 4.5 PERCENT LOW due to Feedwater Flow Transmitter Drift 79-009/03L (2)
1/20/81 2/26/79 Followup Report, Service Water Heat Exchanger Throttle Valve Failed to Open
- 80-070/04X (1)
1/7/81 6/24/80 Oyster Samples at Conoy greater than 10 tires background for Ag-110m
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LER No. (Unit No.)
LER Date Event Date Subject 80-055/03L (2)
1/9/81 12/9/81 No. 12 EDG Removed from Service to Repair Fuel Oil Leak
- 81-03/03L(1)
1/11/81 Auxiliary Fecdwater Low Flow (Note: this LER will be submitted '
after the closing date of this report)
- 80-072/03L(1)
1/23/81 12/25/80 Component Cooling Heat Exchanger
- 80-068/03L (1)
1/9/81 12/10/80 No. 12 Control Room Air Condition-ing Inoperable
- 80-058/03L (1)
12/12/80 11/12/80 Spurious opening of No.114KV normal feeder supply 80-057/03L (2)
1/13/81 12/14/80 CEA 38 Dropped Into the Core During Surveillance Testing
80-052/03L (2)
1/8/81 11/3/80 Containment Penetration Room Exhaust Fan Damper Inoperable
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b.
For the LERs selected for onsite review (denoted by asterisks above), the inspector verified that appropriate corrective action was taken or responsibility assigned and that continued operation of the facility was conducted in accordance with Technical Specifications and did not constitute an unreviewed safety question as defined in 10 CFR 50.59.
Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewed.
80-070/04X (1) - Oyster Samples at Camp Conoy Greater
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than 10 Times Background. This LER was re-submitted in the form of an LER as requested by the inspector. The original report was submitted by the Chief Environmental Engineer on July 30, 1980. The inspector noted that NUREG-0161 requests that reports submitted to the NRC adhere to a particular format. The inspector further noted that if the licensee declined to submit such reports in the requested format the NRC will internally generate a Licensee Event Report, however, it would be easier for the NRC and perhaps more accurate if the licensee's submittals adhered to the requested formats. The licensee acknowledged the inspector's contrants.
81-005/01T (2) - Power Operated Relief Valve Opened During
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Cold Shutdown. The licensee discussed the reportability of this item with the inspector on January 19, 1981. The inspector stated again the NRC's position that inadvertent operation of a power operated relief valve constituted abnormal degradation of the RCS pressure boundary, and expressed concern that this position was not being implemented by the licensee.
The Operations General Supervisor restated the NRC's position in the GS-0 Standing Instruction Book. The cause of the transient was loose mounting screws on the pressure transmitter's oscillator / amplifier which were corrected. The relief valve was open less than one minute and pressure decreased less than 6 psi (Initial pressure 230 psia). The ERV and Blocking Valve were closed and the Acoustic Monitor Alarm functioned properly.
81-001/01T, Indicated Reactor Power 4.5 Percent Low.
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licensee notified the inspector on January 15, 1981 cf discovery that indicated reactor thennal power was approximately six percent low with the reactor at 50 percent power.
Final investigation revealed that the cause was a drift out of calibration of a feedwater flow transmitter.
The power was indicating actually 4.5 percent low (non conservative).
Immediate corrective action was to readjust the Nuclear Instruments and permanent corrective action consisted of replacing and calibrating the feedwater flow transmitte.
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The licensee stated that they believed this event not to be reportable because the overpcwer trip (10 percent greater than existing indicated power) had always been operable and power had not exceeded 60 percent.
The inspector stated that Technical Specification Section 6.9.1.8.1, Prompt Notifications, states that an event such as the discovery of " Performance of structures, systecs, or components that requires remedial action or corrective measures to prevent operation in a manner less conservative than assumed in the accident analyses in the s,afety analysis recort or technical specifications bases", and requires a report to the NRC.
The inspector noted that Technical Specification 3.2.1, Linear Heat Rate assumes a maximun therral power uncertainty of 2% and that the situation of finding power 4.5% high necessitated corrective action to prevent operation in a manner less conservative than addressed in the Technical Soecifications. The licensee agreed to submit the subject report.
80-072/03L - Cocoonent Cooling Heat Exchanger Inoperable.
The
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inspector verified that the Generic Valve Maintenance Procedure, GEN-4, was modified by revision 3, dated January 22, 1981 as stated in the LER.
81-03/03L (1) - Auxiliary Feedwater Flow Low. The circu= stances
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surrounding this event are discussed in paragraph C below and in paragraph 6.
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The inspector requested the licensee to submit LERs 80-058/03L
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(1) and 80-058/03L (1).
The original submissions did not include adequate event descriptions and corrective actions.
Nurerous teetings and individual contacts were made with licensee personnel in an effort to upgrade their event reporting policy and procedure. The Nuclear Power Department Manager, Plant Superintendent, General Supervisor - Operations and other General Supervisor have been provided with recent NRC correspondence regarding the necessity for accurate, complete and factual event data reporting. The licensee acknowledged the inspector's comments and stated an effort was underway to upgrade LER cuality.
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c.
Auxiliary feedwater (AFW) flow to tio.11 and 12 Steam Generators (SGs) was found to be degraded on January 10, 1981, during plant heatup.
Flow to SG11 was 130 gpm, flow to SG12 was 350 gpm (480 gpm total). The cause was a flow restriction introduced pursuant to Maintenance Request MR-0-80-6093, issued on December 15, 1980 and signed off as complete on December 17, 1980.
That MR limited the maximum travel of flow control valves 1-CV-4511 and 1-CV-4512 to 75% open by an adjustment (handwheel)
not involving physical modification of the valves. The purpose of the flow restriction was to prevent AFW pump runout during automatic AFW start on low SG level, a condition which could occur on failure of the valve air supplies (which had not been upgraded as a part of the AFW auto-start modification).
The 75% limit had been evaluated (Bechtel Power Corporation letter of May 30,198')) as providing 460 gpm total flow to both SGs with one AFW pump running. A Combustion Engineering letter of June 4,1980 stated that 460 gpm flow at 1000 Nia would meet residual heat removal requirements; however, Technical Specification Basis 3/4.7.1.2 specifies that each AFW pump is capable delivering a total feedwater flow of 700 gpm at a total dynamic head of 2490 ft, sufficient to remove decay heat and to reduce reactor coolant temperature below 3000F (when shutdown cooling may be placed into operation).
10 CFR 50.59 permits facility changes which do not involve an unreviewed safety question without prior comission approval.
It defines an unreviewed safety question to include reductions in the margin of safety as defined in the basis for any technical specification, and requires submission of an application for
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license amendment for changes which involve an unreviewed safety question. Also, Technical Specification 6.5.2.7 requires OSSRC (Offsite Safety Review Comittee) review of proposed changes to procedures, equipment or systems which involve an unreviewed safety question.
Assessment of signficance of events of this nature includes consideration of whether, prior to flRC discovery, the licensee identifies, corrects and reports (if required) items in a timely fashion.
In this case, licensee identification occurred on January 11, 1981.
Flow was restored to 750 gpm on January 12, 1981. The resident inspector was orally notified on January 12, 1981. A 30 day report, LER 81-02/3L dated February 10, 1981, was submitted to the NRC. Action to upgrade the air supplies to the valves involved was subsequently accomplished, negating the need to reduce flow to prevent AFW pump runout.
No inadequacies in reporting or corrective action were identifie *
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The restriction of AFW flow existed from about December 17, 1980 to January 12, 1981, a 26 day period.
There were no mode 1 (above 5%
power) operations during that period.
Decay heat removal capacity requirements are based upon prolonged operation at high power levels.
AFW decay heat removal capacity with a 480 gpm flow limitation was more than capable of effecting the heat removal specified in the Technical Specification Bases during the 26 days in question. Subsequent to the reporting period the existence of additional information about review and assessment of this situation was identified. This item is unresolved pending evaluation of that information.
(317/81-02-03)
10.
Reactor Coolant System Corrosion Corrosion of carbon steel reactor coolant system has been identified in the suction piping to the Reactor Coolant Pumps. The cause was apparently RCS (Boric Acid) leakage from cracks in pump seal pressure sensing lines and/or bleedoff lines. The leakage ran down the pump casings and inside the piping insulation and finally out the breaks in the insulation to the containment floor.
The corrosion propagated circumferentially around the piping (18 inch arc pipe is 30 inch 0.D.) at a bimetallic weld interface (carbon steel elbow clad with stainless welded with inconel filler to a stainless safe end).
Penetration was a maximum of about 1/8 inch; pipe thickness is 3.6 inches nominal. Additional, apparently more general (as opposed to galvanic)
corrosion was observed on the elbow's outer radius longitudinal weld (carbon steel to carbon steel). This was in the suction piping to 22B Reactor Coolant Pump.
22A pump also had similar corrosion. The other Unit 2 pumps (21A and 218) appear not to be affected. The inspector took pictures of the corrosion in the 22B suction piping and forwarded them to Region I, NRC
for review.
Inservice examination results also revealed corrosion damage on the closure studs of two of the four Byron-Jackson reactor coolant pumps. Examinations were conducted per IE Information Notice 80-27 and Combustion Engineering reconinendations. The cause appears to be attack on the carbon steel studs by boric acid from Reactor Coolant System leaks. No leakage is indicated I
from the pump cover to casing joints which the studs close.
Twelve studs on the 22B pump and four on 22A pump were affected.
The studs do not appear to be as severely corioded as Unit 1 studs (refer to Inspection Report 317/80-26).
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The inspector questioned the licensee concerning the integrity /ISI results of the suction piping on Unit 1 Reactor Coolant Pumps because of the apparently generic nature of the corrosion. The licensee stated that, although none of these particular welds were examined during the recently completed (December,1980) Unit 1 outage, all four welds had been examined in the two outages preceding this one (two each outage).
In addition, the obvious external visual effects of the corrosion noted in the Unit 2 pump suction (rust on insulation, etc.) was not noted on the Unit 1 pump suctions.
The licensee comitted to inspect the pump suction piping for the two Unit 1 pumps which had experienced stud corrosion during an outage scheduled in late March or early April,1981 to inspect snubbers. This area (317/81-02-04;318/81-02-03) will be followed by the NRC.
11.
Survey of Explosive Detectors
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On January 22, 1981 the inspector was directed to perform a survey of portable gas detectors.
Explosive detectors manufactured by Ion Track Instruments, Inc., Burlington Massachusetts contain a nickel-63 source, which is exempt from NRC licensing.
At two nuclear power plants, these sources have been found to have removable contamire'. ion in excess of 0.005 microcuries.
The inspector examined the following instruments used for combustible gas analysis.
Operations: Gas Tech, Inc., Model GX-3, BG&E Serial 9415 Gas Tech, Inc., Model GX-3, BG&E Serial 8893 Mine Safety Appliances, Explosimeter Model 3, BG&E Serial 6393 Mine Safety Appliances, Explosimeter Model 3, BG&E Serial 6392 l
General Electric, Thermal Conductivity Gas Analyzer, Cat. No. 421D18361 Machine Shop:
Biomarine, Model 900R, BG&E Serial 9669 Discussions indicated these were the only portable gas analyzers used by the licensee at the site. The inspector further noted the non-safety-related designation of these instruments and that they were not included on l
a periodic calibration program.
The inspector discussed this aspect with the Industrial Safety Inspector, who acknowledged the inspector's comments.
No itens of noncompliance were identified.
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12.
Survey of Energency Procedures for ATWS Events The resident inspector reviewed licensee emergency procedures that address any or all of the following plant conditions:
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Failure to scram when required.
Failure to complete scram when initiated automatically or manually.
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Inability to move or drive Control Element Assemblies.
(CEAs)
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Failure to automatically scram when a parameter exceeds its trip value.
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Criteria for use of the Emergency Boration System.
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Reactor trip or scram.
Anticipated transient without scram.
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The inspector also reviewed the authorities and responsibilities of operators governing the use of the Emergency Boration System.
a.
Acceptance Criteria The following actions were used in judging the acceptability of procedures for coping with ATWS:
If an automatic scram should have occurred and has not, the licensee should:
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Depress the manual scram button immediately.
(2)
If rods still do not move, begin immediate emergency boration and attempt to drive rods in.
(3)
If rods fail to move, have power disconnect switch or breaker to rod holding coils opened.
(4) Continue efforts to effect shutdown.
The operator should h:ve complete authority to commence emergency boration and shoulr be responsible for doing this when the situation requires it.
Criteria for the use of emergency boration relative to inability to insert negative reactivity by other means should be included in emergency procedures.
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b.
Findings The following were included in this review.
(1)
E0P-1, Reactor Trip, Revision 5, dated 12/16/80.
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(2)
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E0P-13, Emergency Boration, Revision 4 dated 12/5/80.
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(3)
E0P-11, CEA Malfunctions, Revision 9 dated 1/16/80.
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4)
QAP-25, Plant Operations, Revision 8.
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5)
0I-6, Reactor Protection System, Revision 2, dated E/24/77.
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6)
OI-42, CEDM Operation, Revision 6 dated 3/28/79.
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(7)
Utility Group on AlWS, Report No.10, dated January 8,
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1981.
(8)
NRC Inspection and Enforcement Manual Temporary Instruction
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2515/46, Same Subject, dated December 10, 1980.
(9)
BG&E letter to the NRC (Lundvall to Eisenhut), Response to
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NUREG-0737 dated December 15, 1980.
Inspector review of the licensee's procedures revealed tSat the acceptance criteria were not incorporated directly. The licensee ces r.ot have a specific ATWS procedure. BG&E is a member of the Utility Group on ATWS. That group plans to discuss feasibility of standardized procedures or procedure guidelines at its next meeting (Reference 7).
E0P1, Reactor Trip, contains, as its first imediate action, a verification that all full length CEA's are in and reactor power is decreasing.
The licensee stated that this statement satisfies the intent of acceptance criteria (a) and (c), in that these are obvious actions if the verification is negative.
Inspector discussions with operators and licensed staff
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confirmed this interpretation.
Acceptance criterion (b), emergency boration, is adequately addressed in the referenced procedures and the operator's authorities are properly defined. Criterion (d) is non-specific, and actions to be taken necessarily depend on problems encountered with scram and boration systems.
The licensee stated that they did not want to change their E0Ps to literally conform to the acceptance criteria because NUREG-0737 action item I.C.1, Evaluation and Development of Procedures for Transients and Accidents, is being perfonned by the Combustion Engineering Owners Group. A submission to the NRC is expected by May 1,1981 and the associated procedure changes are to address ATWS concepts. The licensee also stated that their licensed staff had received ATWS training on the simulator during calendar year 1980, that a comprehensive ATWS procedure would have additional steps such as increasing feedwater flow to a maximum.
In addition a separate procedure would be more appropriate than the Reactor Trip procedure because this is not necessarilv appropriate (i.e. for ATWS a trip -should have occurred but did not, so the opeiator would not follow actions in the Reactor Trip procedure).
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The inspector concluded that, although the survey acceptance criteria are not literally satisfied, the licensee's Emergency procedures meet current requirements in this area and the licensee is progressing towards development of an ATWS procedure.
No items of noncompliance were identified.
13.
Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee pursuant to Technical Specification 6.9.1 and 6.9.2 were reviewed by the inspector.
This review included the following considerations: The report includes the information required to be reported by NRC requirements; test results and/or supporting information are consistent with design predictions and performance specifications; planned corrective action is adequate for resolution of identified problems; determination whether any information in the report should be classified as an abnormal occurrence; and the validity of reported information. Within the scope of the above, the following periodic reports were reviewed by the inspector:
December,1980 Operations Status Reports for Calvert Cliffs No.1 Unit
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and Calvert Cliffs Unit No. 2, dated January 14, 1981.
14.
Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable, items of noncompliance or deviations.
Unresolved items addressed during this inspection are discussed in Paragraphs 2, 7 and 9 of this report.
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15.
Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A summary of inspection findings was also provided to the licensee at the conclusion o' the report period.
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