IR 05000423/1989002

Insp Rept 50-423/89-02 on 890124-0227.No Violations Noted. Major Areas Inspected:Plant Operations,Lers,Maint, Surveillance,Shutdown Bank D Failing to Move on Command & Reactor Coolant Pump B High Stator Temp

ML20246L856
Person / Time
Site:	Millstone
Issue date:	03/10/1989
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20246L847	List: IR 05000423/1989002 ML20246L843
References
50-423-89-02, 50-423-89-2, IEIN-87-004, IEIN-87-4, NUDOCS 8903240297
Download: ML20246L856 (17)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

j Report N /89-02 Docket N License N NPF-49 Licensee: . Northeast Nuclear Energy Company P. O. Box-270 Hartford, CT 06101-0270 Facility Name: . Millstone Nuclear Power Station, Unit 3 Inspection At: Waterford, Connecticut Inspection Conducted: 1/24/89 - 2/27/89 Reporting Inspector: .G. S. Barber, Resident Inspector Inspectors: W. J. Raymond, Senior Resident Inspector G. S. Barber, Resident' Inspector E. Yachimiak, Operations Engineer D. Jaffe, Licensing Project Manager Approvedby : deO. k O du E. C. McCabe, Chief,.R6 actor Projects Section IB

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3_/10l 89 Date Inspection Summary:

L Areas Inspected: Routine onsite inspection (115 inspection hours, with 11-.5 deep backshift hours and 16 total backshift hours) cf plant operations, Licensee Event Reports (LERs), maintenance, surveillance, Shutdown Bank "D" failing to move on command, "B" Reactor Coolant Pump (RCP) high stator temperature, safety injection with the Reactor Coolant System (RCS) in mid-loop conditions, Plant Incident Re-ports (PIRs), station blackout test; TI 2515/100, Proper Receipt, Storage, and Handling of Emergency Diesel Generator (EDG) Fuel Oil; Rosemount transmitter oil leaks, and licensed operator renewal application practice Results: No unsafe plant conditions, violations, or unresolved items were identi-fied. TI 2515/100 was closed. Control of entering Containment at power to deter-mine the cause for a high RCP stator temperature and the subsequent shutdown and cooldown demonstrated a strong safety attitude. Testing of potentially defective Rosemount transmitters was thorough. Prompt and consistent submission of a Trouble Report (TR) to generate the needed repair of degraded / defective equipment was not being accomplished (Detail 3.1). Licensee PIRs continue to identify repetitive instances of fire watches not being stationed as required (Detail 4.1). j 8903240297 890315 ~ .,

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l TABLE' 0F CONTENTS l l

PAGE 1.0 Persons

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Contacted.................................................... 1 2.0 Summary of Facility Activities........................... ........... 1 3.0 P.eview of Facility Activities......... .............................. 1 3.1 Shutdown Bank "D" Failed to Move on Command (71707).......... .. 1 l 3.2 Unplanned Shutdown Due to "B" RCP High Stator Temperature (71707)................................ ...................... 2 3.3 Safety Injection with the RCS in Mid-Loop Conditions (93702). . .. 2 3.4 MSIV Solenoid Vent Valve Stroke Failure (61726)................. 3 3.5 Reactor Plant Component Cooling Water (RPCCW) System Leaks (71707)......................... .... ........................ 4 3.6 Station Blackout Test (37700)........................ .......... 4 4.0 Plant Operational Status Reviews (71707)............................. 5 4.1 Review of Plant Incident Reports (PIRs) (90712)................. 6 5.0 (Closed) TI 2515/100, " Proper Receipt, Storage, and Handling of i Emergency Diesel Generator (EOG) Fuel Oil" (25500). . . . . . . . . . . . . . . . . 7 5.1 Fuel Oil Sampling and Tank Inspection........................... 7 5.2 System Design and Operation.............. ....... .............. 7 i 5.3 Filter / Strainer Preventive Maintenance.... ..................... 8 5.4 Seismic Qualifications of Instruments and Controls. . . . . . . ..... 9 5.5 Conclusions. .................................. ................ 9 6.0 Licensed Operator Renewal Application Practices (NRC Form 398)

(41701)..................................................... ...... 9 7.0 10 CFR 21 - Rosemount Transmitter Oil Leaks (36100)............... .. 10 l

l 8.0 Review of Licensee Event Reports (LERs) (92700). . . . . . . . . . . . . . . . . . . . . 13 l 9.0 Maintenance (62703)... ............................. ..... .. .... .. 14 10.0 Surveillance (61726).............................................. .. 14 11.0 Management Meeti ng s ( 31703) . . . . . . . . . . . . . . . . . . . . . . ...... ....... 15 l

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DETAILS 1.0 Persons Contacted Inspection findings were discussed periodically with the supervisory and man-agement personnel identified below:

S. Scace, Station Superintendent C. Clement, Unit Superintendent, Unit 3 M. Gentry, Operations Supervisor R. Rothgeb, Maintenance Supervisor K. Burton, Staff Assistant to Unit Superintendent J. Harris, Engineering Supervisor D. McDaniel, Reactor Engineer R. Satchatello, Health Physics Supervisor M. Pearson, Operations Assistant R. Stotts, Operations Training Supervisor B. Ruth, Operations Training Manager K. Covin, Operations Assistant 2.0 Summary of Facility Activities The plant began the inspection period at full powe Long term monitoring of "B" RCP Stator Temperature showed a slow increase to 292-294 degrees F over the 6 weeks prior to February 11 (see Detail 4.2). On February 11, power was reduced to 45%-50% to reduce containment radiation levels. A containment ;

entry was made at 10:21 The entry team exited at 11:46 Management I reviewed the team's findings and concluded it was necessary to shut down and i proceed to cold shutdown (Mode 5) to replace the "B" RCP stator cooler. Ex-cessive boric acid buildup on the stator cooling coils did not allow adequate cooling air flo Mode 5 was entered at 2:33 p.m. , February 12. The source of boric acid was a leaky hot leg stop valve that was repaired and satisfactorily reteste Heatup was commenced. The turbine was on-line at 11:22 a.m. , February 23 with 95% power being reached at 4:00 p.m., February 24. Power was limited since the "A" heater drain pump was removed for repairs. Power remained at 95%

through the end of the perio .0 Review of Facility Activities 3.1 Shutdown Bank "D" Failed to Move on Command (71707)

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Shutdown Bank "D" failed to move when commanded at 6:25 p.m., February J 11 during reactor shutdown. The reactor was being shut down to correct I the cause for a high "B" RCP stator temperature. The on-shift operators contacted Instrumentation & Control (I&C) to troubleshoot the proble I&C recommended cycling the bank select switch and attempting to move the rods again. The switch was cycled and rods were driven inwar i l

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The inspector reviewed-this event and noted that the Shift Supervisor's (SSs) log did not document the submission of a trouble report, nor did the select switch have a trouble sticker on i The submission of a trouble, report (TR) and its documentation in the SSs log assures that L equipment problems are addressed. Timely submittal of TRs ensures that work packages will be written to correct problems. In this case, in--

spector followup on the faulty rod select switch was necessary to initi-ate a trouble report. The submission of TRs and.their documentation in the SSs log will be reviewed further during future routine inspection .2 Unplanned Shutdown Due to "B" RCP High Stator Temperature (71707)

The licensee began a downpower at 1:05 a.m., February 11 to make a con-tainment entry to evaluate a "B" Reactor Coolant Pump (RCP) high stator temperature. Plant power was reduced to 45-50% power to lower the dose rates inside containment prior to the entr The licensee's maintenance and I&C (Instruments and Controls) organizations participated in the entr The spare Reactor Coolant Pump was used as a mock-up in pre-planning the. entry. Maintenance determined that boric acid buildup in the area surrounding the RCP stator cooling coils had reduced air flow enough'to impede RCP stator heat removal. I&C measured the spare RTDs'

output by using a digital voltmeter and comparing it to the indicated temperature of 292 degrees. This comparison confirmed that an actual high temperature condition did exist. The licensee evaluated the cause as boric acid buildup on the stator cooling coils based on reports from the entry team. Per Westinghouse, the primary function of these coolers is to minimize the heat load on the containment atmospher The licensee, in conjunction with Westinghouse, determined that, if stator temperature exceeded 311 degrees F, then the RCP must be shut down within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to prevent excessive insulation breakdown. Although the limit was not exceeded, the licensee decided to continue to shut down and to cool down to cold ;onditions. While shutdown, a contamination survey identified the source of boric acid as a leaking hot leg stop valve. The RCS was drained to mid-loop and the valve was disassemble Licensee inspection showed that the valve's gasket was slightly cu The gasket was replaced and the surface was cleaned and leak checke A successful post repair test was conducted. Heatup was commenced. Mode 3 was entered on 4:10 p.m. , February 21. The turbine was on-line at 11:22 a.m. , February 23, and 95% power was reached at 4:00 p.m. , February 2 Power was limited since the "A" heater drain pump was removed for repairs. The licensee plans to inspect all eight stop valve gasketed surfaces during the next refueling outage. The inspector had no more question .3 Safety Injection with the RCS in Mid-Loop Conditions (93702)

A safety injection (SI) occurred at 8:23 p.m., February 17 with the plant in cold shutdown at mid-loop condition The plant had been shut down earlier with RCS level drained to mid-loop to repair a leaky hot leg stop l

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valve. The plant responded as designed to the."B" train SI with one ,

exception: one chill water. containment isolation valve (3CDS*CTV40) on one of four. return lines failed to clos ~

That. valve'was closed. manuall Subsequent retests showed acceptable operation. Feasibility of periodic

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valve cycling to assure operability will be addressed in future inspec-tion !

The SI was reset one minute af ter'it initiated. Only the "A" charging  ;

E' pump injected because the SI pump breakers were racked down and the RHR' l pumps remained in their shutdown cooling mode, which interlocked their RWST suction valves close The maximum volume injected was estimated at less than 650 gallons since this equates to the maximum flow expected-at pump runout conditions. RCS level rise remained below the top of the hot leg. Hot leg stop valve repairs had been completed just prior.to this event. No increase was noted in containment radiation levels. All equipment started by the SI was stopped by 8:34 p.m. and was returned'

to a standby statu The licensee declared an Unusual Event at 8:35 p.m. because of the actual injection of water to the core. Per the SSs log, the State of Connecticut and NRC were notified at 8:45 and 8:47 p.m.,- respectively. The NRC Operations Center provided a notification time of 9:03 p.m., a 16 minute reporting time discrepanc CFR 50.72 requires that the licensee notify the NRC immediately after notifying state and local agencies but, in all cases, within the one hour of event classification. The licen-see's notification was within one hour requirement, but the inspector questioned the immediacy of the NRC notification since it was 16 minutes after the state notification. After further investigation, the licensee determined that the time delay resulted from filling out a three page form and specifying the correct 10 CFR 50.72 reference. The inspector questioned the licensee to determine if the State and NRC form could be combined or other actions taken to speed up NRC ENS notification. The licensee stated that combining forms would delay initial callouts and delay the State's ability to protect the public. The inspector deter-mined that some delay in NRC ENS notification is consistent with the Statements of Consideration for the Rulemaking that generated the "new" 10 CFR 50.72 rule. Per this reference, the licensee primary responsi-bility is to notify the State to allow them to protect the publi No inadequacies were note .4 MSIV Solenoid Vent Valve Stroke Failure (61726)

During partial stroke testing of the Main Steam Isolation Valves (MSIVs),

the "A" MSIV (3 MSS *CTV27A) above the piston vent so'lenoid failed to close as required. This testing was performed in conjunction with the February 11 shutdown described in Detail The MSIV is closed when steam is admitted to the above piston are Steam is admitted to the above the piston area by opening the steam ad-mission solenoid valve while closing the vent valv _ _ _ _ _ _ _ _ _ _ _ - - _ _ - _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ - _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ - _ - _ _ - _ _ _ _ _ _ _ _ _

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1. Two safety-related trains of solenoid valves ensure MSIV closure even if one vent valve is stuck ope This design feature was demonstrated h[! during the MSIV partial strcke testing on February 11 (both trains were tested simultaneously). Thus, even though 3 MSS *CTV27A1A valve failed i to close, the "B" train provided the needed safety functio The licen- i see performed a detailed investigation to identify and correct the root l

cause of this proble After vent valve disassembly, the licensee noted tarnish marks on the inner solenoid housing near the main spring area. The tarnish marks were on one side only and not symmetrical, which indicated a side loading by the spring. Spring measurements were taken and the results discussed with the vendor (Sulzer, Inc.). Tolerances on these springs are to the tenth of a millimeter. Some of these springs were found out of toleranc The as-supplied springs were canted slightly from the true vertical, causing an inherent alignment problem after vent valve assembly. For all the MSIVs, the licensee machined the spring bases and tops to return the spring alignments to vertical. That returned the springs to within tolerance. The machined springs were reinstalled and retested during the subsequent heatup and startup. Retest results were acceptable. The inspector had no further question .5 Reactor Plant Component Cooling Water (RPCCW) System Leaks (71707)

The licensee has been investigating leaks in the Reactor Plant Component Cooling Water (RPCCW) system. RPCCW provides a fresh water heat sink to various safety-related systems during accident conditions. As of February 27, the "A" RPCCW heat exchanger (HX) had a 4.3 gpm tube lea Since RPCCW is at a higher pressure than service water (SW), leaks are from the fresh water portion of the system to the salt water portio Approximately 6000 gallons of fresh water was needed daily to make up for the February 27 leak. Licensee maintenance discovered another prob-lem during post-repair testing. The Pratt HX inlet and outlet isolation valves had excessive seat leakage. They were sent to the manufacturer for refurbishment and returned for reinstallation. The licensee has scheduled valve replacement for the week of March Other RPCCW heat exchangers have developed leaks in the past. On August 23, 1988, the "B" RPCCW HX developed a leak which was subsequently plugge In the recent past, the "C" RPCCW HX developed a tube leak which was plugged on February 1 Further licensee review is needed to ensure that repeated leaks are not due to a generic problem. RPCCW HX leak tightness will be reviewed in future inspection '

3.6 Station Blackout Test (37700) i Regulatory Guide (RG) 1.68 identifies a means for licensees to demon-strate the dynamic response of the plant for a loss of turbine generator coincident with a loss of offsite powe This test was to be run, during startup testing, in the 10% to 20% power range. The licensee provided the following abstract for this test in FSAR Table 14.2-2:

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Test Objective and Summary ,

This test will demonstrate that the plant responds as designed fol- ]

lowing a plant trip with no offsite power. The reactor will be, j-tripped. The diesel start, load sequencing, and plant response in-cluding natural circulation will be monitored. . The_ turbine-driven l l-- auxiliary feedwater pump shall be run for a minimum of two hours )

I with motor-driven auxiliary feedwater pumps and turbine-driven

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' auxiliary feedwater pump cubicle ventilati_on secured. AC power to; the inverters and battery chargers will be removed for a period of two hours.to force battery operatio Acceptance Criteria The plant responds i

in accordance with design. The turbine-driven auxiliary feedwater pump remains within design limits, and pump room ambient conditions do not exceed environmental qualification limits for safety-related equipment in the roo This test, Startup Test 26 - Station Blackout, was reviewed in NUREG 1031, the Safety Evaluation Report (SER) for operation of Millstone 3. Step (7) of the Phase IX - Warranty Run of the SER reviewed each test to de-termine whether the test objectives, prerequisites, test methods, and acceptance criteria for each test demonstrate functional adequacy of the structures, systems, componi, s, and design feature Startup Test 26 objectives, prerequisites, test methods and acceptance criteria were reviewed and accepted by the staf The staff requested that the licensee modify Test 26 to ensure operation of the batterie This modification was agreed to by the licensee. The staff accepted the revised Test 26 in the SE Subsequent to NRC acceptance of the test, the licensee deleted the Test 26 requirement for the main generate- to be on-line. NRC staff review of the licensee's 10 CFR 50.59 change to Test 26 questioned the accept-ability of the change. A meeting was held on February 22 between the staff and the licensee to discuss the acceptability of Test 26. The licensee presented facts related to testing and analysis performed to date to validate their test. The staff is continuing their review of this issue, which will be further reviewed in future inspection .0 Plant Operational Status Reviews (71707)

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The inspector reviewed plant operations from the control room and reviewed the operational status of plant safety systems to verify safe operation, and compliance with technical specifications and plant operating procedures. Ac- I tions to meet technical specification requirements when equipment was inoper-able were reviewed to verify the limiting conditions for operation were me Plant logs and control room indicators were reviewed to identify changes in plant operational status since the last review, and to verify that changes

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in the status of plant equipment was properly communicated in the logs and record Control room instruments were observed for correlation between channels, proper functioning, and conformance with technical specification Alarm conditions in effect were reviewed with control room operators to verify proper response to off-normal conditions and to verify operators were knowl-edgeable of plant status. Operators were found to be cognizant of control room indications and plant statu Control room manning and shift staffing were reviewed and compared to technical specification requirements. No in-adequacies were identified. The following specific activities were also ad-

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4.1 Review of Plant Incident Reports (PIRs) (90712)

The plant incident reports (PIRs) listed below were reviewed to (i) de-termine the significance of the events; (ii) review the licensee's evaluations; (iii) verify the licensee's response and corrective actions were proper; and (iv) verify that the licensee reported the events in accordance with applicable requirements. The PIRs reviewed were: 13-89 dated 1/26/89, 15-89 dated 1/22/89, 16-89 dated 2/1/89, 17-89 dated 2/6/89, 18-89 dated 2/7/89, 19-89 dated 2/7/89, 22-89 dated 2/16/89, 23-89 dated 2/15/89, 27-89 dated 2/20/89, 28-89 dated 2/17/89, 29-89 dated 2/20/89, 30-89 dated 2/21/89, 31-89 dated 2/16/89, 32-89 dated 2/21/89, 33-89 dated 2/22/89, 34-89 dated 2/23/8 No inadequacies were ,

note i The following items warranted inspector followup:

PIR 20-89 dated 2/11/89 documented a shutdown caused by a "B" RCP high stator temperatur See Detail 3.2 for more informatio PIR 21-89 dated 2/21/89 documented the failure of the "A" MSIV solenoid vent valve to stroke closed during surveillance testin See Detail for more informatio PIRs 14-89, 24-89 and 25-89 dated 1/27/89, 2/16/89 and 2/17/89, respec-tively, documented three instances of fire watches not being statione There were five similar events documented in the previous month's in-spection report (50-423/88-24) and a violation was written in this area in December, 1988 (50-423/88-23). Performance is improving (three events vs. five events), but continued licensee attention is needed to reduce event frequenc Licensee corrective action will be reviewed in future inspections.

l PIR 26-89 documented a Safety Injection with the RCS in Mid-loop condi-l tion See Detail 3.3 for more informatio ___

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7 5.0 (Closed) TI 2515/100, " Proper Receipt, Storage, and Handling of Emergency Diesel Generator (EDG) Fuel Oil" (25500)

NRC Information Notice 87-09 dated January 16, 1987 documents the June 27, 1986 Arkansas Nuclear One Unit 2 (ANO-2) inoperability of an emergency diesel generator due to a high concentration of particulate in the fuel oil. Also, at Millstone Unit 3 on November 20, 1987 (PIR 223-87), an EDG was declared inoperable due to particulate matter in the EDG fuel exceeding the Technical Specification (TS) 4.8.1.1.2e limit of 10 mg/ liter. At that time, the plant was in a refueling outage, the EDG was not in operation, and core alterations were suspended until an acceptable supply of fuel oil was obtaine .1 Fuel Oil Sampling and Tank Inspection Technical Specification 4.8.1.1.2 contains an extensive program for sampling new and existing fuel oil:

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TS 4.8.1.1.2b - Monthly check and removal of water from day tank (Surveillance Procedure SP 3646A.1-1, A.2-1, " Diesel Generator Operability Test")

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TS 4.8.1.1.2C - Monthly check and removal of water from the fuel l oil storage tanks. (SP 3646B.5-1, " Diesel Generator Fuel Oil Storage Tank Dewatering and Sample")

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TS 4.8.1.1.2d - Verification of new fuel oil properties in accord-ance with ASTM-0975-81. (Surveillance Procedure 36468.7-1, B.7-2,

"New Fuel Oil Delivery Sampling")

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TS 4.8.1.1.2e - Monthly test of fuel oil for particulate to verify that particulate concentration is less than 10 mg/ liter. (Surveil-lance Procedure 36468.8-1, " Emergency Generator Fuel Oil Particulate Sample Analysis")

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TS 4.8.1.1.2h - Fuel oil storage tank cleaning and inspection every j 10 years (Surveillance Procedure 3712L, " Emergency Generator Fuel i 011 Storage Tank Cleaning").

The referenced surveillance procedures were reviewed in order to assure that the licensee is in compliance with the Technical Specification In addition, a sanple of completed data sheets were inspected to assure that the results of the inspection program were acceptable. No discre-pancies were note .2 System Design and Operation The EDG fuel oil system is described in Section 9.5.4 of the Millstone Unit 3 FSA Each of the two trains of the EDG fuel oil system have the following design featur l l

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An underground fuel oil storage tank with a. dewatering syste Two fuel oil transfer pumps, each with a discharge strainer equipped with pressure drop' instrumentatio An EDG fuel oil day tan .Two fuel pumps, ~ one-engine driven _ and one DC , motor-drive l

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The EDG fuel oil system operates' automatically to maintain acceptable fuel oil pressure via use of the fuel oil pump Alarms' associated with the EDG fuel oil system appear locally at each of the'two EDG control panels. The control room has two alarms associ-

- ated with the EDG fuel oil system; each alarm indicates that a local (EDG control panel) alar has been sounde The following was noted regarding EDG fuel o1.1 system alarm The FSAR incorrectly describes th'e storage tank level alarms as being level-low and level-high: no level-high alarm is provide The' fuel oil transfer pump strainer pressure drop alarm is described-incorrectly as the " transfer pump" pressure drop alarm in the Con-trol Response. Alarm Book, Operating Procedure 3346A Step 8.2.35, and on the local control pane The " subsequent action" in the event of a " Fuel Oil Pressure Low" alarm (OP 3346A, Step 8.2.15) does not address the possibility that this condition might result from a. clogged duplex filte The above documentation / procedure problems were referred to the licensee for corrective action; these actions were reviewed prior to completion of the inspection and, with the exception of the change to the FSAR, were found to be acceptable. The change to the FSAR is minor and will be re-examined when the next FSAR update is issue In addition to the design features already addressed, the licensee in-tends to purchase a filter skid to be used to filter fuel oil in the storage tanks during refueling outages (per PIR 223-87).

5.3 Filter / Strainer Preventive Maintenance Maintenance Procedure 3720CB, "PM Diesel Generator Mechanical Mainten-ance", addresses preventive maintenance for the EDG fuel oil strainers and filters during refueling outage Step 5.5.14 of MP 3720CB requires

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I inspection and cleaning (as necessary) of the EDG fuel oil transfer pump strainer Step 5.5.15 of MP 3720CB requires inspection and cleaning or replacement of the (duplex) fuel oil filter element .4 Seismic Qualifications of Instruments and Controls Representative instrument / control components were reviewed to determine the adequacy of their seismic design. A pressure switch that automatic-ally starts an auxiliary (DC Motor Driven) fuel pump, 3EGF*PS38A and two !

level switches tha+ control the level of a day, tank 3EFG*LS40A and 41A, were reviewed. T h. - :eismic review of the selected control elements was undertaken via .a 'er of the associated purchase specifications (Spec E-241 and I-626). R was determined that the instruments in question were qualified to IEEE-344-1975 and thus are considered to be Seismic Category .5 Conclusions The EDG fuel oil is sampled using acceptable industry standard The results of recent tests indicate that the qualify of the EDG fuel oil is being maintained in an acceptable manne The licensee's commitment to use a portable filter skid to filter the contents of the fuel oil storage tanks during refueling outages should further reduce particulate in the fuel oi :

With regard to the EDG fuel oil system, sufficient alternate flow paths exist to assure a reliable flow of fuel oi In this regard, the fuel filters and strainers are adequately addressed within the preventive maintenance progra Based upon the above, it is unlikely that the Millstone 3 EDGs will ex-perience fuel oil flow starvation as described in I&E Information Notice No. 87-04. The inspr tor had no further question .0 Licensed Operator Renewal Application Practices (NRC Form 398) (41701) j A review of the license application renewal practices in both the Licensed Operator Training (LOT) and Operations (OPS) departments was performed to veri fy: (1) that information supplied in two recent license renewal applica-tions was complete and accurate; and (2) that the facility licensee had an established process by which to ensure the requirements of 10 CFR 55.53 (e)

were being maintained for all active license holder This review was prompted by a discrepancy in the information supplied by the licensee for a group of operator license renewal applications. The discre-pancy was between the current duties performed by two applicants as licensed l plant equipment operators (LPE0s) and the time which they reported as having l operated the facility during the license renewal period. This discrepancy led the inspector to question the mechanism by which the licensee tracks the active versus inactive status of their licensed personne i

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.To- verify- that-licensed OPS personnel who stood control'. room watches were being maintained in an active status, discussions were conducted with the OPS-assistant and the OPS. supervisor. From these discussions and independent ,

audits of the shift' supervisor's logs and' time keeping records, it was deter-

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i mined that licensed reactor operators [ control operators (COs) and LPE0s] who are'used as part of the control room shift complement are being maintained in an active status in accordance with 10 CFR 55.53(e).

Due to the relatively low number of licenses maintained.by the OPS department, only two licensed LPE0s on shift are required to rotate into the control room as'a CO. To ensure that these two LPE0s meet the minimum time requirements-

. prescribed by 10 CFR 55 (approximately 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> per quarter) all three reactor operators (R0s) on the shifts in question rotate into the C0 position approxi-mately two-thirds of the~ tim This provides each of.these C0s with about 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br /> / year of C0 experienc The inspector also noted that there are licensed SR0s who do not maintain the >

SRO portion of their licenses in an active statu These individuals are-

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utilized as C0s and do not perform the duties of the SCO unless they complete the required 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of shift functions under the direction of an active SR After review of the information on the two recent license renewal applications,  ;

one minor discrepancy existe .

Item 13 of the NRC Form 398 requires that.the l applicant. indicate,'in months, the time spent actually exercising the responsi- ,

bilities of each position held during the license renewal perio If an LPE0

. performs licensed duties-in the control room, as was found to be.the case for two of the renewal. applicants, then this time must be reflected in this spac Form 398, Item 16, experience details, should then be used to describe the duties performed while serving in each position. Applicants who exercise the responsibilities of positions other than their own must have that time and duty description reflected in the above two application item spaces. Licensee '

completion of. renewal application forms will~be further reviewed in future inspection .0 10 CFR 21 - Rosemount Transmitter Oil Leaks '(35100)

Five Rosemount Flow transmitters (FTs) failed between March and October of 1987. Only one fai. lure occurred at a given time, and the reactor trip func-tions of the flow instrumentation remained operable. After each failure, the FTs were replaced in kind. The failures were attributed to a loss of fluid from a transmitter sensing module due to internal leakag In November 1987, the licensee's plant engineering organization completed their review of these failures. They concluded that a Potential Substantial Safety Hazard (PSSH) did exist and forwarded their conclusion to corporate engineering. Their conclusion was based on the number of failures, the fail- l ure frequency, and the fact that the mechanisms for all FTS failures were j identical. Corporate engineering began their PSSH review in November 198 !

After contacting Rosemount, corporate engineering disagreed with the plant's

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PSSH evaluation: the vendor stated that the defects were due to a corrected manufacturing problem. After further discussion with the plant, corporate engineering reevaluated their position.and submitted a 10 CFR 21 report in -

March of 1988. 'The inspector reviewed the issue and rioted that the late re- -

porting of this problem unnecessarily delayed 1 report dissemination to other Rosemount user Inspector. followup showed that this same failure mechanism was identified in prior transmitter failures (1985-1986) at the J.~ A. Fitz-patrick Nuclear Power Plant. This issue was documented in Inspection Report 50-423/88-05 and incorporated in Millstone 3 SALP Report 50-423/87-9 The licensee's 10 CFR 21 report was followed by industry attention. The Electric Power Research Institute (EPRI) and the Institute of Nuclear Power Operations-(INPO) have also reviewed this problem. .Rosemount reevaluated their position and submitted their own 10 CFR 21 report. In a letter dated February 8,1989 from Rosemount, Inc. to Northeast Utilities, the vendor documented the potential for failure of Model 1153 and 1154 Rosemount trans-mitter These models are primarily used in safety-related applications; l Models 1151 and 1152 are used for control functions. Rosemount characterized {

the failures as follow !

"The failure mode is a loss of fill fluid from the transmitter sensing module due to internal leak (no oil is lost into the process fluid).

When this condition occurs, the transmitter may exhibit reduced perform-ance prior to a detectable failure. This reduced performance may mani-fest itself as-an output shift, lack of response over it's full range, and/or an increase in time response. The loss of time response may be uni-directional. At this time, we have not been able to determine the '

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limits of this potential performance reduction."

" Based on existing confirmed information, all reported failures to date i occurred during the first 30 months of service and eventually resulted '

in a detectable condition during that 30 month time span. In these^s'itu-ations, the transmitter would show an increasing output shift, and then ,

possibly resulting in high or low offscale reading. Other symptoms that '!

may identify loss of oil include inability to calibrate (sluggish re-sponse or partial response) and reduced noise in a signal that normally would show nois Data available also suggests but does not yet confirm i that transmitters which have been in service for more than 36 months are not going to fail in this way."

"Recent information indicates that prior to detectable failure, the transmitter may continue to provide a signal but not respond over it's full range and/or time response may be significantly degraded." i The inability to quickly detect degraded performance / time response is safety l significant. Many of these transmitters are used to provide reactor trip j and/or engineered safety features actuation signal l l

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Along with the narrative, Rosemount listed the following 16 potentially af-fected transmitters that were delivered to Millston MODEL DEL DATE TRAN SN MOD SN

'1153085 22984 408074 954082 I 1153GD8 122084 411114 951053  !

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l 1153085 20384 408079 954181 1153HD5 20384 408190 954070 1153D05 90784 410157 1053001 1153D85 20384 408078 954100 1153HD5 22984 408197 954097  !

1153H05 22984 408198 954186 l 1153085 20384 408073 954187 i 1153HD5 20384 408193 954128 1153DB5 20384 408076 954104 1153HD5 20384 408188 954095 1153HD5 13185 411942 1129220 .

1153HD5 13185 411943 1129207  !

1153HD5 13185 411944 1129242  !

1154DP4 50686 414993 1329646 The licensee identified that of the 16 transmitters, 13 were for Millstone 3, 3 were from Millstone 2, and 0 were for Millstone 1. Millstone 2 is ad-dressing this issue and will provide their own corrective action progra Millstone 3 is providing checks through the full range of detector operation (full deflection) travel to identify defective transmitter Three types of checks are being used: (i) calibration checks through the full range of de-tector operation, (ii) comparisons of detector response where multiple detec-tors are used to sense a process /ariable, and (iii) review of recent full range OFIS (Offsite Information System) dat During the 2/11/89 cooldown, three of the four reactor coolant pumps (RCPs)  ;

were tripped from full flow and each of the 3 loops' flow transmitters (FTs) j was cross compared with the other two transmitter No anomalies were note A failure of an FT would result in a difference in the detector output versus time from the other FT This approach is acceptable because the probability of similar simultaneous failure of all 3 FTs in the same loop is considered ,

extremely small. No inadequacies were note Further licensee review used separate calibration checks or a review of recent full range 0FIS data. The licensee found no evidence of slow time response or excessive drift during their review. Licensee testing of potentially de-fective Rosemount transmitters was thorough. The licensee is evaluating the need to resubmit their March 1988, 10 CFR 21 report. This issue will be re-viewed further in future inspection !

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8.0 Review of Licensee Event Reports (LERs) (92700)

Licensee Event Reports (LERs) submitted during the report period were reviewed to assess' accuracy, the adequacy of corrective actions, compliance with 10 CFR 50.73 reporting requirements, generic implications, and whether further information was required.- Selected corrective actions were reviewed for implementation and thoroughnes The LERs reviewed were:

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LER 88-28-00, Reactor Trip Due to Loss of Normal 4160V Bus, documented l a 5:10 p.m., December 29, 1988 reactor trip from 75% power due to a loss i of gating current to the. control rod's silicon controlled rectifiers ;

(SCRs) due to procedural deficiency. Normally, a trip would not.have

. occurred, but a redundant power supply was degraded at the time. Prior to the trip, the emergency busses were being supplied by the Reserve .

Station Service Transformers (RSSTs). The "B" Emergency Diesel Genera- ;

tor (EDG) was started for surveillance testing. When EDG-B was paral-- I leled to Emergency Bus 340, the normal to emergency bus tie breaker opened on a directional overcurrent trip, deenergizing Normal Bus-34 !

Licensee procedures did not provide adequate operator guidance on the !

required electric plant lineup prior to paralleling an Emergency Diesel '

Generator when 4160V buses were supplied from the RSSTs. The procedure has.been corrected. The redundant power supply degradation will be cor-rected during the next reactor shutdown. See Detail 6.0 of Inspection i Report 50-423/88-24 for additional information, i

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LERs 88-26-01 and LER 88-26-02, Potential Damage to Safety-Related Equip-ment Due to Design Inadequacy, both updated a previously issued LE The original LER described a design inadequacy that could have resulted in an out-of phase transfer to the RSSTs. This transfer would damage any previously running safety-related electrical equipment. The first LER revision was written to address single failures of any of three re- .

lays that would cause the same scenari The second revision stated that i a plant modification will be performed in the next refueling outage to block fast transfer on undervoltage. No inadequacies were note LER 89-01-00, Steam Generator Sample Containment Isolation Valves found open due to Personnel Error, documented that both the "B" and "C" steam generator (SG) blowdown (80) containment isolation valves were found open at 4:30 p.m., January 5 and had been open 10.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. This incident was discovered while performing leak rate calculations to verify the valves were closed. Thc Technical Specification Limiting Condition of Operation i

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(LCO) Action Statement requires that the valves not be open for more than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> at a time. The root cause of this event was personnel error.

l The valves were opened at 6:00 am to draw steam generator samples. The E open valves were not discussed during the shift turnover and the oncoming l Shift Supervisor (SS) missed the LC0 Action Statement entry in the SSs log. Corrective action included obtaining a timer to alert Control Room operators of the LCO time limitations. An internal memo was routed to all Operations personnel emphasizing the need to pay close attention to detai The individuals directly involved were counseled on proper

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turnover requirement The replacement of these inoperable valves is  !

scheduled for the next refueling outage. No inadequacies were note /

This licensee-identified item was evaluated as having low safety signi-ficance, being acceptably corrected, not due to a previous corrective action inadequacy, and not required to be reported to the NR I

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LER 89-02-00, Control Building Purge Exhaust Fan Isolation Valve Position Indication Error due to Personnel Error, documented a miswiring erro At 3:00 p.m., January 6, 1989, the licensee determined that the wiring of the position indication lights for the Control Building Mechanical Equipment Room Purge Exhaust Fan Isolation valve (3HVC*A0V22) was not i per design. While stroke testing the valve, the open position was cor-rectly indicated but the intermediate and closed positions were incor-rectly indicate Position indication on the plant process computer and i Engineered Safety Features status board were accurate. With the wiring f error, actual valve closure time was not accurately being measured. The root cause of this event was personnel erro The wiring error occurred on December 26, 1986 during the landing of wires to the terminal block on the valve switch after maintenance. The faulty valve position indi-cation was not observed during the retest due to the short stroke time for the valve (approximately 1 second). Plant procedures were revised in May,1987 to require independent verification for lifting and landing leads on safety related equipment. An internal memo was routed to all-operations personnel emphasizing the need to pay close attention to in-termediate valve position indication during stroke testing and normal operation of valves. This is especially important for short stroke time valves. The inspector had no further question .0 Maintenance (62703)

The inspector observed and reviewed selected portions of preventive and cor-rective maintenance to verify compliance with regulations, use of administra-tive and maintenance procedures, compliance with codes and standards, proper QA/QC involvement, use of bypass jumpers and safety tags, personnel protection, and equipment alignment and retest. The following activities were included:

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Reactor Plant Component Cooling Water Leak Repair, dated 2/19/89

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MSIV Vent Valve Repair, dated 2/20/89 No inadequacies were identifie .0 Surveillance (61726)

The inspector observed portions of surveillance tests to assess performance in accordance with aporoved procedures and Limiting Conditions of Operation, removal and restoration of equipment, and deficiency review and resolutio The following tests were reviewed:

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"B" QSS (Quench Spray System) Spray Pump Op Test, SP360 Train "A" RHR (Residual Heat Removal) Valve Operability, SP 3610 LPSI (Low Pressure Safety Injection) Valve Stroke Time, SP 3610 Charging /SI Pump Inoperability Verification, SP 3604 Containm9nt Manual Isolations (Outside Containment), SP 3612 No inadequacies were note k 11.0 Management Meetings (30703)

Periodic meetings were held with station management to discuss inspection findings during the inspection period. A summary of findings was also dis-cussed at the conclusion of the inspection. No proprietary information was covered within the scope of the inspectio ;-

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