IR 05000213/1988008

Safety Insp Rept 50-213/88-08 on 880405-0516.No Violations Noted.Major Areas Inspected:Plant Operations,Radiation Protection,Fire Protection,Security,Maint,Surveillance Testing & Generic Ltrs 87-12 & 81-21

ML20154R839
Person / Time
Site:	Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png
Issue date:	05/27/1988
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20154R829	List: IR 05000213/1988008 ML20154R825
References
50-213-88-08, 50-213-88-8, GL-81-21, GL-87-12, NUDOCS 8806080212
Download: ML20154R839 (22)

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U.S. NUCLEAR REGULATORY COMMISSI'ON

REGION I

Report No.

50-213/88-08 Docket No.

50-213 License No.

OPR-61 Licensee:

Connecticut Yankee Atomic Power Company P. O. Box 270 Hartford, CT 06101 Facility:

Haddam Neck Plant, Haddam Neck, Connecticut Inspection at:

Haddam Neck Plant Inspection dates:

April 5 to May 16, 1988 Inspectors:

John T. Shediosky, Senior Resident Inspector Andra A. Asars, Resident Inspector Eben L. Conner, Project Engineer, DRP Approved by:

% 6.k% jc s'l2'7 /es

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E. C. McCabe, Chief, Reactor Projects Section IB Date Summary:

Inspection 50-213/88-08 (4/5/88 - 5/16/88)

Areas Inspected: This was a routine safety inspection by the resident inspectors.

Areas reviewed included plant operations, radiation protection, fire protection, security, maintenance, surveillance testing, licensee events occurring during the

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inspection period, open items from previous inspections, Generic Letter 87-12, loss of decay heat removal with the reactor coolant system partially drained, primary coolant system pressure isolation valves (Event V), and implementation of Generic Letter 81-21, Natural Circulation Cooldown.

Results:

No violations were identified. One unresolved item was opened regarding the upgrading of Abnormal Operating Procedures for agreement with the newly up-graded Emergency Operating Procedures.

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8806080212 880527 PDR ADOCK 05000213 i

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l TABLE OF CONTENTS PAGE 1.

Summary of Facility Activities.......................................

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Plant Operations..............................................

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Plant Operations Review Committee....................................

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Maintenance and Surveillance..

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4.1 Failure of Charging Pump Suction Valve to Operate...............

4.2 Reactor Coolant Pump Seal Replacement...........................

5.

Previous Inspection Findings.......

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5.1 Deviation from Emergency Operations Procedures Generation Package..

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5.2 Full Closure of Core Deluge Motor-0perated Valves...............

5.3 Failure to Follow Approved IST Procedures.....................

6.

Events Occorring During the Inspection...

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6.1 Licensee Event Reports and Safcguards Event Reports.............

6.2 Identi fication of Primary to Secondary Lea kage.................

6.3 Inadvertent Severance of Diesel Fuel Oil Line...................

6.4 Control Rod Position Indication Anomalies.......................

6.5 Reactor Trip - April 30, 1988................

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6.6 Discovery of ECCS Single Failure Conditions.....................

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Periodic and Special Reports.........................................

8.

Gene-ic Letter 87-12, Loss of Decay Heat Removal When Reactor Coolant System Partially Drained.

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9.

Primary Coolant System Pressure Isolation Valves.....................

10. Natural Circulation Cooldown - Implementation of Generic Letter 81-21................................................................

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Exit Interview...........

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DETAILS 1.

Summary of Facility Activities At the beginning of the inspection period, the station was operating at 80%

power and had submitted a Proposed Technical Specification (TS)' Change to allow full power operation with a revised large Break LOCA' Analysis.

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April 8, TS Amendment No. 102 permitted plant operation to full power.

Full power was achieved on April 9.

Excessive leakage had been identified from the No. 2 seal on the No. 3 Reactor Coolant Pump (RCP) during plant heatup.

The licensee elected to operate at power in order to identify other material deficiencies. Additionally, a slight primary to secondary leak was identified in Steam Generator No. 2.

Power operation continued for several weeks to monitor plant performance under full power conditions.

During that period, RCP seal leakage did not increase above the original value of three gallons per minute. Also, the calculated primary to secondary leakage decreased from about eight to two gallons per day.

On April 12, during removal of the Service Building hallway floor to support the new Appendix R Switchgear Building construction, the diesel fuel oil transfer line from the fuel oil storage tank to the Emergency Diesel Generator

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fuel oil storage tanks was inadvertently severed by a concrete saw.

The Fire

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Brigade responded; however, the leak was stopped and repaired with no other

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material damage.

On April 29, a plant shutdown to cold shutdown was initiated for replacement of t.he No. 3 RCP seal package. During the shutdown, the plant was placed into three loop operation at 60*.' power to support Internals Vibration Monitoring equipment measurements. As the fourth loop was being returned to service on j

April 30, a reactor trip occurred. The licensee continued with the planned

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outage.

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Ouring the week of i'ay 2, the licensee identified two valves in the charging pump suction lines wnich do not meet the Single Failure Criteria of 10 CFR 50 Appendix A.

At the conclusion of the inspection period, the plant was in mode 5 and the licensee was implementing a design change to bring the charging system into compliance with Single Failure Criteria.

2.

Plant Operations (71707)

The inspector observed plant operation during regular tours of the following plant areas:

Control Room Security Building

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Primary Auxiliary Building Fence Line (Protected Area)

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Vital Switchgear Room Yard Areas

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Diesel Generator Rooms Turbine Building

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Control Point Intake Structure and Pump

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Reactor Containment Building i

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Control room instruments were observed for correlation between channels and for conformance with Technical Specification requirements.

The inspector observed various alarm conditions which had been received and acknowledged.

Operator awareness _ and response to these conditions were reviewed.

Control room and shift manning were compared to regulatory requirements. ' Posting and control cf radiation and high radiation areas was inspected.. Compliance with Radiation Work Permits and use of appropriate personnel monitoring devices were checked.

Plant housekeeping controls were observed, including control and storage of flammable material and other potential safety hazards.

The inspector also examined the condition of various fire protection systems.

During plant tours, logs and records were reviewed to determine if entries were properly made and communicated equipment status / deficiencies.

These records included operating logs, turnover sheets, tagout and jumper logs, process computer printouts, and Plant Information Reports.

The inspector observed selected aspects of plant security including access control, physical barriers, and personnel monitoring.

In addition to normal working hours, the review of plant operations was conducted during the following evening and weekends:

May 1, 1988 1:45 PM to 4:15 PM

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May 13, 1988 6:00 PM to 8:00 PM

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May 15, 1988 2:30 PM to 5:30 PM No unacceptable conditions were identified. Operators were alert and dis-played no signs of inattention to duty or fatigue.

The inspector observed several sources of leakage from reactor coolant systems during inspections made in the containment during the week of May 2.

Nine leaks were identified in components associated with Reactor Coolant, Charging, Core Deluge, Reactor Coolant Pump Seals, Steam generator Vent Header, and Reactor Coolant Fill and Orain Headers.

In each case the leakage was from mechanical fittings such as a valve body to bonnet leak or valve stem packing

j leakage. Although the leaks were apparent because of an accumulation of boric

acid, all were minor. A summary of the inspector's observations were provided l

to the licensee, who took corrective action to repair the leaks and clean up

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the boric acid.

3.

Plant Operations Review Committee (PORC) (40700, 40701)

The inspector attended several Plant Operations Review Committee (PORC) meet-ings.

Technical Specification (TS) 6.5 requirements for required member at-tendance were verified.

The meeting agenda included procedural changes, pro-posed changes to the Technical Specifications, and field changes to design change packages. The meeting was characterized by frank discussions and questioning of the proposed changes.

In particular, consideration was given to assure clarity and consistency among procedures.

Items for which adequate review time was not available were postponed to allow committee members time to review and comment. Dissenting opinions were encouraged.

The inspector had no further comments.

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On May 10, the inspector attended a joint PORC - Nuclear Review Boara (NRB)

meeting-for the Safety Inject;on Logic Modifications for the Charging Pumps.

The modification is discussed in detail 6.6 of this inspection report.

Throughout the meeting, the PORC and NRB focused on the operational and safety implications of this design change.

It was concluded that the change consti-tuted an unreviewed safety question.because it made lesser accidants in the Updated Final Safety Analysis more severe with the tripping of the charging pumps. The committee reviews were carried out thoroughly and with a clear perspective on safety.

4.

Maintenance and Survaillance (61726, 62700)

The inspector observed various maintenance and problem investigation activi-ties for compliance with requirements and applicable codes and standards, QA/QC involvement, safety tags, equipment alignment and use of jumpers, per-sonnel qualifications, radiological controls, fire protection, retest, and

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reportability. Also, the inspector witnessed selected surveillance tests to determine whether properly approved procedures were in use, test instrumenta-tion was properly calibrated and used, technical specifications were satisfied, testing was performed by qualified personnel, procedure details were adequate, and test results satisfied acceptance criteria or were properly dispositioned.

The following activities were reviewed:

SUR 5.7-126, Inservice Inspection of CH-MOV-298 Valve

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SUR 5.7-124, Inservice Inspection of FH-MOV-;35 and DH-MOV-534 Valves

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SUR 5.7-64, No Flow Test of Core Cooling Systems SPL 10.7-346, Preoperational Functional Test of Charging Pump Breaker

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Control Modification PMP 9.8-14, Charging Pump Breaker Trip Test

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Replacement of the No. 3 Reactor Coolant Pump Seal

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Alignment of the No. 3 Reactor Coolant Pump Motor

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4.1 Failure of Charging Pump Suction Valve to Operato Daring routine surveillance testing, on May 2, the isolation valve (CH-MOV-257) in the charging pump suction from the volume control tank (VCT)

failed to close.

SUR 5.7-94, RWST to VCT Pump Suction MOVs, was being performed as a routine, cold shutdown, Inservice Testing surveillance.

When the control switch for CH-MOV-257 was placed in the closed position, the valve it failed to close.

This failure affects the ability to shift the charging pump suction from the VCT to the Refueling Water Storage Tank (RWST) for a safety injectio.

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. Investigation into this failure revealed that a sticking mechanical in-

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terlock_ had inhibited the valve from cycling.

The_ interlock is a West-inghouse Type M-34-1 interlock associated with the motor-uperated valve (MOV) reversing motor contactor.

The interlock had mechanically bound and prevented valve movement.

This device was associated with~a West-inghouse Size 1 motor contactor, Catalogue A211K1JA, Style 276A147001.

t Licensee review indicated that there were approximately fifty (50) safety-related MOVs in the plant with these-interlocks. Six (6) had been changed, along with the associated contactor' assembly, during the re-fueling outage.

For the remaining valves with the old style interlocks, the licensee tested the movement of the interlock.

Besides CH-MOV-257,'

four of these exhibited :ome sluggish movement; their interlocks and contact assemblies were che'

'd to the new style. The licensee is evaluating the necessity ' n ur' er testing or contact / interlock chang-ing for the MOVs with ths a d style interlocks during the next refueling outage.

4.2 Reactor Coelant Pump Seal Replacement The inspector reviewed the. preparations for the replacement of the shaft seals of the Number 3 Reactor Coolant Pump (RCP) and observed portions of the work during the week of May 3.

The No. 2 seal of the No. 3 RCP had been observed to be leaking at about three. (3) gallons per minute since the inii,ial heatup and pressurization of the Reactor Coo! ant System (RCS) at the beginning of this operating'

cycle.

No. 2 seal leakagt is contained by the No. 3 seal and is directed to the Primary Drain Tank (PDT) through the Vapor Seal Head Tank.

This is considered to be identified leakage, limited to a maximum of ten gal-lons per minute by Technical Specification 3.14.A.2.

Seal leakage did not increase during the two months of pump operation.

The licensee developed a new maintenance procedure to direct the work.

CMP 8.5-8, Inspection and Installation of Seals for Reactor Coolant Pumps P-17-1,

-2, -3 and -4, Revision 18 provided a significant upgrade to the content and details of procedures for RCP seal work.

The validation process involved implementation of the procedure on the RCP seal mock-up.

The workers were also trained using the mock-up.

During the seal replacement activities observed, there were no unaccept-able conditions identified. Several defects found in the face of the No. 2 seal accounted for the leakage.

There was no apparent reason found for the damage, which may have occurred during the 1987 refueling / main-tenance outage.

The surface may have been scratched during installation or may have been damaged by foreign material in the nump sea _

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5.

Previous Inspection Findings (92701, 92702)

5.1 Deviation From Emergency Operating Procedures = Generation Package

~(Closed) Deviation (213/87-10-01).

Licensee failure to follow the Writer's Guide Portion of the Procedures Generation Package when de-veloping the new station Emergency Operating Procedures. As a re'sult, although technically adequate, many sections of the.E0Ps do not clearly i

state what operator actions'are required.

The licensee responded to this deviation by letter dated August 5, 1987, as supplemented on December 18, 1987.

Corrective actions described included a human factors review of the procedures and revisions as necessary. These changes, procedure validation and verification, training, and implementation are to be finished approximately three months af ter completion of the review, or by June 11, 1988.

During this inspection period, the inspector observed portions of the validation process on the simulator. The revised E0Ps have been PORC approved and will be implemented by June 11, 1988, after operator retraining has been completed.

This item is closed.

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5.2 Full Closure of Core Deluge Motor-0perated Valves (MOVs)

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(0 pen) Unresolved Item (87-22-05).

Licensee to develop a diverse means

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of assuring full closure of the Core Deluge MOVs (SI-MOV-871 A & B) be-

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fore startup from the refueling outage.

This item was opened after a review of the Pressure Isolation Valves.during the Probabilistic Risk Assessment Based Inspection (213/87-22) in November 1987. These MOVs are not leak tested and are cycled several times during station startup.

The inspectors were concerned that the licensee has no methods to assure full valve closure other than valve motor-operator position indications in the control room.

In response, the licensee developed SPL 10.7-332, Core Deluge MOV Closure Verification.

This procedure details a baseline MOVATs (Motor-0perated Valve Automated Test System) test on the valves

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followed by a leak test to verify closure. Because of valve configura-

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tion, the leak test was conducted with air in the reverse direction.

The leakage measured was well within the acceptance criteria.

Following i-the leak test, four MOVATs tests were performed to determine the average stroke time to full closure for each valve. A final test was performed after reactor reassembly and heatup.

In this manner, the licensee has

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verified full closure by leak testing and developed a baseline time to full closure by MOVATs testing.

The licensee has committed to reperform

the MOVATs portion of this test to verify full closure after valve main-

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tenance which could affect valve operability.

This item will remain open i

j pending licensee development of a method to assure testing is done when

necessary and pending implementation of a permanent procedure for the

testing.

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5.3 Failure to Follow Approved IST Procedures a

l (Closed) Violation (88-01-02) Test personnel failed to completely docu-

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ment test results in sccordance with approved Inservice Test (IST) Pro-

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cedures.

This item was identified during surveillance test observation

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as part of an IST Program Inspection documented in NRC: Inspection Report 50-213/88-01. The licensee responded to the violation by letter. dated April 18, 1988.

Investigation into the violation determined that_the procedure was unclear due to a congested format _and inconsistency in.

where the data was to be recorded. The licensee further explained that surveillance tests are not considered complete until-reviews have been -

performed by the cognizant IST Engineer and Engineering' Supervisor.

Had this omission not been identified during the test performance, it should r

have been identified during subsequent reviews.

Corrective actions in-cluded discussions with operators to emphasize that data taken during these IST procedures must be recorded, and reformatting of the IST and surveillance procedures as part of the current station procedures upgrade program.

This program is scheduled for completion by December 1989 and is being tracked by Unresolved Item 213/88-01-01.

During'this inspection period, the inspectors observed several IST surveillances to verify that test data was appropriately recorded.

No deficiencies were identified; this item is closed.

6.

Events Occurring During the Inspection (61726, 71707, 90712, 93702)

6.1 Licensee Event Reports (LERs) and Safeguards Event _ Reports (SERs)

The following LERs and SERs were reviewed for clarity, accuracy of the

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description of cause, and adequacy of corrective action.

The inspector determined whether further information was required and whether there were generic implications. The inspector also verified that the report-ing requirements of 10 CFR 50.73,10 CFR 73.71, and Station Administra-tive and Operating, and Security Procedures had been met, that appropriate corrective action had been taken, and that the continued operation of the facility was conducted within Technical Specification Limits.

• 88-07 Residual Heat Removal System Not Operating in Mode 5

• 88-08 Zero Power Trip Due to Spurious High Startup Rate

• 88-09 Zero Power Trip Due to Spurious High Start'up Rate

• 88-10 Error Found in Large Break LOCA Analysis 88-11 Surveillance Frequency Exceeded for Overpower Trip Tests 88-S02 Safeguards Event Repoit

• Event detailed in NRC Inspection Report 50-213/87-03

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No unacceptable conditions were identified.

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6.2 Identification of Primary to Secondary Leakage On April 8, with the plant at 80% power, the licansee identified and be-gan trending a primary to secondary ' leak of about eight gallons per day in Steam Generator SG-2.

The Technical Specification limit for this type of leakage is 150 gallons per day.

In accordance with procedures for monitoring such leakage, samples were taken and counted once per shift.

The leak slowly decreased to about two gallons per day on April 29, when the station was shutdown for a planned maintenance outage. The licensee elected not to enter the SG to identify and repair the leak during the outage.

This decision was vased on the small size of the leak, opera-tional experience, and ALARA considerations.

Inservice Inspection Engi-neers stated that a leak this small would be very difficult to locate

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and that, during several previous startups, leaks such as this were identified and monitored for several weeks, at which time they disap-peared. Also, a 100% Inservice Inspection of the SGs was conducted dur-ing the last refueling outage. Any leakage will be monitored during startup from the current maintenance outage.

The inspectors had no fur-

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ther questions.

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6.3 Inadvertent Severance of Diesel Fuel Oil Line On April 12, with the plant at 100% power, during removal of the Service

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Building hallway floor to support New Appendix R Switchgear Building con-

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struction, the diesel fuel oil transfer itne from the fuel oil storage tank to the Emergency Diesel Generator (EOG) fuel oil storage tanks was inadvertently severed by a concrete saw.

The cut line was a common, i

underground supply from the large (42,000 gallons) above ground fuel oil storage tank to the two (5,000 gallons) EDG storage tanks and the two station Auxiliary Boilers, Health Physics and Chemistry personnel re-sponded immediately to assist in containing the fuel oil. Operations

personnel immediately took actions to shut down the operating Auxiliary i

Boiler and its associated transfer pumps.

However, due to line con-figurations, a small amount of fuel oil continued to gravity drain out of the cut line. Operations personnel also isolated the supply line to the EDG fuel oil storage tank to prevent fuel oil contamination.

Con-struction personnel removed the oil from the hallway floor with an ab-so-bent material and set a continuous fire watch.

The Station Fire

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Brigade also responded and were placed in standby to respond if it became necessary.

Notifications were made to the NRC Operations Center.

The area of this spill is of particular concern because this hallway also serves as the cable spreading area for the station.

Both safety and non-safety related cable run from the switchgear room, down through the Ser-l vice Building Hallway, into the cable vault penetration area, and into i

containnent. A fire in this area could severely damage station electri-J cal systems. Also of concern is the limit on the supply of fuel oil to

the EDG fuel oil storage tanks. Both tanks had recently been topped off and contained enough fuel to run both diesels at full load for approxi-mately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,

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Immediately following the event, the licensee developed an emergency action plan to supply fuel oil.to the EDG storage tanks. A temporar/

storage tank-filling arrangemant was developed which required remcving'

a f'xed piping spool piece in each of the EDG fuel transfer systems.

This would provide an opening into each underground tank thrcugh which they could be filled from a portable fuel tank.

This configuration was-

processed as Jumper-Lifted Lead-Bypass No. 88-11. To support this-line bypass, safety evaluations and procedure changes were necessary.

The inspector attended tra Plant Operations Review committee meeting at which these evaluations and procedures were reviewed and noted thorough reviews

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with attention given to security, fire protection, and environmental considerations.

Station maintenance personnel repaired the cut fuel oil line within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the event.

The concrete and oil-contaminated soil was removed and placed in 55 gallon drums for appropriate disposal.

Generation Construction conducted reviews of construction practices in this area.

The licensee had attempted to map the location of buried pipes prior to excavation of the concrete floor with no success.

The fuel oil line was thought to be one foot below grade, saw depth was eight and one half inches.

However, the depth of the line actually decreased where it turned ninety degrees to exit the building.

This was where the line was cut.

In the future, construction personnel are required to set the concrete saw to cut at a depth of six inches in the areas of buried lines, an.1 must use a ground fault interrupter which will stop the con-crete ww upon contact with steel.

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The inspectors followed licensee actions throughout the event and during i

the repair process. They found that the licensee had made an effort to locate the oil line which was known to be buried in the area of the ex-cavation. Although the work in that area has been genera';1y well super-i vised, additional care should have been taken because of the presence of that line. The licensee's response to the cut line was excellent and demonstrated the capability of various individuals and groups to respond

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j to an unusual and potentially threatening situation.

6.4 Control Rod position Indication Anomalies

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During station startup from the refueling outage, the inspectors noted that several Plant Information Reports (PIRs) were written against the Rod Position Indication (RPI) System. The majority of these PIRs re-ported variances in indicated rod position between the digital step counters and the analog RPI in excess of that permitted by Technical Specifications (TS) 3.10.2.2.

There are two independent systems which indicate rod position: step counters and analog position indicators.

The step counters monitor pulses to the control rod lift coils to indicate demanded rod position.

The analog position indication system uses linear variable differential

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transformers (LVDTs) on each control rod housing to indicate actual rod position.

The LVDT supplies signals to the rod bottom-lights, plant computer and digital voltmeter (DVM).

In 1979, NRC requested'that licensees review the specifications for the RPI systems and impose restrictions on operations with misaligned control rods.

These restrictions were to include margin for the' inherent un-certainties in the rod position indication equipment.

This review pre-

cipitated-TS Amendment 47, wnich was issued on March 19, 1982. This amendment created a TS for RPI.

Specifically, all shutdown and control rods must be within 24 steps indicated position of their groups and the

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step counters and analog RPI must be capable of determining rod position within 16 steps while in Modes 1 and 2.

Limiting Conditions-for Opera-tion were also provided, however,-no specific surveillance requirements were stated. The Cycle 15 Reload TS (Amendment No. 97) was issued on November 12, 1987.

This change incorporated Standard TS (STS) format into several sections of TS; including TS 3.10, Reactivity Control.

The specification remained unchanged, but specific surveillance requirements were added. Operations procedures and logs were revised accordingly.

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Through the formalized surveillances of RPI and the PIR process, the licensee has highlighted a chronic problem with the analog RPI system.

Operating experiense has shown that fluctuations in Reactor Coolant Sys-tem temperature can cause variances in the analog RPI system output and the corresponding rod position indication on the DVM.

These changes occur even when there is no rod movement and have made entry into the applicable TS action statement necessary.

The licensee has also postu-lated that induced magnetic fields from control rod lift mechanism operation affect the LVDT output.

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The licensee is currently evaluating possible solutions to this problem.

Until such time as these are implemented, when power manipulations are made, the analog RPI will require frequent recalibration. The inspectors are following licensee initiatives in this area.

6.5 Reactor Trip - April 30, 1988 A reactor trip occurred at 11:30 a.m., April 30 from approximately 57%

reactor power while plant personnel were placing an idle reactor coolant loop in service. Although the control room "first out annunciator" in-dicated that the reactor trip had resulted from a turbine trip, because

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of limited data available to analyze this event, it was not resolved until May 18. The trip had been immediately preceded by the roset of the loop low flow trip and the toggling of the P8 Low Flow Permissive.

These events were included in the licensee's post trip review.

The plant had been placed into three loop operation at 4:45 a.m., April 30 to allow baseline data to be taken with the reactor internals vibra-tion monitoring system. The licensee intended to return to four loop

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operation and then continue with a power reduction and reactor shutdown

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to allow replacement of a Reactor Coolant Pump (RCP) seal. The trip occurred as flow was being restored through the RCS loop and steam began to be drawn from the steam generator.

The licensee determined that trip was due to a false turbine stop valve closure signal.

Investigation found that the linkage between one of the two turbine stop valve position switches was -improperly installed, and the valve indicated closed to the control circuit when it was actually fully open.

The second stop valve position indication went closed as the valve left its full.open position.

These circumstances indicate that the reactor trip was caused as the stop valve position changed slightly during the restoration from three loop operation.

These switches were readjusted and their operation was verified during independent valve operations.

Because the process computer recorded activity within both the No. 4 RCS Loop low flow instrument and the P8 Permissive, these instrument channels were extensively investigated by the licensee. No deficiencies were identified.

However, several days after the investigation, during a subsequent surveillance test of the power range nuclear instrument chan-nels, the P8 Low Flow Permissive Main Board annunciator was observed to come in with only one power range channel's test current above an equivalent 72*i; power.

Sticking relay contacts were found to be the the cause. Although this has not been attributed to be the direct cause of the reactor trip, it may have contributed to the observed toggling of the P8 Permissive prior to the trip.

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The inspectors followed the post trip investigation conducted by the licensee and found it to be thorough and technically detailed.

The in-spectors also concluded that the licensee's efforts would be enhanced with additional points provided to the process computer digital input.

During this event, plant conditions were resulting in changes to the Reactor Protection System (RPS) input which, if recorded, would have enhanced the post trip review.

Examples of valuable information from this event alone are input from Individual turbine stop valve position switches, power range nuclear instrument channel P8 Permissive bistables, and turbine first stage pressure switches.

l The noted sticking contacts are significant.

Similar problems were experienced with relay contacts within the RPS coincidence circuit and the control rod position indication system at the beginning of the operating cycle. Because of plant age, these components may be nearing the end of their reliable lifetime.

The scope of the RPS re-placement scheduled for the next refueling outage should be reviewed by the licensee to assure including components with questionable reliability.

6.6 Discovery of ECCS Single Failure Conditions Report Detail 4.1 addresses a condition where the failure of an electri-cal reversing contactor resulted in the inoperability of a motor-operated valve.

Licensee analysis of that event identified a condition in which

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a single active failure could compromise the availability of charging pumps. The valve (CH-MOV-257) in question is located in the common charging pump suction from the volume control tank (VCT).

Failure of

that valve would affect the ability to shift charging pump suction from the VCT to.the Refueling Water Storage Tank (RWST).

A similar problem was identified with valve BA-M0V-373 in the charging purp suction from the RWST.

The potential implications of this postulated single failure include charging pump failure.

The licensee's current loss of coolant

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safety' analysis relies on these pumps during the recirculation phase.

The licensee's corrective actions were to install a design change which

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will automatically trip the running charging pumps with a safety injec-tion actuation signal. This modification was installed under Plant De-sign Change Record No. 939, following a meeting with the NRC Office of Nuclear Reactor Regulation on May 10. Based on that meeting, the NRC concurred with the modification being being made under 10 CFR 50.59.

The details of the licensee's analysis of the finding and effect of the design changes are contained in their letter dated May 12, 1988.

The modified system was functionally tested under procedure SPL-10.7-346,

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Preoperational Functional Test of Charging Pump Breaker Control _ Modifi-cation. This procedure was reviewed by the inspectors,.who also observed its perfermance.

There were no unacceptable conditions identified.

The licensee also committed to completing an analysis of plant systems for other Emergency Core Cooling System singic active failures and to complete this review prior to reactor startup. This commitment was documented in a letter dated May 13, 1988.

Because this review continued through the end of this inspection period, this issue will be reviewed

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during the next inspection.

7.

Periodic and Special Reports (90713)

Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9 were revie.<ed.

This review verified that the reported in-formation was valid and included the NRC required data, that test results and

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supporting information were consistent with design predictions and performance specifications, and that planned corrective actions were adequate for resolu-tion of the problem.

The inspector also ascertained whether any reported information should be classified as an abnormal occurrence.

The following periodic reports were reviewed:

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Monthly Operating Report 88-03, Covering the Period March 1, 1988 through March 31, 1988 011 Spill Report Submitted to the State of Connecticut Department of

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Environmental Protection, dated April 15, 1988

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Generic Lotter 87-12, Loss of Decay Heat Removal When Reactor Coolant System Partially Drained (92703)

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Generic Letter (GL) 87-12, loss of Decay Heat Removal When Reactor Coolant

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System Partially Filled, was issued to request information from licensees for

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assessment of operations of pressurized water reactors when the reactor cool-ant system (RCS) war.er level is below the top of the reactor vessel.

The principle concerns are whether, in this condition, the Residual Heat Removal-System (RHR) meets the licensing basis of the plant, whether there are any unanalyzed events that may impact safety, and whether there is any further threat to safety which needs to be addressed by the NRC. This matter has previously been discussed in NRC Inspection Report 50-213/87-21.

The GL requested that the licensee provide a description of plant operations during the approach to a partially filled RCS condition and operations with

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the RCS partially filled.

This description was to include specific details

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for nine items listed in the GL.

These items support the plant bases for an approach to mid-loop operations and related issues.

The licensee respended by letter dated September 18, 1987.

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The inspectors reviewed the licensee response and verif" that, for each of the nine items, the information provided was accurate.

.n the response the licensee described the station configuration which permits mid-loop operations to be unnecessary; specifically, Haddam Neck has RCS loop stop valves.

These valves are closed to isolate the loop when maintenance is performed on the Reactor Coolant Pumps or Steam Generators. When maintenance is required on the loop stop valves or valves on the vessel side of the loop stop valves,

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cavity water level is lowered to four inches above the vessel nozzle (18

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inches above loop centerline).

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l In summary, cavity level is rarely lowered to within close proximity of the vessel nozzles.

Licensee calculations indicate that RHR pump cavitation will

not occur when the water level is above the loop centerline. Currently, pro-cedures are in effect for filling and dewatering the cavity and loss of RHR

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under several plant configurations including air binding of the RHR pumps.

The licensee has determined that these procedures are sufficient and that a specific procedure for operations with reduced cavity level is not currently

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necessary.

Currently, there are no requirements for containment integrity

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in relation to operations with reduced cavity levels.

During the last re-fueling outage, the licensee did remove the containment equipment hatch to

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support large component maintenance.

Replacement of the hatch can occur in i

under two hours, as demonstrated during the outage.

Operations personnel have l

received extensive training in operations during shutdown conditions. This

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training has included simulator exercises and review of loss of decay heat removal events at otheas facilities.

Non-operations staff does not receive

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specific training in this area, however, the licensee conducts thorough outage planning and coordination activities to avoid shutdown operational problems due to non-operational personnel activities.

This was successfully demon-strated during the recent refueling outage.

No deficiencies were found in the information contained in the licensee re-sponse to the Generic Letter.

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9.

Prinary Coolant System Pressure Isolation Valves (TI2515/84) (25584)

9.1 Description of Accident Scenario and Documents Reviewed A significant contributor to the risk of a core melt accident'in a PWR is an intersystem loss of coolant accident. This accident has been identified as Event V.

Event V focuses on a failure.of valves which serve as a pressure boundary between the high pressure reactor coolant system (RCS) and lower pressure systems which can lead to a pipe rupture i

of the lower pressure system outside of containment.

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ally calls out two highly susceptible piping configurations: two check'

valves in series, and two check valves in series with a normally-opened motor-operated valve. This classification was later expanded to include all pressure isolation valves (PIVs) which are defined as any two valves in series which separate the high pressure RCS from low' pressure systems.

In 1981, licensees were issued orders for modification of their licenses and Technical-Specification (TS) amendments to include periodic testing, acceptance criteria, and limiting conditions for operation.

During the course of review of Haddom Neck's compliance with the TS amendment, the inspector referred to the following documents.

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Haddam Neck SEP Technical Evaluation Report on Electrical, Instru-mentation and Control Features for Isolation of High and Low Pres-sure Systems, December 27,'1979 Northeast Utilities letter to NRC, dated March 18, 1980, concerning l

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Primary Coolant Isolation Valves

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Haddam Neck Technical Specification Amendment No. 37, dated February

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26, 1981

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NRC letter to Connecticut Yankee, dated September 1,1981, concern-ing SEP Topic V-II.A, Requirements for Isolation of High and Low Pressure Systems Safety Evaluation NRC letter to Connecticut Yankee, dated November 3,1981, concerning

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SEP Topic V-II.A

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NRC Inspection Report 50-213/82-06, dated April 9, 19 a Connecticut Yankee letter to NRC, dated November 5,1981, concerning

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i SEP Topic V-II.A NRC letter to Connecticut Yankee, dated September 30, 1982, con-

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cerning Summary of SEP Differences Connecticut Yankee letter to NRC, dated December 29, 1982, concern-

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ing Systematic Evaluation Program Integrated Assessment

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Haddam Neck Plant Systemrtic Evaluation Program, June 1983

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NRC letter to Connecticut Yankee dated April 5, 1984, concerning Expanded Integrated Assessment for Haddam Neck Connecticut Yankee Prebabilistic Safety Study, February 1986

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NRC Generic Letter 87-06, Periodic Verification of Leak' Tight In-

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tegrity of Pressure Isolation Valves, March 13, 1987 NRC Inspection and Enforcement Manual Temporary Instruction 2515/84,

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Verification of Compliance with Order for Modification of License:

Primary Coolant System Pressure Isolation Valves, April 6,1987 Northeast Utilities letter to NRC, dated June 17, 1987, Response

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to Generic Letter 87-06, Periodic Verification of Leak Tight In-tegrity of Pressure Isolation Valves

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Haddam Neck Plant Draf t Integrated Safety Assessment Report, July 1987

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Connecticut Yankee Third Ten year Interval Inservice Test Pump and Valve Program Submittal, January 1, 1988

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Current Haddam Neck Technical Specifications 9.2 Initiatives to Assure Valve Operability SEP Topic V-II.A was initiated in 1977 and identified the Requirements for Isolation of High and Low Pressure Systems.

This topic' concerned

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the necessity of redundancy and interlocks for PIVs located in the High Pressure Safety Injection (HPSI) and Low Pressure Safety Injection (LPSI)

Systems.

The issue was complicated by the fact that the safety function of these values is to open in event of an accident.

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In February, 1980 NRC requested the licensees to provide information regarding Event V valve configurations and associated surveillance or periodic testing.

Haddam Neck responded that an evaluation of plant

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systems identified no Event V valves but did identify 18 PIVs.

These

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are in the Residual Heat Removal (RHR), LPSI, HPSI, and RCS Loop Drain i

Header Systems.

Check valves in series with a normally-closed motor-operated valve (MOV) are located in the LPSI and HPSI systems, the other systems contain only series MOVs.

i The PIVs were added to the station Inservice Testing (IST) Program by

TS Amendment No. 37 in February 1982.

The TS Amendment specifically

limits the leakage through the LPSI and HPSI check valves to one gpm and details leak testing frequencies.

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Because of the severe consequences of a.LOCA outside of containment, the

. licensee agreed, in December 1982, to install pressure interlocks.on the LPSI and HPSI MOVs during the 1984 refueling outage.

This modification, along with the valve testing provided by the IST program, would satisfy SEP Topic V-II.A.

This proposed solution was documented in the SEP Final Report issued June 1983.

Before the start of the 1984 Refueling Outage, the licensee initiated the Integrated Safety Assessment Program (ISAP).

This program was de-veloped to establish implementation schedules for outstanding safety issues.

The licensee requested, and NRC approved, a temporary relief from the original commitment of installing the interlocks on the.PIVs during the 1984 outage. This modification has been incorporated into the ISAP schedule and is identified as ISAP Topic No.1.02, High/ Low Pressure Valve Interlocks.

As part of the ISAP evaluation, the licensee factored in information from the Probabilistic Safety Study (PSS) published in February 1986. The r

final ISAP report, published in July 1987, concluded tha'. the implemen-

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tation priority for installation of the interlocks is medium. This de-cision was based on the PSS conclusion that the addition of these inter-locks would increase the core melt frequency (CMF) by 1E-5 per year.

The increased CMF is because~, with these valve interlocks, safety injec-tion system unavailability is greater than the reduction in CMF with a LOCA outside containment. hRC review of these calculations concluded thr.t the unavailability factor assumed by the licensee was overconserva-tive. However, the staff 1. greed with the licensee's rating for this topic as medium in implementation priority.

In March of 1987, NRC is',ued Generic Letter (GL) 87-06, Periodic Verif t-cation of Leak Tight In'.egrity of Pressure Isolation Vaives.

This letter requested licensees to submit a list of all PIVs in the plant.

For each valve listed, the licensee was to include a description of any periodic tests or other measures to assure valve integrity, leakage. acceptance criteria, and frequencies of testing.

The licensee responded by letter dated June 17, 1987. The inspector reviewed this letter and verified that the information provided was accurate, 9.3 Surveillances and Test Practices

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Of the 18 PIVs at Haddam Neck, the inspector chose two valves in each if the LPSI and HPSI systems to review surveillance practices and test

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results.

These valves are SI-MOV-8618 and SI-CV-862B of the HPSI system, and SI-MOV-871A and SI-CV-872A of the LPSI/ Core Deluge system.

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SI-MOV-8618 is the Loop 2 HPSI isolation valve.

It is normally closed and during plant operation it sees full RCS pressure.

The IST program specifies that this valve is stroke tested and leak tested with visual verification of valve position at least every two years.

TS 4.3-B.3

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requires that the valve open within 15 seconds.

The valve is also a containment isolation valve and is subject to testing in accordance with 10 CFR 50 Appendix J.

SI-CV-862B is the Loop 2 HPSI check valve located immediately upstream of SI-MOV-8618.

The valve is normally closed and is subject to flow testing and leak rate testing., This valve is also a containment isola-tion valve and is tested accordingly.

SI-MOV-871A is the core deluge to the reactor vessel head isolation valve.

This valve is normally closed and sees full RCS pressure.

The IST program requires only valve stroke testing.

It is physically im-possible for a leak test to be performed because of piping configuration on the reactor vessel head and because the valve is welded to its up-stream check valve.

SI-CV-872A is the core deluge to the reactor vessel head check valve; it is upstream of the isolation valve.

Flow testing and leak testing are required by the IST program.

The inspector reviewed the surveillance tests for these four valves con-ducted during the past four years.

These are as follows:

SUR 5.1-1, Hydrostatic Test

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SUR 5.7-64, No Flow Test of Core Cooling Systems

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SUR 5.7-65, Safety Injection, P-3

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SUR 5.7-106, Full Flow Test of HPSI and LPSI Systems

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SUR 5.7111, Core Deluge Check Valves 872 A&B Leak Test

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SUR 5.7-135, HPSi and LPSI Discharge Check Valve Operability Test In addition, the inspector observed conduct of SUR 5.7-64 on May 2, 1988.

The results were satisfactory.

During review and observation of these tests, the inspector verified that an acceptable test method was used, leak rates were measured for indivi-dual valves where possible, the acceptance criteria specified in the tests agreed witn TS requirements, tests were conducted at the required frequencies, and that adequate corrective actions were taken when test results were unsatisfactory.

The inspector noted that test data was easily retrievable from Nuclear Records.

No deficiencies were identified.

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10.0 Natural Circulation Cooldown - Implementation of Generic Letter 81-21 (MPA-8-66) (Tl 2515/86) (25586, 42700)

10.1 Requirements Associated with Natural Circulation Cooldown

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While St. Lucie 1 was cooling down under natural circulation on June 11,

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1980, flashing of coolant produced a void >in the reactor vessel upper

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head, forcing water into the pressurizer. The reactor was taken-to cold o'

shutdown. Multi plant action item (MPA) B-66 was-developed by the NRC to assure that all pressurized water reactors (PWRs) implement procedures and training' programs to deal with this event. NRC Generic Letter 81-21, dated May 5, 1981, requested licensees to assess facility procedures and

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training program, to include the following:

Demonstration that controlled natural circulation from operating

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conditions to cold shut down conditions, conducted in accordance l

with plant procedures, should not result in reactor vessel voiding.

Verification that supplies of safety grade auxiliary feedwater. are

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sufficient to support plant cooldown.

Description of plant training programs and emergency procedures that

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prevent or mitigate reactor vessel voiding.

The inspectors reviewed the licensee's response and implementation of procedures and training for Natural Circulation Cooldown (NCC).

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10.2 Licensee Response and Actions Taken

By letter dated August 4,1983, NRC issued a Safety Evaluation (SE) of i

the licensee's responses to Generic Letter 81-21, dated November 19, 1981

and June 9, 1982.

The SE concluded that-upper head voiding is not a safety concern at Haddam Neck provided that the operator has adequate training and is knowledgeable in the appropriate procedures.

The licen-see was requested to confirm that the training program addressed the following items identified in the SE.

How voiding occurs anC the safety significance of its consequences;

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Signs that voidir.g is occurring;

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The St. Lucie event; and,

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Discussion of applicable procedures.

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This confirmation was provided by CYAPCO's letter of September 27, 1983, stating that all four items are covered during licensed operator training, the licensed operator upgrade courses, and the licensed operator two year i

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requalification cycle.

Classroom training is evaluated by written ex-aminations, and by independent oral examinations (in the case of R0 and SRO, upgrade training courses).

On September 26, 1981,-a two-hour plant NCC test, commencing 10.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after shutdown, demonstrating the cooling of the Reactor Coolant ~ System (RCS) (as measured in the cold leg) from 527 degrees F to 480 degrees F and the reactor-vessel head from 536 degrees F to 497 degrees F, under Special Operating Procedure, SPL 10.1-13. No indications of a steam bubble in the vessel head were seen.

This test provided beneficial operator training, NCC procedure checkout, and response data for toe NCC event.

10.3 Licensed Operator Training The inspector reviewed training records and confirmed that NCC training was initiated for operators in 1981 by a contractor (General Physics).

The licensee's training staff has provided NCC training from 1982 to the present. The 1981 and 1987 lesson plans were reviewed.

Both showed l

coverage of NCC in theory (core cooling mechanics), St. Lucie event, and modes of NCC (loss of all power, etc.).

Emergency Operation Procedures

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(EOPs), including the symptoms based Emergency Response Guidelines (ERGS),

l were covered in the 1987 training.

The inspector compared an operation department's listing of all licensed R0s and SR0s with training attendance records for 1987.

Eight indivi-duals completed their R0/SR0 qualification program, receiving NCC train-ing in the licensing program.

The other R0s and SROS received NCC training under the requalification program.

The inspector interviewed training department personnel to determine if the training program is contains adequate information on NCC.

In this area, the Licensing Program consists of the following.

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Classroom Phase - Lesson Plan CY-LO-HTFF-L65015, Partial Loss of Flow / Natural Circulation Cooldown, using A0P 3.2-30 is covered during week 8 of R0/SRO Qualification Training.

Briefing Room - Lesson Plans CY-0P-LO-MITCOR-L75002 and L75008,

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Natural Circulation Cooling Basis including St. Lucie Event using E0Ps (ERG), and Natural Circulation Cooldown Background / Basis / Pre-

ventive Maintenance, respectively, are covered during week 41 of Qualification Training.

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Simulator Phase - Simulator Lesson Plan 32, Loss of All AC (1,clud-ing NCC), using ES-0.2 is covered during week 43 of Qualification i

Training.

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The inspector also confirmed that NCC is covered during the biannual requalification training. NCC theory is presented under thermodynamics and NCC E0Ps under Plant Procedures and TS. The St. Lucie Event is covered, without naming the reactor, during the Loss of All AC simulator exercise.

One shortcoming of the requalification training was identified. During interviews of R02 and SR0s on duty, the inspector discovered that, al-though the crew was well trained in use of the ERG - E0Ps, they were much less familiar with A0P 3.2-30, Natural Circulation of RCS.

This A0P is to be used if all RCPs are lost with the reactor shutdown and no Safety Injection is required.

The training staff confirmed that training on A0P 3.2-30 has not been given for the last few years.

They have been concentrating on the new E0Ps.

This issue remains open along with a related issue discussed below.

10.4 Er rgency and Abnormal Operating Procedure Review During this inspection period, the resident inspector observed selected portions of E0P validation at the simulator. The validation process was done for several E0Ps which have undergone major revisions as part of the station procedure upgrade effort and in rasponse to a deviation cited in NRC Inspection Report 50-213/87-10.

The validation process included a demonstration of NCC with the newly revised E0Ps. The licensee is currently conducting E0P training.

The new format highlights the cau-tions and notes and includes other human factor engineering items. Review of the new E0Ps will be the subject of future inspections.

During this review, a discrepancy between station procedures was identi-fied.

The content of A0P 3.2-30 differs from ES-0.2, ES-0.3, and ES-0.4.

For example, A0P 3.2-30 requires that Steam Generator (SG)

levels be maintained at 25% (narrow range), RCS pressure be between 2000 and 2050 psig, and Pressurizer (PZR) level be slightly above 25%. However, the ES-0 Series require SG levels to be maintained between 63% and 69% (wide range), RCS pressure be between 1720 and 1800 psig, and FZR level between 25% and 50%.

These are a few of the differences that could mislead the operator.

In addition to these differences, A0P 3.2-30 lists Reactor and Turbine Trip when above the P-7 permissive as an automatic action.

This A0P should not be used since E-0 covers actions to be taken when the Reactor Trips.

The inspector interviewed one SR0 who was unaware that AOP 3.2-30 still existed.

The inspector reviewed the index of A0Ps and old E0Ps (those not replaced by the new E0Ps) and found several A0Ps and old E0Ps that are closely related to the new E0Ps, and one other old E0P (EOP 3.1.-12, Emergency Boration) which needs upgrading. When the inspector brought this to the attention of plant management, the commitment was made to revise A0P 3.2-30 and E0P 3.1-12 to make them consistent with the ES-0. series.

This issue remains unresolved pending revision of the two outdated pro-cedures and assurance that other remaining procedures are in agreement

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with the ERG, The training problem identified is also considered a part of this unresolved issue since training on A0P 3.2-30 will be necessary after it is revised (UNR 88-08-01).

10.5 Summary Overall, the inspector found that the licensee has effectively imple-mented training and procedures for Natural Circulation Cooldown. Aside from the unresolved issue above, the inspector had no further concerns.

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Exit Interview During this inspection, meetings were held with plant management to discuss the findings. No proprietary information related to this inspection was identified.

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