IR 05000317/1982012

IE Insp Repts 50-317/82-12 & 50-318/82-12 on 820511-0615.No Noncompliance Noted.Major Areas Inspected:Control Room & Accessible Portions of Auxiliary,Turbine,Svc & Intake Bldgs; Radiation Protection;Physical Security & Fire Protection

ML20054M542
Person / Time
Site:	Calvert Cliffs
Issue date:	06/17/1982
From:	Architzel R, Mccabe E, Trimble D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20054M529	List: IR 05000317/1982012 ML20054M528
References
RTR-NUREG-0660, RTR-NUREG-0737, RTR-NUREG-660, RTR-NUREG-737, TASK-1.C.2, TASK-2.E.4.2, TASK-2.F.1, TASK-TM 50-317-82-12, 50-318-82-12, NUDOCS 8207130563
Download: ML20054M542 (20)

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DCS Nas. 50317 820601 50318 820601 50320 790328

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i U. S. NUCLEAR REGULATORY COMMISSION Region I 50-317/82-12 Report No. 50-318/82-10 50-317 Docket N DPR-53 C License No. DPR-69 Priority --

Category C Licensee: Baltimore Gas and Electric Company P. O. Box 1475 Baltimore, Maryland 21203 Facility Name: Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection At: Lusby, Maryland Inspection Conducted: May 11 - June 15,1982 Inspectors: I) O R. E. Architzel, SeniortResident Reactor Inspector n b[/T[8L date signed b.0 {}

D. C. Trimble, Resident Reactor Inspector Gf/bY2L date signed Approved By: A [. U b

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. C. McHbe, Jr. , Chief, Reactor Projects Section 2B b!/7/7k date ' signed Inspection Summary:

Inspection on 5/11-6/15/82 (Combined Report Nos. 50-317/82-12 and 50-318/82-10)

Areas Inspected: Routine, onsite regular and backshift inspection by the resident inspector ( 201 hours0.00233 days <br />0.0558 hours <br />3.323413e-4 weeks <br />7.64805e-5 months <br />). Areas inspected included the control room and the accessible portions of the auxiliary, turbine, service, and intake buildings; radiation protec-tion; physical security; fire protection; plant operating records; maintenance; surveillance; plant operations; radioactive waste releases; open items; TMI Action Plan Items; and reports to the NR Violations: .Non $$[kDO c

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DETAILS j 1. Persons Contacted The following technical and supervisory level personnel were contacted:

D. E. Buffington, Fire Protection Inspector J. T. Carroll, General Supervisor, Operations J. A. Crunkleton, Supervisor, Electrical Maintenance R. E. Denton, General Supervisor, Training / Technical Services C. L. Dunkerly, Shift Supervisor

. W. S. Gibson, General Supervisor, Electrical & Controls J. E. Gilbert, Shift Supervisor J. R. Hill, Shift Supervisor L. S. Hinkle, Engineering Analyst, Electrical & Control Section D. W. Latham, Principal Engineer, Operational, Licensing & Safety Unit J. F. Lohr, Shift Supervisor R. O. Mathews, Assistant General Supervisor, Nuclear Security G. S. Pavis, Engineer, Operations E. T. Reimer, Plant Health Physicist J. E. Rivera, Shift Supervisor P. G. Rizzo, Engineering Analyst L. B. Russell, Plant Superintendent R. P. Sheranko, General Foreman, Production Maintenance J. A. Snyder, Supervisor, Instrument Maintenance Unit 2 R. W. Talley, Jr. , Assistant General Foreman, PMD J. A. Tiernan, Manager, Nuclear Power Department R. L. Wenderlich, Engineer, Operations D. Zyriek, Shift Supervisor Other licensee employees were also contacte . Licensee Action on Previous Inspection Findings (Closed) Violation (318/82-05-01) Failure to Comply with the Requirements of 10CFR20.203(b) (Posting of Unit 2 RWT Room as a Radiation Area). The licensee's corrective actions for this item were reported in a response dated May 19, 1982, which stated that the appropriate sign had been affixed to the door and that technicians verifying posting had been directed to check for adequacy of sign mountings. The inspector rechecked the RWT room and noted that a proper sign had been permanently affixed to the entrance door. He verified through a discussion with a Principal Radiation-Chemistry Technician that appropriate instructions had been given to personnel verifying postings. Additionally, he noted that the RWT room posting was included on the routine checksheet used by technicians for posting verification. The violation and licensee response were properly posted as required by 10CFR19.l (Closed) Violation (317/81-09-02; 318/81-09-02) Seismic Instruments Not Properly Calibrated. The inspector reviewed procedure STP-M-560-0, Seismic Instruments Calibration, revision 3 approved 4/30/82. The procedure now requires testing

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-2-with a vendor supplied " shaker" table which supplies known values of acceleration and displacement. The system calibration completed on 5/6/82 was also reviewe (Closed) Inspector Follow Item (317/82-02-01) Noting Lifted Position of Tags on Record Sheets. The licensee revised procedure CCI-112C, Safety and Safety Tagging (change 5 approved April 22,1982), to require documentation of return to the

" cleared" tag position and established specific requirements for control of lifted tags for post maintenance testin (Closed) Violation (318/81-17-01) Failure to Show Salt Water Pump Sluice Gates in Piping and Instrument Drawings (P&ID). The inspector verified the licensee's corrective actions as stated in a letter dated December 1,198 P& ids M-450 and OM-450 were revised (revision 4 dated 11/19/81) to show the sluice gate The inspector also discussed activities of the appointed task force on drawings (accuracy, operating instruction changes, etc.) with the team leader. Completion of this effort is scheduled during 1982 and is being followed by the NRC as corrective action for other violation (Closed) Unresolved Item (317/82-07-05, 318/82-07-05) Revised Response for ECCS System Outages. The licensee submitted a supplemental response to NUREG 0737

item II.K.3.17. The inspector reviewed the letter dated May 13, 1982 and noted that outages associated with preventive maintenance were addressed as requeste (Closed) Inspector Follow Item (317/81-21-01) Unit 1 Containment Spray Header Isolation Valve not Red Tagged indicating Locked Open. During a containment tour the inspector verified that the red tag had been affixed to Containment Spray Header 11 isolation valv (Closed) Unresolved Item (318/81-04-02) Revise Preventive Maintenance (PM) Card

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for Cleaning Vital AC Inverters. PM Card 2-18-E-R-1 was revised on 3/12/81 to specify a required transfer to the backup power supply prior to cleaning the inverters and clearly specify the alternate fr.eder breaker (Closed) Unresolved Item (318/81-25-01) Unit 2 Boric Acid Storage Tank Room.

. During a tour of the Auxiliary Building the inspector noted that these areas had

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been cleaned up and repainted. The source of leakage of boric acid had also apparently been repaired.

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(Closed) Violation (317/81-07-02) Shift Supervisor's Assistant (SSA) Relieved the Controls without Turnover Checklist. The inspector verified that the

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licensee's actions, as stated in their letter dated June 5,1981 had been completed. This included interim use of the Senior Control Room Operator Checklists and development of a SSA checklist and incorporation into CCI-307, Operations Shift Turnover Checklists. Discussions with operators and review of records indicated the checklists were being use (Closed) Inspector Follow Item (317/81-24-04) Simultaneous Testing of Both Containment Temperature Indicators. The inspector reviewed revised Preventive Maintenance Cards 1-60-I-RQ4-1 and 1-60-I-RQ3-2 which have been changed, approved 6/7/82, to prevent simultaneous testing of both instruments. Unit 2 cards were similarly revised.

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-3-(Closed) Inspector Follow Item (317/80-06-09) Evaluate T.S. Requiring Suction from 12 CS The licensee is installing a motor driven AFW train per the NRC's long tem recommendation In addition, modifications are planned in the suction flow paths from the CST's to the pumps. These proposed changes have been reviewed and evaluated by the NRC. The inspector follow item is no longer appropriat (Closed) Inspector Follow Item (317/82-05-04) Measures to Prevent Recurrence of a Pressurizer Level Transient caused by Instrument Maintenance (LER 82-15).

As stated in a letter dated 4/23/82,the incident was discussed with the individuals involved and all licensed operators and instrument and control technicians were informed of the event. The inspector reviewed a completed Required Reading Routing Sheet dated 4/26/82 for LER 82-15 and a memorandum dated 6/11/82 documenting receipt and training of I&C technicians on the same LE (Closed) Violation (317/81-13-03) Working on 11 MSIV when MR Issued for 12 MSI The licensee responded to this violation in a letter dated September 4,198 The. inspector interviewed licensee personnel and verified that the situation had been reviewed with supervisory and maintenance personnel as committed in the respons In addition, the licensee has revised procedure CCI-200F (April 27, 1982) to require placement of a deficiency tag on the equipment to be worked under an MR by the originator of the M . Review of Plant Operations

Daily Inspection The inspector toured the facility to verify proper manning and access control and abserved adherence to approved procedures and LCOs. Instru-mentation and recorder traces were observed. Status of control room annunciators was reviewed. Nuclear instrument panels and other reactor protective systems were examined. Control rod insertion limits were verified. Containment temperature and pressure indications were checked against Technicial Specifications. Stack monitor recorder traces were reviewed for indications of releases. Panel indications for onsite/off-site emergency power sources were examined for automatic operabilit Control room, shift supervisor, tagout log books, and operating orders were reviewed for operating trends and activities. During egress from the protected area, the inspector verified operability of radiological monitor-ing equipment and that radioactivity monitoring was done before release of equipment and materials to unrestricted us These checks were performed on the following dates: May 11, 13, 14, 18, 1 19, 21, 26, 27, 28, June 1, 2, 3, 7, 8, 11, and 14, 198 On 6/1/82 the inspector noted a Radiation Monitoring System low flow alarm on the Unit 2 condenser vacuum pump monitor. The control room operator was aware of the alarm and stated that proper backup samples were being taken. A maintenance request (MR), however, had not been initiated. The operator agreed with the inspector that an MR should be initiate MR 0-81-2180 was initiated on 6/1/82.

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No violations were identified.

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-4-B. Weekly System Alignment Inspection Operating confirmation was made of selected piping system train Accessible valve positions in the flow path were verified correc Proper power supply and breaker alignment was verified. Visual inspections of major components were performed. Operability of instruments essential to system perfomance was verified. The following systems were checke Fire Water System lineup (Pretreated Water Storage Tanks through Fire Pump Room and selected valves in the plant) on 5/13/8 Salt Water and Service Water lineups in the Unit 2 Service Water Pump Room on 5/19/8 Unit 1 Boration paths on 5/26/82.

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-- Unit 2 Containment Isolation Valve lineups in the 27' West and 10' East Piping Penetration Rooms on 6/4/8 During the lineup checks in the Unit 2 27' West Penetration Room,the inspector observed that the Component Cooling Water (CCW) supply valve (CC 217) to the Steam Generator Bottom and Surface Blowdown Penetration Cooler 21 was chained and had a green tag attached (indicates locked closed). The inspector checked the Operating Instruction and noted that the valve should be open. The licensee checked the valve in question and verified that it was indeed open and removed the green

, tag and locking chain. The shift supervisor directed that the remainder of the CCW lineup to the containment penetration coolers be verifie The CCW system had not yet been verified by the licensee's P&ID/CCI valve lineup task force, scheduled to be completed by December,198 C. Biweekly Inspection

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Verification of the following tagouts indicated the action was properly conducte Tagout 19200, Charging Pump 21 (MR 0-81-4833) restoration lineup checked on 5/14/8 Tagout 19252, High Pressure Safety Injection System Isolation Valves checked on 5/26/8 Tagout 19202, Boric Acid Pump 11 checked on 5/2 Tagout 19015, Charging Pumps 11 and 12 checked on 5/2 On 5/26/82, near Boric Acid Storage Tank 12, the inspector found four loose tags associated with tagout 19171 on the Boric Acid System which

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had been cleared about 5/13/82. It appeared that the system had been properly lined up on tagout clearance but that the tags had been inadvertently left in the area. The inspector informed the tagging

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-5-authority and the Shift Supervisor of the problem. No additional NRC action will be taken on this ite On 5/27/82, the inspector noted that CCI 112, Safety and Safety Tagging, does not require the Shift Supervisor (SS) or Senior Control Room Operator (SCRO) to review the specified cleared equipment positions prior to authorizing clearance of a tagout. When a system required to be operable by Technical Specifications is tagged out and subsequently returned to service, it is necessary that the system be restored to its proper lineu Since in many cases the only procedural guidance covering the restoration of a system to proper lineup is CCI 112, that procedure should include sufficient direction to ensure proper system lineups. The inspector discussed this with the General Supervisor, Operations (GS0). The GS0 stated that in practice the SS or SCR0 does review the cleared equipment positions prior to tagout clearance. The GS0 then agreed to include in CCI 112 an additional requirement for SS/SCR0 review of cleared equipment positions prior to authorization of tagout clearance. This item will be reviewed during a future inspection by the NRC (317/82-12-01).

Boric acid tank samples were compared to the Technical Specification Tank levels were also confirme D. Other Checks During plant tours, the inspector observed shift tuisovers, security practices at vital area barriers, completion and use of radiation work permits, protective clothing and respirators. The use and operational status of personnel monitoring practices, and area radiation and air monitors were reviewed. Equipment tagouts were sampled for confonnance with TS LCOs. Plant housekeeping and cleanliness was evaluated. Other TS LCOs, including RCS Chemistry and Activity, Secondary Chemistry and Activity, watertight doors, and remote instrumentation were checke At 8:26 a.m. on 5/12, smoke was observed in the Security Diesel Generator Room. Oil leakage was found in the room and the Fire Brigade was called out as a precaution. There was no actual fire, and the brigade secured from the fire emergency at 8:33 a.m. The inspector observed the response of the Fire Brigade. The licensee made a 10CFR50.72 and a 10CFR73.71 report to the NRC. No unacceptable conditions were identifie On 5/13 the inspector observed refueling activities from the Unit I refueling machine. Following positioning of the machine next to the last assembly, arrangements were made to transfer the combined transfer tool (used for Control Element Assembly swapping) from the Polar Crane to the Auxiliary Hoist on the Refueling Bridge. Although the operators maneuvered the refueling bridge such that motion of the polar crane load block over the open reactor vessel was not necessary, the transfer tool was brought over the pool while suspended from the load block. This was apparently caused by a miscomunication between the crane operator and Nuclear Fuel Management personnel, who quickly directed the polar crane away from the vessel. The inspector noted that this activity was not

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-6-in accordance with the guidance of NUREG 0612 in that heavy loads (i.e. the polar crane load block) should not pass over irradiated fuel if possible. The inspector discussed the transfer operation with the Production Maintenance Department Training Administrator. A memo-randum was generated (dated May 15,1982) to all crane operators and riggers reemphasizing the requirements in the area of transfer of heavy loads over the reactor. A training memorandum was also issued requiring review of the requirements of NUREG 0612 and Shop Lab Memo M-13 with affected personnel. The inspector had no further questions in this are On 5/26 in the Unit 1 27' West Piping Penetration Room,the inspector observed three people in respirators working under SWP 1676, for repacking Chemical and Volume Control and Safety Injection System valves, and three people without respirators working under SWP 1675, for repacking Reactor Coolant Drain Tank Pump Discharge valve 1-CV-4260. The inspector discussed the situation with Radiation Control personnel. Air samples in the area did not indicate a need for respirator protection, but respirators had been issued as a precautionary measure to the individual working under SWP 1676. Respirators had not been specified for the individuals working under SWP 1675. The individuals without respirators were counseled by Radiation Control personnel to question situations similar to this in the future where they see others wearing respiratory protection equipment. The obvious implication would be that there is a radiological hazard in the are No additional action will be taken by NRC on this ite On 5/18 during a tour of the critical fire protection areas including the cable spreading room and the horizontal and vertical cable chases,the inspector noted that several runs of tygon tubing were still in place in the cable spreading room The tubing had been placed to allow sampling of various levels in the rooms during the conduct of the cable spreading room Halon system testing, which had been completed in October,198 The inspector pointed this out to the Fire Protection Engineer who stated that the tubing would be removed.

l On 6/4 the inspector noted that a piping penetration in the east wall i of the intake structure at the 10' elevation was not sealed to insure watertight integrity. The pipe passing through the penetration was a Unit 1 Screen Wash System hose station supply. The hose station isolation valve was ISWS 135. Additionally, the inspector noted a second unsealed penetration for chlorination system piping in chlorinator bay 12. FSAR section 2.8.3.6 states that because the salt water pumps, which are essential for safe shutdown, are housed in the intake structure, the structure is Class I for seismic, tornado, and hurricane condition FSAR section 2.8.3.5 states that during a hurricane, Chesapeake Bay peal surge could reach 16.2 feet above mean low water (MLW) which is above the elevation of the unsealed piping penetrations. The inspector discussed this item with the Production Maintenance Department's General Foreman who agreed to investigate the design requirements for intake structure piping penetrations and initiate whatever modifications or repairs which may be necessary to meet design requirements for not only the specific penetrations discussed above,but all the intake structure piping penetrations. This item is unresolved pending licensee action to determine design requirements and complete required repairs and subsequent NRC review (317/82-12-04).

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-7-Technical Specification surveillance requirement 4.9.12.d.1 verifies proper pressure drop across the charcoal absorber banks in the spent fuel ventilation exhaust system. The licensee's surveillance test procedure (STP) checking pressure drop across the banks is STP M-542- That procedure does not specify which instrument should be used to measure filter differential pressure (D/P). In the past, a pemanently installed local D/P gauge, 0-PDI-5417, has been used to measure the D/ On 5/26/82 the inspector noted that 0-PDI-5417 carried a calibration sticker indicating a last calibration date of 6/26/74. Followup inspection showed it was not included on the Instrument Maintenance Department's schedule for periodic instrument calibration. That schedule is required by Calvert Cliffs Instruction (CCI) 120, section III CFR50, Appendix B, Criterion XIII requires that measures shall be established to assure that gauges and instruments used in activities affecting quality are properly controlled, calibrated, and adjusted at specified periods to maintain accuracy within necessary limit In this case, sufficient measures were not established to assure the use of a properly calibrated gauge for the conduct of Technical Specification surveillance requirement 4.9.12.d.1 in that the applicable surveillance test procedure, M-542-0, did not specify the instrument to be used for measuring pressure drop across the spent fuel ventilation exhaust charcoal filter and a gauge not included on the plant schedule for periodic calibration was used to conduct the surveillance test. 0-PDI-5417 has been added by the licensee to the recalibration program. Additionally, a 4/28/82 notice to Operations personnel from the General Supervisor, Operations states that " Process gauges (referring to gauges used in surveillance testing) will no longer be labeled with' a calibration due date. Instrument Maintenance (IM) has assured us that they have verified that all instruments used for surveillance testing...are currently being calibrated at the proper frequency. If they have a calibration sticker, we can therefore assume that these gauges are qualified unless we have reason to believe othemise." In the case described above, the instrument had an old calibration sticker which could infer the gauge was included in a proper calibration program. When a" calibration due date" is not placed on an instrument, an individual using the instrument cannot be assured that the instrument in use is being calibrated at the necessary frequenc This point was discussed with the Plant Superintendent. The use of a gauge not included on the plant schedule for periodic recalibration is an un-resolved item and will be reviewed by NRC during a future inspection (317/82-12-02).

4. Surveillance Testing The inspector observed parts of tests to verify perfomance in accordance with epproved procedures, LCOs were satisfied, test results (if completed) were satisfactory, removal and restoration of equipment was properly accomplished, and that deficiencies were properly reviewed and resolved. The following tests were reviewed.

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STP M-213-2, Calibration of Power Range Instruments to In Core Instruments, observed 5/19/8 TSP-17, selected portion of Eddy Current testing of Unit 1 Steam Generator #11 on 5/31/8 Testing of Unit 2 Type 2E Electrical Penetrations per STP M-571-2 (MRI-82-2078)on6/10/8 On 5/20/82 the inspector noted a deficiency in Operating Instruction (01)

41A, concerning startup of Hydrogen Recombiners. Step II.B.3 of the instruction required the operator to obtain a reference power, which is used with an applied correction factor as a setpoint for adjusting recombiner power potentiometers, from the latest data sheet attached to surveillance test procedure (STP)-0-32. STP-0-32 no longer exists; therefore, an operator could not properly complete a recombiner startup procedure. This deficiency was pointed out to operations staff personnel and a procedure change was initiated on 5/20/82. This item is unresolved pending completion of licensee corrective action and subsequent NRC review (317/82-12-03).

The licensee had previously identified a violation (317/82-07-11) con-

cerning operation of Unit 1 above allowable containment leakage rate During the current inspection, the inspector reviewed the historical leak rate test data for the applicable Unit 2 penetrations. A concern for containment integrity was raised by the inspector due to progressive deterioration and the licensee was requested to perform a leak rate test to resolve the concern. The inspector reviewed the Technical Manual on Electrical Penetration Assemblies TM-123-1159 by Amphenol-SAMS Division and applicable drawings. The licensee cut apart old Unit 1 penetration modules and demonstrated that the leakage path was through a self-energized seal and then through a secondary seal (dielectric resin).

Testing of repair methods being developed for possible use on Unit 2 Type 2E containment electrical penetrations was observed. The testing used the (removed) Unit 12E penetrations and consisted of injecting a sealant (from a SCOTCHCAST 82-A3 Power Cable Splice Kit). An air passage was then created through the penetration to ensure its testability.

l Following a several hour cure time the penetration was leak checked, with l results improving from unmeasureable to less than 10,000 sccm. A test was

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performed (accessible from the Auxiliary Building) on 6/10/82 with Unit 2 at full power. The test results (testing observed by the inspector)

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Calvert Cliffs Unit 2 LLRT Data In SCCM Type 2E Penetrations 11/76 5/77 10/77 9/78 12/79 3/81 6/82 ZWB8 1 0 2 2 460 25288 9439 ZWC3 1 0 0 0 2 12930 23596 ZEC2 1 5 3 3 1 125 1 ZEC7 1 5 0 0 10150 57985 35396 Total B+C Tests 39172 21800 29316 53098 40842 140399 A possible explanation for the improvement in leakage was that testing in June, 1982 was performed with the containment at a higher temperatur (Previous tests had been performed in cold shutdown.) Unit 2 Type 2E penetrations are still scheduled for replacement during the Fall,1982 refueling outag No unacceptable conditions were identifie . Plant Maintenance The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and mainten-ance procedures, and codes and standards, proper QA/QC involvement, safety tags use, equipment alignment, jumpers use, personnel qualifications, radiological controls for worker protection, fire protection, retest requirements, and reportability per Technical Specifications. The following activities were include MR M-82-550, Change Oil in Control Room Air Conditioning Unit II due to refrigerant contamination, observed on 5/1 MR 82-6194, observed welding on 5/28/82 on the replacement containment Electrical Penetration 1 ZEC2 (Unit 1). Welding performed under Weld Authorization Traveller specifying procedure MEN 82-343.

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-- Work Procedure RV-71, Unit 1, observed selected portion of repair to reactor vessel closure stud hole #12 on 5/31/8 No unacceptable conditions were identifie . Observation of Physical Security The inspector checked, during regular and off-shift hours, on whether selected aspects of security met regulatory requirements, physical security plans, and approved procedures.

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-10- Security Staffing

-- Observations and personnel interviews indicated that a full time member of the security organization with authority to direct physical security actions was present, as require Manning of all three shifts on various days was observed to be as require Physical Barriers Selected barriers in the protected area and the vital areas were observe Random monitoring of isolation zones was performed. Observations of truck

.and car searches were mad Access Control Observations of the following were made:

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Identification, authorization, and badging;

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Escorting;

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Compensatory measures when require No violations were identifie . Radioactive Waste Releases Records and sample results of the following liquid and/or gaseous radioactive waste releases were reviewed to verify conformance with regulatory requirements prior to releas Gaseous Release Pemit G-051-82, Unit 2 Containment Purge via the ECCS Pump Rgom on 5/11/82; release rates, Group I 2.62 E3 m 3 /sec., Group II-1.72 m3/se Liquid Release Pemit M-072-82, Miscellaneous Waste Monitor Tank released on 5/13/82, 7.02 E-4 curies, excluding trituim and noble gases released.

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Sample calculation for Liquid Pemit R-036-82, release of Reactor Coolant

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Monitoring Tank 12 on 5/20/82. Actual release was postponed.

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-- released Gaseous on 6.4.82;.Pemit G-059-82, release rates, Group Unit 2 I 323.3Containmentm3sec., Vent GroupviaII ECCS 5.21 m sump,3/se (pre-release calculations).

The inspector observed a portion of the release of 12 Reactor Coolant Waste MonitorTank(R-82-41)en6/7/8 __ _

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-11-No unacceptable conditions were identifie . Review of Events Requiring One Hour Notification to the NRC The circumstances surrounding the following events requiring prompt NRC (one hour) notification via the dedicated telephone (ENS-line) were reviewed:

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A licensee employee fell from scaffolding about 11:00 a.m. on 6/1 while working on retubing the main condenser. He was transferred to the Calvert Memorial Hospital by the rescue squad suffering an apparent broken le Radioactive contamination was not involve At 11:25 a.m. on 6/2 Control Element Assembly (CEA) 64 (Unit 2) dropped into the core. The licensee had comenced a power decrease (from 100%)

to clean condenser water boxes,so continued to 70% by boration in order to recover the CEA to group position (12:31 p.m.). The CEA dropped again at 2:37 p.m. and was again restored as required by T.S. by 3:30 The CEA was not being moved either time, which has typically been the situation for previous CEA drops. The inspector observed portions of the licensee's corrective actions from both the control and cable spread-ing rooms. Visicorder traces of coil voltages were taken both time In addition, coil resistance readings and power supply voltages were measured. No cause was found for either drop. On 6/6/82 the licensee replaced the Timer and Upper Gripper Power switch for CEA 64, components which are in the circuit while CEAs are not being moved. During this maintenance action the licensee paralleled CEA 64's normal power supply with a feed from tfie power supply for a (unused) power shaping CE Because these CEAs do not trip the licensee entered T.S. Action ~ State-ment 3.1.3.1.a for five minute,s (10:09 to 10:14 a.m.), which requires the imediate initiation of a shutdown. The NRC Operations Center was notified and the power decrease terminated upon replacement of the components and removal of the parallel source. The CEA was then 2 successfully tested. The inspector reviewed MR 0-82-2273 documenting the corrective actions and POSRC approval of the maintenance procedur CEA Problem Reports to be filed with the vendor (Combustion Engineering)

in accordance with their Availability Data Program were also reviewe The inspector had no further questions in this are At 8:51 p.m. on 5/17, power was lost to 4KV bus la on Unit 1. The unit was shutdown in Mode 6 at the time. An electrician working on inverter 12 shorted across contacts of the synchronizer while the inverter was selected to its backup power supply,120 Vac inverter backup bus 1 This resulted in a voltage fluctuation on inverter fed 120 Vac vital instrument bus 12 which powers the Engineered Safety Features Actuation System (ESFAS) logic cabinet B. The power loss to the ESFAS cabinet caused an undervoltage trip actuation of 4 KV bus 14. Normal power was restored to bus 14 at 8:57 p.m. The licensee notified the NRC of the event by the ENS phone at 9:15 p.m. The inspector had nc further que:,tions on this even .. . . - - - -

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At 9:20 p.m. on 5/17, power was again lost to 4KV bus 14. An electrician troubleshooting the previous loss of power incident mistakenly thought a breaker supplying power from 480 Vac MCC 104R to 120 Vac inverter backup bus 11 had tripped and tried to reset it. The breaker opened and again caused an interruption in power to ESFAS actuation logic cabinet B and an undervoltage trip actuation of 4KV bus 14. Power was immediately restored to the 4KV bus and the NRC was notified at 9:30 p.m. by EN The inspector had no further questions on this even At 4:56 p.m. on 6/4, with Unit 1 in cold shutdown Mode 6, power was lost to 4KV bus 11. The bus tripped while a technician, conducting surveillance test procedure M-538, was testing voltage for pressurizer pressure transmitter PT-105A at 1C25A during subcooled margin monitor calibratio His instrument probes shorted out the power supply to the transmitter.

This apparently caused a voltage fluctuation to ESFAS logic cabinet A and a undervoltage trip actuation to 4 KV bus 11. Additional trip actuations were received for safety injection, recirculation steam generator isolation, containment spray, and chemical and volu,me control system isolation. With the exception of #12 Low Pressure Safety Injection (LPSI) pump, which was supplying shutdown cooling flow, all injection and spray pump handswitches were in pull-to-lock and no water was injected into the Reactor Coolant System or sprayed into containment. Since #12 LPSI pump is powered from 4KV bus 14, shutdown cooling flow was not interrupted. The inspector had no further questions on this even Emergency Power Loss. On 6/2, with Unit 1 in refueling outage (Mode 6)

and Unit 2 at full power, Diesel Generators DG-12 and DG-21 were tested successfully about 5:30 a.m. before taking an offsite power source (500 KV " Red" bus) out-of-service for maintenance. The remaining Diesel Generator (#11) was also out-of-service for maintenance. Following removal of the red bus from service,DG-21 was fully loaded for the purpose of burning up lubricating oil which carries into the exhaust At 6:32 a.m., DG-21 tripped due to a generator piping (of the engines. Operators and electricians were sent to investigate fault lockout).

and MR 0-82-2184 was initiated to investigate. Diesel Generator 12 was then started and fully loaded to demonstrate its operability. About 7:00 a.m. an operator raised the voltage of the Unit 2 generator from 487 to 500 KV in response to a request from the load dispatcher. At 7:05 a.m., while raising voltage to 505 KV in response to another request, DG-12 tripped on a gr.nerator fault. This left both units with no emergency power sources and only one immediate access offsite power circuit, the same line connecting Unit 2 to the grid. A delayed access (less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) 13 KV feeder (5 KVA) capacity was also available from the local electric cocecrative. The licensee determined the cause of the trip to be an underexc'ited condition of the DG resulting in a sensed loss of field (the 140 protective relay sensing loss of field had tripped both times) when the Diesel Generator was driven into a leading condition by adjusting the Unit 2 generator voltage. DG 21 was believed to have trip-ped due to a drifting voltage regulator causing the same effect. The trips were reset and both diesels restarted at 7:16 a.m. The NRC Operations Center was notified at 7:19 Following completion of i

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-13-operability testing. DG 12 was declared operable at 7:35 a.m. and DG 21 at 8:00 The inspector reviewed the sequence of events with licensee personnel and reviewed records, drawings and procedures in evaluating the even The following were included in this revie Recorder Chart for Unit 2 500 KV Voltage

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P&ID IE-68, AC Schematic Diagram Diesel Generators 11 & 12, revision 6

-- Vendor P&ID M-222-39, Colt Industries, Emergency Diesel Generators, revision 7

-- OI 27 C, 4.16 KV System, revision 5

-- OI 21, Emergency Diesel Generators, revision 16

-- Setpoint Book (Protective Relay Section)

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FSAR, Section 8.4.1, Emergency Diesel Generator The licensee detemined that DG-21 was operable after successfully starting and fully loading the Diesel Generator for 15 minutes while paralleled with normal ac power. Several portions of the voltage regulator circuit, which allow paralled operation, are not in the circuit during accident condition In addition, the loss of Generator Field trip is not active when the generator is not paralleled to other sources. This is the design condition of the DGs during an accident. The licensee subsequently test ran DG 21 and noted small magnitude reactive load oscillations indicative of voltage regulator drift and initiated action to replace the regulato Operations personnel noted that a caution note directing that the operator be careful of DG loads when changing main generator voltage had been removed recently in an effort to clean up the Control Boards (INP0 findings). The licensee stated that the note would be replaced and made pemanent. The inspector also noted that the licensee's Operating Instructions did not address the generator trip on a leading power factor and did not adequately address actions to take to avoid such a trip. The licensee stated this area would be examine Additional licensee corrective actions will be examined by the NRC upon receipt of the follow up report to LERs 82-27 (Unit 1) and 82-25 (Unit 2)

which remain open pending review and completion of corrective action The Emergency Response Plan was not initiated for this event because a reactor mode change was not made. (The condition was corrected within time period allowed by T.S.). Appendix C of the NRC letter dated 5/26/82, forwarding the Emergency Preparedness Appraisal Combined Inspection Report 317/81-19 and 318/81-18 stated in the evaluation of Section D, the Emergency Classification System specifically under initiating condition 7 for loss of ac power (and others), that a concurrent Emergency Action

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-14-Level (EAL) criteria of placement of the reactor in a lower mode of operation was irrelavent and should be dropped. The licensee was required to respond to this particular issue within 120 days of the letter; therefore, corrective actions in this area will be evaluated by the NRC upon receip . Review of Licensee Event Reports (LERs)

LERs submitted to NRC:RI were reviewed to verify that the details were clearly reported, including accuracy of the description of cause and adequacy of -

corrective action. The inspector determined whether further information was required from the licen ee, whether generic implications were indicated, and whether the event warrarited onsite followup. The following LERs were reviewe LER N Date of Event Date of Report Subject Unit 1 82-14/3L 04/07/82 05/07/82 RPS CHANNEL C PRESSURIZER AND THERMAL MARGIN / LOW PRESSURE TUs BYPASSED, CHANNEL C PRESSURE DEVIATED HIGH BY 50 PS /3L 04/17/82 05/10/82 RCS INDICATED IDE VALUE OF 1.31 uCi/g /3L 04/17/82 05/17/82 MAIN STEAM SAFETY VALVE IN0PERABL /lT* 05/14/82 05/28/82 RCS DILUTION IN EXCESS OF .5% DELTA K/K WHILE IN MODE 6 FROM SG TUBE LEAKAG /3L 04/17/82 05/17/82 PRESSURIZER LEVEL DEVIATED FROM 1 PROGRAM LEVEL BY MORE THAN 5%.

82-27/lT** 06/02/82 06/02/82 ALL THREE DIESEL GENERATORS INOPERABL Unit 2 82-18/3L* 04/17/82 05/14/82 CEA 21 DROPPED INTO COR /3L 04/12/82 05/07/82 RPS CHANNEL A TRIP UNITS FOR LOW SG PRESSURE AND THERMAL MARGIN / LOW PRESSURE BYPASSED FOR TP.0VBLESH00 TING -

22 PSI DEVIATION BETWEEN CHANNEL /3L 04/17/82 05/17/82 PRESSURIZER LEVEL DEVIATED FROM PROGRAM LEVEL BY 5%.

82-25/1T** 06/02/82 06/02/82 ALL THREE DIESEL GENERATORS INOPERABL '

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• • Addressed in detail in paragraph 8.

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-15-For the LER's selected for onsite review (denoted by asterisk 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 10CER50.5 Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewe LER 82-18 (Unit 2) - Item 3 of Inspection Report 82-07, dated 5/24/82, described the circumstances surrounding an event in which Unit 2 was manually tripped after a technician (electrician) mistakenly opened the power supply breakers to Control Element Assemblies (CEA) 20 and 21 causing the CEAs to drop into the reactor core. This event was later the subject of Unit 2 LER 82-18/3L. Further investigation by the licensee showed that principally due to a breakdown in communications between the Electrical Shop Work Coordinator and an electrician trainee, the trainee thought he had been directed to check resistance readings on Unit 2 CEA lift coils. In fact, he was supposed to do the checks on Unit 1. Operations personnel approved the work based upon the mistaken belief that the work was to be accomplished under a previously authorized tagout for Unit 1 CEA power supply breakers. The inspector reviewed an event report (82-04 dated 6/1/82) generated by the licensee for internal use. The LER stated that the lead electrician has been instructed in the proper means of detemining job scope and that revision to an administrative instruction would be made to provide direction on how jobs which are not continuous are to be reviewed or refine The internal report recommends (1) instruction for the Shop Work Coordinator on work assignment and the electrician trainee on conduct-ing maintenance activities, (2) revision to Calvert Cliffs Instruction (CCI) 200 to give instructions when work is not completed during a shift and when work scope changes, (3) re-labeling of CEA cabinets to reflect unit numbers, and (4) systems training / practical factors for electricians. The inspector had no further questions on the corrective action taken and planned for this ite /lT (Unit 1) RCS Dilution - On 5/12/82, following completion of a rim cut evolution completed on the ninth and tenth tube support plates of

1. 11 Steam Generator (SG), the generator was placed in wet layup. Over a 45 hour5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br /> period, between 5/12/82 and 5/14/82, approximately 25,000 gallons of water leaked out of SG 11 into the Reactor Coolant System (RCS)

through a SG tube (s) damaged during the rim cut operation. This resulted in a short term dilution of about 63 ppmB of RCS boron concentratio This was equivalent to a positive reactivity insertion of approximately 1% 6 K/K. At the time,the reactor vessel head was removed and the fuel

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transfer canal filled. Initial RCS boron concentration was 2443 ppm Subsequent mixing of the RCS and fuel transfer canal water inventories restored RCS boron concentration to 2446 ppmB. SG leakage stopped when the SF water level reached the height of the water level in the refueling canal. The licensee informed the inspector of the SG tube leakage on 5/14/82. The licensee hid detemined that the event did not require a

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-16-a prompt report to the NRC based upon abnomal degradation in pressure boundry considerations. The inspector then asked whether the event was reportable per the T.S. because of dilution. Following calculations,the licensee detemined that the computed value of reactivity change due to the boron dilution was about 1%/\K/K and a prompt report was made in accordance with Technical SpecifTcation requirement 6.9.1.8.d. Additional licensee actions will be reviewed upon receipt of the followup repor This LER remains ope ,

1 Licensee Action on NUREG 0660, NRC Action Plan Developed as a Result of the TMI-2 Accident The NRC's Region I Office has inspection responsibility for selected action plan item These items have been broken down into numbered descriptions (enclosure 1 to NUREG 0737, Clarification of THI Action Plan Items). Licensee letters containing commitments to the NRC were used as the basis for acceptability, along with NRC clarification letters and inspector judgment. The following items were reviewe I.C.2 Shift and Relief Turnover Procedures. This item had previously been inspected and left open pending incorporation of the checklists which had been developed into pemanent plant procedures. The inspector noted that the referenced checkiists have been incorporated into new procedure CCI-307, Operations Shift Turnover Checklist, approved 7/29/8 This closes item I. II.E.4.2(5) Containment Pressure Setpoint Change. This item had previously

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been inspected (Report 317/81-27,318/81-25) and left open pending further NRC evaluation of the licensee's proposed action to leave the setpoints at 4.25 psig. The licensee subsequently agreed to reduce the setpoints to the previously comitted minimum of 2.8 psig. This was documented in an NRC letter (Jaffe to Lundvall) dated 2/1/82. The inspector reviewed MRs I-82-41 (Unit 1) completed 3/2/82 and I-82-2043 (Unit 2) completed 3/1/82 which changed the setpoints of the Containment Isolation signal (both SIAS and CIS)to 2.8 psig. The reactor trip setpoints were also changed to 2.4 psig to ensure a reactor trip prior to a safety injection as analyzed in the accident analysis. Surveillance Test Procedures STP M-220-1 and 2 ESFAS Functional Tests were revised on 3/10/82 to reflect the new setpoints. This item is close II.F.1.3 Containment High Range Monitors. On 6/9/82 and 6/10/82 the inspector reviewed the licensee's implementation of TMI Action P,lan Item II.F.1.3 regarding Containment High Range Radiation monitors. The i licensee has installed under Facility Change Request (FCR) 79-1057, two l monitors per unit with maximum readouts of IE8 R/hr. The monitors have been

insitu calibrated electronically and contain a 1 R/hr alpha check source.

l The NUREG 0737 requirement for insitu calibration for at least one decade below 10 R/hr by a calibrated radiation source has not been completed due to a delay in delivery of necessary calibration equipment. Operations personnel received infomation on the new monitors as part of their j " Degraded Core" training received during October and November of 1981.

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The inspector verified that drawing OM-98 had been revised to reflect installation of the monitors through reference DCN 98-43 and 44 dated

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-17-5/20/80. The monitors have been included in the plant recalibration program by means of Planned Maintenance Card PM-I-77-I-R-1 Monitor operability has not yet been included, as required by NUREG 0737, in the T.S. The licensee is preparing a draft T.S. submittal. Quality Control and POSRC review of the modification was documented in the FC A 10CFR50.59 evaluation for the FCR was completed on 6/2/80 indicating there was no unreviewed safety question involved. A final NRC:RI review of this item will be conducted following licensee completion of radiation source calibration of the monitors (317/82-12-05).

-- II.F.1.4 Containment Pressure. On 6/9 and 6/10/82 the inspector reviewed the licensee's implementation of TMI Action Plan I,emt II.F.1.4 regarding a containment pressure monitor. The licensee recalibrated two existing instruments per unit (0 to 150 psig and -5 to +5 psig). A third instrument has been added to each unit (1-PI-5310 for Unit 1 and 2-PI-5310 for Unit 2) with a range of -5 to 150 psig. The modification was accomplished under FCR 80-1001. The instruments were calibrated under Maintenance Request MOD-80-8 and are included in the licensee's program for periodic instrument calibration under PM card 1-48-I-R-2. The inspector verified that drawing OM-65 had been revised to reflect installation of the instruments through reference to DCN ME-65-5 Quality Control and POSRC review of the modification was documented in the FCR. A 10CFR50.59 evaluation for the FCR was completed on 4/1/80 concluding there was no unreviewed safety question involved. This item is close II.F.1.5 Containment Water Level . On 6/9/82 and 6/10/82 the inspector reviewed the licensee's implementation of TMI Action Pla,n Item II.F. regarding containment water level instrumentation. Previously, the licensee had a narrow range indication of containment sump level (0-30 inches). The licensee added, under FCR 80-1006, two new level instru-ments per unit (1-LI-4146 and 1-LI-4147 on Unit 1, 2-LI-4146 and 2-LI-4147onUnit2). The instruments were calibrated under Maintenance Request MOD 80-14. A change to the licensee's Planned Maintenance Program is in process to include the new instruments on a routine calibration schedule. A 10CFR50.59 evaluation for the FCR was completed on 5/6/80 concluding there was no unreviewed safety question involve DCN ME-74-70 has been issued to include the modification on drawing M-7 The inspector noted that drawing OM-74, the drawing used by operations personnel in the control room, had not been revised to include the modification. The inspector discussed this with personnel who maintain control of plant drawings and found that M and OM drawings, although very similar in content, carry different licensee print numbers and are maintained separately. In this case, a change was issued to the M print but was overlooked for the OM print. This has been a problem in the past which the licensee has identified. Monthly the licensee now reviews its design changes and verifies that modifications affecting M and OM drawings are properly reflected in both drawings. The licensee has designated a task force to walkdown plant systems and verify that prints accurately represent system as-built conditions which is scheduled for completion during 1982. A separate " Document Control" task force has been

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-18-chartered to examine the facility change process and drawing control and detemine necessary changes. That group had currently developed an out-line for a new Quality Assurance Procedure which will address the OM/M drawing update problem. The procedure is scheduled for completion by November 198 Drawing OM-74 was immediately updated to include FCR 80-1006 changes and the proper print was taken to the control roo In a letter dated 1/19/82, the licensee stated that the new level monitors, after an initial period of successful operation, have been giving erroneous level indication The problems is believed to be caused by airentrapped in associated capillary tubing. Corrective action is planned for the current refueling outage on Unit 1 and for the October 1982 outage for Unit 2. The inspector has observed the new level instrument readouts and detemined that in their present condition, the instruments' indications are meaningles A NRC:RI final review of this item will be conducted following completion of licensee corrective action. Final licensee action to ensure proper updates of both M and OM drawings is unresolved and will be reviewed by the NRC:RI during a future inspection (317/82-12-06).

1 Licensee-NRC Meeting On 5/24/82 the inspectors and their accompanying section chief attended a meeting at the BG&E Corporate Office. The purpose of the meeting was to address

" global" scheduling of licensee commitments to the NRC based upon manpower loading, safety significance, and operational constraints. The licensee agreed to work with the Licensing Project Manager to establish such a schedul On 6/14/82, the inspector attended a licensee /NRR meeting in Bethesda, Md. on Unit 1 Steam Generator (SG) tube damage resulting from a " rim cut" modificatio The modification was completed during the current refueling outage (April -

June,1982). Its purpose was to cut the lugs attaching the ninth and tenth tube support plates to the SG shroud and thereby reducesstresses in the support plates induced during the " denting" process. The licensee described the modification, the resulting tube damage, and its planned corrective actio Three tubes in SG 11 and one in SG 12 were apparently damaged during the rim cu All damaged tubes were near the ninth tube support plate in the lug area. All leaking tubes will be plugged. Additionally, the most seriously damaged tube will be stabilized by means of an expanded sleeve insert. The NRR staff requested additional information on how the effects of the tube support plates were nulled out of eddy current testing test data. The NRR staff was appreciative of the briefing and commended the licensee on its efforts expended in preventing tools and debris from falling down into the SG . Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9.1 and 6.9.2 were reviewed. That review included the following:

Inclusion of infomation required by the NRC; test results and/or supporting infomation consistency with design predictions and perfomance specifications; planned corrective action adequacy for resolution of problems; detemination

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-19-whether any information should be classified as an abnormal occurrence; and validity of reported infonnation. The following periodic report was reviewed:

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April,1982 Operations Status Reports for Calvert Cliffs No.1 Unit and Calvert Cliffs No. 2 Unit, dated May 17, 198 . Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable. Unresolved items are discussed in paragraphs 3.C, 3.D , 4 and 10 of this repor . Exit Intervie Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A summary of findings was also provided to the licensee at the conclusion of the report period.

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