IR 05000317/1987010

Insp Repts 50-317/87-10 & 50-318/87-11 on 870414-0518.No Violations Noted.Major Areas Inspected:Facility Activities, Routine Insps,Operational Events,Maint,Surveillance,Physical Security & Licensed Operator Requalification Training

ML20214V189
Person / Time
Site:	Calvert Cliffs
Issue date:	05/29/1987
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20214V176	List: IR 05000317/1987010 ML20214V174
References
50-317-87-10, 50-318-87-11, NUDOCS 8706120012
Download: ML20214V189 (12)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket / Report: 50-317/87-10 License: DPR-53 50-318/87-11 DPR-69 Licensee: Baltimore Gas and Electric Company Facility: Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection At: Lusby, Maryland Dates: April 14 - May 18, 1987 Inspectors: T. Foley, Senior Resident Inspector D Trimb e, Resident Inspector Approved by: . u/ 4 /8 I L. E. Trfp'p, Chief, Reactor Projects Section 3A date Summary: April 14 - May 18, 1987 (Inspection Report 50-317/87-10, 50-318/87-11)

Areas Inspected: (1) facility activities, (2) routine inspections, (3) operational events, (4) maintenance, (5) surveillance, (6) non-conforming commercial quality parts, (7) environmental qualification, (8) radiological controls, (9) physical security, (10) Licensee Event Reports, (11) Requalification Training for Licensed Operators, and (12) reports to the NR Inspection Hours totalled 17 No violations were identifie Results: Repetitive cracking in the vicinity of a socket weld of a branch line for a relief valve (2-RV-439) for the shut down cooling system continues to be a sig-nificant concern, particularly since the root cause of failure has not been posi-tively identified (Section 3 of this report). Significant numbers of deficiencies in the Environmental Qualification (EQ) program (principally in the area of taped splices) were identified during the period by licensee walk down inspections (Sec-tion 7). Additionally, the licensee identified that certain replacement items (principally threaded fasteners) not meeting construction code requirements had been installed in plant components (Section 6). Both the EQ and the replacement parts problems are significant and appear indicative of a more general problem with poor communication of engineering requirements to the field. An Enforcement Con-ference concerning the EQ issues was held in the Region I Office on May 13, 1987.

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DETAILS Within this report period, interviews and discussions were conducted with various licensee personnel, including reactor operators, maintenance and surveillance technicians and the licensee's management staf . Summary of Facility Activities At the beginning of the period Unit 1 was in cold shutdown (Mode 5) conditions for the ptrpose of correcting deficiencies in equipment qualification (EQ)

and U:ilt 2 was shutdown for refueling (Mode 6). Unit 1 had been shut down on April ?, 1987, after NRC inspectors found unqualified tape splices (two on each unit) on equipment under the scope of the environmental qualification (EQ) program (as required by 10 CFR 50.49) and after subsequent licensee sampling of EQ equipment revealed additional taped splices (discussed in Sec-tion 7 of this report).

On April 23, 1987, the licensee informed the NRC that certain replacement items (principally threaded fasteners) not fully meeting construction code requirements had been used in Class 1, 2, and 3 components on both units (Section 6 of this report). While the non-conforming parts appear to trie been manufactured from the correct material, they did not meet code require" ments with respect to marking, certification and, in some cases, non-destruc-tive examination. Resolution of this issue coupled with the EQ problems noted above forced Unit 1 to remain shutdown throughout the report period and ex-tended the Unit 2 refueling outage beyond the end of the report perio A conference call between licensee and NRC Region I personnel was held on April 16 to discuss EQ corrective action On April 20 licensee and NRC personnel met on site with a representative of the International Atomic Energy Agency (IAEA) to discuss an IAEA inspection scheduled for August 10-28, 198 NRC specialist inspectors / examiners visited the site for the following pur-poses: (1) Administer Operator License Examinations and review Operator Re-qualification Program (week of April 20), (2) review maintenance program (week of April 27), and (3) review In Service Inspection Program and 2-RV-439 branch line failure (week of May 11). An NRC team inspection was held during the week of May 11 to review the areas of EQ, non-conforming mechanical commercial quality (MCQ) replacement parts, and licensee departmental interface problems (a suspected root cause of the EQ and MCQ concerns).

Enforcement conferences were held at the NRC Region I Office on April 28 (Refueling Water Tank level transmitter isolation - NRC Inspection Report 50-317/87-09) and May 13 (Equipment Qualification).

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Unit 1 On April 14, 1987 containment spray.was inadvertently initiated due to opera-tor error in performing a valve lineup (see Section 3 of this report for de-tails).

Unit 2

On May 7, a leak developed from a pipe crack in the vicinity of a socket weld of a branch line for a relief valve (2-RV-439) for the shutdown cooling syste , The crack was very similar in appearance to one which was discovered at the

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same location earlier in the outage on March 24 (Section 3 of this report).

2.- Review of Plant Operation - Routine Inspections

. Daily Inspection'

During routine facility tours, the following were checked: manning, ac-cess control, adherence to procedures and LCO's, instrumentation, re-corder traces, protective systems,~ containment temperature and pressure, control rous annunciators, radiation monitors, effluent monitoring, i emergency power source operability, control room logs, shift supervisor logs, and operating orders.

, No unacceptable conditions were note System Alignment Inspection

. Operating confirmation was made of selected piping system trains. Ac-cessible valve positions and status were examined. Visual inspection of major components was performed. Operability of instruments essential l

to system performance was assesse The following systems were checked:

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1. 21 Service Water Subsystem l

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Modified Decay Heat Removal Flow Path during repair of 2-RV-439 No unacceptable conditions were note Biweekly and Other Inspections

! During plant tours, the inspector observed shift turnovers; boric acid l tank samples and tank levels were compared to the Technical Specifica-tions; and the use of radiation work permits and Health Physics proce-dures were reviewed. Area radiation and air monitor use and operational (- status were reviewed. Plant housekeeping and cleanliness were evaluated.

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No unacceptable conditions were noted.

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3. Operational Events Repetitive Cracking in Shutdown Cooling System Branch Line With Unit 2 shutdown for a refueling outage (Mode 5), during the midnight to 8:00 a.m. shift on May 7,1987, a leak (approximately 1 quart / minute) developed in the vicinity of a socket weld of a branch line for a relief valve (2-RV-439)

for the shutdown cooling (Low Pressure Safety Injection) system. The relief valve is located on a section of piping which is common to both shutdown cool-ing loops, making isolation for repair impossible without securing the normal shutdown cooling path. Fuel was in the reactor vessel and the vessel head installe A leak very similar in appearance had occurred at this same location earlier in the outage (March 24, 1987) and is described in Section 4 of Inspection Report 50-317/87-06, 50-318/87-0 Preliminary examination of the March 24 leak area indicated that it was due to low cycle fatigue. A repair /modifica-tion was made to the line which included: (1) a new half coupling; (2) new branch pipe; (3) relocation of the piping flange for the relief valve to eliminate a cantilever configuration; and (4) the addition of a support to remove loading / vibration in the socket weld area. Final confirmation of the root cause of the March 24 failure had not been made due to the difficulties associated with transporting the contaminated component to a clean laboratory

off sit During the above repair, a weld rod other than that called for in ( the repair procedure was utilized (however it was still of an acceptable l material). To comply with the procedure that weld was ground out and the weld j repeated with the specified rod materia Following the May 7 failure, an alternate shutdown cooling path, utilizing a combination of shutdown cooling and High Pressure Safety Injection System (HPSI) piping, was established. A repair, which maintained the then current design configuration was made. The inspector observed this repair. Again an initial examination of the leak area indicated a fatigue failur The inspector reemphasized to the licensee the importance of understanding the root cause of failure in that (1) this piping is used for both shutdown cool-ing and Low Pressure Safety Injection (LPSI), (2) this section of piping is common to both LPSI loops, and (3) the LPSI system was not designed for pas-sive failure. The Manager, Nuclear Operations directed the engineering de-partment to determine and correct the root cause of failure and stated the unit would not be started up until these actions were complete At the close of the inspection period, the engineering department planned to strengthen the design by replacing the half coupling with a weldolet. Instead of a socket weld, the piping will be attached to the weldolet utilizing a butt veld. The branch piping in the area will be increased to 3/4 inch diameter, schedule 80 (currently it is 1/2 inch, schedule 40). The failed material will be transported to the off site laboratory for confirmatory examination. Ad-ditionally, vibration readings were taken on the piping with the system

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operating and during LPSI pump start An Engineering review of the configu-ration coupled with the vibration data could not identify adverse loadings sufficient to cause the failur The inspector asked the Manager, Nuclear Maintenance and the Plant and Project Engineering General Supervisor if they had considered the possibility of set-point drift or improper operation of 2-RV-439 which may cause the valve to be cycling open and closed, thereby causing impact loadings on the affected area. This had been considered, and the valve had recently been checked for proper setpoint/ operatio As noted in Inspection Report 50-317/87-06, 50-318/87-06, the NRC will con-tinue to closely follow licensee resolution of this proble Inadvertent Initiation of Containment Spray About 1:15 p.m. on April 14, 1987, with Unit 1 in cold shutdown (Mode 5) con-ditions, containment spray (CS) was inadvertently initiated and discharged approximately 4,000 gallons of borated water from the Refueling Water Tank (RWT) into Containment (over a 3 minute period). The root cause was operator error in performing a valve lineup (per 0I-3-1, Rev. 34 dated October 1, 1986)

using #11 Containment spray pump to fill #11B Safety Injection Tank. The lineup called for shutting spray header manual isolation valve 1-SI-315. This would have isolated the spray header and prevented spray into Containmen However, the operator, after correctly performing the initial part of the lineup, mistakenly went to the wrong unit (Unit 2) and verified shut the corresponding Unit 2 spray header isolation valve (2-SI-315). That Unit 2 valve was tagged shut at the tim Normally, a air to close/ fail open control valve downstream of 1-SI-315 in the spray header is maintained closed, which would have also prevented the spray event. At that time, however, this valve was deenergized and therefore open due to ongoing EQ wor The operator involved was working a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shift (4:00 a.m.-4:00p.m.). From 4:00 a.m. to 8:00 a.m. he was assigned as the Unit 2 Auxiliary Building opera-tor and had performed valve lineups in Unit 2 rooms corresponding to the Unit I rooms in which the CS lineup was performed. From 8:00 a.m.-12:00 noon the

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operator was assigned as the Unit 1 Auxiliary Building operator. It was dur-ing this period that the error was made. The licensee now believes the rota-tion between units may have contributed to the error, and they have stopped this practic From 12:00 noon to 4:00 p.m. the operator was assigned to the Unit 2 fuel handling bridg The rooms (5 foot East Penetration Rooms) in which 1-SI-315 and 2-SI-315 are

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located are very similar in appearance and the room location markings are poor (grease pencil). Previously, the licensee had initiated a program to improve room door labeling using permanent signs outlined with color coding to help distinguish between units. However, these upgrades had not been accomplished

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in these rooms. These upgrades are scheduled for completion by the end of this calendar year. Additionally, the licensee is considering expanding the-use of color coding to include painting walls and floors as well as the door Because the SI-315 valves are normally locked valves (locked open), by station procedures they require a second check by another individual during valve lineups. This requirement, however, does not apply if the valve has already been tagged out to the appropriate position (2 individuals check valve tag-outs). Since the operator noted that valve 2-SI-315 was tagged shut, he did not get a second person to check that valve. Also because the valve was tagged shut and because this means two individuals have clready checked it, he apparently did not check it as closely as the other valves in the lineu The valves are clearly labeled with metal tags giving the valve number (1-SI-315 or 2-SI-315) and functional descripto Following the spray actuation event, the licensee established and later com-pleted a program to inspect for and correct equipment deficiencies that may have resulte No violations were identifie . Plant Maintenance The inspector observed and reviewed maintenance and problem investigation activities _to verify compliance with regulations, administrative and mainten-ance procedures, codes and standards, proper QA/QC involvement,' safety tag use, equipment alignment, jumper use, radiological controls for worker pro-tection, fire protection, retest requirements, and reportability per Technical Specifications. The following activities were included:

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Ray Chem Splice Installation on Charging Pump Motor Leads

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EQ inspections of 1-CV4150, 1-CV-4151, and Unit 1 RCS RTD's

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1. 22 LPSI Pump No unacceptable conditions were note . Surveillance

! The inspector observed parts of tests to assess performance in accordance with approved procedures and LC0's, test results (if completed), removal and re-storation of equipment, and deficiency review and resolution. The following l

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LLRT on Unit 2 Charging System Piping l

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Nozzle Dam Removal

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Unit 2 TM/LP Setpoint Change per STP M-510-2 No unacceptable conditions were note . Non-Conforming Commercial Quality (CQ) Replacement Parts On April 23, 1987, with both units in shutdown conditions, the licensee in-formed the NRC that certain replacement items (principally threaded fasteners)

not fully meeting construction code (ANSI B31.7) requirements appeared to have been used in Class 1,2, and 3 components. While the non-conforming parts are believed to have been manufactured from material meeting correct ASTM material standards, they do not meet code requirements for, depending on the class in-volved, marking, certification and/or non-destructive examination (NDE).

The replacement items of concern had been procured for safety related appli-cations under the licensee's Quality Assurance Program procedure which permits procurement of commercial grade items when it has been determined that there is sufficient competition in the industry and experience with the product to ensure that variations in quality are not likely to prevent the item from performing its functio The licensee committed to maintain both units shutdown until both this issue and the EQ issue were resolve A CQ task force was organized to resolve the problems. Outside experts were obtained to provide technical advice. The effort consisted of the following:

(1) an initial screening of all maintenance orders (M0's) that have been generated over the life of the plant (approximately 40,000) to identify jobs that could possibly have involved replacement of pressure boundary components; (2) a more detailed review of the approximately 10,000 M0's identified by the initial screening to look for possible installation of CQ material in Class 1, 2, and 3 systems and associated hangers; (3) a similar more detailed review of facility change requests; (4) and an evaluation of questionable items and determination of acceptability as installed or need for replacemen At the end of the reporting period the licensee had finished most of the re-views and was still evaluating questionable items in parallel with replacing material as necessary. They anticipated having to issue approximately 70 maintenance orders for material replacemen Similar to the EQ effort a tracking system for CQ task force activities was established. Daily status meeting were held. The inspector attended two early task force planning meetings and one of the daily meetings. Task force activities were reviewed by a special NRC inspection team during the week of May 11, 1987. Since the EQ and CQ problems possibly share a common root cause (poor communication of engineering requirements to the field / poor engineering and craft interface), the team examined these interface The team also re-viewed the EQ area. Results of that inspection will be documented under Inspection Report 50-317/87-13, 50-318/87-1 ..

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Following the close of the inspection period the licensee committed to test CQ items which have been removed from plant components (to confirm they were made of the proper material and measure mechanical properties). Licensee failure to comply with code requirements for certain replacement parts is unresolved pending receipt of these test results and determination of the safety significance of the problem (UNR 317/87-10-01;318/87-11-01). Environmental Qualification During the week of March 27, 1987 an NRC inspection identified unqualified taped electrical splices on four solenoid valves (SV's) included in the lic-ensee's EQ progra Unit 1 was operating at full power at the time, and Unit 2 was shutdown for a refueling outage. Subsequent to the NRC inspection, the licensee conducted a sampling inspection of Unit 2 EQ program SV's and found additional unqualified splices. Based on these findings, the licensee decided to shutdown Unit 1 to perform a review of the installed configuration of 10 CFR 50.49 equipment. The licensee committed not to start up either unit without first obtaining NRC concurrenc Prior to the above NRC inspection, the licensee's EQ program had been the subject of two NRC team inspections (October 15-19, 1984, Inspection Report 50-317/84-27; September 9-13, 1985, Inspection Report 50-317/85-22). The 1984 inspection was held prior to the NRC deadline for having an EQ program in place and was the first EQ inspection conducted by the NRC. That inspection noted several weaknesses, e.g. EQ files not auditable and lack of an EQ main-tenance program. The report urged increased involvement of Quality Assuranc The 1985 inspection report expressed concern with an apparent lack of adequate management attention with the establishment of a viable program to meet 10 CFR 50.49 requirements. This concern was based on a licensee failure to re-solve a concern noted in the first inspection (Rockbestos cable) and the identification of four new potential enforcement / unresolved items and eight open items. In December 1986 the licensee discovered taped splices on SV's for Auxiliary Feedwater steam supply valves CV 4070 and 4071, which are com-ponents in the EQ program. However, the fact that the splice connectione were not qualified by virtue of not having established qualification files w not previously recognized by licensee managemen Based on this history of weakness in the EQ area, the NRC encouraged the lic-ensee to consider obtaining third part expertise to review their EQ program prior to restart and to conduct a more complete review of their program im-plementation following start up. The licensee did obtain this expertis The licensee was advised that another NRC inspection of the EQ program would be conducted following the detailed third party revie The licensee then initiated an extensive orogram to do detailed inspections of all splices on 10 CFR 50.49 equipment ind to check installed configurations of this equipment against the EQ files. A special task force was organized to perform this work. An interim upgraded program was established to ensure clear communication of EQ maintenance requirements to craftsmen and to ensure work is completed as directed in those maintenance requirements. Following i

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start up of the units the licensee plans to resolve inconsistencies in engi-neering-instructions to the field (Drawing E-406). Regular EQ status meetings were held with site managers and the Vice President, Nuclear Energy. The inspector attended three of these meetings. The meetings were very detailed in nature and reviewed all of the identified discrepancy categories. A com-puterized tracking system for discrepancies was established. NRC inspectors witnessed walk down inspection of a motor operated valve, two solenoids . valves, and two temperature elements (RTD's) and monitored the installation of a Ray Chem. splice kit on charging pump motor leads. Completed EQ work on several penetrations and a motor splice for #12 High Pressure Safety Injection pump  !

was also reviewed. While witnessing a walk down inspection.on a SV associated with a Unit I containment spray valve, the inspector noted that switchboard (SIS) wire jumpers on the field side of terminal blocks inside junction boxes

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did not appear to be called out by the checklists as an item to be examined to ensure installation of only qualified wire. Other SIS wire terminated on the blocks was being checke Identification of jumper wires is often made difficult or impossible because printed vendor information markings may not i be found on the jumpers due to the short wire lengths involved. Initially, task force personnel did not respond to the inspector's concern on these jumpers. Later, after the inspector noted the concern to the site managers,

, jumper wires were promptly added to the inspection checklists and any neces-

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sary rework /reinspections were accomplished.

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On April 20 an Region I NRC manager visited the site to review the status of EQ corrective actions and to perform selected field inspections.

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During the week of May'11, 1987 an NRC team inspection was conducted that included review of the EQ corrective action program as well as review of actions to resolve a mechanical commercial quality (MCQ) replacement parts

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concern (Section 6 of this report). Results of that team inspection will be documented in Inspection Report 50-317/87-13, 50-318/87-14.

I An enforcement conference on EQ was held in the Region I office on May 13, 1987.

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As of the end of the inspection period, EQ corrective actions were essentially

completed on Unit 1 and were nearing completion on Unit No violations were identified.

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8. Radiological Controls

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Radiological controls were observed on a routine basis during the reporting

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period. Standard industry radiological work practices, confermance to radio-logical control procedures and 10 CFR Part 20 requirements wre observe No unacceptable conditions were identified.

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. Observation of Physical Security Checks were made to determine whether security conditions met regulatory re-quirements, the physical security plan, and approved procedures. Those checks included security staffing, protected and vital area barriers, vehicle searches and personnel identification, access control, badging, and compensatory meas-ures when require No unacceptable conditions were note . 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 cor-rective action. 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 re-viewed:

LER N Event Date Report Date Subject Unit 1 87-07* 4/01/87 5/01/87 Environmental Qualification Discrepancies Requiring Shutdown 87-08* 4/14/87 5/14/87 Improper Valve Lineup Resulting in Spraying Borated Water in Containment Building Unit 2 87-03* 3/24/87 4/22/87 Failure of Inlet Piping to Relief Valve (2-RV-439)

• Detailed examination of these events is documented in paragraphs 3 and 7 of this inspection repor No unacceptable conditions were note . Requalification Training for Licensed Operators On April 23, 1987 a Region I examiner conducted a review of the Calvert Cliffs requalification training related to the operational event described in the licensee's Licensee Event Report 86-07, reactor trip from 15% power due to Axial Shape Index (ASI). An effort was made to determine if a weakness in the licensee's requalification training prior to the event contributed to the operator error involved.

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LER 86-07 describes events related to a reactor trip on October 11, 1986 due to the operators attempting to reduce a high negative ASI condition by in-creasing reactor power from an initial low power condition of approximately 10%. The operators mistakenly thought that the increase in core delta T at a higher power would force power lower into the core and thereby improve the

. excessively high negative ASI. The operators failed to account for the com-bination of core burn up and the large Menon transient in progress at the time and further failed to note that ASI was producing an Axial Power Distribution reactor trip condition which automatically became effective when power ex-ceeded 15%. The ASI condition was not improved by the power increase and the reactor tripped when 15% power was reache The licensee's requalification training program provided a classroom lecture on Reactor Operations and Theory for all licensed operators between May 12, 1986 and June 9, 1986. The inspector noted that the learning objectives for this three hour lecture adequately included the effects on ASI of core burn up, moderator temperature, rod position, and xenon. The lesson plan appeared to integrate the theoretical aspects of this subject with plant operation A twenty point quiz was administered to each shift at the end of each one week requalification training session and included four points on ASI. The in-spector spot checked several operators' training records, including operators who were on shift at the time of the incident, and found that most operators received full credit on these relatively straight-forward ASI question Post event training conducted by the licensee consisted of two and one half hours of classroom lecture on this and past related events. The lecture was given to all operators between February 25, 1987 and March 25, 198 The inspector found that the basic concepts associated with ASI influencing factors were presented and tested on during licensee administered requalifi-cation training prior to the even Post event lessons learned and previous event lessons were integrated into a single lecture given to all operators as part of the continuing requalification training program. Thus, the licen-see's training program incorporated the necessary elements of knowledge, testing, and operational feedback to maintain adequate operator knowledge in this area. If there was any weakness to this process, it was only that the operators were not equipped to deal with the complexity of the factors in-fluencing ASI at the time of the incident. The inspector noted that although numerous simulator training sessions incorporate reactor start ups from various conditions, none addressed the specific situation of a end-of-cycle start up with a large xenon transient in progress. The licensee indicated that such a simulator scenario is presently being develope No inadequacies were identifie . Review of Periodic and Special Reports Periodic and special reports submitted to the NRC pursuant to Technical Speci-fication 6.9.1 and 6.9.2 were reviewed. The review ascertained: inclusion of infarmation required by the NRC; test results and/or supporting information;

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consistency with design predictions and performance specifications; adequacy of planned corrective action for resolution of problems; determination whether any information should be classified as an abnormal occurrence, and validity of reported information. The following periodic reports were reviewed:

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March and April Operations Status Reports for Calvert Cliffs No. 1 Unit and Calvert Cliffs No. 2 Unit, dated April 7 and May 8, 198 Report of Start Up Testing for Cycle 9.for Calvert Cliffs No.1 Unit dated April 15, 198 No un6cceptable conditions were identifie . Unresolved Items An unresolved item which requires more information to determine acceptability is discussed in Detail . Exit Interview

. 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 inspection.

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