IR 05000423/1990001

Safety Insp Rept 50-423/90-01 on 900105-0205.Unresolved Items Noted.Major Areas Inspected:Plant Operations,Maint & Surveillance,Engineering & Technical Support,Radiological Controls & Safety Assessment & Quality Verification

ML20033F524
Person / Time
Site:	Millstone
Issue date:	03/08/1990
From:	Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20033F523	List: IR 05000423/1990001 ML20033F522
References
50-423-90-01, 50-423-90-1, NUDOCS 9003210333
Download: ML20033F524 (23)

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U.S. NUCLEAR REGULATORY' COMMISSION

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REGION I

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Report No.:

50-423/90-01

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. Docket No.:

50-423~

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^ License No.

NPF-49

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Licensee:

Northeast Nuclear Energy Company a

P.O. Box 270 h

Hartford, Connecticut 06141-0270

Facility Name: Millstone Nuclear Power Station,. Unit 3 t

. Inspection'at: Waterford, Connecticut

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LInspection Conducted:

January 5, 1990 through February 5, 1990 Reporting Inspector: Kenneth S. Kolaczyk, Resident Inspector, M111 stone 3 L

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LInspectors:

William J. Raymond,. Senior Resident Inspector, Millstone Kenneth S. Kolaczyk, Resident Inspector, Millstone 3'

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William Oliveira, Reactor Engineer,.0perational Programs Section, Division of Reactor Safety-Donald L. Caphton, Senior Reactor Engineer, Operational Programs Section, Division of Reactor Safety

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Approved by:

Md/ e[

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?/Pbc Donald R. Haverkamp, Chief Date

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Reactor Projects Section 4A Division of Reactor Projects Inspection Summary:

Inspection on January 5,1990 - February 5,1990 (Inspection Report No. 50-423/90-01)

Areas Inspected:

Routine safety inspection by resident and regional inspectors of plant operations; radiological controls; maintenance and surveillance;

. engineering'and technical support, and safety assessment and quality verification.

9003210333 900309

{DR ADOCK 05000423 PDC

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Results:

1.

General Conclusions on Adequacy, Strength or Weakness in Licensee Programs Operations:

Performance of operators during off-normal conditions was generally good with one inconsistency noted.

During a loss of feedwater, downpower' transients and plant restarts, operators responded appropriately

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(Section 3.1.1); however, when a partial containtaent depressurization actuation vi;arred, operator diagocsis of the event was slow.

(Section

3.3)- Crew perfermance will be closely monitored during future resident inspections.

Radiological Controls: The health physics department has instituted a new program to reduce the amount of contaminated areas at Millstone Unit 3.

Initial results are guod with a properly focused program. (Section 4.1)

Surveillance: Personnel error caused a surveillance to be missed for the calculation.of average. disintegration energy (E-Bar) which resulted in the necessity to grant enforcement discretion to allow a plant startup. This was caused by conflicting interpretations of the surveillance interval by plant personnel, and appears to be an isolated occurrence as surveillances are routinely performed in a timely manner. (Section 5.2.2)

Engineering / Technical Support: The engineering and instrumentation and controls departments thoroughly researched the January 9 containment depressurization actuation event and found the root cause. Additional engineering support may be required to correct weaknesses identified in-the main feedwater system.

2.

Unresolved Items Three items were closed and one item was opened during the report period.

The closed items concerned the completion of licensee actions regarding upgrade of the Safety Parameter Display System (SPDS) as required in licensee commitment 2C.(12) (87-30-01), redirection of feedwater heater relief valve discharge piping (87-21-03), and upgrading existing requirements for proper preliminary design change request documentation (86-26-01). (Section 6.1) The open item (90-01-01) documents NRC followup of licensee actions to ensure that the quality services department monitors the performance of retests. (Section 7.3)

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L TABLE OF CONTENTS Page'

'1.0 Persons Contacted...........................................

- 2. 0 Summa ry of Fac i l i ty Acti vi ti e s...............................

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3.0 Plant Operations (IP 71707/93702)*...........................

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Control Room Observations..............................

3.1.1~ Manual Reactor Trip Initiated...................

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3.2 Inadvertent Partial Containment Depressurization Actuation..............................................

3.3 Operator Response to Containment Depressurization

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Actuation Transient....................................

4 3.4. Plant Tours............................................

3 3.5 Review of Plant Incident Reports.......................

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4.0 Radiological Controls (IP 71707)............................

m3 4.1 Contamination Control Initiatives......................

5.0 Maintenance / Surveillance (IP 62703/61726/92701).............

5.1 Observation of Maintenance Activities..................

5.1.1 Review of Maintenance Activity Which Caused Containment Depressurization Actuation.................

5.1'.2 Followup to Maintenance Team Inspection (MTI)

Report Items 50-423/89-80..............................

5.2 Observation of Surveillance Activities.................

5.2.1 Verification of Equipment-0perability Following Containment Depressurization Actuation.......

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5.2.2 Enforcement Discretion Granted..................

5.2.3 Technical Specification Improvements Identified.

6.0 Engineering / Technical Support (IP 37701/93702/92701)........

6.1 Previously Identified Items............................

6.1.1 (Closed) Unresolved Item 87-30-01 Safety Parameter Di splay System License Commitment............

6.1.2 (Closed) Followup Item 87-21-03 Actuation of

.Feedwater Heater Relief Valve Discharge Piping.................................................

6.1.3 (Closed)' Unresolved Item 86-26-01 Inadequate Plant Design Change Request Documentation..............

6.1.4 (0 pen) Unresolved Item 50-423/89-15-01 Implementation of NRC Guidance for the ATWS Equipment Operabi,lity and Survei11ance...........................

6.1.5 (0 pen) Unresolved Item 50-423/89-15-02 Untimely Response to Licensee Quality Assurance Audit Findings.........................................

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Page 7.0 Safety' Assessment / Quality Verification (IP 40500/90712/92700)......................................

7.1 Committee Activities...................................

7.2 Li cen see Event Report Review...........................

7.3 Coverage of Maintenance Retests by Quality Control Personne1..............................

8.0 ManagementMeetings(IP30703)..............................

' Figure 1: 3RSS.MOV20 Test. Circuit Schematic

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• The NRC inspection manual inspection procedure (IP) or temporary instruction (TI) that was used as inspection guidance is listed for each applicable report section.

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DETAILS 1.0 Persons Contacted

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Interviews and discussions were conducted with Northeast Nuclear Energy l

Company (NNECo or the licensee) staff and management during the report

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period to obtain information pertinent to the areas inspected.

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Inspection findings were discussed periodically with the supervisory and i

management personnel identified below.

S. Scace, Nuclear Station Director C. Clement, Unit'3 Nuclear Unit Director

• M. Gentry, Operations Manager

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R. Rothgeb, Maintenance Manager j

J. Harris, Engineering Manager

D. McDaniel, Reactor Engineer

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R. Sachatello, Health Physics Manager L

M. Pearson, Operations Assistant B. Enoch, Manager, Instrument and Controls P. Atkinson, Maintenance Engineer

• Attendee at post-inspection exit meeting on March 1, 1990.

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.2.0 Summary of Facility Activities j

i On January 9, while performing maintenance on a motor-driven recirculation j

spray system valve 3RSS*MOV200, a maintenance error caused a partial CDA

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actuation to occur. Operators appropriately stabilized plant conditions, however, full recognition of the event was slow.

The inspector determined f

that crew performance during this event may be an anomaly based on

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observation of their performance during other transients. This area will

.1 continue to be observed during routine resident inspections to determine

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if an actual weakness exists.

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During the report period problems encountered with the feedwater system

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necessitated taking the following actions:

manually tripping the reactor

on January 18 when the 'B' turbine driven feedwater pump coupling failed,

and reducing power to 58% on January 26 to repair a cracked weld on a drain valve for the motor driven feedwater pump recirculation line. Plant startup from the January 18 trip was delayed when the licensee discovered that the motor / turbine alignment on the ' A' turbine driven feedwater pump was incorrect necessitating a realignment of the feedwater pump.

Additionally, while conducting a pre-startup review of technical

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specifications, the licensee discovered that the technical specification surveillance sample for determining average disintegration energy (E-Bar)

had not been met. After completing a review of reactor coolant chemistry i

conditions, the NRC staff granted enforcement discretion and allowed the licensee to startup the facility without meeting the technical

specification requirement for sampling. Mode I was reached on January 20

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L and the turbine was synchronized to the grid later in the day. The i

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reactor coolant was sampled and the plant reached 100% of rated thermal power on January 22. Sample results obtained on January 26 confirmed that

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reactor coolant chemistry was acceptable.

During the ensuing week, a defective weld was discovered on the motor-driven feedwater pump.

Accordingly, the licensee reduced power below 60%, removed the motor-driven feedwater pump from service, and repaired _the defective weld.

Repair of the weld was completed on January 28 and a power ascension began; full power was reached on January 29.

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The inspection activities during this report period included 131 hours0.00152 days <br />0.0364 hours <br />2.166005e-4 weeks <br />4.98455e-5 months <br /> of inspection during normal activity working hours.

In addition, the review of plant operations was routinely conducted during periods of backshifts (evening shifts) and deep backshifts (weekends and midnight shifts).

Inspection coverage was provided for 46 hours5.324074e-4 days <br />0.0128 hours <br />7.60582e-5 weeks <br />1.7503e-5 months <br /> during backshifts and 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> during deep backshifts.

3.0 Plant Operations 3.1 Control Room Observations 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 technical specifications and plant operating procedures. Actions taken to meet technical specification requirements when equipment was inoperable were reviewed to verify the limiting conditions.for operations were met.

Plant logs and control room indicators were i

reviewed to identify changes in plant operational status since the last review and to verify the changes in the status of plant equipment was properly communicated in the logs and records.

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

Alarm conditions in effect were reviewed with control room oper.ators to verify proper response to off-normal conditions and to verity operators were knowledgeable of plant-status. Trainees who were manipulating reactor controls were under instruction by licensed operators. Operators were found to be cognizant of control room indications and plant status during normal-working hours and backshift observations. Control. room manning and shift staffing were reviewed and compared to technical specification requirements. No inadequacies were identified.

3.1.1 Manual Reactor Trip Initiated On January 18, 1990 while the reactor was at 100% of rated thermal power, operators manually tripped the reactor in anticipation of an automatic trip on low steam generator level.

The reduced steam generator level was caused by a loss of

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feedwater flow which occurred when the coupling that joins the

'B' feedwater turbine to the pump failed.

The inspector was in the control room during the transient and determined that operators responded appropriately to the loss of feedwater.- Initial operator diagnosis of the event was hampered by the type of failure that occurred.- Specifically, when the coupling failed,-the feedwater turbine did not overspeed and trip; therefore, when operators scanned the. main control board in. response to annunciators which alerted them to a decrease in steam generator level, the feedwater system indication was essentially normal. Therefore, it was not readily apparent what was causing the reduction in feedwater flow. After first verifying that the cause was not a more obvious failure such as a shut feedwater regulating valve or tripped condensate pump, a third condensate and feedwater pump was started 40 and 51 seconds into the transient, respectively. However, sufficient feedwater flow was not delivered to the generators quickly enough to restore level.

'The-inspector reviewed the sequence of events printout and verified that the plant responded to the event as designed. The coupling that failed was a grease packed, 3 1/2 inch, spool-type design manufactured by Koppers,;which utilized a spline and drum arrangement on either end of the coupling shaft to connect the turbine and pump.

The failed coupling component was the outer drum which connects the coupling shaft to the turbine. When the coupling failed, the drum fractured into several pieces which punctured a protective shield installed around the coupling and damaged electrical conduit which supplied power to the feed pump jacking gear.

Licensee investigation determined that the coupling failed when the preload was lost on the bolts which connect the coupling drum to the turbine. The loss of preload caused excessive movement to develop which led to the resultant failure.

The loss of preload could tue attributed to two causes: the bolts which join the coupling to the turbine were not installed in the direction specified in the coupling installation drawing, i.e.

they were facing inward vice outward; additionally, the turbine and pump were misaligned. Accordingly, the licensee revised the coupling assembly procedure to specify exactly which direction the bolts are to face. Additionally, the licensee will increase.

the frequency of alignment checks of the feedwater pump and turbine to once every refueling outage.

Prior to the failure an alignment check was accomplished only if work was performed on the turbine or pump, with the last alignment performed during the first refueling outage.

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Prior to restart of the reactor, the ' licensee examined the j

coupling on the 'A' turbine-driven and motor-driven feedwater

pumps for cracks.

No coupling inadequacies were identified,

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however, the alignment of the turbine-driven feedwater pump required adjustment prior to plant restart. The inspector reviewed the technical manual for the-feedwater pump and noted tha+ the manual recommended a hot alignment of the pump and

turbine unit be performed. Through conversations with the

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maintenance supervisor, the inspector.was. informed that hot alignments of the coupling assemblies are.not performed due to.

I the difficulty involved and lack of the requisite equipment.

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Specifically, the supervisor stated that an accurate hot alignment can only be performed within five-to-ten minutes of securing steam to the turbine.

Therefore, personnel must j

quickly set up equipment and perform the measurements in order i

to get accurate data.

Because of the difficulty factor and the l

lack of the required equipment, the licensee opted to perform only a cold alignment based on extrapolated equipment growth when hot. -The supervisor stated that, as a result of.the recent

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coupling failure, the licensee is rethinking its position that'a satisfactory alignment can be obtained based upon data obtained when cold.

Prior to the turbine feedwater pump coupling failure, the

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inspector noted that feedwater pump vibration which is recorded i

on a strip chart in the control room increased from 1 mil to 4 j

mils eight hours prior to coupling failure. The inspector asked I

a maintenance engineer whether the annunciator which warns the operators of excessive feed pump vibration is properly set,

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since the 3-mil. increase in vibration could have been an

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indication of a failure but the annunciator which warns of high i

turbine vibration is set at 7 mils. The inspector was informed i

that the bases for the 7-mil setpoint could not be established.

l It appears that during startup operations the alarm setpoint was

initially lover.

However, the lower setpoint resulted in numerous vibration alarms to be annunciated in the control room

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with no indication of feed pump failure.

To reduce the frequency of alarms, the licensee raised the setpoint to the

7-mil setpoint.

Currently, the licensee is evaluating a proposal to reset the alarm setpoint to 3 mils.

During the transient, it was also noted that main feedwater

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l system discharge pressure did not substantially decrease when

l the 'B' turbine feedwater pump failed.

Consequently, the

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motor-driven feedwater pump which receives an automatic start signal when feedwater pressure drops to 950 lbs did not operate.

Therefore, the inspector determined that the motor-driven feedwater pump did not serve its intended function of automatically starting and supplying water to the steam generators when the turbine feed pump was lost.

It is possible that, if the motor-driven feedwater pump started when the 'B'

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i turbine-driven pump' failed, steam generator level may have been restored prior to reaching the low level setpoint. The a

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inspector concluded that the method of sensing a loss of feedwater flow and of starting the motor-driven feedwater pump may be inadequate. The inspector discussed this observation with the operations superintendent who indicated that the method of sensing flow loss is going to be re-evaluated to determine if the motor-driven pump can be made to be more responsive to loss-of feed transients.

• After review of the transient, the-inspector has concluded that the operators responded appropriately to the event. However, the following additional eng.neering support to plant operations is warranted: (1) the method of starting the motor-driven feedwater pump should be re-evaluated to ensure that the pump will start and mitigate postulated loss of feed events, (ii) the E

annunciator which warns the operators of excessive turbine vibration may have to be reset to better notify operators of impending failures, and, (iii) the feedwater pump alignment-procedure should include a hot alignment to ensure proper alignment of the coupling. Through_ discussions with licensee personnel, these observations are being examined, therefore, the inspector has no further questions.

3.2 Inadvertent Partial Containment Depressurization Actuation During routine operation at 100% full power on January 9, a partial containment _depressurization actuation (CDA) occurred on emergency safety-feature (ESF) train A at 8:26 a.m.

The CDA caused the 'A'

diesel generator (DG) and the ' A' auxiliary feedwater pump to start along with other emergency core cooling system pumps as designed.

There was no injection into the reactor vessel or spray injection into the reactor containment because valves did not open as a result of the partial CDA.

The ESF valves did not open because of the manner in which the spurious signal was generated.

Plant operators.

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reset the signal after verifying it was spurious, stabilized the

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'The inspector reviewed the plant status from the control room after the event and the action by plant operators to stabilize the plant and restore normal operations. This review included inspector observations of control board recorders and indications, a review of the event sequence of events printout, and discussions with operations, maintenance, engineering and I&C personnel. The following event sequence was noted by the inspector:

+8:25:39 - Diesel Generator 'A' Sequencer actuates

+8:25:39 - 480V supply breaker 32T to bus 32-3T opens

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'A' diesel generator starts

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'A' Train AFW, CHG, QSS, RHR, SI pumps start

+8:25:47

'A' diesel generator " ready to load"

+8:36:29

'A' RSS pump starts after required-delay

+8:37:38 - Control operator stops AFW, CHG, SIH,

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RHR pumps

+8:37:43 - Control operator stops QSS pump

+8:37:50.- Control operator stops RSS pumps-

+8:59

- Control operator stops the 'A' diesel generator

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The following times and events are notable from the above. The 'A'

quench spray system (QSS) pump operated for 12 minutes at shutoff head and cavitated.

The start of the 'A'

and 'C' recirculation spray system (RSS) pumps was delayed for 10 minutes after the sequencer actuation per design, but the pumps operated for up to 1 minute and

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20 seconds with dry suction lines, prior to being secured by the operators, NRC review of operator _ response to the event is discussed further in Section 3.3.

Licensee inspection and testing of the QSS and RSS pumps ~ and the DG sequencer concluded the equipment operated correctly, remained operable, and were not adversely affected by the event.

Licensee investigation determined that maintenance electricians while burnishing contacts on a recirculation system valve (3RSS*MOV20C)

caused a momentary short that resulted in energization of a single slave relay (K645) in the CDA actuation logic. This action by the electricians would cause the operation of the ' A' DG sequencer and the ESF pumps to start, but the associated ESF valves would not operate since valve operation requires a safeguards actuation signal from the solid-state protection system (SSPS) which did not occur.

The inspector reviewed the licensee's' root cause determination for the event and the logic circuits for the CDA master and slave relays (SSPS prints and ESK 7MW) and 3RSS*MOV20C (ESK 6LF, Rev. 6, 1/28/87).

Refer to Figure 1 for a simplified schematic of the interface between the safeguards actuation logic, the safeguards test circuit (STC),

and MOV20C.

The STC for the CDA actuation logic uses contacts on the RSS discharge motor-operated valves (MOVs) 3RSS*MOV 20A&B and 20C&D to assure the containment spray flow path is secured during testing of the pumps to avoid inadvertent spray of the containment. The STC interface with the master and slave relay logic path provides a

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118-volt potential to be applied on one side of the limit switch

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contacts in the Limitorque motor operator (e.g., contact 6C on MOV 20C).

This potential exists even if the MOV is deenergized for maintenanc a

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f The licensee concluded that the inadvertent' CDA resulted when a momentary short created while working on the MOV caused a potential-dr'op across slave-relay K645,-which energized the relay and caused the diesel sequencer to actuate (see Figure 1).

The inspector

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identified no inadequacies in the licensee's conclusions.

Licensee j

engineering and I&C personnel provided excellent support to plant operations to identify the root cause of the event.

The resident inspector reviewed the licensee's event investigation,-

i testing and corrective actions, and -identified no inadequacies. The licensee accepted the affected equipment as fully operational prior to the completion of the swing shift on January 9.

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identified no inadequacies in the licensee's conclusions regarding equipment operability.

Licensee actions to review the event and to verify-proper plant response were thorough and conservative.

Unit and operations management were actively involved in event followup

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and were effective in coordinating the resources needed to resolve identified issues.

The licensee notified the NRC operations officer of the partial ESF.

actuation at 9:10 a.m. as required by 10 CFR 50.72(b)(2)(ii).

NRC review of the licensee event report required per 10 CFR 50.73(a)

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(2)(iv) will be' completed on a subsequent routine inspection.

3.3 Operator Response to Containment Depressurization Actuation Transient While conducting a review of the January 9,1990 containment discharge actuation event, the inspector noted that operators did not realize that the initiating event was a CDA signal until the recirculation spray system pumps started, eleven minutes after tho first CDA generated annunciators appeared. The inspector noted that once the operators identified the cause of the event, response was proper and the 'A' train engineered safety. features equipment'

(residual heat removal pump, safety injection pump, quench spray pump, and emergency diesel generator), that were started by the signal were shutdown.

See Section 3.2 for the event chronology.

Through conversations with the operators who were on shift at the time of the event, the' inspector noted that when operators responded to the event they focused on treating the effects of the transient and stabilizing plant parameters. The actions that operators performed in response to the event such as cross-connecting the reactor plant component cooling water system trains, securing letdown, and establishing excess letdown were proper and mitigated the event.

However, the inspector noted that there were alarms on the main control board such as " Residual Heat Removal and Quench Spray System Flow Low" that, if noted by the operators, would have guided them into a different thought process in which they could have sooner recognized that a CDA actuation occurred.

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'Through conversations with the shift supervisor, the inspector noted that his attention was focused on main board 8 when bus 32-3T tripped and,'A' diesel generator started due to the CDA actuation..This was despite the fact that there-were many other annunciators that illuminated in response to the CDA signal such as 'A'

RBCCW pump trip on main' board 1, quench spray system flow low and' residual heat removal flow low on main board 2, bus'32-3T trip on main board 8H.,

'A' diesel generator start _on main board 8 and containment recir-culation fan trip on the main ventilation panel. The' inspector concluded that if the shift supervisor responded to the event by

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first observing all the main control boards, even if he did not associate such events with an actual CDA signal,-he might have noted that the quench spray and recirculation spray system pumps were running in a no flow condition and taken-appropriate action.

It is apparent that the broad perspective that should be maintained by supervisory operations personnel was lost during this event.

'The fact that supervisory personnel must maintain a broad overview of

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plant status is recognized in Millstone Station ACP 6.01, Control Room Procedure, which states, in part.... "The shif t supervisor will, maintain an overview of operational conditions that affect safety.

The supervising control operator will not normally become involved in evolutions that require manipulating of the controls." The inspector spoke to the shift supervisor (SS) about crew performance during the event _and the SS acknowledged the fact that he may have become too-involved in the specific board events rather than maintaining a broad perspective.

By losing the broad perspective, it appears that diagnosis of the event became more difficult.

The inspector noted that the safety consequences from the crew-performance was minimal in this specific event, since the plant remained stable and damage to safety equipment was averted.

Additionally, the inspector noted that crew performance during other events, i.e. the December 9 partial CDA actuation and January 21, 1990 loss of feed, consistently has been good; therefore, slow crew diagnosis of this condition may be an anomaly. The inspector has concluded that additional review of crew performance during off-normal conditions is required to determine whether a generic concern exists. This evaluation will be accomplished during routine resident inspections.

3.4 Plant Tours

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The inspector observed plant operations during regular and backshift tours of the following areas:

Control Room Auxiliary Building Vital Switchgear Room Diesel Generator Rooms Turbine Building Intake Structure ESF Building

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During plant tours, logs and records were reviewed to ensure

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compliance with station procedures, to determine if entries were

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correctly made, and to verify correct communication and equipment status.

No inadequacies were noted.

3.5 Review of Plant Incident Reports The plant incident reports (PIRs) listed below were reviewed during the inspection period.to (1) determine the significance of the events; (ii) review the licensee's evaluation of the events; (iii)

verify the licensee's response and corrective actions were proper; and, (iv) verify that the licensee reported the events in accordance

with applicable requirements, if required.

The PIRs reviewed were:

i number's 3-89-221~, 3-90-001, 3-90-002, 3-90-003, 3-90-004, 3-90-005,

-l 3-90-006, 3-90-007, 3-90-008, 3-90-009, 3-90-010, 3-90-011, 3-90-012, i

3-90-013,.3-90-014, 3-90-015, and 3-90-016, 3-90-17, 3-90-18, 3-90-19, 3-90-20, 3-90-21, 3-90-22, and 3-90-23.

The PIRs that warranted inspector followup were 3-90-008, 3-90-014, and 3-90-016 and licensee actions taken during and in response to these plant incidents are discussed in further detail in sections 5.1.1, 3.1.1 and 5.2.3 of this report, respectively.

L 4.0 Radiological Controls (IP 71707/92701)

i 4.1 Contamination Control Initiatives

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i The Health Physics Organization at Millstone Unit 3 has recently instituted a program whereby health physics technicians are assigned specific task areas such as contamination control, procedure upgrade, etc., during non-refuel periods. The technicians are then evaluated on how they perform in the assigned area of responsibility.

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Currently, there are three technicians who are assigned.to contamination control. These technicians are tasked with identifying the contaminated areas in the facility, reasons why the areas are contaminated, and solutions or methods to reduce or eliminate the

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size of the areas.

The inspector interviewed the technicians who are l

responsible for contamination control and found them to be know-

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ledgeable of their responsibilities and well motivated.

The

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inspector noted that the technicians have identified ways to prevent or minimize the spread of contamination and have submitted their suggestions to management for consideration.

Suggestions included:

installation of cofferdams in the charging pump cubicles to prevent leakage that may develop in the cubicles from spilling out of the area onto the levels below; and installation of gooseneck fittings in

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place of straight pipe on contaminated system vents which are

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operated frequently. The inspector noted that such fittings would be useful on the safety injection pump vents where boron deposits have L

collected because of pump venting operations.

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Millstone Unit 3 has approximately 100,500 square feet of floor space

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in the various process buildings which are in a-radiologically

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controlled area (RCA). According to a list provided to the inspector.

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by the licensee, approximately 8000. square feet of the RCA at Millstone Unit 3 is classified as contaminated.

This area has been decreased by 500 square feet since-the incorporation of the new program..The inspector toured the RCA areas with a technician and

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noted that several problem valves which previously caused the spread of contamination were either repaired or trouble reported by the~

technicians and in the process of being evaluated. Through discussions with the technicians, it appeared that maintenance was responsive to the technicians initiatives to identify and repair-leaking joints.. The inspector concluded that an aggressive program of early identification and resolution of known valve and joint leakage would prevent the need for future decontamination of areas that could be required if leakage was allowed to continue unabated.

The licensee's program is only one month old, therefore, the inspector was not able to identify fully its effectiveness in the reduction of contaminated areas.

However, it appears through interviews with technicians that the personnel are enthusiastic and well motivated. Worthwhile ideas to control contamination have been identified by Health Physics personnel and forwarded to management for consideration. The inspector noted that the licensee's approach to reducing the amount of contaminated areas by thorough identification and repair of the source, rather than placing a bag to collect the leakage is sound.

Leaking valves and joints are being aggressively identified by technicians and repaired'by maintenance personnel which eliminates potential contamination sources.

The inspector has therefore concluded that the program is well focused and has the potential to be successful in reducing and controlling the amount of contaminated areas at Millstone Unit 3.

5.0 Maintenance / Surveillance 5.1 Observation of Maintenance Activities The inspector observed and reviewed selected portions of preventive and corrective maintenance to verify compliance with regulations, use of administrative and maintenance procedures, compliance with codes and standards, proper QA/QC involvement, use of bypass jumpers and safety tags, personnel protection, and equipment alignment and retest.

The following activities were included:

'A' RBCCW Heat Exchanger Eddy Current Testing AWO M3-390-01329

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'B' Turbine Driven Feedwater pump Repairs AWO M3-390-01610

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'B' Safety Injection Relief Valve Repair AWO M3-390-02430

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No inadequacies were identified.

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5.1.1 Review of Maintenance Activity Which Caused Containment Depressurization Actuation Work Order AWO M3-89-31828, 3RSS*MOV200, initiated on January 9, 1990, was written to troubleshoot and repair the position

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indication circuitry for valve 3RSS*MOV200, 'C' containment recirculation system spray header isolation valve. The work order was issued after control room operators noted that the internal limit switches were not making up close limits for slave relays even though the valve showed fully closed based on main control board indications.

The position indication was repaired; however, the partial containment depressurization -

actuation event discussed in Section 3.2 occurred during the work-activity.

During interviews with licensee maintenance electricians, the inspector noted.that standard precautions were taken to work on MOV20C, including deenergizing the MOV while burnishing the

. contacts. The valve was deenergized by opening the motor supply breaker at the EE 1AH motor control center.

However, this action did not eliminate the 118 vac supplied to one side of the MOV limit switch contacts due to the interface with the safeguards test circuit (STC). This circuit could not be deenergized because the solid state protection system was required to be operable for the existing plant operating mode.

The maintenance electricians were cognizant that the 118 vac was present and had reviewed the MOV and CDA circuits to assure that, even if the contacts were closed during the work, additional contacts in series with those being worked.on would remain open, thus precluding the completion of an electrical

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circuit required to actuate the CDA slave relay (K645).

However, the electricians' review failed to identify a " sneak path" through the STC whereby a momentary short to ground could actuate the K645 relay, as did occur. The inspector noted that the sneak path was not obvious nor readily identifiable from the logic prints used by the electricians.

In fact, subsequent identification of the root cause of the CDA event by engineering-personnel required-the construction of a composite electrical schematic from at least five ESK logic and solid state protection system prints.

The licensee recognized that the circuit and electrical path

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identified as a problem as a result of the CDA event on January 9 was not unique. The licensee plans to address this issue as part of the long-term corrective actions for the inadvertent CDA event.

The licensee stated this action will include a review by I&C to identify configurations similar to that on MOV20C and the i

development of additional administrative controls to preclude

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recurrence of the problem.

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No inadequacies were identified.by the-inspector regarding the licensee's followup of the event and corrective action plans.

5.1.2 Followup to Maintenance Team Inspection (MTI) Report' Items 50-423/89-80 This report was forwarded to the licensee by letter dated September 1, 1989. The staff's letter requested the licensee to notify the NRC in writing -of ' actions taken or planned in order to enhance maintenance activities regarding the weaknesses identified in Appendix 3 of the report.

The license responded-

.to the weaknes'ses by letter dated November 8,1989.

This inspection reviewed the licensee's corrective action for three of the items.

The item numbers. correspond to those in the report's Summary of Weaknesses.

2.

" Greater attention to detail is needed while performing housekeeping and configuration control walkdowns in all three units."

This item is being lef t open pending additional inspection focus on the licensee's actions toward assuring preserva-

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tion of the material condition and maintaining the configuration of the as-designed plant. The licensee's corrective action focus to date has been on housekeeping, personnel safety and performance.

3.

"NPRDS data is not typically used by Unit 3 maintenance and I&C departments."

A task force action plan has been developed in a W.D.

Romberg memorandum to S.E. Scace, et. al, dated December 4, 1989.

The plan calls for the NPRDS: data bases to be updated for all units by November 1,1990.

Plant personnel are to be trained in the use of the NPRDS data base by March 1, 1990 and a procedure is being planned to direct cognizant personnel to use the NPRDS. This item is being left open to assess the licensee's implementation in late 1990.

5.

" Work order procedure is weak in defining requirements for retests and acceptance criteria."

Based on the corrective action being taken to the revi-sion 21 of ACP-QA-2.02C " Work Orders," and the existing guidance available regarding retests, the concern regarding this weakness is close p

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5.2 Observation of Surveillance Activities The inspector observed portions of and reviewed completed surveillance tests to assess performance in accordance with approved-i procedures and Limiting Conditions of 0peration, removal and j

restoration of equipment, and deficiency review and resolution.

The following tests were reviewed, j

I&C 3443CN21, Protection Set Cabinet III' Operation Test 4--

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I&C 34410021, Excore to Incore Calibration Procedure

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I&C-34401F01, Intermediate and Power Range Detector Plateau Test-

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No inadequacies were noted.

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5.2.1 Verification of Equipment Operability Following Containment j

Depressurizatien Actuation

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The inspector observed portions of the tests listed below and o

reviewed the test results. The testing was completed by the

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licensee as part of its followup of the inadvertent partial containment depressurization actuation (CDA) signal generated on

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January 9,1990.

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+ OPF 3646A.8-1, Slave Relay Test, Train A, 1/9/90

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+ SP 3448E31, Train A Diesel Generator Sequencer Actuation Logic, 1/9/90

+ OPF 3606.3-1, Containment Recirculation Spray i-Test-3RSS*PIC Operational Test, 1/9/90 l

+ OPF 3609.1-1, Quench Spray Pump 3QSS* PIA Operational Readiness Test, 1/9/90 a

+ OPF 3606.8-1, RSS Valve Train "A" Quarterly Stroke Test, 1/9/90 i

The licensee determined that the diesel sequencer and the CDA j

actuation logic worked correctly during the event, that no damage occurred to the RSS and QSS pumps,.and that the emergency (

safety features systems were fully operational. The licensee accepted the test results at 10:25 p.m. on January 9.

The inspector identified no inadequacies in the testing l

completed in response to the CDA. The inspector further i

identified no inadequacies in the licensee's conclusions i

regarding equipment operability.

Licensee actions in response

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to the event to verify equipment operability were thorough and conservative.

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5.2.2. Enforcement Discretion Granted On January 18, 1990, a chemistry supervisor discovered that the surveillance that requires average disintegration energy.(E-Bar)

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be measured once every 6 months per technical specification 4.4.8 had not been met.

The supervisor discovered that fact l

while conducting a review of all chemistry surveillances to j

ensure that they were completed prior to reactor startup.'

l The E-Bar. sample is a measurement of the specific activity of

'l all the isotopes in the reactor coolant that have half lives

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that are greater than 10 minutes. The E-Bar sample is used to

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limit the activity of the reactor coolant which is not allowed q

to exceed a 100/E-Bar limit.

By limiting coolant activity, the

exposure that an individual would receive if a release were made j

to the environment is in turn decreased, j

The chemistry supervisor informed the inspector of his finding

.l at 1:30 p.m. January 18. The supervisor stated that an E-Bar~

l sample was taken per plant technical specifications 20 days

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after returning to power on May 5, 1989.

However, a new E-Bar i

was not calculated until August 14, 1990 when the sample results l

were received from a vendor - Teledyne. The vendor must i

calculate the E-Bar sample since the Millstone chemistry department does not have the facilities to measure the activity of Strontium 89, Strontium 90 and Iron 55 which are alpha emitters. When the technicians received the sample results on August 14, 1989 and calculated a new E-Bar limit, the chemistry

'j department thought that the next E-Bar determination was not required until February of 1990; therefore, an E-bar sample was not drawn in' November of 1989 as required.

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As justification to allow a plant startup, the licensee stated d

that core conditions had not changed appreciably because daily

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samples of gross activity which measures the activity of gamma l

emitting isotopes, which constitute the majority of activity in

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the coolant, had not changed above expected levels.

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Additionally, the licensee determined that the E-bar limit that

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was presently in effect was conservative since the sample was taken at the end of cycle two operations, when there were known leaking fuel elements.

These elements were replaced during the

core refuel period in mid-June 1989. To prevent recurrence of

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the event, the licensee committed to sampling and determination of an E-Bar once every 3 months vice the six-month interval required by technical specifications.

L After review of the licensee data by NRC resident inspector and j

I regional and headquarters personnel, the regional administrator granted enforcement discretion to the licensee, which allowed the licensee to enter an operational mode without meeting all surveillance requirements. The enforcement discretion was l

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granted at 10:00 p.m. on January 18, 1990.. The plant entered mode 1 on January 20 at 1:47 a.m. and a sample was drawn for E-Bar on January 22 at 8:00 a.m.

The sample was sent to the Haddam Neck Plant and analyzed and accepted by the Millstone 3 operations department on January 26. Additionally, the

. inspector reviewed the Licensee Event Report that was submitted to the NRC to document the properly performed E-Bar surveil--

lance. After completing review of the above two items, the

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inspector had no further questions on this issue. The new E-Bar

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limit was 259 pCi/gm (micro curies per gram) which was more conservative, as expected, than the 8.7 pCi/gm limit that was in effect.

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5.2.3 Technical Specification Improvements Identified

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While reviewing technical specification 4.4.8, the licensee.

identified areas where the specification may be improved.

Specifically, the Millstone Unit 3 technical specifications (TS)-

now require. the E-Bar sample to be determined from a calculation of all isotopes in the coolant that have a half-life that is greater than 10 minutes.

This necessitates having to send the sample offsite to the vendor so a calculation of the contamination from alpha-emitting isotopes can be determined. A proposed change that is being contemplated would base the E-Bar determination only on the gamma and beta emitting isotopes which contribute the majority (approximately 99.6%) of the activity to the reactor coolant. These isotopes can be counted at the Millstone site and could enable a faster E-Bar determination.

According to the chemistry supervisor, this change would make

.the Unit 3 (TS) consistent with other facilities, such as Millstone Unit 2, which have their E-Bar only on beta and gamma emitting isotopes. -

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Another proposed improvement to the specifications that is being examined would be the addition of the statement that TS 3.0.4 is not applicable.

This would enable the licensee to change modes without having completed the surveillance requirement for E-Bar.

The inspector noted that this proposed improvement would be necessary -if the plant is shutdown for a six-month or greater period because, in order to complete the TS requirement, the licensee must sample, and since the sample can only be drawn in mode 1, the licensee would have to startup to meet the surveillance.

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The inspector considered that the improvements to the specification that the licensee is examining should improve readability and useability and he had no further questions.

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6.0' Engineering / Technical Support 6.1 Pyeviously Identified Items 6.1.1 (Closed) Unresolved Item 87-30-01, Safety Parameter Display _

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System License Commitment This item tracked the licensee's actions regarding license

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condition 2.C(12), safety parameter display system (SPDS).

Modifications to the SPDS system that were performed before the startup of cycle 2 included adding the following parameters to SPDS.

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Residual Heat Removal Flow

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Containment Isolation

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Containment Hydrogen Concentration

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Primary Coolant System Hot Leg Temperature

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Additional modifications were performed.to the SPDS during the second refueling outage to provide a continuous display for post-LOCA cooling variables and containment hydrogen concentration. These modifications were performed to meet the provisions of supplement 1 to NUREG 0737 (Clarification of TMI

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action plan requirements).

The NRC Office at Nuclear Reactor Regulation issued a safety evaluation report on December 18,

.-1989 which determined that this licensee commitment had been met, therefore this item is closed.

6.1.2 (Closed) Followup Item 87-21-03 Actuation of Feedwater Heater Relief Valve Discharge Piping This item documented a potential personnel hazard that existed in the turbine building which concerned the discharge piping of the feedwater relief valves. While conducting a tour of the turbine building, the inspector noted that the discharge piping from the feedwater heater relief valves ran downward alongside of the heater to the floor. Although the_ discharge area was roped off,'the potential existed for an individual to be burned or killed if he was in an adjacent area and a relief valve lifted.

The licensee originally planned to relocate the discharge piping during the first refueling outage, however, the modification was delayed to the second refueling outage due to problems encountered with the engineering analysis.

The inspector toured the building and noted that the relief valves have been relocated from the top center position and placed at the end of the feedwater heaters per plant design change request (PDCR)

3-87-58. Additionally, the discharge piping has been relocated to vent to the turbine building roof per PDCR 3-86-093.

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inspector determined that the licensee has appropriately eliminated the personnel hazard and this item is. closed.

6.1.3- (Closed) Unresolved Item 86-26-01 Inadequate Plant Design Change Request Documentation This item documented an inspector's finding that plant design change requests (PDCRs) were not adequately organized or filed.

Specifically, several PDCR packages did not contain pertinent

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information such as the status of commitments and related procedures.

Further, the loose pages of PDCR packages were not adequately organized or filed. -In. response to the inspector's comment, the licensee revised station procedure ACP-QA-4.10

" Plant Design Change Request", to include figure 7.2 which provides additional guidance on the type of information that should be included in a PDCR packages prior to transfer to the nuclear records facility. The inspector reviewed PDCR

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MP3-87-062 " Refueling Cavity Drain Line Modification,"

MP3-88-013 " Phase two Annunciator Changes," and MP3-89-001 " Cold-Leg (WR) RTD Replacement," and concluded that each PDCR package was. organized, and contained pertinent information as required by figure 7.2 of ACP-QQ-4.10.

Based upon inspector review of the PDCR packages and review of the station procedure, the inspector considers that completed PDCR packages are adequately organized and filed, therefore, this item is closed.

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6.1.4 {0 pen) Unresolved Item 50-423/89-15-01' Implementation of NRC

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Guidance for Equipment Operability and Surveillance

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This item remains open pending the issuance of guidance by the NRC and the licensee taking action regarding the implementation of the ATWS equipment operability and surveillance requirements.

J 6.1.5 (0 pen) Unresolved Item 50-423/89-15-03 Untimely Response to Licensee's Quality Assurance Audit Findings Licensee actions taken to address this identified weakness consisted of revising the Nuclear Engineering and Operations Procedure 3.07 Response to " Quality Assurance (QA) Audit Findings." The revision which is effective February 20, 1990, is intended to speed up the response to QA audits by initiating the following changes:

(1) QA audit results will be routed through the unit directors for corrective action rather than the station director _ (2) Only one other extension can be given by the Q/A department to respond to the audit findings.

Pending ef fective implementation of NEO 3.07, this item will remain open.

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7.0 Safety Assessment / Quality Verification

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7.1 Committee Activities

~The. inspector attended meetings of_the Plant Operations Review Committee (PORC).

The inspector noted by observation that committee

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administrative requirements were met for the meetings, and that the committees discharged their functions in accordance with regulatory requirements. The inspector observed a thorough discussion of matters before'the PORC and a good regard for safety in the issues under consideration by the committee. No inadequacies were identified.

7.2 Licensee Event Report Review

Licensee event reports (LERs) submitted during the report period were reviewed to assess LER accuracy, adequacy of corrective actions, compliance with 10 CFR 50.73 reporting requirements, and.to determine if there were generic implications or if further information was required.

Selected corrective actions were reviewed for

' implementation and thoroughness.

The LERs reviewed were 89-27-00, 89-33-00,-and 89-34-00.

No inadequacies were noted.

LER 89-34-00 was discussed in section 5.2 of Inspection Report 50-423/89-23.

7.3 Coverage of Maintenance Retests by Quality Control-Personnel Maintenance Team Inspection Report 50-423/89-80 documented a lack of coverage _of maintenance retests by quality control personnel.

In response to this concern, the quality services department (QSD)

developed a retest checklist guide to assist QSD personnel in the i

observation of retest surveillances. Pending the scheduling and observation of plant retests per the new checklist, this is an open item (50-423-90-01).

8.0 Management Meetings

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Periodic meetings were held with station management to discuss inspection findings during the inspection period. A summary of findings was also discussed at the conclusion of the inspection. No proprietary information was covered within the scope of the inspection. No written material was given to the licensee during the inspection perio w;,

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3RSS*N0Y20 TEST CIRCUlT SCHEMATIC f

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SR --> SEQ --> PUNP l

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STC - safeguard test circuit i18 RTN - SSPS chassis ground SR.- slave relay K64S ESF - engineered safety features

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L MR'- master relay GND - ground j

SEQ - diesel generator.

sequencer

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