IR 05000317/1986011

Insp Repts 50-317/86-11 & 50-318/86-11 on 860701-0831. Violation Noted:Msiv Accumulator Valve Isolation.Issue Re Exiguous Operator Awareness of Activities within Area of Responsibility Also Noted

ML20214T672
Person / Time
Site:	Calvert Cliffs
Issue date:	09/18/1986
From:	Tripp J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20214T638	List: IR 05000317/1986011 ML20214T636
References
50-317-86-11, 50-318-86-11, IEB-86-002, IEB-86-2, NUDOCS 8609300373
Download: ML20214T672 (17)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket / Report: 50-317/86-11 License: DPR-53 50-318/86-11 DPR-69 l

Licensee: Baltimore Gas and Electric Company Facility: Calvert Cliffs Nuclear Power Plant, Units 1 and 2

' Inspection At: Lusby, Maryland Dates: July 1 - August 31, 1986 Inspectors: T. Foley, Senior Resident Inspector D. Trimble, Resident Inspector D. Limroth, Project Engineer R Urban Reactor Engineer Approved: ,

(L. E. Trfph, Chief, Reactor Projects Section 3A b

/ D4te Summary: July 1 - August 31, 1986: Inspection Report 50-317/86-11, 50-318/86-11 Areas Inspected: Routine resident inspection of (1) facility activities, (2) opera-tional events, (3) plant operations, (4) events requiring NRC notification, (5) physical security, (6) Licensee Event Reports, (7) maintenance, (8) surveil-lance, (9) other NRC concerns, (10) IEB 86-02, (11) radiological controls, and (12) reports to the NR The inspection consisted of 261 hours0.00302 days <br />0.0725 hours <br />4.315476e-4 weeks <br />9.93105e-5 months <br /> of on site inspec-tio Results: One operational event per unit occurred for which the licensee demonstrated conservative judgment in pursuit of the resolution of the problems at hand (Detail 2). There was one licensee identified violation involving isolation of MSIV ac-cumulators (Detail 8) and one issue regarding exiguous operator awareness of on-going activities within the operator's area of responsibility (Detail 3.a). Lic-ensee actions for the latter two issues are yet to be completed and are tracked as unresolve PDR ADOCK 05000317 G PDR

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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 inspection period both units were operating at full power. At various times throughout the period each unit reduced power to clean water boxes due to marine growth and bio-fowling. On July 18, a SALP management meeting was held on site to candidly discuss the NRC's perception of licensee performance during the previous 18 months. On August 18, the site made preparations for Hurricane "Charlic." Except as noted, both units con-tinued routine power operations:

Unit 1 On July 10, a large influx of jelly fish, crabs, and marine life caused shear pins on the travelling screen motors to shear thus necessitating a power re-duction. This was followed by several days where the bay oxygen concentration was below normal causing increased marine life to accumulate at the intake structure. On July 20, Reactor Coolant Pump 128 tripped off, due to grounds within a capacitor, also causing a plant trip. The unit returned to service the following da On August 3, the licensee reduced power to perform a Temperature Coefficient Surveillance. During much of the month of August, personnel spent consider-able time in preparation for the upcoming ten year ISI refueling outage scheduled for October 25, 198 Unit 2 Conducted routine operations throughout most of July. However, on July 25, a decision was made to shut down due to a concern regarding increasing vibra-tion trends on RCP 218. Before shutdown commenced, a RCP 21A seal pressure transmitter flex hose end fitting separated causing a Reactor Coolant leak rate of about 1.7 gpm. Technical Specifications required the plant to shut down due to leakage greater than 1 gpm. An Unusual Event was simultaneously declared as required by the site Emergency Plan due to any forced shut down required by Technical Specifications. The plant remained shut down while industry experts evaluated vibration traces from RCP 21B until August I when the unit was restarte On August 21, Unit 2 reduced power due to a screen e. ash header pipe rupture which sprayed No. 24 and 25 circulating water pump motors. The unit returned to full power operations the following day and continued throughout the rest of the' perio __

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2. Operational Events July 20,1986 Unit 1 Reactor Plant Trip (RCP Capacitors)

On July 20 at 4:53 a.m., Reactor Coolant Pump (RCP) 128 tripped causing a Reactor Trip due to low RCS flow. During the lower flow condition, RCP 12A's vibration increased from its normal 13 mils to a maximum spike of about 40 mils, then subsided to varying values between 13 and 40 mil Engineers knowledgeable in vibration were called in to monitor and in-terpret the vibrations during the plant cool down. Once cooled down, additional instrumentation was installed to monitor the pump during start up and the permanent probes were adjusted. Investigation of the cause of the-RCP trip determined that one of three surge capacitors developed a short circuit to the casing of the capacito The capacitors on RCP 128 had recently been installed approximately 11 months ago during the prior refueling, as a result of refurbishing a RCP moto RCP 12B was a spare motor, containing (3) Westinghouse 13,800 volt, .05 mfd capacitors, style 634-Al-69A02. All the other capacitors on the rest of the RCPs are style 634-A2-69A02; the difference being a slight physical difference in the external cas The " blown" capacitor was sent off site for metallurgical and chemical analysis to determine the cause of the failur Three newer style A2 capacitors were installed and tested. Then the pump was operationally tested satisfactoril The licensee has experienced approximately 4 other plant trips in the preceding years caused by capacitor failures. As a result, a Preventive Maintenance instruction was written. PM 1-64-E-R-6 is performed on a refueling cycle and utilizes Westinghouse instruction IL-39-241-1C "In-structions for Radiation Resistant Surge Protection Capacitors" to test each capacitor for capacitance. A change in 1% from the name plate value or a change of 1% in readings between refueling tests requires replace-ment of the capacitor. Nonetheless, the capacitors are changed every 48 conths as recommended by the Westinghouse instruction Westinghouse has informed the licensee that they will not be manufacturing this type of capacitor in the future and that other sources should be sough The licensee has been investigating alternatives to the use of the capa-citors, the most likely alternative is doing without the surge capacito The corporate office electrical engineering staff is .in process of per-forming surge tests on a spare motor to confirm the effect of an engi-neering design change of operating without the capacitors. The licensee has a limited supply of spare capacitors on site. This event was accu-rately described to the NRC in Licensee Event Report 86-0 .

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On July 21 at 8:45 p.m., the unit was restarted while closely monitoring the Reactor Coolant Pumps' parameters. RCP 128 responded normally; RCP 12A vibration remained between 9-13 mils and has remained at that level until early August when the amplitude increased to the 14-16 mil rang The licensee continues to monitor the vibration and has again reevaluated the current conditions and set acceptance criteria for alert and for're-quired action f.e., securing the pump. This problem was also addressed in Inspection Report 317/86-09; 318/86-09 which provides additional de-tai b. RCP Sensing Line Break and Unit 2 Reactor Shut Down on July 25, 1986 Early in July the licensee began experiencing Unit 2 Reactor Coolant Pump vibration alarms due to RCP 218. Additional, more sensitive temporary instrumentation (described in Inspection Report 86-09, June, 1986) was removed from Unit 1 and installed on Unit 2 pumps to analyze the signals from the installed vibration sensors. Evaluation and trending of the vibration indicated a trend of increasing amplitude in the fifth harmonic indicative of possible damage associated with the five blade impeller of the pump. Several meetings were held evaluating the vibration data and industry experts were consulted. Simultaneously plans were made for an extended outage to remove and replace most rotating components of the pum On July 25, the licensee made a final decision to shut down Unit 2 to inspect and possibly overhaul the 21B RCP. Later in the day, at 1:45 p.m., before orders were issued to shut down, Unit 2 began experiencing indications of a Reactor Coolant Pump seal failure on RCP 21A. Contain-ment particulate activity increased about 500 counts per minute, reactor coolant primary system leakage increased to about 1.7 gpm (normal leakage is about 0.7 gpm), and the second and third stage seal pressures decreased to zero on RCP 21 A. Operators summarized that a seal sensing line had developed a leak since seal leak off is normally about 1 gpm and the in-creased primary system leakage was about 1 gpm. Because of a total un-identified leak rate of greater than 1 gpm and since the licensee had plans to shut down previously, the licensee decided to shut down immedi-ately due to leakage. Technical Specifications permit four hours to find and isolate the source or be in Hot Standby in the next six hour A concern was voiced that it was possible that RCP 218 vibration name plate or wiring might be switched with RCP 21A vibration instrumentation and therefore the indicated seal problems could be associated with the ap-parent worsening vibratio At 2:15 p.m. the licensee commenced a plant shut down, officially due to the RCS leakage being greater than 1 gpm and declared an Unusual Event as their emergency plan requires in the event of a forced shut down re-quired by Technical Specification .

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At 3:38 p.m., the Unit 2 Main Turbine Generator was manually trippe At 3:42, a steam line ruptured in the Turbine Building. Main Steam Isolation Valves were shut to isolate the steam leak, resulting in the Main Steam Safety Valves opening and reseatin At 3:55 p.m., the steam line rupture was identified as a vent line from No. 23 second stage Moisture Separator Reheater to No. 25 Feedwater Heater and was isolate At 5:15, the RCS leak was identified to be a middle seal Pressure Sensing line flex hose connection failure on RCP 21 A. The seal line was isolate During the shut down, RCP 21 8 was secured first in order to ascertain that the indicated vibration was associated with the correct pump. As the 21 B pump decreased in RPM, the amplitude of vibration associated with 21 B pump also decrease After the unit cool down commenced, Operators received " Loose Parts Monitor" alarms associated with the reactor vessel downstream of 21 B pump discharge. This further heightened the licensee's suspicion re-garding possible degradation of RCP 21 8 impelle After completing repairs to the failed sensing line flex hose, the Unit remained in Hot Shut Down and pressurized in order to test the 21 8 RCP, if deemed necessary. Further inspection and testing of the vibration probes on the pump took place while awaiting results of industry experts'

evaluation of vibration and loose parts monitoring traces. During this time an additional two velocity transducers and two proximity probes were mounted on the pum On July 30, the vendor's review of the RCP vibration trace, by an ex-perienced engineer, questioned whether that the problem was electrical in nature and likely to be associated with the sensing equipment. On July 31, the licensee completed a thorough examination of the installed vibration equipment. During the scrutiny of the proximity probes, a loose connection was found and believed to be possibly the source of the electrical interferenc The licensee and a Bentley Nevada technician checked all other cable connectors and both primary and secondary vibra-tion instrumentation with no additional problems. The licensee started the RCP and monitored vibration during the plant heat up. On August 1, the plant resumed operation, obtaining vibration data at various power level The licensee wrote guidelines, " Reactor Coolant Pump Performance Test,"

providing precautions, initial conditions, a step by step procedure and acceptance criteria for monitoring pump performance during plant heat u Plant heat up and subsequent power operation was accomplished without any further indications of abnormal vibratio Vibration on RCP 21 B has remained at approximately 10 mils throughout the remaining portion

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of the report perio The plant shut down due to unidentified leakage greater than 1 gpm, and the cause of the leakage was accurately described and reported to the NRC in Licensee Event Report 86-0 Simultaneously, licensee and Combustion Engineering representatives evaluated the Loose Parts Monitoring System (LPM) data. Several tests were performed to evaluate the possibility of a loose part in the Unit 2 primary system. The initial data indicated "a small Loose Parts Moni-tor indication on Channel 22 (North West Reactor Bottom) with the largest peak response of 2 Gs".

The licensee's program to evaluate this consisted of running RCP's in various combinations, then commencing a plant heat up monitoring pump D/P, Core D/P, pump vibration and the Loose Parts Monitor. This was performed up to 25% power, then evaluated. Traces at 50% and 100% were also evaluated. Based on these evaluations CE noted the following:

"There does not appear to be a loose part in the Unit 2 RC The LPM system at the Hot Standby condition (normal operating tem-perature and pressure with rods inserted) exhibited acceptable im-pact sensitivit Only five of the eight LPM transducers are fully operationa When the CEDM Trip Breakers are closed, energizing the CEDM coils, high frequency noise spikes are produced continuously by the mag-netic jack This CEDM noise is picked up by the LPM system. This unwanted large noise source requires that LPM alarm set points be set to values which reduce the LPM systems' impact sensitivity."

The licensee continued to monitor the LPM and sends LPM taped data to CE biweekly. The licensee has been requested by CE to be sensitive to any correlation between RCP vibration and LPM alarm activit The licensee's actions during these events were routinely conservativ Technically sound judgments which included a thorough approach to the resolution of the vibration problem was consistently demonstrated to the inspecto No unacceptable conditions were note . Review of Plant Operations Daily Inspection During routine facility tours, the following were checked: manning, ac-cess control, adherence to procedures and LCO's, instrumentation, recor-der traces, protective systems, control rod positions, containment tem-

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perature and pressure, control room annunciators, radiation monitors, effluent monitoring, emergency power source operability, control room logs, shift supervisor logs, tagout logs, and operating order Operator Awareness Routine inspection of Control Room activities results in periodic candid conversations with Control Room Reactor Operator During this inspection period the inspector questioned several Unit I reactor operators about the status of 12 A Reactor Coolant Pump (RCP) vibratio Operators were not aware of increasing trends in amplitude or that during the previous week, the vibration increased to 40 mils shortly after the RCP-12 B trip due to a capacitor failure, causing the reactor trip on July 20, 198 A Unit 2 operator, overhearing the inspector's discussion, validated that indeed the 12 A RCP vibration did increase to 40 mils. However, he had overheard this discussed between two senior operators. The inspector further questioned Unit 1 operators on whether testing of the Main Steam Isolation Valves had begun, (a planned evolution scheduled for a reactor temperature of 525 degrees Fahrenheit). Operators were not aware of the planned evolution and did not know whether or not the testing had begun (plant conditions of 525 degrees Fahrenheit had been achieved). The in-spector discussed with the General Supervisor Operations (GS0) the ap-parent lack of awareness of reactor operators regarding ongoing plant activities possibly affecting their area of responsibility and indicated that this concern had been addressed in previous inspection reports where operators were not cognizant of ongoing maintenance on No. 11 DC Bus (loss of which is the third most dominate risk sequence leading to a core melt pursuant to the Calvert Cliffs Interim Reliability Evaluation Pro-gram Analysis).

The inspector noted that this lack of awareness seems to be due, in part, to inadequate consolidated briefings of all personnel during shift turn-overs. Shift turnovers are done on a "one on one" basis and it appears that much information is sifted out or lost during the transmission through the ranks. It was also suggested that operators do not have the opportunity to provide immediate direct feedback to the shift supervisor when they feel they have an excessive amount of assigned work, or are somewhat unsure of the performance of an assigned tas This may have been a contributing factor leading to the failure of the two operators to unisolate MSIV accumulators causing inoperability of valves (see dis-cussion in paragraph 8). The licensee acknowledged the inspectors' con-cerns, stating that they recognized that shift turnover and communica-tions in general needed improvement, and that in order to improve com-munications, one shift of operations personnel were currently scheduled for a one day workshop on " Team Effectiveness Training". The training consists of a series of lectures and video tapes on team / group dynamics, characteristics of an effective team, conflict and agreement, feedback and application of the aforementioned topics. Additionally, the licensee stated that they would reevaluate shift turnover practices and ensure

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that turnovers adequately prepare all members of the shift to perform their functions. This will be followed as part of the unresolved matter discussed in paragraph 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. Power supply and breaker alignment was checked. Visual inspection of major components was performed. Operability of instruments essential to system perform-ance was assesse The following systems were checked:

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Units 1 and 2 High Pressure Safety Injections System Nos. 11, 12, and 21 Emergency Diesel Generators fuel supply starting air.*

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Units 1 and 2 Auxiliary Feedwater Syste *For this system, the following items were reviewed: The licensee's sys-tem lineup procedure (s); equipment conditions / items that might degrade system performance (hangers, supports, housekeeping, etc.); instrumenta-tion lineup and operability; valve position / locking (where required) and position indication; and availability of valve operator power suppl No unacceptable conditions were noted, Biweekly and Other Inspections During plant tours, the inspector observed shift turnovers; boric acid 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 evaluate No unacceptable conditions were note d. Other Checks On August 18, Hurricane Charlie became a potential threat to the Chesa-peake Bay area. Because of the concern, the licensee developed the fol-lowing interim procedural actions:

Condition Actions Hurricane Watch Obtain weather updates every four hours from the system operato . Test Diesel Generators in accordance with STP 0- .

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Condition Actions Hurricane Warning Secure outside equipmen . Shut intake watertight doors (IS-2 and IS-3) and latche . Recall emergency teams. Emergency team leaders must ensure they have adequate personnel for 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverag Onsite winds expected Reduce power on both units to 300 MW to reach greater than 70 miles per hour or sustained onsite wind speed measured at greater than 60 miles per hou Onsite winds expected to Place both units in hot standby reach greater than 90 per OP-3 and OP- miles per hour or sustained onsite wind speed measured at greater than 80 mp No unacceptable conditions were note . Events Requiring NRC Notification The circumstances surrounding the following events requiring prompt NRC noti-fication pursuant to 10 CFR 50.72 were reviewed. For those events resulting in a plant trip, the inspectors reviewed plant parameters, chart recorders, logs, computer printouts and discussed the event with cognizant licensee per-sonnel to ascertain that the cause of the event had been thoroughly investi-gated for root cause identificatio On July 20, 1986 at 4:53 a.m., a Unit I scram occurred due to low reactor coolant flow. All reactor protection features functioned as designe The cause of the low flow was due to a trip of Reactor Coolant Pump (RCP)

128, which tripped due to an under-voltage condition and was subsequently identified to be caused by a ground fault in the capacitors associated with the RCP (3 capacitors / pump). All appropriate notifications were mad This is discussed under paragraph 2 " Operational Events".

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On July 25,1986 at 2:15 p.m. , Unit 2 commenced shutdown due to RCS un-identified leakage greater than Technical Specification limit of 1 gp This is also discussed under paragraph 2 " Operational Events".

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At 5:40 p.m. on July 31, 1986, the Calvert Cliffs facility lost all tele-phonic communication except for a microwave phone to the dispatcher and a 2-way radio to the Maryland State Police.

The resident inspector and NRC branch chief were notified through the NRC Duty Officer by the system dispatcher. The inspector contacted the Control Room indirectly through the State Police and indirectly through the system dispatcher. The Control Room sent a spare person off site to contact the resident by local telephone line Hourly checks were made by the Control Room to the dispatcher. Microwave or 2-way radio to land line phone connections were not available. The cause of the event was due to road construction at the site access point.

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All communications was restored at 12:50 a.m., August 1,-198 Discussions were held with the licensee's Emergency Preparedness repre-sentatives to determine why the microwave communication system did not function as described in the licensee's emergency plan. Eight microwave lines should have been available to the Control Room operators to contact off' site official A licensee representative stated that corporate office telecommunications engineers are evaluating the problem and be-lieve it to be a software problem associated with the Emergency Off Site

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Facilities Computer. Communication hard and software performance will be evaluated by NRC during the September 9, 1986 emergency dril No unacceptable conditions were note . 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-

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ures when required.

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During this period the site security force developed and implemented plans for the upcoming refueling outage. Portions of this preparations consisted of the development of a Security Outage Coordinator, memorandum regarding requirements of security applicable to (1) Badge Accountabil-ity, (2) Guard Assistance, (3) Trailers and Tool Boxes, (4) Telephones, (5) Temporary Access, (6) Shift Schedules, (7) Protected and Vital Areas, and (8) Escorting. Additionally, applicable NRC Inspection and Enforce-

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ment Information Notices and recent enforcement action regarding security J

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and outage related events were distributed to licensee supervisor These actions reflect a proactive security force and are characteristic of positive attributes in consonance with good work practice 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 re-quired from the licensee, whether generic implications were indicated, and whether the event warranted on site follow up. The following LERs were re-viewe LER N Event Date Report Date Subject Unit 2 86-04* 07/20/86 08/07/86 Reactor was automatically tripped when a Low Reactor Coolant Flow trip signal

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was initiated due to a capacitor failure on RCP 128 86-05* 07/25/86 08/22/86 Flex Hose Fitting Failure

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on 21A Required Unit Shut Down and Unusual Event was declared

• Detailed examination of these events is documented in paragraph 2 of this report.

i 7. Plant Maintenance The inspector observed and reviewed maintenance and problem investigation ac-tivities to verify compliance with regulations, administrative and maintenance procedures, codes and standards, proper QA/QC involvement, safety tag use, equipment alignment, jumper use, personnel qualifications, radiological con-trols for worker protection, fire protection, retest requirements, and re-

, portability per Technical Specifications. The following activities were in-i cluded.

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PM-1-12-M-M-5, Clean and Inspect 12 ECCS Pump Room Air Cooler Strainer

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PM-1-15-I-Q-15, Component Cooling Pump Suction and Discharge Pressure Gauge Replacement

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PM-0-FP-W-3, Diesel Fire Pump Test

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PM-2-36-M-2M, 21 AFW Pump Vibration Readings

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PM-1-65-I-M-100, Seismic Instruments check During the period, a review was conducted of a Part 21 report sent to the NRC-from TELEMECANIQUE, Inc. dated May 23, 1986 regarding the use of ITE Gould Rotary Handles No. 0H-2795 R or Discussions with the licensee representatives indicated that the report was received, reviewed and acted upo The licensee's evaluation concluded that the failure of the handle on the switch was not a concern at Calvert Cliffs since the failure would only effect the indicated position of the breaker as stated in the Part 21 report and the licensee uses indicating lights as well as switch positions for indication of breaker statu The inspector reviewed several breakers and found no unacceptable conditions regarding switch positions or indicating light No unacceptable conditions were note . Surveillance The inspector observed parts of tests to assess performance in accordance with approved procedures and LCO's, test results (if completed), removal and re-storation of equipment, and deficiency review and resolution. The following tests were reviewed:

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STP-M-696-0, Fire Pump Flow Test

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FH-1, New Fuel Assembly and Control Element Assembly Handling, Inspection and Storage

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PSTP-4, Variable Tave Test using Group 5 Control Element' Assemblies

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STP-0-4702, MSIV Partial Stroke Test

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STP-055-2, Containment Integrity Verification

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STP-M-3-1, Main Steam Safety Valve

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STP-0-63-1, Remote Shutdown Instrument check Safety Injection System Check Valve During the performance of Surveillance Test Procedure (STP) 0-65-2, Quarterly Valve Operability Test (Revision 30), on July 2, 1986, Safety Injection System Check Valve 2-SI-148 was found to have very high back leakage (on the order

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of 40 gpm). That valve is a six inch Velan " balanced swing disc" check valve (Velan #P-34702) and has a weighted external lever arm which is oriented to maintain the valve in a normally closed position. A Containment entry was made, and a visual check of of the lever arm showed that the valve was in a full open or nearly full open position. When slight pressure was exerted on the lever arm, the valve close Hand movement of the valve, by means of the lever arm, was smooth with no significant resistance. Later a check of the torque on the packing gland was performed and showed agreement with that de-scribed in the Maintenance Order (MO) which installed the packing (the licen-see initiated efforts to confirm that the 15 foot pound torque valve listed in the MO was the vendor recommended value). A similar valve on a separate safety injection header was manually moved to the full open position by its lever arm. That second valve also would remain fully open until slight pres-sure was exerted on the arm. It would then close. Once 2-SI-148 was closed, its leak check was satisfactor There is one weighted lever arm check valve in each of the four safety injec-tion headers. Each header also has two additional check valves, of a differ-ent design, and a normally closed motor operated valve (MOV) at each High Pressure Safety Injection (HPSI) train tie in poin Because of the large number of check valves in series with normally closed

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MOV's, the Calvert Cliffs Interim Reliability Evaluation Program (IREP) judged the interfacing system Loss-of-Coolant accident not to be a significant acci-dent sequence with a probability on the order of IE-7 per reactor yea 'Although some piping in the HPSI system (upstream of the M0V's) is not rated for full reactor coolant system pressure (rated for 1600 psig; full system pressure is 2250 psig), that piping was at one time hydrostatically tested to 2460 psig. Even assuming a failure of 2-SI-148 to close, the licensee be-lieves that the probability of an interfacing system LOCA is still very low because of the redundancy afforded by the other valves in the injection header and because system piping would likely withstand full RCS pressur ~

ihe licensee committed to resolve the problem of the weighted arm check valves remaining in a full open position, and, in the interim, committed to verify these check valves are closed after each system operation which may cause the check valves to open (such as safety injection tank bleed and feed operations).

Licensee corrective action will be followed by the NR Main Steam Isolation Valve (MSIV) Accumulator Isolations On July 12, 1986, an operator performing a partial stroke surveillance test on the #11 MSIV noted that the isolation valves for accumulators No. 11 and 19 were closed or in the very nearly closed position. No apparent reason for these closures could be found and the valves were reopene Each MSIV is de-signed to be able to close with one of its nineteen accumulators isolated (FSAR Section 10.1.2.2). Each of the two MSIV's was required to be operable during the existing plant mode (Mode 1). The licensee reported the event via the NRC Emergency Notification System. Investigation showed that a Perform-

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ance Evaluation (PE 1-83-4-0-M) had been completed on this valve on July 4-5, 1986. This PE calls for isolating each accumulator, one at a time, and meas-uring the oil and bladder pressure in the accumulator to verify bladder in-tegrit No maintenance or other activity which would have resulted in ac-cumulator isolation had been performed on the valve since that time. The PE was repeated following discovery of the valve isolations and all bladders were found to be intact. An engineering analysis was conducted which showed that

1. 11 MSIV would have closed under design conditions with No. 11 and 19 accumu-lators isolate The July 4-5 PE had been performed over more than one shift. The operator who tested #19 accumulator was interviewed by the General Supervisor, Opera-tions (GS0) and later by the NRC inspectors. That individual partially walked the inspectors through tha evolution. The operator had relieved the watch with the accumulator in a drained condition. As required by Procedure OI 8-E, he cracked open the isolation valve to gradually recharge the accumulato At the time he was carrying out both the Unit 1 and Unit 2 Auxiliary Building-Operator duties since the Unit 2 operator was involved in a fuel moving evolution. To save time, he left the accumulator to take log readings in an adjacent are At the time of the inspector interview, that individual stated he could not recall fully reopening the #19 accumulator after finishing his log readir.g An NRC inspector and the GS0 jointly interviewed the operator who had tested the #11 accumulator. That individual had recently returned to the operations department following a three year assignment in the training department. He had not previously conducted this PE since his retur He could remember cracking open the isolation valve for recharging but could not definitely recall whether he had or had not subsequently fully reopened the valv The licensee concluded that both valve isolations were caused by operator error. The following corrective actions are planned:

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Evaluate shift turnover practices;

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Provide team training to Senior Reactor Operators and Reactor Operators, then evaluate the effectiveness of this team training and possibly pro-vide this training to non-licensed operators as wel This is expected to encourage team members to better communicate and feel less inhibited to express their own shortcomings and fears, and to speak up whenever they are uncertain or feel overloade This failure to follow Performance Evaluation 1-83-4-0-M by not returning two accumulators to service and thus causing a reduction in the conservatism of the system is a licensee identified violation. This event appears to meet the requirements of 10 CFR 2 Appendix C(V)(A) for not being cited by NRC with the possible exception of (4) which requires timely corrective actio Neither

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of the above corrective actions have been complete, nor reviewed by NRC. This matter is unresolved pending evaluation of licensee's actions and timeliness of those actions (317/86-11-01).

9. Other Concerns During the period, NRC personnel expressed concerns regarding functional testing of the. Safe Shut Down Panels used to effectuate a plant cool down in the event the Control Room is uninhabitabl The licensee maintains a remote shut down panel for each unit. Perform-ance evaluations, i.e., functional checks, are performed on each compon-ent of the system on a refueling basis and a channel check / surveillance of the remote shut down instrumentation is performed monthly pursuant to Technical Specification 4.3.3.6. The syste'm, however, has apparently never undergone a complete integrated functional test to determine whether an actual cool down could be accomplishe The inspector ascertained that training has at times been given to opera-tors on an informal basis on a remote shut down panel as part of simu-lator/requalification training, however, not all shifts nor all operators have received this trainin Discussions with the licensee indicated that they recognize the potential inadequacies in not performing an integrated test. The inspector was informed that training on the remote shut down panel will be made part of the formal operator requalification training program and that a one time test would be performed after the reactor is subcritical, either during shut down or prior to start up; that a unit cool down of approxi-mately 50-100 degrees Fahrenheit utilizing a remote shut down panel and other stationed personnel as necessary would be accomplished. The resi-dent inspector expects to witness this evolutio Another NRC concern was expressed regarding "once through cooling" also referred to as " Feed and Bleed" whereby a cooling medium is injected into the reactor coolant system and reactor coolant is discharged through a possible break and/or through the power operated relief valves or safety relief valve Initiation of this step causes large quantities of contaminated water to spill into containment causing considerable contamination problem NRC was concerned that the Emergency Operating Procedures may not ade-quately define at precisely what point once through cooling should be initiated and whether operators would initiate this step as require The inspector discussed this with several shifts of Senior Reactor Opera-tors all of whom knew the set point at which once through cooling should be initiated and indicated without hesitation that should core exit thermocouples reach 565 degrees Fahrenheit or Tcold reach 540 degrees

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Fahrenheit with feed water isolated, they would initiate cooling in ac-cordance with the E0P (3). E0P-3 " Total Loss of Feedwater" clearly states in step 4 when either of the above criteria is attained, then in-itiate once through cooling (by_... steps (a-f)). Operators and training instructors independently discussed the training operators received on the simulator with respect to once through cooling and other aspects of the Emergency Operation Procedure Operators appear to be adequately trained and willing to initiate once through cooling should the need aris . IE Bulletin Followup The inspector reviewed licensee actions on the following IE Bulletin to de-termine that the written response was submitted within the required time period, that the response included the information requested including ade-quate corrective action commitments, and that the licensee management had forwarded copies of the response to responsible on site management. The re-view included discussions with licensee personnel and observations and review of the item discussed below:

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IEB 86-02 Static "0"-Ring Differential Pressure Switches. Licensee re-sponse of July 29, 1986 indicates that these switches are not used nor are planned to be used at the Calvert Cliffs facility and therefore is not a concern at this sit . Radiological Controls Radiological controls were observed on a routine basis during the reporting period. Standard industry radiological work practices, conformance to radio-logical control procedures and 10 CFR Part 20 requirements were observe Independent surveys of radiological boundaries and random surveys of non-radiological points throughout the facility were taken by the inspecto No unacceptable conditions were identifie . 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 reviewe The review ascertained: inclu-sion of infornation required by the NRC; test results and/or supporting in-formation; cr.asistency with design predictions and performance specifications; adequacy of planned corrective action for resolution of problems; determina-tion whether any information should be classified as an abnormal occurrence, and validity of reported informatio The following periodic report was re-viewed:

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July Operations Status Reports for Calvert Cliffs No. 1 Unit and Calvert Cliffs No. 2 Unit, dated August 13, 198 No unacceptable conditions were identifie o

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13. Unresolved Items Unresolved items require more information to determine their acceptability and one such item is discussed in section' . Exit Intervi ty 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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