IR 05000213/1986003

Safety Insp Rept 50-213/86-03 on 860211-0415.Violation Noted:Operating Procedure NOP 2.19-5 Not Implemented Prior to Declaring Steam Generator Wet Layup Sys Operable

ML20197C113
Person / Time
Site:	Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png
Issue date:	05/01/1986
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20197C077	List: IR 05000213/1986003 ML20197C073 ML20197C091
References
TASK-1.A.1.1, TASK-TM 50-213-86-03, 50-213-86-3, IEB-84-03, IEB-84-3, NUDOCS 8605130235
Download: ML20197C113 (16)

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U.S. ' NUCLEAR REGULATORY COMMISSION

REGION I

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Report N /8E-03 Docket N o 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 conducted: February 11 - April 15, 1986

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-Inspectors: Stephen M. Pindale, Resident Inspector Robert Summers, Project Engineer Paul D. Swetland, Senior Resident Inspector Approved by: &kM shl86 I

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E. C. McCabe, Chief, Reactor Projects Section 3B

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Date Summary:

. Areas Inspected: This was a routine safety inspection of refueling outage activi-ties, involving 469 inspection hours by two resident inspectors and a region-based projectengineer. The following areas were inspected: plant'and refueling opera-tions, radiation protection, physical security, fire protection, maintenance and i surveillance testing, plant modifications, and followup on open items, licensee -

events and TMI Action Plan Item Results: Licensee preparation, control, and implementation of various refueling-outage activities were found to be generally acceptable. One violation related to administrative control of plant modifications was identified. Three open in-

spection findings related to containment integrity, operator requalification, and i waste gas system operation were close Two TMI Action Plan Items (I.A.1.1 &

II.F.1.5) were closed, however, the containment pressure monitor item (II.F.1.4)

j remained open pending environmental qualification of this instrument. Action on-a licensee-identified small break loss of coolant accident analysis error remained unresolved pending NRC review of this matte .

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TABLE OF CONTENTS I

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i - S umma ry o f Faci l i ty Ac ti v i ti e s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

' Review of Plant Operations........................................... 1 bservation of Maintenance and Surveillance Testing.................. 2 Followup on Previous Inspection

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Findings............................. 3

!. Followup on IE Bulletins, IE Circulars and InformationLNotices....... 4 Followup on TMI Action Plan Items.................................... 5 t Followup on Events Occurring During the Inspection...................

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+ Review of Plant Modifications........................................ 11

- Review of Periodic and Special Reports. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

1 Unresolved Items..................................................... 13

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d 1 Exit Interview....................................................... 14

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DETAILS Summary of Facility Activities The plant remained in a cold shutdown / refueling condition throughout this in-spection period. The inspection covered days 39 through 102 of the planned 8-week refueling / maintenance outage. During this period, outage activities included steam generator eddy-current testing, welding of the new refueling cavity seal in place, reactor core refueling, containment integrated leak rate testing, plant modifications, and other routine refueling interval maintenance and surveillance testing. During reactor disassembly, while removing the

. upper internals package, a fuel assembly was inadvertently lifted from the core and dropped onto two other_ fuel assemblies. It was subsequently re-covered and refueling activities have been completed. At the end of the in-spection period, the plant was approximately 40 days behind its original out-age schedule, primarily due to the fuel assembly drop incident, and various modification delays. The licensee currently expects to reach criticality on April 28,1986, and 100 percent power on May 9,198 . Review of Plant Operations The inspector observed plant operation during regular tours 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

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Containment Building Building 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 acknowledge Operator awareness and response to these conditions were reviewed. Control room and shift manning were compared to regulatory requirements. Posting and control of radiation and high radiation areas were inspecte 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 system During plant tours, logs and records were reviewed to determine if entries were properly made and communicated .quipment 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. No discrepancies were identifie _

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3. Observation of Maintenance and Surveillance Testing 3.1 The inspector observed various maintenance and problem investigation ac-tivities for compliance with requirements and applicable codes and stand-ards, QA/QC involvement, safety tags, equipment alignment and use of jumpers, personnel qualifications, radiological controls, fire protection, retest, and reportability. Also, the inspector witnessed selected sur-veillance 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 per-sonnel, procedure details were adequate, and test results satisfied ac-ceptance criteria or were properly dispositioned. The following activi-ties were reviewed:

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Containment Integrated Leak Rate Test (Surveillance Procedure 5.7-108) on April 1,1986 through April 6, 198 Full Flow Test of HPSI and LPSI (Surveillance Procedure 5.7-106)

on April 10, 198 Steam Line Break Channel Interaction Assessment (Special Procedure 10.2-22) on April 12, 198 Test of Diesel Generator EDG-28 with Partial Loss of AC coincident with Core Cooling Actuation (Surveillance Procedure 5.1-19) on April 14, 198 Cycle 14 RefuW ing Operations (Vendor Maintenance Procedure 72)

February-March 198 .2 The inspectors observed the conduct of refueling operations throughout the inspection period. These activities were performed in accordance with vendor maintenance procedure (VP) 72, Westinghouse Refueling Pro-cedures; and included reactor disassembly, refueling equipment check-outs, fuel offload and reload, and reactor reassembly. During the im-plementation of these activities, several problems occurred. The fuel I

transfer cart mechanism and interlock switches malfunctioned. The spent fuel pool sluice gate malfunctioned. Quality control checks were omitted for several control rod drive shaft connections, and elongation readings were improperly taken on several reactor vessel studs during tensionin In addition, one fuel element was dropped during reactor disassembl This event is detailed in paragraph 7.2 of this report. Although these problems resulted in significant delays in the refueling process, they

' were identified by the refueling team and promptly brought to management attention. NRC review of the recovery actions found them to be appro-priately reviewed, approved and implemented by the licensee. No further i

discrepancies were identified.

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4. Followup on Previous Inspection Findings During the course of the inspection, three NRC open items were reviewe The inspector found licensee actions with regard to these areas to be sufficient to close these items. Details follow:

4.1 (Closed) Followup Item (213/84-14-05) Operation of Post Accident Sampl-ing System (PASS) manual containment isolation valves was contrary to technical specificaton (TS) requirements for containment integrit Licensee management required the PASS isolation valves to be tagged closed pending NRC approval of the TS change submitted on October 31, 1985. NRC approved the proposed TS changes to the containment integrity definition (TS 1.8) and the added Non-Automatic Containment Isolation Valves Table (3.11-2), which provides TS relief for periodic testing of the PASS valve These changes were issued in Amendment No. 72 to the facility operating license on February 19, 1986. The NRC Safety Evalu-ation Report referred to a monthly Inservice Inspection (ISI) test of the PASS isolation valves, and a concurrent system operability chec However, the licensee plans to perform this combined test quarterl This is consistent with Inservice Inspection (ISI) criteria, and is con-servative, in that the containment isolation valves will be opened less frequentl NRC Region I and Licensing concurred with a quarterly sur-veillance interva The licensee will document the commitment to NRC Licensin The inspector had no further questions in this are .2 (Closed) Followup Item (213/85-18-01) The licensee committed to a 6-week theory upgrade for certain operators as a result of weaknesses identified by NRC in August and November 1984. Upgrade training sessions were observed by NRC in September 1985. No problems were identifie As of March 21, 1986, the applicable upgraded requalification training commitments had been satisfactorily completed for the designated opera-tors. Overall operator requalification will be reviewed in accordance with the routine inspection progra .3 (Closed) Unresolved Item (213/85-21-11) The licensee was to address several NRC concerns regarding their November 1, 1985 unplanned release of noble fission product gase A memorandum was issued to enhance operator understanding and control of Waste Gas System operations. Signs on the back of the Waste Gas System panels warn operators of the high sensitivity of the mercoid switches, and all of tha back covers for the mercoids have been properly installed and labele The Instrument and Control (I&C) group performed a verification check of the setpoints for the gas decay tank auto-transfer and overpressure solenoid relief valve Both set points were found to be within the specifications of 200 and 215 psig, respectively. However, to provide for a greater margin between the gas decay tank pressure and overpressure relief setpoints, the set-point of the auto-transfer was reduced from 200 pounds to 180 pound During the January 1986 refueling outage, further testing was performed to recreate the event. The test showed that with the tank pressure close to the auto transfer setpoint, only a tap on the safety valve mercoid

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was required to activate i As an interim measure, the licensee will maintain the 180 pound auto-transfer setpoint. The final resolution will be to change the mercoid switches to another type which will not be sen-sitive to physical disturbanc There was also a question as to the operator's inability to manually isolate the on-service waste gas storage tank. New instructions to operators were issued to prohibit manual manipulation of the mercoid control switches and require terminating waste gas system operations and contacting I&C when abnormal system operation is suspected. During the January 1986 refueling outage, the licensee demonstrated the capability to manually isolate the waste gas storage tanks using the manual control switches. The inspector had no further questions in this are . Followup on IE Bulletins (IEBs) and Information Notices (ins)

Licensee action on the following IEBs and ins was reviewed for forwarding to appropriate management, licensee review for applicability, response timeliness, response appropriateness, response accuracy, corrective action commitments, and corrective action completio .1 IN 85-62 - Backup Telephone Numbers to the NRC Operations Center This Information Notice was issued to address the use of four backup (commercial) telephone numbers for the NRC Operations Center for emer-gency notification to the NRC whenever the Emergency Notification System (ENS) or Health Physics Network (HPN) is inoperable. The inspector re-viewed Emergency Plan Implementing Procedure (EPIP) 1.5-2, Notification and Communication. The area code of one of the numbers listed in EPIP 1.5-2 (202-951-0550) has been changed. The correct number is 301-951-0550, however either area code can be used at the present time. The licensee revised EPIP 1.5-2 to reflect the current area cod .2. IE8 84-03 - Refueling Cavity Water Seals, and IN 84-93 - Potential for Loss of Water from the Refueling Cavity IEB 84-03 and IN 84-93 were written in response to the August 1984 re-fueling cavity seal failure event at Haddam Neck. During the recovery from that event, several licensee submittals were made to NRC, document-ing licensee positions in response to IEB 84-03. In addition, the po-tential for loss of refueling cavity water through other paths was ad-dressed in the integrated safety evaluation for the event recovery ac-tions. The licensee's submittals were reviewed by NRC Licensing, and the implementation of commitments was documented in NRC Region I Inspec-tion Reports 50-213/84-14 and 84-23. NRC review of licensee actinns concluded that adequate measures had been taken in response to the cavity seal failure event, however the reuse of the modified cavity seal during subsequent refueling outages would require prior NRC review. Subsequent licensee evaluation of the cavity seal design concluded that a new, permanent cavity seal structure would more appropriately meet the design

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objectives of ease of installation and personnel exposure reductio This design was presented to NRC Licensing and found acceptable as docu-mented in an NRC letter dated December 17, 1985. The inspector verified the satisfactory installation of the permanent cavity seal ring (PCSR)

as documented in paragraph 8.1 of this report. Not all of the IEB 84-03 and IN 84-93 concerns were addressed in the PCSR design packag In particular, the inspector brought to licensee attention the need to re-address the limiting cavity drain leak rate and to assure that the cur-rent required cavity level criterion and emergency operator actions re-mained adequate with regard to scope and timeliness. The licensee docu-mented these evaluations in a letter to NRC dated February 19, 198 The inspector verified that the revised evaluations were consistent with revision 2 to Emergency Operating Procedure 3.1-48, Cavity Seal Failur The inspector had no further questions in this area. IEB 84-03 and IN 84-93 are close . Followup on TMI Action Plan Items I.A.1.1 - Shift Technical Advisor (STA)--(Closed)

The licensee was to implement on-shift engineering expertise and describe the current STA qualification and training programs and the long term plan for maintenance or eventual elimination of the STA program. Licen-sees could maintain a dedicated on-shift STA, or a combined Senior Reac-tor Operator (SRO)/STA position. In both cases, the STA was to hold a baccalaureate degree in engineering or related science or its equivalen The licensee committed to fulfill STA requirements in two phases. They planned to utilize a dedicated on-shift STA as an interim measure until their dual role STA position could be manned. The licensee fulfilled its STA commitments to NRC, however the STA program was never finally approved by NRC because the licensee's program of equivalency falls short of TMI Action Plan Item I.A.1.1 requirements. On October 28, 1985, NRC issued its final Policy Statement on Engineering Expertise on Shift, which dropped all reference to the acceptance of an equivalent to bac-calaureate degrees for the dual role STA position. The licensee's STA program remains in variance with this policy. Subsequently, NRC issued Generic Letter (GL) 86-04 on February 13, 1986, requesting that licensees document their plans for implementing the NRC Final Policy Statemen The licensee currently implements their STA qualification program con-sistent with their submittals, which have not yet been acted upon by NR TMI Action item I.A.1.1 will be close However, NRC approval of the licensee's SS/STA program remains open, and will continue to be followed by GL 86-04 and open inspection item 213/85-13-0 .2 II.F.1.4 - Containment Pressure Monitoring System (0 pen)

The licensee was to provide for environmentally qualified, wide range, redundant and continuous monitoring of the reactor containment pressur Item I.F.1.4 was reviewed and approved by NRC (NRR Safety Evaluation Re-port, dated July 9,1985), except for the environmental qualification

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(EQ) of the pressure transmitter (PT). This issue was to be evaluated under the licensee's EQ program (10CFR50.49). With the exception of the EQ issue, the inspector verified that the above requirements have been

, satisfactorily implemented and that the equipment remains operable. The

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t pts are currently not environmentally qualified. However, the licensee has proposed to upgrade the CPMS to EQ requirements during future imple-mentation of modifications to meet the criteria of NRC Regulatory Guide 1.97, Accident Instrumentation. The schedule for these upgrades is being evaluated through the integrated safety assessment program (ISAP). This

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item remains open pending resolution of the EQ issu .3 II.F.1.5 - Containment Water Level Monitoring System (Closed)

The licensee was to provide for continuous monitoring of the containment water level in the control room. NRC reviewed and approved the licensee's containment water level monitoring system (CWLMS) in an NRC Safety Evaluation Report, dated July 9, 1985. The safety evaluation addressed all aspects of the CWLMS, except for environmental qualification (EQ),

which was to be addressed under the licensee's EQ program (10CFR50.49).

The licensee utilizes a single narrow range (NR), non-EQ, containment sump level transmitter (0-2,000 gallon range) and two wide range (WR),

fully qualified, containment level transmitters (0-600,000 gallon range).

The licensee was not required to environmentally qualify the existing NR level transmitter (LT) due to the excessive personnel exposure re-a quired for replacement of the current NRLT. The WRLTs were installed in accordance with Plant Design Change Request No. 371. All three LTs-remain operable. The inspector verified the proper implementation of -

the CWLMS commitments. No discrepancies were identified. This item is close . Followup on Events Occurring During the Inspection

7.1 Licensee Event Reports (LERs)

The following LERs were reviewed for clarity, accuracy of the description

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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 reporting require-ments 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

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Specification Limits.

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86-06, Containment Local Leak Rate Testing

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86-07, Missed Fire Protection System Failures

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86-08, Improperly Tested Containment Electrical Penetrations

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86-09, Inadequate Service Water Flood Barriers

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86-10, Inadequate High Radiation Area Key Control

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86-11, Inoperable Fire Sprinkler System

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86 12, Dropped Fuel Element Event, detailed in paragraph 7.2, below

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86-13, Inadequate Small Break Loss of Coolant Accident (SRLOCA)

Analysis, detailed in paragraph 7.3, below

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86-14, Inoperable Fire Water Pumps 7.2 Dropped Fuel Assembly Event (LER 86-12)

On February 26, 1986, at about 12:10 p.m. , a fuel assembly was dropped into the reactor core, with its bottom nozzle on' top of the core and its

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top nozzle resting against the core barrel on the opposite side of.the reactor vessel. At the time of the event, the reactor upper internals package was being lifted out of the vessel in preparation for refuelin The dropped assembly apparently stuck to the upper internals package during this lift, and was dropped after impacting the side of the core barrel when the internals package was moved laterally toward a storage location. The fuel assembly fell a maximum of three feet onto the core former plate and two adjacent fuel assemblies. There was no change in area radiation levels nor were there any increase; in airborne or primary coolant radioactivity. .The licensee evaluated tre conditions and con-cluded that the assembly probably would not move from its final resting position. There was no release of fission products, and the licensee believed that no release was imminent; therefore, time was available to prepare a recovery procedure. While these preparations progressed, the licensee placed a sling around the assembly to preclude any movemen The licensee conducted underwater video camera inspections of the dropped assembly to determine the extent of damage to the fuel and the reactor vessel components. Although some damage was visible, the work necessary to restore the reactor to normal conditions was indeterminate. A minor amount of loose debris was evident. The licensee utilized the video taped inspections to scope 'out the work required to recover the fuel asse:nbl Due to the cocked position of the fuel assembly, the normal fuel handling equipment could not be utilized during the initial recovery actions.

Therefore, a coordinated effort among engineering, maintenance, the fuel manufacturer, and the normal fuel handling vendor was needed to develop a safe alternate method of handling the fuel. The recovery procedure and referenced safety evaluation were both reviewed and eventually found to be acceptable by the onsite review committee (PORC), and was approved

by plant managemen The inspectors observed the PORC review process.

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Although the procedure development was notably iterative, the review was very thorough, the procedure was well developed, and a smooth re-i covery ultimately occurred. The safety evaluation included review of the method and equipment to be used during the lift of the dropped as-

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. 8 sembly and reviews of other potential concerns, such as the cavity seal, heavy loads over the core and the use of administrative controls to pre-vent lifting the assembly out of the wate The inspector observed a portion of the recovery equipment manufacture and qualification testing. Originally, the lift cables were specified to be stainless steel; however, it appeared that this cable was being overly crushed by the cable clamps when using the specified torque values for this hardware. The lift cables were remade using carbon steel cable with its respective hardware and specified torque value. No further problems were identified. The primary lift rig consisted of; three separate cables attached to the auxiliary hoist of the polar crane, a triangular-shaped cable spreader, three 1-ton rated chainfalls, two calibrated load cells (1 for each of the 2 primary lifting cables), and three cables with qualified hooks. One of these cables was clearly marked with tape to be used as an indicator of vertical position of the fuel assembly. This indication was for assuring that the recovery pro-cess remained within the bounds of the safety analysis. The load bearing portion of the rig was attached to two separate spring clips, which are part of the upper nozzle of the fuel assembly. Two spring clips were necessary because the fuel vendor could not certify a single clip as capable of supporting the total weight (21200 lbs. in water) of the fuel assembly. The third cable was attached to the nozzle through one of the fuel assembly's orientation holes. This was a safety device, capable of supporting the entire load if the primary load bearing portion faile A second lift rig, consisting of two slings, was also constructed onsite and load tested prior to use. This rig used the auxiliary hoist on the manipulator crane and attached to a foot of the assembly's lower nozzl It was only used during the uprighting portion of the recovery proces Once the assembly was vertical, this rig was removed and the total load was sustained by the primary ri The recovery team consisted of the normal fuel handling personnel (vendor supplied), health physics personnel to monitor the process, CY maintenance personnel to operate the cranes and the polar crane main power disconnect, fuel inspectors, the recovery director, and a senior licensed operator (SRO) who was in overall control of the process. The inspector observed the recovery team training on the reccycry prcccdure and observed por-tions of the shift turnover (the recovery process required a second shif t to complete). The training and turnover briefings were very detailed and provided sufficient informatio The procedure and safety evaluation development required a number of iterations due to PORC and NRC concerns to provide sufficient safety margin, contingency planning, loose debris recovery, and personnel safet Throughout the process, safe recovery of the dropped assembly was the clear licensee goal, and any potential impact on the outage schedule did not appear to adversely affect the development or implementation of the recovery process. The fuel assembly was successfully recovered on March

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. 9 2, 198 The dropped assembly was placed in the control rod changeout fixture in the transfer canal inside containment. The assembly was then further inspected and eventually placed in the spent fuel pool on March 3, 1986 using the normal. fuel handling equipment. The process, as im-plemented, safely achieved the desired result with only two minor changes required to the procedur Subsequent to the recovery, it was determined that the two fuel assem-blies impacted by the dropped assembly were also damage The normal fuel handling equipment could not successfully latch onto these assem-blies during core offload. Recovery (fuel handling) procedures were then !

developed to move these assemblies from the core to storage locations in the spent fuel pool. This was also successfully completed. The lic-ensee observed deformation of fuel assembly orientation holes in the as-semblies that have previously occupied the same core location (R7) as the dropped assembly. This deformation was not observed on other assem-blies. The licensee gauged the upper core plate orientation pins for the R7 location and found one pin deformed such that smooth insertion into the fuel assembly alignment holes was precluded. After consultation with l the fuel vender and reactor designer, the licensee removed the bent pin from the upper guide package. Since the R7 location has two assembly surfaces adjacent to the core former baf fle, the removal of one alignment pin in that corner does not affect the stability of that fuel elemen NRC review of this repair action identified no technical concerns, how-

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ever NRC determined that such action may constitute a plant modification requiring a detailed safety evaluation. The licensee processed Plant Design Change Request 822, Upper Guide Structure Pin Removal, which documented the acceptability of the pin remova The licensee inspected and evaluated the core internals and impacted fuel assemblies for damage. The three affected assemblies were not accepted for reuse in this core cycle. These elements had only been used in the first of three planned fuel cycle One undamaged, once-burned fuel as-sembly was removed for core symmetr The licensee qualified four thrice-burned fuel elements for use during this fuel cycle. The revised core reload analyses were reviewed and approved by NRC Licensing. In addition to the three damaged assemblies, one control rod and twc thimbles were

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not qualified for reus The licensee identified no other internal core component damage requiring repair or rewor The inspector had no fur-ther questions in this are .3 Inadequate SBLOCA Analysis (LER 86-13)

' i On April 1, 1986, the licensee reported an error in the current plant safety analysis for SBLOCAs. Certain size leaks in one system location may preclude the proper operation of emergency core cooling systems (ECCS)

in the containment recirculation mode. Uncovering of the core might

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lead to core melt. Although the 58LOCA analysis included small pipe breaks in the loop 2 cold leg area of the reactor coolant system (RCS),

this analysis did not carry out the scenario to the point where the ECCS

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.' 10 flow source must be switched over from the refueling water storage tank (RWST) to the reactor containment sump. For certain sized small breaks in the loop 2 cold leg, RCS pressure is not reduced to the 165 psia maximum discharge pressure of the residual heat removal (RHR) system before the RWST supply reaches its low limit. II. order to assure con-tinued core cooling, the RHR system, which draws' vater from the contain-ment sump, is lined up to supply the charging pumps, which can discharge coolant to the loop 2 RCS piping up to full operating pressure (2000 psig). However, the licensee identified that for a range of small leaks in the loop 2 or charging system locations, the ECCS recirculation flow would leak out the break rather than reaching the core. Without core cooling, reactor vessel level slowly decreases until the core uncover The licensee discovered the analysis error during preparation of the plant Probabilistic Safety Study. The plant was in cold shutdown at the time and the licensee has committed to develop and implement corrective actions prior to plant startup in April 1986. On April 10, 1986, the licensee provided information to NRC Licensing concerning the proposed interim measures to address this problem during cycle 14 plant operatio NRC review of this proposal, involving procedural implementation of al-ternate ECCS recirculation lineups is ongoing. This item remains un-resolved pending NRC Licensing review of the licensee's proposed correc-tive actions and NRC review of the event cause(s) and generic applic-abi1ity (213/86-03-01).

7.4 During the implementation of preventive maintenance requirements for environmentally qualified (EQ) equipment, the licensee identified several discrepancies between EQ program assumed equipment configurations and the as-built configurations found in the fiel Licensee management was notified of the observed problems by a Plant Information Report (No. 86-61) on February 22, 1986. The discrepancies included, in part, incorrect motor terminations and missing motor-operated valve T-drains and grease reliefs. The licensee began a detailed verification of all EQ component configurations. No formal notification to NRC was made because the lic-ensee had not established that any specific discrepancy rendered a com-ponent inoperable. The inspector notified Region I of the nature of the licensee's findings and the intent to correct all discrepancies prior to start-up. On March 31, 1986, a conference call was held between NRC Region I and licensee management to discuss the scope of the licensee's findings and the program for corrective actions. The licensee indicated that their findings were still preliminary, but reiterated commitments to correct all identified discrepancies before start-up, and to notify NRC Region I of the final scope of the identified EQ problems and cor-rective actions. Completion of these commitments will be verified during routine NRC inspection of plant startup activities. NRC Region I will review the licensee's implementation of 10CFR50.49, Environmental Quali-fication, during a subsequent inspectio e

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8. Review of Plant Modifications During the inspection, the inspectors reviewed the implementation of selected modifications in progress to verify that; the modification was properly reviewed and approved prior to implementa-tion including evaluation of work packages risk released for construction prior to final approva the plant work scope was properly documented and controlled as necessary using work orders, procedures, drawings and specification appropriate in process control of field changes were documented and accomplishe the modification was completed in accordance with the design document appropriate construction and pre-operational testing was satisfactorily complete appropriate quality assurance documentation was completed and reviewed prior to system turnove appropricte training and procedures were completed prior to system turnove .1 Plant Design Change Request (PDCR) 781, Permanent Cavity Seal Ring (PCSR),

controlled the installation of a new permanent seal in the annulus be-tween the reactor vessel and the refueling cavity floor. The seal pre-vents loss of refueling cavity water through the annulus during refueling operations, and has four hatches which are opened during plant operation to allow cavity drainage from a leak in the reactor vessel (RV) head area or from the containment spray syste The inspectors observed the im-plementation of this design change, including design approval, installa-tion and testing. The licensee completed the review and approval of PDCR 781 on January 17, 198 Inspector review of the approved design package identified two areas of concern related to the permanent seal desig First, the approved test plan for the cavity seal did not include a functional test to verify the leak tight integrity of the final instal-lation. Second, inadvertent closure of the PCSR hatches obstructs the recirculation flow path of emergency core cooling systems (ECCS) for reactor coolant system breaks in the head area. Similar obstructions to ECCS flow, such as manual valves, are required by technical specifi-

, cations (TS) to be locked in their accident position. No such TS change l was requested for the PCSR hatche The design did specify that the

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hatch covers would be administratively controlled by the refueling pro-

cedure, and grates placed over the hatch openings prevent closure of a l hatch if the grates are installed. The inspector discussed these con-cerns with licensee management. A functional leak test was added to the i

test plan for this project on February 11, 1986. Completion of that test i

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. 12 is discussed below. The licensee committed to address the question of

, TS coverage for the PCSR hatches in the future conversion to standard TSs. This commitment is tracked by nonconformance report 86-107 dated February 20, 198 During NRC Licensing review of the PCSR, the basis of the seal design was questioned because the licensee used a leak-before-break criteria to develop the small break LOCA forces to which the seal structure would be subjected. NRC was concerned that the licensee.had not yet satisfied

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all the prerequisites necessary to use the leak-before-break criteri Specifically, the plant leak monitoring systems are not required to re-main operable during plant operations, and certain structural criteria have not been me These issues are currently being addressed by NRC Licensin Several other problems developed during the PCSR installation. The lic-ensee accepted several nonconforming dimensions in the four cavity seal segments shipped to the site. As a result, the segments did not fit into place as designed. Field changes.were required to address the abnormal fit-up requirements. For one segment, a special heat treatment and bending was attempted to reshape the component to fit into place. Ulti-mately, this segment was preheated into place, resulting in an asymmetric preload on the RV flange in the cold, unloaded condition. The licensee carefully reviewed and controlled these' installation activitie The inspectors found job supervisors and cognizant engineers to be knowledge-able of ongoing activities, and the design field changes were properly documented. One exception to the correct and timely documentation of field changes was the treatment of the backup seal element of the PCS The safety evaluations for PDCR 781 and the onsite review committee .

minutes for meeting no. 86-25 indicate a purpose of the J-seal membrane on each seal segment to be to act as a backup seal should the primary seal membrane fail. Design Change Notices (DCNs) 86-138-02 and 86-138-03 implemented on January 28-30, 1986 and other contractor initiated changes resulted in the backup seal being inctalled in a condition different from the original design. Although cognizant personnel stated that no credit

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was being taken for the backup seal, the inspector found no action taken to clarify the original design documents. The inspector brought this concern to management attention, and on February 12, 1986, a memorandum was written clarifying that the backup seal was not relied upon for the safety of this design. This memorandum was subsequently incorporated in the PDCR 781 package on February 22, 1986.

. Upon completion of the cavity seal installation, a functional leak test

was conducted on February 21, 198 The acceptance criteria specified

was zero leak rate. The inspector observed the leakage verification under the seal and confirmed the identification of two small leaks (ap-proximately 180 drops per minute). After careful consideration of all possible leak sources and the potential for leak propagation, the licen-see dispositioned the PCSR to use-as-i Leakage surveillance continued with specific action required to be taken for any noted change in leak

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. 13 rate. .The inspector verified incorporation of these actions in the ven-

' dor refueling procedure, VP 72. The leakage remained about the same throughout the refueling. No further discrepancies were identifie .2 The inspector also reviewed the implementation of PDCR 786, Steam Genera-tor Wet Layup. This modification involved procurement of temporary steam generator water recirculation and chemical control equipment and instal-lation of valves and fittings to accommodate the portable equipment dur-ing the outage. During the PORC review of the design package on January 10, 1986, it was noted that several fire protection safety measures needed to be incorporated with the design change (memo GMB 85-467). Upon turnover of the modification for operation, the inspector reviewed the installation and system operating procedures to verify incorporation of these committed safety measures. The inspector identified that the sys-tem operating procedure was still in draft, and the fire pratection re-quirements had not yet been implemented. The inspector also found that the system was not operating because of leakage past the main feedwater system check valves inside containment. This prevented filling the steam generators to wet layup without filling the main feed lines outside con-tainment which are not heat traced. Procedure 1.2-3.1, Preparation, Re-view and Disposition of PDCRs, requires all operating procedures to be updated prior to system turnover to operations. The failure to implement normal operating procedure (N0P) 2.19-5, Steam Generator Wet Layup Re-circulation System Setup and Storage, as specified by PDCR 786, prior to system turnover on February 7,1986 constitutes a violation. As of April 1, 1986, N0P 2.19-5 had not been approved and PDCR 786 was being re-evaluated to address the check valve leakage problem. This item will be reviewed upon completion of the system redesign (V'O 213/86-03-02). 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 NRC required data; that test results

! and supporting information were consistent with design predictions and per-L 'formance specifications; and that planned corrective actions were adequate i for resolution of the problem. -The inspector also ascertained whether any reported information should be classified as an abnormal occurrence. The

- following periodic reports were reviewed

--Monthly Operating Report 86-02

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--Monthly Operating Report 86-03 These reports cover plant operations from February 1,1986 to March 31, 198 '

1 Unresolved Items Unresolved items are matters about which more information is required in order to determine whether they are acceptable items or violations. Unresolved

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items identified during this inspection are discussed in Paragraph 7.3.

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During 'this inspection, meetings were held with plant management to discuss

the finding No proprietary information related to this inspection was

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