IR 05000354/1985058
| ML20153E981 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 01/30/1986 |
| From: | Eselgroth P, Fuhrmeister R, Gramm R, Lodewyk A, Kamal Manoly, Paulitz F, Reynolds S, Wink L, Winters R, Woodard C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20153E963 | List: |
| References | |
| 50-354-85-58, IEB-80-17, NUDOCS 8602250222 | |
| Download: ML20153E981 (72) | |
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U.S. NUCLEAR REGULATORY COMMISSION Region I Report No.
50-354/85-58 Docket No.
50-354 License No.
CPPR-120 Category A
Licensee:
Public Service Electric and Gas Company Post Office Box 236 Hancocks Bridge, New Jersey 08038 Facility Name:
Hope Creek Generating Station Inspection At:
Hancocks Bridge, New Jersey Inspection Conducted:
December 2-13, 1985 Inspectors:
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/[ED/d 6 K. Manoly, Lead Reactor Engineer Date M k // Y W A rt-
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_S. Rey Ids, L d actor Engineer Date l!d3 $h VRt h"L]7.
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odewy 'eattorEng) feer
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//?b/84 F. Paulitz, Reactor Engineer Date hd/Cn bY
/bt2/8C C. Woodara',' Reactor Engineer Date
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I R. Winters, R actor E ineer Date h
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R' Gramm, S Resid t Inspector, NMP #2 Date
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c72 shshc R~. FuhrmeistergReactor Engineer Dat'e I
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f. Wink, R ctor En eer
' Dite Approved By:
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.esel_grotyChief,TestProgramsSection,DRS
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i Inspection Summary: Announced As-Built Team Inspection on December 2-13, 1985 l
(Report Number 50-354/85-58)
Areas Inspected: As-built inspection in the areas of Mechanical, Electrical,
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Instrumentation and Control, and Structural Systems. The inspection also
included a review of as-built equipment for selected emergency procedures, and
the FSAR accident analysis assumptions.
Additionally, the licensee actions on previous NRC inspection items and IE
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j Bulletins were also addressed. The inspection involved 829 hours0.00959 days <br />0.23 hours <br />0.00137 weeks <br />3.154345e-4 months <br />.
Results:
No violations were identified.~ The inspectors determined that the systems selected were constructed in conformance to their FSAR descriptions.
Four unresolved items were identified in the areas of piping component and equipment supports and instrumentation and controls.
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Table of Contents Page 1.0 Scope and Purpose of the Inspection....................
2.0 Persons Contacted......................................
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3.0 Mechanical Systems.....................................
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l 4.0 El e c tri ca l Sy s tem s.....................................
5.0 Instrumentation and Control Systems....................
6.0 Civil / Structural.......................................
7.0 As-Built Verification of Equipment for Selected
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Emergency Operating Procedures..........................
8.0 Comparison of FSAR Accident Analyses Descriptions to As-Built...............................................
9.0 Independent Verifications..............................
4 10.0 Quality Assurance Program Inspections..................
11.0 Followup on Outstanding Inspection Findings............
12.0 Unresolved Items.......................................
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13.0 Exit Interview.........................................
Attachment 1 RHR/LPSI MOV Degraded Grid Operability f
Attachment 2 Service Water Voltage and Cable Tension Calculations J
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DETAILS 1.0 Scope and Purpose of the Inspection This as-built team inspection was conducted by region-based reactor engineers to verify that selected systems were constructed substantially in conformance to the description contained in the Final Safety Analysis Report (FSAR) and in NRC's Safety Evaluation Report (SER). The inspection included examination of fluid systems, Heating, Ventilation and Air Conditioning (HVAC) systems, ac and dc power systems and instrumentation and controls systems. Extensive system walkdowns were performed,'during which independent dimensional measurements were made. Also, various project specifications drawings and design calculations were reviewed.
In general, the systems selected for inspection were those associated with meeting reactor safe shutdown and core cooling requirements. This as-built inspection focused particular attention in the following specific areas:
The shutdown cooling functional systems between the Delaware River
and the reactor core.
Systems and equipment necessary to fulfill the functional requirements
of steps, as currently written, in selected Emergency Operating Pro-cedures.
A compatibility check of the plant as-built condition with selected
aspects of plant design specified in the transient analysis portion of the FSAR.
2.0 Persons Contacted Public Service Electric and Gas Company (PSE&G)
- C. McNeill, Vice President - Nuclear
- R. Salvesen, General Manager - Hope Creek Operations
- F. Cielo, Principal Engineer
- J. Nichols,. Technical Manager
- M. Massaro, Lead Engineer
- J. Duffy, Site Engineer
- M. Metcalf, Quality. Assurance (QA) Startup Engineer S. Hilditch, Jr., QA Engineer R. Donges, Lead QA Engineer
- A. Meyer, Senior Staff Engineer
- C. Allen, Technical Engineer
- R. Griffith, Principal QA Engineer R. Audette, Facilities Manager
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- M. Idell, Lead Engineer
- M. Kobran, Lead Engineer
- T. Ram, Supervising Engineer
- R. Campanella, Licensing Engineer
- W. Merritt, Lead Engineer
- T. McLaughlin, QA Engineer
.W. Mussel, Engineer W. Mitchell, Supervisor, Document Control M. Finney, Supervisor, Document Control R. Ritzman, Supervisor, Technical Document Room
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A. Koa, Principal Engineer A. Sternberg, Principal Engineer J. Defabo, QA Engineer J. Montgomery, Staff Maintenance Engineer
- A. Giardino, Manager, Station QA
- M. Mortarulo, Senior Staff Engineer
- W. Denardi, Engineer S. Maginnis, Senior Staff Engineer
- R. Binz, IV, Senior Staff Engineer
- J. Ranalli, Senior Staff Engineer H. Chu, Electrical Engineer D. Schumaker, Civil Engineer M. Massard, Site Engineer
- A. Taylor, Safety Review Engineer
- G. Connor, Operations Manager
- B. Preston, n'anager - Licensing and Regulation
- C. Churchman, Site Engineering Manager N. Dyck, Chairman, Response Coordination Team Bechtel
- B. Markowitz, Project Manager
- J. Isaacs, Deputy Group Supervisor
- R. Goebel, QA Engineer
- G. Moulten, Principal QA Engineer
- C. Headrick, Principal Quality Control (QC) Engineer T. Giordano, I&C Engineer M. Metcalfe, I&C QC Engineer J. Danhert, QC Engineer E. Hanselman, Lead Field Welding Engineer M. May, Assistant Lead Field Welding Engineer J. O' Conner, Field Welding Engineer
- C. Haynes, Resident Engineer, Plant Design General Electric
- T. Bloom, Resident Site Manager
- J. Cockroft, Engineer
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U.S. Nuclear Regulatory Commission-(USNRC)
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- L. Bettenhausen, Chief, Operations Branch
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- J. Strosnider, Chief, Reactor Projects Section IB
- R. Borchardt, Senior Resident Inspector
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- J. Lyash, Resident Inspector
- Denotes individuals present at exit meeting.
Throughout the course of the inspection, other licensee, Bechtel and General Electric engineers and technical personnel were also contacted.
3.0 Mechanical Systems
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3.1 General The scope of inspection in the area of mechanical systems covered piping components, equipment and HVAC systems and their respective
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supports. The specific systems which were inspected in the piping area included:
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Safety Auxiliary Cooling System
Residual Heat Removal System
Control Rod Drive System
The inspection of piping components included the residual heat removal system motor operator valves and the main steam safety relief valves.
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The inspection in the HVAC area focused on the recirculation system for the diesel generator room and the unit cooler for the RHR "A" pump.
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The objective of this inspection was to verify, by sampling review,
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that the above systems were designed and fabricated such that they were capable of performing their intended functions as specified in
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the Final Safety Analysis Report (FSAR) and whether the as-built configurations were in conformance with the FSAR, the SER and system specifications and drawings.
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3.2 Piping Systems The inspection in this area included piping components, equipment and supports. A review of the licensing documents was performed to insure that, for those selected systems, FSAR commitments were correctly i
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translated into specification procedures and drawings. A cross review was also performed of the Piping and Instrumentation Diagrams (P&ID's)
and support detail drawings to verify their consistency and agreement with the as-built installations.
3.2.1 Piping As-Built Reconciliation Program The objective of the NRC review of the piping As-Built Reconciliation (ABR) Program was to assess the various functions and activities contributing to this program and
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to determine whether acceptable engineering practices, regulatory requirements and licensee cownicments had been met. The regulatory positions for the evaluation of as-
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built safety related piping and support systems are addressed in IE Bulletin 79-14.
To achieve the above objective, the NRC staff performed a review cf the governing specifications and procedures which govern this activity in addition to conducting walkdown inspections of selected piping systems and support installa-tions utilizing applicable as-built isometrics and support drawings.
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3.2.1.1 Piping As-Built Reconciliation Overview The as-built reconciliation is performed for nuclear class 1, 2 and 3 large and small bore piping systems and ANSI B31.1 large and small bore piping systems within "Qs" and "Qsh" bound-
artes.
The designation "Qs" identifies the por-tion of piping beyond the ASME boundary (code break) up to a first anchor or terminal end of the piping run. The designation "Qsh" identifies the non-category I piping in the vicinity of "Q" piping and which is designed to mitigate the
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consequences of seismic interaction with "Q" piping.
The requirements for the as-built reconciliation of designated piping systems and the description of the activities.and work flow performed by the stress group are provided in the Technical Specif-ication P-450(Q) for As-Built Reconciliation.
The detail of actions taken by field engineering and quality control to support project engineering
for As-Bailt Reconciliation is provided in a desk-top procedure (ABR/DTP0001).
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documentation of as-built piping and support installations is contained in as-built reconcilia-tion packages (ABP) which consist of final pipe support status and index sheets, system isometrics, hanger detail drawings and the stress calculation cover sheets. Stress reports for nuclear class 1 piping are included in the ABR packages as well.
The information identified by field engineering and shown on class 1, 2 and 3 large bore (21s inch and larger) and class I small bore (2 inch and smaller) piping isometrics include:
as-built configuration; actual location of pipe supports within 2 inches from design location; outstanding Field Change Requests (FCR's) and Field Change Notices (FCN's) against the piping system; loca-tion of lugs for nuclear class 1 piping; grouted-in penetrations; location of components, valves, fittings, flow elements, expansion joints and other in-line components; location of pipe whip restraints and bumpers; type of branch connections other than a tee, such as half coupling, weldolet, sweepolet, threaded connection; valve stem and operator orientations within 5 degrees; vent, drain and root valve configurations; and as-built configuration of field routed small bore piping connected to large bore within Qs boundaries.
Details identified on class 1, 2 and 3 large bore and class 1 small bore pipe hangers include:
type of support, orientation of gaps for whip restraints; length of welds on tube steel if less than the full width; cancelled supports in the AB portion of the isometric; and supporting calcula-tions for small bore support designs by field engineering.
As-built information identified on class 2 and 3 small bore piping isometrics include:
as-built configuration; actual location of all pipe supports; orientation and type of all supports; location of supports / guides added by field engineering; U-bolt locations, substitutions of straps by U-bolts; length of welds on tube steel if less than the full width; penetration numbers; substitution of
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bends for ells or ells for bends; branch connec-tions other than a tee; location of components,.
valves, fittings and other in-line components; changes to CRD insert and withdrawal piping;. valve ~
and stem operator orientation exceeding 15 from design; root valve AB configuration; and individual hanger details.
Completed ABRs are sent to Bechtel's corporate office-in San Francisco for verifying pipe stress orientation and symbols and updating of isometrics.
Depending on the as-built conditions, isometrics are either issued or reconciled by the ABR team.
The reconciliation calculations are incorporated
in either the original or the up-date of pipe stress calculation.
Identified modifications are performed before the issuance of the final pipe stress and pipe support calculations.
This step is followed by the preparation of the ABR packages which contain the N-5 letters, the pipe stress calculation cover sheets and the pipe support calculation numbers and revisions. Assembled ABR-packages are used for the preparation of the N-5 packages.
The following information was gathered by the NRC staff during the review of the ABR program:
approximately 30 large bore and 20 small
bore related modifications have resulted from the ABR activities.
343 large bore stress calculations were
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completed out of 345 total calculations.
186 small bore stress calculations-were
completed out of a 190 total calculations performed for piping inside the drywell.
2293 small bore isometrics were completed
out of a 2570 total isometrics of_ piping outside the drywell.
3.2.1.2 Walkdown Verification of A_s duilt Piping and Support Installations
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The verification of as-built installations was
performed either by visual inspection or by inde-
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pendent measurements of accessible components and supports.
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The criteria used for the assessment of piping components and supports were those described in the installation specifications for these compo-nents. The inspection attributes included verif-
ication of the following:
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linear and angular measurements related to
piping runs and support locations; branch connection types and locations;
piping bend and elbow radii; a
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support mark numbers, functions and locations;
proper flow direction marks on valves; a
correct sequential location of valves on
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piping runs; and, proper identification and orientation of a
valves and Limitorque operators.
The ' inspection attributes for equipment (pumps, heat exchangers, etc.-) included verification of the following:
manufacturer specification and purchase orders;
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name plate data consistency with FSAR
requirements and manufacturer's data (capacity, type, rate head, horse power);
e and, heat exchanger component class (tube side
and shell side).
The inspection attributes for pipe supports included verificatica of the following:
as-built configuration against support detail
drawing (BZ series) 'ncluding dimensions of-members;
connection to-the proper structure;
sizes and quality of welds on hangers, in-
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baseplate dimensions and location of struc-
tural attachment to baseplates; baseplate bolt (concrete expansion or Richmond
insert) tightness sage distance and the bolt mark identification for Hilti-bolts; restraint bleed holes open and free of foreign a
material; load setting of spring hangers;
grouting of floor mounted baseplates and gap
sizes for wall mounted plates; and, pipe routing and support locations such that
movements of piping due to vibration, thermal expansion, etc., would not likely cause con-tact with other pipes, supports, equipment or components.
3.2.2 Station Service Water System (SSWS)
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3.2.2.1 Piping System Walkdown The SSWS provides river water to cool the Safety Auxiliary Cooling System (SACS) heat exchangers during a loss-of-coolant accident and other design basis accidents. The SSWS removes heat from the SACS heat exchanger and transfers the heated water to the cooling tower discharge canal.
The SSWS consists of two redundant loops.
Each loop contains two service water pumps, traveling water screens, service water strainers, spray water pumps and associated valves, piping and instrumentation.
Each loop cools a separate SACS loop.
During this inspection, portions of loop "A" of the SSWS were selected for the purpose of-as-built verification. The walkdown of piping components and supports was conducted from service water pump AP-502 to SACS heat exchanger AE-201. A detailed inspection was conducted on the accessible portions of the system located within the intake structure.
The inspection included those attributes listed in Section 3.2 of this report.
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3.2.2.2 Service Water System Materials Evaluation The inspectors conducted an evaluation of the material selection and installation of-safety related service water piping and service water cooled heat exchangers. The material review was based on previously identified pre-service and operational corrosion problems at other sites including Salem with concentration cell corrosion of stainless steel weld metal and copper alloy heat exchanger tubing (the Salem problem was with stainless weld metal). The review showed that the safety related service water piping consisted of epoxy phenolic coated pipe, coal tar epoxy coated pipe for a wall penetration and reinforced concrete pipe which will negate the oxygen concentration cell problem. The SACS HX tubing is titanium with the water box inside surface lined with alloy 625. The inspector noted that the licensee is committed to visual inspection of
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the HX water boxes each refueling outage to insure there are no holidays in the alloy 625 lining and tube sheet overlay that could cause rapid galvanic small anode /large cathode corrosion problems.
3.2.2.3 Service Water Pump
The inspectors closely examined the Ingersoll Rand (IR) service water pump installation and other ad,jacent equipment in the pump house.
The inspectors noted rusted carbon steel studs and bolts on stainless steel valves, but were provided licensee documents previously identifying this as a potential maintenance problem and committing to corrective action. The inspectors reviewed the IR documentation package and confirmed that the FSAR requirements were reflected in the code
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data sheet and code data plate.
3.2.3 Safety Auxiliary Cooling System (SACS)
3.2.1 piping System Walkdown The SACS is designed to provide cooling water to various engineered safety features equipment, including the residual heat removal (RHR) heat exchanger. Water from the SACS is pumped through the RHR heat exchanger tube side to remove heat from the process for containment cooling during various modes of operation and during loss of off-site power and loss of coolant accidents.
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Loop "A" of the SACS was selected for as-built verification. The walkdawn of piping components and supports was conducted from SACS pump AP-210 to RHR heat exchanger AE-205 to SACS heat exchanger AE-201 and returning to SACS' pump AP-210. A detailed inspection was conducted in accordance with Section 3.2 of this report on the accessible portions of the system loop.
At the time of the NRC inspection, the SACS loop
"A" piping had been inspected in accordance with the licensee as-built verification program.
The inspection included review of ABR package C-1749 Phase II copy for Large Bore Pipe SACS Loop "A" and the associated ABR isometric drawings 1-P-EG-06, Rev. 12(Q) and 1-P-EG-13, Rev. 12(Q).
3.2.3.2 SACS Heat Exchanger (Hx)
The inspectors reviewed in detail the Graham Manufacturing Co. Inc. SACS Hx documentation pack-age and visually inspected the. exterior welds of the Hx, Hx saddle support and Hx structural box supports for the vertically stacked Hx's.
The Hx is designed to ASME Section III-ND and the supports to Section III-NF.
Conspicuous in the documenta-tion package is NCR 1237 which was initiated by Bechtel after visual inspection revealed potantial welding deficiencies in some of the Hx nozzle welds and the heat exchanger supports.
This NCR resulted in a complete re-examination by both Graham and Bechtel QC inspectors to explicit criteria indicated in Graham Inspection Procedure 39047-T (which was signed by the Graham cognizant Design Engineer). The re-examination accepted most of the welds and required repair (by Bechtel)
of other welds. All repair welds received Magnetic Particle surface examination.
The inspector reviewed the welding QC documentation for the repair welds.
An independent inspection was made by the NRC inspectors of 141 welds in the saddle supports and structural box (framework) supports. The inspec-tion showed that all but three welds met the basic fillet weld size requirements and that the three welds met the Inspection Procedure 39047-T II, 2, A, 1 alternative requirements. The voluminous NCR 1237 was determined to be acceptabl *
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The inspectors noted the absence of A193B7 stamp-
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ing on the heat exchanger water box plate cover
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fasteners, but confirmed the material properties
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by review of the fastener material certifications.
Visual inspection'of the Code Data Plate indicated conformance to the Code Data Sheet and minimum FSAR requirements.
The inspector reviewed the maintenance records for the inerting gas protection for the shell side of the heat exchanger.
3.2.3.3 Pumps The inspectors reviewed the SACS pump documentation package, installation, and Code Data Plate. The inspectors reviewed the Code Data Plate, Code Data Sheet, pump curves and
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minimum FSAR requirements and verified conformance.
3.2.4 Residual Heat Removal (RHR) System The RHR system design functions are to remove decay heat from the reactor system during shutdown cooling, to provide Low Pressure Coolant Injection (LPCI) during a design acci-dent, to provide torus spray cooling to limit temperature rise in the torus, and to provide drywell spray cooling to reduce the internal drywell pressure that would accompany a line break accident.
The RHR system consists of four independent loops with motor driven pumps. Two loops are provided with heat exchangers cooled by the Safety Auxiliaries Cooling System (SACS).
All loops are capable of the LPCI function while only the heat exchanger loops are used for _ normal or emergency vessel cooling and primary containment spray cooling.
RHR system loop "A" was selected for the purpose of the as-built verification. The walkdown of piping, supports and components was conducted from the RHRS torus suction nozzle-(P-211C), to the RHR "A" pump (AP-202), and the pump dis-charge lines to the RHR heat exchanger (AE-205), to the
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torus spray nozzle (P-214B), to the LPCI injection nozzle (N-17C), and up to and including the lower drywell spray header. A detailed inspection was conducted on the access-ible portions of the system.
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3.2.5 Safety Related Motor Operated Valves Stroke times for selected valves in the Residual Heat Removal 4-System were reviewed against FSAR requirements, Technical Specifications limits, and General Electric (GE) Design Specification Data Sheet (DSDS). The DSDS values (as modif-ied by FDDR's KT1-571 and KT1-1457), and the FSAR values (as i
modified _by FSAR Change Notice 1040 to be issued as amendment 14) agree with the Technical Specification limiting stroke times. The actual measured. stroke times (from PTP-BC-1)
are within the allowable limits. The particular valves involved were 1-BC-hV-F015A&B, 1-BC-HV-F0008, 1-BC-HV-F009, 1-BC-HV-F022, 1-BC-HV-F023, 1-BC-HV-F024, 1-BC-HV-F010, 1-BC-HV-F027 and 1-BC-HV-F017A, B, C, & D.
The Torus suction valves were reviewed for design data as opposed to actual conditions which could be expected when lined up for shutdown cooling operation. The purchase specification data, manufacturer's data sheet, Line Index and valve nameplate data were compared to calculated condi-tions in the line. No discrepancies were noted.
The motor operated valves (and air operated valves) associated with the steam condensing mode of the residual heat removal system were inspected to verify deactivation.
This was in accordance with the deletion of the steam condensing mode per FDDR KT1-1323.
1-BC-PV-F051A&B and 1-BC-LV-F052A&B were verified to have the airlines disconnected from the actuators and capped.
1-BC-PV-F051A&B were further verified to be in the closed position with the handwheels chained and locked. The following motor operated valves were verified to have their handwheels locked with the valves in the closed position:
1-BC-HV-F026A&B, 1-BC-HV-F011A&B, 1-GC-HV-F052A&B, 1-BC-HV-4420A&B, 1-BC-HV-4421, 1-BC-HV-4428.
In addition, their supply circuit breakers were verified to be danger tagged in the open position.
3.2.6 Control Rod Drive System (CRDS) Scram Discharge Volume (SDV)
The function of the CRDS is to control changes in core reactivity by positioning neutron absorbing control rods J
within the reactor core.
The CRD3 hydraulic system supplies and controls the pressurized fluid for control rod drive movement. During a scram, or rapid insertion of the control rods, water is discharged f~om the control rod drives to the SDV.
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The SDV consists of two sets of 12 inch diameter header piping, one header for each bank of Hydaulic Control Units (HCOs). The header slopes downward to a 12 inch vertical'
Scram Discharge Instrument Volume (SDIV). The SDIV is pro-vided with a 2 inch drain line and a redundant set of level switches and transmitters.
The north SDV system was selected for an as-built verifica-tion. The walkdown was conducted from selected HCU exhaust lines, the SDV (1-BF-040-S06/S07/S08), the SDIV (1-BF-040-
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S05), the vent line from the SDV to the outboard vent valve
(V083), the SDIV drain line to the outboard drain valve (V076), and the piping associated with the SDIV level switches and level transmitters LSN 13A/8/G/H and LTN 12 D/C).
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3.2.7 Main Steam Safety Relief Valves (MSRVs)
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The main steam safety relief valves are part of the nuclear pressure relief system.
These MSRVs protect against over-pressurization of the reactor coolant pressure boundary.
Selected MSRVs are also part of the automatic depressuriza-tion system which functions as part of the emergency core cooling system for events involving small breaks in the reactor coolant pressure boundary.
There are fourteen (14) MSRVs mounted on the main steam lines between the reactor pressure vessel and the inboard main steam isolation valves in the drywell at approximately the 124' elevation.
A visual inspection was made of the installed MSRVs. MSRV name plate data was verified to be in accordance with FSAR requirements. A review was also performed of the valve manufacturer's certification of design and performance requirements, including the results of testing required by the FSAR.
3.2.8 Review of Post Weld Heat Treatment (PWHT) For Feedwater Piping In the process of reviewing Bechtel specification P202 for fabricating piping systems it was noted that paragraphs 3.2 and 3.2.3 indicate a different Code Edition (1977 W78) for PWHT than that utilized for fabrication (1974 W74). As this i
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is an unusual practice, the inspector reviewed the justiff-cation for the difference. There were six instances invol-ving Dravo supplied pipe where the wall thickness of the pipe exceeded 1.5 inches due to excessive ID counter bore which had been compensated by excessive OD weld buildup.
Bechtel made the decision to PWHT these weld joints. The
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weld joint QCIR records including time temperature charts were reviewed by the inspector. The welds in question were AE-003 FW6, AE-017 FW18, AE-017 FW2, AE-017 FW17, AE-017
FW1 and AE-017 FW 22.
In the process of conducting PWHT operations, Bechtel experienced difficulty obtaining the minimum temperature requirement (Table NB-4622.1-1) of 1100F. This problem led to the utilization of the alternate holding time - temperature rules of Table NB-4622.4(c)-1.
Review of the 1974 W74 NB-4622.4(c)(1) indicated the
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requirement for requalification of the SC IX PQR (for the WPS) regardless of "P" grouping.
Further review of this requirement by Section III in the 1977 W78 of the ASME code clarified that the retesting of the PQR was li-ited to P-3 materials, therefore making it not a requirement for P-1.
Bechtel FCR P-9188 requested the utilization of the 1977 W78 rules for PWHT.
Concurrence to this request was given by the licensee. At a later date, the Bechtel P202 specif-ication was changed.
Visual inspection of the Code Data Plate indicated it con-formed to Code Data Sheet and FSAR requirements. The inspector reviewed this item in detail and has no further questions.
3.3 HVAC Systems 3.3.1 Scope The inspection in this area included HVAC components, duct-work, instrumentation, and supports. A review was performed for the selected systems to insure that FSAR commitments were correctly translated into procedures, specifications and drawings. The HVAC recirculation system for Diesel Generator room 5307 and the unit cooler for the RHR "A" pump room 4113 were inspected.
The Diesel Generator recir-culation system consists of two 100% capacity fans, two sets of cooling coils, and associated ductwor *
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The inspector additionally. inspected the low flow instrumen-tation and tubing for fan AV-412 and the control' room alarms and displays related to the DG area ventilation.
3.3.2 Inspection Criteria The specific inspection attributes for.the walkdown included verification of the following:
Duct Inspection proper size and location of duct work
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lack of excessive sheet metal deformation
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proper location and installation of flow sensing devices
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completeness of bolted flange connections Fan (AV-412/EV-412) and Cooling Coil (EV-412/ EVE-412)
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proper connection bolting
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marking and tagging
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proper location and nameplate data
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Fan (AV-412) and Unit Cooler Supports (AVH-210)
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location and completeness dimensions, weld sizes and weld profiles
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proper attachment to embedment plates proper anchor bolt installations
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3.3.3 Findings Relative to Ducts, Supports and Components in the HVAC System The walkdown inspection confirmed that the installed items were in accordance with the design requirements and FSAR commitments.
The inspector.had no further questions.
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3.4 Findings and Conclusion The NRC inspectors found that the large bore piping as-built program had generally documented the proper as-built dimensions. However, in several cases, discrepancies were identified between the as-built drawings and the installed piping by quality assurance reviews. The discrepancies necessitated licensee generation of both Nonconformance Reports and Engineering design change documents to correct the as-built drawings.
The inspectors were informed that none of the discrepancies would negatively impact the validity of the stress reconciliation efforts.
1.
The licensee's program for as-built reconciliation of safety-related large and small bore piping systems, and further verif-ication of as-built installation by the inspection team provides adequate basis for the closecut of IE Bulletin 79-14 at Hope Creek i
Generating Station.
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2.
The licensee response letters to the NRC regional office on May 23, 1979 and August 15, 1979 and Bechtel letter BLP 16565 to PSE&G on October 1984 regarding IE Bulletin 79-07 (Seismic Analysis of Safety Related Piping Systems) were reviewed during this inspection. The above letters indicated that the various computer codes which were utilized for performing response spec-trum saismic analysis of piping systems at Hope Creek Station did not utilize either the algebraic summation of codirectional spatial components or the algebraic summation of codirectional inter-modal response techniques. The licensee's response had also provided a description of the program: used and their verif-ication by other benchmark programs. The licensee submittal was considered adequate for the closecut of IE Bulletin 79-07 at Hope Creek Station.
3.
As a result of the review of the specification for installation of pipe supports P-410(Q), paragraph 4.1.1.0, it was identified that fillet welds may be made on either side of the supplementary steel flange or web when the design drawing specifies a weld on only one side of the flange or web. This deviation is applicable to all supplen.entary steel beam sections, except channels. The inspector indicated that substitution of fillet welds from the outside to the inside flange of wide flanges and angle shapes is not conservative since this results in a reduced weld section I
modulus, and subsequently increases weld stresses.
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The licensee indicated that the pipe support weld design calcu-lations before June 1982 utilized an allowable weld stress of 15 ksi as opposed to the code allowable of 18 ksi. This resulted in a 16.6% conservatism in. weld design calculations. Other mar-gins of conservatism.in weld design' included: a) increase of support design' loads by 151(verified in IOVP Report, Vol. 3, August 30,1985); b) design practice prior to September,1982 -
which utilized conservative code levels A&B allowables in weld design; c) use of enveloped loads at various support joints for sizing of welds; d) rounding up of the decimal calculated welds sizes to the nearest larger fractional size; and e) design of
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welds to meet the minimum weld size requirements. When the above-margins are evaluated collectively, the staff determined that a sufficient margin in weld design was still present.in the support
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installation even when considering a maximum reduction of weld
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section modules by 18% as a result of substitution of flange welds on W4x13 shapes.
For supports designed after June 1982, the licensee in'dicated -
that all welds were either designed or verified, using Bechtel's Standard Weld Design Computer Program ME-120, and the weld qual-
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ification portion of ME-150 of the Structural Analysis Program.
Weld section modulii in both programs are automatically computed assuming tqat welds are in the inside of the wide-flange' beams and the inside of angle legs in structural _ shapes.
The licensee further indicated that the computer codes ME-120 and ME-150 were also utilized in the design or verification 'of support welds involved in FCR and FCN modifications.
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Two cases of closely spaced rigid supports were identified during
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the walkdown of the Safety Auxiliary Cooling System (SACS) piping from the discharge side of the heat exchanger IA2E-201:
a)
Vertical Snubber No. H64 on line No. 1-P-EG-107, and vertical rigid restraint No. H21 on line No. 1-P-EG-104 were spaced approximately 5'-0" apart.
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b)
North-South Snubber No. H32 on line No. 1-P-EG-107 and North-South Snubber No. H22 on line No. 1-P-EG-104 were spaced
approximately 32 inches apart.
The installation of snubbers in proximity to other snubbers, rigid restraints or anchors could result in the inoperability
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of these snubbers if the dead band in a snubber is larger than the pipe translation between the two successive close supports.
A similar problem could also exist if rigid supports were ~
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installed in proximity to other rigid supports or anchors.
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Typically, this would be_ caused by the same circumstances which resulted in the closely spaced snubbers identified above and would result in an overloading of the supports and/or the piping if the gaps between piping and supports exceeded certain limits.
The inspectors presented these concerns to the licensee and pointed out the need for the identification of all cases in which rigid supports (including snubbers) were placed in proximity to other rigid supports (including snubbers) or anchors.
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This item is unresolved pending the licensee response and NRC review (354/85-58-01).
5.
During the review of the design specification for the Safety Auxiliary Cooling System Heat Exchanger (M-069), it was identified in paragraph 10.2 that the specification took an exception to the allowable primary design stress limits specified in subsection NF of the ASME Section 3 for the emergency and faulted conditions.
This identification was further compounded by an apparent error in the specification regarding the allowables specified in the emergency condition as 1.25 and.1.85 for membrane stress and membrane plus bending stress respectively. This discrepancy was presented to the licensee during the exit meeting of December 13, 1985 as an unresolved item. On December 18, 1985, the licensee provided a response to the unresolved item which indicated the following:
The primary stress limits for the emergency condition stated
in paragraph 10.2 of specification M-069 had typographical-errors.
Field Change Notice (FCN-M-2736) has been issued
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to clarify the stress limits for emergency condition as 1.25 and 1.85 for membrane and membrane plus bending, respectively. The nomenclature
"S" is used in the specif-ication to represent "SM" as specified in the ASME code.
The primary stress limits for the faulted condition are
1.5S and 2.25S for membrane and membrane plus bending, re-spectively. The stress limits provided for the emergency condition was found to be consistent with subsection NF of the 1974 edition of ASME Code. However, the membrane plus bending stress limit for the faulted condition was found to exceed that specified in the 1983 edition of the Code. The later edition of the code was used since the 1974 and 1977 editions did not have a specified limit for the above stresses, j
This item is unresolved pending licensee response and NRC review (354/85-58-02).
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The walkdown inspection of the CWS, SSWS and SACS piping components and hangers disclosed the following discrepancies between licensee design documents and existing field installations. The noncon-formance reports (NCR's) referenced below were issued during the inspection to resolve each associated issue.
(i) The existing clearance gap between large bore service. water piping and rigid restraint 1-P-EA-026-H02 was found to be
.049 inches on one side.
Pipe support drawing 1-P-EA-026-H02(Q) Rev. 4, F0 specifies 1/16 inch gap on both sides.
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Specification P-410 specified tolerances with a combined total clearance of 3/32 inches minimum. NCR No. 8875 was written to document the actual gap.
(ii) SACS isometric drawing'1-P-EG-06 shows valve 1-EA-V804 stem in the horizontal position. The existing valve stem is approximately 45* from the horizontal position. This orien-tation was found to facilitate installation to avoid hand-wheel operational interferences and to have minimal impact on system stresses and restraint loading.- NCR No. 8891 and FCR-P-16150 were issued and approved to document the as-found orientation.
(iii) A poorly designed, non-functional (unstable) spring can hanger was found installed on a 1 inch diameter fuel pool make-up line.
FCR No. PF-12046 was issued to redesign the hanger which was reinstalled and found to be acceptable.
(iv) SACS pipe support drawing 1-P-EG-107-H06(Q) specified a 5/16" fillet weld where the existing fillet weld measured k".
NCR No. 8886 was issued to document the nonconforming condition.
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(v) Hanger 1-P-EG-159-H01 clamp was observed by the inspector to be in contact with nearby support steel during SACS operational testing. The hanger was reinspected under non-operating conditions and a.035" clearance was measured.
This gap and the hanger drawing design movemc..t is determined as acceptable for QC inspections. Yet, to enhance the func-tional operation of the spring support, PSE&G will relocate the clamp within the tolerance specified in specification P4.10.
(vi) Anchor bolt elevation and top of floor elevation for chilled water system tank 1AT401 on drawing C-0399-0 Sheet 294 appeared to be in conflict. This discrepancy was attributed to a drafting error and is to be corrected via a Field Change Notice.
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The discrepancies found in the system as-built configuration are being corrected under various licensee programs. The number of items found is relatively small considering the' depth and breath of the as-built walkdown verification. The nonconforming con-citions found would not significantly impact upon the safe operation of tha systems.
7.
The inspector identified that SDV vent valves V776 and V777 had been mistagged as V774 and V775 respectively. The inspector was provided Startup Deficiency Report (SDR) BF-270 that documented the North and South vent valve tags had been mistakenly exchanged.
The inspector was informed that the tags were reaffixed to the proper valves. The licensee stated that the system P&ID had been used to tag the valves in accordance with procedure SEI
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7.4.
The scope of procedure SEI 7.4 is limited to instrument
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root valves and skid mounted valves.
Pending licensee review of the tagging program procedural controls, this item is unresolved.
(354/85-58-03)
8.
The inspector examined small bore support 1-P-BF-435-H3 and found two cases of underlength fillet welds wherein the design specified end returns had not been provided. The inspector reviewed the associated support calculation and ascertained that the end return weldments would not be required to ensure the support load carrying capacity.
Field Change Request P-16162 was issued to provide engineering criteria to inspect the end return welds. Quality Action Request
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F310 was issued to ensure training of appropriate personnel re-garding end return weldments. The inspector reviewed structural, electrical, and other pipe support design drawings and found in all cases that weld length was specified. The inspector had no further questions.
4.0 Electrical Systems 4.1 General
. The objective of this phase of the inspection was to examine the installation of selected portions of the Class IE ac and de power
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systems and to verify that the as-built conditions agree with FSAR and SER descriptions and project specifications and drawing require-
.i ments.
The portion of the ac system selected for inspection were those associated with the "A Train" station service water system, RHR system, and the SACS system.
In the dc power system, the batteries and battery chargers were examined.
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4.2 AC Power System 4.2.1 The inspector conducte'd a fiel.d walkdown of the power feeds from the 4160 volt emergency switchgear 10A401 to the motors of the "A Train" Station Service Water Pump 1AP502, RHR Pump 1AP202, SACS Pump 1A210, to unit substation 1AX401.
From the unit substation at 1AX401, the 480 volt power feed to the station service water building intake structure Motor Control Center (MCC) 10B553 was' walked down. The 4160 volt
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power * feed circuit breakers cable and conduit for the unit substation, the RHR pump and the SACS pump were all contained within the Reactor Building.
The 4160 volt and 480 power feeds'to the station service water pump and MCC leave the
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Reactor Building and are pulled through an underground duct bank to the service water building.
The inspector observed workmanship and the as-built condi-
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i tions_of the switchgear, cable, conduit and cable trays noting in particular, the following attributes:
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Switchgear is of the proper size and rating.
- Cable, raceway and cable trays are properly identified
including color coding.
Electrical separation between redundant trains and
Class IE and non* Class 1E cables is maintained.
Cable, raceway, and cable tray hardware is properly
installed.
Cable support is proper.
- General equipment conditions are good and cleanliness
is maintained.
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Cable terminations are proper.
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The goveraing electrical specifications, standards and pro-cedures for installation and acceptance in these--areas are the followfg :
Specific Work Plan / Procedures SWP/P-E-17 Cable Instal-
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Master Q-C Instructions 10855/E-5.0 Installation.
- Inspection of Class IE Terminations.
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SWP/P-E-33 Specific Work Plan / Procedure' Installation
of Electric Control Boards, Control Complex Equipment, Switchgear, Motor Control Centers, Load Centers and Distribution Panels.
- PQ CI.E-4.0, Quality Control Instruction Installation
of Class 1E Cable.
4.2.2 Findings
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The inspector determined tt,at the identification of' cabling, raceways, trays, and conduit was as required by the specifi-cation including the colce coding. The inspector also noted appropriate cable tray grounding throughout the runs and verified that the cable support routing and termination
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agreed with the cable pull and termination tickets.
Several instances were noted of debris in openJventilated Class 1E
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cable trays.
In each instance, there was either construction activity still in progress (including cable tray cleaning and placing separation covers on the-trays) or the areas
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were being cleaned of debris in preparation for turnover from Bechtel to PSE&G.
However, the amount of debris and the frequency of finding it in several differont locations
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including locations already turned ove-from 3echtel to PSE&G such as the emergency diesel rooms and the station service water building led to a meeting between the NRC inspector, Bechtel' and PSE&G management. The inspector concluded that the current Bechtel and PSE&G cleanup programs
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are' adequate to ensure a satisfactory level of plant clean-liness if properly performed. Commitments by'both Bechtel and PSE&G management to place' additional emphasis on per-formance of the programs are expected to resolve the problems observed.
The,espector did not observe any electrical separation problems in the equipment and power runs walked down. How-ever, on going construction work was in progress in various locations throughout the plant to achieve the FSAR cable
tray separation requirements by the_ installation of metal cable ' ray covers. This program and its status were reviewed.
The work-was estimated by the licensee to be 85 percent complete with completion projected by December 20,'1985.
No deficiencies were observed in the class IE ac electrical
power systems' inspected.
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4.2.3 RHR Valve MCC Wiring A number of motor operated valves (MOVs) in the Residual Heat Removal System were inspected to verify interlocks, logic, control circuits and field wiring.
The control circuits for the Shutdown Cooling Suction MOVs (1-BC-HV-F006A&B) were checked to verify interlocks for preventing vessel blowdown while in Shutdown Cooling Mode of operation.
The control circuit is such that the valve cannot be opened unless its associated suppression pool suction (1-BC-HV-F004A or B), test return (1-BC-HV-F024A or B), and suppression pool spray (1-BV-HV F027A or B) valve'
are all shut. Tht: is in accordance with the logic diagram and the GE Elementary Diagram.
There is however, no inter-lock which would prevent the opening of one of these other valves while operating in Shutdown Cooling mode. This is also in accordance with the GE design as shown on the ele-mentary diagram. This. arrangement will require particular care on the part of the plant operations staff in order to prevent.a blowdown of the reactor vessel due to misoperation of these valves (which has occurred at many other sites).
Control circuits for those valves which receive signals on LOCA logic actuation were also reviewed to verify that the over-load function was only bypassed upon a LOCA which is in conformance with regulatory porition C.1(b) of Regulatory i
Guide 1.106. The MCC terminauuns for these valves were
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inspected to verify conformance with the design as shown on the EE-580 printout (HCG 171-3B).
This overall area was found to be satisfactory.
4.2.4 Control Panel Inspection Five control panels were chosen for a detailed inspection of panel construction, seismic qualification, device mounting, and wiring. These panels all contained Class IE wiring, are safety-related, and located in the Station Service Water System (SSWS) intake structure. The designations of these panels are:
1AC515 1CC515 1AC516 1CC516 The inspector verified that panels 1AC515 and ICC515 manu-factured by Royce Equipment Company, drawing ND-359-00, and panels IAC516 and ICC516 manufactured by Comsip, Inc.
drawing 7374-4 conformed to the drawings. Panel mour. ting
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to the floor as well as device mounting within the panel were also verified. Accessible portions of the wiring in all panels were inspected for correct wire identification and adequate terminations. No defects were found.
The in-spector used the vendor supplied drawings for inspecting terminations made by the vendor and the site wiring Termina-tion Document EC580 for field terminations. At the time of the inspection Low Level Transmitter IEP-LDT-2225C had been removed for repairs per Startup Deviation Request EA-0506.
Seismic qualification of panels IAC515 and 1AC516 was accom-plished by testing.
Testing of panel 1AC515 was performed by Wyle Laboratories and is reported in their report 58878.
Testing of. panel 1AC516 was done by Computech Engineering Services, Inc. and reported in their report 56301.
Testing was performed in accordance with the applicable Bechtel specification as follows:
10855-G-011(Q) General Project Requirements for Seismic Qualification of Class IE Control Devices and Instrumentation 10855-G-012(Q) General Project Requirements for Seismic Qualification of Class 1E Control Panel l
Assemblies No violations were observed.
4.3 DC Power System a
The inspector conducted a walkdown inspection of the 125 volt de class IE batteries and battery charger to verify conformance with FSAR and SER commitments.
Verification also included confirmation that instal -
lation, construction and operatior.al problems identified in previous inspections had been resolved.
4.3.1 Batteries and Battery Chargers The inspector examined the four class 1E 125 volt de batterios and battery chargers and verified that:
The rooms were properly illuminated with lighting systems
equipped with explosion proof fixtures.
Battery and charger room doors were locked and the
keys are controlled in accordance with approved admin-istrative procedures.
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Rooms were equipped with temporary ventilation and
cooling until'the HVAC systems can be completed and turned over.from construction to startup. The rooms ventilation system was not operating properly - con-struction activity was in progress.
The battery rooms were monitored by an operable hydrogen
detection system.
Identification of batteries, chargers, cable, conduit,
rooms and equipment are in accordance with approved drawings.
Equipment and batteries are procured, received,
inspected and installed in accordance with approved
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procedures.
Equipment, batteries and rooms are clean.
- Items identified as unresolved on previous inspections
have been resolved.
There were no outstanding open items or construction deficiency reports.
4.3.2 Documents reviewed for this inspection include the following:
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Technical Specification for Batteries, Spec. No.
10855-E-151 (Q), Rev. 5, March 15, 1984
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Technical Specification for Battery Chargers, Spec.
No. 10855-E-151 (Q), Rev. 6, September. 12, 1984
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C&D Stationary Battery Installation and Operating Instructions,12-800, 1981 Drawing No. M-8004, " Battery Arrangement" C&D Batteries,
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Rev. 1, January 18, 1984
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IEEE 450, " Maintenance, Testing and Replacement of Large Lead Storage Batteries", 1980-
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IEEE 380, " Standard Criteria for Class IE Power Systems", 1980
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Inspection Record for " Installation of Batteries and Racks" QCIR No. IDD410-E-6.7
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Quality Control Inspection Record, Job No. 10855 R-1.00, Rev. 13, " Battery Racks" 4.4 Findings No deficiencies were observed in the 125 volt d c battery systems inspected.
5.0 Instrumentation and Control Systems 5.1 General The scope of inspection in the area of instrumentation and control (I&C) systems covered the following:
Impulse lines
Instruments
Instrument cable, cable routing and terminations l
Control panels
Switchgear and motor starter contrcls
Control cable, cable routing and terminations
Control functions
Review previous identified I&C problems
Investigate current identified I&C problems
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The specific systems which were inspected in the I&C area included:
Reactor Protection (RPS)
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Engineered Safety Features, Emergency Core Cooling System (ECCS)
Safety Auxiliary Cooling System (SACS)
Station Service Water System (SSWS)
The objective of this inspection was to verify, by sampling review, that the above systems were designed and installed to meet their
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intended safety function as specified in the Final Safety Analysis Report (FSAR) and the Safety Evaluation Report (SER). Further, the
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as-built systems were installed in conformance with controlled
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specifications, controlled drawings and implementation of the Qua!!ty Assurance program.
The criteria used during the as-built inspection are as follows:
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Instrument Impulse Lines
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The visual inspection during the walkdown of the instrument impulse lines included checks for the following technical requirements:
protection of redundant channels was maintained by. physical
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separation or barriers designed to withstand the specific hazard.
In non-missile jet stream areas, the minimum separation between redundant instrument sensing lines was three feet in-air in both the horizontal and vertical directions;
the minimum slope requirement for Bechtel instruments was
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per foot and GE instruments h inch per foot; there was a minimum of two valves between the process tapLand
the instrument; isolation valves were located just beyond a penetration on the
Zone 11 side of a shield wall; surface defects did not exceed 0.016 inch;
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there were no carbon steel deposits on stainless-steel tubing
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from welding arcs; tubing, tubing restraints (guides) and anchors were located in
accordance with the drawings and no tubing was located in walkways; and
tubing minimum bend radius not less than 3 tube diameters.
- Cable, Cable Terminations and Raceway The visual inspection during the walkdown of the cables, cable terminations and the raceway included checks for the following technical requirements:
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safety related instrument and control cables were identified at a
each terminating end and at each 15 feet; there was no visual damage to the cables;
the conductors were connected to the terminal point and terminal
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block as shown on the wire termination slip; I
the wire termination terminals were tight;
the conductor terminations were in accordance with the licensee
visual acceptance criteria;
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redundant cables and raceways were separated in accordance with
the electrical installation specification; raceways were identified as required; and
cables were installed in their respective raceways in accordance
with the cable schedule.
Controls The logic diagrams, schematic diagrams and field installations were reviewed to check for the following technical requirements:
redundant components were properly identified;
the functional requirements for the controls were achieved;
resetting of a protective system actuation, at the system level,
would not cause' component action; and there was a system bypass status alarm.
- The documents reviewed during the inspection are listed-in Attachment 11.
In addition, the applicable outstanding Startup Deviation Reports were reviewed.
5.2 Visual Inspection Details The inspector performed the walkdown of the following safety systems and components using the visual criteria listed in paragraph 5.1.
5.2.1 Instrument Impulse Lines Reactor Vessel Level Common ECCS & RpS The impulse line, BB-1"-CCA-230, was visually inspected from the reactor vessel' nozzle, N128, elevation 165'-2",
reference AZ 190 degrees, to the drywell penetration J-1350.
This inspection. continued from outside of the drywell, at J-1350, where downstream from the excess flow check valve the line changed to the tubing. The walkdown continued to the high side connections of level transmitter BB-LT-N091A which is channel A of the Emergency Core Cooling System (ECCS) logic input.
This line is also connected to the high pressure side of level transmitter BB-LT-N080A which is channel W of the RPS system input to Al trip channel.
Both transmitters are located on instrument rack 10C004 in the reactor area 21 (north-west) at elevation 77 fee *
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Reactor Vessel Level RPS The impulse line, BB-1"-CCA-231, was visually inspected from the reactor vessel nozzle,-N168, elevation 145'-9",
reference AZ 190 degrees to the drywell penetration, J1351.
The inspection continued from outside the drywell at J1351-to the low pressure connection of level transmitter BB-LT-N080A.
Reactor Vessel Level ECCS The impulse line, BB-1"-CCA-232, was visually inspected from outside the drywell at penetration, J1352 to the low pressure connection of level transmitter BB-LT-N091A.
Drywell Pressure Common RPS and ECCS The impulse line, HCB-1"-054, was visually inspected from outside the drywell at penetration, J6A, to pressure trans-mitter, BB-PT-N094A, which is Channel A of the ECCS logic input. This line is also connected to pressure transmitter, BB-PT-N050A, which is Channel W of the RPS input to Al trip channel.
- l 5.2.2 Instrument Cables Reactor Vessel Level RPS The instrument cable for reactor vessel level transmitter, BB-LT-N080A, was visually inspected at the analog / digital panel, 10C609CW (GE H11-P609 Bay C).
The cable at the transmitter end was not visually inspected because its termination is within an environmental barrier.
It then enters a terminal box where the terminations were checked.
The conduit leaving the terminal box was verified and visually inspected to where it passed through a barrier wall.
Reactor Vessel Level ECCS The instrument cable for reactor vessel level transmitter, BB-LT-N091A, was visually inspected at the analog / digital panel, 10C617BA (GE H11-P617).
The cable raceway was visually inspected from the instrument to where it passed through the first barrier wall.
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Drywell Pressure RPS The instrument cable for drywell pressure transmitter, BB-PT-N050A, was visually inspected at the analog / digital panel 10C609CW. The cable raceway was visually inspected from the instrument to where it passed through the first barrier wall.
Drywell Pressure ECCS The instrument cable for drywell pressure transmitter BB-PT-94A,-was visually inspected at the analog / digital i
panel 10C617BA. The cable raceway was visually inspected from the instrument to where it passed through the first i
barrier wall.
5.2.3 Control Cables RHR Pump AP 202 The control cable, AP1Q0893D, was visually inspected from the switchgear breaker,10A40106, to the first barrier wall.
The other end of the cable was visually inspected from the solid state output-panel, IAC657BA (Div 1 RHR & CS RLY Vertical Board), to the first barrier wall.
Similarly, control cable, AP1Q08938, was visually inspected at the
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breaker, 10A40106, and panel 1AC657CA.
l SACS Pump AP 210 The control cables, AP1C0301 B&D, were visually inspected from the switchgear breaker, 10A41004, to the_first barrier wall. The other end of the cables was inspected from panel,
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IAC657BA, to the first barrier wall.
Service Water Pump AP 502 The control cables, APIC0205 B&D, were visually inspected j-from the switchgear breaker, 10A40109, to the first barrier wall. The other end of the cable was inspected from panel, IAC657BA, to the first barrier wall.
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5.2.4 Equipment
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The following aquipment was visually inspected to confirm i
their location, identification, and to verify the condition of instruments or control cables entering the electrical raceway system:
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Traveling Screens EP-AS501, CS501, BS501 & DS501.
- Traveling Screen Spray Booster Pumps EP-AP507, CP507,
BP507. The DP507 pump was removed.
Screen Level Instruments LE-2225A1, A2, C1, C2, B1 &
B2, D1 & D2.
River Level Instruments LE2220-1.8.E2220-2 was
removed.
Service Water Pump Suction Level Transmitter LE-2241A,
C, B&D.
Service Water Strainers Differential Pressure Trans-
mitters:
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PDT2194A, C, B&D; PDT2195A, C, B&D; PDR2196A, C, B&D and PDT2197A, C, B&D Traveling Screen Spray Booster Pump Flow Saitch
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EP-FS2225A, C, B&D Service Water Pump Area Heating and Ventilation Control
Panels A & C.
Service Water Pump Area Motor Control Centers 108553,
63, 73 & 83.
Traveling Screen and Wash System Control Panels AC,
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CC, BC & DC 515 and AC, CC, BC & DC 516.
5.3 Findings The inspector found that the state of workmanship in the area was generally good and the instrumentation and control systems inspected conformed to the criteria of paragraph 5.1.
However, as a result of the as-built inspection, the following specific findings were noted for which licensee corrective actions were in progress at the end of the inspection.
1.
Following the visual inspection of the nuclear boiler instrument impulse lines, the inspector reviewed selected reactor water level instrument calibration data sheets and the documentation which provides the basis for these initial calibration setting _.
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During this review, the inspector noted that the initial calibra-
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tions were not based on the as-built elevations of the instrument lines.
The failure to incorporate the as-built elevation data into the calibration calculations could result in the systematic miscalibration of the reactor vessel water level instruments.
The inspector informed the licensee that the adequacy of the reactor vessel water level instrumentation to perform its design -
functions would be considered unresolved until the following concerns are addressed:
(354/85-58-04)
Incorporation of the as-built elevation data into the reactor
vessel level instrument calibration calculations; and Subsequent re-calibration of the affected instruments.
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The inspector review of the draft Technical Specification, , Section 4.8.4.4 Reactor Protection System Electrical Monitoring Surveillance Requirements, finds that the 132 VAC over-voltage setpoint may not protect the scram solenoids from a power supply
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over-voltage condition. The solenoids' electrical tolerance for operability is 115 volts plus or minus 10 percent. Thus, the
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over-voltage value is 127 volts not 132 volts. Neither value accounts for the voltage drop between the Electrical Protective Assembly and the furthest solenoid.
The licensee has agreed to follow the recommendations contained in General Electric Spec Data Sheet MPL Item No. C71-4010,
" Reactor Protection System" 22A3083AK Revision 6 for the setting of the Electrical Protective Assembly which accounts for the voltage drop. After these values are obtained, they will be used in the final Technical Specification.
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3.
The inspector noted the following during the visual inspection:
Five Instruments without identifying tags;
One loose wire termination within each of four control panels;
Three auxiliary relays within each of four control panels
did not have a identifying name plate; One equipment name plate on each of four motor control centers
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had incorrect information; l
One equipment name plate missing from a motor control center;
One motor power conduit identification missing;
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One equipment name on P&ID differed from other identification
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used for the same equipment; One diesel generator room with the incorrect color identi-
fication; and Need for completion of plant program for labeling of pumps,
piping and motor operated valves etc.
The licensee is taking action to assure proper identif wation of clant systems and components. The pump and valve portion of the last item is being addressed by the licensee in a Site Engineering Instruction (SEI) 3.7 Revision 0, " Plant Labeling Programs" dated April 19, 1985. The licensee has not specified when this program will ba completed.
The licensee should assure that completion of plant labeling receives continued attention.
The inspector noted that a cable tray fire stop had been partially opened. A discussion with the licensee and a review of procedure
" Penetration Seal Review, Sign-Off, and Work Tracking" SWP/P-C120, Revision 6 indicated that all acceptance and modification of penetrations, including fire stops, are being controlled.
5.
The inspector reviewed Startup Deviation Reports associated with
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l damaged Rosemount transmitters resulting from the use of Neolube 100 thread sealant on each of two covers per instrument.
Because of the potential damage to the pressure boundary when the covers were removed SDR ZC-0061 was issued, with procedure PSE-PR-E-006, l
Revision 0, Decemoer 11,1985, " Pressure Leak Test for Rosemount 1153 Nuclear Transmitters."
Thirty six transmitters are to be removed and replaced with new transmitters. Seventeen transmitters will have covers replaced.
One transmitter will have its Conex EQ cable nipple replaced.
One hundred and fifty five transmitters will be restored to the original installed conditions and recalibrated.
The inspector visually walked down all transmitters at elevation 55 feet and 77 feet in the reactor building. As a result of this inspection, three additional SDRs were issued.
These were for the following:
one additional transmitter to be removed and replaced; one transmitter cover replaced and one Conex EQ cable replacement. The licensee was also advised that some of the temporary covers had become dislodged. The licensee should assure that before the recalibration takes place that the concerns of finding item 1 above are addressed.
No violations were observed during this, inspection.
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6.1 General The scope of inspection in the civil / structural area included a review of the Building Verification Program and an inspection of the Control
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Rod Drive housing supports and the control area Chilled Water System
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equipment supports. The review also included an evaluation of the licensee's activities related to the implementation of the Visual
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Weld Acceptance Criteria (VWAC) for welds designed to the requirements
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of AWS D1.1 Code.
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6.2 Building Steel Verification Program
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The scope of inspectior in this area focused on the as-built load verification program fo: Category I. structural steel. The licensee's program for this activi'.y was undertaken to verify the adequacy of
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the as-built structures since the initial design was based on estimated loads. In this verification process, evaluation of building structures is performed utilizing actual as-built loads ir.duced by large bore piping and major equipment supports in addition to the support loads from bulk installations which include small bcre piping supports, e
minor equipment, HVAC, conduit, cable tray, tubing, and other mis-
cellaneous attachments.
The objective of the inspection of this activity was to provide an assessment of the licensee's program and to determine whether accept-
able engineering practices, regulatory requirements and licensee
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commitments had been met.
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The inspector performed a review of the design procedures which are-used in the load verification program and conducted meetings with
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cognizant licensee and Bechtel engineers who are involved in carrying out this activity.
Further, the inspector performed a review of some sample design evaluation packages performed for the qualification of a
i selected structural members.
The load verification program addresses three major types of support attachments:
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Pipe support reaction loads as determined from the As-Built
Reconciliation of piping-systems.
Evaluation of building steel i
is performed using the actual magnitudes of large bore reaction loads and actual location of attachments as indicated on the larger drawings.
Bulk installations identified above are evaluated by performing
walkdowns to review and record as-built conditions.
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Major equipment is evaluated based on final loads provided by
vendors and-installation ic.ations as verified by walkdowns.
The inspector determined that the load verification.of bulk attachments require considerable judgement from engineering personnel performing the evaluation since it involves' an assessment of. building structures on the basis of an evaluation of attachment: locations from above and below the floor (via walkdowns).and determining reaction loads using simplified calculations rather than actual as-built final loads.(as in the case of large bore piping attachment _s).
Effects of computed'
bulk loads on structural members are assessed against the original-assumed design uniform floor loads (lbs. per sq. ft.) to verify the design adequacy of these members.
Initial design of structural beams typically includes a minimum of-50 lbs. per sq. ft. floor load to account for all bulk attachments.
Based on the review and assessment of bulk installations, if a floor contains attachments which exceed the assumed design uniform load, the most heavily loaded areas of the floor are selected and the at-tachment loads which are tributary to the most heavily loaded beams are determined. Calculations are performed to verify the adequacy.of these identified beams. Detailed calculations of structural adequacy are also performed for structural beams when changes in loads occur (as in large piping attachments and major equipment). Thus, the~ade-quacy of some beams 'is determined by their similarity with other beams for which detailed calculations are performed.
The licensee indicated that of...e approximately 800 areas reviewed, only 10 cases were found where the 50 psf floor load was exceeded.
In all cases the structural steel beams were determined to be adequate.'
Further, the licensee indicated that the installation of most commod-ities other than conduit and small piping, were complete at the time of the structure load verification walkdowns.
The walkdown is. typically performed by a team of engineers consisting of an originator and a checker. A check sheet is prepared for each area which documents the walkdown results. Rooms on both sides of a common boundary (wall or slab)'are walked down in order to determine the total attachment loads on the wall or slab.
Many of the observations which were noted during this review had been already addressed in the Independent Design Verification (IDVP) report.
Further specific evaluations which were performed by Bechtel in-
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response to the IDVP findings were found to be generally acceptable.
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6.3 Installation of the Control Rod Drive (CRD) Housing Supports
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The function of the control rod drive housing supports is to prevent any significant nuclear transient in the event a drive housing breaks or separates from the bottom of the reactor vessel.
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The CRD housing supports consist of horizontal beams installed.immed-iately below the bottom' head of the reactor vessel, between the rows of CRD hou;ings.
The beams are welded to brackets that are welded to the steel liner of the reactor support pedestal. Hanger rods are supported from the beams on stacks of disc springs.
Support bars are bolted between the bottom ends of the hanger rods ~. ' Individual grids rest on the support bars between adjacent beams.
Each grid assembly is made from two grid plates, a clamp and a bolt. The top part of the clamp guides the grid to its correct position directly below the CRD housing. With the support bars and grids properly installed, a gap of slightly more than one inch exists between the grid assembly and the bottom surface of the CRD housing flange.
A visual inspection was performed of the support bars and grids to
verify proper assembly. Measurements were made, on a sampling basis, to insure that adequate spacing existed between the grid assemblies and CRD housing flanges.
This area was found to be satisfactory.
6.4 Component / Equipment Supports Control Area Chilled Water System (CWS)
The control area chilled water system components were considered for
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as-built verification of their supports due to the following:
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The inspection of the CWS provides a continuation to the inspec-
tion of the Safety Auxiliary Cooling System (SACS) since the CWS is cooled by the SACS The system has a significant safety function since it provides
chilled water to maintain satisfactory ambient air temperatures in the following areas: main control room, auxiliary equipment room including computer room and battery rooms, emergency switch-gear rooms, SACS pump rooms, and class IE panel rooms.
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The control room area CWS consists of two subsystems:
the main con-trol room chillers and the class IE panel room chillers.
Five major components (from both subsystems) were selected for as-built verif-ication of their support and foundation.
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The selected components are:
Control room A/C unit 1AVH-403
l Chilled water circulating pump 1AP-400
l Control equipment room A/C unit 1AVH-407
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Chilled water chemical feed tank 1AT-401
j Chilled water head tank 1A410
The inspection attributes for the above equipment supports included:
verification of as-built support or foundation configuration
dimensions.
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l verification of hold-down anchor bolt sizes, location and tightness
identification of cracks in the concrete foundations
- i visual inspection of welded joints
6.5 Visual Weld Acceptance Criteria (WAC)
The Nuclear Construction Issues Group (NCIG) document NCIG-01 provides
alternate visual weld acceptance criteria (WAC) for structural welding l
conducted to AWS D1.1 requirements.
This document has been endorsed by NRR with the stipulations that the licensee obtain an FSAR change, i
conduct adequate training in the interpretation of the document, and assure that the applicability of the NCIG-01 is acceptable to the cognizant engineer.
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The inspector reviewed the licensee's WAC inspection activities.
l FSAR change Notice 985 addresses the request for the use of NCIG-01.
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The inspector noted that the use of NCIG-01 will be limited to welding-conducted under Bechtel specification C-130Q as amended to add the
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WAC criteria in Appendix "D".
The training program consisted of a 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> lecture (with specially prepared samples) which was given to j
more than 250 people representing FQC's and FWE's. The FWE's were required to take a written test on the WAC criteria.
In a previous
i inspection a regionally based inspector attended a typical training
program conducted on September 23, 1985. The engineering control and the scope of usage of the WAC criteria 4s evidenced by the restric-
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tion of its use to the C130Q specification.
Full implementation of
the WAC document commenced September 26, 1985 in accordance with the N.D. Griffin (Bechtel) memo FE-1955 dated September 20, 1985, t
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6.6 Finding and Conclusion The inspectors concluded that the building structure as-built verif-ication program had met the intent for which it was established.
Though some questions were raised regarding the degree to which engi-neering judgement was used in carrying out the walkdown verification and evaluation of bulk attachments, nevertheless, the cognizant engineering person interviewed by the inspector was found to be know-ledgeable in performing the required activity.
Further assurance regarding the completeness of this activity was derived from the review of result of the IDVP comprehensive evaluation in this area.
Components and equipment supports and foundations verified during.the inspection were found to be in conformance with the installation drawings. No items of noncompliance were identified.
7.0 As-Built Verification of Equipment for Selected Emergency Operating Procedures 7.1 General The scope of this phase of the inspection was to examine the installa-tion of selected portions of safety related systems that would be used during implementation of the plant specific Emergency Operating Procedures.
Portions of the following systems were included in this area of the inspection:
Condensate Storage and Transfer System
Service Water System
High Pressure Coolant Injection System
Reactor Core Insolation Cooling System
Nuclear Steam Supply Shutoff System
The objective of this inspection was to verify that the as-built configurations were in conformance with the FSAR, the SER and system specifications and drawings and that they were capable of performing their intended functions as specified in the FSAR and in the Emergency Operating Procedures.
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7.2 Alternate Reactor Cooling Water Sources The Emergency Operating Procedures identify three alternate water sources that may be used in the extremely unlikely event that both normal _and emergency core cooling systems are unavailable. These three sources are: (1) Condensate Storage and Transfer System; (2)
Service Water System and (3) Fire Water System.
7.2.1 Condensate Storage and Transfer System Accessible portions of the system were visually-inspected from the Condensate Storage Tank (CST) in the yard to the
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residual heat removal and core spray flushing connections in the reactor building.
7.2.2 Service Water System The Service Water System "as visually inspected.' rom the supply header (reactor building elevation 77') to the intertie connection with Loop B of the residual heat removal system.
In addition a visual inspection was performed of the system from the fire hose fill connection (Auxilisry Building Elevation 77') on service water Loop B to the residual heat removal system Loop B intertie.
7.2.3 Fire Water System The ability to connect the fire water system (via fire hose)
to the Loop B service water fill connection was verified.
7.3 Suppression Chamber Level Control The Emargency Operating Procedures identify four systems that may be employed for emergency makeup to the suppression chamber and three systems that can be used for emergency drawdown. Two of these systems, High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC), were selected for inspection since they could be used'
in both modes.
7.3.1 Emergency Makeup When employed for suppression chamber makeup both the HPCI and RCIC systems would be aligned to take suction from the CST and would discharge to the suppression chamber via their separate minimum flow lines. A visual inspection was made of both systems from their separate connections to the con-densate storage and transfer system near the pump suctions (Reactor Building Elevation 54') to their minimum flow return lines to the suppression chamber.
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l 7.3.2 Emergency Drawdown When used for suppression chamber drawdown both the HPCI and RCIC systems would be aligned to take suction from the suppression chamber and discharge to the CST via a common return line at valve BJ-HV-F011. This alignment requires
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that valve interlocks on BJ-HV-F011, which wou'd normally prevent opening if either system's suppression chamber suction valve were open, be~ defeated. A visual inspection was nade of both systems from their separate connections to the suppression chamber near the pump suctions (Reactor Building Elevation 54') to the common return line to the CST at valve BJ-HV-F011 (Reactor Building Elevation 77').
In addition, portions of panels H11-620 and H11-P621 (Auxiliary Building Elevation 102') were inspected to verify that the as-built wiring would support the intended bypassing of the valve interlocks on BJ-HV-F011.
i 7.4 Bypassing Main Steam Isolation Valve (MSIV) Interlocks
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During certain degraded modes of operation the Emerge icy Operation Procedures direct the re-opening of the MSIVs to aid in reactor pressure control and to reduce the heat load on the containment.
To
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accomplish this task it would be necessary to equalize pressure around the inboard MSIVs and, in certain instances, defeat the MSIV isolation interlock on low water level in the reactor vessel '(L1:-129 inches).
A visual inspection was made of the accessible portions of the main steam equalizing lines from inboard of the MSIVs in the drywell via the BB-HV-F016, BB-HV-F019 and BB-HV-F020 valves to the main steam lines in the steam tunnel.
In addition, bays A and C in panel H11-P609 and bays B and D in panel H11-P611 (main control room) were inspected to verify that the as-built wiring would support the intended bypassing l
of the L1 MSIV isolation interlock.
l 7.5 Scram Solenoid De-energization In the extremely unlikely event that some (or all) scram pilot valve solenoids should fail to de-energize when required by the reactor protection system the Emergency Operating Procedures direct actions i
to manually remove power from these solenoids. The method chosen I
requires that eight fuses be removed to achieve a complete de-ener-gization of all solenoids. An inspection was made of the as-built wiring in bays A and F of both panels H11-P609 and H11-P611 (main
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control room) to verify that, with the as-built w} ring, the removal of the indicated fuses would, in fact, produce the desired de-energization.
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7.6 Findings and Conclusions
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The inspection in this area demonstrated that the systems examined were constructed in accordance with the descriptions in the FSAR and
system specifications and drawings. The portions of systems inspected were found to be capable of performing their intended functions as described in the FSAR and as required by the Emergency Operation Procedures.
No discrepancies were observed.
8.0 Comparison of FSAR Accident Analysis Descriptions to As-Built Plant 8.1 General
The objective of this phase of the inspection was to insure that design changes made to the facility during construction were being properly
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incorporated into the accident analysis of the FSAR. A review was made of sections 1 through 4 of Chapter 15 (Accident Analyses) of the I
FSAR to identify any assumptions or inputs into.the accident analysis
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which were in conflict with the as-built plant.
l The inspector identified three instances in which the Chapter 15 discussions failed to reflect the as-built plant.
These items were discussed with the licensee and resolved as indicated below.
i 8.2 Reactor Recirculation Automatic Flow Control The automatic flow control mode of the reactor recirculation system
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is a non-safety related control system which would provide the plant
with limited load following capabilities. While the licensee has elected to defeat this control feature, several sections of _the Chapter 15 analysis still contain discussions of the plant response to transients while operating in this mode. The licensee indicated that the deletion of this control mode was a recent change and pro-r vided the inspector with the change notice that was in process to
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update the FSAR.
Following review of the change notice the inspector
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was satisfied that this change was being properly addressed.
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8.3 Residual Heat Removal Steam Condensing Mode
The steam condensing mode of the residual heat removal system is a non-safety related mode which would provide an alternative means of
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decay heat removal. The licensee has elected to defeat this operating J
mode. However, in the analysis of the loss of feedwater flow transient, the use of this mode is indicated as part of the operator actions in response to the transient. The inspector discussed this discrepancy with the licensee.
The licensee indicated that'this' item had been recently' identified and provided the inspector with a copy of the
applicable change notice which was in process to update the FSAR.
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8.4 Main Steam Line Isolation on Low Reactor Water Level The inspector identified an internal inconsistency in Chapter 15 involving the reactor water level setpoint which would cause a full main steam line isolation. Most analyses indicated that a full iso-lation would occur at a reactor low water level of -129 inches -(L1).
However, in three cases (Generator Load Rejection, Reactor Recircula-tion Pump Trip and Recirculation Flow Control Failure with Increasing Flow), the analyses indicates that a full isolation would occur at a reactor low water level of -38 inches (L2). Discussion with the licensee indicated that the correct setpoint for a full main steam line isolation is -129 inches (L1). The licensee agreed that the i
three cases identified by the inspector were in error and committed
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to revising those sections to reflect the correct setpoint. The inspector noted that the use of the L2 setpoint for full main steam line isolation was conservative in all three cases and provided results which bound the actual plant respense.
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8.5 Findings and Conclusions The inspection in this area demonstrated that accident analysis of Chapter 15 of the FSAR, including pending Change Notices, is in sub-stantial agreement with the as-built facility. Also, the Itcensee's
review program provides reasonable assurance that design changes will be evaluated for potential impact on the FSAR accident analyses.
In response to the. inspector's concern that.long time delays may exist between the approval of a design change and the updating of the FSAR, the licensee briefed the inspector on a recently instituted program to accelerate updating of the FSAR.
The program provides'for a significant reduction in turn around time for incorporation of field changes into the FSAR.
In addition, the program will review all NSSS design changes made to date against the FSAR to insure it accurately reflects the as-built facility.
No violations were identified.
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9.0 Independent Verifications 9.1 Motor Operated Valve Operability The RHR low pressure system injection (LPSI) motor operated valve (MOV),1-BC-HV-F017A, was selected by the inspector to verify control operability during a degraded grid voltage condition coincident with
a loss of coolant accident (LOCA) condition.
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The 4.16 KV Class IE bus A401 supplies power through a load center transformer where the 480 vcit side in turn supplies power the motor control center (MCC) 108212.
The MOV is controlled and supplied power from this MC *
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One equipment name on P&ID differed from other identification
used for the same equipment; One diesel generator room with the incorrect color identi-
fication; and Plant wide lack of labeling of pumps, motor operated valves
etc.
With the exception of the last item, the licensee took prompt corrective action to assure proper identification of components or areas. The last item is being addressed by the licensee in a Site Engineering Instruction (SEI) 3.7 Revision 0, " Plant Labeling Programs" dated April 19, 1985. A purchase specifica-tion is being prepared for plant labels.
The licensee has not specified when this program would be completed.
4.
The inspector noted that a cable tray fire stop had been partially opened. A discussion with the licensee and a review of procedure
" Penetration Seal Review, Sign-Off, and Work Tracking" SWP/P-C120, Revision 6 indicated that all acceptance and modification of penetrations, including fire stops, are being controlled.
5.
The inspector reviewed Startup Deviation Reports associated with damaged Rosemount transmitters resulting from the use of Neolube 100 thread sealant on each of two covers per instrument.
Because of the potential damage to the pressure boundary when the covers were removed SDR ZC-0061 was issued, with procedure PSE-PR-E-006, Revision 0, December 11, 1985, " Pressure Leak Test for Rosemount 1153 Nuclear Transmitters."
Thirty six transmitters are to be removed and replaced with new transmitters. Seventeen transmitters will have covers replaced.
One transmitter will have its Conex EQ cable nipple replaced.
One hundred and fifty five transmitters will be restored to the original installed conditions and recalibrated.
The inspector visually walked down all transmitters at elevation 55 feet and 77 feet in the reactor building. As a result of this inspection, three additional SDRs were issued. These were for the following: one additional transmitter to be removed and replaced; one transmitter cover replaced and one Conex EQ cable replacement. The licensee was also advised that some of the temporary covers had become dislodged. The licensee should assure that before the recalibration takes place that the concerns of finding item 1 above are addressed.
No violations were observed during this inspectiot.
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One equipment name on P&ID diffe' red from other identification
used for the same equipment; One diesel generator room with the incorrect color identi-
fication; and Plant wide lack of labeling of pumps, motor operated valves
etc.
With the exception of the last item, the licensee took prompt corrective action to assure proper identification of components or areas. The last item is being addressed by the licensee in a Site Engineering Instruction (SEI) 3.7 Revision 0, " Plant Labeling Programs" dated April 19, 1985. A purchase specifica-tion is being prepared for plant labels. The licensee has not specified when this program would be completed.
4.
The inspector noted that a cable tray fire stop had been partially opened. A discussion with the licensee and a review of procedure
" Penetration Seal Review, Sign-Off, and Work Tracking" SWP/P-C120, Revision 6 indicated that all acceptance and modification of penetrations, including fire stops, are being controlled.
5.
The inspector reviewed Startup Deviation Reports associated with damaged Rosemount transmitters resulting from the use of Neolube 100 thread sealant on each of two covers per instrument.
Because of the potential damage to the pressure boundary when the covers were removed SDR ZC-0061 was issued, with procedure PSE-PR-E-006, Revision 0, December 11, 1985, " Pressure Leak Test for Rosemount 1153 Nuclear Transmitters."
Thirty six transmitters are to be removed and replaced with new transmitters.
Seventeen transmitters will have covers replaced.
One transmitter will have its Conex EQ cable nipple replaced.
One hundred and fifty five transmitters will be restored to the original installed conditions and recalibrated.
The inspector visually walked down all transmitters at elevation 55 feet and 77 feet in the reactor building. As a result of this inspection, three additional SDRs were issued. These were for the following:
one additional transmitter to be removed and replaced; one transmitter cover replaced and one Conex EQ cable replacement. The licensee was also advised that some of the temporary covers had become dislodged.
The licensee should assure that before the recalibration takes place that the concerns of finding item 1 above are addressed.
No violations were observed during this inspectio *
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During this review, the inspector noted that the initial calibra-tions were not based on the as-built elevations of the instrument lines.
The failure to incorporate the as-built elevation data into the calibration calculations could result in the systematic miscalibration of the reactor vessel water level instruments.
The inspector informed the licensee that the adequacy of the reactor vessel water level instrumentation to perform its design functions would be considered unresolved until the following l
concerns are addressed:
(354/85-58-04)
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i Incorporation of the as-built elevation data into the reactor
vessel level instrument calibration calculations; and Subsequent re calibration of the affected instruments.
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l 2.
The inspector review of the draft Technical Specification, Section 4.8.4.4 Reactor Protection System Electrical Monitoring Surveillance Requirements, finds that the 132 VAC over-voltage setpoint may not protect the scram solenoids from a power supply over voltage condition.
The solenoids' electrical tolerance for operability is 115 volts plus or minus 10 percent.
Thus, the over-voltage value is 127 volts not 132 volts.
Neither value accounts for the voltage drop between the Electrical Protective Assembly and the furthest solenoid.
The licensee has agreed to follow the recommendations contained in General Electric Spec Data Sheet MPL Item No. C71-4010,
" Reactor Protection System" 22A3083AK Revision 6 for the setting of the Electrical Protective Assembly which accounts for the voltage drop.
After these values are obtained, they will be
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used in the final Technical Specification.
3.
The inspector noted the following during the visual inspection:
Five Instruments without identifying tags;
One loose wire termination within each of four control panels;
Three auxiliary relays within each of four control panels
did not have a identifying name plate; One equipment name plate on each of four motor control centers
had incorrect information; One equipment name plate missing from a motor control center;
One motor power conduit identification missing;
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Traveling Screens EP-AS501, CS501, BS501 & DS501.
- Traveling Screen Spray Booster Pumps EP-AP507, CP507,
BP507.
The DP507 pump was removed.
Screen Level Instruments LE-2225A1, A2, C1, C2, B1 &
B2, D1 & D2.
River Level Instruments LE2220-1.LE2220-2 was
removed.
Service Water Pump Suction Level Transmitter LE-2241A,
C, B&D.
Service Water Strainers Differential Pressure Trans-
mitters:
PDT2194A, C, B&D; PDT2195A, C, B&D; PDR2196A, C,
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B&D and PDT2197A, C, B&D Traveling Screen Spray Booster Pump Flow Switch
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EP-FS2225A, C, B&D Service Water Pump Area Heating and Ventilation Control
Panels A & C.
Service Water Pump Area Motor Control Centers 108553,
63, 73 & 83.
Traveling Screen and Wash System Control Panels AC,
CC, BC & DC 515 and AC, CC, BC & DC 516.
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5.3 Findings The inspector found that the state of workmanship in,the area was generally good and the instrumentation and control systems inspected conformed to the criteria of paragraph 5.1.
However, as a result of the as-butit inspection, the following specific findings were noted for which licensee corrective actions were in progress at the end of the inspection.
1.
Following the visual inspection of the nu: lear boiler instrument impulse lines, the inspector reviewed selected reactor water level instrument calibration data sheets and the documentation which provides the basis for these initial calibration settings.
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The discrepancies found in the system as-built configuration are The number of being corrected under various licensee programs.
items found is relatively small considering the depth and breath of the as-built walkdown verification. The nonconforming con-ditions found would not significantly impact upon the safe operation of the systems.
7.
The inspector identified that SOV vent valves V776 and V777 had
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been mistagged as V774 and V775 respectively.
The inspector was
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provided Startup Deficiency Report (SDR) BF-270 that documented the North and South vent valve tags had been mistakenly exchanged.
The inspector was informed that the tags were reaffixed to the proper valves. The licensee stated that the system P&ID had been used to tag the valves in accordance with procedure SEI 7.4.
The scope of procedure SEI 7.4 is limited to instrument
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root valves and skid mounted valves.
Pending licensee review of the tagging prog' ram procedural controls, this item is unresolved.
(354/85-58-03)
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8.
The inspector examined small bore support 1-P-BF-435-H3 and found two cases of underlength fillet welds,wherein the design specified end returns had not been provided. The inspector reviewed the
. associated support calculation and ascertained that the end return weldments would not be required to ensure the support lead carrying capacity.
Field Change Request P-16162 was issued to provide engineering criteria to inspect the end return welds. Quality Action Request F310 was issued to ensure training of appropriate personnel re-garding end return weldments. The inspector reviewed structural, electrical, and other pipe support design drawings and found in all cases that weld length was specified. The inspector had no further questions.
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4.0 Electrical Systems 4.1 General The objective of this phase of the inspection was to examine the installation of selected portions of the Class 1E ac and de power systems and to verify that the as-built conditions agree with FSAR and SER descriptions and project specifications and diawing require-
ments. The portion of the ac system selected for inspection were those associated with the "A Train" station service water system, RHR system, and the SACS system.
In the de power system, the batteries and battery chargers were examined.
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The walkdown inspection of the CWS, SSWS and SACS piping components and hangers disclosed the following discrepancies between licensee design documents and existing field installations.
The noncon-formance reports (NCR's) referenced below were issued during the inspection to resolve each associated issue.
(i) The existing clearance gap between large bore service water piping and rigid restraint 1-P-EA-026-H02 was found to be
.049 inches on one side.
Pipe support drawing 1-P-EA-026-H02(Q) Rev. 4, F0 specifies 1/16 inch gap on both sides.
Specification P-410 specified tolerances with a combined total clearance of 3/32 inches minimum. NCR No. 8875 was written to document the actual gap.
(ii) SACS isometric drawing 1-P-EG-06 shows valve 1-EA-V804 stem in the horizontal position.
The existing valve stem is approximately 45 from the horizontal position. This orien-tation was found to facilitate installation to avoid hand-wheel operational interferences and to have minimal impact on system stresses and restraint loading. NCR No. 8891 and FCR-P-16150 were issued and approved to document the as-found.
orientation.
(iii) A poorly designed, non-functional (unstable) spring can hanger was found installed on a 1 inch diameter fuel pool make-up line.
FCR No. PF-12046 was issued to redesign the hanger which was reinstalled and found to be acceptable.
(iv) SACS pipe support drawing 1-P-EG-107-H06(Q) specified a 5/16" fillet weld where the existing fillet weld measured
"
NCR No. 8886 was issued to document the nonconforming
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condition.
(v) Hanger 1-P-EG-159-H01 clamp was observed by the inspector to be in contact with nearby support steel during SACS operational testing. The hanger was reinspected under non-operating conditions and a.035" clearance was measured.
This gap and the hanger drawing design movement is determined as acceptable for QC inspections.
Yet, to enhance the func-tional operation of the spring support,'PSE&G will relocate the clamp within the tolerance specified in specification P4.10.
(vi) Anchor bolt elevation and top of floor elevation for chilled water. system tank 1AT401 on drawing C-0399-0 Sheet 294 appeared to be in conflict.
This discrepancy was attributed to a drafting error and is to be corrected via a Field Change Notic..
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During a degraded grid voltage condition, the bus A401 normal supply breaker is tripped at 92% bus voltage. Under these conditions, the bus would be reenergized from the standby emergency diesel generator associated with this bus.
A study " Millstone Voltage-1E Buses" Calc. No. 15.1, Revision 2 established the 92% trip setting for all 4.16 KV Class IE busses.
This study also provided the voltage condition at MCC, 108222, which
is the redundant MCC to 108212.
The MCC 108222 has a longer. cable
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length from the loadcenter than MCC 108212, therefore, the low voltage
at the MCC for MOV F017A is conservative.
This value is 86.21% of
480 volts which is equal to 413 volts. The voltage on the secondary side of the control transformer is 413 divided by the turns ratio of a
3.804 which is equal to 106 volts.
This value is representative and d
was used in the study " Control Transformer Selection and Maximum Circuit Wire Lengths for MCC Control Circuits" Calc. No.17A, Revision 1.
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The method of calculation is to add vectors of the control wires and control transformer series impedances to solve for the voltage at the contactor coil. This voltage would then be compared to the minimum pickup voltage specified by the vendor. The inspector's independent calculations are contained in Attachment 1.
The inspector concluded that this MOV will function during a degraded low voltage grid con-
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dition.
9.2 Field Measurements of Piping and Pipe Support As-Builts The inspector used a tape measure and fillet gages to independently verify piping and pipe support measurements on the Residual Heat Removal, Scram Discharge Volume, Service Water, and Safety Auxiliary Cooling Systems. The verified measurements included:
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linear pipe run dimensions
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pipe support locations and unsupported pipe span lengths
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Mechanical component locations
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pipe support member size
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concrete expansion bolt size
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pipe support weld size and length With minor exceptions as discussed in Section 3.4 of this report, the independent measurements were in correlation with licensee design and as-built documentation.
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9.3 Independent Evaluation of Available Voltage at Selected Loads
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The inspector selected the train A. station service water pump and motor control center in the station service water building as repre-sentative safety loads to determine that the voltage available would be adequate under worst case degraded grid voltage conditions for starting and running the motors in this location.
In conducting this evaluation, the inspector reviewed the following:
Cable type, sizes, length and impedances
Circuit breaker type, size and ratings
Pump motor size, starting and running currents
Motor control center starting and running currents
Worst case voltage conditions at the emergency busses
Hope Creek (Millstone) Voltage Study Calculation 15.1(Q) - IE
Buses, Revision 2, dated 10/3/85 Safety. Evaluation Report NUREG-1048, Section 8.3.1.1 " Voltage
Drop Analysis" The inspector reviewed the Bechtel voltage study including voltage profiles at the various IE safety buses under various and worst case type conditions including conditions of degraded grid voltage.
In addition, the inspector reviewed staff conclusions made in SER NUREG-1048 Section 8.3.1.1 related to the fact that there is reasonable assurance that all class IE loads will operate at or within design voltage limits under all~ conditions of plant. operation.
The inspector also conducted a walkdown o# tb. 4160 volt and 480 volt power cable runs from the emergency switchboard and unit substation to their respective service water pump snd motor control center loads to verify circuit breaker adequacy; cab'e type, size, support, spacing, routing, marking, and lengths.
no inspector compared cable pull r
cards and termination records to tha actual installation. No dis-crepancies were discovered.
Using Okonite Company Cable Technical Bulletin EHB-78, the inspector performed independent voltage calculations as shown in Attachment 2 to determine the voltage drops in the power feeder to the Station Service Water Pump "A".
Cable impedances, motor starting and runring currents and the calculated voltage drops were found to be consistent with the data reported in the referenced Bechtel " Millstone Voltage Study." Voltage drops calculated provide assurance of adequate volt-age for starting and running these loads within the 80 percent mini-mum motor voltage requirement of Section 8.3 of the FSA piw-
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9.4 Independent Evaluation of Cable Pulling Tension for Power Cable The inspector selected the power cable for the train A station service water pump as a representative cable to perform an independent evalua-tion of cable pulling tension calculations for comparisons to cor-struction calculations and to actual tension measured during the cable pull. The calculation and comparisons are made to assure that the cable pulling tension calculations and methods used are adequate to ensure protection of the cables during installation.
In conducting the evaluation, the inspector reviewed the following:
Bechtel Power Corporation " Users Manual ECG-102 Cable Pulling
Calculations Using a Programmable Calculator, Horizontal and Vertical Pulls, Book Number Two" General Electric Technical Handbook " Wire and Cable Selection,
Section 8C1 Cable Installation Data" Okonite " Bulletin EHB-78 Engineering Data for Copper and Aluminum
Conductor Electrical Cables" IEEE Standard 422-1977 IEEE Guide for the Design and Installation
of Cable Systems in Power Generating Stations Bechtel Drawing 10855-E-1449-0, Sheet 31A " Cable Pulling Notes
and Diagrams" Bechtel Drawing 10855-E-1000-0, Sheet 1 of 9 " Electrical Cable
Description" In making the cable pulling tension calculations, the inspector deter-mined the following:
The service water pump 1AP502 power cable is Okonite SKV, #4/0,
cable code A04, 3 single conductors.
Each conductor is 1.219 inches 00, 1.161 pounds per foot, and has a minimum bend radius of 14.6 inches and a maximum pulling tension of 1,693 pounds.
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The cable is standard copper with a tinned copper tape shielding and with an overall hypalon insulating jacket.
Okonite specifies a maximum cable sidewall pressure of 500 pounds
per conductor per foot of bend radius for pulling the cable to preclude cable damage. The minimum bend radius for'the cables is 3 feet which provides the most restricting sidewall pressure limitation for this cable pull of 3 x 500 = 1500 pounds, x 3 cables = 4500 pounds which is restricted to 2/3 of this value or 3000 pounds due to the fact one of the cables may try to ride the other two during the pul.. _.
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l For pulling the cable Okonite recommends the use of a pulling
l lubricant compound indicating that for the hypalon Jacket a lube
made by Utility Industries maybe used. The cable was lubricated-
during the pull.
The cable pull card shows that 810 feet of the cable was pulled
l from the service water pump into a buried concrete duct through manhole 15 AM0001A to manhole 15 AMOD01 just outside the diesel-generator building where it was' spliced with 200 feet of cable pulled from the emergency switchgear room to make.an overall j
length of 1010 feet for this power cable.
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This cable is identified as cable number AC10205A.
- The coefficient of friction used for this pull calculation through
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the duct bend for the three single conductors pulled at one time and properly lubricated is 0.5 (Bechtel used a value of 0.4).
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i The cable pull routing description horizontally and vertically
including straight run lengths and angular turns are described
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on Drawing E-1449-0 Sheet 31A. This description forms one of the basis used in this calculations, except that this calculation
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The allowable maximum pull tension for the three cables of
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3X1693 lbs = 5079 lbs is reduced by 1/3 to 3388 pounds since the
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cables are pulled from separate reels in parallel into the same i
conduit and one cable may ride the other two during the pull.
The inspector conducted a walkdown of the cable run from the service water pump out of the service water building and followed the duct bank routing to the manholes and into the diesel generator building-and then to the emergency 1E switchgear breaker cubicle. The cable lengths from the cable pull cards were compared to the length estimated
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during the walkdown. The actual length on the pull card appears to be correct.
Using the formulas and tables in General Electric Technical Handbook for Wire and Cable Installation Data Section 8C1, the inspector calcu-
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lated the expected tension for pulling this cable.
These calculations are shown in Attachment 2.
The calculated value obtained was compared j
to the value calculated by Bechtel as shown on the cable pull card.
The value calculated by the inspector was 2315 pounds as compared to i
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a value calculated by~Bechtel of 2059 pounds. The actual pulling i
tension measured by dynamometer and shown on the cable pull card was J
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2078 pounds.
The inspector finds that the cable pull' tension calcu-
lation formula and methods used by Bechtel to calculate expected cable
pulling tensions to be satisfactory and finds no reason to question
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the calculations.
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No deficiencies were discovered.
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10.0 Quality Assurance Program Inspections i
j-10.1 QC Inspection Records l
The inspector examined QC inspection reports associated with:
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pipe supports; piping installation;
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mechanical equipment installation;
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structural steel erection; and
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Nondestructive Weld examinations.
The records were found to specify the requisite information regarding
the item inspected; reference documents utilized during the inspec-
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tion; Quality Control Inspection Report (QCIR) number; inspector identification; accept reject notation; and report review, i
l The inspector had no further questions.
i 10.2 Quality Control Instructions Quality Control Instructions (QCI) are written to provide inspection checklists consisting of surveillance and mandatory holdpoints. The
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QCIs document inspection attributes contained within engineering-specifications. The QCIs include generic QCIR forms that capture the'
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requisite inspection attributes.
The QCIs are originally written by
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home office quality staff and can be subsequently revised on-site.
f The inspector reviewed QCIs associated with the following activities:
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Structural Steel Erection;
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HVAC Ductwork;
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Piping Fabrication;
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Piping and Pipe Supports Final Inspection.
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These QCIs contained appropriate inspection criteria for the asso-ciated activities,
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The inspector had no further questions.
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s 10.3 QA/QC Interface in Building Load Verification Program The inspector determined that the only QA interface in this activity was conducted as part of an audit (Report No. NH-85-026) performed by the licensee at the-Hope Creek site during the week of August 5, 1985, and at the San Francisco Bechtel Home Office (SFHO) during the
week of August 12, 1985.
The audit included verification of controls associated with preparation of piping As-Built Reconciliation packages, review of pipe support calculation and distribution'of ABR required
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information to layout pipe support and stress group. The applicability of this audit to the building verification program is limited to the verification of attachment reaction loads from large bore piping.
The licensee also identified that an engineering audit was being
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conducted by PSE&G staff at SFHO, during the NRC inspection of Hope
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Creek. The audit was to address the building verification program
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and to verify that all building steel supporting piping, equipment and other bulk installations have been qualified by documented calcu-lations.
The inspector had no further questions.
10.4 Document Control
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During this inspection, some time was allocated to reviewing the adequacy of administrative controls associated'witn preservation of i
the as-built plant conditions. As construction hears completion, a
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two step turnover of plant systems is in process. The first step is j
that as systems are completed, the Contractor (Bechtel) turns the system over the Licensee Startup Group. When the Startup Group has i
completed testing, control of'the system is transferred to the Opera-tions Group. During this period, work controlling documents may be
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issued by any one of these groups depending on the system status.
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The inspector reviewed the operations of two document control centers
used by the Startup Group. These are controlled by the Site Engineering Section. The first area reviewed was Document Control - Test. The
functions in this area were:
Test Engineers request document packages for specific tests to
be performed.
These requests include specific procedures, forms, drawings, etc. required for the test.
Document Control - Test assemblies the package and issues it to
the Test Engineer.
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Upon completion of testing, the Test Engineer returns the package
for distribution and filing.
The inspector reviewed several packages and found them complete.
The inspector asked to see the package for the test that identified defec-tive transmitter 1EP-LDT-2225A reported on NCR 5902. The information available on the NRC did not match the filing designators but the package was readily retrieved.
In this package, one of the work con-trolling documents was General Test Procedure (GTP)-2, Revision 2.
The inspector determined that the revision of GTP-2 as of 12/10/85 was Revision 5, but at the time of the test, October 1984, the Revision 2 was correct.
The inspector reviewed the Technical Document Room (TDR) located in the administration area of the plant operations section. The TDR is the distribution point for documents to be used for work on systems turned over to operations.
Hard copies of vendor manuals, aperture cards of drawings and microfiche of other documents are available in the TDR.
Facilities are available for making hard copies from the microfiche and aperture cards but not for duplicating the microfiche or aperture cards. Access to the computer system for verifying revisions is available. When documents are issued they are either stamped "For Information Only" or " Working Copy User Responsible for Confirming Validity for Field Use.
Issue date This
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document cannot be used in the field after the next revision or 7 days after the issue date." Only approved documents received from the Site Engineering Document Center or Change Authorizing Documents (CAD) received from the Bechtel Document Control Center are available in the TDR. To determine if the system for updating vendor manuals was adequate, the inspector randomly chose several manuals and noted the revisions to various pages of these manuals. He then witnessed the verification against the computer data and subsequently reviewed the same revisions in the master file kept in the Site Engineering Document Center. All of these references agreed with the revisions chosen.
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The inspector reviewed the operations of the Site Engineering Document Control Center. This center is the primary distribution center for vendor manuals and da:uments generated by the Site Engineering organ-ization.
Vendor manuals are being received from Bechtel, San Francisco as well as the licensee purchasing organization. As they are received they are stamped, duplicated and the computer database updated.
Con-trol of the original manuals is accomplished by maintaining them in a locked cage. The original manuals are used solely for the source of controlled copies kept in the TDR or for Engineering reference.
No violations were observed.
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10.5 Review of Nonconformance Reports
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l In accordance with the Bechtel Quality Program nonconformance reports (NCR) are used only on "Q", "F" and seismic systems. With few except-ions, NCR's are written only when deficiencies are found during final
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l inspection. Deficiencies found during work in process are reported i
on one of several documents including Field Change Request, Field Change Notice, Supplier Deviation Disposition Request and Project Change Request.
From project start to December 10, 1985, there have been approximately 8860 NCRs written. Of these, approximately 2825 have been written in 1985. This increase was caused by the large number of final inspections being performed as construction nears completion.
i The inspector reviewed the NCR log and chose eight NCR's written during 1985 to determine the adequacy of the disposition.
For three of these eight, the inspector verified that the work described was done and was acceptable. These were:
NCR Number Subject Disposition
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5902 Level transmitter IE0-LDT-2225A The inspector verified was found defective during pre-the level transmitter system turnover testing.
has been repaired (by the Vendor) and replaced.
8086 Excess material removed from The inspector verified pressure tight door sealing the contour of the surface (arc strike).
sealing surface had been restored by welding and subsequent grinding.
8489 Primary Containment Instrument The. inspector determined gas inlet filters installed the filters had been backwards.
reinstalled correctly, the welds were visually acceptable and the fittings indicating correct fitup for socket welding were present.
Functioning of the Nonconformance Report system was found adequate.
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10.6 Nonconformance Reports Logged in But Not Issued Bechtel maintains a file of Nonconformance Reports that have been l
placed in the tracking system but not issued based on management l
assessment that the items in question did not constitute NCRs. To I
determine if these unissued NCRs were properly dispositioned, the l
inspector reviewed those concerning piping installation. The inspec-tor selected two unissued NCRs for a detailed review. The results
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were as follows:
Inspection Report Number 0-p-EA-01-8-P-1.10 Subject: Wall Thickness Below Minimum on 28" Diameter Schedule 40 Pipe. Spool No. 1-EA-034-503, 503A, 5038 Note:
This is part of Service Water Cooling System piping located on discharge side of the strainers in the Intake Structure.
Disposition:
Spool pieces were replaced with acceptable products.
Control Number N-15 Subject:
1" Diameter Pipe Lacked Markings for Traceability Disposition:
This 4 ft. section of pipe was originally properly marked when installed. A design change required installation of a Tee in the line. When the pipe was cut in place for the Tee, the identification was not transferred.
The inspector verified the original pipe was not removed and the required material identification was shown on drawing 1-P-EE-387.
No violations were observed.
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10.7 Trend Analysis The inspector reviewed the Bechtel system for trend analysis of Non-conformance Reports (NCR).
Sorting of the NCRs for trending is com-puterized using a nine digit code. The first three digits are the problem code, the next three, the commodity and the last three respon-sibility.
Responsibility has only two code numbers indicating Bechtel or Vendor. The inspector chose NCR's relating to pipe support location for verification of trend analysis.
In reviewing the QA Tracking and Trending Profile on a computer print-out of this category, the inspector noted approximately two hundred entries from the original date of July 1984.
Two Quality Assurance
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Reports had been written on the results of analysis of these reports.
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The first was dated 3/29/84 closed 8/7/84, the second QAR was dated 1/25/85 and closed 4/3/85. The analysis was performed by individuals l
in the Quality Assurance organization.
The inspector considered the
resolution of these QARs to be satisfactory and no violations were identified.
The inspector also reviewed the program for trend analysis of Defic-tency Reports (DR), Audits, Cerrective Action Requests and Management Action Requests by the licensee. This program is the responsibility of the Training and Analysis Group of the Nuclear Department. This group is doing the trending for both Hope Creek and Salem. The com-puterized system is set up to sort DRs by department (maintenance, chemistry, etc.), System, Component (based on the material equipment list designations), vendor, cause and organization reporting. Data entry has started, however, at the time of this inspection, there was insufficient deficiency data entered in the system to support a mean-
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ingful analysis.
l 10.8 Personnel Questionnaire for Departures When Quality Assurance / Control personnel terminate employment with Bechtel or Public Service Electric and Gas Company, they are requested
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l to fill out a questionnaire to give their opinions of the quality assurance program on the site.
This questionnaire includes questions on the implementation, plant design and other concerns the departing employee might have. The inspector reviewed approximately 160 of these questionnaires. The results of this review were:
a.
One complaint about lack of training to give consistency in the implementation of the program.
b.
Two individuals refused to fill out the questionnaire, l
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Two individuals were complimentary about the program implementation.
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There were no other comments.
The inspector concluded that no further followup in this area was warranted.
l 10.9 QC Inspections of Steam Condensing Mode Isolations l
l The steam condensing mode of the Residual Heat Removal system has l
been deleted in accordance with FDDR KT1-1323. The deletion of this l
mode of operation requires the isolation of various piping and compo-l nents. This is accomplished primarily by closing and deactivating motor and air-operated valves.
In addition, those lines which con-nect to the primary containment were blocked off by the installation of blind flanges in the lines on the containment side of certain relief I
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valves and vacuum breaker valves.
In the course of verifying this isolation from the containment, an inspection of the physical piping and the associated quality control records was performed. The follow-ing Quality Control Inspection Reports (QCIRs) document the installa-tion of blind flanges on the outlet of relief valves 1-BC-PSV-F097, 1-BC-PSU-F055a and 1-BC-PSU-F055B respectively: BC-01-040A-Pl.10, BC-03-07-0, and BC-01-039-C. The following QCIRs document the instal-iation of blind flanges on the containment side of vacuum breaker MOVs 1-BC-HV-4420A, 1-BC-HV-44208 and 1-BC-HV-4421 respectively:
BC-06-02A-PI.10, BC-06-19-A, and BC-06-12-B. These QCIRs were reviewed and no deficiencies were noted. The blind flanges are not shown on the system Piping and Instrumentation Drawing (PRID) but are on the fabrication isometric drawing.
Licensee personnel stated that the flanges would be added to the system isometric drawings based upon the information from the as-built verification walkdown.
The inspector had no further questions.
10.10 Engineering Assurance The Bechtel Nuclear Quality Assurance Manual (NQAM) specifies, in Section II, the requirement to have Engineering Department Procedures.
Reference is made to ANSI-N45.2.11 as a source of requirements. The following Engineering Department Procedures (EDP) were reviewed and evaluated for conformance with Section II of the NQAM:
EDP 4.27, Revision 0, Design Verification EDP 4.49, Revision 2, Project Specifications E0P 4.37, Revision'7, Design Calculations EDP 4.34, Off-Project Design Review (Design Control Check List and Design Review Notice)
EDP 4.62, Field Change Request / Field Change Notice (FCR/FCW)
l No deficiencies were identified.
11.0 Followup on Outstanding Inspection Findings 11.1 (Closed) Construction Deficiency Report (85-00-08) High Resistance Connection on Bailey Type RZ Push Button Control Modules Reference: Letter to NRC July 17, 1985 The push button switch units had oxidation of the spring steel jumper
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clip used to connect the normally open contacts in series. This problem was discovered when contact resistance testing of twelve RZ modules indicated 112K ohms and 125K onms resistance on two of seventy two push button switch units.
These values of resistance were high enough to prevent the 862 digital and the 70000 analog systems-from performing as required when the push buttons on the RZ modules was depresse.o
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The licensee corrective action was to replace the jumper clips with soldered connections using #22 AWG bare solid wire.
This replacement required 8400 connections to be made to 700 RZ modules.
The inspector discussed this completed field change with the licensee.
The work was performed by Bailey who also provided quality control (QC) for this modification.
The inspector reviewed the Problem Report, Engineering Notice, selected QC documents and concluded that this item is closed.
11.2 (Closed) Construction Deficiency Report (85-00-09) Environmental Qualification Failure of Bailey 862 Logic Modules Reference: Letter to NRC October 10, 1985 o
During environmental qualification (EQ) of the 862 logic module mis-operation was noted when the relative humidity (RH) was 60%.
The specification requires that the units be designed to operate at 80%
RH continuous and between 80% to 90% RH non-condensing for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
This misoperation was caused by electrical leakage current between the printed circuit board pads for the front panel set / reset toggle switches. The physical separation of these pads is insufficient to prevent current leakage when the RH is within the specified design limits.
The licensee corrective action was to modify all logic modules includ-t ing 200 spares.
This modification was to increase the gap between the pads by removing a portion of each pad followed by a general cleaning of the immediate area on the printed circuit board.
This modification was to be performed by Bailey who would also provide quality control.
The inspector discussed this modification with the licensee.
The licensee indicated that this problem occurred some time after the logic modules were installed because the EQ was held up due to the EMI problem. The EQ would include the logic module as modified for CDR 84-00-14.
The inspector reviewed the Engineering Notice, selected QC documents and conclude this item is closed.
11.3 (Closed) Unresolved Item 85-34-01: Construction Deficiency CR0 85-00-04 This item relates to an excessive heat buildup problem in the cmergency diesel generators local generator potential and excitation control panels.
The excessive temperature rise within these units could cause failure of current transformers insulation causing short circuiting of coils and resulting in the loss of excitation current to the diesel generator.
Loss of power from the emergency diesel generators would adversely affect safe shutdown of the plant during emergency conditions.
This problem was reported by the manufacturer in accordance with 10 CFR 21 and by the licensee in accordance with 10 CFR 50.55(e).
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The licensee has modified the panels in accordance with the manufac-turers instructions and has conducted tests and evaluations which demonstrate that the heat buildup problem has been solved. These tests and evaluations were reported to Region I by letter dated November 6, 1985. This item is closed.
11.4 (Closed) 85-00-06 Unresolved Item - Bussman Fuses In accordance with 10 CFR 50.55(e), on April 16, 1985, the licensee reported a potentially significant construction deficiency concerning 155 unqualified Bussman fuses amp and under in panels supplied by Comsip, Inc.
The inspector verified that the unqualified fuses have been replaced
i with qualified Bussman type BBS fuses for under 1 ampere and Bussman KTK fuses for 1 ampere applications.
This item is closed.
11.5 Follow-up on IE Bulletin (60-17) Resolution 11.5.1 General IE Bulletin 80-17 was issued to document an event during which almost one-half of the control rods at Brown's Ferry Unit 3 failed to fully insert during a scram.
,
The Scram Discharge Volume System (SDVS) has been evaluated relative to generic NRC design criteria and found acceptable during the licensing process.
The inspector was informed that additional licensee actions are underway te enhance plant operation or surveillance procedures, therefore the inspection scope was limited to the system hardware aspects.
j 11.5.2 Scope The SDVS documents identified in Attachment B.4 were reviewed.
The components identified in Attachment C.4 were inspected which included for the North bank SDVS:
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Scram Discharge Instrument Volume (SDIV);
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SDV vent lines and supports;
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SDIV drain line and supports;
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SDIV level instrument switches and transmitters;
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control room alarm for SDV high water level;
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control room indications for vent and drain line valve
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positions; control room keylock switches for high water level
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trip bypass; and control room level switch indications.
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11.5.3 Findings The Scram Discharge Volume design and installation was found in accordance with the FSAR commitments.
The inspector noted the licensee has established a well coptrolled program, the Response Coordination Team (RCT),
to assess generic NRC documents such as I&E Bulletins and to institute appropriate corrective actions.
The inspector had no further questions.
12.0 Unresolved Items Unresolved items are matters about which more information is necessary to determine whether they are acceptable, violations or deviations.
Unresolved items are discussed in Sections 3.4 and 5.3.
13.0 Exit Interview The inspectors met with the licensee representatives denoted in paragraph 2 at the conclusion of the inspection.
The inspector summarized the scope and findings of the inspection and the need for licensee attention to address those issues remaining unresolved. No written material was given to the licensee during the course of this inspection. At the exit, the licensee did not identify any proprietary material contained within the scope of the inspection.
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ATTACHMENT 1 RHR/LPSI MOV DEGRADED GRID OPERABILITY The purpose of this calculation is to ascertain if the RHR/LPSI motor operated valve (MOV),1-BC-HV-F017A, starter contactor will pickup (close) to permit the vElve opening during a low voltage condition (92%) at the 4KV bus which is 86.2% at the 480 volt tuotor control center (MCC).
This low voltage condition is*fb7 the redundent MCC'and MOV which was taken from Ref.1 and is a worst case.
References:
1. Millstone Voltage Study-1E Busses 10855 Calculation No.15.1(O)
2. Control Transformer Selection and Maximum Circuit Longths for MCC Control Circuits 10855 Calculation No. 17A(0)
Eaton / Cutler -Hammer Data 10855-E 110 ( q) -107-1 Okonite Cables -General Conductor Information-Bulletin 721.1 3. Cable Termination Tickets Assumptions:
1.
The operating temeperature of the cable conductor is assumed to be 50 degrees C.
2.
The control cable wire reactance as compared to the j
resistance is neglible and is not considered in this i
calculation.
Calculation
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4 -- IT
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_f Starter Control Circuit Impedonce Diagram
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RW contr ol tr mer mer an for sec sec VC c ol
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RC contr onta tor ol cui t wir sec ondary r ondary vol o tr cir mer
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XC c ol c
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ce contactor coil sistan actan o tr n
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ce ce minimum picku Co tr contactor coi l n
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_ _ _ _ _ _o l Tr c il o
p v l tago o
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Rated ____.nsfor r %ctan a
ce e
mer ce i.u 4,N$
Rated v ltage p_r______ Data __ ___Ref.2)
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v l t a pere =i marya
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r XI2=4 2,%1Ratta= 3.804 200 480
v lts g
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e =plu=4.25,%IX
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.uh s
Conta or
~y min
_____.ctor Coi1 1/2%
y us 7
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Siz
_ _ ____. Data
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Rated Starter
.______Ref.2)
M(.
e 1 (
f voltage h
____
a mps=0.G55,In 120 g
uh o ts,Inr f ;g"
-
Inr vl uh VAR s
r s
f.
Calc eG5 61w tts=56 55 a
ush
Co V a102 60.I A
7.,. ;
ntr
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p:
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, Inr Condu tor _ _ _ _ _ _ _Da t a (Re f nu i m pi ckup v. F.
ush P nr
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Cal g3 degr 14AWG_ _ _ _ _ _ _ _ _2. )
t ag e=c =55,12, 9 " ol D
v Re tutan es C.dc anne led 84% of e
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r ce r
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fe me
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=3.29 120 squar i
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X Ta%IX ohms 120 x
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ated ated 1.07S tolera
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di vi ce di vi ded
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RC=Inru h w t__________ Calcance di vided s
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ul i'b
___ __ation by 100
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s r56 55 jh' M. '
a
=77 36 dividedt s di vi ded x
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'h ZCcRated v lt v. :' 4
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?h ohms by 0 85by Inr
4 +,,4., c 'N, 7,1 5x unh
=
120 o
u age 0 055 curr
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a140 120 squ k
XC=Gqu. 35 ohm i vi ded di vi ed j[
j. 9, '..
ed squ
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ar ar
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4u are by ded a
nSqu out 102 6 by Inr r
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are of v.i.! ' m-g, s,
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ot 2C r.qu unh VAR
=Squar r
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e of ar minu
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=S rot 140.35 J
d o
ed quare of o t of 1969 x 140 35 s RC
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= 1 17.10 r o
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'h ( 4 minu 0"
nhm 13713 77.3
$vW P, ared
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ATTACHMENT 1 PAGE 2
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EM-minimum control transfermer secondary voltage l
RT-control transformer secondary resistance j
XT-contral transfarmer secondary reactance f
RW-control circuit wire resistance i
VC-control contactor coil minimum pickup voltage RC-control contactor coil resistance XC-control contactor coil reactance
Control Transformer Data (Ref.2)
l l
Rated voltage primary = 480 volts
'
Rated voltampere = 200 VA Turns ratio = 3.804
%IZ=4.26,%1Ra4.25,%IX.21 Tolerance rplus or minun 7 1/2%
l i
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Contactor Coil Data (Ref.2)
-------------------
Size i Starter j
Rated voltage 120 volts, Inrush VA=102.60, Inrush j
amps =0.G55, Inrush watts =56.55,Imrush P.F.
Calc =55.12, Inrush VAR Calc =US.61,Minumim pickup voltage =84% of rated Control Wire Da t a (F'e f 2.)
Conductor 14AWG annealed coated copper, stranded class B, 25 degrees C,dc resistance per 1000 feet =2.73 ohms Resintance temperature enrrection factor 50 degree C=1.096 Control Transformer Calculation
,
__------.-_------
!
RT=%IR x rated voltage squared x tolerance divided by 100 x l
rated VA l
=4.25 x 120 x 120 x 1.075 divided by 100 x 200
!
=1.29 ohms XT=%1X x rated voltage uquared x tolerance divided by 100 x rated VA
==. 16 ohms
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Contactor Call Calculation I
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--------
l RC= Inrush wattu divided by Inrunh current squared-56. 55 di v t dod by O.f355 x 0.855 l
a77.36 ohms I
2CvRaled voltaqn squared divided by Inrush VAR
'
120 h 120 divided by 102.6 j
=
{
- 140.35 ohms j
XC= Square root of 2C squared minus RC squared j
nSqiiare root of 140.'5 x 140.35 minus 77.36 x77.36
= Square root of 14 WG minun 5905 i
f
= Square root of 13713
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=117.1O nhmn l
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f
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ATTACHMENT 1 PAGE 3 Control Circuit Wire Calculation
______________________________
Cable, AP1000278, length from MCC to MOV=2OO feet (Ref.3)
Cable, AP100827C, length from MCC to logic panel 10C617BA
=300 feet (Ref.3)
Actual circuit length is from the MOV limit switch to the logic panel x 2 L=2OO plus 300 x 2 =1000 feet The resistance of the 14 AWG wire is 2.73 ohms per 1000 feet x 1.096=2.99 ohms corrected to 50 degree C.MaFe this 3 ohms.
Control wire circuit resistance RW=3 ohms
,
Inrush Current At Minimum Pickup Voltage l
______ __________________________._______
!
IT=.04 x 120 divided by XC
!
= 100. 0 d i v:' ded by 140.35 l
=.'7102 amperes l
l Voltage Drop Calculatton l
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Transformer
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=
2.36 volts
=
VXT= XT x IT y
O.16 x 0.718'
'
n
= 0.115 volts EM
/
Control Wire
'
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VXC 7" O.7182
'
=
-
2,15 volts
/
Not to scale
=
Coil
/
VRC= RC X IT
,/
77.36 0.7182
'
-
=
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53.6 volts
=
VXC= XC x IT L- + -
_
VXT
,
117.10 x 0.7182 VRT VRW VRC
=
84 1
"
Voltage Vector Diagram The minimum voltago required on the control trannformer secondary EM = Square root et ( VRT + VRW & VRC ) squared +
(VXT+ VXC) squared
=Gquare root of( 2.36+2.15&55.6) squared +
(O.115 + 04.1) squared
=103.47 volta The minimun voltage availablo on t hs= control transformer secondary is =Minimon primary voltage (Ref.1) divided by the trannformer turnu ratio (Ref.2)=413 divided by 3.804=100.56 volts.
Conclusion
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Since the available minumun voltage, 100.56, is greater than that required,103.47 the valve should open during this degraded voltage condition.
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Attachment 2 Service Water Voltage and Cable Pull Tension Calculations I.
Voltage at motor terminals of station service water pump A 1AP502 and at station service water motor control center A MCC 108553 A.
Station Service Water Pump Pump Data:
4KV, 800 hp, 84% efficient, 885 rpm, 16,500 gpm, 150
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ft. head, 111 amperes full load running current, 666 amperes locked rotor (maximum starting current)
Power Cable:
Okonite 4/0, 3 conductor, stranded copper, 1010 ft.
--
long (actual pull length)
Impedance from Okonite Company Technical Bulletin EHB-78, Tables 1.3, 1.4, 1.5 and 3.1 Rdc = 0.0525 ohms per 1000 ft. at 25*C from Table 1.3 Rdc = 0.0525 ohms x 1.25 = 0.0656 ohms at 90 C from Table 1.4 Rac = 0.0656 x 1.05 = 0.0689 ohms from Table 1.5 Paired cable outside dimension = 1.219 inches which provides a cable cradle factor of 1.219 x 1.15 = 1.40 inches.
Using the 1.40 inches cradle factor the cable reactive impedance x = 0.046 ohms from Table 3-1.
r z = sqrt (R2 +x r ) = sqrt (0.06892 + 0.0462) =
0.08352 ohms per 1000 ft. of cable l
z = 0.08352 x 1010 = 0.0843752 ohms for 1010 ft of 1000 cable Voltage Drops:
--
Running V=
1.731Z = 1.73x111x0.08437 = 16 volts Locked Rotor V = 1.731Z = 1.73x666x0.08437 = 96 volts l
- r
Attachment 2
,
Voltage Motor
--
Terminal Nominal 4160 volts - 16 volts drop running = 4144 running Nominal 4160 volts - 96 volts drop starting = 4064 volts starting Degraded Grid (92%) 3827 volts - 16 volts drop running = 3811 volts running 3827 volts - 96 volts drop starting = 3731 volts starting FSAR Section 8.3.1.1.5b. Design Criteria for Electrical Equipment states "The Class 1E motors are specified with accelerating capability at 80% of nominal voltage at their terminals." The voltage drops shown above do not appear excessive for motor starting or running.
B.
Station Service Water Motor Control Center MCC 108553 Motor Control Center Data:
480 volts Full Load Current 150
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amperes.
Locked Rotor current 900 amperes Cable Data:
Two Okonite 500KCM Triplex Copper
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Stranded Cable, Insulation Class B, length 1000 feet.
Impendance data from Okonite Technical Bulletin EHB-78, Tables 1-3, 1-4, 1-5 and 3-1.
Rdc = 0.0222 ohms at 25*C per cable Rdc = 1.25 x 0.0222 = 0.02775 ohms at 90 C Rac = 0.02775 x 1.13 = 0.03136 ohms at 60 cycles Rac = 0.03136 = 0.01568 ohms per phase
Using a spacing of 1.24 inches between conductors and considering magnetic binding for multiconductor cable;
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Attachment 2
!,
!
.X
= 0.03478 per phase per. conductor r
i'
X = 0.01739 ohms per phase.
p
-
Z = sqrt (R2 + X2) = sqrt (0.015682 +
'
O.017392)
Z = 0.03552 ohms
!
!
Voltage Drops: Running V = 1.73IZ = 1.73x150x0.03552 = 9 volts
--
Locked Rotor 1.73x900x0.03552 = 54 volts Voltage at Motor Control Center
--
i Nominal 480 - 9 volts = 471 volts running
!
I Nominal 480 - 54 volts = 426 volts starting voltage
!
]
Degraded Grid 442 - 9 volts = 433 volts running Degraded Grid 442 - 54 volts = 388 volts starting voltage i
FSAR Section 8.3.1.1.5b Design Criteria for Eleccrical Equipment states "The
Class 1E motors are specified with accelerating capability at 80% of nominal j
voltage at their terminals". The voltage drops shown above do not appear i
excess *ve for motor starting or running.
II. Cable Pull Tension Calculations for Service Water Pump Cable AC 10205A from Pump 1Ap502 to Manhole 15 AM000L.
(Refer to Figure 1 for the routing referred to in the calculation)
!
Formula calculations from GE Technical Handbook 8C-1 and from Okontte
!
Technical Bulletin EHB-78 I
Straight line pull tension = Length x cable weight x coefficient of
-
i friction i
Pull tension through an angle = tension up to the angle x angle
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i factor
!
]
Maximum cable tension to prevent exceeding cable sidewall pressure
-
{
limitations when pulling cable around a bend is equal to the radius j
of the bend in feet times the sidewall pressure for this cable which i.
is 500.
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l i
j i
!
!
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C)
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},
Attachment 2
Formula input data: Cable weight = 3 conductors x 1.161 lbs./ft. per conductor = 3.483 lbs./f t. (use 3.51bs/f t.)
Coefficient of friction: 0.5 Angle factors:
1.14 for 15 ; 1.30 for 30*; 1.48 for 45 ; 1.70 for 60*;
1.94 for 75 and 2.20 for 90.
Calculations:
Tension AV to AU = 2 x 3.5 x 0.5 =
3.5*
AV to AT = 2.5 x 2.2 =
7.8 AT to AS = 1 x 3.5 x 0.5 =
9.6 AN to AR = 9.6 x 1.14 =
AR to AQ = 16 x 3.5 x 0.5 =
AV to AQ = 28 + 11 =
44.5 AP to A0 = 2 x 3.5 x 0.5 =
3.5 AV to A0 =
AV to AN = 48 x 1.14 =
AN to AM = 3 x 3.5 x 0.5 =
AL to AK = 12 x 3.5 x 0.5 =
AV to AK = 68 + 21
=
AV to AJ = 89 x 1.14 =
101 AJ to AI = 99 x 3.5 x 0.5 =
173 AV to AI = 173 + 101 =
274 AV to AH = 274 x 1.14 =
312 AH to AE = 85 x 3.5 x 0.5 =
149
,
AV to AE = 312 + 149 =
471 AV to AD = 471 x 1.14 537 AD to AA = 408 x 3.5 x 0.5 = 714 AV to AA = 537 + 714 =
1251 AV to Z = 1251 x 1.48 =
1426 Z to Y = 68 x 3.5 x 0.5 =
119
AV to Y = 1426 + 119 1545
=
AV to X = 1545 x 1.48 =
2287 X to V = 16 x 3.5 x 0.5 =
AV to V = 2287 + 28 =
2315
,
All values are in pounds of pulling tension.
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Attachment 2
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The cable tension from point AV to point V represents the total calculated tension to pull the three single conductor 4/0 service water pump power cables from the pump 1AP502 to the manhole 15 AM000L just outside the emergency diesel generator building.
Cable pulling tension is limited in this pull by cable strength rather than sidewall pressure. The radius of the sharpest cable bend is three feet. Using this as a basis for calculating allowable pulling tension to prevent exceeding sidewall pressure limitations yields the following:
500 pounds x 3 = 1500 pounds per cable x 3 cables = 4500 pounds x 2/3 derating factor for one cable riding another during the pull = 3000 pounds allowed pulling tension. Since the maximum cable tension calculated is 2315 pounds, sidewall pressure is not limiting.
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