IR 05000443/1986047
| ML20211Q121 | |
| Person / Time | |
|---|---|
| Site: | Seabrook  |
| Issue date: | 12/10/1986 |
| From: | Elsasser T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20211P918 | List: |
| References | |
| 50-443-86-47, IEB-86-002, IEB-86-2, NUDOCS 8612190203 | |
| Download: ML20211Q121 (19) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-443/86-47 Docket No.
50-443 License No.
NPF-56 Permit No.
CPPR-135 Priority --
Category 8/C Licensee:
Public Service Company of New Hampshire 1000 Elm Street Manchester, New Hampshire 03105 Facility Name:
Seabrook Station, Unit 1 Inspection at:
Seabrook, New Hampshire Inspection conducted:
September 16 - November 10,1986 Inspectors:
A. C. Cerne, Sr. Resident Inspector D. G. Ruscitto, Resident Inspector D. R. Haverkamp, Project Engineer J. G. Hunter, Reactor Engineer R. S. Barkle,
ident Inspector, Indian Point 3 Approved by:
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T. C. Elsa Chief, Reactor Projects Section 3C Date Inspection Summary:
Inspection on September 16 - November 10,1986 (Report No.
50-443/86-47)
Areas Inspected: Routine inspection by three resident inspectors and two region-based inspectors of work activities, procedures, and records relative to startup testing and license issuance; core loading activities; maintenance, surveillance and plant operations; and licensee event reports.
The inspectors also reviewed licensee action on previously identified items, including a 10 CFR 50.55(e) report and licensee actions in response to an I&E Bulletin, and performed plant inspec-tion-tours.
The inspection involved 428 inspection-hours by five NRC inspectors.
Results:
An apparent violation was identified concerning the implementation of the locked valve program to prevent dilution of the reactor coolant system (Section 7).
Unresolved items were identified for future follow-up.
With respect to several previously identified open items, including 10 CFR 50.55(e)
reports and response to an I&E Bulletin, licensee actions and corrective measures were verified to be either complete or in progress and properly directed.
8612190203 861212 PDR ADOCK 05000443 Q
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DETAILS 1.
Persons Contacted W. P. Johnson, Vice President and Director of Quality Programs (NHY)
G. S. Thomas, Vice President, Nuclear. Production (NHY)
J. DeVincentis, Director of Engineering-(NHY)
G. F. Mcdonald, Construction QA Manager (YAEC)
D. E. Moody, Station Manager (NH/)
D. G. McLain, Startup Test Group Manager (NHY)
Interviews and discussions with other members of licensee and contractor management, and with their staffs, were also conducted relative to the in-spection of items documented in this report.
2.
Plant Status C': ring this inspection period the unit was readied for core loading operations.
A "zero power" operating license was issued purssant to 10 CFR 50.57(c) on October 17, 1986.
This license authorizes fuel loading and pre-criticality testing but does not allow plant startup and low power testing.
Core load activities commenced and Mode 6 was entered at 6:40 p.m. on October 22, 1986.
Core loading was completed on October 29, 1986.
Reactor vessel head tension-ing was completed at 6:45 p.m. on November 5, 1986 placing the plant in Mode 5.
The unit remained depressurized and vented to atmosphere while prepara-tions were made for filling and venting of the RCS.
3.
Plant Inspection Tours The inspectors observed work activities in progress, completed work and plant status in several areas during general inspection of the plant.
They examined work for any obvious defects or noncompliance with regulatory requirements or license conditions.
Particular note was taken of the presence of quality control inspectors and quality control evidence such as inspection records,
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material identification, nonconforming material identification, housekeeping and equipment preservation.
The inspectors interviewed station staff person-nel, craft personnel, supervision, and quality inspection personnel as such personnel were available in the work areas.
During frequent control room observ'ation periods, the inspectors perisdically reviewed control room logs and' records including night orders, shift journals, shift turnover sheets, completed Repetitive Task Sheets (RTS), the temporary modifications log, weekly surveillance schedules and control board indications.
Specific note was taken of eqJipment in " pull-to lock" conditions, equipment t
tagged, alarm status and adherence to Technical Specifications (TS) Limiting Conditions for Operation (LCOs) and Action Statements.
No violations were identified.
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On August 7, 1986. during the previous resident inspection period, the in-spector observed installation of the reactor vessel upper internals in pre-paration for head installation to facilitate painting on the polar crane.
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The inspector noted that the activity was carried out in accordance with pro-cedure MS0504.15 (Rev. 00), " Installation of Upper Internals Assembly and Removal of Reactor Flange Protective Ring Assembly." The inspector reviewed work request 86W006325 and n,oted that QC holdpoints'were identified and signed i
off as completed, and that procedural prerequesites and initial conditions were met. An adequate number of workers were available to properly perform the task and a quality control (QC) inspector was on the job site.
The job was well supervised and particular attention was paid to the maintenance of cleanliness requirements.
A On October 10,'1986,'while inside the Unit 1 containment, the inspector wit-nessed rework on certain Raychem heat shrinkable tubing. electrical termina-tions.
Based on discussion with the responsible engineer, the inspector.de-termined the adequacy of work controls and that installation criteria.were in accordance with WR 86-2981.
Specifically, this rework was:being conducted to assure use of the properly sized shims and heat shrink tubing for the ter-minati,ons.
The need for rework in other areas of containment, e.g., electri-cal penetrations, had already been addressed in request for engineering ser-vices (RES) 157 which generically covers the question of the acceptabi7fty of environmental qualification (EQ) of the existing splices.
Furttier discussion with licensing engineers indicated that additional analysis of the EQ of certain Raychem electrical splices and terminations with bend
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radii less than five cable diameters was in progress.
Raychem testing was expected to provide data to clarify the acceptability of the subject instal-lations and to determine'whether rework is required.
The inspector noted that the licensee's overall approach to the question of heat shrinkable tubing EQ installation adequacy appeared to be comprehensive and well-defined by cri-teria selected by an engineering review of the available Raychem vendor in-formation.
However, this matter is unresolved pending final licensee deter-mination of the EQ status of these Raychem installations and NRC review of the pertinent test results and analysis (443/86-47-01).
While touring the control room on October 25, 1986, the inspector noted that a particular valve (1-CAP-V-3) indicated mid position.
The plant was in mode 6 at the time and TS 3.9.9, " Containment Purge and Exhaust Isolation System" l
was applicable.
This specification reqdres that the containment air purge (CAP) system be operable.
Licensee operator attempts to close the valve from i
the control room were unsuccessful, and they appropriately suspended core alterations and declared the valve inoperable, entering action statement "a".
This action requires that each purge and exhaust penetration be closed.
Since CAP-V-4, which is in line with CAP-V-3, was shut at the time, no direct, un-isolable path from the containment atmosphere existed.
Control room operator actions were correct and timely, and the inspector had no further questions at thet time.
As of the end of this inspection period, the cause of the CAP-i V-3 failure was still undetermined.
Its repair will be tracked under existing unreso?ved item 86-46-03 dealing with previously identified CAP questions.
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-On October 25, 1986, the inspector identified a potential flow path between the small waste liquid disposal system sumps in containment and the waste processing building sump.
The inspector then questioned the licensee's com-pliance'with TS 3.9.4, " Containment Building Penetrations", which requires that each penetration providing direct access frcm the containment atmosphere to the outside atmosphere be closed.
In response to NRC questioning, licensee
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representatives stated their position that-since the lines were fluid-filled,
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they did not provide a potential flow path.
Subsequent checks by the inspec-l'
tor revealed that the subject line was filled.
Based on this fact and dis-cussion with NRR reviewers with respect to the analysis of flow path criteria,
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f the inspector had no further concerns on this matter. As a result of discus-sion with the inspector and the clarification obtained from NRR, the licensee intends to re-evaluate its procedure and, if necessary, revise the criteria used to select the valves to be surveilled.
On November 7, 1986, while inspecting safety-related equipment for operability in accordance with TS requirements applicable at the time (mode 5), the in-spector noted'that temporary scaffolding had been erected over both centri-fugal charging pumps, over both diesels, and in the boric acid tank room.
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Additionally, permanently installed monorail cranes were unsecured above the charging pumps.
Discussion with licensee personnel revealed that they under-
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stood that conditions affecting component operability could be changed as a result' f temporary staging or storage.
In this regard, licensee personnel had oreviously requested an engineering evaluation of the scaffolding; however, no action had been taken to date.
The licensee agreed to expedite this evaluation as well as to evaluate the possible effects of monorail crane storage on operability.
Specific areas of inspector concern were with both the swing arc of the hoists as well as the seismic acceptability of the rail and/or hoist.
These two concerns along with the above question of temporary staging constitute an unresolved item (443/86-47-02), pending further NRC review of this matter during a subsequent inspection.
During early November 1986, the inspector reviewed the operability of selected-reactor coolant (RC) and safety injection (SI) system relief valves within containment, including RC-V-24 and 89, and SI-V-10, 30, 45, and 60.
Pressure relief setpoints were checked with respect to TS 3.5.1, for the SI accumula-tors, and TS 3.4.9.3, for the RC relief valves on the residual heat removal
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suction (RHR) suction lines.
While the accumulators are not required to be s
operable until in Mode 3, RC-V-24 & 89 operability is a condition of Modes 5 and 6.
These valves were field inspected in accordance with the vendor (Crosby Valve and Gage Co.) instruction manual and shop drawing (Foreign Print
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50457).
While minor discrepancies were identified with respect to valve tag-ging, cap sealing and vent plugging, none of these items adversely affected the operability of the valves.
These discrepancies were discussed with lic-(
ensee maintenance personnel and will be given further licensee review.
Additionally, with respect to TS 3.5.1, the inspector exanined the condition and status of the accumulator isolation valves and the solenoid-operated
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valves providing a vent path for the nitrogen cover gas.
Specifically, re-l dondant train power to the diverse valves on each accumulator was verified.
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Regarding TS 3.4.9.3, the installation of an RCS vent of area greater than 1.58 square inches was noted to be an in progress construction activity, governed by ASME Section XI requirements.
The inspector witnessed certain welding operations for the two-inch branch line and valve (RC-V-468) connec-tion to the pressurizer head piping leading to the power-operated relief valves.
The inspector observed that the hole was acceptably drilled through the nozzle boss and verified that NDE and hydrostatic test details were in accordance with the applicable Section XI provisions for Class 1 piping with a nominal operating pressure of 2235 psig.
The design details and specified controls of engineering change authorization (ECA) 19/118530A were reviewed and QC coverage and hold point inspection activities were confirmed.
With respect to this modification, and valve details checked for conformance to TS conditions, no violations were identified.
During several inspection tours of the plant, the inspector noted certain questionable electrical installation details with respect to the two general areas of conduit support tagging and adjustment of Kellems grips.
The in-spector questioned the status of construction and quality assurance (QA) con-trols in these areas and was informed of the following licensee actions, al-ready in progress.
In regard to conduit support tagging, licensee QA management had determined that missing support tags need not be replaced because quality documentation on the affected supports could be retrieved by either the support number or the conduit number, when traced through the installation inspection reports, to identify the subject support.
Since conduit support tagging represented a good practice for installation and administrative control purposes, rather than a technical requirement, licensee personnel considered that retagging of the electrical supports was not deemed necessary.
The inspector reviewed this position and confirmed the retrievability of construction documentation from quality records and, therefore, the requisite traceability.
In the case of several Kellems grips which appeared to inadequately support their respective cables, the licensee conducted a 100% reinspection of all installed Kellems grips.
This was accomplished in accordance with cable tray access provided by work request (WR) 86-7610, the corrective action disposi-tion to nonconformance report (NCR) 86-0101, and the acceptance criteria de-lineated in engineering change authorization (ECA) 03/118488B.
YAEC QA in-spectors also conducted a surveillance of the subject rework to predetermined engineering acceptance attributes.
The NRC inspector reviewed QC inspection reports and the quality records associated with the 100% reinspection and discussed the rework with QA personnel.
Based on this review, the inspector determined that the installed Kellems grips were adequate.
With reosect to all of the above plant inspection tour and independent in-spection items, no violations were identified.
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4.
Licensee Action on Previously Identified Items (Closed) Construction Deficiency Report (CDR) 85-00-13: Service water a.
system spool piece lining detachment problems.
Upon discovery of several cases of detached polyurethane lining in the service water (SW) system during testing in August,1985, the licensee formed a Service Water Sys-tem Lining Task Team of YAEC and UE&C engineering, construction and QA personnel to quantify the problems and propose engineering solutions.
On August 20,1985, this deficiency was reported to the NRC Region I as a CDR in accordance with 10 CFR 50.55(e).
Since that time, the SW Task Team has issued biweekly status reports of proposed and implemented corrective action.
Also, the licensee issued interim 10 CFR 50.55(e) reports to NRC Region I on September 18, 1985 and January 13, 1986 and a final report on April 10, 1986.
Licensee cor-rective actions included the replacement of the polyurethane linings in the SW pipe spools with a Belzona epoxy-like barrier; the replacement of the polyurethane inserts at the flanges of the cement-lined pipe with another type of Belzona filler and coating; and the modification of the butterfly valve lining and seat design such that a rubber-like Belzona-material reinforced with a steel ring was installed.
Also, flow balanc-ing orifices were installed in the system.
During previous NRC inspections, the inspector reviewed licensee status reports on the implementation of corrective action in progress and peri-odically checked field rework activities including grit blasting, pipe and valve relining, and QC inspection of Belzona lining thicknesses by spark-testing techniques.
YAEC QA surveillance inspection reports of the SW modifications were reviewed to confirm compliance to UE&C proce-dure FPP-13, " Application of Belzona Coatings to Interior Surfaces". The inspector also reviewed an Employee Allegation Resolution (EAR) file which addressed a concern regarding Belzona material curing times and the minimum purge time between metal washings after grit blasting.
Additionally, the inspector witnessed reinspections in March and Septem-I ber, 1986 of the Belzona liner material after operation of the SW system.
At both times, the piping ir. the proximity of service water valve SW-V-15 l
was checked because of the heavy cavitation expected downstream of that valve due to the design flow condition during periods of SW dump to the cooling tower basin. This particular operation is needed for basin de-icing in the winter months.
The inspector noted no evidence of Belzona lining deterioration, even where lining pits had been repaired during earlier rework activities.
I In letters to Region I dated September 18 and October 15, 1986, the lic-ensee addressed the recent SW lining reinspection and its results and committed to another internal inspection after the first refueling outage.
i The inspector evaluated all licensee rework, analyses, and reinspections
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and verified the conduct of appropriate corrective action with adequate QA/QC coverage.
Based on NRC inspector confirmation of licensee actions taken to date, as discussed above, this CDR is closed.
b.
(Closed) IE Bulletin (IEB) 86-02: Static "0" Ring Differential Pressure Switches.
This IEB pertained to specific switches manufactured by 50R, Incorporated.
The licensee response to this bulletin (SBN-1194, dated September 15,1986) indicated that none of the identified pressure switches are utilized at Seabrook in any application.
This bulletin is closed.
c.
(Closed) Unresolved Item (443/86-09-01): SORC Review of Alarm Response Procedures.
This item indicated that there were certain alarm response procedures which required 50RC Review. NRC Region I IR 50-443/86-28 up-dated the status of licensee efforts in this area.
The inspector noted that the SORC had reviewed local alarm response procedures, hard wired annunciator system alarm response procedures and selected safety-related system video alarm procedures.
Based on the above information, this item is closed.
d.
(Closed) Unresolved Item (443/86-09-02): Failure to Provide SORC Review and Station Manager f.pproval For Technical Specification Daily and Shift Surveillance Logs.
The licensee has developed control room logs for modes 1-6 which document daily and shift surveillances required by Tech-nical Specificiations.
Those logs were reviewed and approved by the Station Manager on October 18, 1986 and by the Station Operating Review Committee (SORC) during meeting number 86-50K.
This item is closed.
e.
(Closed) Unresolved Item (443/86-27-01): Apparent Technical Discrepancies Between the Final Safety Analysis Report (FSAR) and the Proposed Techni-cal Specifications (TS).
The inspector verified that the TS and Techni-cal Requirements Manual (NPTR) specifications regarding normal contain-ment operating pressure and containment spray system response times, which were in question, were accurate and within the design bases stated in the FSAR.
This item is closed.
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(Closed) Unresolved Item (443/86-27-03):
Proximity of Construction Site Power Lines and Security Lighting Poles to the Offsite Power Bus Runs.
The inspector toured the area surrounding the offsite power bus runs.
l He verified that the construction power line which previously crossed over the bus runs had been rerouted away from the area.
None of the other lighting and telephone poles in the vicinity present a hazard to the bus runs due to either their location, light construction, or the physical protection features surrounding the buses.
This item is con-sidered closed.
g.
(Closed) Unresolved Item (443/86-28-03): Finalize Reactor Engineering l
Computer Programs.
This item remained open pending completion of licen-see action to complete those reactor engineering programs required for l
core load.
The inspector reviewed the implementing work requests listed
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WR SC-0617, Hot Functional Testing Routines WR SC-0403, RCS Heatup and Cooldown Temperature Changes
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WR SC-0460, CW System Average Temperatures
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86W002110, Various Miscellaneous Routines
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86W002111, Various Miscellaneous Routines Based on the above review, the inspector found licensee action and schedular considerations to be on track and had no further questions.
This item is closed.
h.
-(Closed) Unresolved Item (443/86-46-02): Westinghouse Concurrence With the Preoperational Hot Leg Flow Test Results.
The inspector reviewed a copy of a Westinghouse Electirc Corporation letter (NAH-3179) to YAEC dated October 17, 1986.
The subject test procedure (1-PT-8A) and re-corded test data were reviewed by Westinghouse engineers and found to be functionally consistent with Westinghouse criteria for RHR recircula-tion flow.
Acceptable performance of the low head safety injection pumps during the recirculation mode of operation was achieved by the testing.
In response to an NRC question, the 1-PT-8A test data package was sup-plemented by information to explain why the original maximum RHR flowrate (reference: steps 6.2.8 and 6.2.14) had been exceeded during the hot leg recirculation mode of testing.
This preoperational test supplemental information was approved by the Joint Test Group on September 25, 1986.
Test acceptance criteria previously had been revised correctly in Field Change 5 to the PT.
The inspector had no further questions on the conduct of this preopera-tional test or the recorded test results.
This item is closed.
5.
10 CFR 50.57(c) Submittal On August 22, 1986 the licensee submitted a request to the NRC for issuance of a license to load fuel and to conduct pre-criticality testing in accordance with 10 CFR 50.57(c).
A portion of the licensee's submittal included the measures to be taken to preclude inadvertent criticality, i.e., (1) maintain-ing RCS boron concentration at all times above 2,000 ppm, (2) locking closed all valves which could provide a dilution flow path from an unborated (<2,000 ppm) water source, and (3) periodic sampling of the RCS and makeup supplies to verify boron concentration.
The inspector conducted a detailed review of the licensee's proposed locked valve list and the special procedure written to ensure boron concentration remained above 2,000 ppm.
The initial review indicated that the licensee's evaluation of locked valves was not in conformance fully with their August 22, 1986 affidavit.
Subse-quently, a n.eeting was held in Bethesda, Maryland between the NRC and the licensee.
As a result of this meeting, specific criteria from which the locked valve list would be generated were agreed upon, and based on that cri-
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teria, the licensee submitted a revised listing of lock.ed valves. An addi-tional NRC review was conducted on a sampling basis of the new locked valve list and the licensee's drawings used to generate that list.
Discussions with operations and engineering personnel from NHY resolved any questions or con-cerns with respect to the revised list.
The inspector also discussed with licensee personnel the adequacy of other affected procedures, requiring modi-fication based upon the closure and locking of the listed valves.
These other special procedures were also reviewed on a sampling basis.
In determining that a boron concentration of 2,000 ppm would provide sufficient shutdown margin to preclude inadvertent criticality, the inspector reviewed the YAEC Boron Dilution Analysis for the initial fuel cycle.
He specifically checked calculations for operational modes 3 through 6, confirming an approxi-mate 700 ppm boron margin to criticality in Mode 6.
This mode represents the least conservative mode of operation, because of the insertion of the negative reactivity of heat up thrnugh the other modes.
Also, in accordance with the LCO for TS 3.9.1, a boron concentration greater than 2,000 ppm would ensure aK f less than 0.95.
eff With respect to the licensee's 10CFR50.57(c) request and the subsequent issu-ance of Facility Operating License (NPF-56) on October 17, 1986, the inspect-or's review of the licensee measures to control boron concentration, prevent inadvertent dilution and thus assure subcritical operations under this license, revealed no unresolved safety concerns.
No violations were identified.
6.
Startup Testing a.
1-ST-2 Primary Source Installation The inspector witnessed preparations for installation of the primary neutron source rods, which included fuel assembly transfer, shift pre-briefing, fuel handling equipment surveillance and source cask uprighting.
The reactor engineer supervising the operation was knowledgeable and health physics precautions were given a high priority. When the new fuel elevator top stop bolts sheared during fuel assembly transfer, the ac-tions of the crew were appropriate.
They conservatively jogged the af-fected assembly out of the elevator, visually inspecting it every few inches.
Once the assembly was safely stored in its location in the new fuel storage vault, the test was suspended while senior startup, main-tenance and operating personnel evaluated the situation.
The inoperable new fuel elevator was not required for the next several steps in 1-ST-2, and the source loading was resumed without incident.
The inspector noted that the health physics technicians took charge of the radiation protec-tion and monitoring function and provided independent direction to crew personnel with respect to ALARA considerations.
The presence of QC in-spectors and insertion of QC hold points within the procedure were also noted.
The inspector reviewed the implementing work request (86W004717)
and its associated attachments, particularly checking that the required
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Westinghouse drawings were present for reference.
Proper procedural adherence was verified with specific attention paid to the nut torquing and welding operations.
No violations were identified.
b.
1-ST-4 Initial Core Loading Operational mode 6 was officially entered at 6:40 p.m. on October 22, 1986 and fuel loading continued until completion on October 29, 1986 with some delays for equipment adjustments, procedural interpretation or verification of technical specification (TS) compliance.
NRC inspection activities of the core loading evolution involved full time coverage by resident and region-based inspectors.
The inspectors' observations of initial core loading activities were conducted in the control room, in the fuel storage building (FSB) and in the reactor containment structure.
Overall control and coordination of the initial core loading were provided by reactor engineers in the control room, and core loading was supervised by a senior licensed opera-tor having no concurrent duties.
Startup Test Procedure 1-ST-4, Revision 3, " Initial Core Loading", provided detailed instructions for the conduct of core loading, and Station Operating Procedure OS 1015.05, Revision 1, " Fuel Transfer System and Upender Operation", provided specific equipment operating instructions.
Test procedure 1-ST-4 was reviewed prior to the commencement of core loading tc, verify conformance with Regulatory Guide 1.68 and the Seabrook FSAR.
During the course of the seven-day loading evolution, the inspec-tors frequently reviewed the record copy of the procedure, all field changes, test exceptions, logs and plans.
Initial conditions, references and prerequisites were verified.
One test exception with respect to the recording Fequirements associated with the temporary neutron monitoring instrumentation is described in NRC Region I Inspection Report 50-440/
86-50.
The inspector noted that all personnel who were assigned functions re-lated to initial core loading performed their duties in a well-coordinated and professional manner.
Personnel had been properly trained and briefed and were familiar with the procedures for initial core loading and with their required duties.
Copies of the core loading sequence (Attachaent 9.1 to Procedure 1-ST-4) were provided to and properly implemented by the control room operator, spent fuel bridge operator and refueling machine operator. The master copy of the sequence was properly maintained by the reactor engineers in the control room.
The special nuclear mate-rial (SNM) tag board was used effectively in the control room to maintain specific accountability of fuel assembly movements from the fuel pool to the reactor cavity.
Most importantly, personnel who were directly conducting or supporting fuel assembly handling operations assured that such activities were performed carefully, cautiously, and in accordance with the approved procedures.
Whenever actual problems or potential
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operational concerns were identified, core loading operations were promptly terminated and not resumed until the matter was properly evalu-ated and resolved.
With respect to a problem encountered during fuel loading whereby one assembly could not be properly inserted into its designated core position, Field Change 6 to 1-ST-4 was issued.
The revised procedural steps pro-vided for movement of the subject assembly to an open core position until all other assemblies were inserted into the affected core quadrant.
The subject assembly was then relocated to its designated position and in-serted without problem.
The inspector confirmed that this technique was in accordance with guidance provided by Westinghouse procedures SU-3.2.1 and F-5.
With respect to the TS definition of " core alterations", there was dis-cussion between licensee and NRC personnel over which in-vessel component movements were considered core alterations.
Until such time as a specific clarification could be made, the licensee adopted the conservative posi-tion that movement of any component, including temporary detectors and the core mapping camera, was to be performed with all the requirements for " core alterations" established.
No violations were identified during observations of initial core loading.
c.
Vessel Reassembly The inspectors witnessed installation of the reactor upper internals and removal of the reactor vessel flange protective ring assembly.
These activities were conducted in accordance with procedure M50504.15 (Rev.
00).
The inspector observed proper installation and setup of the load cell and adherence to the Seabrook Station requirements to implement NUREG 0612, " Control of Heavy Loads".
The safe load path drawing for the upper internals is included as Figure 10.1 to MS0504.15.
The in-spector verified that prerequisites were met and that the procedure was followed.
Also, work request (WR) 86W002446, which includes installation of the upper internals, was reviewed.
One minor error with respect to the applicable operating mode on the WR was noted and brought to the attention of the refueling senior reactor operator (SRO).
Following upper internals installation, the control rod drive shafts were coupled to the control rods and the thimble tubes were inserted into the core.
The inspector witnessed the changing of the reactor vessel head 0 rings in accordance with MS0504.13 (Rev.00).
The inspector noted that extreme care was taken in both the removal of the 0-ring protective cover and in lifting the 0-rings into the groove in the vessel head and attach-ing the retaining clips.
The reactor vessel head was then set into place using MS0504.16 (Rev.00).
Once again operation of the load cell and safe load paths were verified.
Following installation of the three radial arm hoists, the reactor head studs, nuts and washers were installed and then sequentially torqued in accordance with MS0504.18 (Rev.00).
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lowing head stud torquing, the reactor cavity seal ring and head lifting rig were removed and stored.
The licensee verified mode change prere-quisites prior to entering Mode 5.
Throughout the duration of the above four procedures, quality control (QC) inspectors were at the job site performing both overall work surveillance and specific inspection of QC hold points which had been established prior to job commencement.
Both the QC inspectors and the maintenance personnel were found to be knowl-edgeable concerning their duties.
All core alterations were supervised by an SRO-licensed individual, as required by Technical Specifications.
Additionally, the inspectors periodically verified both by records review and field inspection that other Technical Specifications requirements for core alterations were being met.
No violations were identified.
d.
Appendix J Testing 10 CFR 50, Appendix J, requires in section III.D.2 that open " containment penetrations subject to Type B testing shall be Type B tested prior to returning the reactor to an operating mode requiring containment integ-rity."
In the case of the containment personnel hatch, which has been open to allow personnel access, this required Type B testing is scheduled for conduct prior to mode 4 operation.
Section III.D.2(b)(1) also states that " air locks shall be tested prior to initial fuel loading..." There-fore, testing prior to mode 6 was required.
On October 16, 1986, a Type B test was performed on the containment per-sonnel hatch in order to meet the requirements of Appendix J,Section III.D.2(b)(i).
The inspector witnessed a major portion of this test, conducted in accordance with surveillance procedure EX1803.003 and under the authority of work request (WR) 86W00865.
Local leak rate testing of the fuel transfer tube flange was also conducted by direction of this WR.
Specifically, the inspector witnessed the completion of local leak rate tests on the inner and outer doors of the personnel hatch and the pres-sure decay leak rate test on the hatch barrel to the point of stabiliza-tion of test pressure and temperature.
Utilizing a nominal test pressure of 50 psig, both doors (for which the 0-rings had been replaced) exhibited
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a measured leak rate of zero.
The hatch barrel, using pressure decay calculations after a one hour hold period at the test pressure, also j
exhibited a zero leak rate.
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The inspector discussed the test results with the responsible test engi-neer and determined that Appendix J requirements for initial fuel loading had been met.
Additional testing to satisfy the containment integrity
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requirements for mode 4 is planned prior to entering that mode of opera-tion.
The inspector also reviewed the preoperational test (1-PT-37.2A) for local leak rate testing of other containment penetrations. With regard to the electrical penetrations, the operation of the low volume test
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panel, the acceptance criteria and the leakage calculations were all discussed with a cognizant licensee startup engineer and an NRC Region I specialist.
The question of the purpose and use of the permanently installed pressure indicator supplied by Westinghouse with each electri-cal penetration was raised.
The inspector determined that maintenance of a nominal pressure on the space between the penetration 0-rings is recommended to preserve the seals, but that this pressure indicator is not used in the actual Type B testing required of the electrical pene-trations to satisfy Appendix J requirements.
Preoperation test 1-PT-37.2A test records document acceptable results with respect to leakage criteria, calculated with respect to the containment design peak accident pressure.
No violations were identified.
7.
Special fuel Load Conditions Upon issuance of the license for fuel loading and precriticality testing, the special conditions specified in license No. NPF-56 were reviewed by the in-spectors and spot-checked for licensee compliance.
Included in the selected sample of licensee activities observed with respect to the license conditions were TS and procedural controls, fire protection program compensatory measures, physical security plan implementation, Appendix J testing and exemptions and special measures to preclude inadvertent boron dilution.
During the period of initial fuel loading, continuous inspection coverage of licensee activities was provided by the NRC inspectors while fuel was being moved.
The applicable inspection areas and findings are documented in this report, in conjunction with specialist inspection coverage documented in NRC inspection report 443/86-50.
The inspectors verified, over the course of this inspection period, that the licensee maintained a boron concentration in ex-cess of 2,000 ppm in the reactor coolant system (RCS).
Additionally, the licensee's implementation of programmatic controls to prevent inadvertent boron dilution was spot-checked as noted below.
Prior to the licensee initiation of mode 6 operation, an NRC inspector inde-pendently verified the " chain-locked closed" condition of 13 of the 17 valves identified by the licensee in a letter to NRR (SBN-1196) as valves in a poten-tial dilution flow path from unborated water sources for which valve operation is prohibited under the NPF-56 license conditions.
Of an additional 20 valves included in SBN-1196 as those which can be unlocked and operated under special controlled conditions, the inspector checked eleven valves and confirmed them to be " chain-locked closea".
He also verified that the power supply to one specific valve, as delineated in SBN-1196, was properly placed out of service with the circuit breaker racked out and locked closed.
Subsequent to the commencement of fuel loading, one of the locked valves (DM-V-237) was found to be leaking by station personnel.
Although the leak was minute, the duty shift superintendent decided to lock open a drain valve (DM-V-82) on the header downstream of the leaking valve to prevent pressurizing the header.
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A revision to the applicable station operating procadure was initiated to add the " chain-locked open" position verification to DM-V-82 to provide commen-surate protection against boron dilution.
h sodically during the course of mode 6 activities, NRC inspectors witnessed sr,, ling of coolant water in the RCS system and confirn'ed the analysis of boron concentration to be within defined procedural li; nits.
The Chemistry Laboratory Log (RCS CH-L01) was reviewed to verify sa:npling not only in com-pliance with license conditions, but also in accordance 1-ST-4 procedural testing precautions.
An inspector also verified the operability of redundant trains of piping and equipment in the RHR system, checking valve position and equipment operation in accordance with the system conditions and lineup asso-ciated with the specific RHR train ("B") in operation at that time.
Other plant system status, e.g., reactor make-up water, was spot-checked during this inspection. Periodically, auxiliary operators (A0s) were accompanied in the performance of tasks associated with TS requirements and special license con-ditions, particularly locked valve surveillarces.
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On October 23, 1986, during the conduct of a surveillance of the unborated water source locked valves.(reference: Station Operating Procedure, 0S-86-1-7, Revision 1),an NRC inspector witnessed A0 performance of the repetitive task verifying the " chain-locked closed" status of all required valves.
At that time, the A0 identified one valve (CS-V-744) to be mispositioned open and locked in this position.
Immediate licensee corrective actions to reposition the valve were initiated and judged adequate by NRC inspection.
Subsequent corrective measures by the licensee included an analysis of the i
potential flow path for unborated water to the RCS created by the open valve; a walkdown of all unborated water source locked valves by the shift superin-tendents and A0s to establish consistency in the application of the repetitive surveillance of these valves; and an evaluation of the method of locking cer-tain valves (including CS-V-744) which prevented the observation of valve position without unlocking the valve.
A Licensee Event Report (LER 86-001-00)
was telephonically communicated to the NRC on October 23, 1986.
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During the period of time that CS-V-744 was mispositioned, a credible flow path of unborated water to the RCS did not exist because of other closed (but not locked) valves in the system and the fact that applicable system pumps
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were not in operation.
A local indicator was subsequently added to CS-V-744 l
to provide positive verifica; ion of valve position without removal of the locking mechanism.
While this specific event represents a licensee-identified item, the conse-quences of which did not adversely impact public safety or the potential for boron dilution, the following factors present a question with respect to the adequacy of predefined controls in this area.
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The original valve lineup, which was independently verified by a separate A0, and four subsequent surveillances failed to identify the incorrect position of CS-V-744.
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Instructions provided to the A0s conducting the repetitive surveillance actitivies were unclear as to whether they were allowed to unlock the chain locks to verify actual valve position.
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Administrative controls over those valves which are procedurally allowed to be unlocked and operated did not provide guidance on timing for re-locking of the valves, once the required evolution of valve opening and operation was complete. (NOTE: This problem was identified by the NHY Operations Manager who expeditiously issued a memorandum on November 1, 1986 to provide the necessary guidance.
This memorandum set an appro-priate time limit of 15 minutes, for which any delays beyond this time merit returning the valves to the required locked-closed position).
Field checks of locked valves by the inspectors revealed certain ques-
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tionable examples of whether the locks provided physical restraint of the affected valves from changing position.
Subsequent discussion with licensee personnel indicated some difference of opinion as to the cri-teria constituting a " locked" valve.
So as to clarify the NRC position in this regard the following interpretation from the NRC Inspection and Enforcement Manual is provided as guidance as to what properly consti-tutes a " locked" manually operated valve:
a.
"The valve should be physically restrained from moving.
The metho-dology by which the restraint is removed should be under admini-strative control.
A key or combination lock is the preferred metho-dology, but the use of a " sealing" technique which will provide evidence of unauthorized manipulation is acceptable (e.g., cable secured by means of a lead seal)."
b.
"A tag or similar device on a valve handwheel does not meet the re-quirements for a locked valve in a fluid system important to safety.
Likewise, simply removing the valve handwheel without securing the stem in position is inadequate."
The four problem areas identified above all related to the event involving the improperly positioned CS-V-744.
This was a licensee-identified event which was properly reported and for which licensee corrective action appeared
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to be prompt and responsive to the safety concerns.
However, the program and
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procedures implemented to control those valves designated to be " locked" to preclude inadvertent boron dilution, appeared to be initially inadequate in providing positive measures to indicate the operating status of certain com-ponents; in this case, valve position.
The existence of these initially questionable controls represents a violation of 10 CFR 50, Appendix B, Cri-terion XIV (443/86-47-03). While the licensee corrective measures on an in-dividual case basis appear to have corrected the identified problems, the generic question of procedural and progammatic adequacy, prior to implemen-tation of the activities requiring control, remains to be addresse ~
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One additional event received special inspection coverage during the conduct of initial fuel loading.
At 12:13 a.m. on October 25,1986 the security com-puter failed with the backup computer unavailable.
For a total period of ten minutes, the security system was degraded while the licensee initiated com-pensatory measures in accordance with the NHY Safeguards Contingency Plan.
The primary computer systen was restored to normal status at 12:23 a.m.
At 12:30 a.m. on October 25, 1986, the NHY Shift Superintendent on duty re-ceived notification from the NRC headquarters duty officer of an anonymous potential threat of unknown nature directed against Seabrook Station.
Again in accordance with the Safeguards Contingency Plan, an increased posture of security vigilance was appropriately maintained.
The inspector reviewed the Safeguards Contingency Plan and the applicable security procedures for an extortion threat / event.
The inspector interviewed toe NHY security supervisor on shift and determined that adequate compensatory measures had been implemented.
The unavailability of the security computer was reported to the NRC in accordance with 10 CFR 73.71(c) as a major loss of physical security effectiveness which had been properly compensated.
No violations were identified with regard to licensee actions in response to both the security computer failure and the potential threat.
8.
Design Changes a.
Boric Acid System In conjunction with the 10 CFR 50.57(c) review discussed in paragraph 5 of this report, the inspector reviewed the implementation of ECA 08/
118448 which added an isolation valve in the line from the boric acid batching tank (1-CS-TK-5) to boric acid tank "B" (1-CS-TK-4B).
The new diaphragm valve (1-CS-V-1207) permits batching operations to be conducted on boric acid tank "A" (1-CS-TK-4A) while keeping boric acid tank "B" in service.
The inspector verified appropriate ASME Code (Sections III and XI) ad-herence, retagging and safety evaluation.
Additionally, a field verifi-cation was ccnducted to ensure as-built conformance with the revised design drawing.
The inspector witnessed portions of the hydrostatic test, discussed test preparations with the start-up test engineer, and had no further questions regarding this design change.
b.
Cathodic Protection The inspector reviewed ECA 03/003144E which provided instructions for installation of the negative node connections for cathodic protection in the service water and circulating water pump houses.
Review of the ECA and field inspection of the service water pumphouse installation revealed no problems regarding the design chang *
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17-9.
Procedure Reviews The inspector reviewed surveillance procedure 0X1423.13 (Rev.02), entitled
" Containment Purge and Exhaust Isolation Surveillance", and noted three errors; one in the references, one in the pre requisites and one in the initial con-ditions.
Reference 2.2 listed five NHY P& ids, none of which relate to this surveillance.
The correct P&ID reference should be for the CAP / COP systems vice the CAH and CBA systems references.
This error was identified to the unit station super-intendent.
Pre-requisite 6.3 and subsequent procedure step 8.18 both refer to section 6.6 of procedure OS1023.68 (" Containment Air Purge System Opera-tion").
This step in procedure 051023.68 provides actions to be taken to return the CAP system to the normal mode which stops fans CAP-FN-34 and CAP-FN-35.
The action desired in 0X1423.13 is to start the fans.
Additionally, step 7.0 states that the initial conditions for these procedures are " Plant in mode 6".
This surveillance is also required in mode 7 prior to entering mode 6. (NOTE: For convenience, Seabrook personnel refer to the defueled plant condition as mode 7 although this is not a TS defined mode).
Further inspec-tion in the control room revealed that the latter two items had been identi-fied previously by the licensee and temporary procedure changes had been in-itiated.
The licensee committed to also correct the reference error.
The inspector reviewed the surveillance records for performance of the above sur-veillance in preparation for entering Mode. 6.
No discrepancies were noted in Repetive Task Sheet (RTS) 86R006150.
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The inspector reviewed the surveillance procedures for the operational test of the source range nuclear instruments (procedure IX1656.912 for N-31 and IX1656.913 for N-32).
The " allowable tech spec" value for the bistable trip was listed in both procedures as being <1.4 X 105 CPS.
The actual TS value is <1.6 X 105 CPS.
Discussion with the I&C Supervisor indicated that, al-though a comprehensive review to correlate the latest TS values with existing surveillance procedures had been done, this specific error had been missed.
The error is in the conservative direction and the tolerances to which the instrument is adjusted are listed correctly; therefore, no actual errors were made or were possible with respect to instrument adjustment.
This TS value is listed to inform the technician that if the "as found" value exceeds the
" allowable" then further action must be taken.
The licensee immediately in-stituted a procedure change.
The inspector considers this an isolated error and had no further concerns regarding this matter.
While reviewing startup test procedure 1-ST-7, " Rod Drop Time Measurements",
Revision 2, July 24, 1986, the inspector noted that the reactor coolant system (RCS) temperature must be greater than 500 degrees F as an initial condition for test performance.
The rod drop time technical specification, TS 3.1.3.4, however, requires Tavg for each loop to be greater than or equal to 551 de-grees F for the performance of rod drop time testing.
The inspector ques-tioned the responsible licensee personnel as to how the startup test procedure was written and approved by SORC without anyone recognizing the difference between the TS and 1-ST-7 conditions for testing, because the final draft TS
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had been issued prior to the writing of the procedure.
The licensee repre-sentative informed the inspector that the TS had been changed prior to license issuance and that the procedure value of 500 degrees F corresponds to the original T.S. requirements.
Hence, the change in TS was not incorporated into the procedure in question.
The startup procedure was updated to reflect the change in TS requirements subsequent to the inspector informing the licensee of the discrepancy.
The inspector's concern was that the rod drop time measurements would be per-formed using the startup procedure and mode 2 entered in violation of TS 3.1.3.4.
The licensee representative, in response to this concern, informed the inspector that the performance of 1-ST-7 would not be used to take credit for complying with technical specification requirements.
The licensee repre-sentative stated that surveillance procedures 151666.911, "CP-113 Control and Shutdown Rod Drop Testing," and RX1700, " Rod Drop Times Surveillance," are in fact the documents used to measure and record rod drop times to meet TS 3.1.3.4.
Licensee personnel had already initiated a revision to IS1666.911 to change the RCS temperature initial conditions from greater than 500 degrees F to greater than 551 degrees F, prior to the inspector expressing his concern.
The inspector reviewed the draft procedure and determined that it adequately addresses the applicable technical specification requirements.
The licensee provided the inspector with sufficient evidence that the rod drop timing would be performed in accordance with technical specification requirements using the revised startup test and operating procedures.
The inspector had no fur-ther questions regarding this issue.
10.
Training The inspector observed a portion of the simulator training program for re-placement operators.
Included in the group were auxiliary operators (R0 Can-didates) and training center instructors (SR0 Candidates).
The candidates were walked through the ECCS, CBS and RHR systems on the main control board.
The simulator objectives were clearly presented prior to the session and re-inforced throughout.
The instructor-to-student ratio was good and the in-structors were knowledgeable on the systems under discussion.
The inspector noted that some recent plant modifications, specifically those on the EFW system had been incorporated into the simulator and that others, such as the RVLIS plasma displays, were installed with work in progress.
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the training program lesson incorporated the recent change in operating the RHR system (refer to CDR 86-00-07 in IR 443/86-46).
The inspector had no concerns with any of the above items.
11.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations.
Unresolved items disclosed during this inspection are discussed in paragraph 3.
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12. Management Meetings At periodic intervals during the course of this inspection, meetings were held with senior plant management to discuss the scope and findings of this in-spection. An exit meeting was conducted on November 13, 1986 to discuss the inspection findings during the pericd.
During this inspection, the NRC in-spectors received no comments from the licensee that any of their inspection items or issues contained proprietary information.
No written material was provided to the licensee during this inspection.