IR 05000317/1989006

Insp Repts 50-317/89-06 & 50-318/89-06 on 890404-0515. Violation Noted.Major Areas Inspected:Facility Activities, Licensee Action on Previous Insp Findings,Operational Safety,Physical Security,Plant Operations,Maint & LERs

ML20247L812
Person / Time
Site:	Calvert Cliffs
Issue date:	07/07/1989
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20247L790	List: IR 05000317/1989006 ML20247L786 ML20247L803
References
50-317-89-06, 50-317-89-6, 50-318-89-06, 50-318-89-6, NUDOCS 8908010354
Download: ML20247L812 (30)

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U.S. NUCLEAR REGULATORY COMMISSION REGION I '

50-317 DPR-53 Docket Nos.: 50-318 License Nos.: DPR-69 i 50-317/89-06 Report Nos.: 50-318/89-06 i

Licensee: Baltimore Gas and Electric Company Post Office Box 1475 l Baltimore, Maryland 21203 Calvert Cliffs Nuclear Power Plant, Units 1 and 2

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Facility: l Inspection at: Lusby, Maryland i i

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Inspection Conducted: April 4 - May 15, 1989 Inspectors: H. Eichenholz, Senior Rer.ident Inspector  !

V. Pritchett, Resident Inspector P. Wilson, Resident Inspector - Beaver Valley l D.[allace, .erations Engineer, DRS Approved By: # . h)

Lowell E. Trit /p, Chic" 7 Of

' Date l Reactor Projects Section No. IA Summary: April 4 - May 15, 1989: Inspection Report Nos. 50-317/89-06 and i 50-318/89-06 I l

Areas Inspected: Facility activities, licensee action on previous inspection l findings, operational safety, physical security, plant operations, maintenance, surveillance, engineering support, Licensee Event Reports, licensee response to i NRC initiatives, review of periodic and special reports, and events requiring l notification to the NR Results: A violation resulted from a change of intent to an operating proced- ,

ure without prior P0RSC review or developing a safety evaluation per the i requirements of 10 CFR 50.59 for the safety related salt water system (see Section 4.1). Lack of communications and coordination during tagging opera- 3 tions resulted in a hazardous condition for a diver during stop log installa- i tion and the potential for salt water pump damage (see Section 6.1). The  ;

licensee's handling of pressurizer heater weld leaks on Unit 2 shows positive i initiative and indication of proper safety perspective (see Section 6.4).

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8908010354 690721 7 PDR ADOCK 0500 O

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TABLE OF CONTENTS PAGE Persons Contacted.................................................... I Summary of Facility Activities....................................... 1 Status of Previous Inspection Findings (IF 71707, 92702, 92701)...... 2 3.1 (Closed) Inspector Follow Item 50-317/85 07-03.................. 2 3.2 (Closed) Unresolved Item 50-317/86-11-01.. ..................... 2 3.3 (Closed) Violation 50-317/86-15-01; 50-318/06-15-01............. 2 3.4 (Closed) Unresolved Item 50-317/88-08-01; 50-318/88-09-01....... 3 3.5 (Closed) Unresolved Item 50-317/85-03-03....... ................ 3 3.6 (0 pen) Inspector Follow Item E0-317/88-04-01; 50-318/88-05-01... 3 3.7 (Closed) Violation 50-317/86-07-02; 50-318/86-07-02............. 3 Operational Safety (IP 71707, 71710)................ ...... ......... 4 4.1 Daily Inspection....... ......................... ....... ...... 4 4.2 System Alignment Ir,spection................................ ... 7 4.3 Biwee kly and Othe r In specti on s. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .,. . . . 7 Security (IP 71707)............... .................................. 8 5.1 Obse rvati on of Physi cal Secu ri ty. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B Plant Operations (IP 71707, 93702, 40500)....... .................... 8 6.1 Diver in #24 Circulating Water Cavity During Dewatering with

1. 22 Salt Water Pump 0perating....................... ... ..... 8 6.2 Unit 2 Refueling Activities..................................... 12 6.3 Unit 1 Shutdown Due to High Sulfate Concentrations ia the Reactor Coolant System........................................ 13 6.4 Identification of Defects in Unit 2 Pressurizer Heater Penetration Welds and Unit 1 Shutdown......................... 15 6.5 Control Element Assembly Drop Event. . . . . ....................... 16 6.6 Medical Emergency Involving Potentially Contaminated Individual.............. . ...... ... ...... .... ........... 17 6.7 Containment Iodine Filters Outside Design Bases Due to Lack of Equipment Qualifications... .................................. 18 Maintenance /Surveillan"ce (IP 71707, 61726, 62703, 70313)........ .... 19 Maintenance............. .... ........ ........... ........... 19 7.2 Surveillance..... ............. ......... ............... ..... 21 i

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, Table of Contents (Continued)  !

PAGE 1 Engineering / Technical Support (IP 71707,37828)...................... 21 l 8.1 Instrument Air System Deficiencies................ ............. 21 . . Licensee Event Reporting (LER)_(IP 93702,90712)..................... 24 9.1 Unit 1 LERs 89-03, 89-04, 89-05, 89-06.............. ........... '24 9.2 Unit 2 LERs 89-03, 89-04, 89-05................... ............. 25 1 Review of Licensee Response to NRC Initiatives-(IP 71707)........ ... 25 10.1 NRC Information Notice 89-33.................................... 25 1 Review of Periodic and Special Reports (IP 71707)................... 26 1 Events Requiring NRC Notification (IP 93702)......................... 26 1 Unresolved Items (IP 93702).......................................... 27 14. Management Meetings (IP 30703)....................................... 27

• The NRC Inspection Manual inspection procedure (IP) or the Region I temporary

' instruction (RTI) that was used.as' inspection guidance is listed for each applicable report sectio i1

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DETAILS l

' Within this report period, interviews and discussions were conducted with varinus licensee . personnel, including reactor operators, maintenance and surveillance technicians and the licensee's management staff. Night shift inspections were conducted on April 10, 14, 17, 18, 19,-20, 24, 25, 26, and May 5,1989. Weekend inspections were conducted on April 7, 15, 16, 23,.May'6 and 7, 198 . Summary of Facility Activities i

Unit 1 The unit began the period shut down due to high sulfate levels in the Reactor Coolant System (RCS). Following rt;olution of the high sulfate issue (see Section 6.3), a slow heat up was initiated on April 18,'198 The unit was paralleled to the grid on April 22, 1989, and reached 100%

power on April 23, 198 On May 3,1989, power was reduced to 90% to repair #11 Circulating Water Pump oil pump. Repairs were completed and the unit returned to 100% power on May 4, 1989. On May 5,1989, the un't initiated a power reduction due to concerns raised relative to Unit 2 pressurizer heater leakage and the potential effects on Unit 1 (see Section 6.4). The unit ended the period in a maintenance shutdown pending the results of the pressurizer heater investigatio Unit 2 The unit was shutdown for the entire period for the 8th cycle scheduled refueling outage. The unit was scheduled to complete its refueling outage and return to power on August 7,198 General Region I specialist inspection personnel performed the following inspec-tions during this time period:  ;

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Week of April 10: mid-loop operation April 17-27: mai.ntenance, loss of refueling containment integrity and installation of temporary modifications. Inspection findings led to a subsequent En f.orcement Conference on May 30, 198 Enforcement actions are pendin _ _ _ _ - _ _

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Week of May 1: separate inspections for security and motor operated valve limitorque switche Week of May 8: inspections of refueling radiation protection, in-service inspection program and primary water chemistr Week of ' May 15: start of two week team inspection of Emergency l.- Operating Procedure . Licensee' Action on Previous Inspection Findings 3.1 (Closed) Inspector Follow Item (50-317/85-07-03): Motor Operated Valves (MOV) Torque Switch Setpoints. IE Notice 84-10 concerned improperly set MOV torque switches and indicated that inadequate controls over torque setpoints was an apparent cause. IE Notice 85-03 was issued to require licensees to develop and implement a pro-gram to ensure torque switch settings on certain safety related _ MOVs are selected, set and maintained properly to accommodate the maximum differential pressure expected on the valve The licensee has implemented maintenance procedures to control the set up adjustment

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and testing of MOV controls. Additionally, the methodology used to calculate the torque switch settings was developed consistent with recommendations of IE Bulletin 85-03. Further, all torque switch setpoints are maintained in a setpoint log which is controlled by Calvert Cliffs Instruction CCI-205, ' Setpoint Control Procedure. Tha licensee has satisfactorily addressed concerns raised by the inspec-tor. This item is close .2 (Closed) Unresolved Item (50-317/86-11-01): Main Steam Isolation Valve (MSIV) accumulator isolation. The licensee has completed evaluation of shift turnover practices which resulted in a General Supervisor of Operations Standing Instruction 86-5 requiring a pre-test briefing be conducted for any test which has reactor trip potential or main generator outpu Further requirements include a pretest briefing for each on-coming shift. In addition, the licensee has conducted team dynamics training for senior reactor operators and reactor operator Also, non-licensed operators have been given in-house team training to promote communication. The inspector has reviewed the licensee's attendance records to verify attendance to the aforementioned training. This item is close .3 (Closed) Violation (50-317/86-15-01: 50-318/86-15-01): Control and i Calibration of Measuring and Test Equipment. The licensee's response to the violation'~ discussed corrective action which had been imple-mente In the corrective actions, the licensee further discussed assigning a fully dedicated Test Equipment Attendan Inspection

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l Report (IR) 88-25 identified ' that' the attendant was being used for other duties. In response to IR 88-25, the licensee formalized the required administrative guidance which had previously led to the deviation from their commitment. This was done through the Elec-trical and Control Secticn Guideline - No. 30, Test Equipment Cage Rules of Operation. The inspector has verified implementation. This 1 item is close .4 (Closed) Unresolved . Item (50-317/88-08-01; 50-318/88-09-01): Aux 11-iary Feedwater System Check Valve Failure. The licensee has deter-mined that the application of the check valves in the system is cor-rect provided they are properly maintained and upstream isolation valves provide a tight shutoff. Additionally, the valves are being-tested for reverse flow to identify potential problem The root cause of the check valve failures was identified as resulting from leakage past the estream control valves, These valves have been modified to imprave snutoff characteristic The bypass valves around the control valves are scheduled for overhaul to reduce leak-age. Subsequently, the disks of identical check valves in both units have been examined and found to be in good condition. This item is close .5 (Closed) Unresolved Item (50-317/85-03-03): Auxiliary Feedwater System (AFW) Pump Room Ventilation. The licensee's Design Engineer-ing Section has reviewed the effe:ts of design basis temperature on all safety-related devices in the AFW pump room and concluded that the devices are fully qualified to withstand post-accident operation for 30 days without temperature induced failur The review and conclusions have been documented in Equipment Qualification Deviation Report (EQDR) for rooms T603 and T605. Design Engineering recom-mended that test procedures, Emergency Operating Procedures (EOPs),

and Abnormal Operating Procedures / AOPs) include the requirement to insure operation of the manual ror 3 cooler or the emergency ven-tilation system during steam driven AFW pump operation or testin Appropriate changes have been made to the procedure Secondary System Engineering will be conducting a test to verify adequate room cooling with the door closed during Unit 2 refueling outag This item is close ,6 (0 pen) Inspector Follow Item (50-317/88-04-01; 50-318/88-05-01):

Emergency Action Levels (EALs) Do Not Conform to the Guidance of NUREG-065 As documented in Section 6.6 of this report, an addi-tional example of the licensee's EALs not conforming to the afore-mentioned guidance was identified. As a result, the existing In-spector Follow Item is being upgraded to an unresolved Item for follow up during subsequent routine inspection of the licensee's emergency preparedness program.

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3.7 (Closed) Violation (50-317/86-07-02; 50-318/86-07-02): Failure to Implement the Requirements of ANSI 45.2.4 and IEEE 336. The in-spector reviewed changes to Quality Assurance Procedure (QAP ' 17, Revision 19 approved November 24,1987) which ' clarified licensee compliance with Regulatory Guide 1.30 which endorses ANSI 45. (March 1, 1972). Further, the inspector reviewed Electrical and Controls Standard Practices No. 28, which 'provides the means for implementing compliance with ANSI 45.2.4 and QAP 17. Inconsistencies with respect to the calibration sticker process have been recently observed by the NRC. This issue will be resolved by the NRC review -

of unresolved item 50-317/89-200-13. This item is close . Operational Safety 4.1 Daily Inspection During routine facility tout s, the following were checked: manning, access control, adherence to procedures and LCO's, instrumentation, recorder traces, protective systems, control rod positions, con-tainment temperature and pressure, control room annunciators, radi-ation monitors, effluent monitoring, emergency power source oper-ability, control room logs, shift supervisor logs, and op3 rating order On May 2,1989, during a review of shift turnover records, the l

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inspector noted that the main steam. isolation valve (MSIV) actu-ators for Unit 2 were removed and that the valve's plugs were considered to be the boundary for refueling containment integ-

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rit Technical Specification (TS) 3.9.4.c requires in b.,de 6 that each penetration providing direct access from the contain-ment etmosphere to the outside atmosphere during refueling operations shall be closed by an isolation valve, blind flange, or manual valve. Since the #21 steam generator's (SG) secondary i

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side manway was removed for J-tube work and ventilation, the licensee was relying on the MSIV valve plug as the boundary device to preclude direct access with containment atmosphere.

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The inspector questioned the licensee about the appropriateness of relying on the valve's plug to achieve compliance with the requirements of the TS and was informed that Temporary Modifi-cation (TM) No. 2-89-20, dated March 29,1989, was issued to

- address this condition. This TM documents the removal of the MSIV actuator and the need to maintain a containment boundary i

during refueling operations. Because the modification to remove the actuator changes the FSAR description of the MSIV, an ac-companying safety evaluation (SE) provided the written basis (

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that an unreviewed safety question was not create The SE takes credit for the fact that the status of the containment penetrations would be maintained per the TS. The licensee im-piements Surveillance Test Procedure (STP) No. 0-55A-2, Con-tainment Integrity Verification (Mode 6), to assure . that the subject TS requirement is me Given the current equipment status, the inspector was concerned that this procedure only indicated that the MSIV be shut and did not provide guidance to th plant operators on how to verify the required position with the actuator and position limit switched remove The opera-tions department was responsive to the inspector's concerns by revising and issuing Revision 14 to STP 0-55A-2 on May 3,1989, which provides the appropriate guidance for ascertaining that the MSIV is in a shut position when the actestor is remove Toward the end of the inspection period, the licensee was ad-dressing recent events and the results of NRC inspections that demonstrated a need to improve procedural adequacy. The in-spector's concerns pertaining to STP 0-55A-2 is further evidence that licensee management attention is warranted to resolve NRC concerns in this area. The inspector had no further questions on this matte At 7:30 p.m. on May 8, 1989, Unit I and 2 entered action state-ments associated with Technical Specification 3.8.1.2 and 3.8.2.2 as a result of systems affected by salt water system inoperability (see Section 8.1). On May 9,1989 at 1:00 p.m.,

the discharge valves on the salt water system for both units

..were throttled to compensate for the potential open failure of the air operated valves on the component cooling and service water cooling heat exchanger outlet. Operations used the locked valve deviation log and a temporary change to the Operating Instruction (01) 29, Salt Water System, to allow for throttlin During a routine inspection of the control room on May 9,1989, at approximately 2:30 p.m., the inspector inquired about the progress being made concerning the solution to the design prob-lem presented by the air tubing to the air operated valves on the salt water syste Operations personnel indicated that changes had been made to the valve alignment of the salt water system and that the units had exited the action statements re-garding salt water system inoperability. The inspector inquired as to the procedure used to make the changes and whether a 10 CFR 50.59 safety evaluation had been conducted and a Plant On Site Safety Review Committee (p0SRC) review had taken plac Operations personnel informed the inspector that a 10 CFR 50.59 safety evaluation had not been performed, that operations had  !

used the 01 29 procedure for the salt water system to change

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L system configuration and no POSRC review was conducted; The inspector indicated that the manipulations being executed on the salt water system were not described in' the procedure and that since the salt water system was a safety related system being placed in a configuration not previously described in the FSAR

- or approved by POSRC, it should receive a 10 CFR 50.59 safety-

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evaluation. Operations personnel agreed to contact licensing personnel to initiate a safety evaluatio The throttling of the salt water system discharge valves was determined by the operations ' personnel to require . prior POSRC approval. On May 9, 1989, at 7:00 p.m., the air operated valves were locked open and instructions placed in the General Super-visor-Nuclear Operations Notes and Instructions indicating ac-tions to be taken in the event that the outlet heat exchanger air operated valves failed ope The salt water system was considered operable based on the written planned actions. The POSRC determined on May 10, 1989, that modifications made to 0129 constituted a change of intent and that the salt water system should be considered inoperabl The action statements were reentered at 5:04. A 10 CFR 50.59 safety evaluation was performed by engineering and POSRC approved the evaluation on May 10, 1989. Revision to 01 29 was reviewed and approved by the POSRC and implemented resulting in exiting the action statements at 5:45 p. May 11, 198 The licensee failed to ocognize that a test was being conducted on a safety related system. The licensee controlling procedure, CCI 300, Calvert Cliffs Operating Manual, covert integrated system operation requirements. However, this particular evolu- I tion involved one system and the conduct of a test to determine salt water pump discharge valve position to preclude pump run ou The configuration change to the safety related salt water system without an appropriate procedure, the required 10 CFR 50.59 I safety evaluation, or the required POSRC determination that an

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unresolved safety question did not exist constitutes a violation (50-317/89-06-01; 50-318/89-06-01).

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The inspector observed operating crew activities on May 7, 1989, from 4:00 a.m. to 12:00 p.m. During this review the inspector-noted that the operating crew was attentive to their. duties and were maintaining the plant in a cooled down and solid pressuri-zer condition. A reactor operator was constantly observing primary pressure and ensuring effective implementation of the j' plant operating procedur .2 System Alignment Inspection Operating confirmation was made of selected piping system train Accessible valve positions and status were examined. Visual inspec-tion of major components was performed. Operability of instruments essential to system performance was assesse No unacceptable conditions were note .3 Biweekly and Other Inspections

'During plant tours, the inspector observed shift turnovers; boric acid tank samples and tank levels were compared to the Technical Specifications; and the use of radiation work permits and Health Physics procedures were reviewed. Plant housekeeping and cleanliness were evaluate During a plant tour of Unit 2 on May 7,1989, at approximately 7:30 a.m., the inspector noted two (2) caution tagged valves had been removed from the AFW (Auxiliary Feedwater) system. These valves, 2-AFW-146 and 2-AFW-147, were found laying on the floor next to the #22 AFW pump. A caution tag was attached to each valv Further investigation revealed that these valves were vent valves for the #22 AFW pump upper casing. These valves had been caution tagged in the open position to maintain a vent path while work was performed on the #22 AFW pump under Maintenance Order 209-009-057 Calvert Cliffs Instruction (CCI)-1121, paragraph III, H, states in part, " Yellow Caution tags are attached to operating devices to denote that the operating device is in a controlled status and is not to be changed or operated unless the restrictions noted on the tag are met". In addition,10 CFR 50, Appendix B, Criterion V requires that tagging activities be accomplished in accordance with the procedure I i

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Although removal of the tagged valves did ~ not precipitate a

. hazardous condition in this situation, removing caution tagged valves 2-AFW-146 and 2-AFW-147 from the AFW system is an ob-served weakness in that the operational status of the valves was-not " controlled" once they had been removed. Because of the low safety significance of the . observation, and the high level of attention that the licensee is giving to the area of safety tagging practices and procedural adherence, no further NRC ac-tion on this item is warrante However, the licensee should address in their corrective actions to upgrade performance in this program area increased sensitivity by plant workers as to the inappropriateness of allowing valves to be removed from their system and lay on the floor with safety tags attache The inspector had no further questions on this matter, Security 5.1 Observation of Physical Security Checks were made to determine whether security conditions met regu-latory requirements, the physical security plan, and approved pro-cedure Those checks included security staffing, protected and vital area barriers, vehicle searches and personnel identification, access control, badging, and compensatory measures when require No unacceptable conditions were note . Plant Operations 6.1 Diver in #24 Circulating Water Cavity During Dewatering With #22 Salt Water Pump Operating On April 28, 1989, at approximately 2:00 p.m. , a diver completed the inspection associated with the insertion of stop logs between the travelling screens and trash racks in the No. 24 intake cavity. The diver was located on the bay side of the stop log between the stop log and the trash rac The diver felt a pull from the water velocity into the cavity. The diver called the control room to in-quire whether there was any equipment operating in the cavit Operations personnel observed #22 salt water pump header pressure low and . in alarm. Shortly thereafter, salt water header pressure was observed rapidly going to O psig. Operations secured #22 salt water pump and started #23 salt water pump. All system valves were ob-served to be normal and reactor coolant system / shutdown cooling system temperature was constant or may have increased approximately one degree Fahrenhei ,

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Calvert Cliffs Unit 2 Circulating Water Pumps Intake Structure has a

' total of 'six intake cavitie Each cavity provides suction to o circulating water pump. Each cavity also is divided such that it requires two stop logs per cavity in order to dewater for mainten-ance. The salt water pumps also take suction from the intake cavi-tie Each salt water pump may be set up to take suction from one cavity or the' adjacent cavity by isolating one suction path with a

- sluice gat These sluice gates are approximately six feet below mean low wate On March 2,1989, plans were made to dewater #24 intake cavity to work on #24 circulating water pump and #24 A&B travelling screen On March 18, 1989, a tagout request was made for #24 cavity work.- On March 28, 1989, the boundaries were established for the work on #24 cavity and #22 salt water pum On April 18, 1989, tagging authority issued the clearance for the wor Some work was accomplished, however, on April 22, 1989, all clearances were requested to be returned because of a scheduled in-spection of #214-KV bus and #21 salt water header inspection. The maintenance orders were not returned. In addition, the tagouts and clearance boundaries were modified to allow the use of #22 3 alt water pump and valves and handswitches for providing cooling to the shut-down cooling heat exchanger via the component cooling heat exchanger from #22 salt water heade A modified clearance was issued on April 27, 1989, for stop logs into

1. 24 cavity and travelling screen This modified clearance did not recognize that with the approvals still in place for the old work order, that work would be accomplished without considering the modif-icetions made to the original clearance and that #22 salt water pump would not be tagged ou This action is contrary to established safety tagging control On April 28, 1989, the stop logs were pulled from #21 cavity and placed in #24 cavit The #23 cavity, the adjacent cavity, was de-watered with the sluice gate blocking suction to #22 salt water pump via alternate pat Personnel working on the installation of the stop log believed #22 salt water pump was still tagged.

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At 2:01 p.m., the diver was in the cavity on the bay side of the stop log. Work was ongoing to install the stop logs in #24 cavity. The diver felt a pull resulting from water velocity into the cavity. The diver called the control room to inquire whether there was any l l

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equipment operatin Operations personnel observed #22 salt water {

pump running, and its associated header pressure low and in alar At 2:04:30 p.m., the salt water header pressure was observed rapidly going to O psig. Operations personnel secured #22 salt water pum j At 2:06:29 p.m., operation.s started #23 salt water pump, observed all )

system values normal and the RCS/SDC temperature was constant or may have increased.about one degree ;

This event highlights the chronic communication and coordination problems which exist at this facility. The lack of communication and !

coordination between organizations responsible for the scoping, 1 planning, scheduling, tagging, controllig and execution of activ- !

ities resulted in an event which indicates the need for increased at-tention by management to assure that acti>ities are properly and safely planned and execute As a result of the event the licensee has taken the following cor-rective actions:

a) All tagging operations were stopped until an evaluation was com-pleted and tagging could be accomplished with proper assurances that the process was under complete contro b) A 100's audit of all tagouts was completed and discrepancies were addresse c) The Supervisor-Operations / Maintenance Coordination now requires two licensed operators to review all maintenance orders prior to starting wor d) All tagout boundaries were reverified for safet l

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e) Physical walkdowns and verifications are now required for tag- )

ging boundarie j l

f) All supplementary clearances issued under a main clearance will now be limited to six to control " housekeeping" problems. These clearances will be closed once returne I g)Y Tagout clearances, numbers and the tags themselves cannot be made out and issued until two days before the actual work is scheduled to begi ___ -

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h) All supplemental clearances were reverified and rewritte ). The GS-N0 directed that if sufficient licensed operators are not available in the Tagging Office, then the shift operating crew-will be used to verify and issue a tagout, j) The Safety Tagging Supervisor was it structed to retain the same personnel during the remainder of tae outage, operating condi-tions permittin k) All tagging modifications were restored to the original bound-arie Only emergency or small modifications are now allowe ) Improvements were made to the internal review p-ocess for approving tagout An administrative. review will now oe per-formed weekl m) All submitted tagout modifications were discarded after the event unless they had been previously approved and issued, n) Supervision emphasized the authority of the Tagging Office to deny an inadequate job scope or pla o) Supervision explained to the Tagging Office personnel and the opercting crews the overall goal and objectives of the plant schedule and outag p) All tagouts were located and the Supervisor-Outage Management Coordination (OMC) directed they only be kept in the Tagging Offic q) The Supervisor-0MC directed there would be no exceptions to the 3-day schedule for allowed work, and no fly-up work would be allowed except via the Shift Supervisor (priority 1 work), and the Outage Director (for outage work).

r) The Supervisor-0MC directed the Safety Tagging Supervisor to reschedule the tagging night shift for 3:00 to 1:00 with I hour of turnover time,10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> maximum per day, 6 ten-hour days maximu s) The Supervisor-0MC had individual intake cavity checklists written and verified, which will be used on any future intake dives.

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t) The Supervisor-0MC directed that tagging be manned with: a minimum of two licensed persons on each shift, 2 senior licensed persons on day shift with one per shift during outages, along with a minimum of 5 nuclear plant operators (6 during outages)

beyond those required to support local leak rate testin u) The Supervisor-0MC directed the planners to assist in clarifi-l cation of tagout boundaries and work scope and instructed them to have tagout plans ready / discussed with tagging by the job start date minus 2 days, or cancel and reschedule ' the jo v) The Assistant General Supervisor, Nuclear Operations (AGS-NO)

directed the Safety and Fire Protection Supervisor to have the Shift Supervisor or his designated representative attend all diving pre-job briefing w) Appropriate concern for the operability of the #22 saltwater pump following the loss of suction was demonstrated by the licensee by the performance of the STP No. 0-73A-2, Salt Water Pump Performance Tes Prior to the licensee's identification of this event, other significant events involving weaknesses in the control of system status and work ac-tivities had occurred (Section 6.2). These events are the subject of pending enforcement which envelopes the concerns involved in this even In addition, the immediate concerns for plant and personnel safety have been addressed by the licensee's _ short term' corrective measures. As a result of these factors no further NRC action on the identified defi-ciencies involved in this event is warrante The inspectors will be monitoring the licensee's corrective action during ,

routine inspectio l 6.2 Unit 2 Refueling Activities I On March 24,1989, Unit 2 entered a planned 65-day refueling outag This followed a plant shutdown on March 17, 1989, due to an increas-ing leak on #22 steam generator (SG) blowdown piping. Throughcut the inspection period, the unit was in a refueling outage status, and the inspectors noted the following significant conditions or events:

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The licensee observed high levels of fluorides in the #21 S This condition resulted from modifications being made to feed-water components inside the SG and failure to prevent the j resulting slag from entering the SG's secondary side inventor The chemistry department increased sampling frequency and q brought the condition to the timely attention of the POSRC for )

their review. The inspector determined that the licensee was j I

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. j 13 l appropriately concerned for the off-normal chemistry condition, assured that the condition received the correct level of organ-izational review for assessment of potential safety signifi-cance, and. implemented appropriate and timely corrective action As documented in Section '3.c of combined inspection report 50-317/89-04; 50-318/89-04, the licensee identified to the NRC on March 15, 1989, a .10 CFR Part 21 concern. involving the

. potential loss of required shutdown margin during refueling operation In response to this concern, the licensee had de-veloped Revision 16 to fuel handling procedure FH-6 to describe the methods to provide alternate locations in the core for fuel assemblies that could not be placed in their original location and ensure that a k-effective of less than 0.95 would be main-tained for all interim location At various times during the inspection period, the licensee in-creased the schedule of the outage. On May 2, 1989, the outage i was scheduled to take 107 days to complete, with seven days ac-counting for the unanticipated early shutdown on March 17, 198 Toward the end of the inspection period,

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licensee's man-agement redirected the priority and scope of work activities at the site to ensure initiatives identified in their Performance Improvement Program are fully developed and implemented. In support of this objective, Unit 2 refueling and maintenance items were given the lowest priority. The NRC views, as a positive development, the licensee's recognition that the com-bined activities associated with both units shutdown has o'ver-taxed their resources and that re-establishing priorities and I work schedules is appropriat During the refueling outage, two operational events occurred on April 17 and 22,'1989, that involved the failure of the licensee to maintain TS required refueling containment integrity during core alteration These events are the subject of an NRC com-bined special inspection 50-317/89-11; 50-318/89-11 conducted during April 17-27, 1989.

l 6.3 Unit 1 Shutdown Due to High Sulfate Concentrations in the Reactor

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Coolant System As discussed in Detail 3.j in the last Resident Inspection Report (89-04), on March 29, 1989, Unit I was returning to power following a maintenance outage to replace Reactor Coolant Pump seals and reduce control room deficiencies. Unusually high sulfate levels were detec-ted in the reactor coolant samples. At 7:45 a.m., a concentration of 208 parts per billion (ppb) was measure Six hours later, plant chemistry measured 299 pp The measured values were such that, pursuant to chemistry specification, continued operation might not be L_____ _.__ _u____ _

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advisable and shutdown should be considered. Further laboratory

investigation indicated that chemically reduced sulfates might be presen Thiosulfate was tentatively identified in one of the March 29, 1989 samples. However, subsequent samples did not substan-tiate or confirm the preliminary indications of thiosulfate in the

. reactor coolant system, thus, it was Disregarde Following consideration of the data collected and consultation with Electric Power R9 search Institute, Combustion Engineering, Chemistry consultants and - plant chemistry staff, the unit was taken to cold shutdown the evening of Aarch 29, 198 The licensee established a task team to put together a sequence of events of Unit I operations- from June 1,1988 to March 31, 1989. A review of the data indicated a 200-300 ppb sulfate spikes shortly af ter cooldown and drain down during the previous two outages. Du r-ing the March 1989 outage, the initial sulfate spike was tapering off when a 1800 ppb sulfate spike occurred on March 20, 1989. Sulfate levels returned to normal soon thereafter. The Task Team was directed to concentrate on determining the cause of the 1800 ppb spik A review of sulfur . bearing compounds that could have entered the Reactor Cociant System (RCS) revealed trace amounts of benzene sul-furic acid which is a decomposition component of resin. Additional possibilities for intrusion of sulfate into the RCS were evaluated (e.g., sabotage, undetected access and system inleakage). Having ruled out all other possibilities, the Task Team concentrated on ion exchange resin as the most likely fource of contamination. Following a review of a number of scenarlos involving the Chemical and Volume Control System (CVCS) ion exchanger, the Miscellaneous Waste ion exchanger and other possibilities which were inconclusive, the Task Team pursued the possibility of a failed outlet retention element on the ion exchanger. The Task Team concluded erroneously that the resin intrusion did not proceed from the CVC The task team then investigated the Spent Fuel Pool Cooling System, Make-up Water System and the Boric Acid Storage System as potential sulfate contributors and discounted the After the team reviewed their findings, there were strong suspicions that #12 CVCS ion exchanger was the cause of the increases in sul-fate. Further investigation indicated that the CVCS basket strainer downstream of #12 ion exchanged ripped along the seams of the 80 mesh filter material. This allowed small amounts of resin beads and fines from the ion exchanger to enter the RCS. As the resin broke down under RCS temperature conditions, sulfur was released. It has been postulated that sulfur plated out in the RCS. The increase in sul-fate concentration during the last two Unit 1 shutdowns could be attributed to the action of increased oxygen concentration on the

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l A safety assessment of the effects of resin in the RCS was complete The following issues were addressed.

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The sulfate concentrations observed in the RCS were considered l for their effects on both metallic and non-metallic components in the RC Both Combustion Engineering and BG&E metallurgical experts concluded that the increase in susceptibility to stress corrosion cracking was insignifican *

The mechanical effects of resin beads on operation of the fol-lowing equipment were reviewed:

CEAs Instrumentation RCPs Shutdown Cooling System PZR Safety Valves Letdown System PZR Spray Valve Sample System No safety concerns were identifie *

The results of the effect of resin on the fuel wcs reviewed by Combustion Engineering and preliminary indications were that resin beads break down to materials which are not harmful to the fuel or the RC The POSRC reviewed the safety evaluation and approvad the Unit 1 startup based on resolution of all safety concerns associated with the sulfate contamination investigatio The unit returned to power on April 23, 198 No unacceptable conditions were note .4 Identification of Defects in Unit 2 Pressurizer Heater Penetration Welds and Unit 1 Shutdown On May 5,1989, at 8:20 a.m., Unit 2 was in a refueling outage (Mode 6) and Unit I was at power. During an inservice inspection of Unit 2 pressurizer, personriel discovered indications of reactor coolant leakage around the pressurizer heater penetrations to the pressurizer vesse Twenty-two of one-hundred and twenty heater penetrations were identified to have visual evidence of boric acid crystals around the area where the heaters penetrate the pressurizer vessel lower head. The inservice inspection further indicated evidence of leakage in_a pressure / level nozzle tap on the upper head of the pressurize Upon discovery of the problem on Unit 2, the licensee initiated a shutdown on Unit I to allow for inspection of the pressurizer on that same da _ - - - - - _ _ .

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initial investigation indicated the boric acid formations tended to favor a pattern affecting the lower most level penetrations. Addi-tionally, the Unit 2 heaters were tested for low ground indications by heater bank groupings. The results were satisfactory in that all banks satisfied the acceptance criteria for insulation resistanc Examination of Unit 1 pressurizer heater area revealed no indication of leakage or boric acid crystal accumulatio The licensee has assembled a project team to address the following objectives:

a) Determine the mode of failure of the pressure boundary of both the pressurizer heater penetrations and the pressure / level nozzle tap on the upper head of the Unit 2 pressurize b) Determine if the failure mode of Unit 2 has implications for Unit , c) Make necessary repairs to ensure that the failure mechanism has been eliminate The licensee intends to keep Unit I shut down until a determination of the failure mode of the Unit 2 pressurizer heater penetrations is made and any repairs, if required, have been accomplishe The licensee's efforts during the discovery, pre planning, and or-ganizing phases of this event displayed the proper safety perspec-tiv Additionally, the licensee has halted efforts to refuel Unit 2 until a safety evaluation can be developed, reviewed, and approved that will ensure that the conduct of refueling operations with de-graded heater penetrations will not result in an unreviewed safety questio The inspectors will follow the licensee's corrective action program and will update progress in subsequent report .5 Control Element Assembly Drop Event On May 5,1989, at 9:12 p.m. , Unit I was in Mode 2 in the process of being shut down to allow inspection of its pressurizer heaters for possible leakages (see Section 6.4). Control Element Assembly (CEA)

1. 31 dropped while the rods were being inserted for reactor shutdow The unit failed to meet the Technical Specification (TS) Limiting Condition for Operation 3.1.3.1 and entered the applicable action statement 3.1.3.1(f). Additionally, operations entered Abnormal Operating Procedure ( AOP) -1B, CEA Malfunctio At 9:15 p.m., the unit entered Mode 3. In Mode 3, the TS action statement was not applicable and the AOP was exited at 9:25 p.m.

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'17 Maintenance personnel determined through troubleshoot.ing that the most probable cause of the rod drop event was a faulty 12 volt power supply. The power supply was replaced. ' Maintenance personnel used Maintenance Order-(MO) #209-128-944A and Maintenance Procedures

1. E-5 "Visicorder Set Up for. Reed Switch and CEDM Honitoring and Analysis" and # E-5 "CEDM Failure Scenarios, Troubleshooting Guide, and Troubleshooting Tasks" to troubleshoot and replace the power sup-ply. To insure tnat troubleshooting had identified the oot cause, the supplemental M0 #209-128-944A was initiated to test the associ-ated timer module and timer switch. A withdrawal and insertion trace was taken'of CEA-31 and found to be satisfactor No unacceptable ec.c.itions were note .6 Medical Emergency Involving Potentially Contaminated Individual At 1:58 a.w. on May 11, 1989, a contractor employee working on a-staffold in the Unit 2 containment's reactor vessel head laydown area

.:ollapsed from heat stress. The individual was wearing a respirator-at the time of the incident. The control room was notified of the situation and declared a Personnel Injury Event in accordance with th11r Emergency Response Plan Implementing Procedure (ERPIP) 3.0, Rev. 13. Because of conditions in the radiological . control area of the plant, it could not be determined if the individual was con-taminated, which resulted i lhe injured person being treated as if he we.; contaminated By 2:30 a.m., an ambulance was on-site to transport the victim to the Calvert Memorial Hospital. This hospital is designated in the licensee's Emergency Response Plan (ERP) to receive contaminated injured site personnel and has a Radiation Emergency area (REA). At 2:48 a.m. , the injured person was removed from the site by ambulance and the event was terminate The inspector reviewed the license's records of the event and dis-cussed the details of the event with cognizant personnel. As a re-

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sult of this review, the inspectnr noted the following:

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Personnel response to this event at the site and the REA appeared to be well controlled and conform to established procedure Following this event, licensee radiological, safety and emerg-ency preparedness personnel developed writter, critiques of various observations made during the even These critiques reflected positive performance as well as items that warrant licensee attention. The licensee's efforts to use actual events for lessons learned to assess and igrove future performance is a notable strengt I

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On_ _ May 11,1989, between 8:00 a.m. and 1:00 p.m. , state agen-cies, city agencies, the resident inspector and the cognizant NRC Region I emergency preparedness inspector were contacted by the licensee for the purpose of informing them that the incident Md occurred. The inspector reviewed the -applicable portion of ERPIP 3.0 to determine - _if the licensee had provided for the transportation of contaminated injured ir.dividuals from the site to. an offsite hospital in the licensee's Emergency . Plan. NUREG 0654, Rev.1, Criteria for Preparation 'and Evaluation of. Radio -

logical Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, indicates the aforementioned event as an example of an initiating condition that usually results in a notification of an Unusual Even NRC concerns pertaining to the licensee's failure to conform to the guidance of NUREG 0654 appears to be a longstanding regu-latory issu The NRC's Emergency Preparedness Appraisal (Com-bined Inspection Report 50-317/81-19 and 50-318/81-18) and In-spector Follow Items 50-317/88-04-01 and 50-318/88-05-01 docu-ment this concern. To ensure that the regulatory concerns re-ceive the appropriate level of attention by both the NRC and the licensee, the existing item will be upgraded to an Unresolved item for follow up during the routine inspection of the licen-see's emergency preparedness progra .7 Containment Iodine Filters Outside Desion Bases Due to Lack of Equipment Qualifications On May 5, 1989, the inspector attended a POSRC meeting that included the review of an engineerir., (determination that the containment iodine filters could not perfu. their design function for the length of time assumed in the FSAR 4.:,ident analysi This condition was applicable to both units and was the result of questionable power cables and fan :notors that are part of the filter system. This dis-ccvery of this condition by the licensee reflected on going activi-ties to upgrade the environmental qualification (EQ) file According to the licensee, the original radiation resistance factor of the equipment qualification used similarity assumptions for dif-ferent manufacturers of cross-linked polyethylene cablin The cur-rent analysis determined that the cable would receive the maximum dose that it could be qualified for in 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />. The licensee com-pared this condition against the FSAR Chapter 14.24 offsite dose calculations, which assumed that two containment iodine filters operated for 30 day The licensee has re-evaluated the offsite doses using more current methodolog The results indicate that the

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charcoal filters will have completed their safety function of re-moving iodine from the containment atmosphere approximately 33 minutes after the design basis accident begins. Current licensee plans include the update of the FSAR analysis using the more recent calculations performed to support the ' equipment qualification issue and the development of a 50.59 safety evaluation to support the FSAR chang The inspector questioned cognizant licensee representatives about the applicability of using an.FSAR update as the appropriate response to resolving this issu Particular concerns involved the following considerations: 1) TS 3.5.3 requires operable containment iodine filter trains and with the FSAR providing, in part, the basis for the TS, the margin of safety may be reduced by not having the system available for the specified 30-day period; and 2) a more current analysis. methodology is being used that in this particular applica-tion may not have received the proper level of NRC revie The licensee's representatives were responsive to the latter concerns by providing 'the inspector with various documents involving the NRC's issuance of Amendment Nos. 115 and 98 to the facility operating license of Units 1 and 2, respectivel These amendments allow the use of the four inch post accident hydrogen purge line for contain-ment purge during normal operation and, according to the licensee, used the same calculational methodology for determining site boundary doses as they are currently using to resolve the subject issu On May 8,1989, the licensee notified the NRC of their determination that this was a reportable even The licensee plans on issuing Licensee Event Report 50-317/89-06 to describe the event, it's con-sequences, and their intended corrective action The acceptability of the licensee's proposed corrective actions to resolve the EQ issues affecting the containment iodine filters is considered an Unresolved Item (50-317/89-06-02; 50-318/89-06-02). Maintenance / Surveillance 7.1 Maintenance i

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The inspector observed and reviewed maintenance and problem inves-  !

tigation activities to verify compliance with regulations, admin-istrative and maintenance procedures, codes and standards, proper  !

QALQC involvement, safety tag use, equipment alignment, jumper use,

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personnel qualifications, fire protection, retest requirements, and deportability per Technical Specification The following activities were reviewed:

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Temporary Modification No. 2-89-20, No. 21 Main Steam Isolation Valve (MSIV) Actuator removed for shipment to Rockwel I

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Maintenance Request (MR) A23876 Unit 1 Control ' Element Assembly No. 31 dropped ~into core on insertio Maintenance Order (MO). No. 208-336-016A, connect up portable air compressor to containment penetratio M0 No. 209-0390396, Install stop logs in No. 24 cavit M0 No. 209-040-480, Disconnect 24 A&B travelling screen M0 No. 209-052-942, Replace 2 inch Steam Generator Blowdown Line

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MO No. 209-009-057, Overhaul #22 Auxiliary Feedwater Pump Based upon a review of the above activities, the inspector had the following comments:

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On February 21, 1989, a maintenance order was generated calling for the replacement of 2 inch cabon steel piping on the blowdown line of #21 Steam Generator (SG). Unit 2 entered a refueling outage on March 24, 1989. Tags were hung on the blowdown line and clearance #29-586 was 1ssued on April 8, 198 On April 19, 1989, the second breach of containment refueling integrity occurred and on April 20, 1989, the licensee committed to review all tagouts and maintain refueling integrity through-out core off-loa Work began on the pipe replacement on April 28, 1989 and was expanded to include re:aoval of the 2-BD-102 valve, which was being used by Surveillance Test Pro-cedure (STP) 0-55A-2 to maintain refueling integrity with the

1. 21SG manway ope On April 29, 1989, Operations personnel found a yellow " Caution" tag la/ing on the ground under where valve 2-BD-102 was previously located and forwarded the tag to the tagging grou The tagout to support STP 0-55A-2 was

. changed to use valve 2-BD-101, which is a gate valve upstream of valve 2-BD-102, as the refueling integrity isolation valve for the blowdown line. During the period that the valve was miss-ing, there were no fuel manipulations underwa Although the yellow caution tag had apparently inadvertently fallen off the 2-80-102 valve, an orange Integrated Leak' Rate

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Test (ILRT) tag was attached to the valve. Contract maintenance workers had asked the safety tagging group if the existence of a

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the ILRT tag would preclude removal of the 2-BD-102 valve from the system and were informed that there were no restriction CCI #1121, " Safety Tagging," provides for the controlling of

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plant equipment only with tags that are authorized by the pro-cedure. The procedure does not' recognize the existence of these

- ar ange ILRT ' tags. When the inspector brought this condition to the licensee's attention, they indicated that a revision to the procedure to authorize the use of these tags, which existed ex-tensively out in the plant on Unit 2, was appropriate. 'This condition _ is a procedural noncompliance that has relatively low safety significance. Its occurrence is symptomatic of a general weakness that is receiving elevated licensee and NRC management attention, and as such further enforcement action is not war-ranted in this particular cas . 2 Surveillance The inspector observed parts of tests to assess performance in' ac-cordance with approved procedures and LCO's, test results (if com-pleted), . removal and restoration of equipment, and deficiency review and resolutio The following tests were reviewed:

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Surveillance Test Procedure (STP) No. 0-55A-2, Rev. 13, Con-tainment Integrity Verification (Mode 6).

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STP No. M-571-2, Rev. 15, Local Leak Rate Tes STP No. 0-73A-2, Salt Water Pump Performance Tes No unacceptable conditions were note . Engineering / Technical Support Instrument Air System Deficiencies On May 8,1989, the inspector attended a POSRC meeting that reviewed a memorandum from a Plant Engineering Department (PED) engineer that l discussed the acceptability of as-found instrument air tubing and supports in the component cooling water room. This memorandum was in response to a May 3,1989, POSRC meeting that requested a rationale to justi fy acceptability of the as-found equipment conditions to maintain operability following a postulated design basis earthquake (DBE). Air tubing for two specific valves was in question (1-CV-5206 and 1-CV-5208). Failure of the air supply of these valves following a DBE would result in the valves failing open and result in runout of the salt water pumps. The engineer's conclusion regarding the air supply tubing for these valves was that the as-found tubing would

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have survived a DBE, but may have been deformed and bent. The memor-

- andum indicated that: (1) other tubing may not have fared so well due to deformation which occurred over the years and many valves

would have gone to their fail safe positions if the tubing failed; and (2) the conditions generally were undesirable and must be promptly rectifie Had some of the deformation to other parts of the system been applied to 1-CV-5206 and 1-CV-5208 tubing, the results of the engineer's review would.have been differen The review by the POSRC, following a lengthy discussion, requested the engineer to return to POSRC at an unspecified date to inform the committee as to what were the design requirements of the air tubin Because the POSRC was unable to come to terms with the issue of whether they were meeting the requirements of the air tubing design, given the nature of the identified deficiencies, the inspector con-tacted the Plant Engineering Department Supervisor to discuss the issue. The Nuclear Engineering Department Manager also attended this meetin The licensee acknowledged the inspector's comments and concerns per-taining to the apparent inability of the licensee's engineering organizat10n and the POSRC to resolve the issue of operability of air system components that had readily identifiable deficiencies without knowledge of the design basis of the syste The engineers were using judgement that concluded it was reasonable to consider the sys-tem operable because they believed that following a DBE, function-ality would be maintained. Recognition that the original design may have included safety margins to compensate for design uncertainties and inservice degradation was not evident by the licensee'3 engi-neers. The licensee's approach to resolving this technical issue did not reflect a proper safety perspectiv Previous history relating to this issue was as follow On March 28, 1989 and March 30, 1989, licensee personnel initiated Non-conformance Report (NCR) Nos. 7765 and 7761, respectively, documen-ting material deficiencies involving tubing deficiencie The PED engineer responded on May 2,1989, to these NCRs. This response in-cluded the following items: In engineering's judgement, while the plant could be degraded

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during a seismic event, the 1-CV-5206 and 1-CV-5208 valves in question would fail safe but could be throttled and therefore there was no operability or technical specification violation that existed at the present tim )

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, Over the years, there had been a deterioration of the installed

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tubing and in many cases it no longer met all original design l and installation criteria.

.. The deterioration was mostly due to poor maintenance practice either due to shoddy workmanship, lack of expertise, or poor attitude on the part of the fitter, with poor QC involvemen This may have been due to the specific instructions given to QC requiring them to only work from their checkshee . At a POSRC meeting on April 28, 1989, concerns with tubing were raise Prior to the POSRC meeting on May 8,1989, the inspector was aware that the licensee had identified concerns with installed tubing meet-ing a currently used upgraded design known as M-500. Walkdowns of systems for Generic Letter 88-14 and a NCR related to conditions not meeting the M-500 upgraded design were the subject of intense PED efforts to resolve the concerns. The POSRC had generated Open Item 88-93-06 related to the M-500 update program. The PED engineer memorandum to the POSRC on April 28, 1989, and considered in the POSRC meeting of that date was in response to the open item. It indicated that a walkdown of the plant would show that designers' and installers' initial installation had been modified over time and in some cases bore little resemblance to the originally installed pro-duct. Tubing had been pulled out of tray sections and bent, clips were left out of tray sections, and generally, if still in its original location, the tubing run had been deformed. The engineer requested that the original open item dua date of April 26, 1989, be extended to August 24, 1989. It appeared to the inspector that the engineer was responding directly to POSRC concerns without an appro-priate level of review and involvement of the engineering organizatio At the conclusion of the May 8,1989, meeting with the licensee's representatives, the inspector was informed that they would review the deficient conditions in light of NRC's concerns that they be able to make a determination of operability, even though they were cur-rently not able to establish the as-built design requirements. The NRC was notified at 9:21 p.m. on May 8,1989, in accordance with 10 CFR 50.72, that instrument air tubing was determined to be outside the design basis of the equipment. Applicable TS action statements were entered in response to this determination. The acceptability of the licensee's approach to resolving instrument air tubing deficien-cies is considered an Unresolved Item (50-317/89-06-03; 50-318/

89-06-03).

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24 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 ade-quacy of corrective actio The inspector determined whether further information was required from the licensee, whether generic implications were' indicated, and whether the event warranted on site follow up. The following LER's were reviewed:

9.1 Unit 1 LER N Event Date Report Date Subject 89-03* 03/19/89 04/10/89 Engineered Safety Fea-ture Actuated Due to Failure to Follow a Pro-cedure Step-by-Step 89-04* 03/20/89 04/10/89 Engineered Safety Fea-

.tures Actuated Due to Operator Skipping Two Procedure Steps 89-05* 03/14/89 04/12/89 Failure of Instrument Air Boundary Check Valve Causing Possible Loss of Salt Water System During LOCA Conditions 89-06 04/17/89 05/17/89 Vent Paths Between In-side and Outside Con-tainment During Core Alterations Caused by Lack of Control of Con-tainment Closure Results in Two Violations of T.S. 3. .2 Unit 2 LER N Event Date Report Date Subject 89;03* 03/07/89 04/06/89 Plant Shutdown Resulting from an Air Leak en Feedwater Regulating Valve Caused by Failure to Identify the "eed to Perform Adequate Pre-ventive Maintenance

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L_ER N Event Date Report Date Subject 89-04* 03/01/89 05/03/89 Auxiliary Feedwater Pump

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Maintenance Error

89-05* 03/23/89 04/24/89 TS Surveillance Time Requirement Exceeded Resulting From the In-ability to Verify Re-produced Previous STP Data Caused by a' Lack of Adequate . STP Control

• Detailed examination of these events is documented in Inspection' Report 317/89-04; 318/89-0 No unacceptable conditions were note . Review of Licensee Response to NRC Initiatives 10.1 NRC Information Notice 89-33: Potential Failure of Westinghouse Steam Generator Tube Mechanical Plug This NRC notice describes a February 1989 event in which North Anna Unit 1 experienced a steam generator tube rupture. Post event in-vestigation determined a failed hot leg mechanical tube plug had been propelled by primary system pressure the length of the affected tube until it impacted and punctured the outer curvature of the tub Preliminarily, Westinghouse indicated the failure mechanism was in-tergranular carbide precipitation induced crackiag, possibly due to a low annealing temperature during milling. Westinghouse has initially identified plugs from two specific heat lot numbers as being most susceptible to this phenomeno The tuba plugs in place at Calvert Cliffs Unit 1 are not from the suspected heat However, Calvert Cliffs Unit 2 has 122 plugs from heat #3513 installed in their steam generator These plugs were installed in both hot and cold leg tubes in May, 1987, e

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Calvert Cliffs is currently in a refueling outage. The licensee will be removing all the hot leg plugs from the affected heat prior to Unit 2 returning to power. The cold leg plugs will be repaired and/

or replaced before their estimated lifetime expires. The licensee will be examining all Westinghouse mechanical tube plugs removed from Calvert Cliffs steam generators. Calvert Cliffs has discovered three plugs on the cold leg of steam generator #21 from heat #3513. At-i tempts have been made to remove two of these plugs unsuccessfully..

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Preparations are underway to remove the third plug via a different technique, if successful, the plug will receive a detailed metallur-gical analysi . Review of Periodic and Special Reports Periodic and special- reports submitted to the NRC pursuant to Technical Specification 6.9.1 and. 6.9.2 were reviewed. The review ascertained:

inclusion of information required by the NRC; test results and/or support-ing information; consistency with design predictions and performance spec-ifications; adequacy of planned corrective action for resolution of prob-lems; determination whether any information should be classified as an abnormal occurrence; 'and validity of reported information. The following periodic report was reviewed:

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April,1989 Operating Data Reports for Calvert Cliffs No.1 Unit and Calvert Cliffs No. 2 Unit, dated May 16, 1989.

l No unacceptable conditions were identifie . Events Requiring NRC Notification The circumstances surrounding the following events, which required NRC notification via the dedicated ENS line, were reviewed. A summary of the inspector's review findings follows or is documented elsewhere as noted below:

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At 8:20 a.m. on May 5,1989, the NRC was notified in accordance with l 10 CFR 50.72 (b)(2)(i) that a visual examination of the bottom head of the pressurizer, in the area of the heater penetrations, had re-vealed signs of boric acid leakage. This event is discussed in Sec-tion At 1:05 on May 8,1989, the NRC was notified in accordance with 10 CFR 50.72(b)(2)(iii)(c) that Environmental Qualification of the motor cables to the fan motors of the containment charcoal filters reflected that the aforementioned cables would only last 10 days as determined by calculation FSAR Chapter 14.24 assumes the contain-

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ment charcoal filters will last 30 days following a DBA. This event is discussed in Section 6.7.

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At 9:21 p.m. on May 8, 1989, the NRC was notified in accordance with 10 CFR 50.72(b)(2)(i) that the safety related instrument air tubing for the salt water system was found to be outside the design basi This event is discussed in Section . Unresolved Item Unresolved items requiring more information to determine their accept-ability are discussed in Sections 6.6, 6.7 and . Management Meetings Meetings were periodically held with senior facility management to discuss the inspection scope and findings. A summary of findings was presented to the licensee at the end of the inspectio T t

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