ML20195C775
| ML20195C775 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 10/12/1988 |
| From: | Jenison K, Shewmaker R NRC OFFICE OF SPECIAL PROJECTS |
| To: | |
| Shared Package | |
| ML20195C765 | List: |
| References | |
| 50-327-88-29, 50-328-88-29, NUDOCS 8811030372 | |
| Download: ML20195C775 (124) | |
See also: IR 05000327/1988029
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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101 MARIETTA ST
N.W.
ATLANTA GEOnGIA 30323
e....
Report Nos.:
50-327/88-29 and 50-328/88-29
Licensee: Tennessee Valley Authority
6N38 A Lookout Place
1101 Market Street
Chattanooga, TN 37402-2801
Docket Nos.:
50-327 and 50-328
License Nos.:
OPR-77 and DPR-79
Facility Name: Sequoyah Units 1 and 2
Inspection Conducted: June 20 - July 8, 1988
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/c/5' 't
Tear, Leader:
K. M. V n
enidt Resident Inspector O F
Dat'e Signed
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W.E.ShewmaTer,Co/TeamLeader,EB/OSP
Date Signed
Team Members: Design Group Leader
R. E. Shewmaker EB/OSP
Mechanical Systems
S. Traiforos, Consultant
Components & Supports
A. V. DuBouchet, Consultant
Piping
V. P. Ferranini, Consultant,
EA;, Inc.
Electrical Power
F. Pau11tz ROB /OSP
Instrumentation and Control
J. M. Leivo Lonsultant, J. M.
Leivo Associctes
Civil / Structural
S. B. Kim, PSB/GP
Field Inspection Group Leader K. M. Jenison, OSP
Mechanical System Walkdown
K. Poertner, OSP
Mechanical
J. Brady, OSP
Supports
- J. York, OSP
R. Compton, Consultant, Nuclear
Power Consultants
Electrical and I & C
- M. Good, Consultant, Comex, Inc.
Operations / Surveillance
M. Branch OSP
A. Long, OSP
R. Gibbs, RII
0. Loveless, OSP
Welding
- G. Walton, OSP
- Personnei wh
were involved for a portion of the inspection
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Approved by:
.Fxn i n'
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B . OfL tW,' R sT s t a n t D i r e c t.'o r f o r T V A
Date Signed
Technical Prog ams, TVA Projects Division
Office of Sp cial Project
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/dY
JV
Frank R.' McCoy, Assistant Director for
Safe Signed
Inspection Programs, TVA Projects Division,
Office of Special Projects
8811030372 801020
ADOCK 05000327
G
PNU
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SUMMARY
Scope:
This special, announced inspection was conducted for the purpose of a
Safety System Quality Evaluation for the Containment Spray system and
included a review of the TVA Nuclear Performance Plan functional
,
correctivt action areas identified in the Sequoyah Unit 1 and Unit 2
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restart program matrix.
The inspection consisted of an in plant
review in the mechanical, electrical, civil,
structural,
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instrumentation and control disciplines in order to verify that the
CS system as currently constructed and installed is in accordance
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with the licensed design bases, system design specifications,
applicable drawings, system modifications and temporary alterations.
In addition, the operational capability of the CS system was
evaluated by reviewing the system operating
instructions and
procedures, surveillance and testing requirements, corrective and
preventive maintenance activities, human factors, emergency operating
instructions and operator training. The inspection team evaluated,
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on a sampling basis, portions of the TVA Nuclear Performance Plan
functional corrective action areas.
Results:
Based on a review of the Containment Spray System there appears to be
adequate program implementation in the fo11 ewing areas to support
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Unit I startup without further detailed NRC inspection:
- Design Basis Verification Program
- TVA As-Constructed Walkdowns
- Drawing Control Program
- Inplant Configuration Control and System Alignment
- Surveillance Instructions
- Restart Test and Functional performance Program
- Design Change and Modifications Programs
- Cable Routing and Cable Loading
- Equipment Qualification and Seismic Programs
- Preoperational Test Program
- Employe* Concerns
- CAOR Including the QA Audit Process
- PRO and LER
- Instrument Line Slope
- System Operating and Emergency Operating Instructions
- Alternate and Rigorous Support Analysis
- Maintenance (including Trending, Material Control, Preventive
Maintenance and Housekeeping)
- Operability Lookback
- Platform Thermal Growth
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' Cable Tray Supports
- Welding (including Pipe, Structural, and Civil)
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- Operator Training
However, some of these areas will be included in a scheduled
operational readiness inspection.
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Nuclear Performance Plan implementation requiring additional NRC
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review is as follows:
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' Critical Calculations Regeneration Program (as part of
violation 327, 328/88-29-01 response)
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- Appendix R
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- Electrical System SER-Related Issues
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- Functional Test Observation of Pump Flow and Component Logic
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- 10 CFR 50 Appendix J Testing
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Within the areas inspected, the following violations were identified:
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327,328/88-29-01: Incomplete Design Basis Calculation
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(paragraph 1)
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327,328/88-29-02: Structural Walkdown Issues (paragraph 6)
327,328/88-29-03: Maintenance of Safety-Related Electrical
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Equipment (Paragraph 2)
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327,328/88-29-04: Inadequate procedures (paragraph 1).
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The violations were determined to be Sequoyah Unit i related.
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Two Unresolved Items (URIs) were identified:
3?7,328/88-29-03: Containment Spray Check Valve Testing,
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paragraphs 1.h.(2)
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327,328/88-29-06: System Design Deficiencies
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Resolution of items 327,328/88-29-01 through 06 is necessary prior
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to the startup of Unit 1.
These two URis are Sequoyah Unit I startup
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related.
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Deficiencies:
Several deficiencies were
identified within the
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report.
These issues do not constitute programmatic
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issues, violations or deviations and because of their
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low safety significance, are not required to be
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resolved prior to the startup of Unit 1.
These
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deficiencies are being identified for completeness and
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their
resolution
could
improve
overall
plant
efficiency and performance.
Ccemitments:
The licensee committed to the following actions during
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tne exit concucted on July 3, 195S:
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to test the CS pump ficw charac teri sti::s
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including a cultiple coint test prior to the
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startup of Unit 1;
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to test the ESF pump valve logic perforniance as
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demonstrated in surveillance instruction SI 68
prior to the startup of Unit 1;
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support NRC review of a new TS indicating _ the
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143 psid required to insure 4750 gpm flow from CS
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pumps prior to the stirtup of Unit 1.
Verify
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this parameter prior to the startup of Unit 1
,
determine what the actual values are for heat
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exchanger differential pressure in order to
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resolve restart test functions72-003 and 72-018
prior to the startup of Unit 1; and
include in the next scheduled update of the CS
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training lesson plans information on the manual
swapover of the CS systen and the interlocks
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associated with the system.
This issue was
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determined not to be startup related,
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NOTE:
Acronyms and initialisms used in this report are listed in the last
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paragraph.
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REPORT DETAILS
1.
Mechanical Inspection
The design aspectf of the inspection evaluated the system and components
against applicable standards, the references cited and listed in this
report, and the SYSTERS/ design basis reports for the Unit 1 CS system.
Inspectors performed a walkdown of portions of the Unit 1 CS system and
performed a comparison between the as-constructed drawings and the actual
installed system. The walkdown was conducted on system piping, valves,
and components inside containment, the annulus, and the auxiliary
building,
Additional information for the walkdown was drawn from
isometric details, design documents, and vendor data packages,
a.
Conformance of the Containment Spray System With the As-Constructed
Drawings
A walkdown of portions of the CS system was performed in the
auxiliary building, annulus, and containment comparing the installed
system with drawings 47W437, sheets 1-6, and 47W312, sheet 1.
The
following system attributes were considered during the walkdown and
drawing review:
Pipe sizing and class
Reducers
Flanges / fittings / spool pieces
Location of vents, drains, thermowells
!sometric routing
Unidentified / undocumented valves, pipes, instrumentation
Interfersnces
Support / restraint location
Valve flow directions
The inspectors identified no major discrepancies during the system
walkdown.
The discrepancies observed by the inspectors had
previously been identified by the licensee prior to the inspectian as
port of the OSLA 107 walkdown program, implemented as part of the
Itcensee's SSQE inspection preparation, and did not affert system
operability,
b.
Associated System Interfaces
A verification was performed of the following associated system
interfaces with the CS system, both on the drawings and on the
installed system:
RHR HX 1A & IB to CS (drawing 47W311. sheet 1)
ERCW to CS HX A & B (drawing 47WT*5)
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Boric Acid Blender to CS (drawing 47W309, sheet 2)
CS Pumps IA & IB suction relief valve discharge (drawing 47WS11,
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sheet 1)
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CS Trains 1A snd IB suction to containment sump (drawing 47W811,
1
sheet 1)
The inspectors noted that several skid mounted valves supplying
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component cooling water for cooling of the CS pump mechanical seal
and the oil bearing cooler were unlabeled and not on the flow
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drawings.
TVA had previously comitted in their response to NRC
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Inspection Report 327,328/87-52 to add skid mounted valves to the SI
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and SOI checklists prior to Unit I startup.
These valves were
identified on SOI checklists 72.1A-1 and 72.1A-2 for CS Pumps IA and
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18, respectively, with the valve numbers listed as N/A. During NRC
system alignment inspection 327,328/87-66, TVA had labeled all Unit 2
skid mounted valves with tags having descriptions matching those in
the SOI checklists. This was necessary to ensure that the operators
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using the checklists would position the proper unnumbered skid valve.
Since this had not yet been accomplished for Unit 1, the inspectors
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obtained a commitment from TVA to label all Unit 1 skid valves with
descriptive tags prior to establishing configuration control for
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Unit 1 restart.
This comitment is being tracked under Violation
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327,328/87-52-01 corrective action.
c.
$hield Building Penetrations
The inspector reviewed the following Unit I
mechanical penetration seals:
Penetration 1X-48 B at Elevation 729'
Fenetration 1X-49 8 at Elevation 729'
Penetration IX-48 8 is a 16 inch pipe sleeve which accommodates the
12 inch line to CS beader 1-B.
Penetration 1K-49 8 is a 12 inch pipe
sleeve which accoraodates the 8 inch line to RHR spray header 1-B.
The mechanical seal penetrations are shown schematically on TVA
drawing No.
Flow Diagram / Containment Spray System,
Revision Y, dated April 11, 1988.
Penetration 1X-48 B is shown on
TVA drawing No. 47W437-5, Mechanical Contairrtent Spray System Piping,
Revision F, dated October 21, 1985. penet,atton 1X-49 B is shown on
TVA drawing No. 47W437-4, Mechanical Containment Spray System Piping.
Revision 0, dated April 1,1980.
At the time of the inspection, these penetrattens were being r0dified
in accordance with the boot seal detail shcwn on sheet 99 of ECN
L73S2B.
(For penetration seals above elevation 724' which is the
flooding level).
The seal type was designated as Category F.
Category F peretration seals tre defined as seals v 'th thermal
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movements which exceed 1/4 inch, and with installed configurations
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which allow for the degradation of the fire and pressure barriers.
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ECN L7382 require s re-booting these penetrations before Unit 1
restart with fire and pressure rated boots which can accommodate
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maximum thermal and Safe Shutdown Earthquake (SSE) pipe movenent.
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For this modified mechanical seal penetration detail, the inspector
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evaluated the design basis loads, and the qualification of the
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penetration materials and boot assembly to the design basis loads.
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The penetration asse-blies are subject to the following design basis
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loads:
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Fire
Radiation
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Environxental temperature and pressure
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Pipe fluid operating temperature
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Piping movements due to thermal and SSE
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TVA was able to provide the inspector with copies of environmental
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drawings and test reports to confirm that the seal assembly is
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qualified to the above design basis loads, with the following
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exception.
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TVA did not have readily retrievable docume.ntation to confirm that
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the penetration seal assembly materials were qualified to the total
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40 year integrated dose of 10' rads specified on TVA drawing
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No. 47E235-51, Revision B, dated October 18, 1934, or to the 400'F
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pipe fluid design temperature specified in the table on sheet 95 of
ECN L73328.
TVA asked Insulation Consultants and Management
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'dryices,
Inc.,
to
provide
the
appropriate
qualification
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documentation, and was able to provide the inspector with a
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comparable document which ICMS prepared for the same penetration seal
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naterials used at another plant.
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To show that penetration seal asse-blies IX-48 8 and IX-49 8 are
qualified to the negatise (0.5 inch w a t,e r) annular pressure
differential and the transient tornadic differential prec ure drop of
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3 psi specified on TVA drawing 47E235-31, TVA pre 'ded the team with
ICMS report No. HT-M05-34
Hydrostatic Test for Mechanical Boot
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Seals, dated May 22, 1486.
The ICMS report surrartres a 2-hour
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hyd ro s t a t.i c test conducted for a 2-inch pipe /IO-inch sleeve to a
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maximum hydrostatic pressure of 28 psi, to confirm the ability of the
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mechanical penetration seal assemblies that are installed below
elevation 724 feet to withstand the design basis flood. This test
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condition would envelope the design pressure environment for
penetrations IX-48 C and 1X-49 B.
The TVA technical staff have
indicated that penetration seal asserblies installed belew ficod
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level are subiect to a maximum dif ferential hycrostatic pressure of
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about IS psi,
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It was noted that TVA had not considered tht axial thrust induced in
the pipe due to the dif ferential hydrostatic pressure on the seal
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which must be restrained by the pipe supports adjacent to the
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penetration. For penetrations IX-45 B and IX-49 8 the loads would be
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small, but for penetrations subjected to 18 PSI the loads are higher.
As an example, a penetration assembly which consists of an 8-inch
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pipe and a 12-inch sleeve appears capable of generating a 4-5 K!P
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thrust due to a hydrostatic pressure of 18 psi. During the course of
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the review it was found for penetrations with significant dP across
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them that TVA did not account for the additional axial load imparted
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to the pipe by t.he Icaded area of the seal. This issue is designated
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URI 327,328/88-29-06, (Example a). Adequate resolution for the above
URI will include Engineering Assurance review and approval of the
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design documentation and requires resolution prior to the startup of
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Sequoyah Unit 1.
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YVA has indicated that Construction Technology Laboratories Report,
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Fire and Hose-Stream Tests for Penetration Seal Systems (hMP2-PSS6),
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dated March 1986 qualifies the penetration assembly to the 3-hour
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fire barrier requirement imposed by 10 CFR 50, Appendix R.
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In addition, the peneteation assembly boot material has been
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proportioned to accomodate the radial and axial pipe movements due
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to thermal and SSE movecents which are listed on sheet 95 of ECW
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L73328.
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The inspector's conclusion is that shield building penetrations
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IV.-48 B and IX-49 8 meet the design bases.
Documentation was
initially not available within TVA to justify that the penetrations
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were qualified to meet the radiation and temperature design bases.
Documentation was generated for the inspectors and appeared to be
adequate.
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d.
System Pressure Boundaries
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Section 2.1.6 a. Systems Integrity for High Radioactivity, of NUREG
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057S, TMI-2 Lessons Learned Task Force Status Report and $hort-Tern
Reco.nendations, dated July 1979, requires that licensees implement a
program to reduce leakage from systems outside containment that
includes: 1) Iriediate leak reduction by implementing all practical
leak reduction measures for all systems that could carry radioactive
fluid outside of containrent ard r.easuring actual leakage rates with
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system in operation and reporting them to the NRC; and 2) Continuirg
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leak reduction by establishirg and impletenting a program of
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preventive maintenance to reduce leakage to as-low-as-practical
levels. This program shall include periedic integrated leak tests at
a frequency not to esteed refueling cycle intervals,
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To assess TVA's implementation of thesa NUREG roquirements, the
inspector reviewed the design changes and surveillance criteria which
TVA prepared and implemented for tne CS system.
TVA letter L51 791031913 dated November 1, 1979, established the
initial guidelines which the TVA technical staff used to
alement
the NUREG requirements.
ECN No. 2586 installed welded nipples and threaded caps on a number
of drains, vents and test valves in the CS system and other systems.
TVA made these design changes by reviewing the as-designed flow
diagrams and identifying drains and vent lines which did not have a
secondary boundary.
For the CS system, the design changes prepared
under ECN 2386 were incorporated into the following as-designed TVA
drawings:
TVA drawing No. 47W812-1, Flow Diagram / Containment Spray System,
Rev. 9, dated September 18, 1979.
The following TVA mechanical CS system piping drawings:
47W437-1, Rev. 17, dated September 12, 1979
47W437-2, Rev. 14, dated September 12, 1979
47W437-5, Rev. 10, dated September 12, 1979
47W437-6, Rev. 11. dated September 12, 1979
Field Change Request SQ-FCR-001 was prepared on February 23, 1980 to
revise Rev. 9 of the fic v diagram when a subsequent review of the
drawing indicated that not all of the design changes had originally
been incorporated into the drawing.
The inspector confirmed that the comparable as-constructed flow
diagram and piping physicals indicated the addition of these nipples
and caps.
On April 2,
1980, TVA provided the NRC with the surveillance
procedures to be used to monitor system leakage (A27 800402 008).
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Surveillance instruction procedure SI-632.0, Auxiliary Building
Combined Systems External Leakage, Rev. O, dated Jani'ary 17, 1980,
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documents the combined extarnal leakage to the auxiliary building
which is monitored by the separate implementation of system-specific
surveillance procedures
such as SI-632.1, Auxiliary Building
Containment Spray System External Leakage, Rev. O, dated January 17,
1980.
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TVA provided the NRC with the results of the leakage tests for the
Unit I systems monitored outside of containment. Supplement No. S to
the SER dated May 1981 indicates that the results of the tests which
TVA submitted to the NRC for Unit I were sati(factory.
The
inspectors concluded that TVA's actions to implement NUREG 0578
Section 2.1.6.a for the CS system were satisfactory.
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e.
System Alignment
The inspectors reviewed S0I checklists 72.1A-1 and 72.1B-1 for
adequacy and conformance with the system drawing.
The inspectors
verified that the system was either aligned per the 50I checklists or
the valve position was documented in the configuration log. During
the walkdown the inspectors noted that valves 72-515, 522 and 524,
which are reach rod operated valves, had hold order tags attached
indicating that the valves were open when the remote position
indicators showed that the valves were shut. The inspectors verified
locally that the valves were actually open. Through discussiuns with
the licensee it was determin?d that the problem with the reach rod
indication had previously been identified by the licensee as part of
an ongoing effort to identify and correct problems with reach rod
operated valves throughout the plant. The licensee currently
requires operators to verify valve position locally on reach rod
operated valves as well as through remote indication,
f.
Component Marking and Accessibility
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A verification was performed to ensure that the equipment
identification, tagging, and nomenclature used in the CS system was
consistent with drawings and procedures. TVA has a tagging / labeling
program in progress.
Components necessary for the operation of the
system were determined to be accessible and adequately identified.
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Minor discrepancies noted by the inspectors had been previously
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identified in th- TVA program,
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Material Traceability
The inspectors verified that the name plate data for both containment
spray heat exchangers, both CS pumps, both CS pump motors, and pump
suction relief valve 1-72-513 were in accordance with vendor data
packages and design docunients. Th? inspectors verified that the size
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imprint on the recently modified orifice plate in the header piping
to the spray nozzles agreed with the size specified on ECN L7381A and
work plan 73S1-01.
The ECN and work plan resized the orifice and
replaced the orifice ta a full flow pipe size.
h.
Snrveillance Requirements,
Emergency Operating Procedures,
and
Functional Testing
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(1) The following equipment surveillances and surveillance records
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were verified to support the requirements of the TS as noted:
- SI-34, Containment Spray System Valve position Verification
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$1-37.1, Containment Spray Pump 1A-A Test, Unit 1
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- SI-37.2, Containment Spray Pump 1B-8 Test, Unit 1
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di-158.1, Containment Isolation Valve Leak Rate Test, Unit 1
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SI-166.39, Disassembly and Inspection of SIS /RHR/CS/UHI Check
Valves During Refueling Outages, Unit 1
SI-186, Locked Valve Position Verification Per NRC Commitment,
Containment Inspection, Unit 0,
Unit 1 (Note:
Unit 0 is a
designation for a common system)
- SI-267.72.1, Functional Pressure Test of Containment Spray
System, Unit 1
IMI-99 RT-16.6, Response Time Test Procedure of Containment
Pressure Channels I and II
IMI-99RT-643B, Response Time Testing Engineered Safety Feature
Actuation Slave Relay K643
SI-166.1, Full Stroking of Category
"A"
and "B" Valves During
Operation
51-166.3, Full Stroking of Category
"A"
and "B" Valves During
Cold Shutdown
SI-166.15
Containment Spray Check Valve Test Performed During
Operation
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SI-251.1, Channel Calibration of Class 1E Motor Operated Valve
Overload Relay Heaters
- SI-68, functional Test of Containment Spray Pumps a.1d Associated
Valves
SI '38, Containment Spray - Spray .ozzle Test
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SI-2, Shift Log
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- The inspector field verified the appropriateness of these
procedures.
Through a mixture of field inspection and review of the last
test performance, the inspectors determi ne:1 that the tests
listed above met the following surveillance reauirements:
4.6.2.1.6
4.6.2.a.c.1
4.6.2.1.c.2
4.6.2.1.d
4.3.2.1.1.d.2a (In Part)
4.3.2.1.3 Table 3.3-5 (In Part)
4.3.2.1.1.A.2.c
4.6.1.2.d (In Part)
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The inspector reviewed SI-138, Containment Spray - Spray Nozzle
Testing.
Step 6.2.3 in the procedure requires the operator to:
Close valve 72-545 upon completion of CSH
"A"
nozzle
verification.
If testing of Train
"B"
is not to be
performed immediately following Train "A", shut down the
hot air compressor to avoid neating/ pressurizing the
piping.
Step 6.2.4 of SI-138 then states:
Open valve 72-546 and start hot-air compressor (if
necessary).
This will allow air flow through CSH "B".
Appendix A of SI-138 gives the following recommindations for Air
Compressor Rental:
Supplier: Atlas Copco Comtec, Inc.
2346 Mellon Ct.
Decatur, GA 30035
Description:
Compressor, Air, 100*. Oil-free Air, @ 300
degree F. 1500 CFM @ 125 psig max., with
relief valve set @ 100 psi.
Lead Time:
5-7 weeks
Previous Requisition:
453185
CAUTION:
If compressor furnished does not have relief
,
capability, appropriate measures should be taken
to ensure relief capability is provided or steps
shall
be
taken
to
prevent
potential
overpressurization of piping by rearrangement of
procedure steps using temporary change forms per
AI-4.
I
The closure of Valve 72-545 in step 6.2.3 isolated the CS system
piping and applies full compressor air pressure to a section of
100 psi rated pipe. Therefore, until the opening of '2-546 in
,
step 6.2.4, the CS piping is relying on the ccmpe
ar relief
u
valve for protection.
If the compressor does not have relief
'
capability, the piping will overpressurize.
It is irprudent at
,
best to close 72-545 until 72-546 is open in either case.
'
Revision 7, the current revision to SI-138, requires the nozzles
to be inspected by use of an infrared camera to verify that each
of the 312 nozzles are open and pass air freely.
Results for
all unobstructed nozzles are documented by checking one blanh.
The procedures also states, "If desired, photos may be made for
future reference."
{
.
_
._
'
.
9
If one or more nozzles are nonfunctional, the number of nonfunc-
tional nozzles are recorded and a sketch is made of the location
of each. Verification is made by the Test Director and a second
party.
The technique used to conduct the surveillance requires the test
director to observe the nozzles for the lack of an infrared
signal.
Previous revisions of the procedure required each
nozzle to be identified and checked off that a positive infrared
signal exists.
Thus the previous revisions of SI-138 required the director to
look for a positive signal as opposed to the lack thereof. The
previous revisions also created more auditable records of the
inspections by requiring the test director to document that each
nozzle flowed freely.
TS Surveillance Requirement 4.6.2.1.1,
requires that each CS spray train shall be demonstrated OPERABLE
by verifying each spray nozzle is unobstructed.
The verifica-
tion for each spray nozzle should be documented.
Revision 7 of SI-138 has never been performed.
Therefora, all
previous tests have
included appropriate procedures and
documentation.
This SI should be revised to include more
appropriate documentation
prior to
its
next
required
performance.
During the review of 51-274.900, Engineered Safety Feature
Response-Time Verification, the inspector became aware of a
potential problem with the response timing of the Containment
Spray actuation system caused by inaccuracies in the Agastat
relay. The Agastat relay is a 0-300 second timing relay used in
the sequencing of EDG loads. The vendor stated accuracy of the
relay is plus or minus 5'a for a specific rep 9atability.
The
licensee stated that the actual accuracy over a test range was
about plus or minus 10'e.
Even though the relay is capable of
operatiag over an entire range, it is operated in the CS system
only at a specific point. Therefore, the inspector requested
the licensee to field verify the accuracy of the relay for its
specific application in the Containment Spray Systen.
In response to this request, on June 29, 1988, the licensee
performed a bench test of one of the Agastat relays for
installation in Unit 1.
The relay was calibrated for 180
seconds.
The relay was independently measured and its
repeatability determined to be accurate within 1?; which was
considered acceptable.
(2) The inspector reviewed the following Emergency Procedures for
the Conttinment Spray System:
.
.
10
E-0, Reactor Trip or Safety Injection
E-1, Loss of Reactor or Secondary Coolant
ES-1.2, Transfer to RHR Containment Spray
ES-1.2 required operators to verify the CS pump .uction to the
containment sump at an RWST. level of less than or equal to 8%
indicated level.
The procedure recommended that the operator
verify ECCS lineup prior to this swap, if time allowed.
The
safety analysis for containment pressure control assumes that
swapover occurs before ice melt, therefore the time dependance
of this swapover was questioned. The inspector determined that
in all cases the swapover should occur prior to complete ice
melt.
i
No violations or deviations were identified.
(3) The inspector questioned the adequacy of the testing of etives
72-547 and 72-548 in that they are not type "C"
leak rate tisted
l
per 10 CFR 50 Appendix J.
The adequacy of the containmsqt
isolation design with respect to GDC-56 was reviewed by .he
,
!
staff during the review of the nuclear performance plan inc is
!
documented in the May 1988 SER.
The inspector will revitw the
'
leak rate testing of these valves durir.g future resid!nt
inspection activities.
This item is
identified as URI
327,328/88-29-05.
,
i
I
(4) A sample of the records for the tvilowing valves were examiced
to assure that inservice testing and MOV thermal overload
protection requirements were met.
These requirements are
contained in the FSAR (6.2 and 9.2), TS (4.8.3.2,
4.0.5,
3.6.2.1),
10 CFR 50 Appendix A (General Design Criteria -
,
l
Section V) and ASME Section XI (IWV).
Valves:
1-FCV-72-2, 13, 20, 21, 22, 23, 34A, 39, 40, 41
1-72-506, 507, 547, 548, 555, and 556
In an SER issued in May 198S (NUREG 1232, Volume 2) the NRC
stated, "Since certain penetrations, including the containment
spray and RHR spray, are part of the systems required to operate
following an accident, it is imprudent to follow the explicit
requirements of GDC 56 red automatically isolate or lock closed
the isolation valves.
In those instances where post-accident
operation is required, remote manual valves are acceptable for
.
'
meeting the GDC as described by SRP section 6.2.4 and the ANSI
standard.
For the containment spray and RHR spray line
penetrations, TVA has identified additional outboard valves that
have remote manual closure capability as containment isolation
valves.
The designation of those valves as containment
isolation valves brings the isolation design
for these
penetrations into compliance with the staff guidelines for
meeting GDC 56 contained in the SRP."
- - - ,
..
,
11
The system is provided with a check valve inside containment
(1-FCV-72-547 and 1-FCV-72-548) and a "remote manual" isolation
valve outside containment (1-FCV-72-2 and 1-FCV-72-39) for each
spray header.
The licensee requested and was granted relief in April 1985
(SER) from exercising valves 72-547 and 72-548 (containment
spray header check valves) in accordance with the requirements
of ASME Section XI, contingent upon providing a method for
verifying full riow capability of the valves.
Testing these
valves with water would jeluge containment, causing potentially
significant damage and cleanup requirements to equipment and
structures. The licensee proposed testing these valves with air
during the spray header nozzle test required by TS 4.6.2.1 at
least once every five years.
The NRC position stated that this
method could not ensure fall stroking of the CVs.
As an
alternate to full flow testing, one of these four CVs will be
disassembled each refueling outage on a rotating basis.
If any
valve is found to be inoperable and the cause determined to be
potentially generic, the other valves must also be disassembled
and inspected before being declared operable.
The disassembly of these valves is performed under SI-166.39,
Disassembly and Inspection of SIRHR/CS/UHI Check Valves During
Refueling Outages, Unit 1.
The inspector reviewed documentation
on the last performance of this SI dated May 1,1986 and found
it to be acceptable.51-158.1, Containment Isolation Valve Leak Rate Test, verifies
that valves 1-FCV-72-2 and 1-FCV-72-39 have acceptable leakage
rates for containment isolation. The latest performance of this
SI dated September 9,
1985, was reviewed and found to be
acceptable.
The inspector reviewed the status of thermal overload protection
devices installed in the containment spray system MOV motor
starters. All thermal overload protection devices were removed
or bypassed with the exception of those in starters associated
with valves 1-FCV-72-20,21,22,23,40 and 41.
These devices are
tested in accordance with 51-251.1, Channel Calibration of
Class 1E Motor Operated Valve Overload Relay Heaters.
This SI
implements the requirements of SR 4.8.3.2.
The
inspector reviewed documentation of the most recent
performances of SI-251.1 on valves 1-FCV-72-20 and 1-FCV-72-21
and found these tests to be acceptable.
The inspector also randomly selected valves and verified that
they were included in the Section XI program and currently
tested per that program.
W
- - -
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12
(5) The following design basis required functions were reviewed to
determine if surveillance or other functional testing adequately
documents the ability of the CS system to meet the design
function.
The operability of the CS pump protective circuit was evaluated.
This circuit protects the pump by allowing pump discharge to be
circulated back to the pump intake if flow in the discharge line
drops below that required for pump protection (1650 gal / min) as
measured by flow elements FE-72-34 or 13, or if 'spon starting
flow is not achieved in the spray header within a preset time
interval (10 seconds). It was determined that construction and
calibration criteria were established. This system capability
was tested in TVA-21B and again in WP 12358 following
modifications.
A review for the existence of an interlock between FCV-72-23 and
22 for CS train "A" and FCV-72-20 and 21 for CS train
"B"
was
performed.
The function of this interlock is to prevent the CS
pump from taking suction from the RWST and the containment sump
at the same time.
This item is discussed further in
Section 1.(j) of this report.
Automatic activation of the CS system is based on activation of
two out of four of the containment hi/hi pressure switches. The
inspectors requested to observe a surveillance which would
demonstrate this system function.
Due to tne CS system being
drained for maintenance, these sis were not performed during the
inspection period.
It will be necessary for two testing func-
tions to be observed prior to the startup of Unit 1:
Pump flow characteristics including a multiple point test
as well as the performance of the current revision of
SI 37.1.
ESF pump / valve logic performance as demonstrated in SI-68.
i.
ASME Code Section XI Testing
The inspector evaluated the implementation of the Section XI testing
program for the IA-A CS pump for consistency with TS requiremenus and
design requirements.
The current TS SR 4.6.2.1.1.b requires that the licensee verify that,
"each containment spray train shall be demonstrated OPERABLE by
verifying, that on recirculation flow, each pump develops a discharge
pressure of greater than or equal to 140 psig when tested pursuant to
TS 4.0.5."
_
'
.
.
13
Baseline flowrate data for the Unit 1 containment spray pumps will be
established during future performances of S1-37.1 and SI-37.2. These
have not been established in the past because it is not a regulatory
requirement and measurement of pump flowrate is not required by the
1974 edition through the summer of 1975 addenda to the ASME Boller &
Pressure Vessel Code Section hI (Code of record for Sequoyah).
Previous tests of the pumps met the allowable ranges of inservice
test quantities identified in Section XI and during baseline tests.
These tests also verified the letter of the TS, However, these tests
never verified that 4750 gpm would be supplied to the spray no:zles
during an accident as assumed in the design basis calculations. This
flowrate is required for the system to meet its design basis.
The licensee has submitted a TS change request to require that the
pumps be tested to deliver 4750 gpm at a dP of 143 psid.
Following the performance of the current revision of SI-37.1 the
pisnt will be ready for resta. t with respect to Section XI and
surveillance testing for the 1A-A CS pump.
10 CFR 50.55a(g) requires inservice testing of pumps and valves in
accordance with ASME Section XI to verify Goerational Readiness.
ASME Section XI, IWV-2100 defines relief valves as category C valves
and ASME Section XI, IWV-3511 requires category C valves to be tested
on at least a five year interval in accordance with Table IWV-3510.1.
Contrary to the above, the licensee failed to include ASME Section XI
requirements for testing of the containment spray system suction
relief valves (72-512 and 72-513) in the instructions for inservice
testing which are provided in Section 6.8 of the SeQv-"ah Final
Safety Analysis Report.
These valves were however,
t.
ed in other
surveillances and were maintained operable.
This is violation
327,328/88-29-04 example 2.
J.
Functional Design Parameters
The following sample cf functional design parameters was reviewed
during the inspection.
(1) The design parameters of the CS piping are shown on drawing
47W312-1, Rev. 16 (Reference 1,
report section
1.L).
Tne
inspector reviewed the calculations which determine these design
parameters for the piping. These calculations are References 2,
3, 4 and 5.
Reference ^ *as prepared on May 27, 1988. References 3, 4 and 5
were prer red in June 1988.
.
.
14
The inspector reviewed these references.
The review revealed
that several pressure and temperature (design conditions)
boundaries as shown in Reference 1 were incorrect.
The results
of the review are as fellows:
The calculation of Reference 2 was rerformed as part of ECN
L6673, dated June 17, 1986.
It changes the design
conditions of the lines from the flow restrictor downstream
of RWST to valves FCV-72-21 and FCV 72-22 to 40 psi and 150
Degrees F.
Reference 1 depicts the old conditions which
were 100 psi and 100 Degrees F.
The parameters 42 psi and
150* degree F were added to the design conditions in design
condition No. 5 of Reference 2.
Reference
3,
addresses the pump suction, discharge,
miniflow and test lines.
This calculation, completed
during the inspection, identified that the design condition
boundaries shown at valves 72-503 and 72-504 are incorrect
because the pressure just downstream of these valves could
be 170 psig, which is higher than the current 100 psig
rating.
The design condition boundary will be moved to
valve 72-502.
Reference 4, addresses the containment spray ring headers
and lines downstream of the isolation valves FCV-72-2 and
FCV-72-39.
This calculation identified that the design
condition boundary should be moved from the outlet of these
valves to the iniet side of the containment penetration
since the pressure at the outlets of these valves could be
127 psig, higher than the current 100 psig rating.
Reference 5, addresses the RHR spray ring headers and lines
downstream of isolation valves FCV-72-40 and FCV-72-41.
This header and piping are considered part of the
Containment Spray system. The calculation identified that
'
I
the design condition boundary should be moved from the
inlet side of these valves to the inlet side of the
penetration since the pressure at the penetration will not
i
i
exceed
100 psi.
By
implementing
the change,
the
penetration will be at design conditions which are in
agreement with its nameplate rating (100 psig).
CAQR SQP 880387, Revision 0, was written on June 24, 1933,
to address the discrepancy between Ref. 1 (Fig. 6.2.2-2 of
the Sequoyah FSAR which currently shows R12) and the
nameplate rating of the pressure of the fluted heads for
containment p:netrations X49A and X49B.
The 100 psi
nameplate rating was found as a result of a system walkdown
performed by TVA on December 13, 1987.
The results of
Reference 5 indicate that the 220 psi rating is not
required as the design pressure of the steel containment
_ _ - _ _ _ _ _ _ _ _ _ _ _
'
.
15
penetration and that the maximum sustained operating
pressure per ANSI B31.1 is below 100 psi.
Therefore, this is considered a documentation problem and
not a component deficiency.
This CAQR is applicable to
both Units 1 and
2.
Due to the above mentioned
discrepancies,
the following corrective actions were
recommended in the CAQR:
Perform calculations to support desion parameters on
drawings 47WS12-1, R16 (Reference 1).
Resolve any discrepancies identified between values
listed on drawings and results of the calculation.
Reevaluate adequacy of components, revise drawings,
determine impact on pipe analysis,
and verify
hydrotest records as necessary if design parameters on
the flow diagram cannot be supported by calculations.
Determine if other design calculations for pressure
and temperature are missing on other systems in order
to establish and resolve the full extent of problem.
An ECN/DCN will be prepared by TVA to update the design
documentation to reflect the changes addressed above and will be
completed prior to Unit I restart.
The failure to have pressure and temperature calculatier.s to
define pressures and temperatures at various points ia the
Containment Spray System is considered to be a violation of
10 CFR 50, Appendix B, Criterion III, Design Control, and is
identified
as
violation
327,328/88-29-01,
Design
Basis
Calculations.
The missing pressure and temperature calculations were re -
generated during the inspection. As a result of the new calru-
lations, several components and associated oiping are in a
higner pressure rating.
TVA is currently assessing the ef fect
of these changes. As of June 27, 1938, no hardware had been
identified as affected by the resulting shift in tho location of
pressure
boundaries.
This
issue is designated as URI
327,328/88-29-06 Example b. , and requires resolution prior to
the startup of Sequoyah Unit 1.
Adequate resolution for the
above URI shall inclede an Engineering Assurance review of the
design basis information related to this issue.
flu a flow acceleration or de-
i
As part of assessing whether
celeration (water hammer) in tne CS system has been considered
by TVA in terms of its resulting dynamic loading of the system,
the inspector reviewed a study entitled, Evaluation of Fluid
,
,
~
'
..
l
16
Dynamic loads on the Containment Spray System, dated May 26,
1987.
This study is incorporated as Appendix A to problem
Number 0600104-01-02 Containment Spray System, Units 1 and 2,
Sequoyah Nuclear Plant. The lack of existence in 1987 of such a
calculation and its subsequent generation by TVA was addressed
in Inspection Report 50-327, 328/87-28.
The following are the results of this calculation review:
(a) The methodology used in the calculation is simplistic with
potentially inaccurate results.
(b) The derivation of maximum force and rise time formula on
page 7 of Appendix A is not given; however, based on
similar studies, it appears that the magnitude of the force
is reasonable.
(c) The derivation of the maximum load on the ring header is
not given.
It is stated that the maximum load occurs at
the time that one-half the header is filled. The inspector
considers that both the magnitude and time of occurrence
are incorrect. Similar studies have shown that the maximum
load on the header could be one order of magnitude higher
than the one calculated in Appendix A.
Moreover, the time
<
of each occurrence is the time at which the two water slugs
which fill the tne header in a symmetric fashion from the
two opposite ends meet each other. A comparison of the
support loads due to water hammer versus other loads is
given in Appandix A.
Although accurately calculated water
!
l.ommer loads may still be substantially smaller than other
loads on the syster, there may be support locations where
such loads are not negligible. Appendix A, indicates that
the CS System is scheduled for reanalysis following Unit 2
restart.
The inspectors consider that a more accurate
<
I
methodology for calculating water hammer loads should be
used.
This issue is designated URI 327,328/88-29-06
Example c and requires resolution prior to the startup of
Seqtoyah Unit 1.
Adequate resolution for the above URI
shall include an Engineering Assurance review of the design
basis informatien related to this issue.
(2) A review of sample piping runs was performed. Two pips stress
analysis problems, 0600104-01-02 and N2-72-1A & 2A, were
selected for review using the piping detailed on physical
drawings 47W812, Sheet 1 and 47W437 Sheets 1-6.
Also included
in the review were all outstanding deficiencies previously
'
identified by TVA.
These analysis problems were reviewed
considering the walkdown attributes listed in Section 1.a in
addition to the design and stress analysis items listad below
which were verified.
_______
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.
17
The stress isometric of record agreed with the current
piping physical drawings.
All pipe supports were identified on the stress isometric
e
including type and direction.
Equipment nozzle loadings were properly considered.
Results of the latr.st system walkdown were considered and
properly accounted for in the analysis.
All anchor and restraint point displacements due to thermal
and seismic effects were properly considered.
Design input parameters such as temperature, pressure, pipe
material and size, seismic anchor movements and response
spectra were properly considered.
Proper modeling considerations such as valve motor
operator, system interconnection and o,erlap, elbow and tee
type, flanges, concentrated masses, e'.c., were made.
All pertinent loading conditions were considered, including
thermal deadweight, seismic, fluid dynamic, and steel
containment vessel thermal displacement.
Pipe stresses were within the specified allowables for all
conditions analyzed.
Containment spray pipe stress problems N2-72-1A & -2A, Rev. 5,
i
dated May 18, 1988, contained the analysis for pipit.g routed
from the containment spray pumps IA-A and 18-8 discharge nozzles
to the containment spray htat exchangers 18 and 1A intake
nozzles.
The system was divided into two problems N2-72-1A and
N2-72-2A as shown on isometric 47K437-50. Problems N2-72-1A and
l
N2-72-2A are not connected and do not overlap with any other
piping system.
I
During the review of the above problems the following items were
discovered.
Page "a"
of the sumary of piping analysis
N2-72-1A, 2A indicates that Rev. 5 voided page 12B; however, the
page was not indicated as voidea.
TVA confirmed that page 128
belongs in the analysis of record package and will modify page
"a"
of the analysis accordingly.
Another area which requires
attention is that the piping analysis isometric of record for
Unit 1 identifies pipe supracts using Unit 2 support identifiers
resulting in confusion whv
trying to review piping analyses.
TVA currently has a prograi which should, in the near future,
update the piping isometrics to reflect both the Unit 1 support
.
identifiers and also include the current as-built system
geometry and support locations.
'
.
18
.
These issues were identified as deficiencies and provided for
licensee information.
.
On page A.18 of the calculation a value of 141/2 inches was
measured in the field as the distance from the pipe center line
to the weld location for a 12 inch long radius elbow.
Since
this elbow standard dimension should be 18 inches, either the
field measurement was incorrect or the elbow was modified. TVA
should review this discrepancy and take appropriate action.
T h', s issue is designated URI 327,328/88-29-06 Example d.,
and
requires resolution prior to the startup of Sequoyah Unit 1.
Adequate resolut. ion for the above URI shall
include an
Engineering Assurance review of the design basis information
related to this issue.
,
Ouring the review of the pipe stress analysis walkdown
evaluation shown on page A.17 of the calculation an apparent
anomaly in the reported as-built piping lengths was discovered.
The walkdown results reported a total deviation of 5 feet, 5 and
1/4 inches between the as-analyzed and as-built dimensions of a
length of pipe run from node point 211 to the control point of
the elbow at point 215 as shown on drawing 47K437-50, R4.
A
field verification of this length performed by the NRC
determined that no deviation exists.
TVA has used these
erroneous lengths in calculations to justify the adequacy of the
as-built piping system and supports.
TVA should review the
,
walkdorin data for this system and modify the calculations as
required.
This issue was identified as a deficiency and
provided for licensee information.
Containment spray pipe stress problem 0600:04-01-02, Rev. 14,
dated May 18, 1988, contains analysis for pipeg routed from the
outlet side of containment spray heat exchangei 18 thru steel
containment vessel penetration IX48B to the conta nment spray
i
header 1-8.
The system was overlapped with problems N2-72-3A
and EM 0600104-01-01 as shown on pipe stress isometric drawing
0600102-01-02, Rev. 12.
,
During the review of the above problem the following items were
identified which require further TVA action.
On page B.26 of
the summary of analysis for system 0600104-01-02, Revision 14,
dated May 18, 1988, the evaluation of a pipe support location
discrepancy did not consider the effects on the X-direction
,.
seismic restraint located at Node 120.
The loading on the
restraint at Node 120 would increase due to the new location of
the adjacent X-direction restraint (C5H-31) located at Node 66.
TVA should determine the load increase and evaluate its effect
on the seismic restraint located at Node 120. Also, the effects
of moving the support at Node 66 on the loading of the
Containment Spray Heat Exchanger 1B has not been considered by
TVA.
'
l
I
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'
'n
v
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,
19
The as-analyzed length between. Node 60 and Node 63 in the
K-direction was 14 feet 6 incnes and the piping physical
.
arawings detail a length of 13 feet 6 inches.
This issue is
designated URI
327,323/38-29-06
Example'e.,
and requires
resolution prior to the startup of Sequoyah 'Jnit 1.
Adequate
resolution for the above URI shall include an Engineering
Assurance review of the design basis information related to this
issue.
In summary, from the design standpoint all items and attributes
listed above, with the exceptions discussed, were determined to
have been adequately addressed by TVA.
The analysis of record
for these piping problems based upon the attributes reviewed are
considered adequate and meet FSAR and design commitments.
(3) The team reviewed Containment Spray Pumps 1A-A and 18-B to
assess the design and procurement of these pumps with respect to
FSAR commitments and design criteria.
The CS pumps are shown on the following as-designed TVA
drawings:
47W812-1, Flow Diagram / Containment Spray System, Rev. 17,
dated June 14, 1988.
47V437-1, Mechanical / Containment Spray System Piping,
Rev. 24, dated May 3, 1938.
FSAR Section 6.2.2.2 specifies that each oump is rated for 4750
gpm flow at a design head of 370 feet.
FSAR Table 6.2.2-1
specifies additional pump design parameters.
FSAR Section
6.2.2.2 also details the functional requirements for the 700 HP
pump motors.
The functional requirements for the pump and pump motor are
reiterated in Design Criteria No. SQN-DC-V-27.5, Containment
Spray System, Rev. 2, dated July 22, 1937.
The design parameters of the CS System punps are provided in
Reference 6.
The calculation considers only / low from the RWST.
Only one pump is assumed operational.
The calculation shows
that each of the pumps, IA-A and IB-B, must develop a head of
328.29' or 142.1 psi at its rated flow. This is lower than the
manufacturer value of about 160 psi. A similar calculation for
Unit 2 resulted in a required head of 328.88' (Reference 7).
TVA could not provide a similar calcul
ion for the required
head when the pump takes suction from
he sump during the
recirculation mode for Unit 1.
Since the RWST is at a higher
elevation from the sump and the piping geometry on the suction
side is different for the two cases (RWST vs. Pump) it could be
expected that during recalculation the required head might be
]
!
-
.
.
20
higher.
On the other hand, since the containment pressure
exerted on the sump assists the pump during recirculation it is
likely that the required pump head during recirculation will be
smaller. Without a calculation it is not apparent which case
might control.
Consequently, the team considers .that a
calculation should be performed by TVA to document the head
required under recirculation mode for Unit 1.
A Technical Specification change has been submitted to the NRC
that will replace the requirement that "on recirculation flow,
each pump develops a discharge pressure of greater than or equal
to 140 psig" to the requirement that "on recirculatio1 flow,
each pump develops a differential pressure of greater than or
equal to 143 psid at greater than or equal to 4750 gpm".
Moreover, Surveillance Instructions SI-37.3 and SI-37.4 for
Unit 2 have been revised to reflect the 143 psid (Reference 12).
Surveillance Instructions SI-37.1 and 51-37.2 for Unit I have
not as yet been revised to reflect 143 psid, although it is
stated in the revision log that the revised differential
pressure was incorporated (Reference 13).
It appears that little or no margins have been incorporated in
the calculations nor have the requirements of ASME Code
Section XI been fully considered by the calculations used to set
the required pressure differential across the pump.
These
issues are designated URI 327,326/85-29-06 Example t.,
and
requires resolution prict to the startup of Sequoyan Unit 1.
Adequate corrective action for the above URI shall include an
Engineering Assurance review of the design basis information
related to this issue.
In both References 6 and 7 the recommendation is made that a
Mmorehensive pre-operational test be performed to establish a
set of performance points for the pumps.
The origin of this
request stems from the test deficiencies experienced in the
original pre-op program conducted in 1930.
This subject was addressed previously by the NRC through URI
327,328/87-50-03.
Specifically, CAQR SQP 870860 was issuec by
the licensee to document the fact that the preoperational test
for the CS pumps was not satisfied, in that, the head may not be
adequate to provide the required system flow.
The CAQR stated
that
preliminary analysis
indicated
that
although
the
preoperational test for pump performance was not satisfied, the
impact on containment integrity was minimal .
Initially, the
reportability of this CAQR and supporting potential reportable
occurrence (PRO) report was determined to be "indeterminate."
The CAQR was later determined, after approximately two months of
engineering evaluation, to be reportable.
The
inspector
cetermined that the licensee has scheduled the technical issue
I
O
21
,
for resolution prior to plant restart.
liowever, the use of
the term "indeterminate" for situations where the licensee knows
'
that a value used in TS and FSAR accident analysis can not be
satisfied by installed equipment is questioned. This issue was
discussed with the licensee in a management meeting conducted on
September 24, 1987.
As part of the resolution of the above CAQR, the licensee
performed special test instruction (STI) STI-65, Containment
Spray Pump Performance for Unit 2.
The intent of the test was
to reestablish a pump performance curve and verify that pump
performance is adequate to provide the needed system flow.
Additionally, this test was to measure actual heat exchanger
differential pressure (dp) and compares it to the value of
10 psid used to size the pump. Due to problems with installed
flow instruments (ANNUBAR), the licensee has had to resort to
the use of ultrasonic flow instruments during testing. The test
results of STI-65 indicated that the 2B pump satisfied the
manufacturers pump prformance curve.
However, the 2A pump
failed to provide the req #ed flow during testing.
It was
later determined that the ultrasonic flow instrument used during
testing of the 2A pump failed it's post use calibration. A
second test was performed using another ultrasonic flow
instrument and again the pump flow curve failed to satisfy the
pump head curve; however, on the second test the pump did
deliver the required 4750 gpm minimum flow. A CAQR was issued
to document the pump failure.
At the time of the SSQE inspection, it was TVA's intention to
perform the recommended testing on the pumps using a single
point test at the 4750 gpm flow rate.
The team considers that
because pump performance appears to be marginally edequate and
that the resciution of this identical issue for Unit 2 included
a three point pump curve flow test, that a three point pump
curve flow tost should be performed for the Unit 1 pumps also.
A licensee commitment was obtained to accomplish this.
This
ssue is designated as URI 327,328/35-29-06 Example
f.,
and
requires resolution prior to the startup of Sequoyah Unit 1.
Adequate resolution for the above URI shall include an
Engineering Assurance review of the design basis information
related to this issue.
The following additional CS Pump functional design parameters
were reviewed:
l
Accuracy of the calculation EPM-DAB-040498 which determines
the required CSS pump head for 4750 gpn.
The inspector requested that TVA perform a co?parison
l
between the piping lengtns appearing in the subject
I
calculation and the as-ouilt crawings.
The inspector
l
.
.
. . ..
. _ _ _ _ _ _ _ _
,
,
l
22
considered that due to the importance of the subject
calculation and the lack of margin in the use of the
generated pump head, such a comparison was crucial.
The
inspectors rmrformed a limited review of TVA's comparison.
The results indicated that the subject calculation was
acceptable.
Consistency of the geometrical configuration and flow loss
coefficient between calculations EPM-DAB-040488 Pumphead
and SQN-SQS4-0107, Pump NPSH.
In order to review the consistency of the input information
used in essential calculations by various preparers, the
.
inspectnr requested that TVA perform a comparison between
the geometrical configuration and flow loss coefficients.
Pipe lengths, fittings, components and the corresponding
l
losses were compared. A limited review of TVA's comparison
indicated that overall, more conservative numbers were used
l
for the calculation of the required NPSH in calculation
j
SQN-SQS4-0107. Since the available NPSH is higher than the
I
required NPSH, the choice of conservative numbers is
l
acceptable.
Clogging of Spray hozzles.
The head loss through the spray nozzles is a significant
contributor to the total system loss.
Moreover the spray
nozzles should be kept clean so that they can pass the
required flow.
Due to the above considerations, the
inspector reviewed TVA's practices in ensuring that these
nozzles remain clean.
Technical
Specification
Surveillance
Requirement
4.6.2.1.1.d (and 4.6.2.1.2) require that the CS System (and
RHR System) spray train shall be demonstrated operable at
least once per five years by performing an air or smoke
flow test through each spray header and verifying each
spray nozzle is unobstructed. This is accomplished through
the Surveillance Instruction SI-138, Rev
6, which was
found to be acceptable in section 1.h of this report.
Opening tines of Valves FCV-72-2 and FCV-72-39.
The inspector reviewad the data sheets on the stroke time
of these valves. The data indicated that both valves open
fully in about 15 seconds.
The maximum allowable stroke
time is about 20 seconds.
ConsidGring that the CSS pumps
reach full speed in about five seconds and that both valves
and pumps receive the signal simultaneously, the valve
opening times are acceptable.
,
, . . . . . . .
.
_ ____-__
____ . _ _ _ _ . _
.
23
Effect of the Opening of the Miniflow Line on CS System
Pump Ability to Deliver the Required Flow of 4753 gpm.
The Annubars used to measure the flow in the CS System are
i
~
susceptible
to
clogging,
particularly
during
the
recirculation mode.
Such clogging could result in a low
flow indication which in turn could result in opening
minimum flow valve FCV-72-13. The orifice in this miniflow
l!ne is sized to pass 250 gpm under deadhead conditions
(201.82 psid).
The inspector questioned whether the CS
System pump can deliver the required flow of 4750 gpm to
the spray header while simultaneously feeding the miniflow
line 250 gpm. The total flow through the pump will be 5000
gpm.
TVA performed a calculation which indicate, that,
under these conditions, the pump can deliver up to 5250
gpm.
The inspector performed a limited review of this
calculation and has found it to be correct. Therefore, the
opening of the miriflow valve will still allow the required
flow to the spraw header.
(4) A review was performed for the CS pumps relative to net positive
suction head (NPSH).
The available NPSH fer the CS pumps is
calculated based on the assumptions that the sump fluid is
subcooled (190 degrees F) and that NPSH available is equal to
the containment pressure prior to LOCA plus the pump static head
minus the vapor pressure head and the line loss. Therefore, the
applied methodology meets the intentions
of
Regulateey
Guide 1.1.
l
The NPSH calculations for the CS pumps are provided in
References 8 and 9 (section ik). These calculations are common
to both units.
Reference 8 compares the net positive suction
head available (NPSHA) to the net positive suction head required
4
(NPSHR) during the RWST injection mode. An adequate margin is
computed.
This calculation used the rated flow rates for the
pumps.
The maximum flow rates should have been used instead.
A similar comparison of NPSHA and NPSH is made in Reference 9
for a large LOCA. Maximum flow rates are us+d.
An adequate
,
margin is computed.
The maximum flow rates for the CS System
!
,
pumps are calculated in Reference 10 for Unit 1 and Reference 11
)
for Unit 2.
Reference 11 is a detailed calculation. Reference
10, dated June 15, 1988, simply states that, due to minor
-
differences in geonetry between Un!ts 1 and 2. the maximum CSS
flow rates are the same for both planto
This issue is
'
designated
327,328/88-29-06
Example g.,
and requires
,
resolution prior to the startup of Sequoyah Unit 1.
Adequate
L
resolution for the above URI shall include an Engineering
l
Assurance review of the design basis information related to this
I
issue,
i
f
.
.
.
.
.
.
.
.
24
(5) The inspector reviewed Containment Spray Heat Exchangers 1A and
IB to assess the design and procurement of tnese heat exchangers
with respect to FSAR commitments and design criteria.
The inspector verified that the CS heat exchangers were vertical
shell, U-tube type heat exchangers with tubes welded to the tube
'
sheet.
These heat exchangers are shown on the following
as-designed TVA drawings:
Flow
Diagram / Containment
Spray
System,
Revision 17. dated June 14, 1938.
47W437-1, Mechanical / Containment Spray System Piping,
Revision 24, dated May 3, 1988.
SQN FSAR Table 3.2.1-2 specified the containment spray heat
exchangers as TVA Class B (tube)/C(shell) seismic category I
components,
the tube side designed in
accordance with
Section III of the ASME Boiler and Pressure Vessel Code, and the
'
shell side in accordance with Section VIII of the ASME Code.
,
FSAR Table 6.2.2-2 specified the following design parameters for
.
the CS heat exchangers:
f
l
Heat Transfer / Unit:
64X108 BTV/ Hour
Flow Shell Side:
5,000 gpm
Flow Tube Side:
4,750 gpm
Tube Side Inlet Temperature:
135.8'F
,
Shell Side Inlet Temperature:
83 F
'
Tube Side Outlet Temperature:
108.5 F
Shell Side Outlet Temperature:
109 F
Design Pressure Shell/ Tube:
150/300 psig
,
Design Temperature Shell/ Tube:
200/300 psig
,
Table 3.7-3 of Design Criteria No. SQN-0C-V-27.5, Containment
Spray System, Rev. 2, dated July 22, 1987, reiteratus these
'
design critoria.
1
A detailed review of the system functional capability of the CS
heat exchangers is presented elsewhere in this report.
TVA procured the CS heat exchangers in accordance with the
design criteria contained in TVA purchase specification
!
No. 71C33-92645, Containment Spray Heat Exchangers, which TVA
prepared on November 19, 1970.
TVA Specification 1152 for Containment Spray Heat Exchangers for
Sequoyah Nuclear Plant Units 1 and 2 f orms a part of the
referenced purcnase specification for the heat exchangers.
Specification 1152 reiterates the requirements that the tube
side of the heat exchangers be designed in accordance with
-
--
-
.
'
.
_
25
Section III of the ASME Bo1~ler and Pressure Vessel Code for
Class C Nuclear Vessels, and that the shell side be designed in
accordance with Section VIII of the ASME Boiler and Pressure
Vessel Ccde.
As noted in Section 19 of Specification 1152, Conditions of
Service, TVA procured the CS heat exchangers to the following
design criteria:
Design pressure, shell, psig
150
Design temperature, shell, F
200
Design pressure, tubes and bonnets, psig 300
Design temperature, tubes and bonnets, F 300
Section 19 specified two limiting conditions (Condition A
and Condition B) related to heat transfer and heat sink
flow parameters as follows:
Condition A Condition B
Quantity of containment spray
4750
4750
water, gpm
Quantity of cooling water, gpm
6028
6028
Temperature of containment spray
156
14C
water in, F
Temperature of c.ontainment spray
115
106
water out, F
,
Temperature of cooling water in, F
91
83
Temperature of cooling water out, F
123
115
Maximum allowable pressure drop
15 (max)
15 (max)
shell side, psi
Maximum allowable pressure drop
10 (max)
10 (max)
tube side, psi
Fouling factor for tube inside,
0.0003
0.0003
2
Hr. F, ft BTU
Fouling factor for tube outside,
0.001
0.001
2
Hr. F, ft Btu
Duty, Btu /hr
97,385,000
95,000,000
These design conditions meet or exceed the design conditions
specified for the CS heat exchangers in the FSAR and Design
Criteria.
i
,
Section 13 of Specification 1152, Seismic Requirements, details
the seismic criteria which the heat exchanger vendor is required
to address in order to seismically qualify the heat exchangers.
The CS heat exchanger is shown on Industrial Process Engineers
Orawing No. F-6663-2, Rev. B, dated January 6, 1970
'
l
TVA provided the
following
Industrial
Process Engineers
'
calculations:
-
. _ .
. _ _ _ _ . _ _ _ _ _ _ _ _ .
. - _ - _ - _ - - - _ _ _ _
_
__ _ . . ,
c_
_
,
.
26
TVA - Sequoyah Nuclear Plant Units 1 and 2/Contr.inme .;
Spray Heat Exchangers/ Code Calculations, dated '4ar.h 5,
1971 (RIMS No. A26 870728 602).
TVA - Sequoyah Nuclear Plant Units 1 and 2/Containe.ent
Spray Heat Exchangers/ Seismic Analysis, dated October 4,
1971 (RIMS No. A26 871020 705).
TVA - Sequoyah Nuclear Plant Units 1 and 2/ Containment
Spray Heat Exchangers/ Weights - C.G. - Lifting Lugs, dated
October 19,1971 (RIMS No. illegible).
TVA - Sequoyah Nuclear Plant Units 1 and 2/Containnent
Spray Heat Exchangers, dated August 24, 1971 (RIMS No.
illegible).
These vendor calculations provide some evidence that the CS heat
exchangers were qualified to the governing mechanical and
seismic criteria, but are not suf ficf ently legible to permit
detailed review.
However, based on three ge.neric deficiencies which the NRC
identified dt. ring inspection 327,328/87-28, Deficiency 03.4-3,
CCW Heat Exchanger Calculation, Deficiency 03.4-4, CCU and CS
Heat
Exchanger No7.zle Loadings,
and Deficiency
04.6-1,
Discrepancies Between Design Calculations and Construction
Drawings, TVA has prepared CAQR No. SQP870199, Rev. O, dated
October 8, 1987. The CAQR indicated that component analysis and
"as-built" anchorages were not consistent and in agreement with
component qualification. The CAQR addressed equipment installed
in Units 1 and 2.
l
To address the CAQR, TVA, in part, prepared the following
calculations:
Calculation No. CEB-CQS-312, loclusion of No:zle Shear
Loads in the Qualification of the Containment Spray Heat
Exchangers
on
contract
Rev. O,
dated
Augus+. 27,1987 (RIMS No. B41870827 002).
,
Calculation No. MCL C12 et al, Structural Evaluation of
As-Modified Containment Spray Heat Exchangers 2A and 28,
Rev. 3, dated February 22, 1998 (RIMS No. 88 0223 310).
TVA closed out CAQR No. SQP870199 on January 12, 1988.
,
On May 27, 1983, TVA prepared CAQR No. SQP 880363, Rev. O, to
indicate that CAQR No. SQP 870199 had been closed for Unit 1
l
without completely documenting the qualification of the CS heat
l
exchanger,s and the associated supports and anchorages, as well
as additional Unit I heat exchangers.
L
.
27
TVA asked Impell to compare the applicability of the Unit 2 heat
exchanger calculations to the Unit I heat exchangers.
i
Impell's letter to TVA dated June 16, 1988, indicates, in part,-
I
that CS Heat Exchanger 1A requires separate qualification due to
significant differences in the supporting structures and nozzle
loads, and that CS Heat Exchanger 1B requires additional
evaluation due to differences in the nozzle loads and as-built
conditions.
TVA is currently considering Impell's proposal to implement the
scope of work outlined in the letter.
The team therefore notes that TVA's actions to re qualify the
components installed in Unit I with respect to the generic
deficiencies which the NRC identified during the 101 inspection
conducted on Unit 2 during the latter part of 1987 are
incomplete at this time.
This issue is designated URI
327,328/88-29-06 Example
h.,
and requires resolution prior to
the startup of Sequoyah Unit 1.
Adequate resolution for the
above URI shall include an Engineering Assurance review of the
design basis information related to this issue.
The maximum operating pressure of the CS system heat exchangers
is calculated in Reference 31 (section 1.1) as 155 psig. This
is below the 220 psi rating of the system.
A study of required ERCW flow rate (shell side) to remove the
heat from the CS system under various ERCW inlet temperatures
and varicus heat exchanger tube plugging is given in Reference
32.
The results from the reference are used to adjust the ERCW
flow rates when Surveillance Instruction SI-566 is implemented
(Reference 33).
A maximum of 10% tube plugging is used in
SI-566.
CAQR SQP 870105, Rev.1 (reference 34), revises FSAR Table
6.2.1-1 sheets 9 through 12. According to TVA, the revised data
agree with HX calculations and the Westinghouse /HX vendor data.
Some inconsistencies between the HX parameters in the current
FSAR and the HX parameters in the Design Criteria of the CS
exist.
The pressure drop across the HX tubes is measured via SI-37.1
and SI-37.2, Containment Spray Pump Tests. During these tests,
conducted as part of the Unit 2 restart test program, a pressure
differential of about 5 psid was developed for the required flow
rate of 4750 gpm.
A recent TVA calculation on the ERCW system performance
following the Loss of Down Stream Dam, Reference 35 concludes
that an ERCW supply temperature as high a s 83.2'F will
.
-.
- - _ = - _ _ - _ - - ,
.
28
adequately remove the required heat load. The team performed a
limited review of this calculation as -it relates to CSS.
An
unverified assumption is used which relates to data received
from Westinghouse.
Some discrepancies were identified between
the unverified assumption and heat removal rates used in
previous calculations.
Inspectors did not perform a review of
the justification of the clarification on the differences by
TVA.
Due to the importance of the CS System HXs, TVA should review in
more detail the HX calculations and their conformance to
component specification 1152, the FSAR, and the CSS design
criteria.
This issue is designated URI 327,328/88-29-06
Example i., and requires resolution prior to the startup of
Sequoyah Unit 1.
Adequate resolution for the above URI shall
include an Engineering Assurance review of the design basis
information related to this issue.
(6) An evaluation was conducted to determine if a hazard analysis
had been performed for the CS system.
Four issues were addrussed by the inspectors.
Effect of a High Energy Line Break on C5 System
Operability.
The inspector evaluated the effect of high eneroy line
breaks (HELB) inside and outside containment on the CS
system.
Two concerns were addressed:
Pipe whip and
flooding
from
such
HELB which
could
potentially
incapacitate the CS system.
Regarding pipe whip for a HELB inside containment, drawings
47W200-12, R5, and 47W200-13, RS, "Equipment, Reactor
Building" and drawing 47W2500-1 through 12, R3, "Composite
Piping" show that the top of the steam generator cavity,
the refueling floor and the control rod drive missile
shield provide a 1hysical separation between any piping in
the lower containment and the CS system piping and
components.
Therefore,
such er
interaction
is not
credible.
A HELB outside containment will not require the ectuation
of the CSS.
Moreover,
a
simultaneous HELB inside
containment is beyond the DBA and need not be analyzed.
Regarding flooding, there is no CSS equip;nent inside
containment that could be affected by a HELB inside
containment. Additionally, for a HELB outside contair.mee.,
the CSS 11 not required to operate.
'
,
29
'
Verification of the Secondary Design Basis of the CS
System.
The FSAR on page 6.2-S7, states, "Tne secondary design
basis for the Containment Heat Removal Spray Systems is the
suppression of steam partial pressure in the upper volume
due to operating deck leakage from a small break before a
full loss-of-coolant accident. The requirement is that the
Containment Spray Systems be able to absorb the steam
leakage through the operating deck at the maximum possible
long-term deck differential pressure of one ocund per
square foot equivalent to the ice :endenser door opening
....". The team requested the analysis which verifies that
the containment spray will guench the leaking steam. TVA's
response was provided in writing to the inspector on
June 30, 1988. According to this response, the secondary
design basis has been deleted from the CS design criteria
SQN-0C-27.5, with Westinghouse's concurrence.
The secondary design basis addresses the protection of the
containment from a double accident that is a small break,
which initiates the CS system, followed by a large break.
In the TVA response, the argument is made that this
scenario goes bayond current NRC requirements. Moreover,
the Technical Specifications' action statements would be
entered and safety injection would be actuated before the
containment sprays would be activated.
The inspector found
this logic acceptable.
According to TVA, the secondary design basis will be
omitted from the FSAR in the next yearly update, scheduled
for April 15, 1939, to make it consistent with the design
criteria.
Effect of CS System Pump Startup Delay, Que to Diesel
loading Sequence, on the Accident Analysis.
The delay time in the FSAR analysis assumed for loading the
spray pumps on the diesels is 30 seconds.
This time has
been changed to 180 seconds to account for random loads
that might occur during the safeguards loadings sequerce.
To assess the impact of this enange, the containment
pressure (due to LOCA) and temperature (due to mainsteam
line break) analyses currently presented in the FSAR have
been reviewed by TVA.
As a result of this review, TVA
concluded through a qualitative evaluation that the delay
has no impact on either analyses.
Westinghouse has concurred with TVA's conclusion. Tne team
has reviewed both TVA's evaluation and the concurrenca
letter form Westingrouse and foor:: trem both acceptaf e.
.
_ _ _ - _ _ _ _ -
_
.
30
Modeling of the Delay Time for Change Over from Injection
'
to Recirculation.
In changing over from injection to recirculation, the CSS
pumps are shut off.
The delay time for changeover from
injectier, to recirculation is given in Table 6.3.2-5 of the
FSAR as the summation of actions 13 through 18. This time
is equal to 110 seconds.
Westinghouse LOCA analysis
assumed 310 . seconds.
The inspector determined that this
modeling assumption was conservative.
(7) An evaluation was performed to ascertain that senti!ation having
airborne radioactivity originating in une pump compartment will
l
not be transmitted to the other pump compartment or to otner
l
vital areas within the auxiliary building.
The design features of the ventilation system which would
prevent the transport of radioactivity from one pump room to the
other were reviewed.
Review of drawings 47WS66-1, -2 and -10
(
"Flow Diagram, l! eating and Ventilating / Air Flow", indicated the
j
following:
Backdraft damoers prevent backflow in the ducts. Each room
'
is equipped with one such camper.
These rooms are normally exhausted by general ventilation.
In case of radiation release, the auxiliary building gas
treatment system is used.
These design features appear to be acceptable.
J.
Preoperationa) Functional Testing
(1) An inspection was performed to verify that the following
preoperational functional testing was performed and to determine
whether or not the testing was adequate.
Test TVA-218, Containment Spray System.
Pumps were operated at reduced flow through the minimlm
flow recirculation lines and essentially heated flow
.hrough the test line to the RWST. Pump performance values
were derived.
Valve
interlocks
in pump suction lines between the
containment sump and RWST were verified to be operable in
accordance with SCN-47W610-72-1. Mechanical Logic Diagram.
The capability of manual oceration from the control rocm
and the auxiliary control room was verified.
_ _ _ _
'
O
31
Test W-6.1A1 - Integrated Flow Testing of the Safety Injection
(SI) System
This test demonstrated acequate net positive suction head
(NPSH) during integrated operation of the CS and SI systems
during the recirculation mode.
.
The inspector reviewed Preoperational Test TVA-218, Containment Spray
System, and verified that the preoperational test operated the pumps
at reduced flow through the minimum flow recirculation line and at
essentially rated flow through the test line to the Refueling Water
Storage Tank, and that pump performance values were generated. The
inspector verified that the preoperational
test
tested
the
-
Containment Spray valve interlockt on the punp suction lines and the
RHR Containment Spray injection valves. The inspector also verified
that the preoperational test verified that the motor operated valves
could be operated f rom the local, remote and auxiliary control
stations.
The inspector also reviewed Preoperational Test W-6.1A1 -
Integrated Flow Testing of the Safety Injection System, as it
pertained to the Containment Spray System.
The inspector noted the
following:
,
TVA-21B did not adequately verify the valve interlocks on the
containment
spray discharge valves
1-FCV-72-40 anc
1-FCV-72-41.
The inspector determined that this condition had
been identified by the licensee as part of the restart test
program.
The inspector, however, determined that the valve
interlock had been tested and verified as part of the ASME
Section XI Program.
Step 5.6.14 of TVA-21B required that inboard and outboard
bearing temperatures and the motor temperature be recorded at 10
minute intervals until the bearing temperature stabilizes.
The
step contains a note that a stable temperature exists when three
successive readings do not vary more than 3%.
Review of the
bearing temperature data rccorded in the pre-operational test
determined that the bearing temperctures did not meet the 35
criteria as required.
Section XI testing requires that pump
bearing temperature be monitored anc that three successive
readings be within 3%.
The inspector determined that the pump
bearing temperatures recorded in the ore-operational test were
.
not excessive and that TVA his received exemption from tne
[
requirement for monitoring pump bearing temperatures on the
,
containment
spray pu-ps based on
inaccurate
temperature
'
measurements of the bearings and the fact that the other test
parameters provide suf ficient information about pump condition.
The inspector believes this deficiency does not present a pump
operability issue and that the licensee'sSection XI testing
provides sufficient information about pu p cordition.
i
- -
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _
"
,
32
k.
The following are additional references that were used during the
,
mechanical portion of this inspection:
(1)
Flow Diagram, Containment Spray S) :i am. Drawing 4'/W612-1,
Rev.16, Febeury 16, 1988.
(2) Design Prev; .. a and Temperature Calculation for RWST Suction
Header and i 4 Return Line EMP-SMJ-022SS6, Rev. 2, May 27,1988,
Units 1 aws 2.
(3) Co nta h.er.t
Spray
Pressure
and Temperature Recuirements.
EPM-STM-C62083, Rev. O, June 24, 1983, Units 1 and 2.
(4) RHR
fpray heacer
oressure
Requirements
at
Containment
Penetrations, EPM-STM-0613SS, Rev. O, June 20, 1988, Units 1 and
2.
(5) RHR
Spray Header Pressure
Requirements
at
Containment
Penetrations, ECM-LFG-061088, Rev. O, June 16, 1988, Units 1 and
2.
(6) Containment Spray Pump Test Requirements EPM-DAB-040488, Rev. O,
Acril 13, 1983. Unit 1.
(7) Containment Spray Pump Test Requirements EPM-OLB-050487, Rev. 3,
November 6,1987, Unit 2.
(8) NPSH Calculations for the CCP, SIP, CSP, and RHR Pumps Operating
in the RWST Injection Mode following a LOCA, Rev. O April 29,
1983, Units 1 and 2.
(9) NPSH Calculations for the RHR and CSS Pumps Operating in the
Recirculation Mode for a large LOCA, Rev. 3,
May 6,
1988,
Units 1 and 2.
.
(10) Containment Spray Pump Maximum Flow EPM-STM-060388, Rev. O,
June 15, 1933, Unit 1.
(11) Containment Spray Pump Maximum Flow EPM-OLB-060537,
.O,
-
July 7, 1987, Unit 2.
l
(12)
Surveillance Instru::tions 37.3 and 37.4 "Containment Spray Pump
2A-A Te st" and "Containment Spray Pump 28-B Test", Unit 2,
Rev.1, February 25, 1933.
(13)
Surveillance Instructions 37.1 and 37.2 "Containment Spray Pump
1A-A Te st" and "Containment Scray Pump IE-B Test", Unit 1.
Rev. 1 June 7, 1953.
4
~ _ , _ _ _ _ _
_ _ _ _ . _ _ _ - _
._
_
,
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
v
33
,
(14) Tubular Exchanger Manufacturers Association. Class R Heat
Exchs ,. ,e r , Tube Side, ASME Boiler and Pressure Vessei Coce
Scction VIII.
(15) ANSI 16.5, Steel Pipe Flanges and Flanged Fitting.
(16) ANSI B 31.1, Code for Pressure Piping with inspection and test
requirements to ANSI B 31.7 Code for Nuclear Piping in lieu of
applicable Nuclear Code Cases.
(17) SSDC 1.3, "System Standard Design Criteria (5500)," Revision 2.
Westinghouse Electric Corporation, cated April 15, 1974.
(18) E-Specification 67S765 - Motor Operated Valves for TVA Secucyah
Nuclear Plants Units 1 and 2,
and G-676258 Motor Operated
V01ves. Westinghouse Electric Corporation.
(19) E-Specifications 67863 - Control Valves for TVA Sequoyah Nuclear
Plant Units 1 and 2,
and E-Specifications 676270 - Control
Valves Westinghouse Electric Corporation.
(20) E-Specifications 67869 - 2 Inches and Below Manual
"T" and "Y"
Globe and Self-Actuated Check Valves for TVA Sequoyah Nuclear
Plant Units 1 and 2, and 678724 - 2 Inches and Below Manual
"T"
and
"Y"
Globe and Self-Actuated Check Valves, Westinghouse
Electric Corporation.
(21) E-Specifications 678760 - Manual "T" and "Y" Globe, Manual Gate,
and Self-Actuated Check Valves for TVA Sequoyah Nuclear Plant
Units 1 and 2, and G-676241 - Manual
"T"
end "Y" Globe, Manual
,
Gate, and Self-Actuated Check Valves, Westinghouse Electric
Corporation.
(22) E-Specifications 67863 - Auxiliary Relief Valves for TVA
Sequoyah Nuclear Plant Units 1 and 2, and G-676257 - Auxiliary
Relief Valves, Westinghouse Electric Corporation.
(23) SQNP-47WS12-1,
Flow
Diagram,
Containment
Spray
System
Powerhouse, Units 1 and 2.
(24) SONP-47W610-72-1, Pechanical Control Diagram, Containment Soray
System.
(25)
SCNP-47W611-72-1, Pechanical ' ogic Diagram. Containment Scray
.
System.
(26)
SCNP-47A366-72-Series, Tabulatien of Valve Marker Tags.
(27)
SCNP-474437-Series. Contain ent Spray System Picing.
,
(25)
SCN-DC-V-27.1, Design ' -'teria for Ice Concenser System.
.
_ _ _ __ _ ___
__
-
,
'
4
.
34
(29) SQN-DC-V-3.1, Classification of Piping. Pumpe, Valves and
Vessels.
(30) Regulatory Guide 1 ., NPSH for ECCS and Containment Heat Removal
oympg,
(31) "Operating Dressure of CSS Heat Exchangers (Tube side)", Rev. P,
SQN-72-0053, EPM-DLB-1219S7, February 10, 1988.
(32) "Containment Spray System Heat Exchanger - Tube Plugging",
Rev. O, SON-72-0053. EMP-KBO-017057, February 29, 1987,
(33) Surveillance Instruction, S1-566, ERCW Flow Verification Test,
RIS, June 15, 1958
(34) CAQR SQF 870105. R1, 5-13-85, "Revise FSAR Table 6.2.1-1 sheets
9 through 12, Heat Exchanger Data".
(35) PIR SQNME986*32, R0. 4-4-87.
(36) ERCW System Loss of Downstream Dam Flow and Temperature
Calculations, SQN-67-0053 HCG-GEB-0510SS R0, 6-7-88.
2.
Electrical Inspection
Design document and in plant field observation were integrated in order to
evaluate the CS system and ccmponents for proper design and design
implementation.
As discussed in each of the following Nctions, the
inspectors evaluated the system and components against the applicable
standards listed at the end of this report and the SYSTERS/ design basic
reports for the Unit 1 CS system.
The inspection of electrical components of the CS system included pumps,
motors, breakers, motor operated valves, and associated cabling and
control devices.
The inspection was conducted on a sampling basis by a
comparison of physical installations to Sequoyah Unit 1 as-constructed
d rawi r.g s .
TVA staff personnel accompan;ed inspecters for most of the
electrical walkdowns and all findings and comments were af scussed with
appropriate personnel. Components selected for saepling were necessary in
supporting the analyzed design, function, and operation of the CS system
and therefore provided an adeouate basis for determination of design,
compliance, and performance.
a.
Electrical Design
(1) General
The cc
of the station auxiliary electrical syste s was
evalua.
- o ascertain whetner they woulo provide reliable power
to cone ,1 anc operate tne Unit 1 :ontainment spray system and
the
associated
support
systems
in
a:corcance with tne
!
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
_ _ _ _ _ _ _ _ - _
.
,
35
requirements of General Design Criteria (GOC) 17 of 10 CFR 50
Appendix A.
Additionally, the cesign was reviewed for con-
formance to the commitments of the Final Safety Analysis Report
(FSAR), the requirements of the TS and license conditions.
This design review was made for normal station operating modes
including the following postulated concitions:
!
Loss of Coolant Accident (LOCA) - Normal offsite power.
'
'
Loss of Coolant Accident - degraded offsite grid.
Loss of Coolant Accicent - loss of offsite oower (LCOP)
Loss of Coolant Accident - electrical fault
The review was made to determine if the steady state and
transient current and voltage were within the systems component
design ratings.
Correlation between the elect ical parameters of selective
electric components was reviewed. These electrical parameters
were specified in the purchase specifications of electrical
'
equipment, vendors test results, field verified equipment name
plate data, and input data to electrical calculations.
The protection coordination of the electrical systems, curing
postulated fault conditions, was reviewed, relative to the
containment spray system, to assure fault removal with the
minimum disturbance to the unaffected portions of the electrical
systems. Field verification of selected protective relay types
and settings was made.
These data were compared to the relay
calibration test data and to the protection coordination study.
An operability evaluation of the electrical systems was made
relative to and including the containment spray system.
This
evaluation was made by reviewing selective surveillance test
records,
These tests and records are required as specified in
the
Technical
Specifications.
Also
reviewed were
the
operability and cesign of the containment spray pump motor space
heaters.
A followup review of the emergency generator
alternstor space heater problems previously identified wac
,
completed. The effects of low voltage during a postulated grid
j
condition,
relative to the containment spray system was
reviewed. This review included both the electric motors and the
motor operated valve motor control center contactor operability,
i
(2)
Scope
l
The design review included oortions of the station ausiliary
electric power system as follows:
,
power supplied to the unit transformer IA from both the
main generator anc rain transformer, to the 6.9KV unit
-
_ _ _ _ _ _ _ _ _
_____
,
36
board 1B, to the 6.9KV shutdown board 1A-A, to the 480V
shutdown board 1Al-A & 1A2-A, to the 4SOV reactor motor
operated valve (MOV) board 1Al-A & 1A2-A.
Power supplied to the 6.9KV shutdown board 1A-A f rom the
6.9KV emergency diesel generator IA-A.
Power supplied fecm 125VDC batteries 1 and 2 to their asse-
ciated distribution systems.
Power supplied from 120VAC vital inverters 1 and 2 to their
.espective distribution sytems.
'
Power is supplied to the common station service transformer A
from the 161KV switchyard to the 6.9KV unit board 1C, to the
6.9KV shutdown board 18-B, to the 480V shutdown board 191-B &
182-B, to the 480V reactor MOV board 181-B and IB2-B.
Power
supplied to the 6.9KV shutdown board IB-B from the 6.9KV
emergency generator IB-B.
Power supplied from 12SVDC batteries
3 and 4 to their respective distribution systems.
Power
supplied from 120VAC inverters 3 and 4 to their respective
distribution systems.
Tne design review included the containment spray system and
specific components as follows:
containment spray pumps (CSP) 1A-A & IB-B
motor operated valves:
1-FCV-72-22
RWST to
-
1-FCV-72-23
SUMP to
-
1-FCV-72-34
-
1-FCV-72-39
CSP 1A-A Disch. Header Isolation
-
1-FCV-72-21
RWST to
CSP 18-B
-
1-FCV-72-20
SUMP to
CSP IB-B
-
1-FCV-72-13
CSP IB-S Re:tr
-
1-FCV-72-02
CSP 1R-B Disch. Header Isolation
-
(3) Auxiliary Electrical System Analysis
The TVA Electrical Loacing Patrix (ELMS) study of the ele:trical
system load flow, fault current and voltage considered the
following plant conditions:
Unit i normal - Unit 2 normal (condition 1)
Unit 1 full load rejection (FLR) - Unit 2 FLR (cond-ition 2)
Unit 1 FLR - Unit 2 Safety Injection (SI) phase A
(condition 3)
Unit 1 FLR - Unit 2 SI pnase B (condition 4)
_ _ _ _ _ _ _
____
a
37
The ibove conditions were analyced at time zero and five seconds
including electric power supplied from tne main generator
(source-1) and from the 161KV system (source-2).
During the
thirty seconds af ter a FLR electric power will be supplied to
the station service auxiliary power system from the main
generator then transferred to the 161KV source.
The ELM study with the reverse of the above conditions for
conditions 3 and 4 and with Unit 1 full load rejection was not
available for review.
The summary and conclusions of the
completed ELM study is presently scheduled to be submitted by
TVA to the NRC ty Ju'y 15, 1988.
The emergency diesel generator loading study was not a"ailable
for review. This study for two unit operation will be submitted
by TVA to the NRC prior to Unit I restart,
The review of these studies are necessary for the completion of
a site electrical systems Safety Evaluation Report.
(4)
Fault Currents
A review of the ELM electrical system study revealed the
following:
The 6.9 KV unit board load breakers interrupt design rating
are exceeded for a postulated fault condition tan a load
cable next to the breaker.
This condition is valid during normal plant operation when
the unit boards are supplied power from the main generator.
The interrupt values that the load breakers would be
required to interrupt are 584 MVA for the smallest motor
and 550 MVA for the largest motor on the unit boards.
The
installed breakers are ITE 7.5HK500 which have a design
interrupt rating of 500 MVA and a performance guarantee
rating cf 525 MVA.
ITE has tested this breaker type for
550 MVA Interruption.
The unit board load becaker interrupt requirements are
higher should a fault occur when the emergency diesel
generators (EDG) are being tested. Only one EDG is tested
at a time. The test frequency is once per month for a one
hour duration per EC3.
The postulated f ault currents in the ELM study are based
upon a three chase bolted f ault with no fault impecance,
This type of fault nas a low probability of occurrence.
The value of the fault currents would cecrease due to both
fault impedance and cistance of the fault from tne bus
toward tne load cue to the increased cable impecance.
.
38
The
6.9KV
shutdown
board
load
breaker
interrupt
requirements are 525 MVA whicn is equal to the breaker
performance guarantee rating.
The ELM study did not list the momentary current for the
fault condition.
Both the interruot and momentary fault
conditions were analy:ed for Unit 2 restart and are
discussed in the Safety Evaluation Report (SER) for
Sequoyah, NUREG-1232, Volume 2.
The interrupt value stated
in the SER for Unit 2 unit board load breakers was more
than 560 MVA. TVA has committed te resolve this problem of
the 6.9KV unit board load breaker fault interruption. This
commitment was given to the NRC in a letter of August 10,
1987.
The NRC staff has requested that TVA provida a
detailed description, analysis, and installation schedule
for implementation of the corrective actions.
TVA has
committed to provide this information before June 30, 1939.
The review of this study is necessary for the completion of
a site electrical systems Safety Evaluation Report and TVA
should make this information available to the NRC reviewer.
The postulated fault current values in the ELM study, at
tne 480 volt portion of sna auxiliary power system, did not
exceed the 480 voit breaker interrupt rating and are
acceptable.
(5) Voltage
The voltage at the 6.9 KV shut swn boards, for time zero,
conditions 1 through 4,
with v rce 1 and 2, was adequate to
maintain the 6.6 KV motors with'i the motors' design rating.
During condition 4 when the shutdown boards are supplied power
from source 2, the voltage at time zero drops below the setooint
of the degraded voltage relay.
This set point is 6560 volts,
plus or minus 33 volts.
After five seconds tne voltage on
shutdown board 1A-A reco"ers to 6662 volts which is 68 volts
above 6560 volts plus 33 volts.
Associated with the degraded
voltage relay is a ten (10) second time delay before system
separation. Although a ten seconc ELMS study was made, it was
not available for review. The concern is the voltage relay cead
band.
TVA was asked to provide this information. The value of
voltage that must be reached to stoo the time delay relay must
be known to assure that the voltage at the shutdown board nas
recovered above the cead band before ten seconds to preclude
unnecessary system separation for the offsite source.
The
information provided oy TVA from the pSO eelay calibration sheet
indicates the uncervoltage relay would reset and stop the timer
at 6600 volts and the snutoo n coarc voltage recovers to 6662 in
5 secones.
, _ _ .
'
.
.
39
The. review of this study is necessary for the completion of a
site electrical systems Safety Evaluation Report and TVA should
make this information available to tne NRC reviewer.
The 480 volt motors did not fall below their 804 starting limits
with one exception.
A motor operated valve (MOV) had 79%
voltage.
The MOV had been specified to start at 75% voltage.
TVA will be asked to show that all 6.6 KV and 460 volt meter
voltages recover to the minimum of minus ten percent of motor
rated voltage after either a condition 3 or 4 when supplied
power from source 2.
The review of this data is necessary for the completion of a
site electrical systems Safety Evaluation Report and TVA should
make this information available to the NRC reviewer.
A review was made for adequate voltage at the containment spray
system Iotors and motor operated valve motor contactors during a
steady state degraded voltage condition.
i
The voltage value used was the setpoint of the degraded voltage
relay which is 6560 volts plus or minus 33 volts. Using tha low
side of 6560 volts minus 33 volts. I volt was added for a value
of 6528 volts.
The containment spray pump motor terminal
voltage was within the motor rating. The motor operated valves,
associated with the containment spray system, also had terminal
y
voltage within their design.
The voltage at the MOV motor
contactor coil was above the TVA test value of 80 volts. During
the contactor minimum voltage test the pickup current was 987
milliamperes. The worst case control current was compared to
the type FRN-1 fuse which is a 1 ampere time delay fuse. The
worst case contactor current was 70% less than the fuse opening
current, at the 10 seconds setpoint of the degraded voltage
condition, where system separation occurs.
(6) Protection Coordination
The protective relay coordination provides selective tripping
during a fault condition to minimize deenergizing electrical
equipment.
The load breakers should open for a load fault
without opening a supply breaker unless there is a f ailure of
its protective relays or the load breaker fails to cpen.
A review was made of protective relays assoc'ated with the unit
transformer and incoming supply breaker to the 6.9 KV unit board
IB.
These relay setpoint curves were compared with the
protective relay setooint curves of reactor coolant pump 2 for
proper coordination.
Reactor coolant pump 2 is the largest
norsepower motor supplied power f rom the unit board 16.
This
coordination review contained for tne protective
relays
associated with unit coard IS tie Dreamer te snutcown Ocard '.A-A
,_
i
'
,
40
including those relays associated with the incoming supply
'reaker to shutdown board 1A-A.
Tne relay setpoint curves
c
associated with the incoming power supply to shutcown board 1A-A
were compared with the protective relay setpoint curves of the
largest norsepower motor on the bus, which is containment soray
pump 1A-A.
The co' rdination review continued from shutdown
board 1A-A through load center transformer 1Al-A to the 450 volt
shutdown board (1Al-A) then to the 480 volt reactor motor
+
operated valve (MOV) board (IAl-A).
supplies power to the containment spray MOVs associated with
containment spray pump 1A-A.
Relay types, trip current setpoints, and time lever settings
were found to be the same between the coordination curves relay
calibration sheets and field verified at the panels.
The
coordination curves indicated that the electrical systems
protective relay setpoint was adequate.
(7) Electrical Operability Surveillance
There were fifteen electrical surveillances considered for
review.
These
are
tests
required
by
the
Technical
Specification.
Due to the extensive data and the review time
available curing this inspection a proper review coulc not be
made at this time.
However, the tests that are identified in
the documents reviewed listing will be given an additional
review both for adequacy of test methods and content.
It was noted in the review for SI-7, Diesel Generato*, that
starting the diesel required pulling fuses, removal of relay
covers, and pushing a relay to make contact.
Also, the
acceptable measurement in the seven day tank, related to the
62,000 gallons required by the Technical Specification, was
given in feet in the Surveillance Instructions.
TVA has not
responded as to why the diesel generator batteries Surveillance
Test did not include both a service and capacity test as did the
vital station batteries.
The review of this information is necessary for the completion
of a site electrical systems Safety Evaluation Report.
'VA
should make this information available to the NRC reviewer.
(B) Electrical Data
There were no dif ferences between electrical parameters listed
in the following documents reviewed:
purchase specification requirements
sencors fill in cata of purcnase specifications
'
vencors test cata
_ _ _ _ _ _ _ _ _ _ - _ _
'
.
41
electrical drawing
relay calibration sheets
electrical studies
field verifiec name plate data:
main generator
-
-
unit transformer 1A
-
-
common transformer A
-
emergency diesel generator 1A-A & 1B-B
-
containment spray pump 1A-A
-
field verifted protective relay setpoints
(9)
Electrical Componee s
The time delay relays uwd for the emergency diesel loading and
degraded voltage time delay are of the electric pneumatic typ9.
These relays require that air bleed off to complete the time
delay function.
TVA was asked to provided data that these
relays would not be adversely affected during a tornaco created
atmosphere depression. TVA provided a study, SON-CSS-019, that
indicated that these time delay relays were not adversely
affected during a tornado.
b.
Electrical Components Inspection
(1) Motor Operated Vahes
A wiring verification and inspection was performed on five
Containment Soray motor operated valves. Work was observed on
two additional motor operated valves that had their valve
operators removed and in the mechanical maintenance shop for
repair, Selected valves in the Containment Spray system were
inspected for proper wiring configuration, qualified wire,
correct termination and crimping, limit switch condition, cable
and conductor damage, valve cleanliness and condition, and
environmental qualification.
The wiring was vcrified to be in
accordance with the "As Configured" wiring diagrams.
The
inspection included an electrical verification of valve condi-
tion in the limit switch compartment.
Prior to the NRC field
'perated valves, the licensee had
inspection of the motor
o
performed a pre-inspection of all CS valves predicated by the
impending NRC inspection. NRC inspectors noted many of tre same
findings that were discovered durirg the pre-inspection.
NRC
inspectors found the additional discrepant es that were act
i
discovered by the licensee during tne pre-inspection:
- = NRC additional discrepancies
- = pre-inspection discrepancies
1-FCV-72-13
.-.
,
_ _ _ - - - - . - - - - - - - - - - - - - - - - - - - - _ _ _ _ _
'
.
42
Motor lead T1 bend radius was not in accordance with
requirements.
The limit switch cover gasket seating surface was coated
with surface rust.
Wire 53 and 55 ter.minal lugs on rotor terminal 2 were bent
in excess of 90 degrees between the ring and the lug.
Crimps on CL1 (red) and 60 (black) conductors af IV3155B.
insulation not under insulation on barrel.
Motor leads T1 and T2 and wire 25 (white) conductor of
cable 1A5335 have cable recairs using electrical tape
rather than Raychem.
Cable identification tag was missing from cable 1A5335.
2 Terminals on rotor 1, contact position 1 were incorrectly
labeled as #53 and #55.
No additional findings.
1-FCV-72-20
Crimps on all conductres of cable IV1842B (except blue),
insulation not under insulation on barrel.
Hairline crack on unused rotor finger block.
Conduit identification tag broken on cable IV18408.
Cable 1A53SS was not tagged correctly.
Cable 1A18428 was not tagged.
Spare conductors were spared using electrical rather than
Raychem.
1-FCV-72-22
Cutoff
terminal
lug
laying
loose
in limit
switch
compartment.
Leose tiewrap laying in limit switch compartment.
Crimp on white-Black conductor on cable IV1872A, insviation
not uncer insulation on carrel.
T1 and T2 motor leads were enarrec.
_ _ _
__
- _ _ .
!
'
.
42
'
Motor lead T1 bend radius was not in accordance with
requirements.
The limit switch cover gasket seating surface was coated
with surface rust.
Wire 53 and 55 terminal lugs on rotor ten *nal 2 .4ere bent
,
in excess of 90 degrees between the ring and the lug
s
Crimps on CL1 (red) and 60 (black) conductors of IV.* 1559,
insulation not under insulation on barrel.
'
Motor leads T1 and T2 and wire 25 (white) conductor of
cable 1A5335 nave cable repairs us' ng electrical tape
rather than Raychem.
Cable identification tag was missing from cable 1A5335.
2 Terminals on rotor 1, contact position 1 were incorrectly
labeled as #53 and #55.
l
No additional findings.
1-FCV-72-20
I
l
Crimps on all conductors of cable IV1842B (except blue),
l
insulation not under insulation on barrel.
l
l
Hairline crack on unused rotor finger block.
.
Conduit identification tag broken on cable IV18408.
,
{
Cable 1A5388 was not tagged correctly,
f
Cable 1A18428 was not tagged.
Spare conductors were spared using electrical rather than
!
Raychem.
1-FCV-72-22
I
t
Cutoff
terminal
lug
laying
loose in
limit
switch
!
compartment.
l
Loose tiewrap laying in limit switch compartment.
,
Crirp on white-Black condu: tor on cable IVIS72A insulation
rot under insulation on barrel,
i
T1 and T2 motor leacs were enarred.
"
-
,
,
I
>
5
.
. - _ _ . ._______ _ ___ _ _ _ _
\\
'
.
'
43
Cable 1A5394 missing identification tag.
f
Spare conductors were spared using electrical tape rather
tnan Raychem.
1-FCV-72-40
Flextite conduit for cable 1A671 pulled out of fitting with
sharp edge resting on conductors.
Conduit fitting loose en flextite for IV2150A.
,
Crimp on T3 motor lug, insulation pulled out from under
insulation on lug barrel.
,
White wire (89) of cable 1A3224 has the same problem as
above.
Conduits 1A3224 and 1A671 missing identification tags.
!
Cable IV2743A mir. sing cable identification.
I
'
Wire 53 (green) and wire 55 (red) were terminated
incorrectly on terminal 16 of rotor #4 rather than 15 as
required by configuration drawings.
Spare conductor spared with electrical tape rather than
,
Raychem.
'-
'
1-FCV-72-41
Terminal nut laying inside limit switch compartment.
washer laying loose 'nside limit switch compartment.
r
A spare rotor block jumper wire 3 inches long with bare
.
terminal at both ends was lef t loose inside limit switch
.
r
compartment,
Crimp on white conductor (#89) of cable 1A3236 wire
[
insulation not crimced under lug barrel insulation.
!
Conduit 1A3236 missing 'dentification tag.
j
Cable IV1910B and IM237 missing identification tags.
-;
Spare conductor spared witn electrical tape rather than
Raychem.
(
,
f
!
- - -
.
- -
-
.
.
_ _ _ _ _ _ .
. _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _
.
,
I
44
L
1-FCV-72-2 and 1-FCV-72-39
Valve operators for these 2 valves were removed and were being
.
!
overhauled.
Inspectors surveyed the valve location in the
Unit 1, 714 ft level penetration room. The valve operators had
been disassembled in place and the operators were in the
mechanical shop.
The limit switch covers, limit switches,
,
torque switches, terminal boards, motors, nuts, bolts and
l
washers were located in the general ' work area on top of hanger
ICSH-5 near the valves about 8 feet above floor level.
Several
deficiencies were noted with regard to proper- in-process
handling, storage, and protection of safety related material and
equipment.
This was discussed with electrical supervisory
personnel; however, the condition remainad unchanged during tne
2 week inspection period. The following was noted.
t
I
The limit switches, torque switches, terminal boards, and
wiring remained exposed and unprotected in an upside down
[
limit switch compartment cover for both valves.
'
'
Nuts, bolts, washers, and other parts of the operator which
'
were not tagged or identified were stored loose under the
torque switch, limit switch and terminal blocks in the
limit switch compartment cover.
Lubricated gears on the torque switches were not protected
[
from damage.
[
Exposed lubricated stems on the valves were not protected.
'
Both operator motors were sitting on the hanger cross beams
p
untagged with exposed unprotected lubricated gears turned
upward.
One motor was tied off. The other motor was
.
cradled between hanger beams.
The hold tag
for 1-FCV-72-39 was attached to the
i
disconnected cable over the, valve rather than to the valve
!
as required.
i
All disconnected cables were hanging loose with no
!
!
protection for the safety related terminations.
Insulation damage was noted on the control power cable
,
conductors for 1-FCV-72-2.
During the period of the inspection, groups of 2 to 4
eaintenance .cersonnel
conducted replacement of mechanical
[
Oenetration seals directly above the valves and exposed parts.
!
'
The work platform for part of the caintenance cere the hanger
r
l
Deams that all of the parts were sitting on.
(
'
?
i
k
!
>
, - . _ . . - _ - . . _ - -
, - . . - . . . - _ _ - - _ - - . - . - _ . . - -
, _ _ - - . - . _- --
. -
- - I
_ _ _ _ _ _ _ - - - _ - _ - _ _ _ _
40
.
45
(2)
Electrical Control Boards
Containment Spray portions of the 6.9 KV shute wn ocards and
reactor ocards were inspected to determine that system circuits,
relays, breakers, fuses, and switches were properly installed
and that corrective and preventative maintenance had maintained
the electrical boards in accordance with procedures and
drawings.
Prior to the NRC inspection of the electrical boards
TVA had performed a pre-inspection of the same boards using
teams composed of DNE, maintenance, QC, modification, and system
engineering personnel.
NRC inspectors performed a
field
inspection verifying the TVA findings and in addition, found
several additional discrepancies that were not identified by
TVA.
NRC field insoections were conducted with electrical
maintenance superviscry and craft personnel.
The following
items were noted:
- = NRC identified
- = Identified during TVA pre-inspection.
6.9 KV Shutdown Board 1A-A, compartment 13.
Front compartment extremely dirty (up to 1/4 inch dust and
dirt in compartment bottom).
Rear compartment had been cleaned af ter the pre-inspection
but cleaning was inconsistent.
The front of current
transformer insulators was clean and wiped down, rear of
current transformer insulators was dirty, front of bus bar
insulators was clean, rear still had dust, etc.
There was improper bolting in front panel between motor
starter relays.
The lock washer and flat washer were
cocked preventing full contact with the panel.
One of two hinge pins on the front panel was not fully
engaged (seismic concerr.).
Some
"A"
phase current transforeer insulator screws were
missing.
Rear panel ec partment neeced cleaning.
One rear canel screw was rissing.
6.9 KV Shutdown Board IB-S, compartment 13.
'
One of two Mnge pins on frent carel daar was not fully
engaged.
Imere;er o:1 ting cetween este- starte- relays.
_ _ _ . _ _ _ - _
'
.
46
Front and rear compartment needed cleaning.
One wire was disconnected with no tag.
480V Reactor P.0V Board 181-B, compartment 13A
'
'
Green vertigree on breaker staves.
Cutofr terminal lug laying in rear of compartment 12 (seen
from rear of compartment 13)
,
One of two hinge pins on front panel door was not fully
engaged.
Bend radius violation on jumper wire for IFU4-72-28.
Front and rear compartments needed cleaning.
480V Reactor MOV Board 181-B, compartment 138.
One of two hinge pins was not fully engaged.
Cutoff tienrap was laying on top of a motor starter relay.
Loose screw was found on compartment floor.
Rear compartment needed cleaning.
Time delay relay (Agastat) was labeled as setting S.O to
8.5 seconds, drawing stated 10 seconds.
480V Reactor MOV Board 181-B, compartment 13C.
Bend radius violations on fuse block jumper wiring.
'
Front panel wiring 1 cop had a broken wire support, tiewraps
were substituted.
One of two hinge pins on front panel door was not fully
engaged.
Rear compartment required cleaning.
4SOV Reactor MOV Soard 181-E, ccmcartment 13E.
One of two hinge pins on front panel cover was not fully
engaged.
'
Rear of compartment neeced cleaning.
4S0V Reactor M0k Board 1Al-A. Comcartment 4E.
,
- , _ _ _ - - , . _ - _ _ - _ _ _
. -_ _ _
'
.
47
The T3 motor lead had a bend radius violation.
The breaker indicating light mounting bracket nad one loose
screw.
One terminal screw was laying in the bottom of the rear
compartment.
Pre-inspection noted no discrepancies.
450V Raactor MOV Board IB1-B, compartment 14A.
Inner frame member support in rear compartment not engaged
with inner frame.
Bend radius violations on fuse block jumper wires.
Several terminal lug connections on the board side of the
MOV control power terminal block do not meet acceptance
criteria for lug insulation crimped over wire insulation.
The 7 conductor control power cable for the MOV had a bend
radius adjacent to the terminal board.
There was green vertigree on the breaker staves.
Rear compartment required cleaning.
M and AI - 7. Cable Terminations, Splicing, and Repairing of
Damaged Cables implements TS 6.8.1 for establishment, implemen-
tation, and maintenance of procedures for the termination and
repair of safety related electrical components was reviewed.
Contrary to sections 3.4 and 5.2 of M&AI-7, motor lead T1 on
flow control valve 1-FCV-72-13 was not trained in accordance
with the required bend radius.
In addition, motor leads T1 and
T2, and white conductor wire 25 of cable 1A5335 have cable
repairs using electrical tapo.
This is a violation 327,328,
SS-29-02, example
1,
failure to maintain
safety related
alectrical equipment.
Green wire 53 and red wire 55 on 1-FCV-72-40 were not routed in
accorcance with Drawing 45N1749-15.
Tnis is a violation,
327,328/88-29-02, exanple 2.
Standard Practice SQA 66, Plant Housekeeping, implements TS
requirements and Nuclear Quality Assurance Manual part II,
Section b 1.2 Requirements for Procedural Control of Work
Activities. Section 5.3.2 of 52A 66 states snat if work extends
beyond one shif t,
and is not continuously worked the craftsman
snall ensure tne work area is lef t clean.
Tools, par ts, anc
ecuipment must ce properly icentified .itn area barrter
ag or
incividual pink tags.
It also states tnat special care snali ce
_ _ _ _ _ _ _ _ _ _ _
.
48
taken when opening or disassembling sensitive electrical
equipment whicn may be damaged oy dust or moisture. Contrary to
this
requirement,
components
for valves
1-FCV-72-2 and
1-FCV-72-39 were not tagged correctly, nor covered.
These
components were stored in an area where penetration seal work
was being conducted directly overhead.
This is a violation,
327,32S/83-29-02, example 3.
Maintenance Instruction MI-6.20, Configuration Control During
Maintenance Activities, impicments TS procedural requirements
for controlled reassembly ^# safety related components. MI-6.20
states that when a configuration change is returned to normal
the accuracy shall be verified and documented. Contrary to this
procecure, during an internal inspection of the limit switch
component
of
valves 1-FCV-72-41 and 1-FCV-72-22,
loose
extraneous material was identified in the internal of the limit
switch.
This is violation 327,323/83-29-02, example 4
The
loose material
which was
identified
in
violation
327,323/88-29-02, example 4 also constitutes a question with
respect to t e maintenance of the seismic qualification of the
equipment in accordance with IEEE 344 Recommended Practice for
Seismic Qualification of Class 1E Eculpment for Nuclear Power
Generating Stations.
IEEE 344 states that it must ce
demonstrated that the equipment is capable of performing its
safety function thecughout its qualified life including its
functional operability during and af ter an SSE at the end of
life. It further states that justification must be provided to
show that the equipment to be qualified is similar to the data
base equipment. If extraneous material has been left within the
qualified equipment, then the installed equipment may no longer
be similar to the data base equipment, test or calculation that
was originally used to support seismic qualification.
In addition to the discrepancies listed in violation 327,323/
83-29-02, examples 1-4, the discrepancies listed in the .MOV and
control board sections cf th!n report relate to inadequate
implementation of several sections of
M&AI-7, Cable Termi-
nations,
Splicing and Repair of Damaged Cables,
SCM-2,
Maintenance Management System, and SQA-66, Plant House Keeping.
The additional discrepancies icentifiec above recuire resolutior
prior to the startup of Sequoyah Unit 1.
Adequate corrective
action for violation 327.323/SE-29-02,
Failure to Paintain
Safety-Related Electrical Equipment, will include correction of
identified deficiencies,
evaluation
of
root
cause
and
appropriate action to preclude recurrence.
In addition adecuate
corrective action for the aDove een.ionec violatien shall
include a Quality Assurance review of the TVA pre-S$QE walk own
discrepancies an: the applicability of inose discrepancies te
other co ponents.
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ - _
.
49
(3) Cabling
Inspectors reviewe: cable routing rec *rds for the Containment
Spray system cables and performed on a sampling basis, a
physical inspection of 6.9 KV Containment Spray pump power
cables, and cable trty system associated with that system.
Cables and trays inspected were reviewed for divisional
separation, segregation, identification, loading, associated
cabling and cable condition. Mechanical aspects of the cable
tray supports are addressed in the support section of this
report. TVA perfor.*ed a cre-inspection of the cables and trays
for the 6.9 KV power cables for the IA-A and IB-B Containment
Spray pumps. During the pre-inspection, cable IPP637B (CS pump
1B-B 6.9 KV power cable) was found to be routed in tne wrong
tray for a distance of about 20 feet.
The cable lef t the
specified tray AA-B between nodes 5 and 6 and entered tray A0-B
between nodes 13 and 14.
The cable exited tray A0-B between
nodes 15 and 16 and entered conduit 1pP6378.
Inspcctors performed a physical
inspection of the
IA-A,
Containment Spray pump power cable tray AM-A between nodes 25
and 28.
Correct cable count and identification were verified
for this tray section.
No deficiencies were noted.
Inspectors performed a physical inspection of the misrouted
cable in tray A0-B on the 669 f t,
level of the auxiliary
building. Inspection of this tray section verified a portion of
the TVA walkdown on cable 1pP625A.
Inspectors performed a
physical inspwetion of cable trays A0-B between nodes 13 and 16
and AA-B between A10 and A12 and verified the misrouted cable.
Although the cable was misrouted and not in accordance with the
approved routing schedule, inspectors concluded that the routing
was
satisfactory with
respect
to
separation,
voltage
segregation, associated cabling, and Appendix R considerations.
Based on tray fill and cable count of tray 40-B in the area of
the misroute, it appeared that tray loading and ampacity would
be satisfactory.
It appeared that the niscouting was from
original plant construction.
Tray AA-8, the correct tray,
turned away from the area the cable needed to be routed and tray
A0-B continued in the required direction to about 5 feet from
the conduit entry point for Containment Spray pu p 1B-B cable.
Inspectors concluded that the miscouted cable presented no
operability or safety prcblems and that based on the tray
location and routing, the misrouting may have been an original
construction walkdown drawing error. Discussions with TVA staff
indicated that a Crawing Desistion request and a CAQR were ceirg
preparec to docu ert anc resoise tne issue,
inis issue .as
identified
as
a
ceficiency
and
proviced
for
licensve
infor:ation.
. . . _ . . .
_ _ _ _ _ _ ___ _--__ _ _ _ _ _ _ _ - _ _ _ _ _ __
_
_ _ _ _ _ _
i
.
,
50
c.
Documents Reviewed
Tne inspector reviewed the cocuments listed as reference 1-19 during
the design review of the ele:trical sy3tems identifie
in the scope;
l
(1) Final Safety Analysis Report (FSAR) - Chapter S.
(2) Technical $pecification. A. mend ent 64 - 3/4.8 Electrical rewer
L
Systems - Table 3.3-4 Engineered Safety Features Actuation
System (ESFAS) Instruments Setpoints.
(3) Safety Evaluation Report on SequoyLh Nu: lear Performance Plan,
NUREG -1232. Vol. 2, May 1958.
(4) Sequoyah Unit 2 Integrated Oesign Inspection (10?.), November 6
j
1987.
(5) 6200V Unit Board Load Coordination Study PSO Plant Section RS
Calculation, Revision 3/SS.
(6) 4SOV AC Class 1E Load Coordination Study, Revision 11,
<
(7) Sargent & Lundy ELMS AC Program - Load Flow, Short Circuit
2
i
Currents & Voltage, Run 6/20/S3.
(8) 05-ES.I.1, Electricat Design Standard for Substitution of Low
]
Voltage Power and Control Fuses, Revision 8/IS/87.
(9) AI-16, Administrative Instruction for Fuse Control, Revision 12,
i
(10) SQEP-34
Engineering Procedure for Implementatien of the
l
Electric Fuse Tabulation, Revision 10.
(11) Data Sheets. Sequoyah Fuses in System 72 Containment Spray
System.
(12) Purchase Specift:ati ns:
9617 Steam Turbogenerators and Reactor Feedpu p Turbines.
9841 Main Power Transformers and heutral Raactors
9S77 Common and Unit Statien Service Trarsformers.
1166 Diesel Engine Ortven Erergen:y Pe.er Packages.
1101 6900 volt Auxiliary Po.er Switchboards,
,
1135 430 soit S. itch: card and Transferners.
t
l
1200 480 voit Motor Control Centers (M;C).
!
1153 Electric Motor Ortsen Containment Spray Puros.
9923 Principle Piping Systens and Apourtenance. (original
POV (parcnase)
MEE-SS10.10 Motor Coerated valve Motor C:erate .
'
(repla:e ent)
i
j
I
4
$
v
- . ,--- . - .
_vy#--,
-
.,,.m.,__
_ _ _ _ _ .
__ . __ _ ________
__ _ ___________ ___ _ _
-
'
l
.
51
(13) Vendors Test Data:
'
main generator
-
.,
i
'
unit & common station service transformers
,
6.9KV switchgear
,
480V switchgear
,
4SOV motor control center (MCC)
'
250V MCC control fuses
-
(14) L6SS3, Engineering Change Notice for Molde6 Case Breaker
f
Replacement and Thermal Overload Bypass.
!
L
(15) SON-CSS-019, Agastat Accuracy During a Tornado Depressurization.
i
(16) FIRL No. F-A5S44, Franklin Institute Research Report for AMERACE
Corporation on Depressurization Tests of Agastat Series E 7000
Time Delay Relays, September 28, 1933.
.
!
(17) IS Surveillance Tests:
,
SI-7, Diesel Generator (DG) revision 41 -DG 19-B 6/11/SS.
j
-
'
SI-26.1A, Loss of Offsite Power with Safety Injection,
-
Revision 13, DG 1A-A 6/22S7, 6/30/87/7/4/87.
SI-26.18, same as above except Revision 9. DG 18-B 10/13/85
i
-
!
$1-233 DG Battery (BAT) System Cperability, Revision 19, DG
-
l
SI-233.1 DG BAT Weekly Test, Revision 14
All DG BA'.
j
-
11/13/83.
S!-238.2 OG BAT and Charger Performance Test, Revision 7
-
DG 2A-A 5/6/S7, C3 1A-A 5/6/S7.
SI-238.3 DG BAT Annual Systwn Inspection, Revision 0, 03
l
-
1B-B S/20/S7.
t
!
i
SI-100.1 125V Vital EAT Weekly Inspection, Revistor 17, all
t
-
BAT 4/11/88.
j
$1-100.3 125V Vital BAT Annual Inspection, Revision 0,
l
-
Vital BAT 4 3/1/SS.
!
,
SI-ICS
125V Vital
BAT 60 Month Perforrance Test.
i
!
-
!
Revision 15, Vital BAT 1 Test 7/22/S5, Vital BAT 2 Test
[
!
5/2S/S5, Vital BAT 3 Test 3/27/S5, Vital BAT 4 Tes.
2/15/SS.
!
!
,
!
[
'
i
I
. _ - _ _ _ - _ _ _ _ - _ _ ___ - _ _ _ _ _ _ _ _ _ _ .
,
52
SI-251.1 MOV Thermal Overload Test. Revision O. 1-FCV-72-20
-
Test 12/19/53, 1-FCV-72-21 Test 12/6/53.
S!-270.1
Fuse
for containment penetration conductor
-
overcurrent protection
surveillance,
Revision 0,
10%
rotating sample 18 month test 3/10/87.
SI-256 Periodic calibrstion of overcurrent and ground fault
-
relays on reactor coolant pumps amd backup devices on 6.9
KV unit board, Revision 10, 72 months test.
SI-258 480V circuit
breaker containment penetration
-
conductor overcurrent protection, Revision 0,10% rotating
sample 18 montn test.
SI-266 6.9 KV circuit breaker inspection and preventative
-
maintenance reactor coolant pump A test.
(18) Cable Data for the following:
Node Number
Cable Number
Node Number
Cable Number
8
1PP625A
122
1PL5075B/1
8
1PP756A
122
1PL5076B/1
8
IPP759A
122
1PL5077B/1
8
IPP750A
122
1PL5075B/1
9
IPP637B
122
1PL49459
9
IPP762B
247
IV1870A
9
1PP7658
247
IV1830A
9
1PP753B
247
IV3160A
13
1PP10552/1
247
IV2S20A
13
1PP10652/1
249
IV2830B
13
1PP10752/1'
249
IV3150B
14
IPP11051/1
249
IV1840B
14
1PP11151/1
249
IV1850B
14
1PP11251/1
449
IPL5047A/1
119
IPL5051A/1
449
IPL504SA/1
119
1PL5052A/1
449
IPL5049 A/1
119
1PL5053A/1
449
IPL5050A/1
119
IPl5054A/1
450
1PL5055A/1
119
1P'4935A
450
1PL5056A/1
120
1PL5059A/1
450
1PL5057A/1
120
1PL5060A/1
450
1PL5053A/1
120
1P L5061 A '1
453
IPL50633/1
120
1PL5062A/1
453
1PL5064B/1
120
1PL493SA
453
1PL5065B/1
121
1PL5067B/1
453
1PL5056B/1
121
IDL50655/1
455
IPL50712/1
121
1PL50693/1
455
!cL5072B/1
121
IPL507:3/1
455
1PL50735/1
121
lEL'9c23
'55
PL53743J1
_ _ _ _ _ _ _ _ _ _
__
'
.
53
i
(19) Orawings
15E500-3, Revision A, Transformer Taps & Voltage Limit AP5
-
15E500-1, Revision H Key Diagram One Line APS
-
15E500-2, Revision I, Key Diagram One Line ASP
-
45N713, Revisian K, Station Serv, Trans. & Bus
-
45N721-1, Revision W, 6.9KV Uni
Boarcs (80) 1A & IB
-
45N721-3, Revision E, 6.9KV Unit BD 1C & 10
-
45N724-1, Revision Z, 6.9KV Shutdown (50) B01A-A
-
45N724-2, Revision 2, 6,9KV $0 BD 18-8
-
45N749-1, Revison RO, 480V SO B0 1Al-A
-
45N749-2, Revision QQ, 4SOV 50 B0 1A2-A
-
L
45N749-3, Revision TT, 480V 50 B0 181-B
-
45N749-4, Revision RO, 480V $0 80 182-8
-
45N751-1, Revision TT, 430V reactor motor operated
-
valve (RMOV) BD 1Al-A sheet 1
45751-2, Revision JJ 4SOV RMOV B0 1Al-A sheet 2
-
45751-5, Revision 00, 480V RMOV B0 IB1-B
-
45N700-1, Revision R. Key Diagram 120VAC & 125VDC
-
Vital Plant Control Power System
45N703-1, Revision UU, 125V Vital Battery (VB) B0 1
-
45N703-2, Revision RC, 125V VB BD 2
-
45N703-3, Revision RO, 125V VB BD 3
-
45N703-4, Revision 00, 125V VB BD 4
-
45N763-7, Revision J. 6.9KV Unit Auxillary Power
-
45N763-1. Revision J, 6.9KV Unit Aux Pwr 00
-
45N763-2, Revision P, 6.9KV Unit Aux Fwr
-
45N765-1, Revision Q, 6.9KV Unit Aux P*r Sneet I
-
. _ .
_ _ _ _ _ _
,
.
54
45N765-2, Revision Q, 6.9KV Unit Aux Pwr Sheet 2
-
45N765-3, Revision AA, 6.9KV Unit Aux Pwr sheet 3
-
45N765-4, Revision R, 6.9KV Unit Aux Pwr Sheet 4
-
45N765-5, Revision CC, 6.9KV Unit Aux Pwr Sheet 5
-
45N765-7, Revision RO, 6.9KV Unit Aux Pwr sheet 7
-
45N765-8, Revision 0, 6.9KV Unit Aux Pwr Sheet S
-
45N765-9, Revision J 6.9KV Unit Aux Pwr Sheet 9
-
45N765-18, Revision II, 4SOV SO Aux Pwr
-
.
45N779-8, Revision II, 480V SD Aux Pwr
-
45N779-10, Revision RO,4SOV SO Aux Pwr Sheet 10
-
45N779-11, Revision V, 480V SO Aus Pwr Sheet 11
-
45N779-25, Revision V, 4SOV SD Aux Pwr Sheet 25
-
45N779-26 Revision T, 4S0V SO Aux Pwr Sheet 26
-
45N1749-15 Revision W, 480V RMOV B0 1Al-A Sheet 8
-
45N1750-5, Revision F, 430V RMOV B0 1B1-B Sheet 5
-
45N1750-13 Revision K, 430V RYOV B0 IB1-B Sheet 7
-
3.
Instru entation and Control (Design Evaluation)
In each of the following sections the design phase of the inspection
evaluated the system and components against select requirements as
indicated in the report,
a.
Instrument Verification
The design aspects and application of the following instruments were
reviewed:
PDT 30-42 Containment / Annulus Differential Pressure Channel IV
POT 30-43 Containment / Annulus Differential Pressure Channel III
POT 30-44 Containment / Annulus Differential Pressure Channel II
POT 30-45 Contain.ent/ Annulus Differential Pressure Channel I
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _
.
55
b.
Interlock and Control Functions
(1) The operability of tne C5 pumo miniflow protective circuit was
evaluatec,
This circuit protects tne pump Oy allowing pump
cischarge to be circulated back.to the pump intake if flow in
the discharge
line drops below that reouired for pu p
operability. The flow is measured by fhw elements FE-72-34 or
13, and if upon starting, flow is not acnieved in the spray
header within a preset time interval, the circulation is back to
the intake.
The flow elements are ANNUBARs.
.
The design evaluation of the miniflow control channels revealed
the following:
inspectors reviewed the specifications for tne
flow channels used for measuring containment spray flow; this
measurement is used for flew indication, and at the lower end of
its range, provides a signal for miniflow control. . Inspectors
also reviewed schematic diagram 45N779-26 nevision T.
dated
January 16,
1983, vendor loop diagram (GE) 0-30C0K13-513
sheet 9, Revision E, instrument accuracy calculation 1-FT-72-13
,
Rey, 4 dated April 30, 1988, and ECN 6674 Revision 1 dated
April 30, 1933.
The inspector identified several miniflow control issues. These
issues regarced the ability of the miniflow control to function
,
as described in the FSAR under all cesign basis conditions, the
"
accuracy of the flow indication presented to the operator, and
j
the implications for any other safety-related systems using
l
Annubars.
I
First, the use of an Annubar for measuring flow during the
containment sump recirculation phase does not assure a
,
functional system, since the ports and plenum of the element
could become blocked by pcst-accident debris or particulates
'
from the sump.
The TVA specification did not stipulate debris
and particulate as a design basis.
If the upstream ports were
blocked, a false low flow measurement could result, which would
,
!
open the miniflon vahe at normal flow values rather inan at the
low flow setpoint.
This would divert flow from the spray
headers, and could occur concurrently for both C5 system trains.
Overriding the flow signal from the cont"ol room (i.e., closing
j
the valve) must be cone by holding down tM mo entary action
I
control switenes, making corrective action difficult.
The consecuences of diserted miniflow are discussed in Srction
1.j.3 of this report. In addition, inaccurate flow irdications
,
in both CSS trains would be presented to tne operator for
serifying containment spray flow; this verification is recuirec
i
i
by Emergency Instruction ES-1,2, "Transfer to RHR Containment
I
Suvo". Rev. 5, catec January 12, 1958. Inis issue is cesignatec
URI 327,323.'55-29-06, Example J.,
anc recuires resolutien prior
'
!
to the startuo of Seanyar Unit 1.
Aceauate resolutten fee tne
!
aoove URI snall irc hce an Engineering Assurance revie, c' tne
'
design casis information t elatec to this issue.
._. . . _ _ _ _ _ _ _ _ _ _ .__ _ _ _ _ _ _ _ _
__.
_
. _ _ _
_
_
, _ .
'
o
.
$
56
i
!
Second
ECN (674 reported structural inadequacy of the original
Annuoars which had one-sided support; that ECN replaces the
original elements with Annubars having two-siced support.
Discussions with TVA staf f indicated snat ene original Annudar
had been damaged in service.
Inspectors requested that TVA
i
crovide a root cause and extent determination for the original
failure of the Annubar element to provido assurance that
problems do not exist for cther safety-related systems.
This
,
issue is designated URI 327,328/SS-29- % , Exaeple
k.,
and
i
requires resolution prior to the startup of Sequoyah Unit 1.
i
Aceouate resolution for the above URI shall include an
l
Engineering Assurance review of the design basis informat' ion
related to this issue.
!
I
Third, it was noted that it was not apparent that element errors
!
due to process upstream / downstream flow conditions were
l
accounted for.
These errors would take into account installed
upstream / downstream straight run, tees, elbows, and other
!
significant disturbances that could result in repeatability
!
trrors
related
to
the
velocity
profile.
Subsequent
documentation of the installed conditions was retrieved by TVA,
r
indicating that the downstream conditions were not within the
i
ieference conditions
stipulated by the vendor
for
the
i
repeatability specifications quoted.
'
This issue was identified as a deficiency and provided for
,
licensee information.
l
P-
It was also noted that the setpoint calculation concludes that a
i
!
setpoint of at least 1200 gpm is required, due to an assumed 5:1
turndown ratio for the element (due to the square root
)
relationship of differential pressure to flow).
However, the
l
actual setpoint indicated on the current instrument tabulation
i
is 500 gpm, which is below the region of accurate measurement.
[
TVA explained that the instrument tabulation will be updated to
l
reflect
the
higher setpoint after the modification is
i
implemented,
Inspectors concluded this action was acceptable
and in accordance with TVA peccedures.
'
(2) An inspection was performed to verify the existence of an
i
interlock between FCV-72-23 and 22 for CS A train and FCV-72-20
and 21 for C$ B trair,.
Tne function of this interlock is to
.
prevent the CS pump f rom taking suction from the RWST and the
i
containment sump at the same time.
l
l
'
Inspector s reviewed schematic diagrams 45N779-S Rev. II, dated
i
I
February 15,195S, 45N779-25 Rev. W,
dated February 15, 1955.
L
and 45N'79-11 Rev. V, cated March 11, 1933, tha% Cescrib? the
f
interlock provisions for RWST outlet salves 72-21 anc 72-22, as
i
well as containeent sump isolation valves 72-20 anc 72-23. Tne
r
i
I
>
.
57
review included three inauiries to TVA regarding the manual
suction transfer scheme.
The inspector note: a safety evaluation assumption cited in
SQN-DC-V-27.5, Rev. 2, paragraph 3,9,1, wherein 110 seconds
'
-
is assumed from CS pump shutoff to pump restart. TVA was
/
asked to provide the basis for a manual switchover (rather
than an automatic switchover) in light of this apparent
requirement for operator action within less than 2 minutes.
TVA clarified the statement in SQN-0C-V-27.5, stating thtt
the 110 seconds is not a limiting value f;r the manual
switchover, but rather represents their evalvation of the
operator action sequence time as described in FSAR Table
6.3.2-5.
It was further stated that the )$miting value as
determined by the containment pressure an 1ysis t is 310
4
seconds, per Table 1 of the "Westinghouse Report for the
SNP Units 1 and 2 Containment Pressure Calculations with an
Extended Containment Spray Pump koading Delay" cated
June 1987.
Considerti,g that the switchover is a manual
preplanned
operation prescribed by procedures,
the
inspector concluded that the requirement for manual actua-
tion within 310 seconds was acceptable.
The inspector noted that a postulated single failure to the
MOV circuits of inttrest might result in connection of the
containment sump and RWST through a single train of valves.
The inspector asked that TVA address the consequences of
this postulated event and demonstrate that the consequences
were within the design basis.
TVA demonstrated that the
consequences of the postulated failure would be an early
switchovt- to sump recirculation (since the RWST level
would drop more rapidly prior to switchover). The FSAR in
section 7.6.6 takes credit for measures that would preclude
spurious actuation of SIS sump valves 63-72 and 63-73;
therefore, we do not include spurious actuation of these
valves in our postulated scenario.
Accordingly, these
valves may be assumed to recat. closed until recircu'ation.
Following switchover, TVA demonstrated that no loss of
inventuty would
result,
spray
flow would not
be
interrupted, and spray temperatures would be within design
values (since ice melt would not be cceplete).
TVA was
aste
to demonstrate that any release paths to atmospnere
(via the RWS f) during this postulated single failure have
been adequately addressed, taking into account check sal,e
leakage.
This issue is designated URI 327,328/8S-29-06,
Example
!..
and requires resolution prior to the startup of
Seonoyah Unit 1.
Adecuate resolutien for the abeve URI
small ',nclude an Engineering Assurance review cf tne cesign
basis information relattd to this issue.
-
._
-
_ _ _ _ _ - _ - _ _ _ _ _ _
1
-
,
58
,
i
l
'
The interlocks that prevent operation of the sump iselation
valves are bypassec ey a "seal-in" wnile the sump valve is
j
opening.
Consecuently, there is a very brief interval
,
where the Ed$T cutlet valve could be reopened from tne
i
control room, defeating the interlock.
However, this
vulnerability is limited to a short interal during the
!
first (nominal) 5*. of sump valve travel, dwing which the
i
postulated overriding operator action would need to be
1
taken to defeat the interlock.
Also, if this were to
!
occur, the corresponding interlock in the RWST valve
!
circuit would be cuickly reinstatec, limiting the RW57
,
valve travel for this event. Emergency Instruction (EI)
ES-1.2, Transfer to RHR Containeent Sum, Rev. 5, dated
January 12, 1955, explictly prescribes the seivence of
!
operator actions required to achieve the manual transfer.
Operating the valves in the postulated manner would violate
the Emergency Instruction.
TVA's response noted that check valve 72-505 is prov'ded as
a second isolation point for the postulated release path
a
h
(Reference FSAR Yable 6.4.2-8).
They stated that this
i
check valve was raanufactured and tested to an acceptance
criteria of 24 cc/ hour of seat leikage, and the valve is
maintained under the ASME Section XI valve testing progre
to assure operability.
In addition, a water leg is
,
1
maintained from the RWST that provides in additional
ba r r'i e r to the ateosphere.
The inspector found TVA's
respenses to be acceptable.
The inspector concluded that this limited vulneN.bility for
defeat of the interlocks is acceptable since nJfeat would
require violation of the E! by the eperator and wtuld only
be possible for only a very brief time interval.
Based on the foregoing review, the design of the interlocks
appears to be acceptable pending a satisf actory re aiution
of URI 327 323/55-23-06, E m ple 1.
(3) An inspection of the design of the provisions fer the acto?atic
activation of the C5 system was performed. The syster is cased
on activation of two out of four of tne contain ent ht/hi
pressure channels.
The insccctor revie ed seseral d e s i g r,
attributes for these
channels against governing cesign requirements.
F5AR 7.3
incluces the chann=t functional, perfor~ence, aad testing
require ents.
The teat cetemined fre? TVA trat the rack
rounted anale; ins'.rw entatien, actuatice lo;ic, and E5' test
caDinets supporting tre CSS actuatten signals
ere of a gaceric
casign proviced d>
the N555 verme anc previously revie t: Dy
_ _ - _ - - _ - - - - . _ _ _ _ _ _ - _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _
.-
_ _ _ _ _ - _ _ __- _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ .
I
.i
.
?
r
j,l
59
r
i
'
'
,
y
i
the NRC staff.
On that basis, we focused our review on the
field instrumentation.
,
t
TVA verified that no hign energy line breaks requiring
[
mitigation by containment spray or high containment pressure
!
initiate safety injections would cause common mode failure of
l
the containment / annulus differential pressure instruments.
On
this basis, the physical separation provided by the 4 field
,
,
instrument racks appears acceptable.
With regard to seismic
j
l c,
supports for the impulse line tubing, TVA is verifying this and
4
l
other field routec tubing as a cart of TVA's longer ters
cce:.rf tment to verification of field routed instrument lines
against engineered installation criteria.
With regard to
.
potential offects on response tiee. TVA reported that tre
sensing lines are 1/2" schodule 80 piping having maximum length
of about 20 feet, the penetrationt, are 3/4" schedule 160, and no
restrictions exist in the lines.
On that basis, inspectors
concluded the lines would not adversely affect response time.
l
l
The inspector noted that TVA is currently replacing the
differential pressure transmitter 1-PDT-30-44 with Foxboro Model
NE130M.
The de cnstrated accuracy calculation dated April 10,
1938, for these new ;ransmitters indicated a range of -1 to 13
psig which was less than the range stipulated in FSAR Taole
7.5.1-2.
TVA determined that this was an isolated typographical
,
!
error appearing once in the calculation and did not affect the
results.
TVA will correct the calculation document.
It was also noted that the au.uracy calculation establishes the
tolerances
for post-accident indication and not for the
actuation signal setpoint. TVA indicatea that the tolerance for
the actuation signal value is determineo by WCAP 11239 Rev. 2,
dated Septe-ber 1986,
TVA was asked to confirm that the new
transmitters are bounded by WCAP 11239 and to more explicitly
demonst, rate or elsrify the margin between the actual setpoint
value and the measured value.
TVA retrieved NS$5 vencor
,
dc;;u:entation cemenstrating tc the team that these aspects of
i
the tolerance ralculations were properly covered by t.he vendor's
support of WCAF 11239.
TVA was asked to provide assu ance that obstruction or isolation
of the lines would net go unottactec, noting tnat the traes-
mitter process input simulation for test purposes is r4 ported to
be do9e at the instru ent rack.
If the untested pettions of the
lines were blocked and not detected, automatic initiation of
containrent spray and automatic initiation of safet,y injection
en high containrent pressure a uld be cefeated.
This issue is
cesignated URI
327.3.'$'51-2 N 6,
Exa Die m.,
anc re wires
resolution prior to tne startuc of Sea;.oyah Unit 1.
3: m ate
resolut4 CM for tre aboit MI small include an Enginded g
l
l
. ]
i
<
'
,
W
,
60
Assurance review of the design basis information related to this
issue.
,
(4) An inspection was performed to verify the discharge isolation
I
valve / pump inte,' lock for one CS train.
Inspectors reviewed schematic diagrams 45N779-10 Rev. O dated
6/1/88 and 45N765-7 Rev. O dated 4/8/88. The interlock were in
conform nce
to
the
requirements
of
6.2.2.5
and
SQN-DC ,-27.5 Rev. 2, para. 3.9.1, and acceptable on that basis,
c.
The following CS instrumentation design criteria were evaluated:
(1) The response time cesign cnaracteristics of the CS system witn a
containment pressure initiation signal was evaluated.
Inspectors examined the overall design of the CSS actuation
signal charnels, noting that the hardware and configuration of
the analog signal conditioning and actuation logic was of a
generic design provided by the NSSS vendor and previously
reviewed by the NRC staff. On that basis, the response times of
the analog signal
conditioning,
function modules,
logic
circuits, and master / slave output relays would be expected to
have an acceptable design basis for use in the containment spray
system.
Similar hardware in the system is used to provide
reactor trip and safety injection signals, for example.
The design of the containment / annulus dif ferential pressure
transmitters and impulse lines was also examined (as reported in
item 3.b.(3), and it was concluded that the design basis for the
'
response time of these instruments appears to be bounded by the
design basis described in FSAR 7.3, and is therefore acceptable.
(2)
he design relationship between the SI system and the CS system
shile in the recirculation mode is described in design document
SQN-0SG7-008.
This design document addresses the containment
sump minimum level at the time of switchover to the recir:ula-
tion mode and the allowable margin for RWST level instrument
inaccuracy for a large LOCA.
(3) Design Evaluation of RWST Level Channel Accuracy
Inspectors checked instrument accuracy calculation 843871001915,
RWS1 Level, Rev. 5.
dated October 1,
19S7.
This calculation
established the demonstrated a; curacy for RWST level channels
1-LT-63-50,-51,-52,53 which are used for automatic switchboard
and lo-lu clarm.
Those instrument channels al>o include level
indicators.
Tne TVA instrmtent calculation appears to establish different
(but coma consereative) values than WCAP 11239 Rev. 2. anc TVA
w
.
_.
_-
'
.
61
was ask to demonstrate that there were no inconsistencies in the
approach and that the TVA methods are intended to be generally
consistent with WCAP 11239 reinocology.
In addition, a review was conducted of interfacing instrument
accuracy assumptions embodied in TVA calculation SQN-0SG7-0008,
Containment Sump Minimum Level at Time of Switchover to
Recenciliation Mode for a large LOCA, Rev. 4, dated May 6, 1988.
The review of these assumptions identified that slightly less
conservative accuracies were assumed in SQN-0$G7-0003 for the
automatic switchover (low level) and alarm (low-low level)
signals
than were demonstrated by the
latest revision
(Revision f) to the instrument calculation. This appears to be
a case where the latest revision of the instrument calculation
was
not used.
The
consequences
of
this
error
are
nonconservative, but are insignificant with respect to safety
(less than 2000 gallons volume and approximately 2 inches water
of NPSH).
However, the programmatic issue of maintaining
current calculation cross references should be addressed by TVA.
We understand that TVA will
issue a PIR addressing and
correcting this inconsistency.
It was noted by the team that if the indicators shown in the
instrument calculation were used for post-accident monitoring
(PAM), the indicator channel accuracy does not appear to be
within the plus or minus 3'; of span specified in FSAR Table
7.5.1-2.
TVA was asked to demonstrate that the PAM RWST level
indicators meet the FSAR requirements.
In addition, TVA should
demonstrate that the RWST level indication used for TS opera-
bility determination
(i.e.,
assurance of adequate RW9T
inventory) has been properly assessed for demonstrated accuracy.
This item remains open pending TVA's clarification of the WCAP
11239 results, issuance of a PIR regarding the calculation
discrepancy, and demonstration that the RWST level indication
channels and allowable values for PMis and TS values have been
properly assessed for the ef fects of instrument errors.
This
issue is designated URI 327,323/88-29-06, Example
n.,
and
requires .esolution prior to the startup of Sequoyah Unit 1.
Adequate resolution for the above URI shall
include an
Engineering Assurance review of the design basis infor.tation
related to this issue.
4.
Component Environmental Qualification Irapection
a.
Field walkdowns were conducted on selected Containment Spray motor
operated valves, instruments, motors, penetrations and electrical
'
equipment.
All Raychem splices encountered in notor operatec valves
were inspected for evidence of deterioration, camage, overlap, terd
radius, and nuclear sealant at the wire / Ray:nem interface.
.imit
.
_
_
_ _ _ _ _ _ _ _ _
_ _ _ .
. _ .
_ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _
.
62
switch covers, gaskets and gasket sealing surfaces were inspected for
condition and damage.
Instruments were inspected for broken
conduits. loose connection boxes, and loose trahw.iite /;nJicatec
covers.
Junction boxes and conculet covers were not removed to
inspect Raychem splices. Containment spray pump motors, penetrations
and other electrical equipment were physically inspected during the
walkdown.
Issues identified in the environmental qualification walkdowns were
limited to improper wire repairs within Containment Spray motor
operated valves. The specific details a-e discussed in section 2 of
this report.
The issees involved use of electrical tape to repair
damaged MOV internal wiring,
b.
EQ binders for the following components were sampled for anomalies
with EQ design bases and other engineering criteria (such as
environmental data and component functional requirements):
(1) Containment Spray Pump Motor (SQNEQ-MOT-001 Rev.10, March 11,
1988).
(2) MOV 1-FCV-72-20: Sump isolation to CSP suction MOV 1-FCV-72-22:
RWST isolation to CSP suction (SQNEQ-M0V-004 Rev. 15, May 6,
1988).
(3)
1-FT-72-13, -34: CSS Header Flow Transmitters (SQNEQ-XMT12-003,
Rev. 13, May 19, 1988).
No anomalies were found in the binders, and they appeared comprehen-
sive and readily auditable.
However, a potential programmatic
problem was identified regarding possible use by engineering of "as
constructed" environmental data drawings (47E235 series).
In the
review, the inspector used "as-constructed" drawings provided by TVA,
and noted technical errors on those drawings regarding post-accident
integrated dose for certain plant areas; these areas were incorrectly
identified as mild radiation (<10' Rad). More current "as-designed"
drawings subsequently retrieved by TVA had correct information.
Tne
inspector had a concern regarding the possibility that a design
engineer might nistakenly use the obsolete "as-constructed" drawings
and incorrectly specify the 59rvice environment for new equipment.
The licensee currently has a comorehensive drawing control and
upgrade program in progress.
This issue was identified as a deficiency ano ;rovided for licensee
information.
5.
Maintenance and Housekeeping Inspection
Inspectors performed a verification on a sampling basis of the adecuacy of
the mair.tenance program as applied to the CS system..
Tne following was
consicerec:
.
63
Management / supervisory involvement.
Maintenan n instruction enhancement.
Preventative maintenance.
Maintenance *, raining.
Ade uacy of recent work requests performed on the system.
Review of work requests encountered during walkdowns.
Inspe: tion for maintenance condition of system components (leakage,
integrity,
bent
stems, missing or imprope- fasteners, mounting,
preservation, hazards) during walkdowns.
The inspector verified the adequacy of all hold orders associated with the
Containment Spray System. The inspector reviewed selected completed work
requerts for acequacy and reviewed the licensee's work control printout of
all open work requests on the Containment Spray System. No discrepancies
were noted in any of the maintenance activities reviewed by the inspector.
The inspector reviewed 'he licensee's preventative maintenance program as
it applies to the containment spray system.
The inspector determined
through discussions with the licensee that a PM upgrade progr_m is
presently in progress to improve and standardize the PM program and
procedures. The first phase of this improvement program is scheduled for
completion prior to the end of 1938.
The program apoeared to be
adequately implemented.
The inspectors conducted a housecleaning inspection of the Unit 1
containment spray pump rooms, heat exchanger (HX) rooms, and pipe chases
and had the following observation.
Large amounts of insulation were
scattered about the pump and HX rooms and the 690 pipe chase.
The
insulation removal was a result of ongoing work. The overall cond',cior
f
the plant was acceptable with respect to housekeeping with the exception
of maintenance discrepancies on motor operated valves discussed in Section
2 of this report.
6.
Structural Supports
Design and in plant field observation phases of tne inspo: tion were used
to evaluate Unit 1 for proper design and design implementation relative to
structural supports.
In each of the following sections, the design phase
of the inspection evaluated the system and components again:t the appli-
cabl9 standards listed at the end of this report and the SYSTERS/ design
basis reports for the Unit 1 CS system.
The inspectors walked down the CS system and selected a number of
hydraulic and mechanical snubbers, other pipe supports, cable tray
supports, and equipment foundations for a detailed review.
The detailed
review was performed to verify whether or not the installation was in
accordance with design drawings and that the installation was techni: ally
adequate.
l
l
.
.
.
_ _ - _ _ _ _ _ . --
.
...
--
_
_
_
_
_ _ _ _ _ _ _ _ _
_
_
_ _ _ _ _
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
'
,
.
64
The inspectors reviewed the con struc tion specifications related to
structural steel ano support activities, including welding, to ascertain
whether the specified technical re q ui reme r.t ; ce,, form to the commitments
contained in Chapter 3 and 5 of the FSAR, aesign document SQN-DC-V-1.0,
and other design documents,
a.
Pipe Snubbers and Other Pipe Supports / Restraints
TVA's program to review the rigorously analyzed piping and supports
for Sequoyah Unit 1 was presented to the NRC on April 14, 1988. As
noted in TVA's presentation, TVA's program philosophy for this review
uses the similarity between Units 1 and 2,
addresses open NRC
Bulletin 79-14 items, and performs an integrated evaluation of
as-built data, nonconformances (CAQRs, NCRs, PIRs, SCRs), and
as-built discrepancies.
The specific elements in TVA's review program include field
walkdowns, a review of the calculations of record, and revisio;i or
regeneration of these calculations as warranted, and modificat'ons to
supports performed pre- or post-restart.
The scope of TVA's program includes the review of 25 safety-related
piping systems, 162 piping analyses, and approximately 2900 pipe
supports. Specific program procedures, originally implemented for
TVA's program to regenerate the pipe support calculations for Unit 2,
include:
(1) Civil Engineering Branch Instruction CEB-CI21.80, Program Plan
for Calculation Regeneration of Pipe Supports on Rigorously
Analyzed Category I Piping - Sequoyah
2,
Revision 1,
dated
August 28, 1987.
(2) CEB-DI21.81, Generation and Control of Rigorous Analysis Problem
Connectivity Diagrams for Category I Piping: Sequoyah 1 and 2
Revision 2, dated March 17, 1988.
(3) CEB-DI21.83, Functional Verification of Supports for Rigerously
l
Analyzed Category I Piping:
Sequoyah Unit 2, Revision 4, dated
l
March 17, 1988.
I
(4) CEB-CI21.84, Control of Correspondence and Transmission of
Design
Documents
Between
and
Engineering
Services
Contractors, Pevision 2, dated April 26, 1988.
(5) CEB-0121.85, Generation of Pipe Support Design Data - Sequoyah 1
and 2, Revision 3, dated April 25, 1988.
(6) CEE-Cl21.SS, Control of Incut and Output from sne Sqn Hanger
Tracking Subprogram of CCRIs (Sequoyan Nuclear Plant Only)
Revision 1, dated October 19, 1957.
. . _
_____ _
,
65
(7) CEB-CI21.89, Modification Priorities for Pioe Suoports on
Ricorously Analyzed Category I Pining - Sequoyah Units 1 and 2,
Revision 3, dated April 7, 198S.
(8) CEB-CI21.90, Gang Hanger and Terminal Anchor Procedure -
Sequoyah Units 1 and 2, Revision 1, dated March 17, 1988
(9) CEB-CI21.91,
Pandling
of
Pipe
Support
Calculation
Review / Regeneration Results - Sequoyah 2,
Revision 0,
dated
December 18, 1987.
(10) CEB-C121.92, Red Lining of Pipe Support Orawings, Sequoyah 2,
Revision 0, dated December 14, 1987.
Revision 4 of CEB-DI 21.83 notes that piping functional verification
of Unit 1 will be performed in accordance with TVA SQN Special
Maintenance Instruction SMI-0-317-69, Performance of Walkdowns for
Verification of Plant As-Installed Configuration, Revision 0, dated
November 14, 1987.
Ravision 3 of CEB-01 21.85 notes that the procedure for the
generation of the remaining support loads for Unit 1 piping is
primarily defined in the Gilbert Commonwealth Report Task R0055,
Rigorously Analyzed Piping Program / Program Document, Revision 0
(preliminary issue).
Revision 3 of CEB-DI 21.87 added TVA's commitment to assess the
adequacy of the pipe support calculations prepared by Gilbert
Commonwealth.
TVA will perform a general technical review of at
least ten percent of the calculations and perform a thorough
line-by-line review of at least 50 pipe support calculations.
TVA's
overview of Gilbert Commonwealth's work parallels TVA's overview of
the pipe support calculations which Bechtel and Stone and Webster
prepared for Unit 2.
Design Criteria No. SQN-DC-V-24.2, Supports for Rigorously Analyzed
Category I Piping, Revision C, dated November 30, 1957, establishes
the design requirements for the evaluation or design of pipe supports
"or rigorously analyzed Category I piping.
Re-evaluated pipe supports which cannot meet the requirements of
Design Criteria SQN-0C-V-24.2 can be evaluated to the interim
criteria detailed in CEB-CI 21.89. Supports which meet these interim
criteria can be reviewed to SQN-DC-V-24.2 after restart and nodified.
Support designs which cannot meet the interim design criteria of
CEB-CI 21.89 must be reconciled, either by enhanced analysis or
modification, prior to restart.
On June 30, 1988, TVA indicated tnat approximately 2500 of 2900 cipe
supports had been reviewed, that 2430 pipe supports required no
modification, that 200 supports reauired ecci fi cati on s befcre
,
--
~ , _ ..,
,.
-
-
.
.
66
restart,
and
that
170
pipe
supports
required modification
post-restart. TVA nas indicated that slightly more than half of the
scheduled pre-restart modification > indse been comoleted to date.
The following snubbers and rigid pipe supports were design reviewed
considering the attributes listed below:
Snubber Mark No.
Size
Pipe Stress Iso. No.
1-CSH-100
10
0600102-01-03
1-CSH-77
10
0600102-01-03
1-CSH-78
10
0600102-01-03
1-CSH-48
10
0600102-01-02
1-CSH-99
3
0600102-01-04
1-CSH-74
10
0600102-01-03
1-CSH-95
10
0600102-01-04
1-CSH-96
10
0600102-01-04
1-CSH-75
10
0600102-01-03
1-CSH-44
10
0600102-01-02
1-CSH-14
10
0600102-01-01
1-CSH-18
35
0600102-01-01
1-CSH-15
10
0600102-01-01
1-CSH-47
10
1-CSH-17
10
0600102-01-01
1-CSH-36
10
0600102-01-01
1-C5H-35
10
0600102-01-02
Restraint Mark No.
Orawing No.
1-CSH-444
1-H21-468
1-CSH-413
1-H21-426
1-C5H-403
1-H21-406,1H21-407A
1-CSH-400
1-H21-401,1H21-401A
The specific attributes which were reviewed for the above pipe
supports are listed below:
The pipe support was designed to restrain the pipe loadings in
the proper direction and location.
The proper loading value, direction and orientation was
transmitted to the pipe support designer f rom the pipe stress
analyst.
The structural analyst checked the pipe support stresses against
the proper allowables for all structural shapes in axial,
bending, shear, co-bined stress interaction, web crippling, etc.
Loccl stresses induced into the piping by welded attacn-ents
were properly consicered.
_ - _ _ _ _ _ _ _ _ _ _ _ _
o
67
o
Torsional stresses were properly considered.
Concrete anchor bolts, including bass olate flexibility, were
addressed.
Support rigidity / frequency or deflection limits were considered
properly.
Component standard supports properly applied.
St'ructural computer program used in an appropriate manner using
proper units, loadings, properties, geometry, etc.
The as-analy:ec pipe support configuration agrees with or has
been properly compared with the as-built condition.
Weld configurations and sizes used in the analysis agree with
the as-built configurationt and sizes.
All structural analysis computer output has been properly
reviewed.
That proper consideration has been given to special design
considerations such as thermal environmental conditions.
In general the pipe support calculations reviewed were prepared in
such a manner that enabled the work to be reviewed with little
outside explanation.
The calculations were considered
to be
auditable and generally well documented.
During the
' view of the
above pipe supports several items were identified whicn require TVA
action.
On page 6 of the pipe support calculation for 1-H21-17 the loadings
are i sntified in a local direction.
However, the piping isometric
and
tress analysis calculations clearly indicate that the direction
of estraint is the global Z-direction. Existing Unit 2 calculations
e ussd to qualify the Unit i support and the Unit 2 calculation
w
as performed using the proper load orientation.
Therefore, this
item results in only a documentation error which TVA should correct.
This issue was identified as a deficiency and provided for licensee
j
information.
l
j
For support calculation 1-421-100, it was not apparent that the
as-installed direction of the snubber is in agreement with the
i
restraint direction indicated in the pipe stress analysis.
It was
necessary to perform a calculation to insure that the restraint was
installed in tne proper direction.
Generally, a pipe support's
direction of restraint is oDvious and can be determined from just
looking at the support drawing.
However, for supports with
complicated geometry such as supper's connecting to the steel
, - _
'
l
.
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68
containment vessel, a calculation may be required when the restraint
direction is not clear from just looking at the support drawing. TVA
should consicer performing the necessary cal;ulations where required
to assure that the pipe support has been destgred to restrain the
proper loading direction.
This issto was identified as a deficiency and provided for licensee
information.
Page 16 of pipe support calculation 1-CHS-96 contains a weld calcu-
lation which indicates a weld si:e of 0.132 inch is requirec arc a
0.165 inch weld is provided.
However, the calculation also states
that a significant portion of the weld was determined to have a size
of only 0.08 inch.
Therefore, tne welc as analyzed would result in
an overstressed condition.
Also the weld calculation is not very
clear in its determination of weld size.
TVA was notified of this
issue and should resolve the inconsistency.
This issue is designated URI 327.323/88-29-06
Example
o.,
and
requires resolution p r i c .-
+o
the :tartup of Sequoyah Unit 1.
.
Adequate resolution for the above URI shall include an Engineering
Assurance review of the design basis information related to this
i
issue.
l
The inspector's review of pipe restraints 1-CSH-400, -403, -413 and
'
-444 indicated no deficiencies with respect to the design attributes.
In conclusion, the sample of rigorously analyzed snubber and rigid
i
pipe supports were reviewed for the attributes listed above and with
i
the exceptions discussed, the supports were determined to have )een
adequately addressed by TVA. The analyses of record for these pipe
l
suoports reviewed were considered adequate and meet the FSAR and
l
design commitments relative to the attributes reviewed.
.
The inspectors selected seven pipe snubbers and five other pipe
l
!
supports / restraints associated with the CS system and performed
visual inspections with the aid of measuring devices and inspcction
l
mirrors
tc
verify
the
installations
were
as depicted
in
l
as-constructed drawings.
These installations were inspected for:
Deterioration and Leakage.
Correct structural member, bolts, and fasteners properly
installed.
Moving / rotational parts ..are free to move.
Alignment.
Interferences.
.
,
69
Fluid level (hydraulic).
The following snubbers were inspected:
Hark No.
Size
1-CSH-36
4 (hydraulic)
1-CSH-7
10
1-CSH-37
10
1-CSH-65
10
1-CSH-66
10
1-CSH-67
10
1-CSH-470
3
Seven discrepancies were noted on five snubbers.
No discrepancies
were noted on two snubbers. The following table provides a detailed
description of the NRC inspection findings.
Snubber /Orawing/ Discrepancies
1-CSH-7 (H21-7)
Undersize weld.
Rear bracket to plate (piece 7) is 3/16"
vs 1/4" as required.
Undersize weld. Wide flange (piece 9) to horizontal wide
flange is 3/16" vs 1/4" as required.
Piece 7 is 6 3/4' by 63/4" rather than 7" by 7" as
required by the drawing.
1-CSH-65(H21-65)
l
Snubber indicator tube / cap assembly is bound up in pipe
l
clamp.
l
l
1-CSH-66 (H21-66)
l
'
No deficiencies identified.
'
1-CSH-470 (H21-499, 500)
No deficiencies identified.
1-CSH-67 (H21-67)
piece 3.in bill of material not shann on detail.
'
r
'
.
70
1-CSH-37 (H21-37)
As-configured drawing spe:ifies 1-1/4 Inch wedge anchor
bolts. Actual installed coits are 1 inch.
1-C5H-36 (H21-36)
J
Orawing does not show a weld or weld details for attachment
of rear bracket to piece 2.
Discrepancies marked with an asterisk were identified in both NRC and
TVA walkdowns.
In addition, TVA performed an inspection of 10 CSS snubbers prior to
the NRC
inspection.
The
following
table
categorizes
the
discrepancies noted during both inspections:
Discrepancy / Resolution
NRC (7 samples).
TVA (10 samples)
Category
- Observed
- Observed
Inadequate / incorrect drawings
1
1
Hardware / installation discreoancies
noted by TVn, evaluation acceptable,
drawings.
Not yet changed.
1
2
Hardware / installation discrepancies
not previously identified.
5
2
The inspectors also selected five other types (struts, springs) of
pipe supports / restraints.
During the inspection of the five
supports / restraints, additional discrepancies were noted on two
adjacent Auxiliary Feedwater System supports.
Twenty
one
discrepancies
were
noted
on
these
seven
supports / restraints.
At least one discrepancy was noted on each
support / restraint examined. The following table provides a detailed
description of the NRC inspection findings:
1-CSH-400 (H21-400,401,401A)
al.
Drawing does not snow weld details f ar clamp stiffeners and
bracket to clamp joint for west strot.
- 2.
Spacers, piece 3 en drawing, are net installed (or recuired).
s
- 3.
Expansion anchor / bolt assembly fcr west baseplate is not
identified on bill of material.
- 4.
Connection welds for piece 12 exhibit poor weld contour.
- 5.
Piece 17 is 6 by 6-3/4 inches. Drawing specifies 6-1/2 cy
7 inches.
.
"
,
.
,
71
1-CSH-401 (H21-402, 403)
1.
As-constructed drawino scecifies si:e 11 spring cans.
Actual spring cans installed are size 9.
2.
Spacer plates are not centered as show on drawing. Drawing
does not show/specify orientation of spacer plates.
Drawing does not specify the required weld length between
piece 7 and spacer plates.
Drawing does not specify weld
size, length or location for spacer plate to embed weld.
3.
Piece 7 wide flange undersize. Drawing specifies W6X20.
Installed flange is W6X15.5.
1-CSH-408 (H21-415, 417)
1.
As-constructed drawing specifies size 12 spring cans.
Actually installed are size 9,
2.
Beam attachment load bolts are actually 3/4 inch diameter.
Vendor catalogue specifies a 7/8 inch bolt.
3.
Washer platos are not welded to back channels on outboard
ends.
Drawings specify an all around weld.
4.
Fabricated U-bolt (piece 3) is bent on both sides and thus
center to center spacing specified on the drawing as 1 ft
1-3/4 inches is actually 11-5/8 inches.
5.
Weld attaching wide flange piece 6 to existing wide flange
exhibits poor weld contour.
6.
Drawing provides no weld details for attaching piece 6 to
existing wide flange.
7.
As-constructed drawing specifies a 3/4 inch rod and beam
attachment.
The vendor catalogue specifies a 1 inch
diameter rod and beam attachment for the size 12 spring can
detailed on the drawing.
1-CSH-413 (H-426, 427)
1.
Undersize wide flange.
Piece 1 i s W5X15.5.
Drawing
specifies W6X20.
"2.
Drawing does not specify weld details for the rear bracket
1-CSH-449 (H21-473)
- 1.
Undersi:ed welds for pieces 2 and 3 to baseplates. Drawing
specifies 1/4 inch, actual is 3/16 inch.
1-AF0H-300 (H3-329, 330)
1.
The 5/8 inch beam attachment that is installed requires a
3/4 inen diameter load bolt.
Actually installed is a 1/2
1rch diameter bolt.
2.
The drawing is in error in that a 1/2 inch diameter rad and
beam attacnment assembly is specified for a si:e 7 soring
can.
This si:e spring can requires a 5/8 inch dia eter
bolt per the vendor's catalog.
_ _ _ _ _ _ _ _ _ _ _
.
72
1-AFDH-301 (H3-332)
1.
Drawing specifies a 5/8 in:n ceam attachment with bolt.
The catalog requires a 3/4 inen diameter load bolt for this
attachment. Actually installed is a 5/8 inch bolt that is
tnreaded full shank.
Grinnel supplied load bolts are not
threaded full shank.
In addition, TVA performed an inspection of 14 non-snubber CSS
supports / restraints prior to the NRC inspection. The following table
categorizes the discrepancies noted during both the NRC and TVA
inspection.
Observation / Resolution
NRC (7 samples)
TVA (14 samoles)
Resolution
- Observed
- Observed
Inadequate / incorrect drawing.
6
5
dware/ installation discrepancies
"
previously noted by TVA, evaluated as
acceptable but not yet included in
drawings.
2
9
,
Hardware / installation discrepancies
1ot previously identified.
13
19
The di sc repar.cie s identified by TVA in their pre-SSQE walkdown
included undersized welds, missing locknuts, undersized material and
dimensional discrepanedes.
The new discrepancies identified by the
NRC inspector included undersized welds, load bolts, structural
shapes, concrete expansion anchors and spring can assemblies.
Nineteen of the 29 discrepancies identified by the NRC had not been
identified during the previous TVA walkdown programs or by the
walkdown TVA conducted prior to the SSQF inspection.
Numerous instances were identified where design features, such as
weld details, were not specified on the drawings used for
construction and inspection. Undersized welds, expansion anchors and
load bolts indicate that either inadequate modifications have been
performed or the supports had been inadequately inspected.
In
addition, numerous discrepancies had not been identified earlier
curing previous TVA walkcown/ inspections either due to a oif f e ent
scope of inspection or an inadequate inspection.
Inadequate design
change controls are evident by issuance of as-configured drawings
indicating that ECN 5277/WP9911 had been completed on 1-CSH-401 and
408 when the required larger spring hanger assemblies had not been
installed.
The f ailure to install pipe supoorts and restraints 1-CSH-401. and
405 in accordance with design drawings
is violation
327,
32S/SS-29-03, example 2, Structural walkcown discrepancy.
- _-
.
_.
_
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.
,
73
1
!
This issue requires resolution prior to the startup of Sequoyah
Unit 1.
Adequate corrective action for violation 327,328/88-29-03,
Failure to Install Components in Accordance With Design Documents,
6
will include retrieval, generation or regeneration of sufficient
system operability determination information necessary to resolve
this issue.
In addition, adequate corrective action for the above
!
mentioned violation shall include a Quality Assurance review of the
!
TVA pre-SSQE walkdown discrepancies and the licensee's previous field
i
i
inspection /walkdown programs for this type of component.
,
,
b.
Equipment Foundation Inspection
.
The inspector selected two equipment foundations on the CS system and
i
performed visual inspections and measurements to verify compliance
.
with design drawings and support documents. A design evaluation was
t
performed on the CS Heat Exchanger 1A and CS Pump 1A-A and IB-B
'
supports.
(1) CS Heat Exchanger Support 1A calculation SCG 1S 180 (B25
l
880113-801), Rev. O, dated January 13, 1988, indicated that the
l
Unit 1
Containment
Spray Heat Exchanger support adopts
calculation SCG 15 179, Rev. O, cated December 19, 1987, which
'
analyzed the identical heat exchanger supports in Unit 2.
These
calculations were performed as a result of the discovery of
inadequacies in the original calculations as identified by CAQR
SQP 870188, dated March 11, 1987.
This CAQR identified the
inadequacy of the calculations in that improper vendor loads had
,
been used. Review of Drawing 48N1231 demonstrated that the heat
!
exchanger foundation supports are identical except they are
mirror images.
The Unit 2 corrective measure was reviewed by
t
the previous NRC IDI team and found to be acceptable (Inspection
l
Report 327,328/88-13, May 26, 1988).
The
IDI report also
1
outlined the past sequence of activities which led the
!
inspectors to the current issue which is identified as
'
improperly considered nozzle loads.
1
TVA completed the same field modification for Unit 1 as was
!
completed for Unit 2.
Subsequently, it was determined that
!
Unit I nozzle loads differed considerably from those of Unit 2.
l
The team was informed that this condition is documented in CAQR
SQP 880363, dated May 27, 1988. This has been determined to be
!
a restart item by TVA,
!
+
This issue is designated URI 327.328/88-29-06, Example
p.,
and
I
requires resolution prior to the startup of Sequoyah Unit 1.
Adequate resolution for the above URI shall
include an
!
Engineering Assurance review of the design basis information
[
related to this issue.
!
,
i
(2) SQN FSAR Table 3.2.1-2 specifies the containment spray pumps as
l
TVA Class 8
seismic Category I components,
designed in
.
!
!
. _ _ .
--
-
. .
-
.
,
74
accordance with the Draf t ASME Code for Pumps and Valves for
Nuclear Power, Class II, dated 1968, and March 1970 AJdenda.
TVA procured the CS pumps in accordance with the design criteria
contained in TVA purchase specification No. 71C30-92646,mPumps,
Centrifugal,
Electric-Motor-Driven, which TVA prepared on
November 9, 1970.
TVA design specification No. N2M-46 R0, Sequoyah Nuclear Plant
Units 1 and 2/ Centrifugal Pumps for Containment Spray, dated
May 18,
1972,
forms a part of the CS pump purchase
specification, and contains detailed design provisions in
specification 1153 for Electric-Motor-Driven Centrifugal Pumping
Units for Containment Spray Service for Sequoyah Nuclear
Plants 1 and 2.
TVA prepared this specification in compliance
with paragraph N-141 of the draft ASME Code for Pumps and Valves
for Nuclear Power, dated November 1968.
The functional requirements for the pump and motor detailed in
Specification 1153 are in accordance with the pump and motor
design parameters specified in the FSAR.
Section 22 of
Specification 1153, Seismic Requirements, notes in part that:
The pump-motor assembly and all individual parts of the
pump shall be designed to operate satisfactorily during
earthquake forces resulting from acceleration in the
horizontal and vertical directions.
The forces are 1.0 g
horizontal and 0.67 g vertical, applied simultaneously at
the center of gravity.
The entire assembly must be
designed to receive and transmit these forces through the
supports to the foundation.
TVA procured the CS pumps prior to TVA's formal implementation
of Appendix F, Design Criteria for Qualification of Seismic
Class I and Seismic Class II Mechanical
and
Electrical
Equipment, which TVA issued on February 11, 1971, and which TVA
subsequently used to specify the seismic requirements for
safsty-related mechanical and electrical equipment.
The CS pump is shown on Weise & Monski Outline Drawing No. UE
032-12.50-2. Rev. 1, dated June 23, 1972.
Weise & Monski calculation No. TP-001-2, Seismic Calculation of
Strengths, Containment Spray Pump, Rev.1, dated July 27, 1972,
(RIMS No. 870824T0771) was originally prepared to qualify the CS
pumps to the design criteria detailed in TVA Specification 1153.
However, based on two generic deficiencies which the NRC
identified during an inspection of SQN Unit 2 during the latter
part of 1987, Deficiency 03.4-6, Vendor Seismic Qualification
.
75
Reports, and Deficiency D3.6-1,
Equinment Anchorages, TVA
prepared the following calculations:
TVA calculation No. SCG-4M-168, Containment Spray Pump,
Rev. 1, dated June 20, 1988 (no RIMS No.).
calculation
SQN-CEB-SCG-2E-105-375,
Seismic
Qualification, Equipment, Rev. O, dated February 12, 1988
(RIMS No. B25 88 0215 319).
United Engineers (UEC) prepared Rev. O of the first calculation
for TVA on November 24, 1987, to compute the anchor bolt loads
for the Unit 2 CS pump.
TVA technical staff revised the
calculation to incorporate the Unit 1 CS pumps.
Impell prepared the second calculation for TVA to re qualify the
Unit 2 pump to the governing mechanical and seismic loads in
accordance with the ASME design code of record. As noted in the
Impell calculotion, the original qualification report which
Weise & Monski prepared for the CS pump was prepared in
accordance with German standards applicable to commercial pumps,
and did not provide documented evidence that these criteria were
consistent with the ASME code requirements for the CS pump
materials and pump assembly.
Review of the first TVA calculation indicated that UEC computed
the seismic component of the anchor bolt tension and shear by
using the zero period acceleration (ZPA) loads instead of the
1.0g horizontal, 2/39 vertical accelerations specified for the
CS pump in the purchase specification. The ZPA loads are about
15 percent of the specified seismic loads. UEC chose to use the
ZPA loads based on the assumption that the CS pumps are rigid.
However, UEC's use of the ZPA loads to compute the seismic
component of the anchor bolt loads is unconservative with
respect to Specification 1153.
The inspector noted that
Impell's calculation to re qualify the pump assembly uses the
correct seismic loads.
TVA's design of the pump foundation pad, which uses the anchor
bolt loads as input design loads, also needs to be reviewed.
The second calculation, which Impell
prepared for TVA,
requalifies the CS pump assembly, in part, to the manufacturer's
allowable suction nozzle loads and to the Unit 2 discharge
nozzle loads calculated in the piping analysis of record by TVA.
However,
the
calculation does not address the seismic
qualification of the Westinghouse motor, or the qualification of
the bolts which restrain the motor to the pump baseplate.
. _ - _ _
- - _ _ -
_
_
_
_ _ _ _ _ _ _ _ _ _
a
-
.
,
76
The CS pump motor is shown on Westinghouse drawirig No. 269CG80,
TVA contract No. 71-92646.
To
address
this concern,
A09/SCG-4M-00457, Seismic Qualification of Containment Spray
Pump Motor,
Rev. O,
dated June 24,
1988.
However,
the
calculation does not confirm the seismic qualification of the
motor and the motor hold-down bolts to the 1.0 , 2/39 design
9
seismic loads.
TVA provided the inspectors with an additional calculation
entitled Sequoyah Nuclear Plant, Containment Spray Pump Nozzle,
Rev. 1, dated February 23,1982 (RIMS no. CEB 82 0225 002). The
team recommends that this calculation be voided, since the
calculation appears to be superseded by the calculation which
Impell recently prepared for TVA.
In summary, the team notes that TVA needs to perform the
following:
Check the CS pump base plate anchor bolts for the design
seismic loads.
o
Review the design for the CS pump foundation pad for these
revised loads.
Requalify the CS pump for the Unit i nozzle loads.
Provide evidence that the CS pump motor and motor hold-down
bolts are qualified for the design seismic loads.
This issue is designated URI 327,328/88-29-06, Example
q.,
and
requires resolution prior to the startup of Sequoyah Unit 1.
Adequate resolution for the above URI shall include an
j
Engineering Assurance review of the design basis information
related to this issue.
j
The inspectors reviewed a calculation for pump foundation
supports SCG15173x106 (B25 8P-1029-482), dated January 29, 1988.
I
Orawing 41N307-3 locates nump and mark number 410307-1 provides
the bolt details.
Drawing 41N353-1 Revision 4,
contains
dimensions of the punp concrete foundation.
The pump is held down to a 2'-3" reinforced concrete slab by six
1" diameter A307 bolts. There is 5/4" of grout and a 6" thick
concrete pad between the concrete slab and the bottom of the
pump support frame.
An anchor bolt is designed for maximum of 16570 lbs. of tension
and 9844 lbs. of shear.
These loads are results of a separate
pump analysis referenced as SCG-4M-00168.
The bolt stress
_ _ _ _ _ _
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
.
'
.
77
.
.
calculation was done in accordance with the methodology provided
in . AISC Sec. 5-1.6.3 and concluded that they are within
allowable stresses.
The inspectors performed a simplified and
conservative independent calculation and came to the same
conclusion.
The anchor bolt concrete capacity was investigated
for tension pullout load.
The (rout pad and 6" concrete pad
were not considered, which is conservative.
The result indicated that there exists a safety factor of more
than four which is acceptable.
(3) The following foundations were inspected in the field:
CS Heat Exchanger 1B per drawing 48N1231, FCR 6873 R1,
CS Pump 18-B per drawings UE 032-12.50-2, 41N353-1, 41N307,
41N307-3, 41N309, and 41N309-1.
The lower support for the Heat Exchanger 1B was found to be
installed in accordance with design drawings with regard to
bolting, member size, configuration, and weld size, location and
quality. The following discrepancies related to bolting of the
heat exchanger to the upper support structure were identified:
Six of eight fasteners were loose, two with only 1/2 nut
engagement.
One assembly had no washer.
The remaining seven fasteners had flat washers ir stalled on
the sloped inside surface of the structural channel flange.
The American Institute of Steel Construction (AISI) Manual
of Steel Construction and TVA Modifications and Addition
Instruction M& AI 9,
"Tightening,
Inspection,
and
Documentation of Bolted Connections", require the use of
beveled washers for surfaces that slope greater than 1:20.
A fol;owup inspection by TVA also identified that 3/4 inch
diameter bolts were installed. The heat exchanger mounting feet
have holes for one inch bolts.
l
The failure tu install CS Heat Exchanger 1B in accordance with
design drawings and site procedures is Violation 327,328/
l
88-29-02, example 1.
l
CS Pump 18 B was generally installed in accordince with design
drawings and site procedures. However, the inspector ider c;fied
that the holes in the mounting bracket of the vendor $Jpplied
pump asserbly had been enlarged (slotted), apparently to aid in
the alignment of the holes with the anchor bolts excedded in the
concrete foundation pad.
Vendor drawing UE 032-12.50-2
. - .
__ _ . . _ _ . _ , _ _ _ _ _ _.
_
_. _
__ _
. _ _ _
._
_ _ _ _ _ _ _ .
. _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _
- __
____
,
..
,
78
i
t
specifies 1-1/8 inch diameter holes. At least four holes had
'
been enlarged a minimum of an additional 7/16 inch.
This
minimum dimensio'n is based on measured gaps visible outside the
washer and assuming the bolt is in contact with the bracket on
i
the opposite side (nuts were not removed for the inspection).
TVA staff indicated that they were unable to provide any
documentation to show that this condition had been previously
identified, documented, or evaluated for effect on the seismic
design basis. As a result of this inspection, TVA is performing
new seismic calculations to determine the technical accepta-
bility of the as-installed condition.
CAOR SQN 880392 was
issued by TVA to address this matter.
The failure to properly control the installation and design
changes to CSS Pump 18-8 installed foundation brackets is
Violation 327,328/88-29-03, example 3.
The walkdown discrepancies identified in the structural section
l
of this report involve the as-built configuration of the plant.
Adequate corrective action for violation 327,328/88-29-03 will
i
include retrieval, generation or regeneration of sufficient
system operability determination information necessary to
resolve this issue. In addition, adequate corrective action for
the above mentioned violation shall include a Quality Assurance
review of the TVA pre-SSQE walkdown discrepancies and the
licensee's previous field inspection /walkdown programs.
These
I
additional corrective actions for violation 327,328/88-29-03 are
i
required to be completed prior to Unit 1 startup.
!
c.
Platform Thermal Growth
!
TVA found, in May 1935, that structural and miscellaneous steel were
designed and installed without proper consideration of thermal
1
loading from a postulated DBA (Staff Safety Evaluation Report,
NUREG 1232, Volume 2, on TVA Sequoyah Nuclear Performanco Plan -
.
May 1988).
Subsequently, TVA completed corrective measures which
I
resulted in several structural modifications introducing connections
I
'
with slotted holes to allow thermal expansion.
The staf f reviewed
and approved the TVA corrective actions for Unit 2 restait (see above
i
noted staff SER).
The modifications were comon to both Unit 1 and
,
Unit 2.
t
!
The
inspector
found no unreviewed potential
thermal
growth
interference of structural steel and concrete within the cor tainment
i
spray system.
However, the inspectors reviewed the thermal growth
interaction between
t' e containment spray piping and the steel
containment shell.
It was noted during the inspector's field walkdown that several
platforms were attached to the containment spray pipes.
Piping
,
isonetric drawing 0600102-01-02 details the horizontal restraint of
!
{
I
. . _ _ _ _ .
- _ _ _ _ _ _ _ , _ _ .
_ _ _ _ _
. _ _ . _ _ _
____ _ _ _ __ _
.I
-
,-
,
79
the pipe at the location of the platforms.
These platforms are
acting as pipe supports, (Drcing 482412-1, R1) and they are in turn
supported by the steel shell containment.
Review of shell stress
summary report (SCG-CSG-SS-091, Rev. O,
B25-8S-0227-308) revealed
that no stresses from thermal growth were accounted for at the
location of pipe supports.
Design basis related thermal growth of containment shell will be
reflected in the piping reactions and these reactions are to be
incorporated into shell stress analysis.
This is required by FSAR
Section 3.8.2.3.2. , items 4A and 40.
TVA stated that it is their
belief that the calculation did not include piping rea-tions because
they were considered to be small.
TVA presented several aspects of conservatisms inherent in their
'
shell stress calculation including conservative shell wall thickness
close to where the pipino is supported.
TVA also stated that when
3
they determined that the antribution of piping reactions to shell
j
stresses was considered to be large, such effects were included in
the total stress calculation in the final stress report, thus meeting
the FSAR requirements.
The inspector was
unable to complete a
review of TVA's information and related calculational packages
CSG-87-058, Rev. O,
841-87-0605-006 SON Unit 2 - Steel Containment
-
Vessel - Pad Plate Analysis - Containment Spray System Supports and
CSG-87-037, Rev. 1, B41-87-1019-008 SQN Unit 1 - Steel Containment
Vessel - Pen. X-48A Shell and Nozzle Evaluation.
i
This issue is designated URI 327,328/88-29-06, Example
r.,
and
,
requires resolution prior to the startup of Sequoyah Unit 1.
Adequate resolution for the above URI shall include an Engineering
.
Assurance review of the design basis information related to this
j
issue.
d.
Cable Tray Support
,
Cable tray supports for CS pump motor 6900 V power and control cables
were inspected on a sampling basis. Selected supports were inspected
to the specifications of drawings 48N13'O and 48N1360.
The cable
tray supports supported power and control trays for CS cables in
,
6900 V shut down board rooms 1A-A and 18-B and the surrounding areas.
-
(1) Eight cable tray supports on tray AM-A auxiliary building
j
elevation 734 were inspected for proper spacing and location,
reembersize, configuration and orientation, weld size, attachment
location on embedded plates and tray attachment to supports.
The following drawings provided the acceptance criteria for this
inspection:
'
4SN1338, 45N828-3, 48N1340, 4SN1360. 4SN1361
i
!
.
. _ - _ - -
--.
.
- _ -
.-
_ __
'
.
80
~
One potential discrepancy was notad concerning relocated
expansion anchor bolts and enlarged base plate holes.
This
issue appeared to have little safety significance and was
referred to TVA for resolution.
i
This ',ssue was identified as a deficiency and provided for
licensee information.
(2) The inspector reviewed the TVA design of cable tray supports.
Design criteria SQN-DC-V-1.3.4 entitled Category I Cable Tray
Support System, Revision 1, December 22, 1936 (805-861230 501),
included Appendix A "Interim Acceptance Criteria for Reevalua-
tion of Category I Cable Tray Supports".
The purpose of this
appendix is to provide an interim acceptance criteria for the
reevaluation to be completed prior to the restart of the
'
Sequoyah units. A set of calculations SCG1552x1, (Rev. O. B25
860913 825), SCG1547x1 (Rev. O,
825 860913 801), SCG1S47x2
(Pev. 1, B25-861113-818) and SCGIS29x46 (Rev. 1, B25 861113 817)
,
constitutes such a reevaluation.
'
-
As stated in NRC staff safety evaluation, NURE6-1232, Volume 2,
May 1988, several audits have been completed and both interim
criteria and TVA calculational methodology were approved with
TVA's com.mitment that original FSAR criteria for the affected
cable tray supports will be restored in an orderly manner after
2
i
restart.
Interim acceptance criteria for cable tray supports
are less stringent than those in the FSAR.
TVA calculations
were performed on worst case bases.
The SER stated that
regarding the selection methodology, the staff finds that TVA
has used good engineering judgement in its selection of the
worst cases and found the approach used acceptable for restart.
The inspector selected two cable tray supports for review. They
are MK-1B in 48N1337, R 10 and MK-2F in 48N1338R9C.
TVA's
reevaluation calculation of the cable tray supports also
selected MK-1B as a worst case sample (SCG-IS-47x1) even though
it is at a different elevation (drawing 48N1360).
Therefore,
the inspector's review of support MK-1B in 48N1337 constituted a
review of the TVA reevaluation calculation.
No inadequacies
were identified.
Next, the inspectors reviewed support MK-2F to determine if this
support is bounded by the worst case support, MK-1B.
Consideration of the number of cable trays at the support, span
distances to +he next supports, support member sizes, and its
unsupporteu length as prescribed in the TVA worst case selection
rethodology demonstrated that support MK-1B bounds MK-2F. This
issue is closed and the inspe: tors concluded that design of
cable tray supports is adequate for restart.
1
.
,
81
!
e
7.
Weld Inspection
!
The inspectors performed field inspections, observed nondestructive
examinations (NDE), and reviewed welding records (including RT film,
inservice inspection data, etc.) for the following nozzle, piping, and
3
structural welds related to the CS system on a sampling basis. Welds were
examined in the field for size, contour, and surface conditions.
Documentation was examined for welder qualification, weld procedure
qualification, and NDE results of compliance with design requirements,
j
i
The inspectors performed inspections in the following areas:
a.
Pipe Welds
(1)
Field Welds
Drawing (Welding Map)
i
1199,1200,1201 & 1202
CS-4
-
F-21,22,23,28,28A & 29
NAVC0 A-7204
Detailed welding procedures were checked.
[
-
Welder identification, qualification, and welding
-
continuity were examined.
NDE inspections were signed off.
-
,
Qualifications of NDE inspectors were examined.
-
The NRP inspectors accompanied by licensee welding QC inspectors
performed the following reinspections:
Type
keld No.
P_ipe Diameter
of Weld
Inspection Pe' formed
l
1-CSF-21
12"
Butt Weld
Visual and DT*
'
1-CsF-22
12"
Butt Weld
Visual and PT
,
'
1-CSF-13
12"
Butt Weld
Visual and PT
1-CSF-28
12"
Butt weld
Visual and P'
1-CSF-28A
12"
Butt weld
Visual and P'
,
1-CSF-29
12"
Butt weld
Visual and PT
l
1-CSF-30
12"
Butt weld
Visual only
l
1-CS-1199
2"
Socket weld
Visual only
,
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1-CS-1200
2"
Socket weld
Visual and PT
,
1-C5-1201
2"
Socket weld
Visual only
i
1-CS-1202
2"
Socket weld
Visual and PT
,
- PT - dye penetrant inspection.
(2) The inspectors reviewed the documentation on spuol piece
Nos. ICS 14 and 15 (Drawing NAVC0 A-7204).
l
l
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, _ . _ _ _ . _ _ . _ _ _ ~ , _ . , . _ . , _ , . _ - . . _ . _
.
82
4
b.
Equipment Nozzle Welds
t
The inspectors performed the following inspections on one nozzle for
!
CS pump 1A and two nozzles for CS heat exchanger IA:
Weld No.
Pipe Diameter
Type of Weld
Inspection Performed
r
1-CSF-42
12"
Nozzle weld
Visual and PT
1-CSF-31
12"
Nozzle weld
Visual and PT
1-CSF-20
12"
Nozzle weld
Visual and PT
The inspectors reviewed the radiographic film for the following field
fabricated welds:
L
CSC-X23
12" Butt Welds
CSF-28A
12" Butt Welds
i
CSC-29
12" Butt Welds
CSF-20X1
12" Butt Welds
l
CSC-31
12" Butt Welds
CSF-42
12" Butt Welds
i
CSC-28
12" Butt Weldt
CSF-30
12" Butt Welds
CSC-21
12" Butt Welds
CSF 22
12" Butt Welds
The radiographic film was reviewed to determine compliance with USAS
B31.7 code in the adequacy of weld quali'.y, weld coverage, film
density, penetrameter size and location, sensitivity, and geometric
unsharpness.
The following discrepancies were identified.
The radiographic data sheets which accompanied the file packet failed
to reference the radiographic procedure used. However, the licensee
was able to reconstruct this information through review of weld data
sheets and determining the time frame the welds were welded and
radiographed.
From the inspection dates the licensee determined the
document applicable to the radiography was G-29 Process Specification
3.M.3.1, Rev. 3, Spe:ification For Radiographic Examination Of Welded
Joints.
As specified in Table 1 of this procedure, in the weld
thickness range of 1/4" through 3/8" a number 7 penetrameter with 2T
sensitivity is required to show on the radiographic film. The review
of the following welds with a nominal wall thickness of .365 and .375
inches revealed a number 10 film side penetrameter was placed on the
material.
1-CSF-X23
.375 wall
-
1-CSF-28A
.375 wall
-
1-CSF-29
.375 wall
-
1-CSF-20X1
.375 wall
-
1-CSF-31P4
.a75 wall
-
1-CSF-42
.375 wall
-
1-CSF-28
.375 wall
-
1-CSF-30
.375 wall
-
Initially the licensee was unable to provice a basis for using a
9
_ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _
.
83
numbar 10 penetrameter when a number 7 was specified except they
believed the weld, with reinforcement, was actually thicker than .375
inches.
To determine the actual wall thickness, the inspector
requested an ultrasonic wall thickness of the following welds.
1-CSF-28
Measured minimura wall thickness .372
-
1-CSF-31
Measured minimum wall thickness .246
-
1-CSF-23
Measured minimum wall thickness .381
-
1-CSF-28A
Measured minimum wall thickness .426
-
1-CSF-29
Measured minimum wall thickness .462
-
As noted above weids 1-CSF-28, 1-CSF-31 were below the .375 wall
thickness and a number 7 penetrameter is required to meet the
requirements specified in USAS B31.7
Table 3.2.2.2 of the FSAR states the code applicable for fabrication,
and nondestructive examinations of TVA Class B piping is 831.7.
The licensee informed the inspector that Code Case 115 was approved
.
and allowed the substitution of ASME Section III requirements for
piping weld.
ASME Section III allows the use of a number 10
penetrameter in the thickness ranges discussed above.
Based on the
applicability of Code Case 115
the penetraneter selection is
,
acceptable.
The licensee performed calculations of the pipe weld to heat
exchanger nozzle weld (CS-1-00-31) with a measured wall thickness of
,
.246 inch thick to determine seismic and pressure / temperature
adequacy.
Ca l cul a +. i on number SCG-4M-00461 determined the weld is
i
seismically adequate.
Calculation number SQN-72-0053 determined a
minimum wall thickness requirement of .151 inch. Therefore the weld
,
thickness is considered adequate. The inspector determined the wall
reduction from the original design nominal wall thickness of .375
inches occurred when grinding was perfortned during fabrication to
remove surface defects found by radiography.
The licensee was
successful
in producing a defect free weld that passed the
radiography examination; however, they failed to consider the minimum
wall thickness requirements.
Quality Control inspection for wall
thickness reduction was not included in the inspection program during
fabrication of the field piping welds.
Failure to comply with the co .mitted to 831.7 weld standard n
implemented by TVA procedure G-29 is violation 327,328/88-29-04
'
example 1.
Adequate corrective action for this violation will
include TVA review to determine if minimum wall design requirements
were met on other field fabricated pipe welds.
4
!
In addition to the above radiographic film review, the licensee
re-radiographed the following listed welds for the inspectors review:
1-CSF-23
-
1-CSF-28A
-
1-CSF-29
-
i
,
1
84
The inspector's review included a comparison of the original
radiographic film to the new film to determine if the original weld
radiographed matched the weld number shown on the drawing. The new
film was also reviewed for weld quality, and a determination if
intergranular stress corrosion cracking (IGSC) and/or microbiological
intrusion corrosion (MIC) had occurred. No fabrication defects were
observed and no IGSC or MIC were apparent.
c.
Structural Welds
The inspectors reviewed the pipe support calculations for pipe
restraints 1-CSC-15, -47,
-400, -403, -413 and -444, in part to
confirm that the pipe support detail sheets properly indicated weld
si:es wnere required, and that welds were checked to confirm
structural adequacy with respect to the forces imaosed by the
connected members.
The inspectors did not identify any deficiencies
from this review.
,
,
The inspector reviewed a weld calculation of the heat exchanger 1A
4
foundation suppcrts.
The calculation required two 1/4 inch fillet
welds 6 inches long on each side of the web of a f14 X 13 diagonal
member (see SCG IS 180 Rev, 9, B25-88113-801, dated January 3, 1988,
1
which in turn references SCG 15 179, B25-88-0223-310, dated
1
February 22, 1988 - P 118 for 1/4 inch welds). The M4x 13 section is
a newly added member to strengthen the foundation support required by
a recent modification (see CAQR SQP 870 188, 3/1.'87).
This weld
connects the web of the M4x12 to the flange of vercical member of
,
!
8WF35.
The angle between two members is shown to the 56.5 degrees.
The theoretically available maximum length for the fillet weld due to
geometric constraints including 56.5 degree angle between the members
i
as well as TVA's subsequent field as-built measurement indicated that
'
it is not possible to have more than 4 inches of weld. TVA admitted
.
that 6 inch length in the calculation does not reflect field
measurement and a CAQR is being issued reflecting the error in the
'
j
calculation.
TVA has initiated a modification to the calculation
with the purpose of showing that the current as-built weld of
'
approximately 4 inches of weld continues to be adequate to satisfy
4
design requirements committed to in the FSAR.
i
The issue will remain open subject to a review of the calculation.
TVA has determined that this issue is to be resolved prior to restart
of Unit 1.
TVA indicated that revised calculations would include
'
evaluation of calculational conservatism as well as conservatism in
-
I
the value for the weld allowable stress,
in addition, an entire weld
.
calculation of the heat exchanger foundation supports is being
l
re-evaluated for a complete accuracy check.
It should be noted that
l
a previous IDI report (NRC Inspection Report 50-327-S3-13, May 26,
1928) noted several calculational errors and Rev. 3, of SC GIS 179
!
,
that the current inspector has reviewed is supposed to have addressed
i
the items with "line by line review cemments".
This issue is
1
I
i
i
%u
,
85
designated URI 327,328/83-29-06, Example
s.,
and requires resolution-
prior to the startup of Sequoyah Unit 1.
Adequate resolution for the
above URI shall include an Engineering Assurance review of the design
basis information related to this issue.
8.
Operational and Experience Review Issues
The following areas were reviewed to determine if systemic operational or
experience review issues existed.
a.
Restart Test Program (RTP)
The inspector reviewed the Unit 2 CS system Restart Test Program
(RTP) test matrix and compared the matrix to the Unit No. 1 CS system
functions.
The inspector also compared the general Unit 1 program
against the Unit 2 completed program. The inspection objectives for
the CS along with the inspector's finding are provided below.
(1) Unit No. 1 CS Restart Test Program Review
The objectives of this inspection were as follows:
To verify that the Restart Test Group (RTG) functional
review process in being adequately implemented.
To verify that component / system functions that are
identified as requiring testing are properly dispositioned.
To provide a sample assessment of the technical adequacy of
several portions of previously completed preoperational
tests that are being used to satisfy the functional testing
requirements.
To provide a sample assessment of the correctness of the
FSAR as it related to system functional requirements.
The inspectors reviewed the identificd system package to
verify compliance to the specified program.
Specifically,
the following items were addressed during this review:
Verify that the functional analysis report (FAR) matrix
package complied with the following documents as applicable
and contained the necessary information:
Function Review Process - Unit 1 (SIL-6)
Function and Punchlist Tracking - Unit 1 (SIL-7)
Test Analysis Report - Unit 1 (SIL-8)
Function Analysis Report - Unit 1 (SIL-9)
RTP Interface Report - Unit 1 (SIL-9A)
Modification Review Report - Unit 1 (SIL-98)
<
r
.
.
86
RTG Generated Testing Implementation Unit 1 (SIL-10)
RTG Closure Reports - Unit 1 (SIL-11)
Review ( 10-20*.) Division of Nuclear Engineering (DNE)
documents to Restart Test Engineer (RTE) which list
component / system functions and verify that the functions
were listed on the functional review matrix (FRM).
Determine
if
RTE
has
identified
any ' additional
component / system fun-tions as a result of the reviews and
ascertain the reason the functions were not listed by DNE.
Verify that any additional functions identified during the
review were listed on the Punchlist and determine if they
were properly identified to DNE and if the item resulted in
a Conditica Adverse to Quality Report (CAQR).
Discuss with RTE their background experience and verify
'
qualifications, documented training, and required reading
are in accordance with SIL-1.
Review the FAR, including the punchlist report and FRM to
verify that the above documents are in agreement as to
number of identified retests / tests to be performed, the
disposition of punchlist items, and the resolution of
f
identified interface items. Additionally, the conclusions
reached by the RTE should be evaluated and discussed with
the RTE. The following points should be considered when
perforraing the above review:
(a)
If the function has never been tested:
is testing
planned; what type of function
(i.e.,
control,
indication, safety, etc.); will a special test be
written or will the existing SI be modified?
If a
safety
function
is
involved, was existing SI
inadequate? Was CAQR issued?
( .-)
If function was last tested during preoperational
testing, should it be included in an existing SI as a
requirement or an enhancement, added to a preventive
,
maint3 nance program or ISI program, etc.?
(c) Are TS, FSAR, and/or design criteria document changes
necessary? What method has TVA used to identify / track
these changes?
Evaluate the supervisory and JTG review and approval of the
'
system package
Verify that the FRM reflects the functions listed in the
applicable FSAR and TS section.
_
_
c
>
-
"*
J
- ,
'
-
.
,
87
c
The inspector determined that for the CCS (system 72) the
requirements of the Unit I restart test program were properly
implemented.
The inspector did question the following:
DNE provided functions72-052 and 72-053 required the local
handswitches (1-HS-72-2B and 1-HS-72-398) to open or close
>
their respective valves from the local control station.
These functions were not verified as pa'rt of the review
!
process and the FAR indicated that DNE concurred with the
I
RTE that the functions were neither normal nor safety
(
functions for the system.
..
Subsequent discussion indicated that the ability of the
,
local switches to open the valves in riuestion was verified
during preoperational
testing.
Howev6r,
the closing
'
function of these local switches 'was not verified.
The
l
licensee indicated that the JTG had advised the RTE that as
!
i
long as the specified function did not reqvire additional
testing DNE agreed that the local switches d'd not provide
,
any safety or normal control function and we e installed
>
for maintenance purposes only. Given that the switches are
!
located in an area that would be inaccessible during an
accident condition, the inspector agreed with ths licensee
position that this function would be outside the intended
scope of the RTP.
Functions72-002 and /2-017 require that the CS pumps
deliver 4750 GPM with a discharge head of 143 psid.
For
Unit No. 2, RTG had determi md that during preoperational
testing the' vendor pump csr es had not been properly
validated and required in STI-65 that a three point flow
test be performed.
However, for Unit 1,
the licensee
.
indicated that the function would be validated by 51-37.1 &
i
37.2 for the 1A-A & IB-B pumps respectively. These two sis
!
only
require a single point verification of pump
'
performance as required by ASME Section XI.
The inspector
questioned the acceptability of validating pump performance
j
with a single point test when the licensee's preoperational
test for pump performance was never satisfied.
l
The licensee was requested to justify the adequacy of a
I
single point test to validate this function for the IA-A &
[
1B-B pumps.
j
f
Functions72-003 and 72-018 specify CS heat exchangers IA &
t
1B differential pressure (DP) as 10 psid.
The inspector
determined that the 10 osid specified was in error because
!
the results of recent CS flow calculations for both Unit 1
}
and Unit 2, which were performed to verify the adequacy of
l
the r odified system to deliver the required 4750 GFM,
t
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I
l
-
-
-
-
- . .
.
.
,-
. _
. , ..
.
.
.,
,$
l,
4
,
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.,.
.
88
indicated that maximum heat exchanger DP could not exceed
6'psid at 4750 GPM.
The inspecto-
requested that TVA determine if the FAR
,
functions were inc6rrectly stated and if so detarmine if
-
the FRM should be modified to accurately reflec' i maximum
of 6 psid.
Additionally, the FAR should be changed to
r
reflect the correct maximum heat exchanger DP.
-
Resolution ut these issucs is a restart item and was committed
i
to by the licensee at the inspection exit held on July 8, 1933.
L.
Comparison of Unit 3 RTP to the Unit 2 Completed Program
The' purpose of this comparison was to determine the adequacy of the
modifi 4 Unit 1 RTP as contrasted to the Unit 2 program that was
accepte; by the NRC and cocumented in NUREG-1232 Volume 2, Safety
!
Evaluation Report of TVA Sequoyah Nuclear Performance Plan.
The RTP for Unit ; wat essentially the same as that for Unit 2 and
the evaluation and conclusions discussed in the SER mentioned above
I
are considtred valid for both ; nits.
However, the Unit 1 program
scope was reduced from that used for Unit 2 based on lessons learned,
and as a result of modifications to other Unit 1 programs that we.'e
l
inputs to the RTP.
These differences along with th9 inspector
'
comments are provided below:
Once the design functions W2re established, the revicw of the
impact cf previous modifications was performed by :he RTE
'
utilizing SIL-98 to generate the modification review report.
,
This was different from the Unit 2 program which utilized the
DBVP output for the list of modifications which may ef fect the
system.
The inspector identified a possible weakness with this approach
specifically, the Unit 2 program had also used red iine drawings
-
to depict the as constructed
,ystem at the timo the
l
preoperational tests wtre performed. Combining the DSVP output
(i.e., mocs since time of licensing) with the red line drawings,
i
the Unit 2 program evaluated the tdeqtacy of post modification
testing of
all
modifications
subsequent
to
successful
l
preoperational testing.
In comparison, the Unit 1 program which
did net include the red line drawing process created a gap
'
involving the adeauacy of cost modification testing between the
time the preoperational test was per formed and the time of
R
issuance of the operating licensing (OL).
'
The above mentioned problem only affected those functions where
.
'
the licensee was taking creuit for preoperational tests to
validate adequate testing of the specified function.
,
I
I
1
,
-
.__
-
..
.-.
- - .
.
- _ _ -
-
-
_-
_ _ _
_ _ _ _ _ _ _ _ _ __
_ _ _ _ _ _ _ _ _
. _ _
. _ _ _
. _ _ _ _ _
.
89
Subsequent to the inspector's identification of this problem,
the licensee determined that 274 modifications fell into the
post preoperational testing and pre OL category. Of these, 190
modifications were reviewed as part of the modifications review
for Unit 1 and 16 were Unit 2 only which left 68 modificationa
to.be reviewed. Two of the 68 modification were determined to
have a potential impact on previously tested equipment and both
of these modifications were determined to be adequately tested
and had no impact on the function involved.
The Unit 2 program requirement to review the results of the post
maintenance test survey was not included in the Unit 1 program.
This decision was based on lessons . learned from the Unit 2
program which indicated that approximately 6% of the MR reviewed
Indicated either a lack of acequate test documentation or a lack
e f adequate testing.
Additionally, the post maintenance test
survey was not conducted for Unit 1 as part of D8VP; therefore,
the RTP could not use it as an input to their process.
The inspector was provided with a copy of memo (RIM S16 880624
890) dated June 24, 1988, from the RTP manager to the JTG which
provided statistics from the Unit 2 ef fort and provided the
basis for not including it in the Unit 1 program. Additionally,
the inspector was informed that the additional testing controls,
put in place at the station as a result of the Unit 2
maintenance program upgrade should also reduce the impact of
possible inadequate post maintenance testing on the validity of
previc'Js functional test.
T!
Unit 2 requirement to review the impact of the piece parts
review was also deleted from the Unit 1 program. The licensee
previded the inspector a copy of a February 10, 1988 letter to
the NRC (RIM L44 880210 800) which indicated that based on the
Unit 2 program lessons learned the scope of the Unit 1 piece
parts program would be reduced. The letter indicated that less
than four hundredths of one percent (5 of 13,000) of the
reviewed parts required change out.
T h e .", < , based on the above statistic, did not identify a need
to review the output of the piece part program far impact on
functional test validation. Additionally as stated above the
licensee feels that the improved naintenance program would
ensure that any part replaced as a result of the piece parts
review would be adequately tested.
As
stated earlier based
on
the
above minoi
program
implementation changes, the esalvation and conclusio.- for the
Unit 2 program as stated in the SER appear to generally bound
the Unit 1 program.
_ _ - _ - _ -
_ _ _ _ - - _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - _
_ - _ - . . _ - _ - _ _ _ _ _ .
_ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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!
90
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With the exception of tne three point pump test, the RTP appears to
be adequately implemented.
c.
Quality Assurance (QA) audit or surveillance items which may be
applicable to Unit 1
During this inspection the licensee was requested to provide the
results of ary quality assurance audits or surveillances which had
been conducted on the CS System. Discussions with licensee personnel
concerning this subject revealed that no audits or surveillances had
been conducted specifically on the CS system.
Audits are conducted
to verify programmatic controls and surveillances are conducted on
specific site activities.
Further discussion indicated that, if
deficiencies on the CS system hao been icentified by other
programmatic audits or activity surveillances, the results would be
available on the TROI computer tracking system which was reviewed by
the inspector. As a result of the above, the licensee was requested
to provide the results of any audits concerning operational readiness
conducted prior to the restart of Unit 2.
The licensee provided the
audits and the inspector reviewed them for proper corrective action
and closecut (as apprcpriate). The following audits were included in
this review:
SQA-87-0020
Restart Test Program
SSA-87-0019
Control of Replacement Items
SQA-87-801
RTI-1.1 Master Test Sequence
SQA-88-804
Revised Procedural Ctange Review System and
USQD Process
SQK-88-804
Correction of Oeficiencies
SQA-86-007
Calibration of CSSC Instruments
WBA-87-0018
Generic Reviews of iSN Categories
SSA-88-807
Generic Reviews of NBN CAQRs for Impact on SQN
No violations or deviations were found in this. area,
d.
Employee Concerns CATO items which art specifically applicable to the
Unit 1 or Uni; 2 CS systeas
The inspector reviewed issues which had been presented to the New
Employee Concerns program for sigd ficant items applicable to tFe
containment spray system.
The liew Employee Concerns program was
formed on February 1,1986, in order to resolve problems identified
after that date.
The licensee was requested to identify any ECP issues which could
af fect the CS system. One case, ECP-87-SQ-510-09, was identified as
' he report for this open case
being relevant to containment spray.
,
was to supercede ECP report ECP-S6-50-253-01 and provice a revised
response to NRC allegation RII-84-A-OlS7, which involved the adequacy
and implementation of procedures concerning heat number valication on
structural raterial.
The original licensee investigation had
-
..
-
-.
-_
_ .-
- .
t
>
'
.
91
i
t
,
'
concluded that the concern in ECP-86-SQ-253-01 was unsubstantia ted,
i
but this conclusion was later invalidated and the case reopened. The
!
reinvestigation reviewed the heat number validation program for the
time period from 1977 through 1984 as well as the information from
'
L
previous investigations.
<
The ECP-87-SQ-510-09 investigation identified 31 receipt inspection
i
data cards for QA Level I structural steel on which material
i
inspectors certified that the inspection was accomplished according
!
to procedure when it had not been.
In addition, ECP identified a
<'
number of violations of heat number validation procedures, including
y
a seven year period of routinely verifying heat numbers by using an
j
indexed listing which was unauthorized and contrary to procedures.
Use of the incexing listing has been evaluated for impact on the
quality of pressure boundary construction but not for structural
i
,
construction.
4
,
The inspector reviewed a draf t of the ECP report, and a TVA letts
l
dated May 27, 198b, from the Site Quality Manager to the Site
i
Director in response to the ECP report draft.
This letter stated
I
i
that the ECP report brought into question the adequacy of the
material controls for the structural steel installed at Sequoyah
!
during construction.
The letter also outlined a proposed plan of
action to assure the required traceabili'y.
The planned course of
'
action had not been finalized at the time of the inspection,
j
All information obtained during the inspection regarding this
,
,
!
Empicyoe Concern will be forwarded to the Allegation Coordinator, NRC
(
!
HQ Of fice of Special Projects, for inclusion into the overall
i
.
resolution of heat code traceability issues.
-
i'
The inspector also reviewed the listing of all safety significant
employee concerns and open files, and identified approximately thirty
I
!
additional cases involving general issues which could possibly affect
f
The licensee provided the inspector with a
summary of the resolution or the status of each of these cases. With
one exception, the cases identified by the inspector had either been
i
i
unsubstantiated, were restricted to systems other than the Unit 1 CS,
j
had not at Tected equipment operability, or were being addressed
l
'
programmatically and adequately resolved.
l
ECP-SS-SQ-658, concerning wall thickness on inaccessible tubing,
appeared to have possible relevance to containment spray.
This
concern resulted from an allegation nade at Bellefonte that Sequoyah
i
E
may not have adequately handled a nonconformance identified at
Bellefonte. The issue identified that Sequoyah had a problem with a
,
failure to verify wall thickness on inaccessible tubing as identified
j
In response to *he inspector's request to evaluate
!
!
the concern for possiele applicability to Unit 1 CS, the licensee
{
l
determined that the issue was being adcressed through PIR SQNCEBS74
i
!
and that corrective action arid closure will he a post restart item
i
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- . _ _. - -
.
- . -
_ _ - - , _ -
.t
,_ _ ____ _ ____-___________ _
!
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,
92
,
for both enits. The PIR does affect the Containment Spray System, in
'
that tube steel was used in t.he support; for that system.
The
maximum decrease in tube steel wall thickness identified in this PIR
>
is 6.2% less than required.
CEB-C1 21.82 permits a 20f. increase in
>
allowable stress in determining restart status.
Since the area of
.
steel increases linearly with the wall thickness, and the rection
modulus could increase with the square of the wall thickness the
worst case would be (1.062)2=.88, or a 12% reduction in section
modulus. Therefore, under the maximum design stress conditions, the
i
tube steel would qualify for restart.
'
e.
Maintenance History and Trending
In
response
to violations identified in Inspection Reports
327,328/85-15 and 327,328/86-37, TVA implemented in
1986
a
!
maintenance history and trending program intended to improve the
l
timeliness and effectiveness of corrective actions for equipment
failures and out-of-tolerance conditions. As described below, the
maintenance history and trending consisted of an "Operability
Lookback" at pre-1986 issues, and an ongoing program consisting of
several computer data-bases. The inspector reviewed portions of the
!
history and trending for components in the CS system to identify
l
possible equipment operability issues and to assess the effectiveness
j
of the licensee program.
Within this area of inspection, no vic.lations or deviations were
i
identified.
Effective use of histo,; cal maintenance records to
,
identify and resrive recurring problems had been made by the licensee
I
on several occasions.
In the future, as more information is added to
3
the data bases for periods of plant operation, and the presently
i
planned refinements have been fully incorporated, the tracking and
trending program should prove more useful.
(1) Operability Lookback Review
l
To aid in identifying potential operabi tity questions resulting
,
from past undetected repetitive failures.
the
licensee
l
"Operability Lookback" review was conducted to identify and
evaluate equipment problems which occurred prior to the
initiation of the tracking and trending program in 1986.
The
objectives of the lookback program included the identification
of adverse conditions associated with equipment operability, the
evaluation of these conditions for significance with respect to
safety, documentation of the existence and effectiveness cf
corrective actions, and the proposal of additional or modified
corrective actions.
The Operability Lookback utili:ed data
obtained from PRDs from both Sequoyah units, and interviews with
senior
plant
employees.
The
review
process
evaluated
operability issues involving generic equipment groups, as well
as problems with specific individual components.
, _ _ _ _ _
_- _ _-- _-_ . _ _ _ _ -
. _
_ _ _ _ _ .
_ ___-_
. _ _ _ _ _ _ _ _ _ _ _
_ __
__.
L
id
'
. ,
,
93
The inspector reviewed each PRO evaluation from the CS system
"
portion of the Operability Lookback. The Operability Lookback
review had identified eleven significant component failures in
'
containment spray. Of these, the following were classified by
the licensee as isolated cases:
The 18-B containment spray pump failed to manually start
-
because the breaker locking lever was not adequately
lubricated. The PRO evaluation included a review of prior
work requests ( A529411, A38689, A232/41, A157697) and
concluded that there was no evidence of repetitive failures
for the same root cause.
In response to this finding, a
recommendation was made to revise maintenance instruction
(MI-10.4) to require lubrication of breaker locking levers.
The inspector confirmed that this procedure modification
had been made.
Containment Spray pump 2B-B failed a surveillance test
-
because the timer was out of tolerance.
,
!
Containment spray pump 2A-A was declared inoperable due to
-
i
a failure of undervoltage relay BCTA-72-27. The PRO review
i
noted that there had been a similar previous undervoltage
relay f ailure on DG 1A, but the two f ailures were not
'
i
considered to represent a trend
1
Check valve 72-525 failed 51-166.45 twice. Because the SI
-
was run every 92 days and the valve enly failed twice, the
4
i
PRO concluded that the problem was not significant,
u..]
additional corrective action was not recammended.
i
Check valves 72-506 and 507 failed a sureatllance test
-
because the valve internals had not been repisced af ter
flushing the system.
Flow transmitter 2-FT-72-13 failed upscale due to air being
[
-
trapped ir. the sense lines. The PRO evaluation documented
'
that another failure of this flow transmitter had occurred
on 4/11/83 due to a failed power supply.
.
Containment spray mini-flow valve w;uld not open due to a
-
Buchanan plug coming loose on the control room handswitch.
The following issue was also identified in the lockback review:
Possible deterioration of the containment spray heat
-
exchanger tubing could go unnoticed.
The recommended
corrective action was to perform eddy current testing of
i
the heat exchanger during every cutage. The PRO evaluation
package, dated 1/27/S7, states that this eddy current
testing had been performed at least once since 1979. The
F
!-
I
,
_ _ _ - _ - _ _ _ _ _ . _.
_
_ _ _ . _ _
__
_ _ -
.
.
'
.
94
inspector verified through discussions with the licensee
that the eddy current testing had been performed during
subsequent outages.
The following CS issues had been incorporated into the
Operability Iookback generic equipment concern packages for
Arrow Hart and Limitorque:
Flow Control valve 1-FCV-72-24 failed to open due to dirty
-
breaker contacts (Arrow Hart).
Failure of BCTO-072-2A ( Arrow Hart).
'
-
1-FCV-72-20 failed to open due to loose bolts on the torque
-
switch (Limitorque). The PRO review generic package for
this issue included one additional example of a valve which
failed to stroke due to loose bolts.
The generic PRO review package for Arrow Hart contactors
included at least eight PR0s addressing failures of these
components. The generic review, dated 3/13/87, stated that
problems with the contactors had occurred since early plant
operation, and a corrective uaintenance plan had been documented
in LER 84014 R1,
After implementation of this corrective
maintenance plan, additional failures occurred due to dirty
e
contacts and dirt in the lubrication.
DNE and Electrical
Maintenance then determined that the lubrication appeared to
create problems which negated the benefits. Laboratory testing
j
was performed which showed that unlubricated contacts performed
reliably for five times the number of cycles expected during the
j
40 year life of the plant. As a resuit, the lubrication was
removed, and M1-10.40 was revised to require inspection of the
'
breaker contacts. The inspector discussed the current status of
this issue with Electrical Maintenance p e r s o,",e l , and the
proble.n appeared to have been resolved.
The inspector observed that once the Operability Lookback issues
had been identified through a search of the PR0s, the PRO
reviews made effective use of available maintenance tracking and
,
trending data records when evaluating tbs issues for repetitive
or generic failures. However, the a sessma its appeared to focus
primarily on f ailures of a particular cr fonent having the same
root cause, and the review could therefore have failed to fully
identify the significance of repetitive failures due to
different causes.
Frequent failures of a particular type of
component for different reasons or due to failures of different
subcomponents could indicate the need to increase the testing
frequency for that component,
In addition, because the Operability Lookback was baseo
primarily on a resiew of existing FR0s, the potential existed
.
m
. _ _ _ - _ _ _ _ _ _ _ _ _ _ - - - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - .
__
_ . _ _ _ _ _ -
_ _________ _
__ -_- _
.
95
!
i
for repetitive failures apparent from WR records not to be
identified. The inspector performed a cursory review of the WRs
issued during the tcNJ of the lookback study, and noted
possible patterns which were not picked up by the Operability
lookback.
In particular, an unusually large number of WRs were
observed for the flow transmitters and flow indication
instrumentation, including calibration and other problems. This
was not reflected in the Operability Lookback.
However,
previcus trends, if they continue and are of significance, are
expectea to be identified by the new ongoing tracking and
trending program.
,
This issue was identified as a deficiency and provided for
licensee information.
Inspection Report 327,328/87-24 identified that the findings of
,
the Operability Lookback program were being tracked to
'
completion but were not being directly factored into the new
tracking and trending program data base.
The licensee had
,
responded that the operability lookback issue summary packages
would be made readily available for utilization by those groups
i
i
reviewing the trending and tracking data for repetitive
instrument deficiencies. The inspector noted that although the
Operability Lookback equipment failu'e issues were not directly
l
factored into the new program, those issues addressed in WRs
'
were included in the maintenance history records and thus
available for incorporation in future trending reviews.
In conjunction with the review of the new mainterance history
and trending program, the inspector reviewed the history and
(
trending records for subsequent f ailures of selected comnonents
flagged in the operability lockback review.
The resul6s are
[
documented below.
f
(2) Maintenance History and Trending Program
ANS 3.2/ ANSI NIS.7, Section 4.1.4 requires that a program be
[
established which detects trer.ds in activities affecting plant
r
safety which may not be apparent to the day-to-day observer.
l
Procedural requirements for trending the required information
obtained from WRs. special reports, and out-of-calibration
reports are specified in SQM-58, "Maintenance History and
Trending".
The inspector reviewed Revision 6 of the procedure.
The Maintenece History and Treeding program documented in
SQM-58 was implemented to satisfy le ANSI requiremr.ts by
providing cyprehensive raintenance n' story reccrds for major
plant co.tponen a , in a readily retries.ble format useful for
detecting failure trends.
Maintenanc-
history tracks three
l
- .tegories:
1) NPRDS reportable items, 2) Class IE and 50.49
,
t
t
'
<
.
96
!
!
components, and 3) Other components (including CSSC) falling
outside of the other two categories.
Maintanance history information is tracked in three data bases
'
from which it can be trended:
(a) NPROS: Program Procedure 1601.02 documents that ANSI NI8.7
!
history and trendir.g requirements will be satisfied through
use of the NPRDS program.
The NPRDS program, managed by
.-
INP0, provides maintenance
trending
and reliability
information which is both specific to Sequoyah and commor.
l
'
to the industry.
The components tracked by NPRDS ne
prescribed by
the
program description.
Semi-annual
4
trending reports are prepared based on this data base, each
covering a twelve month period so that all significant data
.
will be included.
The trending analysis incorporates
l
criteria for identifying both repetitive and generic
component failures.
(b) EQls:
Program Procedure 1601.02 documents that 10 CFR
[
50.49 tracking requirements will be satisfied through the
use of the EQIS data base.
EQIS is used to store NPRDS
L
,
reportable activities, Class IE and 50.49 failures, and
certain other failures documented on WRs. The data entered
!
into EQIS is primarily failure related.
EQIS was
5plemented in January 1986
'nd contains information
,
processed after that date.
The 1E and 50.49 components are trended annually with EQIS
.
using the same criteria as for the NPRDS data.
CSSC
!
'
'
components which are non-NPRDS and non-1E/50.49 are also
trended annually using EQIS. The capability exists to use
t
EQIS to trend the NPRDS components but this is not
i
'
routinaly done.
EQIS trending is also required whenever a component failure
results in a reactor trip, turbine trip, load reduction, or
,
LER. Each time a work request is entered, the data base is
!
reviewed for similar failures of that component and
f
cumponents with three or more failures are flagged for
further review.
(c) Maintenance History:
The Maintenance History data base
l
contains records of all maintenance activities requiring
i
documentation fJr tracking, both failures and non-failures,
,
Thi: data bire can be sorted and trended using the SEEK
!
program to obtain comprehensive maintenance records for
,
particular components, but the program is not designed for
t
routine use for identifying repetitive failure trends.
i
l
l
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!
!
!
.
'
r
-
_ _ _ _ _ _ _ --__ - _ - - - - - - - _ - _ _ - - - - - _ - - _ - - - _ _ - - _ -
- _ _ _ - - - _ _ . _ _ _ - - _ _ - - - - - - - - - - - - - - . - - - - -
- - - - _ - - - - - _ - - _ _ _ . - - -
4
.
,
97
The threshold criteria which indicate a rapetitive or generic
failu.e are specified in SQM-58 as:
1) Any component failing
two or more times in 12 months, 2) Any component model number
with failures or more than 3'
of the . omponents during 12
.
months, and 3) Any item of the same function made by the same
manufacturer with 5'4 f ailur es in 12 months.
SQM-58 requires
that when repetitive or generic component failure trends are
identified, an evaluation be performed in accordance with the
appropriate attachments to the procedure.
The inspector reviewed selected WRs to independently identify
issues relevant to equipment operability, and to assess how
effectively these issues were being evaluated and trended by the
licensee. The licensee was requested to provide a list of all
WRs issued on the Unit 1 CS system since 1985 (the approximate
time period applicable to EQIS entries), including those WRs
which were either active or completed but in the review process.
From the list which was provided, the inspector reviewed those
WRs listed below for generic issues which affected equip ent
cperability and could indicate design problems, a need for
increased preventive maintenance, er a need for an increosa in
surveillance testing frequency. For purposes of the inspector's
review, an equipment failure was defined as any condition which
could prevent the equipment from performing its intended
function. This included out of calibration conditions. When it
was not apparent from the WR whather or not the equipment was
actually found out of tolerance during a calibration, the IM
calibration cards were consulted.
In some cases the available
information
was
not
sufficient
to warrant a
failure
determination.
WR #
Component
Description
Repair or replace
B278242
Active WR
-
throttTing valve crifice (WR dated
12-4-88)
A560117
PMP-72-10
No failure.
Oil leakage created a
room hazard.
Cause of the oil leak
was a loose plug in the reservoir
and a poor oil level sight glass
cesign,
which
resulted
in
overfilling and leakage. Replacement
of the sight glass with different
design was recommended. (WR dated
8/2/86)
A5:3784
PMP-72-10
No failure.
Oil leakage was being
caused by a loose reservoir plug.
(WR dated 3/21/85)
_ _ _ __ .___-. __ __ . _ .
..
7-
e ';
.
V
98
B117523
PMP-72-10
Failure, Active WR - During four
performances of SI-37, the pump, had
come
close
to
exceeding
tht
acceptable ASME Section XI sibration
range.
The pump motor was aligned
3
to the pump.
The cause of the
problem was attributed to n)rmal
operating conditions over a period
of
time
causing
a
gradusi
misalignment.
(WR dated.5/20/86)
B232275
PMP-72-10
Active
WR -
Change
grease
in
coupling, verify no leaks per SQM 66
to clear CAQR 50P-SS0035. (WR dated
4/27/83)
B232274
PMP-72-27
Active WR
Change grease in
-
coupling, verify no leaks per SQM 66
to clear CAQR SQP-880035. (UR dated
4/27/88)
A089626
MTR-72-10B
Failure, Surveillance had indicated
inboard bearing was bad.
Vibration
analysis had indic3ted progressive
worsening. The motor bearings were
replaced and the motor was retested
^
successfully.
The
problem
was
attributed to normal wear.
(WR
dated 1/15/85)
A543339
MTR-72-10B
No failure.
Performed insulation
check per MI-10.20.
(WR dated
12/5/85)
A291498
MV0P-72-02
No f ailure on Unit 1.
The Unit 1
operator was replaced af ter it was
used to replace the operator in
Unit 2.
(WR dated 2/1/85)
8295983
MV0P-72-218
ko
failure.
Rebuild
-
i
operator and replace gear box grease
per Mi-11.2.
(WR dated 2/23/88)
B234170
MV0P-72-22A
Rebuild
operator
and
replace gear box grease per MI-11.2.
(9/22/87)
B295970
MV0P-72-39A
Rebuild
operator
and
replace gear box greace per MI-11.2.
(1/4/83)
.
_ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
f
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99
,
r
i
B234173
MV0P-72-20B
Rebuild and regrease of Limitorque.
(WR dated 9/22/87)
B103544
MOV0P-72-34
Active WR - Valve stem broke during
functional test
(WR dated 1/6/86)
!
B234171
MV0P-72-23A
Rebuild and regrease of Limitorque.
'
(WR dated 9/22/87)
l
8228011
MV0P-72-0039
No failure.
Sampled grease and
i
replaced plugs.
(4/4/87)
8247230
MV0P-72-13
No failure.
(10/27/87)
,
i
B784921
VLV-72-misc
Active WR - Specifies for listed CS
r
system valves, visually inspect,
!
stroke to ensure no binding, check
,
for packing leakage or damage,
repair as necessary.
(WR dated
5/27/88)
i
B784807
VLV-72-512
Active WR - Removal of valves from
VLV-52-513
system, performance of setpoint and
!
leakage test, repair at necessary,
and
reinstallation.
(WR
dated
'
5/27/87)
Valve binds when
B114204
VLV-72-503
Active WR
-
,
operated.
(WR dated 3/14/86)
B233705
VLV-72-5025
No failure.
Excessive force had
4
been required to open and close the
!
valve.
When the valve stem was
'
cleaned
and
lubricated,
it
functioned
properly.
(WR
dated
4/18/87)
B233706
VLV-72-504
No failure.
Excessive force had
been required to open and close the
l
valve.
When the salve stem was
cleaned
and
lubricated,
it
functioned
properly.
(WR dated
4/18/87)
FCV-72-40
B751301
FCV-72-40
Failure, Active WR
-
failed the maximum stroke time for
SI-166.6 (PMT on MOVATS) with a
stroke
time of
11 seconds as
l
compared to a limit of 10 seconds.
l
(WR dated 5/10/8S)
i
l
l
_
_
_ _ _ - - _ -
_ _ _ _ _ _ _ _ - _ _ _ - - _ _ _ _
__
.
i
,
i
100
B119812
FCV-72-40
Failure. Valve FCV-72-40 failed the
SI-166.6 stroke time test.
The
problem war,' corrected by resetting
!
the open limit switches per MI-11.2B
and the stroke time acceptance
,
criterir,n was then met.
(WR dated
4/14/86)
!
A529253
FCV-72-2
Failure.
The valve had failed to
l
'
open during the performance of an
SI.
The problem was corrected by
cleaning
the contacts
at
the
starter.
(WR dated 1/26/85)
l
!
B100508
FCV-72-34A
Failure.
The valve stem coupling
i
broke while attempting to handcrank
l
the valve open during a functional
test. The failure was attributed to
l
'
stripped coupling bolts caused by
excessive force. The bolts were
replaced.
(WR
dated
1/14/86,
l
Duplicate of WR 103544)
A116682
FCV-72-22
Replacement of Crydom relay 1Al-153,
which had burned up.
(WR dated
i
10/25/85)
{
B292544
FCV-72-13
Active WR - Rework tu' *ng to resolve
!
SMI-1-317-26
FCV-72-34
!
discrepancies.
(dR dated 3/9/88)
!
B784949
FCV-72-misc
Active WR
For specified CS
-
,
valves, WR specifies checking and
!
cleaning and lubricating valve stem,
l
stroking test position indication
I
l
and smooth travel, inspection of
(
j
packing
condition,
repair
as
nec e s sa ry.
(WR dated 5/27/88)
j
A524367
Removal and reinstc11ation of insu-
l
l
1ation for ISI inspection.
(WR
[
l
dated 1/9/86)
!
A524366
Removal
and
reinsta11ation
of
!
insulation
for
inspection.
(
(7/1/85)
l
8119627
FT-72-13B
Ouring an outage, the flow indicator
l
indicated flew when pump was of f.
l
l
Ths instrument (Rosemont) was found
[
i
to be within the allowed bands
L
!
!
.
+-
e
,
n
,~~w
-
,,-+-e
,- ~- rm
,-w
n------y-,,-e~yee------e-.e
,,mcw
~-m
'um
-
-,e
- - " - - -
-
_ _ _ _ . _ _ _ _ . _
. _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _
!
..
k,
!
101
'
i
during the recalibration. (WR dated
5/2/86)
l
r
B118633
FT-72-138
Calibration Check for SI-37 B.
(WR
dated 4/4/86)
,
8218755
FT-72-13B
Failure. During an outage, the Flow
!
.
transmitter was providing a 600 gpm
signal to the indicator, when no
r
flow was present in the system. The
!
threads on the tee connection were
i
defective, and the tea was replaced,
f
(WR dated 1/3/87)
,
B132532
FT-32-13B
No Fat iure.
Calibrated for SI, and
i
as-found was within specifications.
.
(WR dated 5/4/86)
l
A550904
FI-72-13
Instrument was calibrated for $1-32
Part B.
(WR dated 10/22/85)
!
B237669
FI-72-34
Active WR - Flow Indicator showing
j
approximately 1000 gpm flow with
!
s
!
pumps
off
and valves closed.
Calib* ate or Repair as needed.
[
(6-12-88)
j
B221760
WR stated that the instrument would
I
'
not calibrate below 25*.' of normal
I
span due to wrong input resistor.
!
'
IM calibration showed instrument was
found in tolerance.
(WR dated
3/2/87)
l
B227289
RLY-72-34A
VR stated that time delay relays
I
ftLY-72-13B
were
not
within
acceptance
i
criterion.
(4/30/S7)
[
'
!
A529411
BCTA-72-10
Failure.
CS pump 18-B did not
i
operate because
breaker
lecking
t
lever did not fully close. Problem
[
was resolved by repairing the lever
t
and lubricating.
The problem was
I
caused by racking in the breaker too
l
tightly.
Note:
This issue was
included
in
the
Operability
l
'
1
Loolback.
(WR dated 3/3/S5)
[,
B285372
BCTO-72-39
Replace creaker wires with broken
strands.
(2/3/SS)
j
!
!
i
- . , _ _ - _ _ . _ _ . _
- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ -
- _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
_
_
_ - _ _ _
L
..
r
102
'
i
'B299963
Pd!-72-16
No Failure, Active WR - The licensee
i
FdI-72-33
vertical slice walkdown identified
,
!
that these two containment spray
pump B startup strainer differential
t
pressure indicators were swapped.
The instruments were to be removed
!
and swapped.
(WR dated 6/13/88)
!
.!
B104134
FTG-72-misc
Tube fittings were leaking due to
j
boron butidup.
(WR dated 2/10/86)
!
!
Investigation,
B261795
Air Test Line
Active
-
evaluation,
and
repair
(if
f
neces sary) of an are strike on
containment spray pipe.
(WR dated
5/28/88, was not planned yet at the
t
time of the inspection.)
l
1
I
This WR review, in conjunction with the Operability Lookback
[
information in the above paragraph did not indicate any current
t
l-
generic or repetitive instrument problems, other than possible
i
repetitive problems with the flow instrumentation.
I
+
i
'
l
The EQIS records were reviewed for each component for which a
failure was identified in a WR, No repetitive failure trends
!
were identified.
The inspector requested the licensee to
[
provide the failure records on all Unit I and Unit 2 plant
[
components with the same manufacturer and model numbers as
selected components in the CS system.
These component model
!
'
i
numbers were determined by the licensee to only be found in
i
containment spray. The results of the model number scan were as
!
follows:
1
l
CS Pumps:
No failure entries
!
-
CS Pump Recirculation Flow Control Valves (72-13, 72-34):
>
-
t
I
B100508:
1-FCV-72-34 stem coupling failure (11/14/85)
i
A119737:
2-FCV-72-34 improper operation due to dirt
[
and lack of lubrication (11/29/84)
[
.
A242957:
1-FCV-72-34 did not close due to trip on
!
'
thermal
overload
f^r
unknown
reasons
j
1
(12/14/83)
L
I
RWST to Spray Header Flow Cortrol Valves (72-21, 72-22) and
l
-
Containment Spray Header Isolation Valves (72-2, 72-39):
i
'
B205037:
2-FCV-72-21 had leak and boron buildup cue
to worn packing (10/31/56)
i
l
.
!
,
I
!
'
l
-
- - -
__
___
________________ _ __ _ _ __
.h
'
.
103
.
A040290:
2-FCV-72-22 had boron acid residue due to
worn packing (09/29/84)
B219517:
2-FCV-72-22 had packing leak (01/15/87)
Manual Isolation Valvc s (72-500, 502, 503, 504, 533, 534):
-
B114204:
1-VLV-072-503 worn internals (3/3/86)
B208153:
1-VLV-072-500 worn packing (10/13/86)
8233708:
1-VLV-72-500 would not operate due to lack
of lubrication (4/23/87)
8223815:
2-VLV-72-502 packing leak (5/5/87)
B103103:
2-VLV-72-502 packing leak (1/25/86)
B115481:
2-VLV-72-504 packing leak and boron buildup
(4/2/86)
The above information was not considered by the inspector to
indicate any generic equipment problems.
To assess whether component failures were reliably being entered
into the EQIS and NPROS data bases, the Unit 1 EQIS data base
was searched for records of those WRs considered by the
inspector to constitute component failures.
A number of the
above WRs had either been filed prior to the inceptie~ of EQIS,
or had not completed the review process at the time of the
inspection. The remaining component failures identified from
the WRs by the inspector were all properly identified in EQIS
,
and reported to NPROS when required.
The licensee had also
l
implemented an independent engineering review of the component
failure designations for added assurance that all applicable
data would be tracked and trended as required, and be properly
classified.
The licensee identified to the inspector that CAQR CHS 88001 had
been written to address the fact that a number of data entries
had been accidently deleted from the E015 data base and actions
were being taken to restore the information to the records.
This loss of data did not af fect the trending commitments with
respect to data being trended through NPRDS, but potentially
affected the trending of 50.49 components with EQIS.
Licensee
corrective action for this problem was ongoing at the time of
the inspection, and appeared to be adequas?.
The inspector noted that PRO 1-86-076, dated 4/8/S6,
-
identified that 1-FM-72-13A and 1-FM-72-13B were found to
_
_ --
_
_ - _ _ _ _ _ _ _ - - _ _ _ _ _ - _ _
_______ _ _______ - ____ _
- .
104
be out of tolerance. The EQIS data base did not contain a
failure entry for the associated work request, B11S633.
The inspector briefly reviewed with the licensee the evaluations
of repetitive or generic failures identified in the annual EQIS
reviews for IE/50.49 components.
No issues were identified as
applicable to the CS system.
NPRDS failure reports identified only one potential generic or
repetitive failure pertaining to the CS system.
The report for
the period from July 19S5 through June 1956, prepared by the TVA
!
Performance and Analysis Section, identified multiple problems
!
involving Kerostat valves similar to FCV-72-34.
The inspector
reviewed the licensee evaluation of this issue, which concluded
that the failures were due to unrelated causes (dirt in the
system, broken stem coupling, worn bearings, scratched end
seat).
No further corrective action was recommended.
The inspector reviewed four additional review and evaluation
packages for generic or repetitive equipment failures identified
through the trending programs for systems other than containment
spray.
The packages which were reviewed addressed generic
problems
with
Quincy
Air
Start
Compressors,
transmit *,ers, and Asco pressure switches. Each of these reviews
,
l
were considered by the inspector to be thorough and
'
comprehensive, and produced meaningful and significant results
and recommendations.
The inspector noted that some of the reviews of repetitive
failures (primarily those in the Operability Lookback review)
l
appeared to focus primarily on root c.use determination, and
possibly deemphasized the importance of repetitive failures from
'
different causes. Numerous repetitive failures resulting from
different root causes could indicate a need for an increased
,
testing frequency.
Licensee plans
included more
fully
l
implementing this type of review in the future as the data base
'
is expanded.
The inspector noticed in the review of +5e EQIS records that no
CS pump failures were logged, although failures of subcomponents
were logged which could have affected the operability of the CS
pumps.
The licensee follows the NPRDS guidelines concerning
which components are to be tracked and where the failures should
be entered.
Effe:tive trending of failures of eajor components
due to different root causes must be accomplished by trending
the major component together with all applicable subcomponents.
.
- _ _ _ _ . _ . _ _ _ _ _
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _
- _ _ _ - _ _ _ -
_
.. ..
i
i
i
!
l
105
j
r
f
f.
Potential Reportable Occurrences (PRO) which were applicable to
Unit 1 or Unit 2 C5 systems (from August 1985 to present)
i
!
7he licensee was requested to provide the inspection team with copies
[
of all PR0s which were written on the CS system for both units from
!
August of 1935 to the present. These reports were provided and were
i
included in the Operation Experience Review. The PR0s were reviewed
i
to determine any trends which may have existed concerning proper
[
equipment operation and reliability.
Additionally, the review
i
included an assessment of: the evaluation and corrective actions for
'
all deficiencies, the root cause analysis determination and actions
l
to prevent recurrence (where applicable), the reportability of
[
deficiencies,
the operability of equipment, and the generic
[
applicability of reported deficiencies, wnere aopropriate.
The
following is a listing of PR0s and LERs included in this review:
PR0s
LERs
}
r
1-86-076
1-87-117
2-88-001
l
1-86-125
1-87-177
1-37-050
l
1-86-216
1-87-256
1-87-069
1-86-301
1-87-257
86-028
1
1-87-027
1-87-396
87-010
l
1-86-361
1-88-137
[
1-87-049
2-87-012
1-87-053
2-87-016
1-87-055
2-87-017
1-87-110
2-87-018
2-88-5
2-88-138
During the review of PRO 1-86-125 several concerns were identified
L
regarding the installation and testing of relief valves on the
I
containment spray sy m ".
One concern resulted in a problem area
!
j
requiring licensee mamgement attention end corrective action as
follows:
l
During the review of PRO 1-S6-125, dccumentation provided
l
-
indicated that the suction relief valves (72-512 and 72-513)
!
were not included in the sites inservice testing program.
[
further investigation of this concern with the licensee revealed
!
the following facts regarding this concern:
f
i
a)
10 CFR 50.55a(g) requires inservice testing of pumps and
l
valves in accordance with ASME Se: tion XI to verify
'
cperational readiness,
b)
ASME Section XI, IW-3511 requires category C salves te be
tested in accordance with Table IW-3510-1 (at least on a
five year interval).
F
c)
The valves on both units were tested as requireo by ASV.:
Section XI.
Docusentation was provided by the licerste
I
(Reference work plans 6313-01 and 1 309).
l
r
- - - - -,
- - - _ _ - - - - _ _ - - - _ - - - . - - -
- - - - - - - -
_ - - . - -
- _ - - - . _ - - - - - . - - - - _ - - -
- _
_
-_
-
--
.
1
i
.
,
!
,
,
106
e
d)
The
licensee's
Section XI pump and valve program,
I
Section 6.8 of the FSAR, does not require valves 72-512 and
1
I
72-513 to be tested in accordance with ASME Section XI.
This issue is addressed as violation 327,328/88-29-04.
>
g.
Condition Adverse to Quality Requests (CAQRs) which were applicable
to Unit 1 or Unit 2 CS systems (from August 1985 to present)
{
!
The licensee was requested to provide the inspection team with copies
!
of all CAQRs (Conditions Adverse to Quality Reports) which were
i
written on the CS system for both units from August of 1935 to the
present.
These reports were provided and were included in the
Operation Experience Review. The CAQRs were reviewed to determine
!
any trends whid may have existed concerning proper equipment
'
operation and reliability.
Additionally, the review included an
i
'
assessment of:
the evaluation and corrective actions for all
deficiencies, the root cause analysis determination and actions to
i
prevent
recurrence
(where applicable),
the reportability of
l
deficiencies,
the operability of equipment,
and the generic
'
applicability of reported deficiencies, where appropriate.
The
l
following is a listing of CAQRs included in this review *
CAQR
SQP 87-0570
SQP 88-0344
SQT 87-0713
SQP 88-0287
i
'
SQP 87-0697
SQP 87-1543
!
SQP 88-0212
SQE 870R01003
SQP 87"1481
SQP 87-1697
!
SQP P7-0603
SQP 87-1559
f
f
No violations or deviations were found in this area.
h.
Preoperational Test Deficiency Resolution
}
r
The inspector revie ed Preoperational test W-6.1A, SIS-Integrated
l
Flow Testing, as it relateo to the CS and Preoperational Test
l
TVA-21B, Containment Spray System for the purposes of evaluating the
L
TVA resolution of test deficiencies. The specific test along with
l
the inspection findings are listed below:
[
W-6.1A1 - Of the eight deficiencies listed in this test package
-
only deficiency DN-5 related to the containment spray system.
This defici:ency involved suction pressure gage PI-72-33 being
found defective during testing and required test gages to be
installed to complete testing. Subsequent to the test the gages
r
were recalibrated and reinstalled thereby, reselving the test
l
ceficiency.
i
l
i
-
l
. _ _ - -
_ _ _
_ . _ _ _ _ . _ _ _ _ _ _ _ _ _ _ - _ _ _ _
_ _ _
_
!
- -
..
.
107
l
1
TVA-218 - This test comprised the ma,iority of testirg associated
l
-
with the CS.
The review of the test results for this test
revealed that 10 test deficiencies were written during the
[
course of this testing which was conducted in the January 1979
I
time frame. Of the deficiencies written, 8 involved equipment
i
failure and af ter repairs or replacement, the equipment was
l
successfully retested.
However, deficiencies DN-9 and DN-10
l
involved the fact that both the IA-A and 1B-B CSS pumps failed
to meet the manufacturer's pump curve and exceeded the expected
I
starting current. The starting current deficiency was evaluated
!
by DNE and found to be acceptable.
The pump curve deficiency,
i
however, was never properly resolved.
The licensee resolved
i
this tr. sue for Unit 2 startup by performing STI-65.
STI-65
!
required that a three point flow test be performed so that the
i
manufacture's curve could be validated. However, for Unit 1 the
!
licensee indicated that SI 37.1 and 37.2 would be performed to
[
verify proper pump performance.
[
t
The inspector's review of SI 37.1 and 37.2 indicated that only
!
one flow data point was being verif ted at the required flow of
I
4750 GpM. This issue was previously discussed in section 8.a of
'
this report.
'
i.
Industry Nuclear Experience Review (NER)
issues specifically
applicable to the Unit 1 or Unit 2 CS systems (Note:
this included
SER, 50ER, IEB, IEN, NSRS, NMRG, and NSRB items from August 1935 to
present)
Other items concerning industry nuclear operating experience issues
with the Containment Spray System were reviewed by the inspector
(NERs, SERs and IEBs). The following items were included in this
review:
NER 88-0250
NER 88-0196
NER 87-0683
l
NER 870464002
l
NER 850314001
l
l
IEN 84-39
,
'
The corrective actions for inree of these items was determined to be
weak or nonexistent:
corrective action for NER 850314001 which
concerned inadvertent actuations of the contaiament spray system at
various other utilities did not indicate that a thorough review of
instrumentation / controls, procedures and personnel training had been
conducted.
No documentation of corrective actions was previded by
the licensee for SER 30-34 (Inadvertent Actuation or containment
spray at another utility),
nor IE Notice 64-39 (Inadvertent
Isolations of Conta*nment Spray Systems at cther utilities).
. - _ _ _ _ _ _ _ - - - - - - - - - - - _ - - - - - - - - - - - - _ - - - -
-_--__ -
'.
,
108
!
t
This issue was identified as a deficiency and provided for licensee
(
information.
l
j.
Training of Licensed Operators and Aux liary Unit Operators Which are
Specifically Applicable to the Unit 1 or Unit 2 CS Systems
,
!
As part of this inspection the inspector requested and reviewed Power
j
Operations Training Center (POTC) course outlines / lesson plans
associat'sd with the CSS. A review of these lesson plans to determine
the detail and type of questions prov ided during this training for
both AVO and licensee operators was pteformed and is discussed below:
Course outline OPN 017.027 (PWR), Student III, Step 1B - Reactor
Technology (SON-WBN) which is taught to AV0s during the course
of their training prior to being assigned to an operating plant.
This course has an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> duration and contained basic system
function description.
Course outline OPN 218.067, Student III, Step II - Containment
Spray (system 72) which is taught to AVO during the last part of
their training phase was revi+wed. This course, listed as an 8
hour program, provided a bash system function description as
well as providing system operating information.
Course outline OPL271C024, SQN Operator Certification Training -
Containment Systems, which is taught to licensed operators
during a part of their qualification and requalification
t 'aining, was also reviewed.
Thi s instruction also provided
basic system description and operating instruction.
Based on a review of the above lesson plans the inspector provided
the following observation:
None of the above three lesson plans discussed the interlocks
associated with this system.
These interlocks involving are
very important to proper system operation.
This observation was discussed with the POTC PWR training
manager who indicated that a training letter discussing these
interlocks would be issued within seven dtys #ollowed by a
revision to the above training plans during the next scheduled
update.
This is a coreitment which the licensee agreed to at
the exit meeting conducted on July 8,19SS.
In addition to the above, the inspector reviewed past training
records to determine if students demonstrated any generic weakness on
the CSS.
Additionally, the inspector reviewed approximately 20
student feed back forms required by Procedure SQ-0TIL-14 in an
attempt to identify any stucent suggestions to inprove the training
on the CSS.
No problems associated with these reviews were
identified.
.
<
.
i
109
9.
Additional References (some referenced in taxt)
Drawing CB-1, sheets 74 & 75, Containment Pipe Supports
.w
Drawing 47W611-72-1, Mechanical Logic Diagram, Containment Spray System
Orawing 47B16-2, Piping Class Drawing
Drawing 47B601-72, Mechanical Instrument Tabulation
,
Drawing 47W437, Mechanical Containment Spray System Piping
Orawing 47WS12-1, Flow Diagram, Containment Spray System
Orawings 47A30, 47A31, Pressure Indicators Tap Drawings
Orawing 47A37. Temperature Connections
Orawings 478001 series, Auxiliary Piping Installation drawings
Drawings 47A053 series, 2" or Smaller Field Run Piping
Drawings 45N751-1, 2, 5, 6, MOV Electriesi Configuration
Drawing E-4SS40, Aloyco, 300 PSI, 12" MOV
Drawing E-4SS36, Aloyco, 300 PSI, 8" MOV
Drawing E-4SS48, Aloyco, 300 PSI, 12" MOV
Orawing TV-0-9909MO-(2).. Karotest, Containment Spray Recirculation Flow
Drawing 15-476-2411, Limitorque Wiring Diagram
50I-72.1, Containment Spr.y Systems
TVA Detailed Design Criteria, SQN-0C-V-27,5, Containment Spray System
TVA Detailed Design Criteria, SQN-0C-V-3.0, Classification of Piping,
Valves, and Vessels
$1-34. Containment Soray System Valve Position Verification, Units 1 & 2
51-37.1, Containment Spray Pump 1A-A Test, Unit 1
SI-37.2, Containment Spray Pump 18-B Test, Unit 1
SI-153.1, Containment Isolation Valve Liak Rate Test, Unit 1 & Unit 2
_
. - _ _ _ _ _ _ _ _ _ _
___
- _ - _ _ _ _ _
_ _ _ _ _ _-_
_ _ _ _ _ _ _ _ _ _ _ _ _
,
p
110-
SI-162.1, Snubber Visual Inspection (Hydraulic and Mechanical), Unit 1 &
Unit 2
SI-162.2, Snubber Functional Testing (Hydraulic and Mechanical), Unit 1 &
Unit 2
51-166,39, Disassembly and Inspection of SIS /RHR/CS/VHI check valves
[t
during refueling outages, Units 1 & 2
.51-186,
Locked Valve Verification Per NRC Commitment, Containment
'>'
Inspection, Units 0, 1, 2
'
',
SI-267-72.1, Functional Oressure Test of Containment Spray System, Units 1
'
L2
51-604, Essential Instrumentation Operability Verification
!
Technical Specifications, Unit 1
Section 3/4.6.2, Depressurization and
<
Cooling Systems
'
,.
ASME Boiler & Pressure Vessel Code, Sections III, VIII, IX, XI
ASME Draf t Code for Pumps and Valves for Nuclear Power, November 1968
Hydraulic Institute, Section B, (Centrifugal Pumps)
Tubular Exchanger Manufacturers Association, Class R Heat Exchanger, Tube
Side, ASME Boiler & Pressure Vessel Code Section VIII
National Electrical Manufacturers . Association
1963
ANSI 16.5 Steel Pipe Flanges & Flanged Fittings
ANSI B 31.1 Code for Pressure Piping with Inspection and Test Requirements
to ANSI B 31.7 Code for Nuclear Piping in Lieu of Applicable Nuclear Code
Cases
SSDC 1.12
System Standard Design (SSDC), NSSS Layout Guidelines,
Westinghouse Electric Corporation, dated March 1971
SSDC 1.14, System Standard Design Criteria (SSDC), Nuclear Steam Supply
System
Containment
Isolation,
Revision 3
Electric
Corporation, dated September 1931
SSDC 1.15, Systems Standard Design Criteria (SSDC) NSSS and Related
Systems Equipment Safety Classification, Revision 3. Westinghouse Electric
Corporation, dated May 1978
SSDC 1.3, System Standard Design Criteria (5500), Revision 2, Westingneuse
Electric Corporation, dated April 15, 1974
.
.
Ill
SSI.3X, System Standard (SS) 1.3X Nuclear Steam Supply System Auxiliary
Equipment Design Traraients for all Standard Plants, Revision
0,
Westinghouse Electric Corporation, dated September 1978
IEEE 279-1971, Standara Criteria for Protection Systems for Nuclear Power
Generating Stations
IEEE Std. 379-1972/ ANSI N 41.2, Guide for the Application of the Single
Failure Criterion to Nuclear Power Generating Station Protection Systems
Containment Sump Minimum Level ct Time of Switchover to Re:1rculation Mode
and Allowable Margin for RWST Level Instrument Inaccuracy for a large LOCA
(SQN-OSG7-008).
Unit 1 corollary
E-Specification 673765 - Motor Operated Valves foe TVA Sequoyah Nuclear
Plants Units 1 and 2, & G-676258 Motor Operated Valycs, Westinghouse
Electric Corporation
E-Specifications 67863 - Control Valves for TVA Sequoyah Nuclear Plant
Units 1 and 2, and E-Specif.1 cations 676270 - Contril Valves, Westinghouse
Electric Corporation
E-Specificatiens 67869 - 2 Inches and Below Manual "T" and "Y" Globe and
Self-Actuated Check Valves for TVA' Sequoyah Nuclear Plant _ Units 1 and 2,
and 678724 - 2 InChai and Below Manual "T" and "Y" GIUbe and Self-Actuated
Check Valves, Westinghouse Electric Corporation
l
E-Specifications 678760 - Manual
"T"
and
"Y" Globe, Manusi Ga +.e.
and
Self-Actuated Check Valves for TVA Sequoyah Nuclear Plant Units 1 and 2,
l
and G-676241 - Manual "T"
and "Y" Globe, Manual Gate, and Self-Actuated
Check Valves, Westinghouse Electric Corporation
E-Specifications 67858 - Auxiliary Relief Valves for TVA Sequoyah Nuclear
Plant Units 1 and 2, and G-676258 - Auxiliary Relief Valves, Westinghouse
Electric Corporation
SQNP-47W312-1, Flow Diagram, Containment Spray System Fewerhouse, Units 1
l
and 2
SQNP-47W610-72-1, Mechanical Control Clagram, Containment Spray System
SQNP-47W611-72-1 Mechanical Logic Diagram, Containment Spray System
SONP-47AS66-72-Series, Tabelation of Valve Marker Tags
SQNP-47Wa37-Series, Containment Spray System Piping
50NP-4706U1-72-Series, Fechanical Instrurr:nt Tatulattun
SQNP-47516-2, Piping System Classification
.
_ _ ____- -_ _ _ - __-_______
_ _ _ _ _ _ _ _ _
_
__
___-__ _
,
.
1
112
i
}
Wrest.inghouse Drawing 110E338, Sequoyah Unit 1 - Safety Injection System,
Flow Diagram
.,
SQN-47W811-1, riow Diagram, Safety Injection System Powerhouse, Units I
!
and 2"
SQN-DC-V-10.1,
Design
Criteria Mechanical
Unit Control
Panels -
January 11, 1971
SQN-DC-V-10.3, Design Cr *teria Mechanical Auxiliary Instrumentation (Room)
l
Panels - July 14, 1971
SQN-DC-V-10.4, Design Criteria Mechanical local Panels for Class I
-
Equipment - January 10, 1972
,
SQN-DC-V-1.0, General Civil Design Criteria
a
i
SQN-DC-V-2,16,
Single
Failure Criteria for Fluid and Electrical
Safety-Related Systems
<
)
SON-DC-V-10.5, separation of Instrument Sensing Lines and Instrument Air
Lines
i
SQN-DC-V-11.2, 125-V DC Vital Battery System
SQN-DC-V-11.3, Power Control and Signal Cables For Use In Category I
Structures
SQN-DC-V-11.6, 120-V AC Vital Instrument Power System
'
l
SON-DC-V-11.4.1, Normal and Emergency Auxiliary Power Systems
,
i
SQN-DC-V-12.2, Separation of Electrical Equipment and Wiring
TVA Sequoyah Nuclear Plant Unit 2
Final Safety Analysis Report,
'
]
Amendment 3, filed on 6/16/S6
TVA-TR75-1A, Quality Assurance Program Description for Design Construction
,
and Operatica of TVA Nuclear Power Plants, Revision 8, October 1984
TVA Nuclear Quality Assurance Manual
,
SQN-DC-V-21.0, Design Criteria for Environmental Design
l
SQN-DC-V-27.1, Design Criteria for Ice Condenser System
j
SQN-DC-V-3.0, The Classification of Piping, Pu ps Valves and Vessels
SON-DC-V-2.3, Containment Vessels
SON-DC-V-27.6, Design Criteria for RHR System
i
1
. - _ _ _ _ . - _ . _ - . . - _ _ . , _ . , _ _ - - - - - - _ , _ .
._,_.,___--.------_m.-
. . ,
-
_ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
_ _ _ _ _ _ _
__ .__
l
!
i
I
113
'
,
!
!
SON-DC-V-2.15, Containment Isolation
SON-DC-V-7.5, Fire Protection Systems
!
f
SQN-DC-V-7.6, Proprietary Protective Signal Systems for Fire Alarm and
Supervisory Service
SQN-DC-V-27.3, Design Criteria for Safet,*. Injection System
!
SOEP-29, Procedure for Preparing Design Basis Document for Sequoyah
l
Nuclear Plant
l
SQNP-DC-V-7.4, Essential Raw Cooling Water System
i
Civil Design Guide DG-C1.3.4 - Extreme Wind and Tornado Wind Forces on
l
Structures
l
l
Response to High Containment Pressure, Functional Restoration Guideline
FR-Z.1
t
i
Quality Assurance Plan Westinghouse Nuclear Energy Systems Divisions.
[
WCAP-8370, Revision 7A, February 1975
Westinghouse Water Reactor Divisions Quality Assurance Plan, VCAP-8370,
i
Revision SA, September 1977
Westinghouse Water Reactor Division Quality Assurance Plan, WCAP-8370,
Revision 9A, October 1979
i
i
Nuclear Fuel Division Quality Assurance Program Plan, WCAP-7800, Revision
!
5, December 1977
Westinghouse Water Reactor Divisions Quality Assurance Plan, WCAP-8370,
!
Revision 9A Amendrent 1. February 1931
l
t
Water
Reactor
Divisions
Quality
Assurance
Plan,
WCAP-8370/7800, Revision 10A/CA, August 1934
f
CE-CPA-546 - System Functional Requirements for Systems Safety Injection
l
System Actuation: a) 515 Actuation and Reactor Trip, b) Containment Spray
Actuation, M. A. Mangan, R. M. Reymers, May 6, 1970, TVA-300/6
.
Nuclear Engineering Procedure NEP 9.1, Corrective Action
10 CFR Part 50.59, changes, Tests and Experiments
Regulatory Guide 1.105, November 1975, Instrument Set Points for Safety
}
Related Items
i
l
'
Regulatory Gu;de 1.29, Seismic Design Classification
t
!
!
I
.
- -
_ _ _ _ _ . _ _ _ - _ ._
__
_ _______ ______
_ - _ _ _
____
_
_ _ _ _ _ . ,
'
.
114
P
Regulatory Guide '1.53, June 1973, Application of the Single Failure
h
Criterion to Nuclear Power Plant Protection Systems
'
10 CFR 50.59, Equip <nent Qualification
10 CFR 50, Appendix A, 1970 Oraft Version
10.
Persons Contacted
t.icensee Ernployees
- S. A. White Senior.Vice Fresident, Nuclear Power
"J, T. Bynum, Assistant Manager, Nuclear Power - Operations
- H
L. Abercrombie, Site Director
"J. T. La Point. Deputy Site Director
- S. Smith, Plant Manager
- J. Patrick, Operations Group Manager
R. J. Prince, Radiological Control Superintendent
- M. J. Ray, Licensing Group Manager
L. E. Martin, Site Quality Manager
- P. G. Trudel, Project Engineer
R. W. Olson, Modifications Branch Manager
J. M. Anthony, Operations Group Supervisor
R. V. Pierce, Mechanical Maintenance Supervisor
M. A. Scarzinski, Electrical Maintenance Supervisor
H. D. Elkins, Instrunent Maintenance Group Manager
R. S. Kaplan Site Security Manager
J. T. Crittenden, Pubite Safety Service Chief
R. W. Fortenberry, Technical Support Supervisor
J. H. Sullivan, Regulatory Engineerf ng Supervisor
J. L. Hamilton, Quaitty Engineering M . nager
- H. R. Rogers, Plant Operations Review Staff
-
M. A. Cooper, Compliance Licensing Supervisor
R, M111s, EQ Engineer
Roger Field - Principle Engine,'r, CEC /CSG
Nat Foster - Technical Supervisor, CEB/CSG
Kreis Lester - Technical Supervisor, CEB/CSG
Charlfe Jchnson - Lead Engineer, CEB/CSG
Carl Barker - Technical Supervisor, CEB/CSG
Mike Edward - Technical Supervisor, CES/CSG
Orhan Gurbuz - Consultant, Bechtel
Chang Chen - Censultant, Gilbert Con etwealth
"Raj Kundelkar - Assistant Lead Engineer, CEB/CSG
Coleman Haskin - Engineer, CEB/CSG
George East - Section Manager. SWEC
Cebbie Burch. Mechanical Ergineer
Calvin Burrell, Mechanical Engineer
Stan Duke, Mechanical Engineer
.
-_- _
_ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _
__
,
'
-
..
!
115
l
!
i
!
Chris Fulwider, Principal Mechanical Engineer
s
Roger Gist., Mechanical Engineer
'
Mike Hammond. Mechanical Engineer
!
Roy Hoekstra, Principal Civil Engineer
.
'
Ken House, Section Supervisor
T. J. Means, Design Engineer Associate Mechanical
"Ken Mogg, EMG Lead Engineer
,
Bill Roberts, Principal Civil Engineer
[
George B. Sanders, Project Engineer (G/C)
!
- Mark Serhal, Nuclear Engineer
!
Jim Southers, Design Engineer, Associate Mecnanical
l
- Ed Steinhauser, Lead Engineer
'
J. M. Warren, Mechanical Engineer (G/C)
Charles W. Whitehead Project Engineer (G/C)
- R. C. Williams, Electrical /I&C Team Leader
!
"
M. B e an, Electrical Engineer
R. Hall, Principal Electrical Engineer
A. Pal, Electrical Specialist
!
.
J. Hutson, Assistant Chief Electrical Engineer
j
.
J. Edwards, Electrical Group Leader
S. Ga11ager, Electrical Engineer
i
,
A. Raju, Electricc1 Engineer
i
3
S. Jackson, Mechanical Engineer
a
Joseph Drago, Engineering Specialist
!
,
Robert Adkison, Civil Engineer
Rick Daniels, lead Mechanical Engineer
i
j
Bob Bryan, Nuclear Engineering Staff Specialist (Knoxville through
Mark Serbs1)
t
Randy Devault, Nuclear Engineer
j
- Frank Denny, Engineering Assurance
Aubrey Co'eman, Mechanical Engineer
i
I
Other licensee employees contacted included technicians, operators, shift
!
engineers, security force members, engineers ar * naintenance personnel,
j
NRC Representatives
'J. G. Partlow, Director, Office of Spot.fal Projects (OSP)
f
,
Division. OSP
7
'R, Pierson, Bran:b Chief, Plant Systems Cranch, OSP
l
'
"J. N. Donchew, Project Manager, Sequcyah Restart, OSP
l
"Attended exit interview
t
r
11.
Exit Interstew
[
I
t
The inspection scope and findings were sumari:ed with the Plant Manager
.
and re:cers of his staff en July S. 1555.
Four violattens cascribed in
I
l
this report's Sumary paragrapn were discussed.
No deviations were
{
i
4
. _ - - . -
- - _ -.- _.
- - - _ -
.
_-
_ - - -
-
_ _ _ _
116
)
discussed.
The licensee acknowledged the inspection findings.
The
-f t he material reviewed by
licensee did not identify as proprietary
,
'= resorting period,
the inspectors during this inspection.
v.
frequent discussions were held with the Site
.
'r, Piant Manager an<
other managers concerning inspection findings.
"
12. Acronyms and Initialisms
ABGST -
Auxiliary Building Gas Treatment System
I
ABSCE -
Auxiliary Puilding Seccndary Containment Enclosure
-
Administrative Instruction
AI
-
AOI
-
Abnormal Operating Inst uction
AVO
-
Auxiliary Unit Operator
Assistant Shift Oparating Supervisor
A505
-
BIT
-
Boron Injection Tank
C&A
-
Control and Auxiliary Building-
CAQR -
Conditicns Adverse to Quality Report
-
Centrifegal Charging Pump
CCTS -
Corpor Tte Commitment Tracking System
COPS -
Cold Overpressure Protection System
CSH
-
CSSC -
Critical Structures, Systems and Corponents
-
Containment Ventilation Isolation
-
Direct Current
DCN
-
Design Change Natice
Division of Nuclear Engineering
-
ECCS -
Emergency Core Conling System
-
,
EI
-
Emergency Instructions
ELM
-
Electrical Loading Matrix
-
Emergency Notification System
Engineered Safety Feature
-
-
Flow C;-trol Valve
FSAR -
Final Safety Analysis Report
General Design Criteria
GDC
-
GL
-
Gere-ic Letter
Hand-operated Indicating Controller
-
Hold Order
H0
-
Health Physics
-
Heat Exchanger
-
ICMS -
Insulation Consultants and Manage ent Services
IN
-
NRC Information Netice
Inspector Followup Item
IFI
-
Instrument Maintenance
IM
-
Instrument Maintenance Instruction
IMI
-
IR
Inspe: tion Report
-
Kilopound Thru:t
KP
-
Kilovolt-Arp
KVA
-
Kilowatt
AW
-
.
-
..
.
117
Kilovolt
KV
-
LER
Licensee Event Report
-
LCO
-
Limiting Condition for Operation
Loss of Coolant Accident
-
Maintenance Instruction
MI
-
NB
NOC Bulletin
-
-
Nuclear Regulatory Commission
NRC
-
OSLA
Operations Section Letter - Administrative
-
Operations Section Letter - Training
OSLT
-
Office of Special Projects
-
Post Modificatica Test
-
Plant Operation Review Committee
-
Plant Operation Review Staff
PORS
-
Potentially Reportable Occurrence
PRO
-
Quality Assurance
-
Quality Control
-
-
Regulatory Guide
AG
-
Radiation Monitor
-
-
Radiation Work Permit
-
Reactor Water Storage Tank
-
Sa/ety Evaluation Report
-
-
Surveillance Instruction
-
SOI
-
System Operating Instructions
SOS
-
Shift Operating Supervisor
Sequoyah Standard Pr ' ice Maintenance
SQM
-
.
Surveillance Requi.<ments
SR
-
Senior Reactor Operator
-
SSQE -
Safety System Quality Evaluattor.
Special Test Instruction
-
SYSERS-
System Evaluation Report
Temporary Alteration Control Form
TACF
-
Tracking Open Itens
TROI
-
Technical Specifications
l3
-
Tennessee Valley Authority
-
Unresolved Item
-
Unreviewed Safety Question Determ' nation
USQD
-
Work Control Group
WCG
-
Work Plan
WP
-
Work Roquest
-
_ . ._.
- Print' Diagnostics for: 3650 3577
.
Total Formatting Exceptions = 2
Total Listed Below = 2
Tha Following Two Formats Will Be Used:
fage/Line
Format Exception Message Found By The IBM 5520
Sneet Number
Format Exception Message Found By The Printer
1.0.0/13
1187+End Underline Control Deleted
74.0.0/32
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