IR 05000213/1987025

Safety Rept 50-213/87-25 on 870826-1008.No Violations Noted. One Unresolved Item Identified.Major Areas Inspected:Plant Outage Activities,Radiation Protection,Fire Protection, Security & Licensee Events

ML20236J032
Person / Time
Site:	Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png
Issue date:	10/26/1987
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20236J008	List: IR 05000213/1987025 ML20236J005
References
50-213-87-25, IEB-85-003, IEB-85-3, IEIN-86-106, IEIN-87-001, IEIN-87-036, IEIN-87-1, IEIN-87-36, NUDOCS 8711050105
Download: ML20236J032 (31)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /87-25 Docket N License N DPR-61 Licensee: Connecticut Yankee Atomic Power Company P. O. Box 270 Hartford, CT 06101 Facility: Haddam Neck Plant, Haddam, Connecticut Inspection at: Haddam Neck Plant Inspection dates: August 26, 1987 through October 8, 1987 Inspectors: William T. Russell, Regional Administrator  !

Andra A. Asars, Resident Inspector John T. Shedlosky, Senior Resident Inspector Eben L. Conner, Project Engineer Stanley D. Kucharski, Resident Inspector, Limerick 1 Anthony A. Weadock, Radiation Specialist Approved by: db 6. da dA , b to /26/e'7 E. C. McCabe, Chief, Reactor Projects 1B Date Summary: Inspection 50-213/87-25 (8/26/87 - 10/8/87)

Areas Inspected: This was a routine safety inspection (395 hours0.00457 days <br />0.11 hours <br />6.531085e-4 weeks <br />1.502975e-4 months <br />) by resident and region-based inspectors. Areas reviewed included plant outage activities, radiation protection, fire protection, security, maintenance, surveillance testing, licensee events, open items from previous inspections, plant design changes, and diving evolution Results: No violations were identified. One unresolved item was opened relating to the omission of commitments in the Emergency Operating Procedures when the procedures were rewritten in symptom-oriented format (Detail 13.a.).

8711050105 871028 PDR 4 DOCK 05000213 G PDR

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TABLE OF CONTENTS Page

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. S umma ry o f Fa c i l i ty Ac t i v i ti e s . . . . . . . . . . . . . . . . . . , 1

. Review of Plant Operations . . . . . . . . . . . . . . . . . . . . . 1 Plan Operations Review Committee ................. 3 Observation of Maintenance and Surveillance Activities . . ..... 3 4.1 Containment Integrated Leak Rate Test ............. 4 4.2 Emergency Core Cooling Flow Test . ............... 8 4.3 Reactor Pressure Vessel Shell Inservice Inspection . . . . . . . 9 4.4 Reactor Core Support Barrel Inspections and Repair . ...... 10 4.5 Replacement of the Reactor Protection System Instrumentation . . 11 Followup on Previous Inspection Findings . . . . . ........ 12 5.1 Inadequate Breaker Coordination . ............... 12 5.2 Uncontrolled Tagging System for Equipment Out of Service ... 12 5.3 Inadequate PORC Review of PORCs . . . . . . . ......... 13 5.4 Breach of Containment Integrity During Surveillance Testing . . 13 5.5 Unauthorized Opening of Containment Isolation Valves ..... 14 Followup on Information Notices and Bulletins ........... 15 Followup on Events Occurring During the Inspection . ........ 16 Review of Periodic and Special Reports . . ......... ... 16 Reactor Coolant System Support Modifications . . . ......... 17 I

1 Snubber Inspection . .... .................... 18 l l

1 Rod Cluster Control Assembly Replacement . ...... ...... 19 j 1 Cycle 15 T-Average Increase .................... 20 13. Motor-Operated Valve Testing (IEB 85-03) . . . . ......... 21 14. Motor-Operated Valve Overload Protection Upgrade . .......,. 23 !

1 Feedwater Mot or-Operated Valve Replacement ..... .. ... 24 1 Control AS1 Containment Instrument Air Modifications . . ...... 24 1 Regional Administrator Inspection ................ 25 18. Ground Water Inleakage into Cable Vault .. ........... 25 1 Radiological Controls During Diving Evolutions . . . . . . ..... 26 l 2 Exit Interview . . ........ ....... ......... 27 i i l

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DETAILS Summary of Facility Activities The reactor was shutdown, with all fuel removed, for a refueling and maintenance outage during this entire inspection period. That outage started on July 18. Major activities included: inspections of the reactor vessel and the core support barrel and repair of the vessel thermal shield attachment devices; inspection of steam generator tubes and plugging of defective tubes; installation of replacement instrument channels as part of an upgrade -to the Reactor Protection System; and completion of a containment integrated leak rate tes . Review of Plant Operations The ins'pectors observed plant activities and conditions during regular inspections of the following plant areas:

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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 Building Control room instruments meaningful in this plant condition were observed for correlation between channels and for conformance with Technical Specification requirements. The inspector observed various associated alarm l conditions which were received and acknowledged. Operator awareness and '

response to these conditions were appropriate. Control room and shift manning were compared to regulatory requirements. Posting and control of radiation and high radiation areas was inspected. Compliance with Radiation Work Permita and use of appropriate personnel monitoring devices were checked. P; ant housekeeping controls were observed, including control and storage of flammable material and other potential safety hazards. The inspector also examined 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 l included operating logs, turnover sheets, tagout and jumper logs, process computer printouts, and Plant Information Report The inspector observed  !

selected aspects of plant security including access control, physical '

barriers, and personnel monitoring. In addition to inspection during normal working hours, the review of plant operations was conducted during the following midnight shifts, weekends, and holiday >

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September 18, 1987 3:00 AM to 6:00 AM September 26, 1987 8:00 AM to 5:00 PM September 27, 1987 8:00 AM to 3:30 PM October 5, 1987 1:00 AM to 6:00 AM No unacceptable conditions were identified. Operators were alert and displayed no signs of inattention to duty or fatigu . Plant Operations Review Committee (PORCJ The inspectors attended several Plant Operations Review Committee (PORC)

meeting Technical Specification 6.5 requirements for required member _

attendance were verified. The meeting agenda included procedural changes, proposed changes to the Technical Specifications and field changes to design change packages. The meetings were 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 commen Olssenting opinions were encouraged. The inspectors had no comments on the PORC meeting . Observation of Maintenance and Surveillance Testing The inspector observed various maintenance and problem investigation activities for compliance with requirements and applicable codes and standards, QA/QC involvement, safety tags, equipment alignment and use of jumpers, personnel qualifications, radiological controls, fire protection, retest, and deportability. Also, the inspector witnessed selected surveillance tests to determine whether properly approved procedures were

> in use, test instrumentation 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 dispositione The following activities were reviewe l SUR 5.7-57, Air Monitor Sample to Containmen SUR 5.7-108, Containment Integrated Leak Rate Tes SPL 10.7-298, ECCS Flow Testing - Injection Line Balancing and Short Term l Recirculatio SUR 5.1-18, Test of Emergency Diesel Generator EG-2A with Partial Loss of AC Coincident with Core Cooling Actuatio ,

I Inservice Inspections of:

Reactor Vessel shell weld area Steam Generator tube Reactor Core Support barrel and Thermal Shield attachment l

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Maintenance and modifications:

Steam Generator tube pluggin Replacement of Core Support barrel / Thermal Shield attachment bolt Replacement of the Reactor Protection System instrumentation syste Low pressure' turbine replacemen .1 Containment Integrated Leak Rate Test (CILRTJ Documentation Reviewed

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CILRT valve lineu CILRT related Technical Specification SUR 5.7-108, Containment Integrated Leak Rate Test, Revision 4, September 18, 198 PMP 9.2-88, Calibration of Foxboro Platinum Resistance Temperature Detector ~

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PMP 9.2-87, Calibration of Foxboro Dewcell Elemen '.

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Report of Calibration for Heise Pressure Gage, Model Type er - ,*~

PPG-149, Serial No. 1003/5974, June 10, 198 .~

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Report of Calibration for Heise Pressure Gage, Model Type P PPG-149, Serial No. 1004/5976, June 10, 1987 an Calibration data for flow meters, Serial Nos. 8119-1, 8119-2, September 10, 198 Scope of Review The inspector reviewed the above listed documentation for technical l adequacy and to ascertain compliance with the regulatory requirements )j of 10 CFR 50, Appendix J, Technical Specifications, and applicable industry standards. The inspector witnessed activities related to I the CILRT and the subsequent verification tes Procedure Review The inspector reviewed the documentation for technical adequacy and for consistency with regulatory requirements, guidance and license _

commitments. Review of the procedure acceptance criteria, test )

methods and references found conformance with 10 CFR 50, Appendix The inspector reviewed the valve line-ups for piping penetration This review was to ensure that systems were properly vented and drained to expose the containment isolation valves to containment )

atmosphere and test differential pressure with no artificial l boundaries. No unacceptable conditions were identifie {

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The inspector reviewed the calibration records for the resistance temperature detectors (RTDs), dew point instruments, precision pressure detectors, and the verification test flow mete The

, calibrations prior to the CILRT were found to meet the applicable

'. accuracy. requirements and were traceable to the National Bureau of Standards. No unacceptable conditions were identifie CILRT Chronology Date Time Activity 9/22/87 1433 Commenced pressurization of containment with eight air compressors in operatio Shutdown one compresso Heatup rate was too fast. Operations was notified to reduce flow rat Back pressure set to 90 lbs by throttle inlet valve (V497). Temperature rise is 2.2 degrees F/ hou Shutdown three more compressors, to maintain backpressure at 90 lb A high containment pressure alarm was received at 3 psi psig containment pressure alarm sounde /23/87 0300 Checked containment outer l boundary for leakage at 23 psig. No l leaks identifie l 1318 Reached test pressure of 41.741 psi l 1319 Secured compressor Initialized temperature stabilization, 9/24/87 0843 Commenced CILR Recommendation to shutdown Containment Air Recirculation (CAR) fans because of containment temperature ris l

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1455 CAR fans isolate )

1500 Start temperature stabilizatio ,

1900 Commenced CILR, /25/87 0105 Operations to perform a penetration inspection for signs of leakage No significant leaks were foun Operators performing walkdowns of secondary plant system checking for possible leak Removed dewcell #3 from calculatio Dewcell #4 was reweighted, f

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1059 All dewcells dropped readings about 15 degrees All dewcells out of rang Power to  !

the dewcells tripped on HP 9826  ;

compute Power restore l 1159 All dewcells back to original tren !

1600 Operations found a leak in seal water syste No adjustments have been mad Operations isolated seal water supply i

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valve /26/87 0215 CILRT restart commence /27/87 0530 Completed CILRT (24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> test)

1004 Establisher' an imposed flow rate of 10.1 SCFM which decayed to 9.8 SCFM, which is still within bound Started verification tes Completed data collection for verification tes /28/87 0235 Commenced depressurizatio _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ -

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Test Performance / Control The test was performed within the guidelines of the procedur Procedural precautions were adhered to, especially those that related to manipulation of containment boundaries during testing. Two problems caused the test to be restarted twic ,

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The first problem dealt with the continual rise of the containment air temperatur The licensee discovered an increase in service water temperature which in turn caused an increase in containment air temperature due to the running of the CAR fan The fans were isolated and the test was restarte The second problem was that, because the rise in temperature in the containment causes an increase in pressure, leaks may be masked. Once the CAR fans were stopped the licensee noticed a containment pressure decrease which indicated a leak. The licensee found the leak and proceeded according to tne procedure by isolating the leak and perform-ing a leak tes This was performed adequately and in conformance i with the regulation No unacceptable conditions were identifie ;

Test Results Review The licensee evaluated the test results for the September 26 - 27, l 1987, 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> CILRT period (0215 on the 26th to 0530 on the 27th). l The calculated leakage rate at the upper confidence limit was 0.0789 weight percent per day for the mass point calculation and 0.082 weight percent per day for the total time metho The test ,

acceptance criteria based on 0.75 La is 0.135 weight percent per da {

The CILRT was followed by a successful superimposed leak verification tes The licensee imposed a leak of 9.03 SCFM or 0.1609 weight percent per day on the existing overall leakage. The test results were within the acceptance criteria band which are as follows: Mass Point Band 0.1936 < 0.261 < 0.2836 Total Time Band 0.1952 < 0.229 < 0.2852 No unacceptable conditions were identifie l l

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-Facility Inspec. tion-Tours

The inspector._ conducted inspection tours independently and with

. licensee personnel before and'during the CILRT. During these-

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tours, the inspector observed activities in progress, implementation-of radiological controls, and the general condition _of safety-related 1'

Lequipment.- In addition, the inspector examined.the containment system boundaries, component tagging, and CILRT instrumentation. During_these j c tours the inspector. observed liccasee personnel checking for evidence i of. leakage and ' verifying selected valvos to be in the correct position 1-according to procedural requirement ~ ~ ~ ~ ' '

No _ unacceptable conditions were identifie .2 Emergency Core Cooling System Flow' Test The. inspectors witnessed SPL 10.7-298 flow testing of the Emergency Core _

Cooling System (ECCS) on September 29. The' flow test was part of the l post modification testing for the ECCS modifications made under Plant Design Change Record (PDCR) 85 This change installed piping and associated valves to prov1de a flow path from the discharge of the 9

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Residual Heat Removal (RHR)_ and Low- Pressure Safety Injection (LPSI)

. pumps' discharge to the suction of the High Pressure Safety. Injectio (HPSI) pumps. . Also installed were four globe valves to' throttle HPSI j flow to' the Reactor Coolant System'(RCS). During' the test, the globe

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valves were' to _be ' positioned and a four_ loop flow test run to verify  !

adequate total flow to.the,RCS. The licensee had planned to measure loop flow with ultrasonic measuring equipment downstream of the new globe valves,, at the RHR to HPSI crosstie and at the HPSI suction lin .i During; test performance, the measuring equipment downstrean of the globe valve was not used because excessive noise produced indicated .i instrument faults. This had been anticipated.and alternate testing methods using the other two instrument locations had been included in the procedure. 'This test required that the loop flows be adjusted 4 individually and.then two path verification be performed. After each

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. loop was tested it was to be isolated by the motor-operated valve  !

(MOV) downstream of the globe valves. Then, the globe valves were to be secured in.their throttled position However, when the test was performed, the MOVs would not close against system pressure. Test personnel elected to record the indicated position of the globe valve in the lef t-hand margin of the procedure, then close the globe valve and the associated MOV. All four loops were balanced in this manner. The four loop flow test conducted to verify that the globe l valve' positions allow adequate flow to the RCS was successful, l

After the flew balancing portion of the orocedure was completed, Temporary Procedure Change (TPC)87-421 was issue The TPC corrected several typing errors, added the requirements to record globe valve position indication, added steps to cycle the globe

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m valves;for'NOV closure, and added restoration steps for the globe valves. The inspector reviewed the TPC and noted..that the new steps,

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, =a dditional sign-offs, and data-table. modifications were not made in the-body of'the procedure. -This situation made the TPC an academic exercise. .The.necessary sign-offs for additional valve manipulation

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.and position recording were:not incorporated into the procedure until after the'related portion of the test'was complet ;

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In conjunction with this concern, tile inspector reviewed ACP 1.2-6.4, a '

Temporary Procedure Change, Revision 20. This procedure governs the changes to procedures and does not specify- that changes be. reflected-in the body.of.the procedur _

i Following the. review of the TPC by' station management, it was deter-

-mined-that.reperformance.of this test was prudent to verify globe u nve positions. <The inspectors reviewed the new procedure revision

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and had no furtoer concerns. At the close of the inspection period, the ; flow retest had not yet been performe I 4.3 Reactor pressure' Vessel Shell Inservice' Inspection '

The Reactor Pressure Vessel-Inservice Inspection program for this outage was initially addressed in NRC Region I inspection 50-213/87-2 The-inspector'noted that, because of.a change in'the governing ASME Boiler.and Pressure Vessel (B&PV) Code requirements between the

.first and second ten year inspection intervals,100% of ~the beltline welds were not examined as was. implied in the later code. The firs > ten year inspection interval was performed to the'1974 Edition through Summer 1975 Addenda, The second ten year. interval was performed to the 1980 Edition up to and including the Winter 1980 Addenda. The earlier code required 10% of the length of each longitudinal weld and 5% 'of the length of each circumferential weld to be inspecte The 1980 l Edition of the code requires 100% inspection of all beltline welds in the first inspection interva Since the Haddam Neck plant reactor vessel was inspected to the earlier code edition during the first ten year inspection interval, it had never received the full inspection assumed by the 1980 Editio Based on these inspection findings, the licensee elected to increase the scope of the current outage inspections. The expanded inspection program included examination of all pressure vessel circumferential weld areas except the lower hemispheric aad disc to peel segment wel All longitudinal welds were also included except for five of the six l meridian welds of the lower head. The licensee's action produced a ^

significant increase in reactor vessel inservice data.

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There were.no defects identified for the reactor vessel by the i ultrasonic data analyzed through the conclusion of this inspectio l The inservice test report far this outage will be addressed in a '

future NRC intpection. Thete were no unacceptable conditions identifie .4 Reactor Core Support Barrel Inspections and Repair )

The inservice inspections scheduled for this refueling / maintenance outage included examinations of the Reactor Core Support Barre Following the removal of that assembly, several defects in the i Thermal Shield attachments were observed. Also, debris was found in '

the bottom of the Reactor Pressure Vessel, The debris has been recovered and matched with material missing from the core support barrel. Damaged areas include one holder for surveillance samples of vessel material and the thermal shield support block attachment bolts and pins. The debris included a surveillance holder guide frame and material from three of the attachment bolt Initial inspection also noted that three dowel pins were partially backed out at the thermal shield attachment point The thermal shield is a stainless steel cylinder located outside of the core support barrel. The shield is supported on six (6) blocks which are positioned in recesses on the outside surface of the core support barre Each block is attached to the core support barrel with five (5) one-inch bolts and three (3) dowel pins. Each of those devices was provided with locking welds. The design of the block is such that two (2) of the bolts are not accessible from the outside of the thermal shield. They were in place prior to assembling the thermal shield onto the core support barre l The repair process being implemented by the licensee consists of replacing all eighteen (18) accessible bolts (three per support block) and fc';r (4) of the dowel p' ins. The pins to be replaced include three (3) which were found partially backed out during the initial inspection and one (1) pin with a defective seal weld. At the conclusion of this inspection period ten (10) bolts were successfully replaced. Five (5) bolts were removed, however a frat'ent of broken t bolt material approximately S/8 inch long remains in the core barre Three (3) of the original bolts have not been removed because of defects in the bolt head. The licensee has special tooling available and is presently working to remove pins, bolts and bolt fragment The licensee has inspected the core barrel / thermal shield attachment points from both the inside and outside of the core barre From visual and ultrasonic inspections it was determined that all of the installed dowel pins are intact. Also, the ligament area of the core t's trel j between the bolts and pins was examined '

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ultrasonically and no defects were found. However, all twelve (12)

of the inaccessible bolts are defective. They were found broken t approximately 5/8 inch from the end of the bol Those bolts are not-accessible with the thermal shield in place. The licensee expects to restore the thermal shield attachment supports to their original configuration with the exception of these bolt The disposition and/or replacement of those hidden belts along with the failure analysis remains to be completed prior to reactor restar These issues will be followed during future on-site inspection The inspectors have observed various phases of the inspection, investigation and repair process. Radiological controls have been of particular interest because of the significant source. The inspectors found that the preparations for work activities and the centrols exercised during those activities were acceptable. The radiological aspects of these activities are also addressed in Detail 19 of this repor .5 Replacement of the Reactor Protection Systam Instrumentation A modification to modernize the Reactor Protection System and the Reactor Control System was commenced this outage. The scope of this design change included the replacement of the original plant equipment for Pressurizer Pressure, Pressurizer Level, Reactor Coolant System (RCS) Differential Pressure, RCS Average Temperature, RCS Wide Range Temperature, High Pressure Steam Dump, and Charging Flow. Included was the replacement of transmitters, signal conditioning equipment, bistables, isolation devices, process computer interface equipment, Main Control Board control stations, displays and recorders, and control room wirin The inspectors reviewed the scope of the modification as described in Plant Design Change Record (PDCR) 861, the 10CFR Part 50.59 evaluation, and its supporting safety analysi There were no unacceptable conditions identifie Because of the extent of this design change, however, the NRC Of*1ce of Nuclear Reactor Regulation is currently examining the modification in several areas including equipment qualification, failure modes, and microprocessor software verification and validatio Work in progress during installation of this equipment was reviewed during this inspectio Review of equipment calibration and testing will be addressed during a future inspectie _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ -

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5. Followup on Previous Inspection Findings 5.1 Inadequate Breaker Coordination (Closed) Violation (86-17-06) This violation involved deficiencies in the test results for the 480 volt breaker (D8-25) from Bus 5 to the metering charging pump (P-11-1A). The breaker test procedure, PMP 9.5-17, DB-25 Breakers, Rev.10, did not require a comparison of the test results with the desired trip settings required by engineering. The licensee had committed to review and revise the procedure to conform to the breaker coordination study before repecting the tes The inspector reviewed Revision 11 of PMP 9.5-17 and verified that it contains the desired trip setting The licensee action on this issue is completed and the inspector had no further questions.

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5.2 Uncontrolled Tagging System for Equipment Out of Service (Closed) Inspector Follow Item (86-15-05). A controlled tagging system did not exist for identifying equipment which was out of servic In the interim, operators were using uncontrolled notes to serve as personal reminders of equipment conditions. In response, the licensee initiated the Trouble Reporting System, controlled in accordance with ACP 1.2-5.1, PMMS Trouble Reporting System and Automated Work Order (AWO). The inspector reviewed the applicable portions of the procedure to verify that this system adequately identifies out of service equipment. Also reviewed were tagging practices in the plant to verify adherence to this procedure. The inspector noted several minor deficiencie Several tags surveyed were exposed to harsh environments, inside and outside plant buildings, and had become weathered and illegible because they were not protected. Information provided on the tags was not consistent; some listed equipment numbers, some names or descriptions of equipment, and several contained problem descriptions which were vague. Attempts to verify that the necessary AW0s had been issued in j response to these Trouble Reports (TRs) showed that the process of j correlating between the TR and PMMS systems is complex. When an operator !

hangs a TR tag, the bottom portion of the tag is returned to the Control Room where a TR number (which is different from the sequential numbers on the tags) is issued and entered into a computer. If the operator does not go back to the tag and record this TR number, the equipment number can be used to search fo'r the TR aumber. When a TR number is entered and an AWO is initiated, the AWO number may be entered into the TR description portion of the TR syste If the AWO number is provided, it may easily be used to search the PMMS sy tem. If the

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AWO number is not provided, a search of the PMMS system must be conducted using the equipment number. This search can result in many AW0s outstanding for a piece of equipment. Descriptions for each AWO can be reviewed to find the corresponding TR number, provided that it was entered into the PMMS system when the AWO was initiated. The

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large number of steps involved in this process and the reliance on

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operators to take additional actions to. ensure traceability makes this system vulnerable to error The inspector also noted that TR tags are not consistently removed from equipment after repairs have been effecte The goals of the TR system are to clearly identify equipment requiring repair and generate the necessary AW0s. The inspection concluded that these goals are met with the current system, not withstanding the minor deficiencies found. Those items were discussed with licensee managemen Adequacy of tagging practices will be routinely reviewed incident to routine inspectio .3 Inadequate PORC Review of PDCRs (Closed) Unresolved Item (85-15-02) PORC reviews of Plant Design Change Records (PDCRs) had failed to identify violation of Technical Specification requirements when a design change was implemented. An additional example was described in NRC Inspection Report 86-29. In

, response, the licensee changed the method by which PORC reviews PDCR These actions included requiring all PDCRs to be reviewed in PORC >

meetings other.than the routine meetings. By letter dated September 8, 1987, the licensee informed NRC that this practice had been dis-continued. This decision was based on two years of experience in implementing the requirement. In that time, the licensee instituted other measures such as more timely delivery of PDCRs to the site from the corporate office and advanced distribution of materials to PORC members. The separate PORC meetings have artificially increased the number of PORC meetings. In many instances, the inspector observed one PORC meeting being ended, and another being immediately initiated j for the PDCR review. The inspectors have attended many PORC meetings -

for outage PDCRs and noted that the reviews were thorough and that special attention was paid to Technical Specification requirements  ;

and safety implication The inspectors concluded that it is accep- '

table to eliminate the separate PORC meeting requirement for PDCR revie .4 Breach of Containment Integrity During Surveillance Testing (0 pen) Violation (86-20-03) Violation of Containment Integrity Technical Specifications (TS) by operation of four manual containment isolation valves during surveillance testin This item has been previously discussed in NRC Inspection Reports 50-213/86-20 and 86-27. The licensee had identified several containment isolation valves which must be opened for periodic surveillance and routine plant evolutions during full power operations. Previously, the operation of these valves was not permitted by TS when the reactor

, was critica To remedy this situation, TS Amendment 90 was issued l~ on March 11, 1987 to permit limited and controlled operaticr. of these valves during operation. The inspector reviewed the associated l

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surveillance and normal operating procedures to verify that they have been~ updated to reflect this TS chang Four procedures were directly affected by this chang SUR 5.1-4,

. Core Cooling Hot Operational Test, was updated on September 3 to

. include a~ note' which reiterates the new TS requirement. Specifically,

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when SI-V-863A, 8, C, and D are operated an operator must be' stationed at the valve with constant communications so:that,.in case of a required containment isolation, the valves may be closed within one minute. ' Notes concerning the TS requirements associated with the neutron shield tank fill line isolation valve (CC-V-884) are currently

.being added into NOP 2.2-2, Operations at Power - Steady State Operations and Surveillance. This procedure contains the normal operator logs. The inspector reviewed the draft revision and noted that the licensee has elected-to include the TS requirements asfa note to this procedure.because there is no formal. procedure governing neutron shield tank filling. The licensee considers the operation of this valve to be a simple operation, conducted during the' auxiliary operator tour when tank level'is verified. The neutron shield tank sample valve (SS-V-999A) is also a containment isolation. valv Taking a sample of 'this tank is governed by CHM 7.4-2, Component'

Cooling and Neutron Shield Tank Chemistry Control. Currently, the' .

I procedure clearly states that, when containment integrity is required, this sample will not be taken. The licensee is aware that, should .

need arise to-sample the' tank, the procedure would have to be updated to include the.TS requirements for valve operation. Revisions to SUR 5.1-6, Reactor Containment Leakage Monitoring, were made on December 9,1986 to reflect the -TS requirements for SA-V-413. The revision

' calls attention to the.importance of this valve as a containment isolation valve but does not require that an operator be stationed at

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the valve for the duration that it'is opene The procedure does require ~ that the operator maintain constant radio communications with the' control room. The. inspector questioned the adequacy of this nrethod to fulfill the TS requirement of a locally stationed operato This item will remain open pending resolution of this matte .5 Unauthorized Open_ing_of Containment Isolation Valves (Closed) Violation (66-27-04) Licensee identified unauthorized operation of containment isolation valve to fill the neutron shield tank. This violation was a recurrent violation of containment integrity which was previously cited as Violation 86-20-03 (discussed in detail 5.4 of this. inspection report). The immediate corrective action for 86-20-03 was to inform shift supervisors that containment isolation valves were not to be operated for routine evolutions and surveillanc '

i y However, this information was not relayed to plant operators and, I subsequently, the neutron shield tank fill line isolation valve was I opened for routine tank fillin In response, direction was given to all operators not to operate the containment isolation valves identified

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in response to 86-20-03 until the necessary TS change could be processe .x

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This change was issued as TS Amendment 90 on March 11, 198 Review of the related procedure updates is discussed in detail . Followup on Information Notices and Bulletins Licensee action on the following Bulletins (bus) and Information Notices-(ins) were reviewed for forwarding to appropriate maragement, licensee review for applicability, response timeliness, response appropriateness, response accuracy, corrective action commitments, and corrective action completio IN 86-106: Feedwater Line Break

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IN 87-36: Significant Unexpected Erosion of Feedwater Lines

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BU 87-01: Thinning of Pipe Walls in Nuclear Power Plants The information notices were issued to alert licensees to.the potential far significant degradation of secondary plant systems; in these examples, feedwater systems. IN 86-106 details the events surrounding the Surry Power Station feedwater line rupture. IN 87-36 was initiated after Trojan Nuclear Plant expanded their secondary plant inspection program to include single phase flow piping and identified several areas where wall-thinning had occurre The bulletin requested that licensees provide NRC with information about their programs for monitoring the thickness of pipe walls in high-energy, single phase and two phase carbon steel piping system In 1977, Haddam Neck established a Secondary Side Wall Thickness Program I which provided for inspections of piping containing both single and two phase flow. Since 1984, the program has operated on a five year interval of coverage and trending of all designated areas. The piping which is examined includes portions of the following systems: main steam, turbine exhaust, condensate, feedwater, and service water. In response to industry events in the secondary plant, the licensee is expanding this progra Included will be 100% of the feedwater suction lines to verify that !

degradation similar to that at Surry does not exis The program requires I that, if any area inspected is identified to be within 10% of the ANSI i 831.1 minimum wall thickness calculation, an engineering evaluation is conducted to determine if the line should be left as-is, repaired, or replaced. Any lines which are left as-is are reinspected the following outage. When welds are inspected in a geometric transitional crea, the )

inspection is extended past the welded area about six to twelve inches to determine the exteat of the degradation. Locations adjacent to those where piping is being replaced are visually examined to determine if additional ultrasonic examinations or pipe replacements are necessar !

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Currently, the main steam and feedwater piping (ASME Class 2) inside of q containment is being inspected under the ASME Section XI Inservice !

Inspection Program. None of this piping has been replaced or repaired !

under this program. However, portions of these systems are being added to l the wall thickness progra The licensee has completed inspecting those areas designated for inspection during this outage. Several portions of piping in the I extraction steam and feedwater systems are being replace The licensee responded to BU 87-01 by letter dated September 11, 198 Materials were provided describing the scope and extent of the program and conditions identified since the program's origin. The inspector reviewed-this response and found it adequately addressed the topics of the bulletin. Also, the inspector reviewed the wall thickness program progression and the inspection results from the last three refueling outage No deficiencies were identifie . Followup on Events Occurring During the Inspection The following LERs were reviewed for clarity, accuracy of the description of cause, and adequacy of corrective action. The inspector determined whether further information was required and whether there were generic implication The inspector also verified that the reporting requirements of 10 CFR 50.73 and Station Administrative and Operating Procedures had been met, that appropriate corrective action had been taken, and that the continued operation of the facility was conducted within Technical Specification Limit ;

87-12 Steam Generator Tubes Require 100 Percent Eddy Current Testing (ECT) Based on Initial Inspection Results

• 87-13 Inoperable Fire Suppression System Due to Personnel Error

• 87-14 Inadequate Contractor Training / Awareness Results in Inoperable Fire Barriers

• 87-15 Personnel Error Causes Temporary Loss of Spent Fuel Pit Cooling Pumps' Power

• Event Jetailed in NRC Inspection Report 50-213/87-21 No unacceptable conditions were identifie . Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted pursuant to Technical Specification 6.9 were reviewed. This review verified that the reported information was valid and included the required data; that test results

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and supporting information were consistent with design predictions and 1 performance specifications; and that plained corrective actions were adequate for resolution of the problem. fne inspector also ascertained l whether any reported information should be classified as an abnormal l occurrence. The following periodic reports were reviewed:

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Monthly Operating Report 87-08, plant operations for the period q August 1 - 31, 198 Bimonthly Progress Report No. 6 for New Switchgear Building

' Construction No unacceptable conditions were identified 9. Reactor Coolant System (RCS) Support Modifications

Under the Systematic Evaluation Pr; gram (SEP) Topic III-6, the licensee reanalyzed the RCS for normal operating and faulted conditions. This reanalysis identified three areas in the RCS which would be overloaded during the newly determined safe shutdown earthquake (SSE) condition. The overloaded supports were the pressurizer truss and end connections, spring ,

can RC-H-17 on the pressurizer surge line; and c) the reactor coolant pump (RCP) spring cans if settings are such that less travel is available than would be required during the SS The analysis did not take credit for the four large hydraulic snubbers on the neutron shield tank, in order that these snubbers could be remove Plant Design Change Record (PDCR) 870 evaluates the following design change .

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Replace spring hanger RC-H-17 on the pressurizer surge line with a rigid sway strut; i

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Add cover plates to the back-to-back angles which make up the pressurizer truss and repair truss end connections;

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Readjust RCP spring hangers as required; and

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Remove reactor vessel neutron shield tank snubber The inspector reviewed PDCR 870 and observed the modifications made during the outage. Also reviewed were the spring can load data. An issue was raised by Westinghouse in 1984 that, based on 1976 data and the new SSE conditions, spring cans could bottom-out and components could be overstressed during an bSE. During the 1986 outage, spring can load measurements were taken for all four RCPs. However, the data for RCPs 2 and 4 was considered unreasonable by NUSCO Mechanical Engineering in that the recorded spring can load was identical for the three cans on each pump. NUSCO required that new data be taken early in this outage, under PDCR 870, so any needed adjustments to the spring cans could be mad Review of the data showed that cold (as-measured loads), hot (as-calculated loads), and seismic minimum and maximum spring can loads to be within the spring can acceptable range of 0 to 1.75 inche Therefore, f readjustment of the RCP spring hangers was not necessar _ ____-_--___ -

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The inspector questioned the licensee's timeliness in resolving'this spring can load problem. The licensee responded that this issue was considered a plant improvement made under SEP, the NRC staff was involved with the issue, and no justification for completing this PDCR ahead of the set schedule had been identified. The inspector had no further question . Snubber Inspection Haddam Neck Technical Specifications 3.19.and 4.13 contain operational and surveillance requirements for hydraulic snubbers only. As discussed in Section 9.0, above, the last four hydraulic snubbers in the plant were removed during this outage. By application, dated June 1, 1987, the licensee proposed Technical Specifications (TS) for snubbers that are consistent with'

the NRC Standard (STS). This TS change request, delineating operability and surveillance requirements for both hydraulic (in case they'are.used in the future) and mechanical snubbers, was reviewed by Region There are currently 35 safety-related mechanical snubbers at the plan During this outage, the licensee performed visual, in place stroke tests and functional testing (at the Millstone test facility) as would be required by their proposed STS. This was done in accordance with SUR 5.7-73, Mechanical Snubber Visual Inspection, Removal, Stroke Test, Functional Test, and Reinstallation, Rev. 5 (dated July 23,1987) to meet ANSI /ASME and other requirement The inspector reviewed SUR 5.7-73 and identified the followin i

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Step 6.1 indicates that only accessible snubbers will have a frequency of inspection change based on inspection results. The licensee committed to process a Temporary Procedure Change (TPC) to correct this proble SUR 5.7-73 and the Snubber Test Data Sheet do not have any acceptance l criteria for the snubbec piston setting Since the piston will move in or out as piant temperature changes and as predicted for seismic action, the rcnge of snubber piston settings must be given to assure proper snubber action. Except for two new snubbers, RH-AC-2120-5 and-9, the required cold and hot setting ranges were available. The licensee committed to procesc a TPC to incorporate the setting range The inspector confirmed that necessary corrections were made under TPC 87-174,87-224, and 87-29 The inspector reviewed the Snubber Test Data Sheet for all visual and stroke inspections, and the bench test data for those snubbers sent to the Millstone Station for testing. Also reviewed were the following

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Nonconformance Reports (NCRs) and their respective dispositions.

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NCR 87-228: The hanger plate attached to snubber HSS-1006B has a gap of about 1/16 inch frort the wall. The NUSCO engineering disposition was to torque the bolts to 75 foot pounds and, if bolt torque is l ' achieved,;the support is acceptable as is. The bolts successfully

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torqued to 75 foot pounds, however, station ISI engineering requested  :

NUSCO engineering provide a more specific basis for NCR closecu The final disposition was that the 1/16 inch gaps have a minimal  :

effect on the integrity of the plate and anchorage based upon data "

published in Teledyne Engineering Services Report TR-3501-2, August This final disposition was accepted by station ISI

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engineerin NCR 87-229: The extension tube for snubber PR-240 was found bent approximately 3 degrees. The licensee believes this condition f existed since original installatio The extension tube was replaced I and the snubber alignment checked to be within Pacific Scientific (PSA) requirement NCR 87-253: A PSA mechanical snubber in the loop drain system, ,

ORH-ASS-1659A, was found frozen. The condition was apparently caused by someone stepping on the snubber, which is located on the bottom level of containment. A new snubber was installed and a PDCR Evaluation Form was issued, requesting a protective cage be built over the snubber. A similar situation was identified with a snubber located on the charging floo This snubber, RV-C-7, was satisfactorily stroke tested and a. protective cage was requested. The inspector reviewed Automated Work Orders (AW0s) CY 87-07110 and CY 87-09942 which were prepared for installation of protective covers for these snubber This work is to be completed before the end of the outag No deficiencies were identifie . Rod Cluster Control Assembly (RCCA) Replacement Eddy current testing performed on all RCCAs, following Cycle 13 operation (1985), identified 32 of the 47 rods had Intergranular Stress Corrosion Cracking (IGSCC) type cracked rodlets and all rodlets had varying degrees of fretting wear (due to flow induced vibration of the rodlet against the guide plates). The original Westinghouse des gned RCCAs are being repisced this outage by Babcock & Wilcox (B&W) designed rods under PDCR 832. The major design improvements are a cast versus brazed spider assembly, Inconel )

625 verses stainless steel 304 clad material and, a reduced diameter in the lower 12 inches of the rodlets. The licensee purchased 48 of these new RCCAs (one spare assembly) and will replace all RCCAs prior to startu The inspector reviewed PDCR 832 and talked with the responsible Plant Engineer. Although the new RCCA rodlets are still subjected to flow

. induced vibration, the poison will still swell, and reactor trips will ,

still produce axial loadc in the spider vanes, the licensee believes the '

problems experienced with the original RCCAs will be reduced with the

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m newly designed RCCAs. With these new RCCAs, the probability of occurrence of a stuck rod will be reduced, the probability of failure of the RCCA will be reduced, and the performance of the reactor control system will be ,

' improve The inspector had no further question '

12 ^ Cycle 15 T-Average Increase During the 1985 refueling' outage (between Cycles 13 and 14), the cold leg Resistance Temperature Detectors (RTDs) were relocated to the discharge of the respective Reactor Coolant Pumps (RCPs) under PDCR 758. This resulted in improved accuracy of the bulk RCS loop temperature measurements and an indicated increase in T-cold of approximately 5 F. The Cycle 13, Cycle 14 and Cycle 15 (predicted values) are as follow Cycle 13 Cycle 14 Cycle 15 !

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Thermal Power Level (MWt) 1825 1825 1825*

Average Temperature 556 556 562* .

Delta Temperature 41 46 46* :

Hot Leg Temperature 586 579 585* :

Cold Leg Temperature 535 533 539* '

Main Steam Pressure 685 640 685*

• Values estimated by licensee from data takes during Special Procedure SPL 10.7-28 Prior to Cycle 14, when the nominal full load T-avg of 555 F was )

indicated, the actual RCS average temperature was slightly highe I Therefore, for a given temperature / load relationship the corresponding steam header pressure is slightly lower than in cycles before the RTDs were moved. This results in a decrease in turbine efficiency and the electrical generation rate at rated full power. The licensee performed SPL 10.7-286 in May 1986, during Cycle 14 operation, to establish plant parameters at Cycle 13 condition The maximum T-avg and delta-T recorded were 561.5 F and 47.5, respectively. The licensee performed an engineering evaluation and made system modifications (instrument calibrations, setpoint changes, and replacement of the meter face for T-avg indication) under PDCR 84 The inspector reviewed PDCR 841, RCS T-avg Increase to 562 F, SPL 10,7-268, Determination of Plant T-avg at Optimum Turbine Control Valve Position, SUR 5.3-45, Four Loop Reactor Coolant Flow Measurement and talked with NUSCO and station engineers. The testing required by PDCR 841 l

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will be done during the startup testing phase following the current 1 outage. The inspector had no further questions at this time, however, )

further inspection will be conducted during startup testing, j 13. Motor-0perated Valve (MOV) Testing

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By letter dated June 11, 1986, the licensee responded to IE Bulletin 85-03 and addressed the six actions required.Bulletin 85-03 specifies that, ,

for MOVs in the high pressure coulant injection / core spray and emergency j feedwater systems that are required to be tested for operational readiness in accordance with 10 CFR 50.55a(g), licensees develop and implement a program to ensure that operator switches are selected, set, and maintained properly. The licensee concluded that, for Haddam Neck, this includes the Auxiliary Feedwater (AFW) system, the High Pressure Safety Injection (HPSI) system, and the Chemical and Volume Control System (CVCS). All

. motor-operated valves in both the suction and discharge flow paths of these systems were addressed; valves which are normally de-energized were not addressed. The bulletin provisions are addressed as follows Design Bases for Motor-Operated Valves The licensee was to review and document the desigri basis for each MOV including the maximum valve differential pressure expected during both opening and closing for both normal and abnormal events. Two AFW MOVs, four HPSI MOVs, and six CVCS MOVs required esaluatio FSAR, Technical Specifications (TS), Normal Operating Procedures, and Emergency Operating Procedures (EOPs) were reviewed to determine the design basis for each valv Single failures, assuming only on-site

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power or only off site power availability, included: 1) active instrument and control failures, valve actuator failures, spurious opening and closing of valves, and operator errors; and 2) passive failures such as pipe break and check valve failure The specific design differential pressures for nine of the 12 valves were greater than the normal and abnor. ;l event maximum differential pressures. For the three valves determined to have inadequate design dif ferential pressures, FW-MOV-35 (alternate AFW feed to steam generators) and CH-MOV-2928 and C (parallel charging pump discharge isolation valves), the licensee committed to initiate procedure revisions to insure the design limitations are not exceeded and the reactor operators are aware of the limitations. The inspector reviewed E0Ps and noted that Temporary Procedure Changes (TPCs)86-505, 506, and 507 provided operator guidance for three E0Ps affected by possible inoperability of FW-MOV-35. The operator is instructed to close the AFW discharge valves or stop the AFW pumps

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and open FW-MOV-35 and then realign AFW and fee The inspector was unable to identify any procedural changes related to the commitment on CH-MOV-2928 and These normally open, Loop 2, cold leg isolation valves are to be closed during the transfer to two path recirculation in accordance with ES- The licensee had

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l changed E0P 3.1-4 in May 1986 to include a statement to close l charging line manual isolation valves if the MOVs fail to clos However, this statement had not been transferred to the symptom oriented procedure (ES-1.4), implemented in August 1986. The

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licensee has committed to correct ES-1.4 by adding a statement similar to that for E0P 3.1-4. In addition, the licensee committed to determine the cause of dropping the statement in this E0P/ES

, change and review the EGP change process to ensure other commitments were not omitted. This issue will remain unresolved pending licensee ccmpletion of these reviews (UNR 50-213/87-25-01).

b. Translate the Specified Design Differential Pressure to the Correct MOV Switch Settings The licensee's response outlined a plan to determine the proper switch setting using a combination of analytical and empirical dat The review of this plan will be performed after receipt of the licensee's final report on this bulleti ,

c. Testing cf MOVs to Insure Valve Switch Settings The licensee committed to stroke test each valve, to the extent practical, to verify that the settings defined have been properly implemente Motor Operator Valve Analysis and Test System (MOVATS)

equipment has been purchased for this testing. The inspector reviewed PMP 9.5-3 (-4), Procedure for Testing Teledyne (Limitorque)

M0Vs Using MOVATS, and observed the physical testing of several MOV !

During this outage, a total of 14 MOVs were as-found tested), any necessary modifications made, and then as-lef t tested. The licensee stated that important MOV findings / resettings will be provided with the final repor d. Review / Revise Procedures to Ensure Correct MOV Switch Settings '

The licensee committed to review and revise procedures as necessary to ensure that correct switch settings are determined and maintained through the life of the plan The licensee is working toward making any necessary procedure changes after completion of the testing program, before their use during the next refueling outage, e. Report the Resuits of MOV Design Basis Review and Provide the Schedule for Corrective Actions The licensee's June 11, 1986 letter provides the results of MOV design basis review and commits to complete the other actions for Haddam Neck by November 1987. The NRC will review the bulletin response including the inspection data to be submitted in the form of a final repor *

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The licensee's June 11, 1986 letter discusses the scheduled j inspections for Haddam Neck and Millstone 1, 2, and 3, but does not 1 commit to an issuance date for a final report for any plant. In  ;

discussions with the licensee, it appears that the final report will be available in about 60 days after completion of the program at all four units, or mid-summer 198 . Moter-OperatedValve(MOVloverloadProtectionUpgrade The Systematic Evaluation Program (SEP) Report, Section 4.13, discusses the staff evaluation of Topic III-10.A and finds that thermal-overload protection for MOVs at Haddam Neck does not satisfy current licensing requirement Thermal-overload devices are not bypassed, no information is available to support adequacy of trip setpoints, and torque switches rather than limit switches are used to terminate valve travel. The licensee is to do the following:

1) Replace the actuators on 17 MOVs in harsh environments to conform to electrical equipment qualification requirements; 2) As these actuators are replaced, verify the adequacy of the thermal-overload devices; 3) Verify suitability of all safety-related MOVs required to change position during an accident; 4) Revise thermal-overload setpoints as necessary; 5) Modify, as necessary, the control circuits for the MOVs using torque switches so that valve travel in the open direction is terminated by a limit switch and valve travel in the close direction is terminated by a torque switch; 6) Retain torque switch protection in both the open and close directions; 7) Disable torque switch protection near the closed seat when the t valve is moving in the open direction and near the fully open position when the valve is moving in the close direction; and, 8) Complete the above MOV control circuit work and other modifications in conjunction with valve actuator replacemen This work was started in 198 During the current outage, work on Items 2 and 4 was performed, under PDCR 890, on four MOV The Safety Evaluation addresses the replacement of the thermal-overload relays and heaters by ones protected by ambient compensated overload relays. This provides better overall MOV overload protection by eliminating the effects of

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! ambient temperature at the relay (MCC) location, thereby allowing the relay to respond to current onl This work was performed at the MCC The modifications, with the exception of, torque switch protection n (Items 6 and 7, above) on a few MOVs, are completed. The licensee will be submitting a final report on SEP Topic III-10.A. The inspector had no further questions at this tim . Feedwater MOV Replacement The existing main feedwater motor operated isolation valves, PbMOVs 11, 12,13,and 14, were replaced in order to meet environmental qualifications and thermal overload protection (SEP Topic III-10.A) requirements. These valves also have a history of leakage and operational problems which require significant maintenanc The valves receive an automatic closure signal as a result of high containment pressure and/or safety injectio Valve replacement was controlled by PDCR 896. The existing Crane / Chapman 12 inch, 600 lb carbon steel, bolted bonnet, single wedge gate valves, equipped with Limitorque SMA-2-60 actuators, were replaced with Anchor / Darling 12 inch, 500 lb carbon steel, pressure seat bonnet, live loaa packing: double disk gate valves, equipped with Limitorque SMB-1-60 actuator Based on ultrasonic wall thickness data taken over the last few years, the 12 inch elbows downstream of these MOVs were replaced to eliminate an area where wall thinning had occurred as identified by the Secondary Side Wall Thickness Progra The inspector reviewed the PDCR and found it very conplete. The inspector questioned how the thermal overload protection requirements will be incorporated into future MOV replacemer.ts. The licensee indicated that Corrective Maintenance Procedure (CMP) 8.5-126, Testing of Motor Overload Relays, includes detailed instructions that answer this concer The inspector observed portions of the valve / piping replacement had no further concern . Control Air / Containment Instrument Air Modifications In Information Notice 85-84, the NRC informed all licensees of a generic problem involving failure of Main Steam Trip Valvet (MSTVs) to close when control air was isolated. During this outage, the MSTVs were upgraded to QA Category I by adding two new soft-seat, testable check valves and a new larger size accumulator, and seismic supports for all component Because of problems including operational failures, poor quality of air, and not being able to obtain spare parts, the licensee replaced the containment instrument air system (CIAS) and moved the compressors, air receivers, and other components up to the 22 foot level (up one floor from its previous location) in the containmen This system supplies control air to the pressurizer spray control valves, the containment air recircu-lation fans, the power-operated relief valves, and other valves and instrumentation inside containment. The CIAS now consists of two skid-mounted 29 cfm (each) compressors, a singla 400 gallon receiver, a

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dryer unit, and filters upstream and down . ceam of the dryer unit. Both of these modifications were perf]rmed under PDCR 894 and ts related work order The inspector reviewed PPCR 894, talked to the responsible site engineer, and physically inspected the modification location The method of support of the 1/2 inch stainless steal tubing from the old 3/4 inch brass pipe to the new accumulator was questioned as to adequacy. This tubing contains the new soft-seat check valves, the valves to be used to confirm check valve operability, and an isolation valv The tubing, between the support and the connection into the accumulator, measured about 60 inches (within the 74 inches allowed by the design). The responsible engineer stated that the support calculation was based on a twenty pound weight placed in the middle of this span of tubing. The inspector had no further question . Regional Administrator Inspection On September 10, 1987, a material condition inspection was performed by the NRC Region I Regional Administrator. Areas inspected included the Primary Auxiliary Building, Containment Building, Emergency Diesel Generator Building, Cable Vault, Auxiliary Feed Pump Room, Switchgear Room, and Control Room. Instrumentation, cabling, control system, valves, valve motors operators, motors, pumps, electrical switchboards, batteries, and motor generators were inspected in these areas. Vital and emergency equipment were inspected to determine overall material condition and impact of the licensee's maintenance program. Additionally, housekeeping, general cleanliness and control of radiological areas were also observe The detailed results of the inspection were discussed with licensee management. A written summary of the inspection results was provided to the licensee and is appended as Attachment 1 to this repor . Ground Water Inleakage into Cable Vault In April 1987, the licensee determined that water inleakage into the containment cable vault is a possible substantial safety hazard (PSSH) and initiated the required ?SSH evaluation (CY-87-02) in accordance with Administrative Control Procedure 1.0-14, Implementation of 10 CFR 21:

Reporting of Defects and hancompliances. LER 87-07 and 87-07-01 were submitted as informational LERs (see NRC Inspection Report 213/87-18 detail 6.1). The PSSH evaluation has been completed through the Nuclear Review Board (NRB) review. Thus far, the licensee has concluded that this is not a substantial safety hazard (SSH) and is not reportable per 10 CFR 2 This determination is based on reviews of the cable vault wall, conduit and duct-bank structural drawings showing that the forces during the postulated safe shutdown earthquake would not cause inleakage into the cable vault to increase. With an inleakage rate of one eighth inch per ho.ur, there is ample time for water removal before any containment penetrations are affected. The inspector attended the NRB meeting which

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I reviewed this PSSH evaluation. Th' NR8 did not alter the conclusion that this is not an SSH, but did table the discussion until the next meeting so that the postulated water inleakage rates could be confirmed. NR8 also discussed the short term corrective action which have been taken to

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compensate for water inleakage and proposed long term actions. There were no unacceptable conditions identified concerning this review. However, the inspector noted that this area has no flooding alarms or installed sump pumps and will monitor licensee actions on this item incident to routine inspectio >

1 Radiological Controls During Diving Evolutions During the inspection period, the licensee utilized divers to remove dowel pins from the thermal shield support blocks on the core barre During this evolution the reactor cavity was flooded up and the core barrel was positioned over the reactor vessel. Preparations for the diving operation were reviewed by a regional radiat>on specialist by the following method Discussion with members of the diving team and licensee HP personne '

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Review of the controlling RWP (#2805) and the associated ALARA revie Review of pre-work survey {

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Review of the following procedures:

--RAP 6.2-12, Spent Fuel Pool and Reactor Cavity Evolution VP 346, Removal of the 1" Dowel Pin on the Thermal Shield Support Block .

Licensee preparations for the diving operation were extensive and compared favorably with those used at other utilities. Off-site mock-up training was provided to the divers to provide familiarity with the long-handled dowel removal tool. Metal and plexiglass barriers were utilized to separate the diving work area from high dose rate areas; these provided additional control compared to the common practice of using cargo netting as a flexible barrier. Pre-work surveys were performed using an underwater probe (Dositec PR-2). A Tl0 tree, consisting of numerous TLDs in waterproof containers mounted on an aluminum frame, was also lowered into the work area to measure dose rate During the pre-work surveys the licensee made efforts to position the PR-2 probe at the same location as the underwater TLDs. The inspector reviewed the survey results and noted that the PR-2 probe measurements appeared consistently higher by a factor of two than the licensee's TLD l measurement The inspector questioned the licensee as to whether their l TLD was potentially under-responding in the underwater environment. The licensee stated that the measurement discrepancy was probably due to positioning effects in the severe dose gradients; however, they also committed to further evaluate the TLD and PR-2 underwater response to

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I identify if a correction factor was needed to record personnel dos Meanwhile,.the diving operation was controlled using stay times based on the more conservative PR-2 general area dose rate measurement Subsequent evaluation by the licensee, based on additional survey measurements and communication with the Dositec PR-2 manufacturer, identified that, when underwater, the PR-2 over responds to low energy gamma energy created by scatter in the underwater environment. The manufacturer has developed 'a probe modification to correct for this overcompensation; however, the licensee's probe was' purchased crior to this development and was not modified. The 1icensee has since had their probe modified by the vendor to correct the above over-respons Subsequent comparison of underwater dose rate measurements made by the TLDs and by a modified PR-2 probe showed good agreemen NRC Information Notice 84-61 recommends that emergency procedures for diver rescue be provided for personnel involved in diving operations. The inspector noted that procedure VP 346, a Westinghouse procedure that was internally reviewed and approved by the licensee to support the cperation, did contain an appendix that covered diver emergency procedures. The licensee's in-house diving procedure (RAP o.2-12), however, did not address emergency diver rescue. The inspector noted that, in future diving situations in which RAP 6.2-12 is used.as the sole controlling procedure to cover diving operations, the area of emergency diver rescue-may not be addressed. The licensee indicated that this area is typically discussed in the required pre-dive briefings; however, the licensee also j revised. procedure RAP 6.2-12 to incorporate an appendix detailing diver emergency response procedure f The inspector had no further concern . Exit Interview During this inspection, meetings were held with plant management to discuss the findings. No proprietary information related to this inspection was identifie l l

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Region I Inspection Report 50-213/87-25 Attachment 1 September 11, 1987 Memorandum For: Don Miller, Station Superintendent, Haddam Neck-Frem: Tom Shedlosky, Senior Resident Inspector, Haddam Neck Subject: Inspection Tour Observations The observations resulting from the inspection tour of Haddam Neck on September 10, 1987 by Bill Russell are summarized in Attachment 1 to this memorandu These items will be included in the current routine resident inspection report (IR 50-213/87-25).

Thank you for your and your staffs' assistance during Mr. Russell's visi

Sincerely, Tom Shedlosky cc:

W. Russell W. Kane J. Wiggins G. Bouchard E. Debarba

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Attachment 1 Inspection Tour Findings and Observations September 10, 1987 Several valves in containment had excessive buildup of boric acid crystals and were not tagged to show that a trouble report had been written. An unchecked buildup of boric acid indicates leng term leakage and adds '

significantly to area contamination. It was not evident that there is an effective program for maintaining valves in containment and contaminated area The absence of tags also made it unclear whether any maintenance is planne Foreign materials and debris were identified in the containment lower level drain trenches. The debris appeared to be from outage activitie Nails, probably' from the construction of scaffolding, are a particular concern because of the potential for damage to the sump or safeguards pump The radiologically controlled area (RCA) had high contamination areas not unique to outage situations. An example was the residual heat removal (RHR) pit in the primary auxiliary building (PAB), where alpha contamination is a particular concern. This indicates unchecked valve, flange, and equipment leakag Decontamination would reduce exposures and *

. facilitate identifying leaks for maintenance. Generally, zone health physics technicians had thorough knowledge of area radiation levels and hot spot Instrumentation and electrical equipment conditions were identified as good, including controllers and limit switches which provide vital information to the control room operators. No loosened or removed flexible conduits were found. Emergency Diesel Generators (EDGs) were well !

maintained, with no loose wires, connections or instrument tubing, j Decommissioned cables in the cable vault are not terminated and labeled consistentl F. When work is not in progress, more attention is needed to temporary equipment. A step stool was leaning against terminal boards and cable trays inside the control room vertical board Equipment was resting against the containment air recirculation fan coolers; several cooler fins were damaged. Other equipment was noted to be protected during work.

I Specifically, the EDGs were covered by plastic during overhead work on exhaust support Loose nuts, bolts and other parts in switchgear cabinets could adversely affect the equipment during operational events. Several bolts were found in the base of a rod control cabinet that was undergoing maintenance. The licensee noted that inspection of these cabinets is on the startup j checkl i s I

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There was a possible leaking weld-o-let on the discharge pipe of the spent l fuel storage pool cooling flat' plate heat exchanger, j l There were many ongoing activities and, with one exception, personnel were  !

actively working and not lingering in radiation ' areas. The exception was  !

an individual sleeping in the containment annulus area. The licensee {

stated that his site access was immediately terminated in accordance with i station polic The Regional Administrator remarked that he has seen plants in worse material J conditions during outages and that, he has also observed plants of the same j vintage as Haddam Neck in much better condition. He expressed the intent to return early in December to observe the plant during power operatio l l

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