IR 05000245/1989012

Insp Rept 50-245/89-12 on 890509-0615.Major Areas Inspected: Previously Identified Items,Outage Activities,Plant Operations,Physical Security,Recirculation Pump Seal Failure Event,Reactor Scram on Low Main Condenser Vacuum & LERs

ML20247D202
Person / Time
Site:	Millstone
Issue date:	07/19/1989
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20247D193	List: IR 05000245/1989012 ML20247D191
References
50-245-89-12, NUDOCS 8907250079
Download: ML20247D202 (20)

Text

b

. a '

.

, ,

.. .

.

, .

I U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /89-12 Docket N License N DPR-21 Licensee: Northeast Nuclear Energy Company Facility: Millstone Nuclear Power Station, Unit 1 Inspection At: Waterford, Connecticut Dates; May 9 through A ne 15, 1989 Inspectors: Stephen Barr, Reactor Engineer, RPS 4A Peter Habighorst, Resident Inspector, Millstone 2 Paul Kaufman, Project Engineer, RPS 2B Lynn Kolonauski, Resident Inspector, Millstone 1 William Raymond, Senior Resident Inspector Approved-by: N Ebe McCabe, Chief, Reactor Prbjects Section 4A IT-Date-

'I,1spection Summary: Inspection from 5/9/89 - 6/15/89 (Report 50-245/89-12)

Areas Inspected: Routine NRC inspection of previously identified items, outage i activities, plant operations, physical security, the recirculation pump seal failure event, the reactor scram on low main condenser vacuum, the offsite l shipment of contaminated equipment, plant design changes, outage performance, l crack indications on reactor vessel head nozzle welds, maintenance and surveil- I lance ~ activities, licensee event reports and committee. activitie .

i The inspection involved 263 inspection hours. Thirty -(30) backshift hours, including eight (8) deep backshift hours, were conducte ]

'Re sul ts : The inspection identified no unsafe plant conditions. During the ref-ueling outage, the licensee demonstrated effective planning, communication, interdepartmental cooperation, and regard for safety. Follow-up is planned for the instrumentation and controls procedure for surveillance schedule compliance (Detail 11.0). j

, s

6

!

!

8907250079 890719 "

PDR ADOCK 05000245 Q PDC

. - _ - _ _ _ _ _ _ _ _ - . _ .

_ _ _ _ _ , _ _

_

_ . _ __ _ _ _

'

L . ...

2-

'.. .

.

TABLE OF CONTENTS PAGE

<

'1. 0 Persons Contacted.................................................... 1 i

2.0 Summary of Facility Activities....................................... l'

3.0 ' Previous Inspection Findings (93701/71707)........................... 2 3.1 (Closed) UNR 88-24-01, " Biennial Review Process Not Conducted for Several Operations Procedures".................. ......... 2 3.2 (Closed) UNR 89-02-01, " Items Identified During Standby Liquid Control System Walkdown"............. ........................ 2 3.3 -(Closed) UNR 89-08-02, " Secondary Containment Testing Under Degraded Conditions".......................................... 3 3.4 (Closed) UNR 89-08-05, "CUAJ-5 Weld Repair"..................... 4

. Facility Tours and Operational Status Reviews (71707/71710/93702). . . . 4 4.1 Safety System Operability............................... ..... . 5 4.2 Plant Incident Reports.......................................... 5 4.3 Engineered Safety Feature Walkdowns............................. 6 4.4 Unusual Event - High Reactor Coolant System Leakage............. 6 4.5 Reactor Scram on Low Main Condenser Vacuum........ ..........., 8 5.0 Contaminated Equipment Released Offsite (93702)....................... 9 6.0 Reactor Building Closed Cooling Water Containment Isolation Valve Modifications (37700/37828)................. .... ................. 10 7.0 Outage Performance (71707)........................................... 11 8.0 Crack Indications on Reactor Vessel Head Nozzle Welds (71707). . . . . . . . 12 9.0 Maintenance (62703)..................................... ............ 12

10.0 Surveillance (61726).................... . .......................... 12 11.0 Li ce n see Event Reports ( 92700) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 12.0 Licensee Self Assessment Capability (40500). ................ .... .. 17 13.0 Management Meetings (30703). .............. ... ............ ........ 18 i

_ _ --.---_ _ _ _------

, . . .

e :: v .

..-

DETAILS

<

1.0 Persons Contacted J. Stetz, Unit 1 Superintendent R. Palmieri, Operations Supervisor P. Prezkop, Instrumentation and Controls Supervisor N. Bergh, Maintenance Supervisor W. Vogel, Engineering Supervisor

..

M. Brennan, Health Physics Supervisor The inspectors also contacted other Operations, Instrumentation and Con-trol, Maintenance, Engineering, and Health Physics personne .0 Summary of Facility Activities Millstone I was in cold shutdown at the start of the inspection perio Major refueling activities completed during the period included:

--

The reactor water cleanup (RWCU) system isolation signal on high dry-well pressure was removed._ The lir.ensee added the signal during the last cycle upon finding that RWCU isolation during a small break loss of coolant accident (LOCA) was not assured because isolation valves 1-CV-2 and 3 had unqualified motor operators. Qualified motor-opera-tors were installed during the outage, so the additional isolation signal was'no longer neede The existing station and instrument. air compressors, aftercooler, and air dryer were removed and replaced with new equipmen The eleventh stage extraction steam piping, originally carbon steel, was replaced with chrome molybdenum (CrMo) steel to reduce wet steam erosion. Both carbon steel extraction steam inlet nozzles to the intermediate pressure feedwater heaters were replaced with carbon steel nozzles clad with CrM I

--

The ten year high pressure turbine inspection was satisfactorily com- i plete An operational leak check of the reactor pressure vessel was com-pleted (see. Detail 10.0).

--

A ermanent vibration monitoring system was installed on the recir-culation pumps for cracked pump / motor shaft detection. The system provides continuously trended running speed, shaft vibration ampli-tude, and phase informatio An acoustic leakage detection system was installed in primary con- '

tainment penetration X-16B, to monitor an uninspectable core spray l system wel )

l i

e i

,

<

, . :... .

,,

.

' '

l- ]

.'

.

!

l

L {,

l-

'

--

The licensee installed a woven mesh' screen on the "D" waterbox inlet to minimize mussel intrusion which has been linked to localized high velocity erosion of condenser tubes. The installation of additional ,

screens will depend on results obtained during this cycl _

--

Structural upgrades were performed on the anchorage at primary con-tainment penetration X-10A, located on the isolation condenser supply line, to ensure a safety factor of fou 'Startup for Cycle 13 began on May 25, with criticality achieved on May 26 at 1:36 a.m. Millstone 1 was at full power on May 29 at 1:30 a.m. In response to indications of "A" recirculation pump seal failure, the opera-tors reduced power to 75% at 2:22 p.m. By 4:55 p.m., the licensee con-firmed that reactor. coolant system leakage was in excess of Technical i Specification. limits and commenced a unit shutdown. Cold shutdown was achieved by 4:03 a.m. on.May 30. The recirculation seal was replaced, as

.was the topworks assembly for the "C" reactor pressure vessel safety re-lief valve which had ind1cated high tailpipe temperature prior to the shutdow Restart commenced on June 1 at 12:39 a.m. Criticality was achieved at 1: 48 a.m. on June 2. At 10:37 a.m., the operations shift allowed reactor pressure to exceed 600 psig without sufficient main condenser vacuum. The unit scrammed. Restart began at 1:05 p.m. Full power was attained on June 4 at 12:35 a; Full power operation continued for the rest of the period except for short power reductions for routine surveillanc .0 Status of Previous Inspection Findings 3.1 .(Closed) UNR 88-24-01, Biennial Review Not Conducted for Several Operations Procedures In November 1988, the inspector noted that procedures OP 303, OP 305, SP 611.1, and SP 613.1 had not been reviewed. The inspector verified that the licensee has since reviewed these procedures and reissued OP 303, OP 305, and.SP 611.1. This item is close .2 (Closed) UNR 89-02-01, Items Identified During Standby Liquid Control System Walkdown On February 13, 1989, the inspector identified a number of discre-pancies during a walkdown of the Standby Liquid Control (SLC) syste These are listed below with their associated licensee responses. All items were satisfactorily disp 3sitioned and this item is close The inspector noted sodium pentaborate crystal buildup in the interior of both SLC pump casings on the packing for 1-SLC- The licensee removed the buildup within days of the inspection and instituted daily wipedowns of areas prone to crystal build-up. The inspector has since observed considerably less buildu I i

i

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - -

- - _ _ _ ._-_ - __

.. . .

,

.. : .

.

--

The inspector noted that, for system valves 1-SL-27 through 30,

.the Architect Engineer numbers on OPS Form 304-1 did not match those given on piping and instrumentation drawing (P&ID) 25202-26022. These have been removed by the licensee, as they are not normally used by_0perations personnel. The accurate Millstone 1 valve identification numbers remai The inspector also noted that OPS Form 304-1 identified the nor-mal position for 1-IA-445 as locked open; P&ID 25202-26022 iden-tified the valve position as locked closed. The P&ID was in error and was correcte OP 304 Figure 10.1 accurately illustrated the air supply system for SLC tank level instrumentation, but the figure did not con-tain any valve numbers. Because detailed guidance exists within the text of OP 304, the licensee deleted the figure. The in-spector reviewed OP 304 and determined that an operator could purge the SLC tank level indicator without Figure 1 .3 (Closed) UNR 89-08-02, Secondary Containment Testing Under Degraded Conditions On May 2, at 8:30 a.m., the licensee removed the "A" standby gas

, treatment system (SGTS) from service for environmental equipment qualification upgrades. On May 3, the licensee discove-ed that a tagging error had left the "A" SGTS inlet and outlet dampers ope,,

setting up a recirculation / bypass flow path through the "A" SGTS train when the "B" SGTS train was placed in service. Preliminary licensee evaluations concluded that the degraded SGTS condition would have provided some negative pressure (0.17" WG) within the reactor building, but could not conclude that the 0.25" WG criterion of TS 4.7.C.1.a for secondary containment integrity would be satisfie Secondary containment integrity is required for irradiated fuel move-ment, which was conducted from May 2 at 8:30 a.m. until May 3 at 9:10 a.m., when the licensee suspended fuel movemen On May 17, the licensee conducted another secondary containment tightness test under the same degraded conditions caused by the tag-ging erro The inspector reviewed the surveillance results and noted that secondary containment pressures ranged from -0.27 WG to-0.34" WG with 725 scfm. Thus TS 4.7.C.I.a requirements for second-ary containment integrity (-0.25" WG with SGTS flow not in excess of 1000 scfm) were met in spite of the bypass flow lost through the idle SGTS trai The licensee reported the event on May 2 per 10 CFR 50.72 (b)(2)(iii).

Since subsequent testing proved that secondary containment operabil-ity was raintained, the licensee does not plan to submit an associ-ated licensee event report (LER) per 10 CFR 50.73 (a)(2)(v). TFe

_ _ _ _ _ _ _ _ . _ _ _ ._ _ _ _

. m .

l .

, ,

.

,

.

licensee provided this information to the NRC Region I Regional Ad-ministrator in a letter dated June 19, 1989 (MP-13223). The inspec-tor found no weaknesses in this approach and had no further questions on this event. This item is close l The licensee plans to revise surveillance procedures 646.6, "Func-tional Test When One Circuit of SGTS Is Inoperable" and 646.7, " Test of Operable SGTS Train," to require that these surveillance be per-formed prior to and immediately following an SGTS train tagout. The original practice was to demonstrate operability of the inservice SGTS train prior to tagging out the remaining train. This will mini-mize the possibility of lapses in SGTS operability due to tagging errors. The inspector had no further question .4 (Closed) UNR 89-08-05, CUAJ-5 Weld Repair The licensee determined that unacceptable crack indications were present on the upstream pipe to valve weld (CUAJ-5) for reactor water cleanup (RWCU) system inlet valve 1-CU-2. The licensee conducted a l weld overlay and submitted his repair plan to NRC:NRR for revie NRR approval, which was required prior to restart, was granted by letter dated May 22, 1989. This item is close i 4.0 Facility Tours and Operational Status Reviews j l

The inspector reviewed control indications for proper functioning, cor- ]i relation between channels, and conformance with Technical Specifications (TS). The 'nspector verified proper control room manning and discussed i alarm conditions in effect and alarms received with the operators and J found them to be cognizant of plant conditions and indications. The in- l spector observed prompt and appropriate operator response to offnormal and changing plant conditions. Shift turnovers were found to be thorough and in conformance with ACP 6.12, " Shift Relief Procedure." Operating logs 5 and Plant Incident Reports (PIRs) were reviewed for accuracy and adherence 1 to station procedures. During plant tours, posting, control, and the use l of personnel monitoring devices for radiation, contamination, and high  !

radiation areas were inspected. The inspectors also verified proper im- l plementation of selected aspects of the station security program, includ-

'

l ing site access controls, personnel searches, compensatory measures, ade- !

quacy of physical barriers, and guard force response to alarms and de- 1 graded conditions. No inadequacies were identifie Plant housekeeping controls were observed, including control of flammable and othsr hazardous materials. On June 1, members of the NRC Maintenance Program inspection. team identified housekeeping inadequacies in the Millstone 1 drywell, including loose tape, paper tags, and tiewraps. The resident inspector conducted a subsequent drywell tour and determined that no apparent safety hazard existed due to the small quantity of debri _______-_______-a . :. ..

-

. .

.

The licensee responded with a thorough cleaning effort and, on June 2, the resident inspector verified that the drywell cleanliness was satisfactory and acceptable for startu Prior to startup on May 25, the inspector verified that all conditions required ay Technical Specifications for plant criticality and startup were included in the prerequisites or text of Operations Procedures (ops)

201, " Approach to Criticality," OP 202, "P ant Heatup," and OP 203, " Plant Startup to Rated Power." The inspectors a'so verified licensee completion of the associated stcrtup checklists and ct.nducted independent verifica-tions of selected prerequisites. No inadequacies were identifie The inspectors conducted backshift inspect'ons of the control room and found all shift personnel to be alert and attentive to their dutie No unacceptable conditions were identified. The inspectors also addressed the following activitie .1 Safety System Operability During the refueling outags, the inspectors verified licensee com-pliance with appropriate technical specifications, including those for mode switch position, minimum neutron monitoring instrumentation, shutdown cooling, and spent fuel pool level and cooling. Prior to startup, standby emergency systems were inspected to determine system operability and readiness for automatic initiatio The following systems were reviewed: feedwater coolant injection, automatic pres-sure relief, low pressure coolant injection, emergency service water, core spray, standby gas treatment, and standby liquid control. The status of the control rod drive hydraulic control units, emergency

. diesel generator, gas turbine, station batteries, ard isolation con-denser was also inspected. The reviews considered (as applicable)

proper positioning of major flow path valves, operable normal a emergency power sources, proper operation of indications and con-trols, and proper cooling and lubricatio References used for the review included the Updated Final Safety Analysis Report, and system diagrams and operating procedures. The inspectors identified no in-adequacie .2 Plant Incident Reports Selected plant incident reports (PIRs) were reviewed to (i) determine the significance of the events, (ii) review the licensee's evalu-ation of the events, (iii) verify the licensee's response and cor-rective actions, and (iv) verify whether the licensee reported the events in accordance with applicable requirements. The following PIRs were reviewed; significant events are described elsewhere in this report as referenced: 1-88-19, 1-89-2, 1-89-8 (Detail 11.0),

1-89-18 (Detail 10.0), 1-89-23, 1-89-28, 1-89-36, 1-89-38 (Detail 5.0), 1-89-43, 1-89-44/46 (Detail 4.4),1-89-45 (ratail 4.5). No inadequacies were identified.

L-_ _ _-_ --- -_ -- .-

_ - - _ _ _ - - -

f .,

.. . .

• *

4 '4

. ..' ,

p ..

l 6 4.3- Engineered Safety Feature Walkdowns Prior to startup and after the licensee had declared the systems operable, inspectors " walked down" the below, listed systems using the

licensee's valve lineups. The valve lineups, which are documented in 1-the associated Operations procedures, were first reviewed for accu-racy by using. controlled piping and instrumentation diagrams (P& ids).

The inspectors verified that all accessible valves were in their

'

proper positions and that system tagging was consistent with the con-trolled P&ID. The inspectors identified no inadequacies in the physical condition of the valves, valve operators, supports, or in-

,

strumentation. Both local and control room indications were as ex-1 pected for system standby readiness and no conditions adverse to system operability were note Containment Spray, including the Emergency Service ' Water System

--

Low Pressure Coolant Injection System

--

. Isolation Condenser System

--

Standby Liquid Control System

--

Standby Gas Treatment System 4.4 Unusual' Event'- High Reactor Coolant System Leakage Startup from the refueling outage began on May 25, with reactor cri-ticality at 1:30 a.m. on May 26. During plant heatup on May 27, the operators noted intermittent seal failure indications for the "A" ..

recirculation pump inner seal. Th' licensee continued with restart testing and power escalation while making plans to replace the seal 'l and determine material availabilit Full power was reached at 1:30 a.m. on May 2 The following list presents a chronology of the seal failure even /29 2:10 p.m. Unider.tified reactor coolant system (RCS) lerkage rate ;

exceeds 2 b gpm. Control room indications show fail-

]j ure of the outer "A" recirculation pump seal as wel :22 p.m. Operators ieduce reactor power to 75%.

2:30 p.m. Unidentified RCS leakage rate is measured at 8.5 gp ,

3:50 p.m. Unidentified RCS leakage rate is measured at 9.0 gp . 4:05 p.m. An unusual Event is declared based on a plant shutdown J-per Technical Specifications, initiated by the con-firmed high RCS leakage rat ;

4:55 p.m. A controlled shutdown (50F/ hour cooldown rate)

commence l

= _ - _ -

__

,- . ..

-

. . .

( .*

L 7 9:00 p.m. Total (unidentified and identified) RCS leakage rate L reache; a maximum of 46 gpm, just below the Alert I

level of 50 gpm per the licensee's Emergency Classi .

fication Pla :00 p.m. All control rods are full i !

5/30 4:03 a.m. Cold shutdown conditions (less than 212F) are~ reached; unusual event is terminate The' leak rate decreased slightly as the RCS was-depressurized; the inner seal may have reseated slightly to help limit the leak rat In any case, leakage would have been limited to 60 gpm (at rated pressure) by the design of the recirculation pump seal breakdown bushin The normal feedwater system was used to makeup lost inventory. All  ;

emergency core cooling systems were available for use but were not

'

required. Leakage into the drywell raised bulk temperature from the normal temperature of 135F to a maximum of 142F. Heatup was limited by operation of the drywell recirculation coolers, which were used to restore normal temperatures. Plant operators vented the drywell- l through the standby gas treatment system periodically as necessary to '

keep pressure below 1.0 psig. The d vwell was kept inerted with ni-trogen. Drywel' radiation levtis did not increase significantly as a -

result of the leak, based on indications from containment monitors and a grab sample of the drywel' atmosphere (gross activity of 3.5 x 10-9 uC1/cc). Plant stack noble gas monitors showed no increase in ;j plant release rates above normal background levels. No equipment '

problems were noted as a result of the drywell condition (

The resident inspector responded to the plant at 9:40 p.m. to verify  ;

plant conditions and review licensee plans to stabilize the plant in cold shutdown and to isolate the pump. The recirculation seal was 3 replace Startup commenced oa June 1 at 12:39 The licensee J has not yet determined the pump seal failure cause but is working with the pump manufacturer, Byron Jackson, to this en In reviewing the event, the inspectors identified the following con-cerns:

--

OP1301, " Recirculation System," states that "If seal failure occurs, it is preferable to continue running the pump... Pump must not be isElated while it is still hot unless other serious problems develo If leakage ext.eeds TS limits, then reactor must be shutdown and cooled down, pump isolated, and seal changed out. Isolation valves should not be closed prior to cooldown or valve binding could occur."

The inspectors found this note to lack sufficient quantitative direc-  ;

tion as to when the recirculation pump should be isolated. The lic-ensee agreed and plans to change the procedure accordingl l

= _-__- -_--____-._- __ __ - _ _ _ _ - _ _ _ - - _ _ _ _ _ _ _ _ _ . _ _ _ _ _ - - -

__ .- .

'o a .

' '

/

4 ,.

--

The licensee's only available leakage detection method is through drywell- equipment sump pump dow This method is not very accurate and only provides intermittent readings. The licensee'should con-

. sider the addition of an improved RCS leakage detection metho The licensee made frequent contact with both:the resident inspector and the-NRC Operations Center throughout the event, but when total RCS leakage rate increased from approximately 9 gpm at 5:00 p.m. o a maximum of 46 gpm at 9:00 p.m., the Operations Center was not noti-fied of the increase. Althrugh the licensee was not required to re-port the change until a new Emergency Plan action level was reached (Alert at 50 gpm), the inspectors felt that the change was great enough to warrant an Operations Center notification. This would have allowed the NRC to more closely follow the event. This issue was dis-cussed with the licensee who agreed that future events would be treated with more sensitivity to reportin The above items will be considered by NRC in future assessments of licensee performanc .5 Reactor Scram on Low Main Condenser Vacuum Ouring startup on June 2 at 10:37 a.m., Millstone 1 scrammed from Intermediate Range Monitor (IRM) range 9 because the operators al-lowed reactor pressure to exceed 600 psig with main condenser vacuum less than 23" Hg. No engineered safety feature actuations occurred and the plant responded as designed. The inspectors responded to the control room and observed the licensee's cause determination process and post-trip review. The inspectors reviewed procedure OP 202,

" Plant Heatup," and found an explicit caution identifying the scram potentia While reviewing the sequence of events (SOE) printout, the inspector noted that reactor protection system (RPS) subchannel "B1" was not liste Subs >aquent licensee investigation determined that RPS sub-subchannel "81" did actuate, but the card feeding the associated SOE computer point (RPS 579).had failed. The card was replaced and ac- .)

tuation was successfully reteste J The inspectors also reviewed the t nular trend data report which 11-lustrated that, at 596.84 psig ai.a d.34" HgA, the reactor pressure-and main condenser vacuum setpoints for RPS actuation were conserva-tiv In addition, the Instrumentation and Controls (I&C) department conducted IC 408J, " Condenser Low Vacuum Scram Functioaal," and found the vacuum switch setpoints to be within tolerance.. The inspectors four i no inadequacies in the licensee's response to the scram.

,

..

_ .a_.-.- -

- _ -

,

I y . ,

,- . .

.

l l Upon completion of the startup checklists, the operators began con-trol red withdrawal.at 1:05 p.m.; full power was reached by 12:35 I

a.m..on June The inspector attended the Plant Operations Review Committee (PORC)

meeting in which the-licensee reviewed the associated licensee event report (LER). The discussion was thorough and went beyond simple personnel error. The PORC addressed the weaknescas in the operating shift configuration present at the time of the scram: the shift was not a usual operating shift group and the members were perhaps less familiar with each other; the Supervising Control Operator (SCO),

although an SRO license holder, was newly upgraded from a Control Operator (C0/RO) position; and the Shift Supervisor was in the plant at the time of the scram. In response, the licensee committed to re-vising the associated Operations instructions to include additional cautions and attention to thift composition during changing plant conditions. The inspector will review the revised ops incident to routine inspectio .0 Contaminated Equipment Released Offsite On May 11, Millstone 1 released a hydrolysing rig for transportation to its owner, Westinghouse Radiological Services (WRS). The rig arrived at WRS, located in Moorestown, NJ, on May 12. On May 15, WRS notifieci the licensee that receipt surveys indicated removable exterior contamination at a maximum of 26,375 dpm/100 cm2 on the trailer deck. The rig has no cover and was transported with exterior surfaces exposed. Federal trans-portation regulations in 49 CFR 173.443 limit the maximum contamination level for free release at 22,000 dpm/100 cm2. %ximum contact dose rates (beta gamma) were 0.4 mrem /hr; no alpha radiation was detected. A maximum contamination level of 225,000 dpm/100 cm2 was measured inside the hydro-lasing water tan Millstone 1 received the rig directly from Indian Point 2 (IP2) and did not conduct a receipt radiation survey. As the rig was locr ed outside of the radiological control area (RCA), no release survey was conducte IP-2 stated that they conducted an (undocumented) release survey and found no contamination. Isotopic analyses conducted by IP-2 indicated very low activity level The rig was used in decontaminating the Millstone 1 reactor cavity. Iso-topic analyses conducted by Millstone 1 indicated a substantial amount of Zn-65, which the licensee uses to reduce Cobalt-00 deposition in recir- ;

culatioh' piping and lower drywell radiation dose rates. This finding traces the contamination source to Millstone 1 reactor cavity water, which appears to have been siphoned to the rig. Nearly 100 feet of elevation difference existed between the rig (14'6") and the refueling floor (108').

,

i . . .

,

.

'* .

.

The licensee reported the event via the ENS per 10 CFR 50.72 (b)(2)(vi) on May 16 at-11:15 a.m...and notified the State of Connecticut. The licensee also made an INP0 NETWORK entry to alert other licensees to the possibil-ity of such an unanticipated contamination occurrence. As an interim measure, the licensee positioned a Health Physics technician at the Mill-stone Vehicle Access Point to survey all vehicles leaving the Protected Area. The licensee is developing improvements to the radiological control program as part of their long term corrective action An NRC Regional Radiation Protection Specialist responded to the site on May 17 to review the event; findings are documented in NRC inspection re-i port 40-245/89-13. An enforcement conference was conducted in the NRC Region I office on June 2 .0 Reactor Building Closed Cooling Water (RBCCW) System Containment Isolation Valve Modification The licensee determined that a break in the RBCCW system caused by a high energy pipe break (HEPB) could result in a breach of primary containment integrity because RBCCW was not equipped with qualified containment iso-

-lation valves per 10 CFR 50 Appendices A and J. 1he licensee developed a Justi fication for Continued Operation for the time period between dis-covery ci the deficiencies and their correction during the 1989 outag This event was first discussed in NRC inspection report 50-245/89-04. De-tail RBCCW supply penetration X-23 had a check valve inside containment; return penetration X-24 had a remote manual isolation valve outside containmen The licensee installed four motor-operated containment isolation valves with four 6-inch manual stop valves for local leak rate testing (LLRT) on the RBCCW lines (6"-RCW8 and 6"-RCW20) which enter the drywell at pene-trations X-23 and'X-2 In addition, four 3/4" test connections, with four 3/4" globe valves, were installed for local leak rate testin The inspector reviewed plant design change record (PDCR) 1-17-89, Revision 1, "RBCCW Containment Isolation Valve Installation." The inspector found the plant design change to be properly developed, reviewed, verified, and controlled adequately by the responsible organizations and consistent with Station Procedure ACP-QA-3.1 The inspector reviewed the licensee's safety evaluations (under Project Assignment PA 80-18]) contained within the PDCR package and verified that the design changes were evaluated and analyzed in conformance with the requireinents of 10 CFR 50.59 and licensee implementing procedure ACP-QA-3.08, Revision 4, " Safety Evaluations." This particular RBCCW desisc change involved numerous safety evaluations by various disciplines in-ciuding Generation Instrumentation and Control Engineering and General Electric Engineering. The inspector found the safety evaluations com- !

prehensive and consistent with licensee station nrocedure and NRC regu-latory requirements.

- _ - - _

_ - _ _ _ _

. .

.

.-

The inspector observed during a walkdown of the Rf;CCW modification that one of the 6" manual gate valves (1-RC-208) had already been installed in the RBCCW return line (6"-RCW20) to the RBCCW pump The addition of this valve and existing manual valve 1-RC-137 permitted the RBCCW system to operate and cool the reactor building systems while the other containment isolation valves were being installe The installation of the RBCCW containment isolation valves was controlled per Specification SP-ME431, Revision 3. The inspector observed the con-tractors, who were supervised by NUSCo Betterment Construction, performing pipe cutting activities on the 6" RBCCW8 supply line. The contractors were preparing to install the shop fabricated spool pieces which included the motor-operated valves and manual gate valves. The modification work was conducted to ASME Boiler and Pressure. Vessel Code,Section XI, " Rules for In-Service Inspection of Nuclear P ser Plant Components," 1980 Edition through 1980 Winter Addend The inspector concluded that the observed modification work was properly implemented and supervise .0 Outage Performance The licensee maintained Operations as the focal point during the outage and the department was heavily involved in planning and controlling re-fueling outage activities. An efficient outage organization comprised of an experienced shift supervisor and a team of operators provided plant configuration contro Unit staff meetings were held twice per day on weekdays; weekend meetings were also held. These meetings offered accurate updates, kept unit per-sonnel aware of plant status, and promoted effective communications be-tween unit departments. Management provided clear and frequent direction on unit goals and gave timely feedback to unit personnel. The outage scheduling group provided a positive contribution through detailed prirted schedules which were maintained on a computer base and served to further assure personnel awarenes Cooperation between departments was exemp-lary. Continuous management representative coverage, a position filled by department heads or other management personnel, was effective in timely problem resolutio Health Physics staffing was increased and an effective outage organization was established. The inspectors routinely reviewed radiological controls and found the field technicians to be knowledgeable and dedicate Although the outage was extended by nine days because of delays in the Gas Turbine Generator (GTG) governor replacement project, no comprises in safety for the sake of maintaining the schedule were observed. The in-spectors concluded that the outage was well planned and executed.

l l

l L__ _ __

-- _--- _ ---- __ _ _ _ _

,

,

. ~ .

'

.

-e f

,

'

12 i i

I 8.0 Crack Indications on Reactor Vessel Head Nozzle Welds i On April 28, the licensee identified micro /issure crack indications on the inner diameter of the reactor pressure vessel (RPV) head spray and level instrumentation nozzle welds. The licensee used ultrasonic testing (UT)

and liquid penetrant testing methods. Both nozzles are carbon steel with stainlesr, steel cladding; the welds are ASME Section XI Category B-D weldment The crack indications were reduced in size after grinding. Subsequent j licensee measurements were evaluated against the acceptance criteria of  ;

Table IWB3510-1 of ASME Section XI,1980 edition including the Winter i addenda. The licensee determined that the indications were acceptable and typical of base / clad metal interfaces. Although tha licensee reported.the event per 10 CFR 50.72 (b)(2)(i) on April 28, a corresponding licensee event report per 10 CFR 50.73 (a)(2)(ii) will not be submitted because of  ;

the revised findings. An NRC Region I specialist inspector reviewed the i findings during a May-1-5 inspection (50-245/89-13) and found the licen-see's actions to be appropriate. The inspector had no further question .0 tiaintenance The inspector observed and reviewed selected aspects of the following safety-related maintenance, including procedural adherence, obtaining re-quirc.a administrative approvals and tagouts prior to work initiation, proper quality assurance and personnel protection measures, and verifi-cation of proper system restoration and retest prior to return to servic No inadequacies were identifie Emerpency Diesel Generator Engine 5.00 Hour Inspection per MP 743.2, ,

on May 1 '

--

Replacement of the Diesel Generator Lower Drive Thrust Bearing on May 2 The inspector observed work in progress per automated work order (AWO) 89-05702, initiated when maintenance personnel noted bearing wear c'uring the 500 hour0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br /> inspection listed above. The lower thrust bearing acts on the vertical drive assembly which transfers 30*4 of '

the engine work from the upper crankshaft to the lower crankshaft. A j new thrust bearing was installed. Inspector review noted that the  !

work was done by experienced licensee personnel per a detailed work i list with designated Quality "ontrol (QC) inspection points. No in- )

adequacies were identifie j

_<. : )

--

Replacement of the "C" Reactor Vessel Safety Relief Valve (SRV) Top-works Assembly on A:ne .0 Surveillance The inspector observed and reviewed selected aspects of the following sur-veillances for conduct in accordance with current approved procedures, for test result compliance with administrative requirements and technical j l

l 1 .. ._ -- ._ - ____---_ _ _

. . .

'

. : .

.

? 13 specifications, and for deficiency correction in accordance with admini-strative requirements. The inspector noted that the surveillance teams displayed thorough coordination and adherence to procedures. No inade-quacies were identifie SP 4118, " Main Steam Line High Flow Functional Test" on May 3 SP 668,2, " Gas Turbine Emergency Start Fast Test" on May 9 and 1 IC 406Q, " Reactor Building Exhaust Duct Radiation Monitor Test" on May 1 IC 406M, " Service Water Effluent Radiation Monitor Calibration" on  !

May 1 SP 412K, " Low Pressure Coolant Injection / Containment Cooling System Logic Test" on May 1 SP 624.1, " Secondary Containment Tightness Test" on May 1 SP 681, " Operational Leak Test of Reactor Vessel" on May 20

--

SP 617.1, " Loss of Normal Power Relays Test" on May 2 SP 628.1, " Integrated Sin.ulated Automatic Actuation of FWCI, Core Spray, LPCI, Diesel, an6 Gas Turbine Generators" on May 2 IC 411A, " Main Steam Line High Flow Functional Test" on May 3 SP 412K, " Low Pressure Coolant Injection / Containment Cooling System Log i c Te s t'_'_

The Instrumentation and Controls (I&C) department revised SP 412K during Cycle 12 to include a new LPCI logic test switch box. The box reduces repetitive lifting and placing of jumpers used to simulate level and pres-sure switch actuation from the fiel The inspectors noted effective color coding on the test box and on the LPCI/ Containment Cooling system test. Jacks. The inspector observed that, in one case, the quick initi-ation of a test box switch did .not allow enough time for a particular re-lay to reset, and inaccurately simulated a pressure change which would normally occur over a longer period of time. This error was corrected via a nonintent change by directing the operator to pause before throwing the switch. No other test discrepancies occurred. The inspectors noted ap-propriate management, engineering, and technician presence and identified no inadequacie SP 681, " Operational Leak Test of Reactor Vessel" On May 20, the inspector reviewed the reactor operational leak test pro-cedure and test results. The test was performed to verify reactor leak tightness was assured prior to operation following the outage. No pres-sure boundary leakage was identified; minor leakage was noted in valve packing', control rod drive gasketed flanges and assorted valve flanges. A minor leak was also noted in the seal weld installed during the outage on the "B" recirculation pump suction valve (1-RR- B).

r- -

- ~' -

- -- --

. .

..

,

.- .

,

,

The Jnspector attended a meeting between plant staff and management'on May 20 to review and prioritize the inspection findings. The inspector iden- ..!

tified'no discrepancies in the licensee's disposition of the work list., '{

The 1-RR-1B seal weld was among the items repaire No inadequacies were identifie SP 628.1, " Integrated Siniulated Automatic Actuation of FWCI, Core Spray, LPCI, Diesel, and Gas Turbine Generators" The inspectors observed the conduct of the integrated loss of normal i power / emergency core cooling system (LNP/ECCS) actuation test on May 2 '

The test was initiated at 2:30 p.m. by simulating a loss of normal power i coincident with a high drywell pressure condition to verify proper re- 'l sponse of plant emergency systems. All plant systems responded by design with the LOCI loop selection logi. appropriately selecting the "B" re-circulation, loop by default, since a break indication was not simulate NRC inspection included a review of test procedure SP 628.1; the test methodology was found acceptable to perform a satisfactory test of the ECCS and electrical system logic and to confirm the satisfactory restora-tion of plant systems disturbed during the outage. NRC inspe': tion also verified that: test prerequisite conditions were met; test data required by procedure was collected; and test acceptance critera were met based on independent inspector observations of the LPCI, core spray, reactor pro-tection, emergency diesel generator and gas turbine generator system re-sponse The inspectors observed good protocol during performance of the tes . Experienced operators were used to monitor plant performance and collect test data. There was good supervision by the test director (Duty Shift Supervisor) to assure proper coordination by test personnel at various control room and plant locations. Test personnel communicated effectively during the tes Restoration actions were timely and proper to stabilize plant conditions after test data collectio The inspector verified that the multi-channel event recordar was supplied by vital AC as required per the test prerequisites, but noted that the recorder itself was not a qualified device. This was confirmed by the licensee, who ran a calibration check after performing the surveillanc {'

'It was successful and confirmed the validity of the test dat The in-spector, commented that the licensee should consider adding a 60 hertz tim-ing signai to the parameters recorded duiing the test to allow better con-firmation of load sequencing times. The licensee acknowledged the commen The inspector also noted that, while the test acceptance criteria included Gas Turbine and Diesel Generator start times, ECCS valve responses, and LPCI loop selection logic response, the diesel generator loading sequence was not verified. The appropriate information is gathered with the multi-channel recorder, and the licensee is evaluating its addition to the test acceptance criteri The inspector had no further questions, se r sh m ___ _m__ __ _ . _ _ . _ _ _ _ _ _ . _ _ _ . . _ _ _ _ _ _ _ _ . _

-__- _ _

, w . . *

,

i .

q

, 11.0 Licensee Even' *epo. s The following Licensee Event Reports (LERs) were reviewed to assess LER accuracy, the adequacy of corrective actions, compliance with 10 CFR re-porting requirements and to determine if there were generic implications or if- further information was required. No inadequacies were note LER 89-07, "Feedwater Coolant Injection (FWCI) System Testing

~

Inadequacy?

On February 2, the licensee concluded that Technical Specification 4.5.c.1.b had not been met in full. The finding was identified by a lic-

~

ensee-sponsored Safety Systam Functional Inspection (SSFI). TS 4.5.c. requires that a simulated saamatic test of "FWCI subsystems" be conducted during each refueling outage. The licensee's integrated Loss of Normal Power / Emergency Core Cooling Systems test (SP 628.1, " Integrated Simulated Automatic Actuation of FWCI, Core Spray, LPCI, Diese' and Gas Turbine") is conducted with the FWCI train selector switch selected to either the "A" or "B" FWCI train. Consequently, part of the selection circuitry for the unselected train was not tested. This could affect the system's automatic start capability; it would still have been available for manual start Since the feedwater system is continuously in service during power opera-tion, there is sorne inherent assurance that the system would have per-formed if require Upon discovery, the licensee selected the FWCI train which had been tested during the 1987 outage. Opera *. ions hung a caution tag on the FWCI selec-tor switch stating that viv the tested train could be selected. This did not require entrance inc. any TS action statement and FWCI operability per TS was maintaine The inspector noted however, that the tag was hung on December 5, 1988, and that the LER reported a February 2, 1989 identifi-cation date for deportabilit It appears in this case that the report-ability determination was delayed. That was evaluated as a performance weakness but not as a violation of NRC requirement The licensee also developed a new surveillance procedure to functionally a test the selection circuitry omitted by SP 628.1; the test was satisfac-torily completed on April 7. The inspector had no further questions on the even LER 89-04, " Standby Gas Treatment Initiation Due to Reactor Building Exhaust Hig'o Radiation" l

l On March 28 at 6:10 p.m. , the standby gas treatment system (SGTS) initi-ated and normal reactor building ve.itilation isolated in response to a high radiation signal from reactor building ventilation exhaust monitor 33/2. Health Physics performed a general survey and no abnormal dose rates were detected. Channel 33/2 was bypassed, SGTS was secured, and normal ventilation was restore _ _ - _ - _ _ _ _ _ _ _ _

f - ~ Lf o f

y .

,

,n'." .

p 16

, The licensee-determined that the Geiger Muller (GM) tube installed in channel 33/' might not be compatible with the circuit design. In June 1980, Generc Zlectric issued Service Information Letter (SIL) 327 which ident1*ied the possible incompatibility, and recommended GM tube testing i

,. prior to installation. The licensee failed to incorporate the SIL in-formation, but has since revised the procedure accordingly. The GM tube was removed and replaced with one having proven compatibility. In addi-tion, I&C modified their purchasing records to prevent further procurement of potentially incompatible GM tubes. The inspector had to further ques-tion LER 89-10, " Failure to Complete Surveillance in Reauired Time" During the refueling outage on April 23, the licensee discovered that the

' monthly surveillance for the reactor building ventilation exhaust, re-fueling floor, and steam tunnel ventilation exhaust radiation monitors were not completed by their April 13 due date. The surveillance were satisfactorily completed on April 2 The licensee had mistakenly deter-mined that the surveillance could be deferred because of the outag Although failure to perform the surveillar.e ' represents a viulation of Technical Specification requirements, no violation will be issued in this case because: the event was licensee-identified, it had low safety sig-

'

'nificance as the radiation monitors were proven operable on April 22, and it was reported as required. Also, it could not reasonably have been pre-vented by the corrective actions instituted for a previous violation, as only one other surveillance (of hundreds) was missed during the current SALP (Systematic Assessmer.t of Licensee Performance) cycle, which started on January 1, 1988. The earlier missed surveillance was a missed Inser-vice Testing (IST) surveillance, which is the responsibility of the Engi-neering department and is unrelated to the I&C surveillance program. To prevent recurrence in the present case, the I&C department will develop a new procedure to ensure compliance with the surveillance. schedule. The inspector will review the revised procedure upon issuance (UNR 89-12-01).

The events assc~iated with the following LERs were covered in previous NRC inspection reports, as reference The inspector found the LERs to be accurate and contain sufficient detail. A minor discrepancy was noted in that, while LER 89-13 contained adequate supporting information, no dis-crete statement addressing the event's safety significance was given as listed in NRC NUREG 1022, " Licensee Event Report System." The inspector reviewed the LERs issued since January 1988, and noted that a concise safety a.ssessment was also absent from LER 89-06, which was reviewed in IR 50-245/89-08. The inspector discussed this finding with the licensee, who stated that the engineers do utilize NUREG 1022 in preparing LERs. The inspector had no further comment LER 89-03, "Gesign Deficiency in RBCCW Piping" (89-04, Detail 6.0)

___ --- _ __

_ - - _ _ _ _ _ _ -

') .

.,-

. ,

,

~

17 \

1

LER 89-12, "LNP While Switching Reserve Station Services Transformer" (89-08, Detail 4.3)

LER 89-13, " Core Spray System Orifice Plate Flanges" (89-08, Detail 4.1) i 12.0 Licensee Self Asse3sment Capability Millstone I has a range of self-assessment programs. Self-initiated ef-forts include the Safety System Functional Inspection (SSFI) and the Human Performance Evaluation System (HPES). Programs required by Technical Specifications include the Plant Operations Review Committee (PORC) and the Nuclear Review Board (NRB).

The inspector attended many PORC meetings, both scheduled and those held on a reactive basis, generally in response to plant events. requiring special procedure or post-scram reviews. In all cases observed, PORC re-quirements per TS were met. The dis.cussions were thorough and conserva-tive, with a. appropriate safety regard. The discussions were open and opposing views were encouraged. The PORC members were well experienced 9 and knowledgeable; the majority hold NRC Senior Reactor Operator licenses on Millstone 1. The inspector had one minor suggestion for improvement of PORC performance: the ine.pector observed that a significant amount of PORC time is spent in reviewing routine procedure revisions, such as revised formats and typographical errors. The administrative control procedure (ACP) allows the use of PORC subcommittees to review this level of changes. It appears that Millstone 1 management time would be better spent if these reviews were deleted from the PORC agenda, as the potential exists for diluting committee attention to more sa'ety significant issue The inspector discussed this issue with the Unit ., superintendent who said that he would consider the suggestion but is reluctant to decrease the PORC review scop The inspector attended a number of NRB meetings and observed that the TS requirements for quorum were met, and the meetings were consistently well planned and attended. As the NRB generally meets on a monthly basis, the meeting frenuency exceeds the TS requirement for semiannual meetings. The members were sufficiently critical of Millstone 1, and the variation in j member backgrounds allowed indepth reviews from a variety of approache ;

The inspector noted that NRB nembers received comprehensive briefing pack- l ages, but found that they received their packages only a few days prior to the meeting. The inspector expressed this concern to the licensee who stated that it had been a long standing issue. The NRB secretary now establishes a cutoff date to allow the members to receive their packages approximately two weeks prior to the meetin '

The licensee conducted a Safety System Functional Inspection (SSFI) of the Feedwater Coolant Injection (FWCI) system; the effort was modeled after the NRC's SSFIs. The multidisciplined inspection team was -comprised of 3 ten independent licensee employees with varied backgrounds and extensive experience. The inspection lasted eight weeks and evaluated several sys-tem aspects, including operations, engineering and design, surveillance

!

_

.. .- ,

,

e t

..

testing, and maintenance. The SSFI. team and a Millstone 1 representative held daily meetings to review and discuss findings. The SSFI team priori-tized the findings asithey were identified. Millstone I was very prompt in addressing the ninety-six (96) findings; all were resolved to the satisfaction of the SSFI team within one month of the inspection's con-clusion. The SSFI concluded that the system would function in both normal and emergency mode The inspector reviewed the licensee's implementation of the Human Per-formance Evaluation System (HPES). The HPES coordinator is sufficiently experienced to conduct meaningful reviews of work activities, has high visibility in the plant, and cctively seeks HPES review requests from all levels of plant personnel. The inspector reviewed several HPES reports and found them to be thorough and technically sound. In addition'to con-ducting HPES reviews, the coordinator issues an annual report summarizing cause data for the Millstone human error events. Millstone 1 management provides good interaction and feedback. The inspector concluded that HPES prov' ides a po:itive safety contribution to Millstone The inspector observed that the licensee has several effective self as-sessment progra,ns in ' place and concluded that the licensee has the ability to conduct critical self' reviews. The inspector found no inadequacies in the licensee's self-assessment progra .0 Management Meetings Deriodic meetings were held with station management to discuss inspection findings during the period. A suxnary of findings was also discussed a'.

the conclusion of the inspection. No proprietary information was covered during the inspection. The inspectors provided no written material to the license g i

)