IR 05000245/1987030

Insp Repts 50-245/87-30 & 50-336/87-25 on 871027-1130. Violations Noted.Major Areas Inspected:Physical Security, Operations,Svc Water Sys Operability,Vital Dc Switchgear Ventilation,Surveillance & LERs

ML20147E750
Person / Time
Site:	Millstone
Issue date:	01/06/1988
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20147E647	List: IR 05000245/1987030 ML20147E644 ML20147E689
References
50-245-87-30, 50-336-87-25, NUDOCS 8801210211
Download: ML20147E750 (18)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report: 50-245/87-30; 50-336/87-25 Docket Nos: 50-245; 50-336 License Nos: DPR-21; DPR-65 Licensee: Northeast Nuclear Energy Company Facility: Millstone Nuclear Power Station, Waterford, Connecticut Inspection at: MillstoneUnitsIg Dates: October 27, 1987 through November 30, 1987 Inspectors: William J. Raymond, Senior Resident Inspector Lynn Kolonauski, Resident Inspector Other Personnel: Dave Jaffe, Millstone 2 Licensing Project Manager, NRR Reporting Inspector: William J. Raymond, Senior Resident Inspector Approved: CA P N M,)t- #/6/&B E. C. McCabe, Chief, Reactor Projects section IB Date Summary: Report 50-245/87-30; 50-336/87-25 (10/27/87 - 11/30/1987)

Areas Inspected: Routine inspection (138 hours0.0016 days <br />0.0383 hours <br />2.281746e-4 weeks <br />5.2509e-5 months <br />) on day and back shifts of: actions on previous inspection findings; physical security; operations, including opera-tional status reviews and facility tours; service water system operability; vital DC switchgear ventilation; the Unit 2 reactor scram on 11/16/87; surveillance; committee activities; Inleakage into the control room ventilation system; fuel assembly pressure drop test plans; and licensee event reports (LERs).

Results; No unsafe plant operations were identified. One apparent violation was identifie, acerning the inoperability of the Unit 2 vital DC switchgear room cooling system for about 4 years due to heat exchanger maintenance problems (Sec-tion 6.0). Licensee and resident inspector followup is warranted on: (1) future actions to assure continued operability of the chilled water heat exchangers used in the vital DC Switchgear room cooling system (11) long term corrective actions to assure operability of the auxiliary feedwater system auto initiation logic (Section 7.0); and evaluations and corrective actions to verify the control room air inleakage remains within acceptable limits (Section 10.0).

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8801210211 000111 5 DR ADOCK 050 i

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TABLE OF CONTENTS Page 1.0 Persons Contacted.......................................... ......... 1 2.0 Summary of Fac,ility Activities....................................... 1 3.0 Status of Previous Inspection Findings............................... 1 4.0 Obse rva ti on s o f Phy si cal Securi ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 5.0 Facility Tours and Plant Operational Review Status................... 3 5.1 Safety System Operability Review................................ 3 5.2 Review of Plant Incident Reports................................ 4 5.3 Minor Vehicle Fire in Main Sw1tchyard........................... 4 5.4 Unidentified Leakage Inside the Drywell-Unit 1.................. 4 s 5.5 Service Water System Operability Review-Unit 2.................. 5 6.0 Vital DC Switchgear Ventilation System............................... 7 7.0 Reactor Scram on #1 Steam Generator low Level, 11/16/87-Unit 2....... 9 j 8.0 Review of Licensee Event Reports..................................... 12

9.0 Surveillance Activities.............................................. 12 l 10.0 Increased Auxiliary Building and Control Room Radiation Levels..... . 13 11.0 Fuel Assembly Pressure Drop Testing-Unit 2........................... 15 12.0 Committee Activities................................................. 16 13.0 Management Meetings....... ... ...................... ............... 16 i

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DETAILS 1.0 _ Persons Contacted Northeast Nuclear Energy Company

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Inspection findings were discussed periodically with the supervisory and management personnel identified belo Mr. F. Dacimo, Unit 2 Engineering Supervisor Mr. J. Keenan, Unit 2 Superintendent Mr. S. Scace, Station Superintendent Mr. J. Stetz, Unit 1 Superintendent The inspector participated in a telephone conference call on October 30, 1987, '

between Unit 2 personnel, Region I management, and Mr. W. Romberg, Vice President-Operations, to discuss the status and plans regarding Heat Exchan-gers X169A&B in the Vital DC Switchgear Chilled Water System. This item is discussed further in Section 6.0 belo State of Connecticut Mr. K. McCarthy, Department of Environmental Protection Mr. K. McCarthy accompanied the Resident Inspector and the NRR Project Manager onsite on October 27, 1987 for a tour of Millstone 2 plant areas and to ob-serve portions of test activities in progress on the service water syste .0 Summary of Facility Activities Millstone Unit 1 operated at 100% power from the start of the inspection

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period until November 14, 1987, when the unit was taken to cold shutdown to investigate and repair the source of unidentified leakage into the drywell floor drain sump. The unit returned to full power operation on November 14, 1987 following repairs of packing leakage from isolation condenser valve IC-1 and coatinued routine full power operations for the rest of the perio Millstone Unit 2 operated at 100% power from the start of the inspection period until November 16, 1987, when the reactor scrammed on low level in Steam Generator #1 due to a malfunction in the #1 Feedwater Regulating Valve (FRV). Following repairs, the unit returned to power operation on November 17, 1987 and continued routine power operations for the rest of the perio .0 Status of Previous Inspection Findings (Closed) Unresolved Item 50-245/87-27-01: 1987 Outage - Technical Specifica-tion and Procedure Changes. The licensee completed a review of all design changes implemented during the 1987 refueling outage and verified that ap-propriate changes to procedures and the technical specifications were pro- ,

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. 2 cessed. No other discrepancies were identified by the licensee's revie Since the event reported in LER 87-41 (see Section 10.0 below) was found to be an isolated event, no add'tional corrective actions were taken or planne This item is close .0 Observations of Physical Security Selected aspects of site security were reviewed during tours, including site access controls, personnel and vehicle searches, personnel monitoring, place-ment of physical barriers, compensatory measures, guard force staffing, and response to alarms and degraded condition Security event reports (SERs) issued were reviewed to determine whether 10 CFR 50.73 reporting requirements were met and that the report accurately de-scribed the events. The security reports r^ viewed included SER 87-15 dated 11/13/87 and SER 87-16 dated 11/19/87. No inadequacies were identifie Revised access control established by the licensee for visitors requiring escorted access in the protected area were implemented on November 18th. The inspector reviewed the modified controls with the security supervisor, and verified the access control officer on duty at 7:00 p.m. on November 18th was aware of the new requirements. No inadequacies were identifie Guards posted for compensatory measures at the North end of the site at 7:00 p.m. on November 18 were performing duties in accordance with the post order However, a subsequent problem occurred in maintenance of this post, as dis-cussed further below. No other inadequacies were identified. The following two security events warranted inspector followup:

About 9:20 a.m. on 11/19, a replacement security guard posted on the North side of the protected area was relieved of his post by his supervisor. The supervisor was apparently misinformed at shift turnover that the post was no longer required. The relocation of guards was not reported to the Assistant Security Shift Supervisor (ASSS) as required by security procedures. The absence of a guard at the post was discovered at 9:45 on 11/19 when the guard previously assigned to this post returned to it and reported this to the ASS Because the earlier repositioning of guards was not reported to the ASSS, the ASSS questioned the manning status of the post. The guard stated that the post had not been manned. After investigation, the ASSS determined that the post was not manned from shortly after 9:20 a.m. until 9:45 a.m. Appropriate area checks were made with acceptable results. The event was reported by the licensee in accordance with 10 CFR 73.71(c) via the ENS; a State of Connecti-cut general interest event was also declared in accordance with the site emergency plan. Neither the inspector nor the NRC regional security special-ists had further question A second security incident occurred on 11/12/87. An operations shift super-visor discovered a guard allegedly sleeping at his post at 12:30 a.m. The guard was posted as a compensatory measure. The operations shift supervisor notified the security shif t supervisor who posted a replacement guard within

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10 minutes of the discovery. The original guard was relieved of duty and was .:

. assigned to a site access point with another guard present. The guard denied ;

that he had been sleeping, but was suspended without pay while the licensee ;

investigated the incident, The guard was reinstated when the investigation !

proved to be inconclusive. The licensee reported the event via the ENS on

. November 12 per 10 CFR 50.71(c). The inspector had no further comments on ,

this area at the present time. The performance of the security force wil i be reviewed further during subsequent routine inspection '

5.0 Facility Tours and Plant Operational Status Reviews i The inspector reviewed plant operations and the operational status of plant '

s2fety systems to verify safe operation of the plant in accordance with the -

requirements of the technical specifications and plant operating procedure ,

Actions taken to meet technical specifications *sre reviewed to verify the i limiting conditions for operations were met. Plant logs and control room

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indicators were reviewed to identify changes in plant operational status and ,

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to verify that changes in the status of plant equipment was properly communi- l cated in the logs and record ;

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Control room instruments were observed for correlation between channels, proper functioning and conformance with technical specifications. Alarm .

conditions were reviewed with control room operators to verify proper re-A sponse to off n:rmal conditions and to verify operators were knowledgeable r of plant status. Operators were found cognizant of control room indications '

and plant status. Control room manning and shift staffing were reviewed and i found to meet to technical specification requirement i

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The inspector observed plant operations during regular and back shif t hours to verify safe operating practices and that activities were conducted in ,

i accordance with approved procedures. The back shift inspections included I tours made at 7:30 p.m. on November 11, 1987 and 9:00 p.m. on November 16, ,

198 Posting and control of radiation, contamination and high radiation i i areas was reviewed. The use of personnel monitoring devices and general com- !

! pliance with the RWP requirements was verified. Plant housekeeping controls ;

were observed, including the control of flammable and other hazardous mate- i

rials. No inadequacies were identifie The following specific activities !

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were also addresse i i 5.1 Safety System Operability Review  :

i Units 1&2 l

Standby emergency systems were reviewed to verify the systems were oper- r able in the standby mode. The systens reviewed included the Unit 1 i standby gas treatment, low pressure coolant injection, core spray, (

isolation condenser, and standby gas turbine generator systems; and Unit :

2 containment spray, safety injection tenk, low pressure safety injec- !

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tion, high pressure safety injection, and emergency diesel generator i systems.

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The review included proper positioning of major flow path valves, oper- !

, able-normal and emergency power supplies,'and indicator and control functioning. References used included applicable flow diagrams, and Unit I w rveillance procedure SP 623.18. No inadequacies were identifie i 5.2 Review Plant Incident Reports The plant incident reports (PIRs) listed below were reviewed during the inspection period to (i) determine.the significance of the events;

(ii) review the licensee's evaluation of the events; (iii) verify the .

licensee's response and corrective actions were proper; (iv) verify that e the licensee reported the events in accordance with applicable require- i ments, if required. The PIRs reviewed were: Unit 1, 87-94 dated 10/27/87 and 87-95 dated 10/28/87; Unit 2 87-76 dated 10/30/87, 87-77 ;

dated 11/3/87, 87-78 dated 11/3/87, 87-79 dated 11/16/87, 87-80 dated !

11/16/87, and 87-81 dated 11/21/8 !

PIR 2-87-86 co'ncerned increased radiation levels in the Unit 2 control room on October 30, 1987 and is discussed further in Section 10.0 belo l PIR 1-87-80 concerned the failure of the "A" Auxiliary Feedwater Pump i

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to start on demand, as discussed in Secticn 8.0 below. No inadequacies were identified regarding the review of PIR j 5.3 Minor V:hicle Fire in Main Switchyard A minor fire occurred in the engine compartment of a truck parked outside the protected area in the main station switchyard at 10:18 a.m. on Octo-ber 29, 1987. The fire was identified ./ sn electrician, who called the [

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Goshen Fire Department and the Unit 1 control room. Two members of the i onsite fire brigade responded to the scene. However, members of the ,

Goshen Fire Department were the first to arrive at the scene and they [

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extinguished the fire by cutting the truck's battery ground cable at !

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25 There were no injuries and no vital equipment was damage !

The licensee informed the resident inspector of the event at 10:25 s

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quacies were identified in the licensee's respons i i

5.4 Unidentified Leakage Inside the Drywell-Unit 1 l

The inspector noted that leakage collected by the drywell floor drain sump (DWFDS) increased gradually during the inspection period, but re- ;

j mained well below the 2.5 gpm limit established by Technical Specifica- !

tion 3.6,0. With the leak rate at 1.8 gpm and increasing slowly, the

licensee decided on November 13, 1987 to conduct a drywell entry to in-vestigate the source of leakage. Plant load was reduced to 20% power !

, on November 14, 1987 and the drywell was deinerte Subsequent inspec-tion by licensee personnel identified the source of the leakage to be :

i a packing leak from IC-1, the inboard steam supply valve from the reactor '

to the isolation condenser. The reactor was taken to cold shutdown to i

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. 5 allow worker access to upper levels of the drywell to effect repair The plant returned to power operation on November 16, 1987 following repairs to 1C-1. Subsequent leakage into the DWFDS was less than gpm. No inadequacies were identifie .5 Service Water System Operability Review-Unit 2 The Service Water System (SWS) circulates salt water, using three verti-cal pumps located in the intake structure, to provide cooling water under normal and accident conditions. The following are major heat loads associated with the SWS: Reactor Building Closed Cooling Water (RBCCW),

Turbine Building Closed Cooling Water (TBCCW), Emergency Olesel Genera-tors (EDG), Vital AC Switchgear Room Coolers, and Vital DC Switchgear Room Cooler Salt water discharged from the above sources is collected in the SWS discharge headers and routed to the main plant discharge poin The SWS was inspected to determine proper valve alignment, system oper-ability, and housekeeping. Procedure SP 2612C was used to check valve alignment together with P&ID 25203-26008. With the exception of the discrepancies noted in Section 6.0 below, the SWS appeared to be in good physical condition and showing proper valve alignment. Valve 2-SW-61A, a pump strainer vent, was found to be leaking and six valve identifica-tion tags were missing. These items were referred to the licensee for corrective action. The licensee indicated that valve identification tags are routinely lost when the attachment wire becomes corroded, breaks, and the tag falls off. A plant-wide retagging will be undertaken using plastic tags and braided wire to correct this proble Housekeeping was found to be quite good in all SWS plant areas. The housekeeping inspection included electrical cabinets. The licensee opened two cabinets for inspection, a 4160 volt breaker for SW Pump B (A502) and a 480 volt breaker for SW Strainer B (B5154). The insides of the cabinets appeared clean with all electrical connections tigh Some standing water was noted in the 480 volt vital switchgear enclosure on the 14'6" level of the Auxiliary Buildin The licensee stated that he would investigate this conditio Operating Procedure (0P) 2326A, Rev. 9, provides instructions for opera-tion of the SWS under normal and degraded conditions. This procedure was reviewed in detail for accuracy and clarity with two resulting com-ments-

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Step 7.2.11 addresses lube water status for a shutdown SWS pump and requires valve manipulation without ident'.fying the valve number Step 8.6 describes an alarm condition; "Vital AC SWGR RM CLG Coil lo Dis Press," without identifying the centrol room panel and alarm window number The above comments were referred to the licensee for corrective action, l

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The surveillance procedures (SPs) contained in the master surveillance list were reviewed against the Technical Specification (TS) surveillance requirements for the SWS to assure compliance with the specification Except as noted below, the performance of the SPs assured compliance with the TS surveillance requirement TS 4.7.4.1.a.4 requires a monthly verification that each SWS loop is aligned to receive electrical power from separate operable emergency busses. The requirement to observe correct electrical alignment is contained in OP 2346A, which is only performed when the SWS pumps are started or stopped. For this reason, if a SWS pump has been running for an extended period of time (e.g., more than a month), electrical alignment is not verifie Although the electrical alignment of the SWS pumps is verified before starting and cannot change while the pump is running, the licensee cannot assure tha*. manthly electrical alignment checks have taken place, thus, a violation of TS surveillance requirements could occur. The licensee agreed to make a change to procedures SP 2612C and 0 to require monthly verification of SWS electrical alignment when the SWS pumps are runnin The inspector had no further comment on this ite The SWS is controlled from panels C 06/07 and C 80 in the Control Roo The SWS controls and alarms were compared with P&IO 25203-26008 and the Control Room Annunciator Book (CRAB), which describes initiating devices and corresponding sections in OP 2346A for correction of the alarm con-dition. Except as noted below, the CRAB entries associated with the SWS and P&ID 25203-260'18 provided correct identif :ation of alarm initiating devices and appropriate references in OP 2346A for correction of t%

alarm condition ,

-- P&ID 25203-26008 (dated April 31, 1987, Sheet 3 of 4 did not show Pressure Switches (PSs) 6925, 6926, and 6927, which sense low dis-charge pressure on the vital AC switchgear room cooling coils (alarm window C-5 on panel C7067).

The above inaccuracy was discussed with the licensee. PS 6925, 6926, and 6927 did appear on previous P&lDs is and not on the current version due to an oversight when the licensee converted to their computer aided design (CAD) system. The licensee also indicated that vital AC switch-gear room cooling coil moisture switches (mss) 6825, 6826, and 6827, while shown on the current P&ID in question, are no longer installed. The above findings were referred to the licensee for corrective action. The inspector will review the adequacy of flow diagrams on subsequent routine inspections to determinc whether a programmatic concern exists in regard to operating procedures.

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. 7 6.0 Vital DC Switchgear Ventilatinn System

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During a routine tour of the Turbine Building on October 27, 1987, as part of his review of the Service Water System, the NRR Licensing Project Manager noted that both vital chilled water heat exchangers, X169A & B, were dis-assembled with the end caps removed. The resident inspector was notified and subsequent inspection of the area identified the findings summarized belo The vital DC switchgear rooms are normally cooled by a non-safety-related system during routine plant operations. For emergency conditions, the vital DC Switchgear rooms are cooled by the vital chilled water system, which is cooled in turn b.' the service water system using vital chilled water heat exchangers X169A & B. Both heat exchangers were inoperable on October 26, 1987 to allow inspection and repair of leaky tubes. The licensee stated that repair actions were in progress with the intention of restoring the units to an operable status prior to the January 1988 plant shutdown for the refueling outag Based on discussions with plant personnel, the heat exchangers have been in- ,

operable for about 4 years due to a long history of maintenance problem Tube leaks have occurred because of the susceptibility of the heat exchanger materials to salt water corrosion. The corrosion is enhanced by the normal standby status of the vital chiller system resulting in the heat exchangers being in wet layup using salt water for long periods. The heat exchangers were replaced under plant design change request (PDCR) 2-71-85 with new units utilizing 90-10 copper-nickel tubes. Although the PDCR was completed on May 15, 1956, due to either continued problems with corrosion or with qualifying replacement components, the heat exchangers were never declarei operabl There are no direct operability requirements for this equipn.cnt in the Mill-stone Unit 2 technical specifications, and operating periods without the equipment is not tracked as operation in a limiting condition for operatio However, the vital DC switchgear ventilation system is part of the licensing design basis for the plant, as described in FSAR Section 9.9.15, and would be called upon to function following loss of Coolant or loss of Normal Power events to provide area cooling to the vital DC switchgear rooms. As a result, the plant operated for about four years without the redundant, safety-related support system included in the plant licensing basi The licensee evaluated this mode of operation ar.d concluded that the cooling function assumed in the FSAR Section 9.9.15 licensing basis could be ade-quately assured via alternate means, which includes the use of redundant, safety-related Battery Room cooling fans F112A&B, together with proceduralized manual actions that would require operators to open room doors and use port-able fans as necessary to supplement room cooling. The evaluation was de- L scribed in licensee memoranda dated November 29, 1983, December 28, 1983, and January 3, 1984, and in calculation 82-209-309-GM. The mode of operation was also reviewed by the Plant Operations Review Committee (PORC) in Meeting 2-85-186 on 9/26/85, about two years af ter the unoperability occurred. The licensee concluded that continued plant operation with temporary ventilation

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until the vital equipment could be repaired or replaced involved no unreviewed *

safety question. The licensee stated that adequacy of using the alternate ventilation mode had been previously demonstrated during short term outages of the normal ventilation system during summer month The inspector reviewed the licensee's calculations and independently confirmed  ;

the conclusions were adequate. .The calculation showed that 3450 cubic feet per minute of cooling would be required to remove the heat loads, and that l'

4125 CFM was available from each battery room fan to maintain room tempera-tures below the 104 degrees F. The temperature limit for the battery chargers,

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the most limiting component in the vital DC switchgear room, is 113 degrees F. The manual actions were found to be described in Section 8.3 of OP 23158,  :

Non-Radioactive Ventilation System, Revision 3. The inspector noted that, t although the instructions to the operators in OP 2315B did not clearly ad-dress all assumptions specified in calculation 82-209-309-GM, the procedure ,

t did instruct the operators to open the switchgear room doors and to instal .

portable coolin !

I The inspector reviewed the conditions in both DC switchgear rooms, and noted that temperatures were in the range of 85-88 degrees F and that there were '

no apparent adverse conditions for present plant operations. The change in i equipment operating status following a Loss of Coolant or Loss of-Normal Power events would cause heat loads in the rooms to decrease. Based on the above, no inadequacies were identified in the licensee's conclusion l 3 However, in spite of the acceptability of the interim cooling method, the >

] inspector concluded that the alternative mode was unacceptable for the long q term since it did not provide cooling commensurate with the redundant, safety ,

class system previously accepted by the NRC staff as part of the original

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plant licensing basis. The inspector noted further that operation of the  !

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plant with the vital heat exchangers inoperable for several years due to j l "maintenance problems" appeared to be a de facto design change to the facility j

. as described in Section 9.9 of the FSAR. The inspector noted that the licen-  ;

see did not either submit a proposed amendment to modify the licensirg basis, *

or report the change as part of the annual 10 CFR 50.59 report. The licensee  ;

stated that the alternate operating mode was not intended as a permanent  ;

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change to the facilit ,

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NRC concerns regarding this item were discussed in a telephone conference call with Millstone 2 Site Management and the Vice President of Operations on

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October 30. The licensee committed to the following actions

(1) actions in  :

progress to repair chilled water system heat exchangers X169A&B would continue

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on a best effort basis to return the system to an operable status as soon as  !

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possible; (ii) submit a letter to NRC that documents the evaluation for the ,

system, describes the history of problems, and describes short and long term t

plans to address the problem; and, (iii) revise emergency procedures as necessary to assure they adequately incorporate all manual actions identified  ;

in the safety evaluation as required to assure adequate cooling of the DC

switchgear rooms, should continued reliance on the alternate cooling mode be

] found necessary. The inspector noted that the licensee completed work on the

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. 9 heat exchangers and both units were returned to an operable status on November 6, 1987. The licensee submitted the letter to NRC after the inspection perio Licensee action for this item will be followed on a subsequent inspection (UNR 50-336/87-25-01).

Failure to correct the Inoperability of the C-C switchgear from chillers for about four years without changing the associated FSAR design basis violates 10 CFR 50 Appendix B Criterion XVI (VIO 50-335/87-25-02).

7.0 Reactor Scram on #1 Steam Generator low Level, _11/16/87-Unit 2 The reactor scrammed automatically from full power at 2:11 a.m. on 11/16/87 due to a low level condition on the #1 steam generator (SG). The level transient occurred about 4 minutes following the completion of a routine surveillance on the turbine stop and intercept valves, but was not related to that testing. The following summarizes the major events in the sequence:

2:03:17 turbine valve testing completed 2:06:34 SG #1 5% level deviation alarm (Hi)

2:10:37 SG #1 hi level at 85% - FRV closes 2:11:7 SG #1 low water level at 36%

2:11:7 Reactor Scram / Turbine Trip 2:11:7 Bus 25A Transfer Failure, "A"/"C" Reactor Coolant Pumps (RCPs) lost 2:11:11 Operator Inserts Manual Scram 2:11:15 SG #1 lo-lo level at 12*4 - AFW auto start timer 2:11:35 Operator Tries to Manually Close Bus 25A RSS Bkr - Fails 2:14 "B" Auxiliary Feedwater Pump Auto Starts, "A" Start Fails 2:15 Plant stable in hot shutdown, main feedwater available Upon completion of turbine testing, a level increase transient occurred on the #1 SG apparently due to a malfunction on the #1 feedwater regulating valve (FRV) controller, which was followed by a level decreasing transient as a result of operator and automatic feedwater system responses to a high level condition at 85%. The operator responded to the high level alarm, but did not get the expected response from the controller for the feedwater regulating valve on either the level increasing or decreasing transient. The reactor scrammed as required when level in the #1 SG decreased to 36%.

Following the scram and turbine generator trip, the 25A 6.9 KV bus did not fast transfer to the backup supply, which resulted in the loss of the A&C reactor coolant pumps (1 in each SG loop). Level in the #1 SG decreased to 4*., which was below the auxiliary feedwater (AFV) actuation point of 12* The "B" motor-driven AFW pump started as required after the delay circuitry tin,ed out with SG level less than 12*. for greater than 3 minutes 25 second The "A" motor-driven AFW pump did not start as require The turbine-driven AFV pump was available if needed. Plant operators stabilized the plant in the hot shutdown condition using tne main feedwater pumps for SG 1evel coatro The 25A bus was energized from the reserve station transformer by the opera-tors at 2: 45 a.m. af ter the reserve station service transformer (RSST) tie breaker, H103, was racked down and back up again.

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During subsequent recovery actions, the plant cooled down from 532F to 485F until the operators shut the Main Steam Isolation Valves (MSIVs). All other I plant systems reportedly responded as expected. The MSIVs were reopened at *

8:40 a.m. after operators closed a steam supply valve to the moisture separa-tor second stage reheate l Subsequent licensee investigation did not identify a clear cause for the mal- ;

function in the #1 feedwater regulating valve, but the valve positioner was

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, replaced because of minor anomalies noted in its operation. The valve was i then stroked satisfactorily under no load condition Further investigation '

was deferred until plant startup when testing with feedwater pump discharge  :

pressure identified no further anomalous operatio f

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i The failure of the "A" auxiliary feedwater pump to start on demand at 12% '

level on the #1 SG was found to be a faulty GE type SBl control switch in the !

logic initiation circuit. This switch was found to be stuck in the "reset"  !

position. The four position switch has a "normal" position which operates  !

to close a contact in the spring-return-to-normal position from the logic

"start" or "reset" positions. The closed contact is used in series with other !

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contacts for the actuation relay for the AFW initiation logic. Actuation of- t the end point relay provides for auto start of one AFV pump and opening both  !

AFV regulating valves at low level in the SG. The switch was found to be rotated slightly toward the "reset" position such that the initiation logic 1

, was effectively blocked. The inspector verified this failure mode by review of a 581 type control switch, and by review of Drawings 25203-32012, Sheets ,

l- A, 11, 44 and 46. The licensee also completed continuity checks in the in- t itiation circuit to verify the circuit was ready for auto start with the [

twitch in the "normal" position. The inspector noted that there were no l operational or surveillance activities that would exercise the switch for the a remainder of the operating cycle. One additional, similar switch is located '

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on the alternate shutdown panel. Electrical continuity through this switch t was proven by the ability to manually start the "A" AFW pum .

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Discovery of the misaligned 581 switch condition by the operators was hampered !

by the use of a circular, unmarked handle on the control switch. Additional l licensee corrective actions prior to plant restart included replacing the l circular handle with a pistol grip handle having an arrow and pointer that l

clearly shows when the switch is in the "normal" position. Long term correc- l

tive actions will include replacement of the switch during the upcoming re-fueling outage. The inspector stated to the licensee that long term followup

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generic question of whether a similar switch failure could affect other safety (

feature actuation circuits. The licensee stated that this matter would be  ;

reviewed as part of the long term followup of PIR 2-87-8 ;i i

licensee investigatiun attributed the cause for the unexpected cooldown to f

two open valves in the steam supply line for the second stage reheater in the l IB Moisture Separator / Reheater. Both valves normally receive a signal to e automatically close following a turbine tri However, the MS-28 valve power j

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l l supply breaker was tagged open with the valve open due to a maintenance prob-

! lem with its operator, and the controller for MS-79A was in manual and could not respond to the auto close signal. The status of valve MS-2B was left unchanged and it will be addressed as a maintenance item during the refueling l outage. 1.icensee followup actions included informing the operators of the condition on MS-2B and confirmation that the valve could be closed manually, if needed. The inspector noted that the operating procedure for the moisture separators, while somewhat vague, does allow the operator to operate the low load steam supply valve MS-79A&B as necessary to assure yniform loading con-ditions are maintained on the turbine during startup. The low load valves

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are fully open when the plant is at 65'. power, and their position and method of control (auto or manual) has no impact on plant operations for normal full power operation. The licensee used the manual control mode for the valves during the subsequent plant startup on November 17, 1987, and then placed the controllers in automatic for subsequent full power operations. The inspector verified the controllers were in automatic on November 18, 198 The fast transfer circuitry for Bus 25A was tested and found satisfactor Thus the cause for the bus transfer failure was e termined to be faulty con-tacts in the H103 RSST tie breaker. Further investigation was deferred until plant startup since the H103 breaker was in use to power the 25A bu The licensee identified a bad contact in the closing circuit for the H103 RSST tie breaker, a GE magne-blast circuit breaker, and a bent shaft in the snubber l for the elevator motor control handle. The licensee postulated that the shaft

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was bent when the breaker was previously racked up when a plant equipment I

operator (PEO) released the handle prematurely upon hearing the spring charg-l ing motor energize prior to full travel of the breake The control handle l operates interlock switches via the positive interlock roller in the breaker l closing control circui The bent shaft prevented full retraction of the control handle, which in turn caused only partial operation of breaker inter-lock switch 52/I5 (GE Type 29400310). Of the two contacts used in the inter-lock switch, one which allowed energiration of the spring charging motor when the breaker was racked up was found fused closed. The other was held open by th' partially retracted handle, which prevented energization of the 52X closing coil when the f ast transfer was called for.

The faulty interlock switch and the bent snubber shaft were replaced. The licensee checked all 4KV and 6.9KV breakers and found no others that had con-trol handles bound in a similar manner. Final repair of the closing circuit was completed during the morning of November 17 after the Bus 25A supply was transferred back to the normal station service transformer (NSST). Post-repair testing included manually switching the Bus 25A supply from the RSST to the NSST three times, which tested the closing circuit upstream of the l faulty interlock switch. The licensee is reviewing additional long term cor-rective actions, including replacement of the CR2940 control switches peri-edically during routine breaker PMs, and retraining PEOs to assure they do not release the elevator operating handle until the breaker is fully u The inspector reviewed the H103 failure mechanism and independently concluded that the cause was correctly identified and corrected.

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l The reactor was restarted following completion of the above investigations, >

was taken critical at 8:18 p.m. on November 16, 1987, and was phased to the grid at 4:16 a.m. on 11/17/8 Inspector review of the transient, the causes and equipment failures, and the licensee's followup actions and corrective '

measures identified no individual inadequacies. The resident inspector wit-nessed the reactor startup and verified it was completed in a safe and orderly manner. The reactor resumed power operations and escalated to full load under normal chemistry and ramp rate restraint The inspector will follow the licensee's corrective actions to determine (i) whether changes in breaker preventive maintenance and/or testing is needed to prevent recurrence of the H103 type failure; and, (ii) what additional actions are necessary to ada.ess other possibly faulty SBl type switches is safety actuation circuits (UNR 50-336/87-25-03).

8.0 Review of Licensee Event Reports

One Licensee Event Report (LER) submitted during the report period was re- :

viewed to assess LER accuracy, corrective action adequacy, compliance with 10 CFR 50.73 reporting requirements, and whether toere were generic implica-tions or if further information was required. Selected corrective actions were reviewed for implementation and thoroughness. The LER reviewed was: >

Unit 1

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87-41, Design Change Prohibited by Technical Specifications, 11/13/8 The licensee completed a review of all design changes implemented during the 1987 refueling outage to verify that appropriate changes to proce- '

dures and the technical specifications were processed. The inspector reviewed the results documented in a memorandum to the Unit 1 Superin-tendent dated November 4,1987. No other discrepancies were identified by the licensee's revie Since the event reported in the LER (and re-viewed in Inspection 50-245/87-27 & 50-336/87-23) was found to be an isolated event, no additional corrective actions were taken or are ,

planned. No inadequacies were identifie .0 Surveillance Activities The surveillance test listed below was reviewed to verify that testing was performed in accordance with approved procedures, test results demonstrated compliance with technical specification and administrative requirements, and that deficiencies (if any) were corrected in accordance with established administrative requirements,

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SP 26128, Service Water Pump Operability Facility II, completed 10/27/8 SP 2612B was performed along with OP 2326A to test the "C" Service Water >

Pum Test activities were observed in the control room, the RBCCW heat exchanger area and in the intake structur P.ased on observations by

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the inspector and the NRR Project Manager, SP 26128 and applicable sec- i tions of OP 2326A were correctly implemented, and data recorded on form 2612B-1 showed that the "C" Service Water Pump was operable. No inade-quacies were identifie '

10.0 Increased Auxilia,ry__8uilding and Control Room Radiation Levels A routine primary coolant sample was drawn by a chemistry technician from the l primary sample sink in the primary auxiliary building (PAB) 34 ft elevation at about 7:30 a.m. on October 30, 1987. The sample valve failed to fully close after the sample was drawn, resulting in a continuous drain of primary coolant into the sample sink, which is hard piped to a floor drain near the sink. The liquid leakage was drained to the radwaste system for processing, but noble gases evolved from the leakage and caused increased noble gas ac-tivity in the sample sink general are Most of the airborne activity was collected and released by the auxiliary butiding ventilatier, system. But a portion of th3 activity travelled via the interconnected floor drain system to the control room ventilation room. The motive force pulling the gas from the PAB to the ventilation room came from the auxiliary building supply fan and the control room supply fans, which are located in the room and have ducting that passes through the room. Even

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though the auxiliary building and control room fans do not communicate with the rooms directly per design, the fans pulled air from the rooms into their respective ducting through plenum access doors with worn seals. This leakage path was subsequently proved by the licensee using a helium leak tes l Once the radioactivity entered the control room ventilation system, it was recirculated into the control room and to the DC switchgear room, which re-ceives a slip stream from the control room ventilation system. A ground level release occurred via the DC Switchgear and battery room exhaust fans, F112A&B, one of which is normally operating and both of which discharge to the atmos-phere on the East side of the PAB. The increase in noble gas activity was

noted in the control room by 9

30 a.m., when an annunc'ation was received from -

the P.M 8011, which monitors the control room ventilation header on the dis-  !

charge of the supply fans. Throughout the subsequent event, the activity recorded by the monitor increased from the normal background level of 20 counts per minute (cpm) to a maximum value of 100 cp RM 8011 provides only an alarm function and does not initiate control room isolation. Automatic control room isolation is provided by redundant radiation monitors located  ;

on the fresh air intake duct, which would be the presumed source of activity ,

to the control room following a design basis acciden l The operators responded to the control room radiation alarm and requested  !

health physics personnel to take air Samples in the control room and the PA l The control room was posted as an airborne radiation area when gas concentra-tions reached 0.3 MPC and 0.1 MPC for Xe-133 and Xe-135, respectively. Con-trol room activity remained below the level which would have required the room be posted as a radiation work permit (RWP) area. No increase in airborne

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activity was detected in the common access corridor between Units 1&2. There l

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was no impact:on Unit I sinra the ventilation. systems for the units are separate. There was no impuct on Unit 2. operations as a result of posting the control room and the plant continued routine full power operations throughout the even Plant operators closed the open samplo sink valve. by 10:30 a.m. A sharp de-crease in activity was indicated on RM 8011 following this action. The operators placed the control room ventilation system on recirculation by 11:15 a.m., terminating the ground level release. All radiation levels in the PAB returned to normal by about 1:30 p.m., as shown by strip chart recordings from radiation monitors RM 843A, 8997,899 The licensee evaluated the event and concluded no hazard occurred for either site personnel or to the general public due to the low levels of activity involve 4. The licensee used the reading from RM 8011 as a source term for ,

an offsite release calculation. The licensee calculated, for a 1.4 uCi/sec release rate over an assumed 5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> period, a maximum probable estimated total dose at the site boundary of 0.00001 mrem due to the ground level releas ,

The calculation was dons using the MPOOSE computer code and actual meteorology for the, event. The inspector reviewed the licensee's calculation, verified n that it was conservative, and concluded that no 10 CFR Part 20 limits at the ,

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site boundary were exceedad. The licensee informed the Stat ^ of Connecticut about tt.a release by declaring a General In*erest Event at 5:00 p.m. on Octo-  ;

ber 30, 1987. The repart was made because a release had occurred through a monitored but unintended release path. A 10 CFR 50.72(b)(2)(vi) notification was made to the NRC based on the notification to offsite authoritie The resident inspector reviewed the licensee's immediate actions in response ,

to the event and identified no inadequacies. Actions were taken to inform technicians of the need to ensure sample valves are securely closed after drawing a sample. The interconnected floor drain system had a water loop seal between the PAB and the enclosure building, but not between various areas within the PAB or between the PAB and areas like the control room ventilation room. Actions were taken'by November 9 to install a 6-inch water seal on three floor drains in the control room ventilation room, which will require *

periodic surveillance by plant equipment operators to assure the seals stay i

water covered. The inspector reviewed the design of the seal as described in PDCR 2-87-76 and witnessed the PORC review and approval on November 6, 198 No inadequacies were identified for the short term action Long term action on the iten; is planned by the licensee and is needed to ad-dress concerns made evident by the event. While the actual radiological hazard for the October 30 event was insignificant, the event revealed a leak-age path into the control room that bypassed engineered safety features de-signed to ensure control room habitability and mitigate the consequences of design basis accident conditions. The licensee is reviewing the event to determine what long term corrective actions are warranted. Followup actions ,

are being tracked per PIR 87-76. These actions will include an assessment of the control room envelope during a special test planned during the upcoming refueling outage. The licensee will perform a leakage test on the control L

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y 15 room envelope to. verify inleakage is less than the 100 cfm assumed in the bases for the accident analyses. The testing is_ planned to establish a base-line for subsequent plant operations _in accordance with control room habit-ability surveillance requirements that will be-in effect upon startup from the outage. As part of this effort, the licensee has actions in progress to identify and eliminate inleakage into the control room ventilation housin The inspector will folicw the-licensee's actions in this area during subse-quent routine inspections to verify plant operation in accordan':e with license '

conditions (UNR 50-336/87-250-04).

In' addition to the above actions, during a meeting with the Unit 2 Superin-tendent on November 24, the inspector requested the licensee to complete an

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evaluation of control room habitability based on the as-found conditions re-vealed during the October 30 even The evaluation is necessary to assess the significance of the leakage path and to evaluate the integrity of the control room envelope for the postulated design basis accident condition The licensee agreed to complete the evaluation, which would include an an-alysis of three scenarios selected to bound postulated accidents, as follows:

Loss of Coolant Events on Units 2 or 3 and a main steam line event o Unit 1; a rupture of a waste gas decay tank in the Unit 2 PAB; and plant operation for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> with the maximum allowable identified leak rate of 10 gpm concur-rent with primary coolant radiochemistry at the maximum concentrations allowed-by the technical specifications. The licensee stated they expected to have the results of these analyses available for NRC review in December 1987. The inspector requested the licensee to either test tne control room enve?oce in the as-found condition to demonstrate that the 100 cfm inleakage values as-sumed in the accident analysis is bounding, or otherwise account for uncer-

/- tainties in the inleakage value (which could be greater than 100 cfm) in his analytical evaluation The inspector identified no inat'equacies with the licensee's proposed plans and schedule. This item will be reviewed further on a subsequent routine inspection (UNR 50-336/87-25-05).

11.0 Fuel Assembly Pressure Drop Testing-Unit 2

The' licensee conducted testing during the inspection period to complete pres-sure drop measurements on a new fuel assembly per the instruction of In-Service Test T87-27, Pressure Drop Test on Westinghouse Fuel Assembl The testing was conducted in r special portable hydraulic test facility supplied l

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by Advanced Nuclear Fuels Corporation that was set up in the Unit 2 Fuel Storage Building. The test was completed to obtain fuel assemble pressure drop data in support for future fuel cycle analyse The inspector reviewed the test plan and method w!.h the Unit 2 Reactor Engi-neer and reviewed the licensee's safety evaluation for the test in advance of the measurements. The licensee's evaluation was found to be complete, technically adequate, and satisfactory to address potential concerns associ-ated with the conduct of the test. The inspector noted that the licensee's evaluations considered seismic issues for the potential impact on the new

"test" fuel bundle, and the potential impact from postulated malfunct'oas of

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the' test rig on fuel stored in'the fuel storage building. ;The testing was

' subsequently completed. satisfactorily during the~ week of November 23, and the

~ test facility was removed. No inadequacies were identifie Committee' Activities

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The. inspector; attended Unit 2.PORC Meeting 2-87-115 on November 6, 198 Technical Specification 6.5 requirements for committee composition and quorum were met. 'The meeting agenda included review of PDCR 2-87-76,.as described in Section 10.0 above. The inspector observed a good regard for safety b the PORC in regard to the matters under review. No inadequacies were identi-fie .0 Management Meetings 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 inspection. No written material was provided-to the licensee during the inspection period.

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