IR 05000317/1981004
| ML20009F978 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 05/13/1981 |
| From: | Architzel R, Callahan C, Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20009F971 | List: |
| References | |
| 50-317-81-04, 50-317-81-4, 50-318-81-04, 50-318-81-4, NUDOCS 8108030213 | |
| Download: ML20009F978 (20) | |
Text
~ 50317-81-01-11 50318-81-01-01
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' 50317-81-09-19 50318-81-01-23 50'317-81'-01-13 50318-81-02-04 50317-81-01-12 50318-81-02-12 50317-81-02-03 50317-81-01-23 U. S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTI0'; AND ENFORCEMENT
REGION I
50-317/81-04 Report No.
50-318/81-04 Docket No.
50-3T7; 50-318 OPR-53 C
License No. OPR-69 Priority Category C
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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 Inspection Conducted:
February 2-March 1, 1981 Inspectors:
P. 0 b %, hi.
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R. E. Architzel, Senior Resident Reactor Inspector date R e. /k %, k. L e/i?/s e C. J. Callahan, Resident Reacter Inspector date date Approved by:
8. O N Mt dh r//r/El i
E. C. McCabe, Jr., Chief, Reactor Projects date Section No. 2 B, Reactor Projects Branch 2 Inspection Summary:
Inspection on February 2-March 1, 1981 (Combined Report Nos. 50-317/81-04 and 50-318/81-04)
Areas Inspected:
Routine, onsite regular and backshift inspection by the resident inspectors (45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br />, Unit 1; 51 hours5.902778e-4 days <br />0.0142 hours <br />8.43254e-5 weeks <br />1.94055e-5 months <br />, Unit 2).
Areas inspected included the control room and the accessible portions of the auxiliary, turbine, service, Unit 2 containment and intake buildings; radiation protection; physical security; fire protection; plant operating records; licensee action on previous inspection findings, IE Bulletin 79-25; Fuel Misorientation (Unit 2); Unit 2 RCP Lube Oil Collection System Modifications; and reporting to the NRC.
Noncompliances - Unit 1 - Reducing AFW flow below operability value (Paragraphs 2 and 14); Unit 2 - Inadequate procedures for core loading verification (Paragraph 10).
Region I Form 12 (Rev. April 1977)
8108G30213 810715 PDR ADOCK 05000317
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i DETAILS 1.
Persons Contacted The following technical and supervisory level personnel were contacted:
R. F. Ash, Chief Nuclear Engineer, EED E. R. Bauer, Modifications Supervisor D. G. Buffington, Fire Protection Inspector J. T. Carroll, General Supervisor, Operations G. C. Creel, Manager, Production Maintenance Department S. M. Davis, Senior Engineer, Operations R. E. Denton, General Supervisor, Training and Technical Services C. L. Dunkerly, Shift Supervisor W. S. Gibson, General Supervisor, Electrical and Controls J. E. Gilbert, Shift Supervisor J. R. Hill, Shift Supervisor R. P. Heible, Principal Engineer, Technical Support L. S. Hinkle, Supervisor, Instrument Maintenance J. F. Lohr, Shift Supervisor R. O. Mathews, Assistant General Supervisor, Nuclear Security J. A. Mihalcik, Senior Engineer Fuel Management N. L. Millis, General Supervisor, Radiation Safety B. C. Rudell, Engineer, Technical Services L. B. Russell, Plant Superintendent R. L. Wenderlich, Engineer, Operctions M; J. Warren, Engineering Technician W. L. Whitaker, Assistant General Foreman, PMD D. Zyrick, Shift Supervisor Rt W. Talley, Jr., Assistant General Foreman, PMD 2.
Licensee Action on Previous Inspection Findings (Closed) Unresolved Item (318/80-05-03):
Replace Rod Drive Motor Generator Sets Voltage Regulators.
The inspector reviewed Maintenance Request 0-80-2095 completed on September 15, 1980.
This maintenance request i
documented the replacement and testing of the voltage regulators with an improved model (No. 73) which resulted in a stable output during parallel operations.
(Closed) Unresolved Item (317/80-16-08; 318/80-15-07):
Revise Alarm Procedures for Subcooled Margin Monitors Alarm Window Procedure for Panel IC06. Alarm E-16 has been revised (Revision 14) to reflect ins +.allation I
of the subcooled Margin Monitor (alarms at 50 F). The operator is directed l
to appropriate E0P's and informed of the indication of loss of forced circulation or loss of coolant.
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i (Closed) Noncompliance (317/80-21-01) and Unresolved Item (317/80-21-02):
Failure to Implement Purchase Specifications Requiring Spent Fuel Rack Construction and Resubmittal of soplication to change the Facility License.
The licensee responded to the item of noncompliance in a letter dated December 31, 1981.
The licensee changed the specification for construc-
tion of the racks to reflect the as-built technique used which was in conformance with the American Institute of Steel Construction (AISC)
i Code.
In addition, the licensee submitted a letter on January 29, 1981 i
supplementing their request for amendments 47 and 30 for. Units 1 and 2, respectively.
The letter addressed the as-built configuration and requested NRC review and concurrence with the change in specifications (stated in Safety Evaluation) from NF to AISC. The inspector attended a meeting in Bethesda, Maryland on February 26, 1981.
The licensee and vendor (NES)
presented justification for the specification change and a history of past problems with Spent Fuel Rack spot welds in the NES supplied racks.
The Operating Reactors Project Manager, and other representatives from i
the Office of Nuclear Reactor Regulation and Standards were present.
The inspector stated that NRC, I&E actions had been completed and any future
inspections regarding this particular aspect of Spent Fuel Rack installation would follow NRR review of the licensee's submittal.
(0 pen) Inspector follow item (318/81-02-04):
Corrosion of Carbon Steel RCS Components: Maintenance Requests MR-81-2195 and MR-81-2209 were
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reviewed to verify replacement of 4 studs on RCP No. 22A and 16 studs on RCP No. 22B in accordance with the commitments made in Baltimore Gas and Electric letter of February 5, 1981 to R. A. Clark, Chief Operating Reactors Branch No. 3, Division of Licensing.
During inspection conducted pursuant to IE Information Notice 80-27, Degradation of Reactor Coolant Pump Studs, several instances of carbon steel clamping device wastage has been identified.
In addition to the reactor coolant pump stud wastage, corrosion has been discovered in No. 12 steam generator primary manway fasteners, Unit 2 pressurizer manway fasteners, and safety injection
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reactor coolant loop 2.B check valve studs. The licensee has initiated a comprehensive inspection program and will submit a report of the results by March 7, 1981.
(Change) Unresolved Item (317/81-02-03):
Restriction of AFW Flow Below T.S. Basis.
This item was reinspected and changed to an item of non-j compliance (Paragraph 14).
3.
Review of Plant Operations
a.
Plant Tour
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At various times the inspector toured the facility, including the Control Room, Auxiliary Building, Turbine Building, Outside Peripheral Area, Security Buildings, Health Physics Control Points, Diesel Generator Rooms, Service Building, Intake Structure and Unit 2 Containment.
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Sampling checks of the following were made.
Radiation controls established by the licensee, including
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posting of radiation areas, conditions of step-off pads and disposal of protective clothing.
Control Room manning, including observation of shift turnover
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and panel walkdowns.
Systems and equipment checks for fluid leaks or abnormal piping
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vibration.
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Seismic restraint and hydraulic snubber checks to verify adequate installation and fluid levels.
Plant housekeeping conditions, including general cleanliness
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and 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, safety-related valve position indi-cation, and annunciator status.
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Whether proper access controls were established.
The following significant Unit 1 Annunciators were in the alarm condition at the close of this report period.
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RC Loop II Margin to Saturation Low (E-14) MR-C-80-154.
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Power Level Rate Bypass S/U Range (D45), normal operation above 12% power.
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Reg. Group Withdrawal Inhibit (D-31) MR-0-81-436.
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Feedwater Heater Level High (C-9).
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S/G Auxiliary Feed Discharge Suct Press Low (C-47), normal operation with low auxiliary feedwater discharge pressure.
I Unit 1 Main Vent Radiation Monitor (IK 26-05) MR-0-80-1230.
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21 S/G Blowdown Tank RMS Flow Low (IK 26-19), Unit 2 outage.
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The following significant Unit 1 Annunciators were out of service at the close of this report period.
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12B SI Tank Press Level to (H-43) MR-081-527.
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11B SI Tank Press Level Lo (G-35) MR-0-81-862.
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Unit 2 Containment Air Lock (T-10). Air locks open for outage.
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Charging Header Flow Pressure Low (F-45) MR-0-81-689.
Radiation Monitor Level Hi (F-21) MR-0-80-96.
Failed fuel
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element detector out of service.
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Letdown RV 345/354 Li fted (F-2) MR-0-81-104.
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Channel A&B Boric Acid Heat Tracing (F-3 and F4).
No MR issued, FC" unde-consideration.
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11A and 11B RCP Seal Temperature High Pressure (E-51 and E55)
MR-0-81-863, MR-0-81-864.
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CEA TCB 10 Open (D-4) normal operation with part length CEA sup31y breaker open.
During a tour of the Auxiliary Building the inspector noted that housekeeping was inadequate in the Boric Acid Storage Tank Room for Unit No. 2.
Pictures of the crystalline Loric acid on the floor and in the vicinity of several pipe supports were provided to the Plant Superintendent.
The inspector expressed concern to the licensee about the cleanliness of this area and requested the licensee evaluate the support integrity following cleanup. This item is unresolved (318/81-04-01) pending completion of the licensee's actions.
b.
Review of Operating Logs, Records Logs and records were reviewed to identify significant change 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 r- *ewed 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 Operator's Log
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Nuclear Plant Engineer - Operations Notes and Instructions
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Unit I and 2's Control Room Daily Operating Logs (sampling review)
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Service Building Operator's Log
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Annunciator Status Log
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Shift Turnover Sheet
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Jumper Log
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Operations Maintenance Request File (sampling review)
No unacceptable conditions were identified.
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4.
Review of Events Requiring One Hour Notification of the NRC The circumstances surrounding the following events requiring prompt (one hour) notification of the NRC via the dedicated telephone (ENS-line) were reviewed.
At 8:43 p.m. on February 4,1981 a loss of shutdown cooling and
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Engineered Safeguards Fectures Actuation System (ESFAS) actuation occurred on Unit 2.
An electrician performing preventive maintenance on the 21 Vital A.C. bus inverter mistakenly opened the back up power supply breaker to which the bus had been shifted.
The bus (one of 4 Unit 2 Vital 120V A.C. Busses) powers one of four ESFAS sensor cabinets and one of the two GSFAS logic cabinets.
Subsr.quent reenergizing of the bus resulted in an actuation of the 4 KV Bus 21 JSFAS logic and stripping of this bus followed by normal start (less than 10 seconds) of 21 Diesel Generator to repower the bus.
Shutdown cooling was isolated because a motor operated valve in the suction piping (one of two similar valves in series) closes automatically on a sensed overpressure condition (the sensor lost power, failing high) to protect the low pressure piping from o/erpressurizing.
Redundant decay heat removal was available per IE Bulletin 80-12
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(water in the Spent Fuel Pool).
Systems were returned to normal power and shutdown cooling restored within 17 minutes.
The inspector noted during review of this event that Preventive Maintenance Card, 2-18-E-R-1, Clean and Inspect Vital A.C. Inverters 21, 22, 23, and 24, Revision 0 dated May 21, 1977 was not clear regarding action to be taken by an electrician with respect to the power supplies in that the breakers were only listed, both DC c."d AC feeds.
This item is unresolved (318/81-04-02) pending revision of the referenced PMS card to clearly specify steps to be taken to perform the preventive maintenance.
ENS Notification was completed as required, 5.
a.
Review of Licensee Event Reports (LER's)
The inspector rev'ewed LER's submitted to the NRC:RI office to verify that the details of the avent were clearly reported, including the accuracy of the description of cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup.
The following LER's were reviewed:
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Docket No. 50-317 (Unit No.1)
DATE DATE LER NO.
OF EVENT OF REPORT SUBJECT
- 81-02/3L 01/11/81 02/10/81 AFW to Steam Generators was only 480 GPM.
Regulating Valves Reset to Flow of 750 GPM.
81-04/3L 01/19/81 02/17/81 During Test #14 Containment Coolcr 8" SRW Discharge Valve Failed to Ops.n 81-05/3L 01/19/81 02/17/81 During Surveillance Test #14 Containment Cooler Would Not Start in Slow Speed 81-06/3L 01/13/81 02/12/81 SG #11 Level "0" was Placed Out of Ser-vice to Correct Problem With Reference Leg 81-07/3L 01/12/81 02/11/81 ESFAS Sensor Channel ZE f.c #12 SG Pressure Placed Out of Service to Correct Erroneous Sensor Input
- 81-08/01T 02/03/81 02/17/81 Backup Fire Hoses Were Not Routed as Required by T.S. 3.7.11.4.a 81-10/3L 01/23/81 02/20/81 During Power Operation, the Nipple on Valve CV-5178, Salt Water Emergency Return Isolation From ECCS Pump Room Coolers, was Broken Off Docket No. 50-318 (Unit No. 2)
81-01/3L 01/07/81 02/05/81 Channel B Reactor Protective System Trip Units for Hi Power TM/LP and AFD Bypassed for Trouble-Shooting the Linear Power Range Instrument 81-02/3L 01/23/81 02/06/81
- 12 Diesel Generator Started Auto-matically for no Apparent Reason 81-03-3L 1/23/81 02/20/81 In Mode 6, Shutdown Cooling Flow was Stopped for 5 Minutes
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~_/04/81 03/04/81 Loss of Shutdown Cooling During
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Preventive Maintenance (see para. 4)
i 81-06/3L 01/13/81 02/12/81 During Test #12 Generator Breaker did not Close to #21 4 KV BUS
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j 81-08/3L 01/13/81 02/12/81 ESFAS Channel 20 was Deenergized for
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Maintenance on #22 Steam Generator
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b.
For.the LER's 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 ccnducted in accordance with Technical Specifica-tions 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. One item of noncompliance was identified as noted in paragraph 2.
6.
IE Bulletin Followup
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The inspector reviewed licensee actions on the following IE Bulletins (IE2s) to determine that the written response was submitted within the required time period, that the response included the information required including adequate corrective action commitments, and that licensee management had forwarded copies of the response to responsible onsite management.
The review included discussions with licensee personnel and observations and review of items discussed below.
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IEB 79-25, Failure of Westinghouse BFD Relays in Safety-Related Systems.
i.iis bulletin had previously been inspected during NRC Inspection 317/80-11; 318/80-10 conducted on July 1-31, 1980.
During that inspection it was noted that the bulletin response was not accurate in that additional relays of the type addressed were installed and a replacement program was not in progress.
The licensee stated that a revised response would be submitted to the NRC by August 31, 1980 accurately addressing the status of W BFD relays. The licensee had not submitted a revised response as of March 3, 198*., although the licensea has been contacted again by the inspector (both EED and NPD personnel) on various occasions since August 31, 1980.
This bulletin remains OPEN.
7.
Plant Maintenance During the inspection period, the inspector observed various maintenance and problem investigation activities.
The inspector reviewed these activities to verify compliance with regulatory requirements, including those stated in the Technical Specifications; compliance with the administrative and maintenance procedures; compliance with applicable codes and standards; required QA/CC involvement; proper use of safety tags; proper equipment alignment and use of jumpers; personnel qualifi-cations; radiological controls for worker protection; fire protection; retest requirements and ascertain reportability as required by Technical Specifications.
The following activities were ircluded during this review:
PM Card 1-36-M-R-1, AFP Turbine Mechanical Maintenance, February 16,
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MR-0-81-658, Unit 1, No. 11 AFP Inner Turbine Bearing Oil Dirty, Change / Investigate.
Iriitiated 2130, February 16, 1981.
No unacceptable conditions were identified.
8.
IE Circular Review The following IE Circulars were reviewed o' site to determine that the circular was received by licensee management, a review for.pplicability was performed, and that further action taken or planned was appropriate.
IE Circular No. 79-05, Moisture Leakage in Stranded Wire Condi:ctors.
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No ur. acceptable conditions were identified.
9.
Obser'/ation of Physical Security he residant inspector checked, during regular and off-shift hours, on hether salected aspects of security met regulatory requirements, physical security plans and approved procedures, a.
Physical Protection Security Organization Observations and personnel interviews indicated that a full
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time member of the security organization with authority to direct physical security actions was pic:ent, as required.
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Manning of all three shifts on various days was observed to be as equired.
b.
Physical Barriers Selected barriers in the protected area (PA) and the vital areas (VA) were observed and random monitoring of isolation zones was performed. Observations of truck and car searches were made.
c.
Access Control Observations of the following items were made:
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Identification, authorization and badging Access control searches
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Escorting Cnmmunications
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Compensatory measures when required.
No unacceptable conditions were identified.
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10.
Fuel Misorientation, Unit 2 On February 10, 1981 the licensee was informed by Combustion Engineering (CE) of an error in the CE fuel loading program.
This errer was dis-covered during formal documentation and QA of the Calvert Cliffs and Unit 2 Cycle 4 full core loading pattern to be supplied by the vendor.
The error involved a reversal of the alpha-numeric coordinate system resulting in the irradiated assemblies (eighty-eight) with the exception of the center assembly being analyzed oriented plant north. As a design feature the licensee has historically oriented Unit 2 Fuel, both in the spent fuel pool and in the reactor South and Unit 1 Fuel North. This loading minimizes the possibility of a misorientation by allowing a uniform orientation.
The licensee loaded the core according to the preliminary core map transmitted by the vendor.
The preliminary core load did not include the previous core locations of the irradiated fuel.
The licensee stated that a verification of the motion of each assembly is normally conducted by comparing the previous cycle location with the new location.
This check would have identified the misloading upon receipt of the final core load.
The licensee stated that a two dimensional analysis had been performed to evaluate the consequences of the loading and a determination made that the total Planar Radial peaking factor would have been increased to 1.58 during the most limiting part of Cycle 4, which was below the T.S. Limit (less than 1.620).
The licensee did not perform a detailed analysis but reoriented the eighty-eight assemblies to plant north.
Because the Calvert Cliffs core uses quarter core symmetry relocation to the quadrant in which the irradiated assemblies had been analyzed was not necessary, merely a reorientation (180 degrees) of the fuel to the
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analyzed geometry within the quadrant.
The inspector reviewed a letter dated February 13, 1981 from Combustion Engineering to Baltimore Gas and Electric Company, " Unit 2 Cycle 4 Core Loading Pattern." This letter documented the alpha-numberic reversal used to determine the preliminary core loading and stated the error was discovered during formal documentation and QA of the loading pattern.
The letter further stated that it was a normal course of action to transmit a formal letter documenting the final core loading prior to plant startup.
The inspector noted that as of February 10, 1981, the date of notification by CE, the Unit 2 core loading had been completed and verification completed pursuant eo the licensee's procedure (FH-6, Core Reloading Procedure Unit 2, Revision 6 dated Jaunuary 23, 1981).
Although licensee procedures did not require further checking of the core load, the licensee stated that a detailed review of the final core load as supplied by the vendor was always made, including an assembly by assembly verification of previous and present location (core, fuel pool, or new fuel storage). This check would have identified the misorientation.
The inspector also reviewed the Safety Evaluation for Calvert Cliffs Unit No. 1, Cycle 5, issued December 12, 1980 which stated the following regarding a fuel loading error.
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Anticipated Operational Occurrence (A00):
"2.4.1.3 Fuel Loading Error This A00 nas not previously been calculated for CCNPP-1 as required by our Standard Review Plan (SRP) Section 15.4.7.
BG&E has committed to submit an analysis within 6 months of the issuance of this SE.
The event has previously been prevented by strict procedural control. We find this acceptable for one additional cycle if the procedures are acceptable.
Procedures for verifying that fuel is loaded into proper core locations are the same as the procedures which were used for the reference cycla.
Presently, there are two methods which are used to determine a fuel mis-loading.
These are a visual core loading verification and CEA symmetry checks.
The visual core loading check not only verifies the placement of assemblies in the proper core location but also verifies the proper orientation of each assembly.
The CEA symmetry checks will be performed as a part of the Cycle 5 startup test program to insure that fuel mis-loadings, which might cause a sufficient deviation from the planned design power distributions to impact the safety analyses, would be detected. We, therefore, find these two procedures for verifying that fuel is properly loaded to be acceptable. "
The Unit 2 Cycle 4 Safety Evaluation used Unit 1 Cycle 5 as a reference cycle.
Therefore, the comments regarding the Fuel Loading Error are equally valid.
The inspector noted that because the formal procedural centrols in place by the licensee did not include provisions to ensure that a final, approved core loading pattern was in place prior to startup following refueling, the procedures were inadequately implemented.
This is an item of noncompliance (318/81-04-03).
11.
txceotion to ASME,Section XI, B&PV Code, 1974 Edition and Addenda Through 1976 During installation of a 2" motor operated valve in the Unit 2 Safety Injection System (to allow for remote post LOCA core flush capability) an arc strike occurred on the pipe (ASTM-A-376, Schedule 40) adjacent to the socket weld.
In accordance with the code (for ccmponents) the licensee ground out the arc strike, penetrant tested the area of grinding, welded the area, ground weld flush with pipe, penetrant tested after grinding
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the weld flush and hydrostatically tested to 625 psig (125 percent).
Because of adjacent piping interference and location of the arc strike adjacent to the socket weld, radiography of the repair was not feasible.
The inspector reviewed the code requirements with the licensee and inspected the geometry of the installation.
The licensee stated that an exception would be requested to the Section XI requirements for radio-graphy in this instance.
No unacceptable conditions were identified.
The submission of the exemption request will be followed (318/81-04-04).
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12. Unit 2 haactor Coolant Pump Lube Oil Collection System Modification
Amendment 31 to License No. DPR69 for Unit 2 addressed the NRC's evaluation of fire hrotection of the Reactor Coolant Pump lube oil collection system.
The Safe'ty Evaluation stated that the. I&E Resident Inspector would confirm acceptability of the installation.
The inspector reviewed Facility Change Request 79-1023, Units 1 and 2, and supplements 1 - 8 (thruugh December 6, 1980).
The physical installa--
tion of the sub.iect modification was also examined on all four Unit 2 Reactor Coolanc Pumps.
The change was completed prior to restart.
No unacceptable conditions were identified.
13.
10 CFR 50.72 Reporting Requirements In a letter dated February 17, 1981 to NRR's Division of Licensing, BG&E discussed tneir interpretation of 10 CFR 50.72 and provided a copy of specific guidelines which have been developed for site personnel use to assist them in fulfilling the Reporting Requirements.
The inspector reviewed the enclosed guidance which was a portion of the most recent change (Change 4 dated February 23, 1981) to CCI/18 D, Reporting Requirements.
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The inspector ii formed the licensee that two subparts of the CCI were
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misinterpreted.
The subparts in question are listed below followed by the licensee's n)tes.
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50.72(a)(5)
/ iy event requiring initiation of shutdown of the nuclear power plant in accordance with Technical Specification Limitiac 4.anditions for Operation.
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This item should be reported when the unit is placed in
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50.72(a)(8)
Any accidental, unplanned, or uncontrolled radio-l active release.
(Normal or expected releases from maintenance or other operational activities are not
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included).
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For gaseous activity, this item should be reported anytime either main vent monitor count rate increases to a count rate equivalent to 25% of the limits specified in Appendix'
B Technical Specification 2.3.8.1.if the alarms and
increases in count rates cannot be attributed to main-tenance or operational activities in progress such as
Reactor Coolant diversion.
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Regarding item (5), the Technical Specifications require the plant to be shutdown (either modes 3, 4 or 5) following a period of time during which operation can be continued in the degraded condition Following expiration of the initial in erval of time an additional, specified time period is allowed to reach the stated shutdown condition.
For example, Technical Specification 3.0.3 requires the facility be placed in at least HOT STANDBY (Mode 3) within one hour for a condition in excess of those addressed in Technical Specifications.
If the situation requiring the shutdown is corrected within the specified time period, completion of the action is not required.
The inspector stated that 10 CFR 50.72 (5) clearly requires reporting as a significant event those situations where the Technical Specifications require the initiation of a shutdown. That included anytime the facility was being operated in a condition requiring a shutdown.
Regarding item (8), the inspector stated the NRC would enforce as failure to report pursuant to 10 CFR 50.72 any unplanned event resulting in an increase of 50% above background release rate for airborne radioactive materials, which was not the subject of a 10 CFR 50.72 report to the NRC Operations Center, Bethesda, Maryland.
This item is unresolved (317/81-04-01; 318/81-04-05) pending either formal clarification of the misinterpretation or appropriate revision of CCI 118 D.
14.
Degradation of Unit 1 Auxiliary Feedwater (AFW) Flow This item was previously inspected and documented in Inspection Report 317/81-02 and left Unresolved pending additional inspection.
The findings detailed are repeated below for clarity.
(Paragraph 6 and Paragraph 9.c)
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The inspector reviewed Maintenance Request 0-80-6093 which was issued to imit the maximum travel of Unit 1 Feedwater Control valves to 75% open. The purpose was to prevent pump runout upon failure of control air.
This modification was required to support completion of Facility Change Request 79-1060 and 79-1035 issued for installat on of an auxiliary feedwater pump automatic start feature.
'he maintenance request form was completed in accordance with Calvert Cliffs Instruction 200D, Change 1.
Although this action modified the system flow path, the senior control room operator did not require in operational test to determine if the minimum specified auxiliary feedwater flow requirements were satisfici.
This area is addressed in detail in paragraph 9.c.
9.c.
Auxiliary feedwater (AFW) flow to No.11 and 12 Steam Generators (SGs1 was found to be degraded on January 10, 1981, during planc heatup.
Flow to SG11 was 130 gpm, flow to SG12 was 350
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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 sinned of as compieted on December 17, 1980. That MR limited u. a max mum travel of flow control valves 1-CV-4511 and 1-CV-4512 to 5% 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 AP' 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 30,1980) as providing 460 gpm total flow to both SGs with one AFW pump running. A Combusion Engineering letter of June 4. 1980 stated that 460 gpm flow at 1000 psia would meet res' dual heat removal requirements; however, Technical Specifir.ation Basis 3/4.7.1.2 specifies that each AFW pump is capable of 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 300 degrees F (when shutdown cooling may be placed into operation).
10 CFR 50.59 permits facility changes.which do not involve an unreviewel safety question without prior commission approval.
It defines an unreviewed safety question to include reductions in the margin of safety as defined in the basis for acy tech-nical specification, and requires submission of an application for license amendment for changes which involve an unreviewed safety question.
(Also, Technical Spec'fication 6.5.2.7 requires OSSRC (Offsite Safety Review Comnittee) review of proposed changes to procedures, equipment or systems which involve an unreviewed safety question.
Assessment of significance of events of this nature includes consideration of whether, prior to NRC 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 IC, 1981, was submitted to the NRC. Action to upgrade the air supplies to the valves involved was subsequently accomplished, negating the nced to reduce the flow to prevent AFW pump runout.
No inadequacies in reporting or corrective action were identified.
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
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480 gpm flow limitation was more than capable of effecting the
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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)
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During this inspection period, the following additional information and l
errors in the above description were identified.
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Actual Mode 1, 2, a ;d 3 operations involved were:
From To Houis Mode 12/20/81-3:30 am 12/21/81-7:00 pm 39.5 3 (Hot Standby)
12/21/80-7:00 pm 12/22/80-9:27 pm 26.5 2 (Startup)
12/22/80-9:27 pm 12/23/80-1:05 am 3.6
12/23/80-1:05 am 12/24/80-7:16 pm 42.2
12/24/80-7:16 pm 12/25/80-2:40 am 7.4 1 (Power Operation)
12/25/80-2:40 am 12/25/80-2:51 am 0.2
12/25/80-2:51 am 12/26/80-9:00 pm 42.1
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1/9/81-12:23 am 1/10/81-1:55 pm 37.5
1/10/81-1:55 pm 1/11/81-3:23 am 13.5
1/11/81-3:23 am 1/12/81-4:10 pm 36.8
Total Mode 1, 2, 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> - 249.3 Mode 1 Subtotal Hours - 44.2 Mode 2 Subtotal Hours - 82.4 Mode 3 Subtotal Hours - 122.7 The restriction of the AFW Regulating Valve full open position had
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l been performed under Supplement 5 (approved 7/9/80) to FCR 79-1035.
A 10 CFR 50.59 Safety Analysis had been performed for this FCR Supplement. The analysis was dated June 12, 1980, checked June 16, 1980, and reviewed by the P0RSC on July 9, 1980 and the OSSRC in Meeting 80-16.
The Safety Analysis addressed both the addition of single failure proof time delayeu automatic start of AFW flow to the Steam Generators and reduction of initial flow by using the api Regulating Valve handwheels.
The summary statement concluded that the ha.idwheel restriction allowed for sufficient AFW flow to maintain hot standby with worst case decay heat load.
The section addressing the margin of safety as det'ned in the technical specification basis was not completed.
The licensee stated that this omission was an oversight, however they did not believe the T.S. basis required that the stated flow be available solely from the Control Room, and that the system could have achieved the basis flows by local manual operatio l
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The inspector also reviewed the Special Instructions accompanying FCR 79-1035, Supplement 5, which included the following statement:
" Note that use of CV handwheel as a limit stop does not prevent use of the MCR (Main Control Room) HIC (Hand Indicating Controller) to further reduce valve opening if air is available. To allow for increased rate of cooldown after AFW is initiated, remove handwheel restriction on AFW regulating valves."
Although other aspects of the Special Instruction were incorporated into Operating Procedures and training as discussed below, this particular aspect of the Special Instructions was not addressed further.
The inspector reviewed training Information Sheets for FCR 79-1035, Interim Modifications to Auxiliary Feedwater Systems, which were prepared and training conducted for all licensed personnel by July, 1980.
This training document did not address the maximum flow setting of the auxiliary feedwater regulating valves because this portion of the FCR, Supplement 5, was approved in July, 1980 and not implemented until December, 1980.
The Informatior. Sheet did contain the following statement:
"In the future, the system will be aligned so that feed will automatically be started when the pumps come on.
These changes (will) include supplying IA from the saltwater system air compressors to the AFW Reg. valves and administratively controlling the settings of the AFW reg. valves and AFW pump speed controllers and HIC's."
The inspector also reviewed the training Information Sheets associated with FCR 79-1060, Upgrade AFP Auto Start to Safety Related.
The applicable portion of this training notice (for all licensed personnel) identified that Instrument Air (Safety Related) would be added to the ~eedwater Regulating Valves air regulators.
0I-32, Auxiliary Feedwater System, Revision 13 dated September 25, 1980 and E0P-14, Loss of Instrument Air, Revision 2, dated December 16, 1980, were reviewed.
Tia inspector checked the notes addressed in whe special instructions accompanying the Safety Evaluation for FCR 79-1035, Supple-ment 5.
These included the following:
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A note that, to prevent cavitation, a flow of 800 gpm should not be exceeded.
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note to dispatch personnel to trip one AFW pump, if two are running d Instrument Air is lost, to avoid cavitation.
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A caution note not to exceed the maximum cooldown rate on the Steam Generator.
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Section on Remote Operation discusses decreasing flow by locally restricting Feedwater Regulating Valve by the handwheel in the event of loss of instrument ai,
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Based on.a result of the above reviews and previous inspections, the inspector concluded that the licensee has completed TMI Action Plan Items II.E.1.2 (NUREG 0660) Sub items (descriptions defined in NUREG 0737) 1.A, Control Grade AFW Initiation, and 2.C, Safety Grade Flow Indication on both Units 1 and 2.
Completion of Safety Grade Auto Start (NUREG 0737 description 1.B) including automatic ini iation of flow to the Steam Generators will be examined in future NRC inspections.
Note:
The licensee considers automatic initiation of flow to be an Unreviewed Safety Question and has procedurally required the AFW Regulating Valves Main Control Room Hand Indicating Controllers ba maintained in the closed position, such that operator action is required to actually feed a Steam Generator (BG&E letter dated November 8,1979).
Further reviewing documents associated with AFWS auto start, the inspector noted that NUREG 0660 recognized that several licensees considered AFWS auto start to be an Unreviewed Safety Question.
Task II.E.1 states in part:
"NRR has issued letters to the licensees of plants with manually initiated AFW systems requesting them to (1) submit design proposals to meet NUREG-0578 Recommendations 2.1.7.a and 2.1.7.b, and (2) analyze a potential unresolved safety issue (identified by some of these licensees) that relates to automatic AFW initiation with a postulated main steamline break inside the containment structure (MSLBIC) and its effect on con-tainment pressure design capability and return to reactor power.
In March 1980, NRR issued a letter to all licensees informing them that NRC approval is no longer required prior to implementing modifications needed to meet control grade requirements of 2.1.7.a. "
The inspector also reviewed IE Bulletin 80-04, Analysis of a PWR Main Steam Line Break with Continued Feedwater Addition, and the licensee's responses dated January 25,1980 (tc NRR, Automatic Initiation of AFWS),
February 12, 1980, and May 21, 1980.
The January 25, 1980 response again
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stated that the licensee would not implement initiation of AFW flow to the Steam Generators without approval by the NRC.
In the licensee's response to Bulletin Question 1, the licensee addressed the NRC's concern ("In your.eview (pursuant to IEB 80-04) consider your ability to detect and iso' ate the damaged steam generator from these sources and the ability of the pumns to remain operable after extended operation at runout flow"):
"The auxiliary feedwater (AFW) pumps cannot run without severe cavitation at the runout flow used in the analyses described in Reference (a). With two pumps operating, against maximum steam generator pressure, a maximum combined flow rate of 960 gpm can be reached without cavitation to either pump.
Therefore, in order to protect the auxiliary feedwater pumps, administrative controls shall ce initiated on June 1, 1980 (pending NRC approval) to set and maintain the AFW pump discharge valve at a 57% open position. This setting will prevent cavitation of the pump at all pressures above the steam generator isolation signal setpoint, while providing adequate flow to the steam generators in order to maintain an adeouate heat sink."
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With respect to Bulletin Item 3, the licensee concluded that a return to power condition will not occur nor will a containment overpressurization occur following a Main Steam Line Break. This analysis considered a ramp to 5% full feedwater flow in 60 seconds and delayed actuation of the AFWS for 180 seconds following a steam line break. The inspector had no further questions regarding this aspect of the licensee's response to IEB 80-04, however noted that the NRC's office of Nuclear Reactor Regulation will be evaluating the licensee's response.
The inspector also reviewed a BG&E letter dated January 26, 1981, docu-menting requests for documentation of selected licensee actions on NRC reconnendations as a result of a telephone conversation with the NRC held on January 23, 1981. The letter stated:
"A letter from Lundvall to Clark, dated August 27, 1980, discussed our plans to implement NUREG-0578 item 2.1.7a.
These items are further discussed in our November 18, 1980, letter along with scheduled imple-mentation. We are presently calculating an AFW flowrate which will provide adequate flow to maintain proper steam generator level, but not lead to excessive cooldown rates.
This would allow for automatic initiation of AFW flow."
Additional NRC correspondence reviewed relating to the AFWS included a memorandum dated February 20, 1980 for H. R. Denton from D. G. Eisenhut.
This memorandum specifically addressed the seismic qualifications of selected plants' AFWS, including a site visit which had been made to Calvert Cliffs. The memorandum states, e
"At Calvert Cliffs, ror example, several locations were found in which the supports for the control-air for the auxiliary feedwater pumps and for the auxiliary feedwater control valve were disconnected from their intended mounting locations.
These were examples of important, but non-essential systems (i.e., local manual control of the pumps and valves could be used if the air-system were damaged) which could be easily upgraded to increase the plants chility to remove decay heat subsequent to an earthquake."
The AFW Regulating Valve handwheels at Calvert Cliffs were being restricted in travel to address these concerns of pump run out following initiation (IEB 80-04), preventing excessive cooldown following a DBA, etc., considering the fact that the FRV's air supply was not seismically qualified, and that these aspects of auto start of the AFWS system were considered an Unreviewed Safety Question by the licensee.
The Shift Supervisor on duty at the time of determination of reportability (January 11,1981) was interviewed (on May 28,1981) concerning his view-point of system operability at the time. The Shift Supervisor was cognizant that the flow had been reduced pursuant to an approved facility
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change, however considered the AFWS flow reduction to require corrective action and initiated a maintenance action, MR 0-81-135, on January 11, 1981 to restore AFWS flow. The Shift Supervisor did not consider the AFWS system inoperable and stated that he was aware that if increased flow was required the AFWS Regulating Valve Handwheel could be opened or the valve bypasses used to increase flows (Technical Specification 4.7.1.2 re-quires that each AFWS pump be demonstrated operable by verifying a total
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dynamic head greater than 2800 feet on recirculation. The flow restriction involved did not affect the pumps ability to meet the Surveillance Testing requirement.)
In summary, the inspector concluded that a change had been instituted which reduced AFWS flow, as controlled from the Control Room, below the T.S. basis value. The change had been initiated without adequately implementing procedural requirements and training to ensure flow was restored locally to the basis value if required, and no application was made for license change to the NRC. The inspector stated that Unresolved Item (317/81-02-03) had been changed to an Item of Noncompliance.
15. 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 require-ments; 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. With the scope of the above, the following periodic reports were reviewed by the inspector:
-- January, 1981 Operations Status Reports for Calvert Cliffs No.1 Unit and Calvert Cliffs No. 2 Unit, dated February 13, 1981.
Calendar Year 1980 Report of Radiation Worker Exposure by Work and
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Job Function, BG&E letter dated February 4,1981, and corrected report dated February 12, 1981.
Calvert Cliffs Nuclear Power Plant Units Nos. I and 2, CEA Guide
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Tube Inspection Program, BG&E letter dated January 21, 1981.
Calvert Cliffs Nuclear Power I'lant, Unit No.1, Reactor Pressure
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Vessel Surveillance Program Capsule 263, BG&E letter dated February 4, 1981 (Technical Specification 4.4.9.1.2).
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Unresolved Items Unresolved items are matters about which more infonnation is required to determine whether they are acceptchle, items of noncompliance or deviations.
Unresolved items addressed dur'ng this inspection are discussed in Para-graphs 3, 4, and 13 of this repor _.
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Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection s cope and findings.
A summary of inspection findings was also provided to the licensee at the conclusion of the report period.
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