IR 05000423/1989011

Insp Rept 50-423/89-11 on 890613-0717.No Violations Noted. Major Areas Inspected:Facility Tours of MP-3 Site,Esf Sys Walkdowns of Recirculation Spray Sys,Si Pump Cooling Sys, Turbine Driven Auxiliary Feed Pump Sys & Review of LERs

ML20248A664
Person / Time
Site:	Millstone
Issue date:	08/02/1989
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20248A660	List: IR 05000423/1989011 ML20248A657
References
50-423-89-11, NUDOCS 8908080361
Download: ML20248A664 (21)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /89-11 Docket N License N NPF-49 l Licensee: Northeast Nuclear Energy Company

'P.O. Box 270 Hartford, CT 06101-0270-I Facility Name: Millstone Nuclear Power Station,-Unit 3 Inspection At: Waterford, Connecticut

' Inspection Conducted: June _13 to-July 17, 1989-Reporting Inspector: K. S. Kolaczyk, Resident Inspector MP-3 Inspectors: W.J. Raymond, Senior Resident Inspector J. Golla, Reactor Engineer J. Yerokun, Reactor Engineer S. Barr, Reactor Engineer K. S. Kolaczyk, Resident Inspector Approved by: kbh E. C. McCabe, Chief, Reactor Projects Section'1B f/2/&T Date

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Inspection Summary: Inspection on 6/13/89-7/17/89 Areas Inspected: Routine onsite inspection'(272.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />) including 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of-

backshift coverage of Plant Operations; Facility tours of entire MP-3 site, ESF System walkdowns of recirculation spray system,.SI pump cooling. system, turbine driven auxiliary feed pump system, rod cluster control assembly substitution, safety parameter display system upgrade, containment integrated. leak' rate-test; Review of Plant. Incident Reports; Review of Licensee Event Reports; mainten-ance; and surveillanc Results

No' unsafe conditions were identified. Onc unresolved item concerning accumulator transmitter errors was closed (Detail 4'.0).

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TABLE OF CONTENTS PAGE 1.0 Persons Contacted.................................................... 1 2.0 Summary of Facility

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Activities....................................... 1 3' 0 Review of Outage Activities (71710/71707/62703) . . . . . . . . . . . . . . . . . . . . . .

. 2 3.1 Fa c i l i ty T o u r s . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 3.2 Work Practices 0bserved.......................................... 3

' Service Water Leaks Identi fied ( PIR 89-122). . . . . . . . . . . . . . . . . . . . . . 3 3.4 Containment Observations............... ........................ 4 3.5 Review of Scaffolding Engineering Analysis...................... 4'

3.6 Engineering' Safety Feature (ESF) Systems Wal kdown. . . . . . . . . . . . . . . 5-3.7 Rod Cluster. Control Assembly Substitution During the Outage..... 6 4.0 Status of Previous Inspection Findings (93702)....................... 7-4.1 (Closed) UNR 89-01-02: Accumulator Level Transmitter Errors..... '7 5.0 Plant Operational Status Reviews.(71707/71711)....................... 8 5.1 Review of Plant Incident Reports (PIRs) . . . . . . . . . . . . . . . . . . . . . . . . . 81 5.2 Review of Plant Startup Activities.............................. 9 6.0 Safety Parameter Display System (SPDS) Upgrade (71707)................ 9 7.0 Containment Integrated Leak Rate Test (70313)........................ 10 7.1 Valve Line-ups.................................................. 31- Instrumentation................................................. 11 7.3 Administrative Control of CILRT and Procedure Review............ 12-7.4 Test Performance and Contro1.................................... 12 7.5 Edited Chronologylof Events..................................... 13 7.6 CILRT Results................................................... 14 Findings........................................................ 1 .0 Events Requi ring Inspection Followup ( 92703) . :. . . . . . . . . . . . . . . . . . . . . . . . 14

8.1 Polar Crane Fire (PIR 89-111)................................... 14 8.2 Steam Leak Necessitating Turbice Shutdown....................... 16 8.3 Spill of Contaminated F1uids.................................... 16- ;

8.4 Inadvertent Control Building Isolation........................... 17 - ;

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9.0 Review of Licensee Event Reports (LERs) (92703). . . . . . . . . . . . . . . . . . . . . . - 18 .)

10.0 Maintenance (62703).................................................. 18 11.0 Surveillance (61726)................................................. 11 8 l 12.0 Management Meetings (30703).......................................... 19

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DETAILS 1.0 Persons Contacted

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Inspection findings were discussed periodically'with the supervisory and management personnel identified below:

S. Scace, Station Superintendent-C. Clement, Unit 3 Superintendent 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-S. Sudigala, Assistant Maintenance Supervisor-G. Bohn, Senior Engineer B. Beckman, Instrumentation and Controls Supervisor i 2.0 Summary of Facility Activities

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The plant completed its second refueling outage and returned to power ]

operation during the report period. The reactor was in mode- 6 (refueling) 1 at the start of this report period. Cold Shutdown was entered on June 20 t when the reactor was refilled and vessel bolts were fully tensioned.- The plant was then placed in mid-loop operation to facilitate repair of loop isolation valve body to bonnet leakage. Loops were filled swept and vented on July 2 and a containment integrated leak rate test (CILRT) was performed. Upon successful completion of the.CILRT plant heatup bega Normal operating temperature and pressure were reached on July During the heatup, RCS pressurizer safety valves exhibited signs of leak . i age. Although the leakage was quantified to be small, this area will con- -l tinue to be closely monitore Reactor criticality was achieved on July 10. Power was maintained at a low power level =1x10 -8 amps to support core physics testing and to allow completion of final equipment hot functional test Mode I was entered on July 12. Pcwer escalation proceeded slowly due to secondary chemistry hold points, flux mapping and emergent equipment prob-lems. One such emergent equipment problem was the failure of a we'id on'a l turbine control valve drain line which necessitated a power redottion .from 30% and taking the turbine off-line to affect repairs. At the end of the 4 inspection period power was being held at 95% while the licensee examined l the "B" condenser water box for leakeg I

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3.0 Review of Outage Activities (71710/71707/62703)

Outage performance l

Licensee management was actively involved in planning and controlling re-fueling outage activities. An outage organization composed of engineer- i ing, supervisory, and experienced operations staff provided good control i of activities and plant configuratio Unit staff meetings were held twice daily and on weekends. The meetings I provided accurate updates of work and plant status and provided the focal ;

point for problems and conflicts that required management attention. The j meetings kept personnel aware of plant status and promoted effective com-munication between departments. Management provided clear and frequent direction on outage activities and was effective in resolving problem l The outage schedule group provided a positive contribution to outage acti- i vity control through computer generated outage schedule reports, with the i three-day outage look ahead for charts showing the status of critical path {

jobs and activitie Continuous management representative coverage was effectively used to monitor activities and resolve problem ]

q The planned outage duration was extended because of minor problems and delay in completing the integrated leak rate schedule. No compromise in maintaining safety for the sake of maintaining the schedule was observe A number of minor problems occurred with /uel handling equipment and in operations in the reactor cavity and the spent fuel pool. The licensee plans to address this matter in the post-outage critique. The inspector concluded the outage was well planned and execute .1 Facility Tours j

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During the outage period frequent tours were made of the Millstone 3 site to assess the overall condition of the unit. Areas examined .

included general housekeeping, material condition of piping and com- l ponents, work practices of Millstone personnel, and adherence to pro-cedural ano station rules. During outage completion and plant start-up, the inspector noticed housekeeping improvement in the well traveled location In areas that are less frequently traveled such as the Recirculation Spray Systen: (RSS) and Residual Heat Removal !

(RHR) Heat Exchanger Cubicles in the Emergency Safety Features (ESP)

building and the Demineralized Water Storage Tank valve area, the inspector identified articles such as removed insulation, old pro-tective clothing and rusted tools laying adrif It was apparent that some of the articles left in these areas were longstanding items based on their condition. Increased licensee at- ,

tention should be directed at these area i i

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.3.2 Work Practices Observed The inspector toured the station and on several occasions, not iced licensee personnel' standing on safety related piping and valve opera-tors. The inspector considers standing on motor operated valves while performing unrelated work, a' poor work practice. A worker standing on the valve actuator may unknowingly damage electrical con-nections_such as limit switches,' damage seals that maintain a sys-tem's environmental qualification, or inadvertently engage the manual-

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.J actuator. These actions could result _in equipment inoperabilit Standing on safety related piping may damage supports which restrain ]

the pipe _during seismic events.. The inspector discussed his observa- 1 tions witii the operations supervisor who acknowledged the inspector _'s comments. Although the inspector has no knowledge of any equipment being damaged by personnel at this facility, prudence would dictate that caution should be used when working on or near safety'related system .3 Service Water Leaks identified (PIR 89-122)

The inspector noticed the presence of leakage.on the "B&D" Recircu-lation Sprey System (RSS) service water piping. The. inspector re-ported the leakage to the licensee assistant maintenance' supervisor who initiated work orders to inspect the piping._ . Inspection of the  !

piping-revealed the presence of.a through wall defect on the "D" RSS service water piping just downstream of a bellows expansion joint on the heat exchanger outlet, and a leaking gasket on a flanged Bellows joint on the upstream side of the "B".RSS Heat Exchange Inlet. The licensee reported that the cause of the through wall leak was attri- ,

buted to a defect in the monel cladding of the carbon steel pip ]

The gasket leak on the "B" recirculation Cooler Service water piping I was attributed to normal agin l The inspector witnessed portions of the repair to the "B" service -

water piping. Tho jefect was ground out and rewelded.. To prevent-recurrence of this problem the interior of the piping was covered with belzona sealant. The licensee examined the identical areas on the remaining piping systems and found no evidence of degradatio The inspector noted that the licensee response to the 1_eakage was-thorough and prompt, however, the inspector was_ concerned regarding i the lack of licensee identification. Normally, system leaks.are:  !

located by primary equipment operators-(PEOs) while they-perform j their tours throughout the facility. :It' appears that this system I works well in high. traveled areas, since pipe material conditions and j area cleanliness in the plant is generally. satisfactory. Improve- l ments are needed in less frequented areas in order to provide prompt correction of leak !

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4 3.4 Containment Observations During the refuel outage frequent tours of the containment structure i were performed by the inspector. While in the containment the in- I spector noted housekeeping to be adequate and high radiation area j jobs well posted. Health physics technicians were knowledgeable of 1 radiological conditions and appeared to have a genuine concern for i minimizing radiation exposure of personnel. At high radiation area entrance points, detailed photographs of the areas were taken and hot ;

spots of higher exposure were identified on the photographs. The i inspector noted the detailed photographs could assist in reducing J exposure of personnel by providing them with a more detailed picture 1 of what an area's radiological conditions were like prior to entr While in the containment structure, the inspector noticed the pre- {

sence of black cable tie wraps in containment. The inspector asked a j senior electrical engineer whether the black tie wraps are qualified for use in a harsh environment. The engineer and the inspector ex-amined Millstone specification SP-EE-076 which revealed that only i blue tie wraps are qualified for use in containment. The signifi-cance associated with having unqualified tie wraps in containment are that unqualified equipment could disintegrate during a Loss of Cool-ant Accident (LOCA) and clog the recirculation sump strainer and !

thereby cause the RSS pumps to loose suction during the recirculation i phase of an accident. The components of an unknown chemical composi-tion in the containment; which are not analyzed may also have a de- i leterious effect on the containment equipment in an accident atmos- I phere. The inspector and licensee engineer toured the containment prior to final closure to determine the extent of the problem. The detailed walk down of the containment structure revealed that the unqualified black tie wraps were used in only a few locations. The l unqualified tie wraps were removed from the containment prior to startup and the inspector concluded that no safety concern exists in '

this are .5 Review of Scaffolding Engineering Analysis During the inspection period select licensee engineering documenta-tion was reviewed to ensure that the calculations.used were conserva-tive and actions taken would not affect safety. One such calculation (3-ENG-146) involved a technical justification for temporarily stor-ing scaffolding in containment during the Millstone Unit-3 operating cycle. By leaving the scaffolding in containment, the licensee would reduce the amount of material that had to be removed and decontami-nated during final containment cleanup and would thereby reduce the i length of the outage by allowing an early containment closecu '

The problems associated with leaving scaffolding in containment are:

the scaffolding may become a missile hazard during a seismic event and damage equipment in containment; and, the zinc that is contained

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vironment and generate excessive amounts of hydrogen that was not !

analyzed in the Final Safety Analysis Report (FSAR).

The insp9ctor reviewed non-conformance report (NCR) 389-217, which 1 allows the scaffolding to' remain and verified that the scaffolding j would be chained down in an appropriate location which would not  ;

present a danger to plant equipment. The inspector also reviewed the i engineering analysis which verified that the amcunt of zine that  !

would be added to the containment by the scaffolding would still fall j within the analyzed amount in which the FSAR is base Inspector review of the analysis found it to be conservative and well sup-ported. It was calculated that the amount of zinc that weuld be added by the addition of the scaffolding was well within the 20% con-tingency ainount analyzed in the FSAR. However, an error was noted in 1 one of the assumptions used in the calculations. Specifically, one I of the assumptions made was the amount of conduits, conduit supports, junction boxes, and galvanized paint that was located in containment was to increase by 50% of the original amount analyzed in the FSA This assumption was to allow for any equipment that had already been added to the containment and may have not been analyzed. In one of the calculations an incorrect amount was taken from the FSAR Tabl The licensee engineer used the amount of zinc contained in flow switches that are in containment and not the amount in paint as was ca' led for in the initial assumption. The inspector notified the preparer of the analysis of his error, and the analysis was cor-rected. It was concluded the error was minor when considering the conservative numbers used. The inspector is satisfied that the en-gineering analysis adequately addressed any concerns associated with the scaffolding, and no safety concerns were note .6 Engineering Safety Feature (ESF) System Walkdowns The inspector performed a detailed system walkdown of the Safety In-jection Pump cooling water system, the "D" RSS and the Turbine Driven Auxiliary Feedwater (TDAFW) pump system prior to plant startup. Dur-ing the walkdown the inspector compared the as-built piping system with the plant drawings, examined the physical cendition of the pip-ing and components and noted the status of housekeeping in the gene-ral are Additionally, the inspector verified the licensee valve lineups for the system. No discrepancies were noted between the as-built system and piping drawings. On the RSS, the inspector noted several packing and joint leaks. The inspector considered this a relatively high number since this system is normally kept dry and is filled only when tested. A review of outstanding work items revealed that only one packing leak was documented on the licensee's planned maintenance management system (PMMS). The inspector noted that this piping area is not located in a high travel area and thereby receives less scrutiny from licensee personnel. This may also account for the debris lef t in the RSS heat exchange area as discussed earlier. The

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RSS system may require additional attention in maintenance and house -

keeping so that it may be maintained at the same level as the more visible systems are in the plan .7 Rod Cluster Control Assembly (RCCA) Substitution During the Outage During the first week of June the licensee had non-destructive ex-aminations performed on all rod cluster control assemblies (RCCAs)

which had been removed from the core. The reactor core contains 61 RCCAs which are used to control the reactor during operation and to shut down the reactor when required. The results of RCCA inspections at other plants similar in design to Millstone 3 had revealed swell-ing of the rod absorber material, leading to bulging of the RCCA rod-let cladding. This phenomena was investigated by the vendor (West-inghouse) who concluded the cause to be hydriding of the hafnium (Hf)

absorber material. (This problem was discussed in detail in NRC In-spection Report 50-423/88-23, dated January 19,-1989). The concern is that rod swelling might lead to RCCA sticking or to unacceptable increases in rod drop times. The vendor evaluated possible substi-tutes for the absorber material and determined a Silver-Indium-Cadmium (AgInCd) alloy possessed similar neutronic characteristics without manifesting the same swelling problems. The. licensee con-ducted a safety evaluation for substituting Ag-In-Cd rods for damaged Hf rods and concluded the change to be safe and not an unreviewed safety question. Initial results from Combustion Engineering, the contractor that performed the non-destructive examinations, indicated that five RCCAs needed to be replaced. The licensee decided to re- 1 place Shutdown RCCA Bank E with Ag-In-Cd rods (Shutdown Bank E has four rods). In order to maintain reactor core symmetry, the fifth rod was replaced with a new Hf rod. The new RCCAs were installed in their respective fuel assemblies while.the fuel was being held in the Spent Fuel Poo While the fuel was being re-loaded into the reactor vessel, Combus-tion Engineering informed the licensee that, after reviewing the test results, it had determined that another RCCA needed replacement. The licensee decided to add a fifth AgInCd RCCA and shift all new AgInCd RCCAs to Control Bank D, which has five rods in it. Since the fuel i assemblies had already been loaded in the reactor vessel, the licen-  !

see intended to use the SIGMA fuel-handling machine, which is inside containment, to perform the necessary RCCA manipulations. When the

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SIGMA machine removed the damaged Hf RCCA, it could not place it into the " dummy" fuel assembly needed to transfer the RCCA to the Spent Fuel Pool. The licensee cetermined that the SIGMA machine did not have the proper grid dip assembly, especially if the rodlets have been deformed due to hafnium hydriding. -A special case was designed and manufactured by the licensee in order to transport the damaged RCCA out of the reactor cavity and into the Spent Fuel Pool. Due to

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the inadequacy of the SIGMA machine, the licensee decided to off-load the nine necessary fuel assemblies with their RCCAs and perform all l RCCA transfers in the Spent Fuel Poo !

During a refuel pool transfer, an additional Hf RCCA was damaged due j to operator error. This resulted in a total of six AgInCd RCCAs '

being required in the new core. The licensee held discussions with Westinghouse concerning optimal RCCA placement in order to minimize i future RCCA and fuel assembly movement i These discussions resulted in a licensee decision to place four of the new AgInCd RCCAs in the Control Bank D and two in Shutdown Bank The fifth RCCA in Control Bank 0 is an old Hf RCCA. Core sym-metry is maintained because this RCCA is at the geometric center of the core. The two remaining RCCAs in Shutdown Bank E are also old Hf rods. Because Shutdown Bank E RCCAs are at the outermost periphery of the core and have very low rod worth, it was determined by the  ;

licensee that symmetry was not required in Shutdown Bank E. The'nine i fuel assemblies and RCCAs were re-loaded in the reactor vessel with-out incident, and core re-load was completed on June 1 The inspector followed, and discussed with the licensee, these events as they developed and reviewed the Westinghouse and licensee safety j evaluations. The licensee handled problems that arose in a safe and i conservative manner, although with additional consideration and care, f some of the RCCA handling problems may not have happened at all. The j licensee plans to conduct a critique and self-evaluation of this mat-ter following the cutage, which will be reviewed in a future routine inspectio .0 Status of Previous Inspection Findings (93702)

4.1 (Closed) UNR 89-01-02: Accumulator Level Transmitter Errors The licensee completed a deportability evaluation for PIR 3-89-90 regarding 7 of 8 level transmitters for the safety injection accumu- <

1ators that were found out of calibratio !

Instrument calibrations of accumulator level transmitters (LT 950,  ;

951, 952, 953, 954, 955, 956 and 957) per procedure SP3447D01 during  !

the refueling outage found calibration points that were outside of ,

the acceptance level by a small amount. There are four accumulator tanks, each having 2 level transmitter Licensee review of tank inventory records found both level indicators on each accumulator .,

read within 5 gallons during the operating cycle. The licensee found 4 no evidente that drift occurred during the operating cycl The eval 3 tion de anstrated the calibration error had no safety sig- l nificance dying ah3 last operating cycle since actual accumulator water invenG Q w aained within the assumptions of the accident an-alysis. The m m tank water volume in the FSAR is 6433 gallons,

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minus a 1% volume for tank dimension uncertainties. The lowest re-corded level for any accumulator was' 6640 gallons during the last cycle. The worst case channel-error was 59 gallons, such that the

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lowest volume in the tanks was 6581 gallons (B accumulator) which is l

. greater than FSAR assumptio Based'on the above, the licensee concluded that the requirements of'

Technical Specifications 6.5.1 regarding operable accumulators was

. met during the.last operating cycle. Further, the licensee deter-mined the event was not reportable per 10 CFR 50.73. The inspecto identified no inadequacies in the licensee's evaluation. This item a is close .0 Plant Operational Status Reviews (71707/71711) j

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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 of-the plant in accordance with the requirements.of the' technical ~specifica--

tions and plant operating procedures. Actions taken to meet-technical specification requirements when equipment was inoperable'were reviewed to verify the limiting conditions for operations lwere met. Plant logs and control room indicators were reviewed to identify changes in plant opera-tional status since the last review and to verify that changes in.the i status of plant equipment was properly communicated in' the logs and  ;

records. Control room instruments were observed for correlation between l channels', proper functioning and conformance with technical specifica-

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tions. Alarm conditions in effect'were reviewed with control room opera-  ;

tors to verify proper response to off-normal. conditions and to verify .

operators were knowledgeable of plant status.. Operators were found to be cognizant of control room indications and plant status. Control room man- )

ning and shift staf fing were reviewed and. compared to technical 'specifi- -!

cation requirements. No inadequacies were identified. The following i specific activities were also addresse :

5.1 Review of Plant Incident Reports (PIRs)

The plant incident reports (PIRs) listed below were reviewed during the inspection period to (i) determine the safety significance of the events; (ii) review the-licensee's evaluation'of the events; (iii)~as-sess the licensee's. response and corrective actions'-and,

(iv) verify that the licensee reported the events in,accordance with the applic-i able requirements, if required. .The PIRs' reviewed were

numbers L 89-108 dated 6/17,89-109 dated 6/19,89-110 dated 6/20, 89-112-dated ,

L 6/22,89-113 dated 6/22,89-114 dated 6/23,89-116 dated 6/23,89-117 i dated 6/22,89-118 dated 6/16,89-119 dated 6/25,89-120 dated 6/26,.89-123 dated 7/1,89-124 dated 7/1,89-125 dated 7/3,89-126 dated:

- 7/4,89-127 dated 7/7,89-128 dated 7/9,89-129 dated 7/9,.89-131 dated 7/10, and 89-133 dated 7/12. No inadequacies were noted. 'The-folicwing PIRs required inspector followu _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ - - - _ - _ - - __ a

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PIR.89-111 dated 6/2 '

Fire in containment polar. cran Re-.

viewed in detail,in section PIR 89-122 dated 6/3 Service water leak on recirculation spray' syste Reviewed'in detai1~in section .2 Review of-Plant Startup Activities The' inspector reviewed licensee plans and procedu' res and obsierved activities in progress to' restart;the plant following the-completion of refueling and maintenance' outage. The'ir,spection. included:-ob- ,

servation of. control room activities to verify plant systems.' statu ,

was ready to startup as required by plant procedures and-the tech- '

nical specifications; shift-staffing met technical. specification.re-quirements; verification on a sampling basis the prerequisite con--

ditions listed in procedure OP3201, " Plant Heatup", were met.and; plant ' operators followed the procedure justifications and'precau-tions. Verification by review and. independent walkdown of .the . ,

auxiliary.feedwater, safety injection cooling water and recirculation -

spray systems that plant systems were properly aligned to. support ~]

heatup and plant entry into Node 4 (RCS temperature greater than 200 )

degrees F). Observation'of.a shift briefing on 7/8/89 at 3:30 p.m;,. i was thorough and accurate in the discussion of plant status,'startup'

plans and testing in progress; and review and observation of sur-veillances that demonstrated plant systems were. operable to support I startu Items of minor significance were questioned and satisfac-torily addressed by the licensee. No unacceptable. conditions were identifie Inspector review showed licensee actions were generally effectice and showed good regard for safe reactor startup... Technical specification limits were met. No inadequacies were identifie .0 Safety Parameter Display System (SPDS) Upgrade License Condition C(12) of the Millstone Unit 3 Operatirig' License requires that " Prior to restart following the first refueling outage, Northeast 1 Nuclear Energy Company (NNECO) shall add to the safety' parameter display system-(SPDS) and have operational the following SPDS parameters:

(1) . Residual Heat Removal (RHR) flow (2) Containment Isolation l (3) Containment Hydrogen Concentration (4) Piimary Coolant System Hot Leg Temperature" ,

Lit > see letters dated November 13, 1987, December.24, 1987 and January-l 14, 1968, provided additional information'regarding this license condi- '

l tio The NRC reviewed this' information, and in a March 7,'1988, letter to ti.c licensee, concluded that the license condition 'had been satisfie The NRC letter also indicated, however, that the provision of Supplement 1

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10-i to NUREG-0737 (Clarification.of-TMI Action Plan Requirements) to provide'a continuous display was not~yet satisfied for the post-LOCA cooling vari-ables and containment hydrogen concentratio To resolve'this:1ssue, NNECO committed,lin their November 13,-1987 letter, to further evaluate the post-LOCA cooling variables and hydrogen concen- -

tration and, if deemed feasible, to implement these parameters prior' to '

startup from the second refueling outage. : At an April 25, 1988 meeting with the NRC, the licensee discussed the conceptual design features to provide a SPDS top level display for post-LOCA; cooling variables and con-tainment hydrogen concentration with existing plant process computer, para .

meters. The licensee..followed_.this meeting with a_May 2, 1988 letter which summarized how the top level displays for these parameters were to be_ achieved and restated'the licensee commitment to implement the SPDS upgrade prior to re. start following the'second refueling outage.' In'a July-27, 1988 letter, the NRC found the licensee commitments to meet all the requirements of Supplement 1 to' NUREG-0737 and the proposed schedule' for implementation to_be acceptabl The design of the new level. SPOS displays was completed by the licensee on June 7,1988, and the software ' installed into the SPDS during the week ofE 7 j June 25, 198 .0 Containment Integrated Leak Rate Test (70313)

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On July 2,1989, the licensee conducted the first periodic Containment Integrated Leak Rate Test (CILRT) for the Unit 3 containment as required by 10 CFR 50, Appendix A The test was conducted with containment isola-tion boundaries in an as-left conditio '

The test was performed in accordance with Station Procedure No. SP_ 31103,.

Rev. 1, " Containment Leak Rate Test - Type A" which utilized methodologies endorsed by industry standard BN-TOP-1, Rev.1, " Testing Criteria for In- 1 tegrated Leakage Rate Testing of Primary Containment Structures for Nuc- j lear Power Plants." l The test was observed by 2 region. based inspectors and l' resident inspec-tor. The inspectors reviewed the test procedure and witnessed prepara-p tions for. and various. portions of the as-left CILR '

l The purpose of this inspection was to ascertain that the'CILRT was con- i ducted in compliance with Technical Specifications and 10.CFR 50, Appendi ;

J, and that the test results met the. acceptance criteria. The procedure ;

was reviewed for its technical adequacy to perform the'. intended activi- l ties. Other documents reviewed include the CILRT test logs calibration '!

records for CILRT instrumentation, Plant and _ Instrumentation Drawings ,

(P&ID) test data and result i l

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7.1 Valve Lineups The inspectors independently verified on a' sampling basis,the posi-tioning of valves identified in Station Procedure-SP 31103, Rev. The penetrations reviewed were found.to be in an acceptable configu-ration such that containment isolation valves were exposed to the CILRT differential. pressur .2 Instrumentation The inspector reviewed the calibration records for the resistance temperature-detectors (23 utilized), dew' cells (5 utilized), pressure

detectors (one utilized plus a backup) and .2 Volumetrics FMIOHL's (verification test flowmeters). The instrumentation was:within-specified calibration values as of the time of calibration. The in-spectors verified that these instruments- were calibrated within the required 6. month period preceding the. test. It was noted that the licensee does a loop calibration and an onsite check of the RTD's and dewcells prior to the test. This was found acceptabl During the verification test, however, both FMIOHL Volumetrics flow-meters failed. The licensee attributed-the failure of-the first flow instrument to component malfunction. .The cause of the second flow instrument failure was determined to be'due to rust that had col-1ected in the carbon steel line through which the simulated leak was- i established. Apparently when the superimposed leak was established, rust from the line clogged the pitot tube which the instrument'was using to determine air flo Licensee actions were to forego use of the pitot tube instruments and-use an installed thermoconducting instrument which was the flow meas-uring device used during theiconstruction test CILRT. It was rea-soned that rust would not affect this instrument because it measures flow based on the change in conductivity of ? metal foil that occurs g when air passes over it. The inspector exame d the carbort steel j pipe in question and determined that the licen ue explanation of the failure of the second flow instrument was reasonabl i ANSI 56.8 1987 Section 3.2.6(b) states that " verification test by '!

rejection or removal of a quantity of air from or into the contain - !

ment shall be performed as soon as possible following each type A )

test." The licensee. interprets "as soon as possible" to be within )

one hou Since the length ~of time between the performance of the <

CILRT test and simulated test had been greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> the licen- :

see elected to reperform another 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> leak rate test and use the

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7.3 Administrative Control of CILRT and Procedure Review The inspectors reviewed procedural sign offs and the CILRT log of' i events and held discussions with.the test supervisor to verify that:

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Test directors were designated and their responsibilities were

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The procedure was adequately detailed'to assure satisfactory performance;

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Test prerequisites were met;

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All. systems required to maintain the plant in a safe condition were operable and in their normal mod The inspectors noted upon reviewing SP 31103, Rev. I several typo--

graphical errors. These were brought to the attention of the licen-see who promptly made procedural changes to correct them. The in-spectors found that the procedure was otherwise.well written and suf-ficiently detailed to assure technical adequacy and proper conduct of the tes It was noted that the'. licensee (test supervisors) con-ducted shift briefings with control room personnel to coordinate test activities with operations and.to stress control of access to pene -

tration areas during the tes .4 Test performance and Control Tours were made by the inspectors before and during the CILRT to as-sure that test activities were being conducted in accordance with the test procedure and within regulatory requirements. During these tours, test boundaries were surveyed for evidence of . leakage and valve position. Valves were observed to be in their correct posi-tion. Additionally, the licensee had leak crews throughout the pene-tration areas during various stages of the test. Only minor leaks were identified which required no action to complete the tes During a tour of the Auxiliary Building penetration areas, it was noted by the inspectors that a control room operator was sent to one of the penetration areas (4'8" elevation Aux. Bldg) to perform an j inspection of a motor-operated containment isolation valve (CIV)

which involved removal of the valves outer casing at the limit switch area. The inspector stated to the test supervisors, present at the time, that any manipulation of a' containment isolation' valves posi-tion during the test would immediately invalidate it. The' inspectors '

also discussed with the licensee the'importance of controlling access-l to penetration areas during the tes The test supervisors stated

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that the operators intended actions (inspec. tion of valve to determine limit switch setting) would not have altered the position of the valve and would be postponed unt11'after completion of the test and i; that his admittance to the penetration area and approval by shift i supervision was not intended by them and was an oversight. Shift briefings by the test supervisors had stressed that any activity in

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the penetration areas or any activity that could possibly affect the test be approved by them. This was stressed again by the test super-visors to the shift after the above occurrenc The inspectors noted that the licensee clearly understood the test requirements and had no intention of altering the configuration of the penetrations in question. The issue was resolved promptly and had no effect on the test. The inspectors had no further questions, 7.5 Edited Chronology of Events 7/3/89 0919 ILRT measurement system fully operable and read Began pressurization 1547 Rate of pressurization 3.5 psig/hr rate of tem incr. 0.33 degrees F/hr 1615 Leak searches identified minor leaks 2255 Test pressure reached isolated and vented fro compressors l 2337 Begin stabilization period 7/4/89 0337 Temperature stabilization criteria met 0415 Start-ILRT 0518 Containment air mass acting erratic due to dewcell i

rsadings 0528 Containment air mass stabilizing 0549 Decision :nade to restart the official start time ,

0600 Restart of ILRT 1507 End of ILRT total time, reduced duration test per BN-TOP-1 <

1745 Start of superimposed leak test. One flowmeter (FMIOHL-1) would not provide the HP computer with 4 a signal. Switched to FMIOHL-2 j 2030 Flowmeter (FMIOHL-2) failed. Licensee elected to use installed thermo flowmeter F-28. Personnel are called in to calibrate the instrumen l

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1 /5/89 0815 Licensee elects to reperform 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> CILRT due to-length of time that has' elapsed since' initial containment leak rate was determine Completed 8 h~ur o tes Started superimposed leak tes Completed superim.csssed leak tes /6/89 0000 Began containment depressurizatio Completed containment depressurizatio .6 CILRT Results The containment successfully passed the Integrated Leak Rate Tes The calculated. leak rate using the total time method was determined to be 0209 WTisday'which was well'within the acceptance criteria'of-

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.675 WT!; da .7 Finding All leaks identified were within the acceptance criteria and the con-tainment lesk rate met the acceptance criteria in both the as-found and as-left unditions. The test was performed within the guidelines of the procedure. Procedural precautions were adh'ered to and all test personnel interviewed were knowledgeable and competent to per-form their duties. Minor administrative' errors in the test procedure were identified by the inspectors.and were promptly corrected. Con-trol of penetration areas was ' adequate although an oversight resulted in an operator given permission by on shift supervision.to reinove a piece of casing from a containment-isolation valve to inspect the-limit switch setting without approva'l by the test; supervisor. 'This-

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activity was suspended by the: test supervisor when informed by the- t inspector. Instrumentation problems (failed verification test flow- I meters) forced the test to'be re-ru >

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8.0 Events Requiring Inspector Followup (92703) j 8.1 polar Crane Fire (PIR 89-111)

Wnile raising the reactor vessel seal tray onto-the-refueling water- d channel using the Polar crane, a fire started in the resister banks which control the speed of the auxiliary- crane hoo . Licensee response to the fire was prompt and effective, the fire was extinguished af ter 15 minutes by a licensee. fire brigade which was assisted by personnel from Millstone units one and two. ~During the !

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course 'of extinguishing the blaze, two individuals were contaminateri -

one on tha hand and soles of his shoes, the.other only on.the. sole .;

of his shoes. Both individuals were easily decontaminated. -A fol- 1 lowup whole body count did not show any signs of contamination in--

take.

I Because the fire lasted longer than 20 minutes, the. licensee declared an unusual event in accordance with the site emergency plan. LDuring' 1 the classification of the event, confusion between the shift super- j visor (SS) and shif t supervisor station assistant-(SSSA) caused the_ j event to be incorrectly classified as an echo or item of ~ immediate local interest. This confusion resulted in the notification being-issued two minutes later than the required 15 minutes. as specified in i the licensee emergency plan. Licensee Plant Incident Report (pIR) j 3-89-110 documents the event. Conversations with cont ol room staff, r the nspector determined that the late notification was due to mis-communication between the SS and SSSA. The inspector determined that ;

this miscommunication appears to be an isolated incident' cnd no fur- I ther action is require The cause of the polar crcne resister bank-fire was attributed to the melting of a cooling fan which was placed on the resister bank cabi-net in place of a cover that is normally installed. Tia fan was in--

stalled to supply forced cooling to the bank when the night shift maintenance supervisor determined that the resister banks were get-tirg too hot and that the rrrmal convection air flow through the !

banks was insufficient to prevent resister bank system failur How- !

ever during the course of polar crane operation, the fan became un- 1 plugged. The resultant heat buildup that occurred.during crane 1 . !

operation melted the plastic fan blades. This molten plastic then- l spilled onto the hot resister banks and ignite l

Licensee and vendor repairs to the resisters ccnsisted 'of removin'g i the upper two resister banks and replacing.them with . identical 're- !

sisters from the new fuel handling crane, removal of residual fire '{

fighting dry chemical on the banks and electrical resistance check '

The inspector noted that the licensee approach to the problem was ;

thorough and well thought out. All troubleshooting and repairs per-formed on the crane as written in the non-conformance report were ,

approved by the plant operation review committee (PORC) prior to im- '

plementatio Long-term evaluation as to whether the resister banks require cooling has yet to be completed. Final licensee solution to the possible ;

overheating problem with the polar crane resister bank is an open )

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l 8.2 Steam Leak' Necessitating Turbine Shutdown

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On July 15, 1989 at 9:30 a.m. while holding at.30% power, a steam leak developed on a turbine control valve drain.line weld. The loca- 1 tion of the weld necessitated shutdown of the' turbine and control of-plant power by use of steam dumps. During this evolution, a gland

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seal pressure regulating valve failed which caused the loss of gland sealing steam. Loss of gland scaling steam caused condenser vacuum to decrease below 25" Hg vacuum. The decrease in vacuum caused the condenser availability interlock C-9 to trip which closed the steam dumps. The closure of the steam dumps allowed a pressure transient to occur.which activated steam generator safety and power operated atmospheric relief valves. Operators quickly recovered condenser i vacuum and bypassed the defective' regulating valve. Plant pressure control was returned to the steam dumps, the defective weld was re-paired and the turbine was placed back on the grid later that day at-7:30 p.m. The inspector reviewed plant response to the transient and~

detected no abnormalities. Two Plant Incident Reports (PIR) were generated - one concerned the defective weld, the other reported the failure of the gland seal regulating va'.a. These Plant Incident Reports will be reviewed the next reporting perio .3 Spill of Contaminated Fluids On July 12, 1989, while shifting reactor building component coolin water (RBCCW) pumps, several relief valves lifted on the "A" RBCCW system. The lifting of reliefs while shifting RBCCW' pumps is ex-pected by operators who routinely dispatch a Primary Equipment Opera-tor (PE0) to examine the CCW system and reseat any- relief valves that have lifted. During this evolution, the PE0 did not examine all CCW

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continued to discharge its contents.to the. auxiliary building sum This water was then pumped to~ the high level waste collecting tnk located in the waste building. This tank which contained high acti-vity resin fines collected from an earlier discharge of chemical volume control system (CVCS) resin., overflowed into a- waste building sump which in turn overflowed onto the waste building' floor at the 4'

elevation. An estimated 2000 gallons of water spilled from the tank before a PE0 was able to reseat the lifting relief and direct other discharges to the tank elsewher No personnel were contaminated by j the event nor did any activity leave the waste building. Inspector j review of this event focused or. the events leading up to, during and ]

cfter the event. Through conversations with the operations super- i visor, the inspector learned that:it is " normal":for RBCCW relief 1 valves to lift during a pump shif Licensee efforts to ameliorate the pr6clem which was~ identified during preoperational testing con ~

sisted of raising relief valve setpoints and remachining the RBCCW pump impellers in an effort to reduce the pressure increase when a  ;

pump is started. The operations supervisor stated that despite these i

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I i efforts, the problem still exists, therefore, operators must rou- f tinely dispatch a PE0 to check RBCCW reliefs during a pump shif During the event the inspector reasoned that the discharged water !

would not be noticed by the operators since there is no indication on the control panel of sump pump activation. The water that was lost 4 out of the RBCCW system would be automatically made up to the RBCCW expansion tank prior to the tank reaching the low level alarm on the ]

j control panel. The inspector toured the waste building 4' elevation i and verified that decontamination was being performed in a satis- !

factory manner. Personnel were adhering to radiological instructions j and appropriate measures were being taken to protect the spread of 1 contamination. The inspector had no further questions on this event and is satisfied with the licensee efforts to remove the contaminated fluid .4 Inadvertent Control Building Isolation On July 14, 1989 while performing a test of the control panel safety injection (SI) switch, a control building isolation occurre The cause of the control building isolation was procedural inadequac Prior to performing testing of the manual SI switch reactor trip ,

function, leads are required to be lifted which would prevent a l safety injection, and a control building isolation from occurrin '

However, the procedure as written required that only the SI initi-ation signal to be disabled prior to testing of the switch. Con- j sequently when the manual SI switch was activated, both the reactor trip breakers opeud and an uncontrolled control building isolation )

i occurred. When .the event occurred, the operators verified that the j system functioned as designed, then reset the signal and returned the '

control building ventilation to the normal lineup. When reviewing i this incident, the inspector noted that the procedure was revised on i March 3,1987 and had been performed during the last refueling out- i age, October 30, 1987 - February 16, 1988. The inspector questioned licensee personnel as to why this inadequacy had not been identified earlier since if personnel were performing this procedure verbatim they would have either detected the deficiency or caused an inad-vertent control building isolatio Licensee engineer's reasoned that during the previous performance of this test, the technicians could have overlooked the procedure deficiency and performed the test because they '",new" what had to be done. The licensee also hypothe-sized that since the defective steps, were sequenced in between steps that required lifting lends, the technicians after removing the SI signal " forgot" where they were, overlooked the defective steps, lifted the leads that actuate control building isolation and then continued on with the test per the procedure and tested the SI switch reactor tri To this end, the safety significance of this particu-lar event is small, however, this is in example of a failere to rigidly adhere to a procedure. It should also be noted that the in-spector has net identified any other examples of failure to follow a J

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procedure during this inspection period. Therefore,,this event is considered an isolated occurrence and the inspector has no furthe question '0

. Review of Licensee Event Reports (LERs) (92703)

Licen see Event Reports (LERs) submitted during the ~ report period were re-vi ewet.: to assess LER accuracy, the. adequacy of corrective actions, compli-ante with 10 CFR 50.73 reporting requirements and to determine if there were generic' implications or if further information was require Selected corrective actions were reviewed for implementation and thorough--

ness. The LERs reviewed were: 89-014-00, 89-013-00, 89-012-00 and 89-011-0 .0 Maintenance (62703)'

The inspector observed and reviewed selected portions of preventive and-corrective maintenance to verify compliance with regulations, use of ad-ministrative and maintenance procedures, compliance with codes and stand-ards, proper QA/QC involvement, use' of bypass jumpers and safety tags, pr.rsonnel protection, and equipment alignment and retest. The following activity was included:

Repair of leaking service water piping which was already discussed in Sec-tion No inadequacies were identifie j l 11.0 Surveillance (61726)

The inspector observed partions of surveillance. tests to assess perform- 'l

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ance in accordance with approved procedures and limiting conditions of operation, removal and ' restoration of equipment, anc' deficiency review and i resolution. The following procedures were monitored.:

-- SP 3616A.I., MSIV Stroke Time Testing

-- SP 3612B.3, Containment Air Lock Leak Rate Test l, -- OP 3209B-2, Reactor Shutdown Margin verification

-- SP 3266.4, Turbine Driven Auxiliary Feedwater Pump Valve Status

-- SP 3622.3, Auxiliary Feedwater Pump Operational Readiness Tes i The program to track and verify satisfactory completion of surveillance ]

needed for plant startup was reviewed with personnel responsible for the i function. The program was detailed and well organized. Personnel re- 1 sponsible for the activity were knowledgeable of the test completion  ;

status and the items outstanding for plant.startup. No inadequacies were {

identifie 'l No inadequacies were note q

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l 12.0, Management Meetings (30703)

Periodic meetings were held with station management to discuss inspection 'l findings during the inspection period. A summary of findings was also {

discussed at the conclusion of the inspection. No proprietary information I was covered within the scope of the inspection. No written material was {

given to the licensee during the inspection perio j l

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