IR 05000317/1985015

Insp Repts 50-317/85-15 & 50-318/85-13 on 850618-0815.No Violation Noted.Major Areas Inspected:Control Room, Accessible Parts of Plant Structures,Plant Operations,Fire Protection & Physical Security

ML20135G578
Person / Time
Site:	Calvert Cliffs
Issue date:	09/09/1985
From:	Elsasser T, Foley T, Trimble D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20135G573	List: IR 05000317/1985015 ML20135G572
References
50-317-85-13, 50-317-85-15, GL-83-28, NUDOCS 8509190439
Download: ML20135G578 (17)

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U. S. NUCLEAR REGULATORY COMMISSION Region I Docket / Report: 50-317/85-15 License: DPR-53 50-318/85-13 DPR-69 Licensee: Baltimore Gas and Electric Company Facility: Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection At: Lusby, Maryland Dates: June 18 - August 15, 1985 Inspectors: b / [M -

kf[f5 f.Foley,Seni ident Inspector Date y 9, A Q Vl, M !Nes D. C. Trim esident Inspector Date Approved by: - -

T. C. Elsa$ etT Chief, Reactor Projects Section 3C fkJ Date Summary: June 18-August 15, 1985: Inspection Report 50-317/85-15,50-318/85-1 Areas Inspected: Routine resident inspection of the Control Room, accessible parts of plant structures, plant operations, radiation protection, physical security, fire protection, plant operating records, maintenance, surveillance, open items, Annual Emergency Medical Drill, documents provided to the licensee and reports to the NRC. Inspection hours totaled 238 hour0.00275 days <br />0.0661 hours <br />3.935185e-4 weeks <br />9.0559e-5 months <br /> No violations were foun Results: During the period the licensee demonstrated strong initiative and took conservative actions in identifying and correcting the root cause of recent fail-ures of the #21 Main Steam Isolation Valve. Weaknesses were noted, however, in two other areas. First, corrosion / erosion problems in the suction bells of the Salt Water pumps and a repair technique being used to correct these problems did not appear to have been adequately evaluated by the licensee. Second, two Unit 1 plant trips occurred due to personnel error (valve in a secondary system not re-stored to proper position after removal-of a system tagout and failure of operators to maintain proper steam generator level).

During the period the licensee identified a repeat problem associated with the separation of laminated sections of the armature of Reactor Trip Breaker under-voltage devices. The licensee plans to notify the vendor and industry of this problem. An NRC IE Notice on this subject is under revie DR ADOCK O

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DETAILS Persons Contacted 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 Unit I remained shutdown while repairs to the Main Electrical Generator lower stater bars insulation was'being effecte Unit 2 entered the period on its 26th day of full power operation since its last start u On June 24, 1985, Unit I was brought critical and commenced' low power physics

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testing with the Main Generator decoupled from the turbine. Two days later the testing was complete, and the unit returned to cold shutdown to perform additional eddy current testing on the Steam Generators, replace No. 12B Reactor Coolant Pump Seal, and refurbish No.12 Salt Water Pum On July 18, two pin hole sized steam leaks were -identified on a cold reheat line just above the Unit 2 High Pressure Turbine. Because of this, the licen-see shutdown Unit 2 on July 24 to examine and repair the steam pipe. During this shutdown Main Steam Isolation Valve 21 (MSIV 21) failed to fully close when required for surveillance test purposes. The licensee immediately em-barked on a test program to determine the " root cause" of the failur Re-pairs to the Cold Reheat line took about one day. Investigation of MSIV 21 continued for several day On July 30, after repairs to Unit 1 Main Generator were complete'd.and while

the unit was heating up to recommence operation, Reactor Coolant Pump (RCP)

11B experienced a failed sea The unit returned to cold shutdown to replace the No. 11B RCP sea On August 5 both units were near operating temperature. Unit 2 had identified and corrected several problems with 21 MSIV, and Unit 1 had replaced the RCP seal. Unit 2 became critical at 6:23 a.m. and paralleled to the grid at 10:05 a.m.. Unit 1 became critical at 2:05 p.m. and after generator testing paralleled to the grid at 4:03 a.m. on August 6. At 4:27 on August 6, Unit 1 tripped from 17% power due to a high level in the Moisture Separator Re-heator (MSR). At 1:50 p.m. Unit 1 returned to power operations. Later on August 6 Unit 1 tripped from 28% power at 9:46 p.m. due to a low Steam Gener-ator water level cond'ition. The unit was returned to power on August 7 at 5:47 a.m. , however at 7:50 p.m. tripped on " loss of load" from 50% powe The unit again returned to power operations at 9:35 a.m. on August 6, and re-mained at power throughout the rest of this period. The above events are discussed in detail in the paragraph entitled Events Requiring Prompt Notifi-catio . . , --

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g Four inspections were conducted by regional specialists in the following areas:

Post Accident Sampling; Radiological Waste Transportation; a follow up team inspection of Post Accident Sampling and related TMI Action Plan items; and Environmental releases / monitorin Facility housekeeping and Control Room environment and professionalism remain consistently goo . Licensee Action on Previous Inspection Findings (Closed) Inspector Follow Item (317/85-07-05) Need for Clarification of Pump-Vibration Monitoring Frocedure. The inspector reviewed Unit 2 Surveillance Test Procedure STP 0-73-2, ESFAS (Engineered Safety Features Actuation System)

Equipment Performance Test, Revision 22, dated May 24, 1985 and confirmed that the procedure clearly specifies the vibration sensing instrument to be used and the sensing points on the pumps to be monitored. The inspector confirmed with the Surveillance Test Coordinator responsible for vibration monitoring that similar information was scheduled for inclusion in the Unit 1 STP. In-corporation of this information was expected by August 15, 1985. This item is closed.

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(Closed) Violation (318/81-23-04) Technical Specification Instantaneous Radioactive Release Limit (for I-131 and Particulates with Half Lives Greater than 8 days) Exceeded. This problem resulted from apparent back leakage from the Volume Control Tank (VCT) through an in-line check valve to a nitrogen supply header relief valve (1-RV-105). This problem appears to have been an isolated event. VCT pressure is now administrative 1y limited to a maximum of 50 psig (by operator log) and an annunciator alarm at this pressure pro-vides warning to the operators of a high pressure condition. The inspector confirmed that the relief valve setpoint was checked during the Spring 1985 refueling outage. That valve setpoint is 70 psig. This 20 pound margin re-

. duces the likelihood of similar releases in the event of check valve back leakage with appropriate allowance for relief valve setpoint/VCT pressure instrument drift. This item is close (Closed) Unresolved Item (318/83-21-03) Installation of Improved Locking De-vices on Locked Valves. The licensee replaced clipped chain locking devices with pad locked chains. This item is close (Closed) Inspector Follow Item (317/83-18-02 and 318/83-21-01) Licensee Evaluation and Modifications to Ensure a Loss of Instrument Air Will Not Cause Unanticipated Failures of Safety Related Systems. As described in Sec-tion 2 in Inspection Report 50-317/84-03, 50-318/84-03, the licensee performed the above evaluation and found deficiencies in three ventilation system Facility changes have been completed on both units which resolve these de-ficiencies. Specifically, a second accumulator was added for motive air for the fan discharge dampers for the Emergency Core Cooling System Pump Room, Spent Fuel Pool,'and Penetration Room Ventilation Systems. This item is ,

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(Closed) Unresolved Item (317/83-31-05) Licensee Unable to Comply with Envi-ronmental Technical Specification (ETS) 2.3.B.4 in that Automatic Release Isolation Based Upon Iodine and Long-Lived Particulate Activity Does Not Exis This was due to an apparent error in the ETS's. The TMI Action Plan (II.F.1)

acknowledges that on line monitoring (measurement) of iodine may not currently

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be possible with presently available equipment. On July 1,1985 Technical Specification Amendments 105 (Unit 1) and 86 (Unit 2) were issued which de-leted Appendix B (ETS) and incorporated new Radiological Effluent Technical Specifications (RETS) into Appendix A. RETS does not include a requirement for automatic release isolation based on iodine and particulates. This item is close . 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-perature and pressure, control room annunciators, radiation monitors, radiation monitoring, emergency power source operability, control room logs, shift supervisor logs, and operating order No violations were identifie 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 perfor-mance was assesse The following systems were checked:

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Containment Cooling, Units 1 and 2 checked on June 28, 198 Iodine Filters Inside Containment, Unit 1, checked on July 11, 198 Emergency Boration, Units 1 and 2 checked on July 7.5, 198 Auxiliary Feedwater System,. Units 1 and 2 checked on August 12, 1985.*

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High Pressure Safety Injection System, Units 1 and 2 checked on July 16, 198 *For this system, the following items were reviewed: The licensee's

, system lineup procedure (s); equipment conditions / items that might degrade system performance (hangers, supports, housekeeping, etc.); instrumen-tation. lineup and operability; valve position / locking (where required)

and position indication; and availability of valve operator power suppl *

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(1) On August 12 during a verification of system operability, the in-spector noted that neither steam driven Auxiliary Feedwater pump 21 or 22 on Unit 2 were aligned for automatic initiatio The inspector verified that the No. 23 motor driven Auxiliary Feedwater pump was properly aligned and operabl Investigation of sta'us t of the pumps revealed that 21 AFW pump (normally aligned for automatic initiation)was removed from service for preventative maintenanc No. 22 AFW pump is normally aligned in the " standby mode" with both steam supplies locked shut. Tech-nical Specification 3.7.1.2 states:

"Two auxiliary feedwater trains consisting of one steam driven and one motor driven pump and associated flow paths capable of auto-matically initiating flow shall be OPERABLE. (An OPERABLE steam driven train shall consist of one pump aligned for automatic flow initiation and one pump aligned in standby.)* and

With one steam-driven pump inoperable:

(a) Align the OPERABLE steam driven pump to automatic initiating status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, and (b) Restore the inoperable steam driven pump to standby status (or automatic initiating status if the other steam driven pump is

to be placed in standby) within-the next 7 days or be in HOT SHUTDOWN within the next 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> With any two pumps inoperable: Verify that the remaining pump.is aligned to automatic initi-ating status within one hour, and Verify within one hour that No. 13 motor driven pump is OPERABLE and valve 1-CV-4550 has been exercised within the last 30 days, and Restore.a second pump to automatic initiating. status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in HOT SHUTDOWN within the next 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> *A standby pump shall be available for operation but_ aligned so that automatic flow initiation is defeated upon AFAS actuation."

i The 21 AFW pump had been removed from service in the morning on August 12 and was scheduled for approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of preventive maintenance. The Limiting Condition for Operation (LCO) stated above provides for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to align the standby pump for automatic initiatio Since'the maintenance would be completed prior to the expiration of the LCO operators did not realign the " standby pump" for automatic initiatio .-. . . -. .

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During discussions with the Plant Superintendent it was mutually agreed that the operating philosophy should be such that any time a component or system is out of service for any reason, and another is capable af performing the intended function of the component out of service, then it should be placed in service to minimize the time during which the margin to safety is reduced (allocated time of the LCO). The licensee immediately placed the standby pump in the automatic mode, which provided the original reliability and redun-dancy while performing maintenance on what now would be considered the " standby pump".

The licensee was requested to evaluate what other systems, (i.e.,

the " swing" HPSI pump) have standby components which could be used in lieu of the primary component to provide the original capabili-ties required by Technical Specifications rather than remaining in an Action Statement at a reduced margin to safety. The licensee stated they would evaluate the potential generic applicability on other system (2) During this period an incident took place at the Davis-Besse Nuclear Power Plant which highlighted problems associated with operator ac-cess to vital areas. The inspector reviewed licensee procedures in this area and determined improvements were necessary to expedite access. This subject was discussed with the Plant Superintenden Necessary procedure changes are planned to be made by August 12, 198 No violations were identifie c. 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 was reviewe Plant housekeeping and cleanliness were evaluate No violations were identifie d. Other Inspections (1) Cause of Failure of #21 Atmospheric Dump Valve Following a trip of Unit 2 on April 25, 1985 #21 Atmospheric Dump Valve failed open. The licensee determined the root cause to be mechanical interference of the positioner feedback linkage. The positioner was manufactured by Moore Products (Model #72G315). The remaining atmospheric dump valves were inspected. A similar poten-tial for interference was found and corrected in one of the Unit 1 Atmospheric Dump valve All problems were correcte *

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This is the only safety related application for these positioners, however, the licensee will check other Moore positioners elsewhere *

in the plant by the end of the yea (2) Review of Procedures for Mispositioned Control Element Assemblies (CEA's)

Because of industry problems associated with improper recovery of misaligned CEA's (which could potentially damage fuel cladding),

the inspector reviewed procedures in this are Those procedures did adequately define steps necessary for a recovery from a mis-positioned CEA. The inspector did note, however, a potentially confusing arrangement of steps in Abnormal Operating Procedure A0PIB, Revision 20, dated May 3, 1985. In Section II of that pro-cedure, "Mispositioned CEA's (greater than 15 inches miscligned)",

Step B.5 directs that if a CEA has been misaligned and a power re-duction was not commenced in less than one hour of the misalignment, then operators should not attempt to recover the CEA without first seeking the guidance of the Fuel Management Group (a shutdown to comply with Technical Specifications is an allowed exception). The potential confusion arises in that Step B.5 follows a step directing realignment of mispositoned rods that does not contain the precau-tions of B.S. An operator could, therefore, first realign a CEA and then realize his proper action should have been to first con-tact the Fuel Management Group for guidanc The licensee agreed that this was confusing and will appropriately modify the procedure No unacceptable conditions were identifie (3) Salt Water Pump Suction Bell Erosion / Corrosion During the period, operations personnel diss3vered through wall leakage on the suction bell of the #12 Salt Water (SW) pump. The pump was removed from service and disassemble During mechanical cleaning three additional holes were identifie The holes were finger sized and spaced around the periphery of the suction bell (near the top flange). Although general erosion / corrosion damage was evident on the surface area near the flange, the licensee de-termined that any significant wall thinning problems were confined to the localized areas of the holes. The holes and thinned walled areas were repaired with a metal filler material ("Belzona") and the surface was coated with coal tar epox Less severe damage of the same nature had previously been found and similarly repaired by the licensee on SW pump #21. A through wall hole on the #11 SW pump, due to erosion, was previously found and repaire In 1984 the casing of the #22 pump was found ~6o be near minimum wall thickness and is currently being monitored for further degradation (casing scheduled to be replaced at next Unit 2 refueling outage -

Fall 1985).

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The inspectors discussed this general problem with the Plant Super-intendent (PS) who stated that remaining Unit 2 SW pump suction bells will be inspected during the fall refueling outage and that the remaining Unit 1 pump will be inspected before that outag The PS also stated an evaluation will be conducted regarding the potential for and c7nsequences of further suction bell failures (including failures of Belzona material). This item will be fol-lowed by the NRC (IFI 317/85-15-01). The licensee's engineering group previously performed a safety analysis for the Belzona repairs of the suction bells (Facility Change Request 84-12). However, that analysis appeared inadequate in that it did not address the poten-tial for and consequences of failure of the Belzona plugs nor did it address the potential and consequences of failure of the as yet uninspected pumps (which history would indicate suffer similar degradation problems).

(4) Limited Review of ECCS Systems Subject to Potential Overpressuri-zation Due To A Intersystem Loss of Coolaat Accident (LOCA)

The inspector reviewed all Emergency Core Cooling Systems (ECCS)

connecting to the Reactor Coolant System and containing components or piping with design pressures equal to or less than 70% of the RCS design pressure. The purpose of this review was to confirm in-formation in NUREG/CR-2069, Summary Report on a Survey of Light Water Reactor Safety Systems. No discrepancies were identifie A sampling review of the testing of valves in-line between high and low design pressure systems was don Following is a summary of that testin Component Test Description / Plant Condition Shutdown Cooling Suction Cycled each refueling to verify auto-Motor Operated Valves (MOV's) matic closure at 300 psig RCS pres-sure. Also received Local Leak Rate Test (LLRT).

HPSI/LPSI Check Valves Forward Direction, full flow test once per refueling, (Surveillance Test Procedure STP 0-66), plant in Cold Shutdow LPSI Check Valve SI-114, Quarterly reverse flow (STP 0-65),

HPSI Check Valve SI-113 plant operatin HPSI/LPSI Shared Check Reverse Flow tested at refueling, Valve SI-118 Cold Shutdown (STP 0-66).

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HPSI/LPSI Shared Check No test conducted, however, a down-Valve SI-217 stream control room alarm annunciator and indication exist (alarm at 300 psig). ,

i HPSI/LPSI MOV's Timed Cycle Test quarterly (STP 0-65),

cycled monthly with automatic ESF actuation system (STP 0-7), cycled once per refueling as part of inte-grated ESF TEST (STP 0-4). Valve stroke times trende ,

Through discussions with maintenance and operations personnel, the j inspector learned that very few MOV problems have been experienced.

The surveillance coordinator could not recall any significant prob-

less with check valve back leakage. Two shift supervisors recalled, however, one isolated instance in the 1978 time frame when one HPSI

! leg was pressurized to full RCS pressure up to the normally closed

. MOV due to check valve back leakage.

I j Plant maintenance is not performed on the check valves. Every-other

refueling planned maintenance is conducted on MOV controllers, limit ,

j switches, torque switches, and insulation.

1 No unacceptable conditions were identified by the inspector during j this review.

$; Events Requiring Prompt Notification -'

) The circumstances surrounding the following events requiring prompt NRC noti-t fication pursuant to 10 CFR 50.72 were reviewed. For those events resulting i in a plant trip, the inspectors reviewed plant parameters, chart recorders, j logs, computer printouts and discussed the event with cognizant licensee per-

sonnel to ascertain that the cause of the event had been thoroughly investi- 1

gated; identified, reviewed, corrected and reported as required.

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During this period three plant trips occurred during the startup on Unit

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1. For each trip the licensee notified the NRC Duty Officer and all

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automatic reactor protection features responded as designed.

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On August 6, 1985, at about 4:30 a.m. while increasing power the unit automatically tripped from 1ZE power. The annunciator. indicated a tur-i'

bine trip, which caused an automatic reactor trip. The turbine trip was Leaused by a high level in the Moisture Separator Reheater (MSR). This l was due to a mispositioned isolation valve which was erroneously aligned

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. after a tagout was cleared on the MSR. ~This reactor trip was.due to a l breakdown in the tagout_ control _ system and could have been prevente i r

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At approximately 2:00 p.m. the unit returned to power operation. While escalating in power at 28% the unit tripped again. This trip was due to low steam generator water level which directly trips the reactor pro-tection system. The cause of the low water level was failure of the reactor operators to adequately control water level and coordinate the reactor power and feed the steam generator The inspector noted that this is an unusual condition for the operators since the reactor is at the beginning of core life and has positive temperature coefficient at this time, which requires a substantial change in operation by the oper-ators during startu This was discussed with the General Supervisor, Operations who stated that the onsite simulator would be programmed ap-propriately and the Training Department would be requested to incorporate these concerns in their program before the next startup from refuelin This trip was due to operator error, perhaps insufficient training, and could have been prevente The third trip occurred at approximately 8:00 p.m. on August 7,1985 due to a " Loss of Load" caused by the turbine thrust bearing wear detecto The trust bearing detector was apparently misaligned. The licensee's vendor normally makes this adjustment. This is not considered to be a trip that could have reasonably been prevented. The unit returned to power operation in the morning of August 8 and remained at power through the rest of the perio No violations were identifie . Observations 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 compen-satory measures when require No violations were identifie . Review of Licensee Event Reports (LER's)

LER's submitted to NRC:RI were reviewed to verify that the details were clearly reported, including accuracy of the description of cause and adequacy of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LER's were reviewed.

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i LER N Event Date Report Date Subject Unit 2

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85-02 05/06/85 06/05/85 Reactor Trip caused by an In-advertent Actuation of 21A RCP Overcurrent Device 85-03 05/18/85 06/17/85 Incorrect Fastener Material Used in Pressurizer Spray Valves 85-05 05/23/85 06/21/85 Recirculation Actuation Signal Inadvertent Initiation

85-06 05/26/85 06/21/85 Inoperable Diesel Generators 8. Plant Maintenance The inspector observed and reviewed maintenance and problem investigation ac-tivities to verify compliance with regulations, administrative and maintenance procedure, codes and standards, proper QA/QC involvement, safety tag use, equipment alignment, jumper use, personnel qualifications, radiological con-

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trols for worker protection, fire protection, retest requirements, and re-

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

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Purge of #21 MSIV Hydraulic Package observed on July 30, 198 Refurbishing of #12 Salt Water Pum Reactor Trip Breaker UV Device During routine maintenance on July 24, 1985 on Unit 1 Reactor Trip Circuit Breaker (TCB) #5, technicians noted that pickup and dropout voltages for the undervoltage (UV) device were below their minimum allowable values (pickup 101.1 volts vice specified minimum of 104 volts; drop out voltage 37.5 volts vice specified minimum of 36.3 volts). The laminated armature to pole piece gap was found to be below its minimum allowed value of .029 inches (actual

.022 inches). The licensee determined that the laminated sections of the ar-mature, which are riveted together, were loose on their rivet such that rela-tive movement between sections was occurring. 'A similar, but more severe, problem was noted on Unit 2 TCB-1 in February 1985 (see section 10 of Inspec-tion Report 50-317/85-02, 50-318/85-02) which caused excessive breaker trip

, response times. In the present case, TCB-5 on Unit 1, response time was not noticeably affecte The UV device on TCB-5 was replaced and the problem thereby corrected. The licensee plans to notify the vendor (GE) of the prob-1em and to advise other utilities (via " Network") of this problem. It should be noted that the licensee checks the armature to pole piece gap based upon a recommendation from a vendor representative. Pertinent service advice let-ters do not mention this check. Since other utilities may not be taking this

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measurement and since it may provide a valuable warning of subject lamination separation problem, the licensee will discuss this measurement in their in-dustry notificatio No violations were identifie . Surveillance Testing 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

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tests were reviewed:

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M220-1, ESFAS Functional Test, observed on July 10, 198 , MSIV Fast Stroke Test, observed on July 26 and 30,198 On July 10, 1985, while observing the performance of Surveillance Test Procedure STP M220-1, ESFAS Functional Test, the inspector noted that the terminal label plate was missing for the A2 terminal block in Sensor Cabinet ZE. The technician in charge stated that he would mention this fact to his supervisor and initiate a maintenance request for a replace-ment plat No violations were~ identified.

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1 Licensee Response to Generic Letter 83-28, Generic Implications of ATWS Events at the Salem Nuclear Power Plant The NRC's Region I office is assisting the Office of Nuclear Reactor Regula-

tion in reviewing the licensee's response to selected items of Generic Letter 83-2 The licensee's February 29, 1984 response to Item 3.2.1 described their review to assure that post maintenance testing of all safety related equipment was being performed. This review adequately addressed the item and was scheduled to be completed by January 31, 198 The inspector reviewed a sample of the documentation completed by the licensee for close out of their review. Through discussions with the licensee on July

! 18, 1985, the inspector determined that Item 3.2.1 had been properly closed by the licensee as a result of their completed revie . Annual Emergency Medical Drill On August 7, 1985 the licensee conducted the Annual Emergency Medical Dril The inspector witnessed various parts of the drill and discussed aspects of the drill with Mr. F. Rocco of Helgeson Scientific Services, consultant to the license l

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The drill consisted of two injured personnel, one seriously injured and con-taminated. The second individual required only first aid and local decon-tamination procedures. Both persons were located on the 45 foot elevation of the Auxiliary Building by the Steau Generator Blowdown tank when the in-juries were sustaine First aid was administered promptly and appeared ef-fective. Ambulance response was not hurried, nor was it untimel Calvert Memorial Hospital fully participated providing a very real simulatio Doctors and nurses worked well with Health Physics technicians decontaminating the injured man. Hospital procedures are in place and appear effective in handling radiological medical emergencies. The hospital facility and staff appear to be adequately supported with appropriate radiokpcal supplies and detection instrumentatio The inspector had no unresolved concerns regarding the medical dril . 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 . Main Steam Isolation Valve Operability The Plant Final Safety Analysis Report and Technical Specifications require that the Main Steam Isolation Valves (MSIVs) be tested by part stroking during operation and full stroke test per article IWV-3000 of Section XI of the American Society of Mechanical Engineers (ASME) Code (FSAR Section 10.1. and TS 3.7.1.5). ASME Section XI IWV-3400 also requires that power operated valves be time teste The licensee has been timing this part strokes of the MSIVs on a weekly basi During the preceding several months the licensee has been puzzled by erratic stroke times (34 to 190 seconds) apparently changing without cause on 21 MSIV. The other MSIVs have been consistently 50 +/- 20 seconds. Because of this a decision was made to full stroke / fast stroke the valve during the next available shutdow On July 24, 1985, while shutting down Unit 2 to repair a pinhole steam leak on a cold reheat steam line, the licensee manually initiated an MSIV closure of 21 MSIV in accordance with STP-0-1 " Main Steam Isolation Valve Test".

During this test the valve failed to fully close, and failed to meet the TS requirements to close within 3.6 second The valve was subsequently closed utilizing an installed hydraulic pum The licensee embarked on a test pro-gram to determine the cause of the failur Based on previous problems and subsequent test program described in Inspection Report 50-317/85-01 dated February 25, 1985, and current pressure data on cap end and rod ends (of the hydraulic actuator),the licensee determined that either air or nitrogen was entrapped in the hydraulic fluid or a gas bubble

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existed in the system thereby preventing the valve from being fully functiona Gas in the system would either displace fluid causing insufficient volume to close the valve or provide a gas volume to absorb the hydraulic force / pressure to shut the valv The licensee's program consisted of an operational evaluation during both fast and slow strokes of the valve. The following were performed before, during, and after the operational evaluation, as appropriate:

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System flushes of hydraulic fluid and replacement of hydraulic flui Checks of accumulator and surge suppressor bladders for gas leak Analysis of hydraulic fluid for total gas concentration and identifica-tion of specific' gas in solutio Comparison checks between 21 MSIV and other MSIV hydraulic package Attachment of visicorder test equipment to monitor instantaneous pressure parameter A simulated hydraulic accumulator failed bladder test to reproduce the failure mechanis Overhaul of the hydraulic oil pumps and check for air leakag Isolation of individual accumulators to determine reserve capacit Replacement of surge suppressor Refurbishment of hydraulic check valve Several strokes of the valve shortly after shutdown and after flushing the system appeared to indicate the valve was operable, (i.e., met the 3.6 second criteria of Technical Specifications) however, cap end pressures were not as per the technical manual (2400 psi vice minimum of 2600 psi after each stroke).

Test data appeared to reflect some time dependency associated with acceptable strokes of the valve in that: If a stroke was acceptable and then a period of 6-8 hours passed, the next subsequent stroke generally faile After.many unsuccessful and some successful strokes with indication that the

" Gas problem" still existed, the licensee determined that a Gas Surge sup-pressors bladder had failed (was leaking only during valve operation). The surge suppressor maintained 1200 psi and would drop to 1100 psi after cycling the MSIV. This was corrected and several sequential strokes passed the ac-ceptance criteria established by the licensee of 3.6 seconds overall stroke time (TS 3.7.1.5); 2600 psi cap end pressure after the stroke (FSAR) and le'ss than .2 seconds valve response time after initiatio .- . - _ _ _ _ _ _ _ - - _ _ ___ _ - _ - _ _ . _ - . . ~ _ . _ _ . _ - - . _ . ._ _

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l The valve was then declared operable and heat up to normal-operating tempera-i ture was performed 6-8 hours after the previous tests. This hot stroke failed to meet each of the acceptable criteria. An investigation revealed three i

failed accumulator bladders that appeared to leak only during valve function-

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l ing but otherwise would maintain between 3000 and 5000 psi.- The bladders were

! replaced, hydraulic check valves refurbished and the valve tested.

! The valve passed two sequencial tests and was also part stroked. All para- '

i meters returned to approximately those of the other MSIV's and also met all j established acceptance criteria. The determination of the root cause failure of MSIV 21 was pin hole leaks in high pressure hydraulic accumulators and

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surge suppressor bladders. This involved approximately 35 strokes of the i valve and seven days of testing. The licensee stated that as a result of this-i problem, the bladder leak detection (PM) procedure would be revised and per-

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formed weekly vice monthly, STP-0-47 MSIV part stroke test would be revised

to monitor reservoir level during strokes as an-indication of system voiding,

STP-0-1 MSIV Fast Stroke would be revised to verify bladder integrity before i and following fast stroke testing, and operator logs would be revised to re-

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cord MSIV reservoir levels once per shift to detect bladder failures. Addi-j tionally, " alert" and " action required" ranges would be established for the

! part stroke test by which the valve may be declared inoperable during opera-

tion should it exceed the action requirement limit.

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This licensee performance is in consonance with the NRC's policy on determin-ing the root cause of equipment failures prior to declaring a component oper-

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able. No inadequacies were identifie . Diesel Generator Interpolar Connectina Bars t

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Section 4d of Inspection Report 50-317/85-13,50-318/85-11 discussed failures in and removal of diesel generator interpobr connecting bars.

, Two region based NRC inspectors visited the plant site and the licensee's j metallurgical lab, examined the Diesel Generators, and held discussions with l plant personnel. The above report describes the fact that additional cracks l in connecting bar stubs left in two generators were identified by one of these

, inspectors. Those stubs were subsequently removed. Additionally, those in-j spectors arrived at the following conclusions.

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The inspector concluded that the BG&E Metallurgical Group had adequately in-l- vestigated and reported the failure cause anc had recommended' appropriate L corrective action.

f As the site did not initially remove the connecting straps at the position that would also remove shorting strap fatigue cracks, a lack of communication between the Metallurgical Lab and the site was noted. The BG&E QA/QC organi-zation is evaluating this occurience to identify and correct this apparent communication proble .

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The inspector reviewed the licensee's engineering evaluation, Facility Change Request (FCR) No. 95-1025, dated May 26, 1985, on-the change of the emergency diesel generators' output caused by removing the interpolar connecting straps which link the damper bars on the faces of the field poles. The FCR is based on information supplied by the manufacturer as evaluated by the BG&E electri-cal engineering departmen The inspector reviewed this evaluation and concurred with the licensee, after subsequent discussions with the manufacturer / vendor (Louis Allis), that by removing the copper connecting straps, the generators' output will have no measurable affect on voltage and frequency regulation nor will any relay co-ordination have to be recalculate Based on this review, the inspector concluded that the removal of these straps will change the negative sequence reactance and the subtransient reactance i

by increasing them. The net effect will be reduced fault current. The con-necting straps will have a measurable effect only when the generator is run in parallel with a unit of dissimilar size. Parallel operation of emergency diesel generators is in violation of Techncial Specification requirements.

Subsequent to the removal of the connecting straps, the inspector reviewed

] the Emergency Diesel Generator Surveillance Test Procedures (STP-0-4-1) for j

1. 12 and #21 generators to verify conformance with previous testing result In addition, the inspector reviewed the vibration analysis performed and con-cluded that voltage regulation currents, frequency, and vibration results were in conformance with prescribed procedure Based upon their followup of this event during the week of June 10, 1985, the region based inspectors concluded that the BG&E company had provided for

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evaluation of effects of removal of the interpolar connecting straps and pro-vided for removal of the straps including the fatigue cracks in the shorting strap stub Based on a review of operating history of 14 similar diesels without the interpolar connectors, a review of specific factors involving this

, issue, and input from the manufacturer and independent observations, the in-I spectors concluded that satisfactory preventive / corrective actions have been completed or were in progres No violations 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 reviewed. The review ascertained: In-clusion of information required by the NRC; test results and/or supporting information; consistency with design predictions and performance specifica-tions; adequacy of planned corrective action for resolution of problems; de-termination whether any information should be classified as an abnormal oc-currence, and validity of reported information. The following periodic re-ports were reviewed:

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April,1985 Operations Status Reports for Calvert Cliffs No.1 Unit and Calvert Cliffs No. 2 Unit, dated May 14, 198 May, 1985 Operations Status Reports for Calvert Cliffs No. 1 Unit and

Calvert Cliffs No. 2 Unit, dated June 17, 1985.

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June, 1985 Operating Data Reports for Calvert Cliffs No. 1 Unit and Calvert Cliffs No. 2 Unit, dated July 11, 198 During this period a memorandum dated April 12, 1985 to J. Taylor, Director IE from W. Dircks, Executive Director for Operations regarding Housekeeping and Control Room Behavior at Nuclear Power Plants was pro-

! vided to the Plant Superintenden This memo is believed to be in the Public Document Room.

j 16. Exit-Interview

Meetings were periodically held with senior facility management to dis.

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the inspection scope and findings. A summary of findings was presentei to the licensee at the end of the inspection.

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