IR 05000336/1989003
| ML20236A569 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 03/06/1989 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236A567 | List: |
| References | |
| 50-336-89-03, 50-336-89-3, IEB-83-06, IEB-83-6, IEB-87-002, IEB-87-2, IEB-88-011, IEB-88-11, IEIN-83-07, IEIN-83-7, NUDOCS 8903170443 | |
| Download: ML20236A569 (45) | |
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U.'S. NUCLEAR REGULATORY COMMISSION
REGION I
. Report No.
50-336/89-03-
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, Docket No.-
50-336
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License No.
OPR-65 Licensee:
Northeast Nuclear Energy Company
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P.O. Box 270 Hartford, CT- - 06101-0270
.l Facility.Name: Millstone Nuclear Power Station, Unit 2
' Inspection.~At:,Waterford, Connecticut-Dates:
' January 11 through February 10, 1989
- Reporting ~
. Inspector:
P. J. Habighorst,' Resident Inspector
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Inspectors:
-W J. Raymond, Senior Resident Inspector, M111ston.e
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G. S. Barber.. Resident Inspector, M111 stone 3
L. M. Kolonauski, Resident Inspector, Millstone.1 Approved by:-
% O. k dele,h 3/6/et-E. C. McCabe, Chief, Reactor Projects Section 18 Date.-
Inspection' Summary:
1/11/89 - 2/10/89-(Report 50-336/89-03)
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2 Areas Inspected: Routine NRC resident inspection (174 regular huurs, 4 backshift
' hours, and 8.5 deep backshift hours), of plant operations, outage activities,.sur--
'veillanco, maintenance, previously identified items, NRC bulletin 1 follow-up, Plant-Incident. Report (PIR) follow-up, design changes and modifications,.and committee'
activities.
' Resul ts': 'No unsafe conditions were identified. No violations or deviations-were identified. Attached to this report is the licensee's January 26 presentation on-Steam Generator (SG) Eddy Current Testing (Detail 9.0).
Four previously identified items were closed (Detail 3.0),
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8903170443 890306 PDR ADOCK 0500
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TABLE OF CONTENTS
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j 1.0 Persons Contacted....................................................
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2.0 Summary of Facility Activities.......................................
3.0 Previously Identified Items (92701/90712/9370).......................
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3.1. (0 pen) IFI 88-10-03: Differences Between Form 2540-1 " Functional'
Recovery Safety Function Status Check (SFSC) and the Safety Parameter Display System (SPOS) in the Emergency Operating P ro c ed u re s ( E0P s ).............................................
3.2 (Closed) TI 2500/26, Fastener Testing to Determine. Conformance l
with Applicable Material Specifications (IEB 87-02)...........
3.3 (Closed), Violation 87-16-02: Inadequate Fire Barrier Separating the West Electrical Penetration Room from the Auxiliary Building due to No Fire Damper in Ventilation Duct............
3.4 (Closed) IEB 83-06: " Nonconforming Materials Supplied by the Tube-Line Corporation"........................................
3.5 (Closed)'IFI 87-22-01: Incorrect Reporting of Wind Direction....
4.0 Facility Tours (71707)..............................................
5.0 Plant Operational Status Reviews (71707).............................
5.1 Review of Plant Incident Reports (PIRs).........................
5.2 Main Steam Line Code Safety Valve Failure (PIR 89-10)..........,
5.3 Mechanical Snubber Failure (PIR 89-09)..........................
6.0 Outage Activi ti es (60710/37700/71707)................................
6.1 Pre-Refueling Activities........................................
6.2 Radiological Contrt's for S/G Nozzle Dam Installation...........
7.0 NRC Bulletin 88-11 " Pressurizer Surge Line Thermal Stratification" (73753/92700)................................................
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i 8.0 Physical Security (81700)............................................
8.1 Contraband within the Protected Area............................
9.0 Steam Generator (SG) Eddy Current Testing (ECT) Presentation (73753).
10.0 Allegations by Former Securi ty Guard (RI-87-A-137)..................
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' Table'of Contents PAGE 11.0 Committee Activities (40500).........................................
12.0 Maintenance (62703)..................................................
13.0 Surveillance Testing (61726).........................................
14.0 Management Meetings (30703)..........................................
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l DETAILS 1.0 Persons Contacted i
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Inspection findings were discussed periodically with the supervisory and man-
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agement personnel identified below, S. Scace, Millstone Station Superintendent J. Keenan, Unit 2 Superintendent
J. Riley, Unit 2 Maintenance Supervisor
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F. Dacimo, Unit 2 Engineering Supervisor D. Kross, Unit 2 Instrument and Controls Supervisor J. Smith, Unit 2 Operations Supervisor The inspector also contacted other members of the Operations, Radiation Pro-tection, Chemistry, Instrument and Control, Maintenance, Reactor Engineering, and Security Departments.
2.0 Summary of Facility Activities The unit was at full power from the beginning of the inspection period until February 4.
During this period the licensee experienced an electrical ground on safety-related battery bus 201A and intermittent electrical grounds on_the main generator field. The-licensee implemented the ground isolation procedure for bus 201A, but the cause of the ground was not identified during power
~4 operation. On February 6 the ground was traced to the steam generator SG-1 feed pump trip reset circuit. The licensee continues to investigate the cause for the intermittent electrical ground on the. main generator field.
l The-plant began to shut down for the cycle 9 refueling outage at 12:15 a.m.
on February 4.
Major outage work includes: SG eddy current testing, imple-mentation of Anticipated Transient Without Scram (ATWS) provisions, in-service testing-of the reactor vessel and reactor coolant system, and service water pipe replacement.
3.0 - Previously Identified Items (92701/90712/93702)
3.1 (Open) Inspector Follow Item (IFI) 88-10-03: Differences Between Form 2540-1, " Functional Recovery Safety Function Status Check " (SFSC) and the " Safety Parameter Display System" (SPDS) in the Emergency Operating Procedures (E0Ps)
This item concerns five differences between the SPDS and the safety func-tion status check sheet. The discrepancies and licensee actions follow.
3.1.1 Containment Hydrogen Concentration E0P 2532 SFSC Condition 2.b.i.i., states the containment hydro-
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gen concentration decision point as less than 2%, which differs from the value of "less than 3%" on the SPDS.
Plant Operations
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ReviewCommittee(PORC) meeting 2-88-181 approved a revision to E0r 2532.
The revision added "less than 3%" hydrogen con-centration to assure containment integrity for Condition 2.
(Condition 2 requires emergency boration to shut down the reactor in lieu of.the control element assemblies (CEAs).
For Condition 1, the CEAs are' inserted to shut down the reactor,
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and the hydrogen concentration limit is.less than 2%).
h The inspector reviewed the' technical basis for the 3% hydrogen concentration.
The documents reviewed follow.
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OP 2313C, " Containment Post Incident Hydrogen Control,"
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Rev.-12.
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Final Safety Analysis Report (FSAR) Section 14.8.
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E0P 2532, " Loss of Primary Coolant."
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CEN-152, Rev. 2 " Emergency Procedure Guidelines."
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CEN-152, Rev. 2 recommends a plant specific limit to prevent
. containment atmosphere from reaching the flammable hydrogen i
concentration of 4%.
E0P 2532.(Step 3.36) directs the control room operators to place the hydrogen recombiners in operation if the containment hydrogen concentration exceeds 1.5%.
This step is performed in parallel-with the SFSC. The contingency l
action for Step 3.36 directs the operators to purge containment per OP 2313C if the recombiners are inoperable. or if the hydro--
gen concentration.is greater than 3%.
'i The inspector reviewed FSAR Section 14.18,." Hydrogen Accumula-tion.in Containment," to determine the containment integrity impact of changing the SFSC criterion from less than 2% to less than 3%. The analysis.shows a 3% volume fraction for hydrogen
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approximately 12 days after the LOCA.
The time. difference t.
between reaching 2% and 3% hydrogen concentrations is 8 days.
Based on FSAR Section 14.18.3.1, the preferred starting time i
for the hydrogen recombiners is one day after the LOCA. The FSAR concludes the peak hydrogen concentration would then reach 1.7%.
FSAR Section 14.18.3.3 concludes that hydrogen recombiner operation could be delayed as long as 19 days after a LOCA and still maintain the hydrogen concentration below the 4% concentration spec;fied in NRC Safety Guide 7.
This item is closed.
3.1.2 Instrument Air Header Pressure
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For instrument air (IA) becder pressure, SFSC Step 6.c in E0P 2532 indicated " greater than 90 PSIG" and the SPDS indicated
" normal." The licensee's corrective action was to change ac-ceptable SPDS vital instrument air pressure to greater than
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90 PSIG. The inspector verified the change.
No discrepancy
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now exists between SPDS-and SFSC..The inspector also reviewed OP 2332 B, Rev. 9, " Instrument Air System," and verified.the control room " Instrument Air Ho der Pressure Lo" alarm on panel C06/C07 setpoint is 88 psig. Tht: initiating pressure switch'
PS-7079 for the control room alarm is also the input into the SPDS computer program. This item'is closed.
3.1.3 Containment Pressure
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The' third discrepancy between SPDS and SFSC was containment pressure. The SFSC criterion was less than 2 psig; the SPDS criterion was less than 5 psig.
Revision of E0P 2532, per PORC meeting 2-88-181, changed the SFSC criterion to less'than 5'psig.
The containment spray actuation signal (CSAS) setpoint at M111 stone 2 is.27 psig. 'FSAR Section 14.16.3 states the as-sumed_ start. time for the containment spray system is 56.3
seconds assuming a 30 second delay. The 27 psig setpoint is reached 6 seconds after the initiation of the DBA (Design Basis Accident).
E0P 2532, Step 3.13 directs the control room opera-tor to~ secure and reset the CSAS for automatic actuation when
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The inspector contair, ment pressure is less than 10 psig.
questioned the licensee on.the bases for.the SFSC change from 2.psig to 5 psig. The licensee responded.that the containment response outcome is unaffected. The inspector had no further questions.
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Decay Heat Removal The fourth discrepancy between SPDS and the SFSC was on the heat removal function in E0P 2540, " Functional Recovery." The SFSC acceptance condition indicated " feed flow." SPDS accept -
ance criteria indicated a minimum value of 300 gpm for Auxil-iary feedwater flow, with no mention of main feedwater flow.
The licensee changed the SPDS acceptance criteria to indicate
" greater than zero" for both main and auxiliary feedwater flow.
The inspector asked whether the main / auxiliary.feedwater flow could read "no flow" based on differential pressure transmitter
" drift". The licensee then confirmed, on the training simula-tor, that a malfunction in the feedwater and/or auxiliary feedwater system would not necessarily result in "zero" indi-cated flow. The licensee committed to reevaluate minimum feed
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flow and instrument drift values to address this item.
I The inspector reviewed the guidance provided in CEN-152 Rev.
2 to determine if sufficient indication is provided to control room operators to determine if the decay heat removal of the
steam generators is acceptable, considering potential inade-quacies in feed flow determination.
The guidance identifies
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parameters such as' steam generator pressure and reactor. coolant-
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. System average temperature.as. determinants of_SG heat removal
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capability : E0P 2526, Standard Post Trip Actions, provides-
-for a feedwater. system alignment check prior to functional usage of SPOS or SFSC.
The inspector will review the.licen--
'see's. evaluation of acceptable feedwater.flowrates in' future
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inspections.
3.2.(Closed) TI 2500/26, Fastener Testing to Determine Conformance with'
Applicable Material. Specifications (IEB 87-02)
The.NRC' issued'IE Bulletin 87-02 on November 6, 1987 to request licensees
.to review receipt inspection requirements for fasteners.and to determino, through independent) testing, whether fasteners'in stock meet required R
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mechanical and chemical specifications.
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The licensee responded to IE Bulletin 87-02 by letter dated January'12, 1988.
Inspector review (Inspection Report 50-423/88-02)'found that let-ter responsive to the information requested by the Bulletin.
Out of-160 r
fasteners-sampled, seven' discrepancies were identified. Of.the seven,
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two'were found to be' nonconforming. Nonconformance Reports (NCRs) were
written..These two fasteners were dispositioned to use "as is"'since their out-of-tolerance condition (within 2% of ASTM EIO measurement ac-curacy) did not significantly affect their strength, ductility or cor-
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rosion resistance. ~The licensee concluded that no additional actions relative to the fasteners in. stock were' warranted.
During this previous inspection, the. inspector _noted no inadequacies in licensee plans or.
conclusions.
However, the inspector planned further review of TI 2500/26,
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' items 5.01 and 5.02 regarding receipt inspection.
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I TI Items 5.01 and 5.02 specified a comparison of the licensee's receipt inspection program / procedures, maintenance warehouse procedures, and the licensee's descriptions in the bulletin response.
The inspector per-formed the comparison and noted that the bulletin response accurately summarizes the requirements'of the following procedures: QSD 3.08, Per-formance of Receipt Inspection Activities; and QSD 3.07,. Preparation, Performance and Reporting'of Source Inspections. No inadequacies were noted.
This TI is closed.
3.3 (Closed) Violation 87-16-02: Inadequate Fire Barrier Separating the West Electrical Penetration Room from the Auxiliary Building Due to No Fire Damper in Ventilation Duct This item concerned the fire barrier separating the west electrical penetration room and auxiliary building. The barrier did not have a three-hour rating as described in the Fire. Hazards Analysis. A three-hour rating was not appropriate because the main exhaust ventilation duct penetrating this barrier did not have a fire damper. The licensee had not performed an analysis to support the acceptability of this deficiency.
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Licensee evaluation 86-10 " Lack of Damper in Ductwork between 10 CFR L-50 Appendix' R Fire Area R-1 and R-2," concluded that a fire damper is not. required in this.. location.
NRC inspection concurred, based on the
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Lsmall fire loading in the affected areas.
In Inspection-Report 50-336/
87-16,.the' licensee was informed of that. concurrence, but absence of supportive evaluation in the. Fire Hazards Analysis constituted'a viola-i tion. The corrective. actions taken by the-licensee satisfied the NRC D
concerns documented in report 50-336/87-16.
The inspector reviewed -licensee evaluation 86-10.
The fire. areas have f
a 16-minute fire load for-the West Electrical.' Penetration. Area and a.
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23-minute load for the ' Auxiliary Building Area. The combustible materia 1I in both' areas consists primarily of electrical cable insulation withufire-
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retardant properties. R-1 and R-2 both have ionization smoke. detection capability.
Fire. suppression is achieved with fire extinguishers, re -
.sponse of.the Fire Brigade, and a wet pipe sprinkler system installed:
sin R-2nduring the 1988 refuel outage.
No' inadequacies were identified.
j This item is closed.
l 3.4 (Closed) IEB.83-06: Nonconforming Materials Supplied by the Tube-Line
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Corporation-In' NRC 'Information Notice 83-07 ' dated March 7,1983,. power reactor lic :
-ensees received-notification of nonc'onforming materials supplied by the
Tube-Line (T-L)-Corporation. The NRC subsequently issued NRC Bulletin 83-06 on July 22, 1983,~after NRC inspections of T-L facilities identi-fied the potential for generic safety implications. - The licensee-re-sponded to Bulletin 83-06 by letter dated November.7, 1983.
Licensee review identified 'no direct T-L shipments to Millstone, but confirmed that the 1982 receipt of 342 stainless steel flanges from Guyon
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Alloys, Incorporated was, accompanied by T-L documentation. This trans-
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action was listed-in Attachment:3 to IEB 83-06. The-licensee determined, through review of description an'd heat code information. supplied by T_L, that 289 of the 342 flanges = lacked annealing heat treatment..The licen-see placed:the 341 in-stock flanges in a non-conforming hold status. prior.
to their return to' Guyon Alloys. The remaining 150 pound, 4" stainless steel blind-flange had been issued and was discarded because it was con-taminated.
The licensee concluded that no T-L supplied materials were
.being used in safety-related applications at Millstone 1 or 2.
No in-adequacies were identified.
The inspector had no further questions.
3.5 (Closed) IFI 87-22-01: Incorrect Reporting of Wind Direction This item addressed the incorrect wind directions reported by the Shift Supervisor Staff Assistant (SSSA) during the October 8, 1987 emergency exercise. NRC combined Inspection Report 50-245/88-23; 50-336/88-26; 50-423/88-20 covered the licensee's annual emergency preparedness exer-cise conducted on November 16, 1988 and reported closure of the associ-ated inspector followup item (IFI) 50-423/87-20-01 after the inspectors
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h verified correct licensee reporting of, wind direction:during the.1988 o
exercise. The report,- however, did not close the associated Millstone-l'and 2 inspector followup items, 50-245/87-26-01.and 50-336/87-22-01.
ihose-items.also are closed based on the November 16, 1988 exercise.
40 Facility-Tours (71707)
The. inspector observed plant operations during regular and backshift tours of.the following areas:
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Control Room-Containment Vital Switchgear Room Diesel Generator Room Turbine Building Intake Structure Enclosure Building ESF Cubicles Control room instruments were observed for correlation between channels, pro -
per functioning,-and conformance with Technical ~ Specifications. Alarm condi-
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tions in effect and alarms received in the control room were discussed with I
operators. The inspector periodically reviewed the night order log, tagout
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log, Plant' Incident ~ Report (PIR)L log, key log, and bypass jumper log. Each of the respective logs was discussed with-the operations department staff.
1No inadequacies were noted.
I During plant tours, logs and records were reviewed to ensure compliance with j
station procedures, to determine if entries.were cor'rectly made, and to verify correct communication and equipment status.
No inadequacies were noted.
5.0 Plant Operational Status Reviews (71707)
5.1 Review of Plant' Incident Reports (PIRs)
.The plant incident reports'(PIRs) listed below were reviewed during.the inspection period to (i) determine the significance of the events; (ii) review the licensee's evaluation of the events; (iii)' verify the-licensee's response and. corrective actions V:r: pr:p3r; and, (iv) verify that the licensee reported the events in accordance with applicable re-quirements, if required.
The PIRs reviewed were 89-01 thru 89-10. The following items warranted inspector follow-up:
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PIR 89-10 " Main Steam Line Code Safety Valve Failure" (Detail 5.2)
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PIR 89-09 " Mechanical Snubber Failure" (Detail 5.3)
5.2 Main Steam Line Code Safety Valve Failure (PIR 89-10)
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The licensee performed main steam safety valve " simmer" testing on February 4, 1989. The plant was in hot standby (Mode 3), at 0% power, 525 degrees Fahrenheit, and 2250 psig. The " simmer" test purpose was l
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l to verify compliance with the Limiting Condition of Operation (LCO) of
Technical Specification TS 4.7.1.1.
The licensee reported that six.(6)
out of sixteen (16) valves failed the initial test.
i The licensee conducts this test with a hydroset unit. The hydroset re-
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duces spring pressure without raising main steam line pressure, allowing j
the safety valve to lift. The licensee calculates the safety valve ac-l tuation pressure based on the hydroset pressure and steam line header
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pressure.
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i The main steam safety valve ac.ceptance criteria is +/- one percent of the setpoint. The six valves that failed were: 2-MS-240, 2-MS-242, 2-MS-245, 2-MS-246, 2-MS-250, and 2-MS-252.
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l The "as-found" set pressures were: -2% for 2-MS-240, -2.7% for 2-MS-241, l-2.0% for 2-MS-245, -5.2% for 2-MS-246, +1.3% for 2-MS-250, and -4.1%
for 2-MS-252.
These are eight-inch, spring loaded code safety valves j
maintained under American Society of Mechanical Engineers (ASME) Code Section III, Class 2, 1970 Summer edition. The licensee adjusted five of the six discrepant valves and conducted two consecutive acceptable j
tests of each.
Safety valve 2-MS-240 was retested and adjusted'five separate times with only one acceptable test.
The licensee plans to send valve 2-MS-240 to a contractor facility for independent testing, rework,
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and reinsta11ation prior to plant startup.
l The inspector reviewed past documentation concerning main steam code
'i safety valve testing.
The documents reviewed were o
Licensee Event Reports (LERs) 86-008-00, 86-008-01, 87-014-01.
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NRC Inspection Report 50-336/86-21.
Advanced Nuclear Fuel (ANF) Safety Analysis Report 87-161.
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Final. Safety Analysis Report (FSAR).
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NRC Information Notice 86-56, " Reliability of Main Steam Safety
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Valves."
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ASME Section XI Subsection IWV-3510 dated July 1,1974.
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LER review showed that, in the past two safety valve surveillance, the licensee had six (in 1986) and twelve (in 1987) valves that failed the initial " simmer" test.
In 1986, the licensee's corrective action was to improve the test method by: 1) increasing the accuracy of pressure gauges on the hydroset from a +/- 5 psi error to a +/- 1 psi error; ii) valve spring and ambient temperature data collection to aid in dup-lication of re-test conditions; and iii) valve temperature stabilization
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Other corrective action included a revision to the l
test procedure acceptance criteria to require two consecutive tests I
within the setpoint tolerance for an overall acceptable test.
In 1987,
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l additional licensee corrective action was to increase the number of safety valves sent to a contractor for refurbishment from four to six
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valves every refueling outage.
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The inspector reviewed ANF 87-161, " Safety Analysis Report".
That review addressed the " Closure of a Single Main Steam Isolation Valve (MSIV)"
and " Loss of External Load" event analyses.
The document states the safety valves were modeled with a +/- 3% drift allowance.
The licensee's TS limit is +/- 1% of setpoint.
The ANF 87-161 analyses concluded that, I
with the 3% drift allowance applied to all 16 safety valves in the non-conservative direction, the calculated secondary pressure transient was less than the design pressure (1100 psi). A review of licensee calcula-tion W2-517-845-RE was conducted. The licensee reanalyzed the steam generator tube rupture (SGTR) event and loss of load events in calcula-tion W2-517-845-RE.
For the SGTR event, setpoint drift would result in increased steaming to the atmosphere and an increase in offsite dose.
For the loss of load event, the setpoint drift affects peak steam gene-rator pressure. The analyses concluded there was a negligible effect on offsite doses and a slight SG pressure increase below design limits on loss of load events.
For the specific valve errors found on February 4,1989 (including the 4.1% and 5.2% errors), the analysis concluded that design basis functions were not compromised.
The inspector will review licensee actions to minimize setpoint drift on main steam safety valves in future inspections.
5.3 Mechanical Snubber Failure (PIR 89-09)
On February 5, the licensee identified a functional test failure of mechanical snubber serial number 22332 on support 402008.
The plant was in hot shutdown (Mode 4) and reactor coolant system temperature at 270 l
degrees Fahrenheit.
The mechanical snubber was a one-inch support on the common shut-down cooling suction for both low pressure safety injec-tion pumps.
The licensee identified the failure during required tech-nical specification (TS) surveillance 4.7.8.e, " Mechanical Snubber Func-tional Test." The licensee is required to select a representative sample (10% of each type of snubber, mechanical and hydraulic) to test every eighteen months. The functional test acceptance criteria are: (1) the
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drag force to initiate free movement is less than the specified maximum; and (ii) activation is achieved within the specified range of velocity or acceleration in both tension and compression. The failed mechanical snubber was found " locked-up" in the normal position during licensee bench testing.
The failure was excessive force being required to in-itiate free movement.
Procedure EN-21149 requires mechanical snubber #22332 to be operable in refueling (Mode 6) to support shutdown cooling. The inspector questioned the licensee on the basis for selecting plant refueling for surveilling this mechanical snubber's operability.
TS 3.7.8 specifies snubber oper-ability in Modes 5 and 6 for snubbers on systems required to be operable then.
TS 3.4.1.3, " Reactor Coolant Systems," requires shutdown cooling
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loop operation with RCS temperature less than 275 degrees Fahrenheit (Modes 4 and 5). Mechanical snubber #22332 is located in the shutdown cooling system and thus should be operable in plant Modes 4, 5, and 6.
The inspector will review this item further.
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The licensee's initial corrective action was a replacement of the me-
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chanical snubber under authorized work order (AWO) M2-88-12941 on Febru-
ary 5, 1989.
TS 4.7.8.c requires, for any snubber found inoperable, that
an engineering evaluation be conducted on components supported by the snubber. The purpose of the engineering evaluation is to determine if components were adversely affected by snubber inoperability. The licen-see generated engineering evaluation PIR 89-9-1050GP, Millstone 2 Stress Problem No. 46-Snubber Lock-up, on February 5.
The evaluation assumed the failed snubber was a rigid restraint, and evaluated the shutdown cooling system impact during a thermal transient at the design tempera-ture of the piping (300 degrees Fahrenheit).
The licensee analyzed the i
system to American Society of Mechanical Engineer (ASME)Section III, 1974 edition. The resultant stresses on the piping were compared to ASME III allowables, and the licensee determined-the values were acceptable.
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The licensee also evaluated the support and anchor loads.
In two sup-l ports (R-4 and R-5), design loads were exceeded by the assumed condition.
j The licensee then evaluated each of the two supports and concluded no j
structural failure would occur during an analyzed event. The inspector
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discussed evaluation PIR-89-9-1050GP with the licensee and agreed with the licensee's conclusion.
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As a result of a failed mechanical snubber, the licensee is required per TS 4.7.8.c to test an additional 5% of all mechanical snubbers.
The i
inspector' verified the additional snubbers are to be tested based on review of the licensee's snubber work list.
No inadequacies were noted.
The licensee's program for the 1989 refueling outage inclwdes a 100%
visual inspection of all safety-related snubbers. All snubber functional bench-testing is performed by the licensee at the station. According to the licensee, all mechanical and hydraulic snubbers (except eight-inch hydraulic snubbers) selected for functional testing are one-for-one re-
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placed, and the removed snubber is tested later. A dedicated staff engineer is responsible for the snubber testing program.
No inadequacies were noted.
6.0 Outage Activities (60710/30700)
6.1 Pre-Refueling Activities The inspector conducted sampling inspections of TS required surveillance and plant conditions to verify that significant items were accomplished i
I prior to refueling (Mode 6). These inspections included control room l
activities, plant shutdown / reactor shutdown, licensee outage meetings,
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' the Cycle' 10 core reload Plant Design Change-Reques't (PDCR),- control.off
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containment activities,' licensee commitments.in. response to NRC Generic-
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' Letter 88-17, " Loss of Decay Heat Removal," and management controls.
The-TS surveillance inspected included: boron concentration in the'
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reactor; coolant system and. refueling canal.(TS 3.9.1), containment in-
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~~tegrity. during-control element assembly-(CEA) movement- (TS 3.9.4), shut-
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down cooling loop operation (TS 3.9.8.1),uminimum-re' actor cavity water
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. level (TS 3.9.11), boron injection flowpath operability (TS 3.1.2.4),
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power-operated relief valve status (TS 3.4.3), Low-Temperature 0ver-Pressure Protection (TS 3.4.9.3), shutdown. margin calculations.(TS 3.1.1),
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. reactor coolant system cool-down rates (TS 3.4.9.1), shutdown electrical-distribution (TS 3.8.2.2), diesel generator operability-(TS 3.8.1.2),-
reactor decay-heat determination (TS 3.9.3.1), source range. monitor operability.(TS 3.9.2), de-energized control element drive mechanisms'
-(CEDMs) (TS 3.1.3.7), and control room manning (TS 6.2.2.c).
The'in-i spector verified the acceptability of.TS surveillance by control room indications, local indications, and discussions with control room opera-
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. tors.-
The' inspector witnessed control room activities during steam plant shut-j down, reactor shutdown, and plant cooldown on February 4 and 6.
Proce-
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dures OP-2206, Rev. 6, " Reactor Shutdown," and OP-2207, Rev. 14, " Plant
. Shutdown'N we re.util i zed.
Overall, the plant. shutdown. evolution was con-
- i ducted well: there was good adherence to technical specification. and-
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procedure requirements. Two: exceptions-were'noted as discussed below.
During.the plant cooldown on February 4, the inspector.noted that pre-
'ceution 4.32 and Step 5.2 of'0P-2207 were not completed by the' control V
room operators. The procedure step implements TS 3.1.3.7, requiring 'that the CEDMs be de energized prior to-cooling down the plant in order to preclude'a. rod withdrawal accident in a condition outside the plant'
u fety' analyses. The' procedure requires that, with Reactor Coolant Sys -
tem (RCS) boron concentration less than 1720 ppm, RCS temperature:less
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than 500 degrees Fahrenheit, pressurizer pressure less than 2000. psia,
'less than four reactor coolant pumps operating, and the high power trip inoperable, the operator de-energize the CEDMs by either tagging open-the CEDM MG-set output breakers, or removing and tagging the coil power programmer output cables for all CEA's. The inspector noted at 5:23 p.m.
on' February 4 that the' control operator was implementing Step b.9 of OP 2207 and that plant conditions referenced in TS 3.1.3.7 were met, but that no action had been taken to remove the coil power cables or open the output breakers.
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This observation was discussed with the operators. Actions were then taken to perform Step 5.2.
The licensee added the CEDM output breakers to an' existing tag-out (Clearance 2-26'8-89) and opened the breakers as specified in Step 5.2el.
The inspector noted that, prior to this action to comply with Step 5.2, the reactnr trip breakers (RTBs) were open, de-energizing the CEDMs.
Use of the RTBs is recognized in the TS 3.1.3.7 r
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Action Statement as an acceptable method of de-energizing the CEDMs.
Thus, although the operators did not recognize they were in a TS action statement, no violation of the tLanical specification occurred.
OP 2207, Step 5.27.2, is a caution step which requires the operators to
enter TS action statement 3.4.c.3 prior to filling the pressurizer and venting it to the quench tank.
TS 3.4.9.3 requires two operable PORVs.
.With one PORV inoperable, both PORVs must again be operable within seven.
j days or the. licensee must depressurize and vent the RCS. On February
6, inspector review of pressurizer Power-0perated Relief Valve (PORV)
status noted that only one PORV was available for Low-Temperature Over-Pressure (LTOP) protection. The inspector discussed this condition with the control room operators.
The operator entered the TS action statement at 10:30 a.m.
Review of plant operating logs and plant conditions indi-cated the action statement should have been entered at 2:53 p.m. on February 5.
In this case, there was no specific safety significance be-cause:
(i) The TS Limiting Condition for Operation was not exceeded.
(ii) A continuous vent path between the pressurizer and the quench tank was available.
The inspector discussed OP 2207 adherence with the Plant Superintendent and the Operations Supervisor on February 7.
The inspector noted there
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were six cc.nplicated temporary changes to OP 2207 in use for the February l
shutdown.
That potentially affected the ease of use of the procedure.
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The licensee acknowledged the inspector's comments. Operator adherence to procedures and techr.ical specifications will continue to be included in routine. inspections and Systematic Assessments of Licensee Performance (SALPs). Overall, licensee control of activities during plant shutdown /
cooldown was evaluated as good except for the procedure adherence dis-crepancy.
The inspector reviewed PDCR 2-34-88, " Cycle 10 Reload of Fuel." Based on their safety evaluation, the licensee concluded the Cycle 10 reload
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is an unreviewei safety question (USQ) under 10 CFR 50.59 for plant operational Modes 1-4.
(This USQ was included in the reload submittal
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to NRR.) This was based on the conclusion that operation with the new i
core would constitute an increase in the consequences of previous an-alyzed accidents in the Final Safety Analysis Report (FSAR).
Specific-ally, the licensee's conclusion is based on the different method of cal-l culating Departure from Nucleate Boiling Ratio (DNBR) between the pre-
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vious fuel vendor (Westinghouse) and the new vendor (Advanced Nu:: lear J
Fuels). ANF uses statistical methods; Westinghouse used deterministic
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methods.
The ANF results indicate the following potential increases in
consequences.
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A rod ejection accident consequence with an increase in generated
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enthalpy from 174.7 cal /gm to 240.6 cal /gm based on an increased assumption for fuel clad failure.
For rod withdrawal from subcritical conditions, evaluations conclude
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an increase in peak fuel temperature based on the linear heat gene-ration rate.
The licensee concluded the unreviewed safety question had no potential additional impact on protective boundaries, and that all parameters re-mained below the analytical acceptance criteria contained in the NRC Standard Review Plan (SRP).
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l The licensee submitted a TS change request for Cycle 10 fuel load to the NRC on November 15, 1988.
The licensee's TS safety assessment concluded there were no significant hazards considerations in accordance with 10 CFR 50.92. The inspector compared PDCR 2-34-88 and the licensee's TS submittal, and diseussed NRC approval witn NRR. Approval of the unre-viewed safety question is enveloped within approval of the TS amendment request.
The NRC had not approved the licensee's TS amendment request as of the end of the inspection period.
The inspector reviewed 10 CFR 50.59 safety evaluations for the following
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design change / modification PDCRs scheduled so be completed during the refueling outage.
PDCR 2-028-87, Millstone 2 Anticipated Transient Without Scram (ATWS).
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PDCR 2-007-88, Auxiliary Feedwater Steam Bypass Line.
PDCR 2-25-88, Millstone 2 Transfer Canal Qu ck Open Flange.
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PDCR 2-011-88, Secondary Side Stcam Relief hive (SRV).
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PDCR 2-19-88, Millstone 2 Reactor Coolant Pump Vibration Monitoring
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PDCR 2-014-88, Containment Sump Discharoe Pipe Strainer.
l No inadequacies were noted.
Further inspector review will address im-l plementation of the associated modifications.. Quality Assurance Controls, l
functional testing, and verification that preventive maintenance, inser-vice inspection, and inservice test requirements have been included cs
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required, l
Between February 7-9, the inspector reviewed licensee commitments to operate in reduced RCS inventory conditions as documented ir. NRC Inspec-tion Report 50-336/88-28. The inspector verified implementation of ad-ministrative control of containment closure, reactor vessel level and temperature indications and alarms, charging and high pressure safety injection pump availability for inventory make-up, pressurizer manway remcval prior to the last SG nozzle dam installation, and licensee con-
trol of activities to prevent a perturbation on the SDC (sbutdown cool-i ing) system. The inspcctor reviewed licensee activities during RCS
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reduced inventory conditions.
No inadequacies were noted. The inspector j
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found good licensee control of plant shutdown, in-depth safety evalu-
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ations in PDCR 2-34-88, and good control of reduced RCS inventory.
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6.2 Radiological Controls for Steam Generator Nozzle Dam Installation q
On February 8, at approximately 12:30 p.m., the licensee performed radi-l atton surveys for both steam generatcr (SG) primary cavities in prepara-tion for installation of the nozzle dams. The SG nozzle dams provide a watertight barrier between the SG and the reactor te. enable SG eddy current testing (ECT).
The radiation surveys were taken in a four-step approach.
The surveys included: beta / gamma radiation levels outside the manway and inside the SG bowl region; an array of thermo-luminescent dosimeters (TLDs) sup-ported at the SG tube sheet; dry swipes for contamination; and an iso-topic determination using a detector (GeLi). The gamma survey was con-ducted from outside the SG manway with a teletector. The beta radiation levels were evaluated by an R02 ion chamber to measure beta attenuation and exposure to the lens of the eye (Beta exposare to the lens of the
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eye is considered whole body exposure.) The beta radiation was evaluated
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for skin exposure based or, an array of TLDs suspended in the cavity with
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various shielding (bubble hood, coveralls, plastics / coveralls, and open).
The final licensee evaluation was of contamination swipes.
The purpose of the survey was to determine the beta / gamma to alpha ratio.
The ratio provided assurance that, if beta airborne exposure were con-trolled, no further control for alpha exposure was required.
Isotopic analysis was made to determine the sources of beta, gamma, and alpha radiaticn.
The inspector discussed SG nozzle dam installation and licensee enhance-ments since the last installation.
Licensee improvements to the nozzle dams include lock pin modifications, an additional tab on the air dia-phragm, and a camera display and communications between the SG primary cavities and the 3 ft. 6 in, containment level (control point).
The inspector reviewed the licensee's As-Low-As-Reasonably-Achievable (ALARA) analysis to evaluate the acceptability of chemical decontamina-tion of the SG primary cavity prior to SG nozzle dam installation. The ALARA analysis concluded that decontamination was not recommended based on predicted additional exposure and outage extension. The estimated exposure for nozzle dam installation and SG ECT was 104.6 man-rem with
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decontamination and 62.1 man-rem without decontamination.
The inspector reviewed the licensee's radiation survey results. The highest gamma radiation for both SG primary cavities was on contact with the lower bowl.
The levels recorded by teletector (Geiger-Mueller) de-tection was 20 rads /hr.
The licensee detected no beta through the at-tentuator (symbolizing the thickness of the lens of the eyes) for both
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steam ~ generators. -The licensee, limited individual." stay time"'to six H
minutes. The stay. time was based.on' a 20 rad /hr contact reading and
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limiting _ total individual exposure to 2 rads. The-licensee's radiation-L4
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r work permit' requirement for !cavi.ty. entry. was: full cloth and plastic-pro-tective clothing and a bubble' hood. The dosimetry requirements were 5
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- TLDsL(head, left knee,.right knee,' lower back, chest), 10 pocket dosime-
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'ters'(0-2R range), and a finger ring.
The licensee. recorded the highest-
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E pocket' dosimeter on the radiation' work permit (RWP) for e'ach individual.
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The inspector reviewed ALARA controls utilized for the installation.of SG nozzle dams. The controls included: on-site mock-up training, pre-
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. paration and testing of. nozzle dams in' a low dose rate area of contain-
. ment (-22' elevation),'and removal of residual. water in channel. heads'.
. Good licensee initiatives to reduce exposure-for nozzle-dam installation-
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' we re..eviden t : the_ exposure for nozzle ~ dam installation.in February'1989-
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was ?4 5 man-rem, whereas the exposure in January 1988 was 48.79 man-rem.
The insputor had no further questions.
7,0 NRC Bulletin 86 M, " Pressurizer Surge Line Thermal. Stratification
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-(73753/92700)
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On December'20, 1988,- the NRC issued Bulletin 88-11 to reouest licensees to-d confirm pressurizer surge line integrity and inform the.NRC of actions taken-
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to resolve this issue.
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The NRCJissued Bulletin 88-11 based on unexpected movement of the pressurizer
.surgelline at the Trojan Nuclear Power Plant.
Unexpected piping movements
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'can'cause high p.iping stresses that may' exceed design limits. The pipe move-
ments at the Trojan facility'were caused by thermal stratification. During a typical' plant heatup, water in theLpressurizer is-heated to about 440 de-
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grees F; a steam bubble is then forined in the pressurizer. As the hot water.-
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flows'(at a very' low rate) from the pressurizer through the surge._line to the-hot-leg piping, it' rides onLa layer of cooler water, causing the upper part of'the pipe ~'to be heated to a higher temperature than the. lower part.- The.
d differential' temperature could be as high as 300 degrees F, and differential-
expansion can cause the pipe to deflect significantly.
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One specific requested. licensee action was visual' inspection (ASME Section XI VT-3) of the pressurizer surge line at the first available cold shutdown.
Inspection should determine any gross discernible distress or structural dam-age in the entire pressurizer surge line, including piping, pipe supports, pipe whip restraints and anchor bolts.
'On February 8, the licensee conducted a VT-3 examination of the pressurizer i
surge line and its the nine spring cans, associated anchor bolts,.and pipe clamps. The licensee documented the results of the inspection using engineer-
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ing procedure NU-VT-1, Results were as follows:
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All nine supports were missing a load setting plate.
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The PSLH-8 s.pring can was horizontally misaligned on the support bracket.
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The_PSLH-9 spring can wall plate was pulled out approximately 1/4 of an
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inch. The pipe clamp and hanger rod were misaligned.
For the PSLH-1, PSLH-2, and PSLH-3 combination support, the pipe collar
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bottom left bolt was loose.
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The licensee generated four unresolved indication reports (UIRs).
Each VIR describes indications, evaluations, and the engineering disposition.
The licensee concluded that one of the four UIRs was rejectable. That UIR was the loose pipe collar on the combination support for PSLH-1, PSLH-2 and PSLH-
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The licensee concluded that the remaining three indications were accept-able based on: no effect on load carrying capability; and no load setting plate being required for spring cans in this location.
The inspector witnessed the entire VT-3 inspection, reviewed the UIRs and engineering dispositions, and had no further questions.
During the inspection, the inspector noted that a support for the high pressure safety injection line was misaligned between the lower pipe and its support structure.
The licensee submitted a Non-Conformance Report (NCR) to disposition this discrepancy.
The inspector will continue to review licensee actions concerning this matter.
l NRC Bulletin 88-11 requested long-term licensee actions as follows: evaluation i
of whether the pressurizer surge line meets acceptable design codes and other
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FSAR and regulatory commitments; and updating of the stress and fatigue an-alysis to ensure compliance with code requirements, considering the VT-3 ex-amination results.
The inspector will review these evaluations in future inspections.
8.0 Physical Security (81700)
Selected aspects of site security were verified to be proper during inspection tours, including sito access controls, personnel searches, personnel monitor-ing, placement of physical barriers, compensatory measures, guard force staff-ing, and response to alarms and degraded conditions.
The following item war-
< ranted inspector followup:
8.1 Contraband within the Protected Area During a routine tour on January 19, a security guard sergeant discovered a single.38 caliber bullet on the ground inside the protected area.
The bullet was confiscated and a search of the area verified that no other contraband material was present.
The licensee notified the resi-dent inspector of the incident. A 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> report per 10 CFR 50.73 was made to the NRC at 9:15 a.m. or, January 19.
The licensee concluded the bullet was brought into the protected area undetected by normal security screening. The bullet, a.38 caliber, semi-jacketed round, was different than the standard issue ammunition issued to the security guard force.
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The licensee checked all ammunition currently. issued to the guard' force to verify only!the standard issue bullets (correct type and numbers).~were
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in use.
The matter was discussed with the. security force to increase guard awareness and sensitivity in'the search for contraband at the station access points.
The licensee also ordered posters.which graphic-ally display types of contraband material and which will'be incorporated
in the. general employee training program.
The inspector'had no further.
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questions on the licensee' corrective actions.
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- The inspector noted that a similar incident or ' December 4,1988 involved
.22 caliber rounds as described in NRC Inspection Report 50-336/88-28.-
The~11censee's ability to detect such contraband is discussed in that report.
The inspector concluded that no security threat existed on
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-January'19 based on the amount of contraband.
The corrective actions..
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from the previous incident (NV5 88-28-01) could not have been reasonably expected to prevent the January 19 event.
This licensee' identified item
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9.0 Steam Generator (SGl, Eddy Current Testing (ECT) Presentation L73753)
On January 26, the licensee provided a presentation concerning steam generator (SG). eddy current testing (ECT) to the resident staff. The ' licensee presen-tation providing information on five specific areas of SG ECT: inspection engineering, data acquisition, data analysis, data management, and computer
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-data screening.. SG.ECT is to be conducted beginning on February 4,1989.
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The licensee's information is enclosed.as Appendix A.to this inspection report.
The inspector noted~that the licensee's presentation described comprehensive i
SG ECT scope, improved inspection techniques, implementation of computer data analysis, a plant specific data analysis training program, and independence of data analysis.
Enhancements for the licensee's 1989 SG ECT program include
' i increased sensitivity for the wide groove and segmented bobbin coil probes, increased full length probe testing speed-(with no compromise to sample / linear inch of SG tube), and inclusion of the computer-assisted data analysis.
The effectiveness of SG ECT program enhancements will be reviewed during and after the scheduled 1989 refuel outage.
y 10.0 Allegation by Former Security Guard (RI-87-A-137)
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This allegation concerned issues raised by a former guard in the licensee's
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contact security force.
Some of the issues identified to the NRC resident inspector during a meeting on August 4, 1988 were the same as those previously f
addressed by the NRC (reference: NRC Region I Inspection Report 50-423/88-12).
New issues identified on August 4 concerned: (i) alleged drug use offsite hv
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a Millstone employee; (ii) guard sergeant termination after arrest for dry
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use offsite;'(iii): guard's' drawing weapons on each other; and, (iv) guards
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using weapons in horse play.
By letter _ dated 9/19/88, the NRC staff referred p
these matters to the licensee for review and followup.
The licensee interviewed the alleger and reviewed the above issues.
The.re-sults of the licensee's investigation were provided'in a November 18, 1988 letter'to NRC Region I.
The licensee concluded the allegation of drug use offsite by a Millstone employee or the former guard sergeant _could not-be.
- j substantiated. The licensee also could not substantiate'the use of weapons in horse play. The licensee found the issue involving guards drawing their
weapons referred to an incident on March 28, 1988 in which one guard accused another guard of drawing his weapon during an argument. The matter was re-ported to security and licensee management at that time and was-promptly in'-
.vestigated.
The investigation exonerated the accused officer.
Licensee oversight of the incident and guard force was maintained, As part.of his follow-up to the above issues, the licensee documented.his pro -
gram for Fitness for Duty Policy on Drug Abuse and summarized actions taken i
to implement the program for Millstone and contractor personnel. The licen-see's program provides oversight of contractor and licensee personnel. To i
assure continued effectiveness of contractor oversight, the-licensee committed i
to complete additional fitness-for-duty training for contractor supervisory personnel by 1/31/89.
The inspector reviewed the guard attendance records for the training completed in December.- January, as summarized in a January 26 memorandum to the Security Supervisor.
Licensee actions on this item were assessed as. prompt, thorough and complete.
No unacceptable conditions were identified.
i 11.0 Committee Activities (40500)
The inspector attended Plant Operations Review Committee (PORC)' meetings 2-
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89-05, 2-89-06, 2-89-07, 2-89-09, 2-89-10,-2-89-19, and 2-89-21 on January 11, January 13, January 18, January 27, February 1, February 9, and February 10.
The inspector noted by observation that committee administrative require-ments were met for the meetings, and that the committees discharged-their functions in accordance with regulatory requirements. The inspector observed a thorough discussion of matters before the PORC and a good regard for safety in the issues under consideration.
No inadequacies were identified.
12.0 Maintenance (62703)
The inspector observed and reviewed selected portions of preventive and cor-rective maintenance to verify compliance with regulations, use of administra-tive and maintenance procedures, compliance with codes and standards, proper QA/QC involvement, use of bypass jumpers and safety tags, personnel protection, and equipment alignment and retest.
The following activities were included.
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AWO M2-89-1353 'B' Emergency Diesel Generator voltage / frequency switch change-out on 2/7/89.
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'B Emergency Diesel Generator Overhaul on 2/7/89.
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AWO M2-89-01662 CEDM 'A' Shutdown Group -15VDC Power Supply replacement
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on 2/6/89.
-i No. inadequacies were identified.
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13.0 Surveillance (61726)'
'The inspector observed portions of and reviewed completed surveillance tests.
to assess performance in accordance with approved procedures and limiting. con-ditions for operation,. removal and restoration ofLequipment, and deficiency.
review and resolution. The following tests were inspected.
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OP-2654-12, " Shaft Voltage Test," on 1/24/89.
SP-27308, " Main Steam Safety Valve Simmer. Test," on 2/6/89.
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VT-3 Examination of Pressurizer Surge Line on 2/8/89.
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SP-2605D Type 'C'
LLRT on 2-CH-516 c<. 2/8/89.
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No inadequacies were noted.
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14.0 Management Mer'ings (30703).
Periodic meetings were held with station management to discuss inspection
' findings during the. inspection period. A summary of findings:was also dis-cussed at the conclusion of the inspection. No proprietary information' was t
covered within'the scope of the inspection. No written material was.given to the -licensee during_ the inspection _ period.
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ATTACHMENT 1
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Introduction
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l Inspection Engineering - J. Benson/T. Blanchard Data Acquistion -T. Blanchard
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i Data Analysis - J, Benson a
Data Management - T. Blanchard
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Computer Data Screening - J. Benson/S. Alspaugb(Zetec)
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Inspection Engineering
Assess Results of Prior Inspections
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Define Steam ~ Generator Inspection Workscope
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Technical Specification Requirements
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EPRI NDE Guideline Recominendations
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Specific MP2 Inspection Needs
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Selection ofInspection Sample
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. Development of Test Methods for Specific Need
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Improved Defect Identification and Resolution
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P Exposure Reduction e
ProductivityImprovement
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Assessment of Prior Inspection Results Define Corrective Actions
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l Chemistry Modifications e
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Copper Removal
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Chemical Cleaning
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Boric Acid Addition e
Repair Strategies e
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Bimetallic Sleeve Development e
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Determine Inspection Needs
New Inspection Techniques
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t New Data Analysis Methods
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Plan Future Inspection Work Scope
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Projection of Repairs
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Input to Outage Schedule
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Technical Specification Examination Requirements The tubes selected for each inservice inspection shall include at least l
'
l 3% of the total number of tubes in all steam generators; the tubes selected for these inspections shall be selected on a random basis except:
Where experience in similar plants with similar water a.
chemistry indicates b.
The first sample of tubes selected for each inservice inspection (subsequent to the preservice inspection) of each steam generator shall include:
1.
All nonplugged tube that previously had detectable wall penetrations (>20%)
2.
Tubes in those areas where experience has indicated potential problems The results of each sample inspection shall be classified into one of the following three categories:
Ca tecory Inspection Results C-1 Less than 5% of the total tubes inspected are degraded tubes and none of the inspected tubes are defective.
C-2 One or more tubes, but not more than 1% of the total tubes inspeced are defective, or between 5% and 10% of the total tubes inspected are degraded tubes C-3 More than 10% of the total tubes inspeced are degraded tubes or more than 1% of the l
inspected tubes are degraded.
.
-
_
-
.-
-
-
'
"
~
' --
_ _ _ _ _ - - _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ' - - - - ~ - ^ - - - - ^ ~ - - - - ~ - - ' - - ^ ' - ~ ~ - - ' ' -'
I
-
..
j o
,
'
1989 Examination Scope
'
Description of Tests Number of Tests 9c' of Tubes
,
High Frequency _
24953 Tube Ends 100 Narrow m e
. Bobbin Coll to First Egg Crate Support '
)
Standard Bobbin Coll 5624 Tubes 38 %
r ull Length Sleeve Exams 1000 Sleeved Tubes 20 %
f
,
Profilometry 1300 Tubes 9%
,
Rotating Pancake As Required *
--
Coll l
Sludge Height
!
2389 Tube Ends 10% of g
Measurement Unsleeved Tubes
!
.
Ultrasonic As Required
--
Examination
\\
-
Total Numbers of Tests 31,217+
For Flaws I
L E = = = L = = = 1-J: z z =
= - -
-
-
-
-
.-
'
'
1989 Sample Selection
-
Narrow Field High Freauency Bobbin Coll (To First Sunport)
Pitting, Region Restricted to Top of Tubesheet(Sludge Pile e
All bu( % of 8000 Ereviously Identified Flaws in This Region e
~
Conventional Bobbih 'est (Full Length)
Active Tubes with Flaws above First Support (Only 2)
All tubes not tested full length during.the four, previous e
inspections Tubes in potential "prontem micas -
e e
- Perimeter Tubes e
- Row 7 Tubes m..
- Egg Crate Chord Tubes (Rows 36, 37, 66, 67)
~ Sleeved Tube Ends (Special Probe)
- No Service Related Defects Seen (Inservice Since 1983)
e Random Sample e
Rotating Pancake Coll Test of Selected Tubes Evaluation of Tubes with Indications Similar to Defect e
Seen In January 1988 Leaking Tube Sample Based on Bobbin Coll Inspection Results e
Profilometry (Non-Critical Path)
Same Sample Monitored Each Year for Tube Denting Progression e
. Ultrasonic Examination of Selected Tubes Discretionary
.
= =
--
!
'
..
..
.
.
.
Northeast Utilities Development Programs Prior to 1988 Qualification of a High Frequency Narrow Focus
.
Bobbin Coil Probe for Pit Detection in the Presence of Copper Deposits (1983)
Qualification of a Crosswound Prove for Sleeve Exami
.
nations (1985)
' Qualification of a Three Frequency Mix for
.
. Suppression of Top of Tubesheet Dents (1986)
Development of Data Analysis Guidelines for Unit 2 (1987)
Qualification of an analysis technique for comparing
{
.
Rotating Pancake Coil and Bobbin Coil test results to determine flaw characteristics (1987)
Qualification of Ultrasonic Examination Techniques to
.
determine flaw characteristics (1987)
Destructive Examination of Pulled Tubes to Optimize
.
Non Destructive Examination Techniques Denting (1978)
.
Cold Leg Pitting (1982)
.
Hot Leg Pitting (1983)
.
_
Ifot Leg Distorted Signals @TS) (1985)
_
~
Stress Corrosion (1988)
.
_ _ _ - _ _ x _ _ --- = -
.
..
Improved Inspection Techniques
'
'
Developed for 1989 Examinations
'
Computer Data Analysis e
0.520" Wide Grove (WG) Bobbin Coil Probe
.
Segmented Bobbin Coil Probe-e Increase Full Length Test Speed to 24 Inches /Second e
f I
Advanced Mixing Techniques (Still Under Evaluation)
j
.
.
.
- * - *
.,.
--
-
- - --
-
.
'
'
Increasgd Data Acquisition Speeds New Equipment Anows 1000 Samples Per Second
.
,
Versus 400 Samples Per Second Previously
'
'
(12"/Sec) x (1 sec/400 Samples) = 1 Sample /0.030" e
l (24"/Sec) x (1 sec/1000 Samples) = 1 Sample /0.024" e
Increased Bobbin Coil Probe Speed Has No Effect On:
e l
Signal Quality
.
~
Flaw Detection
.
,
Probe Speed of 24"/sec Will Be Used For Full Length
.
Examinations
,
.
- - - - -. - - _ _. - _ _ - _ _ - _ _ - - - - - -. - - _ _ -.. _ _ _ - - - - - - -. - _ _ _ -. -
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- - -
. _ - _ - - -
- - _ _ - -
. - - - -
- - -
- - --
-
-
-
.
'
'
Data Acquisition j
4,
,
Equipment At Steam Generator (Each Plenum)',
>e Manipulator (Genesisi
)
.
Probe Pusher (27tZ4t6c 4DJ e
In-Line Calibration Standards e
Miz-18-A/D Converter and Controller e
Radiation Reducing Doors
.
. At Data Acquisition T. railer ma,ch Position)
.
e Genesis Controller DDA4 Data Collection System e
. -Video Recording Equipment Special Features Compliance with Loss of Shutdown Cooling Precau-
.
tions Elimination of Human Interface Between Genesis
.
Position and DDA4 Data Input Video Recording of Extent of Test
.
Final Product
.
Data Disk Data Tape
.
Video Tape e
Examination Report
.
_ _ _ _
- __.
1._ '~ ~
1;;;;;~ Ti
-
~
_ ___
_ _ _ _ _ _ _ - _ _ _ _ _ _
..
..
-.
,
..
,
' Note: A11 eessurseents free center-Full typerates a Elev. I to 7
.
of tube support er top of tubesheet.
Portfal Eggerates = Elev. 8 4,
'
Part1al Dritied Supports * Elev. 10 & 11
.
.
\\
.
-
.
'
.
%
l
i
.
,
MM
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.
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-
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// A 1VA f ){ Y f Rf 1 ii1 oJf 27.13" NTS L I4 AL.LM
' u /'/r CTS
.
.; %NN; l/////9 al.s-me en f
,
,
,
,
A l
A /
INLET M
,
,
OUTLET Millstone Point 2 Steam Generater Arrangessent i
- 10 -
I
-
.
-
i
.,
..
..
'
Eddy Current Data Analysis
'
-
.
Data Analysis Equipment
.
i Data Analysis Guidelines
.
Data Analyst Training and Qualification
.
Independent Data Analysis
.
l Computer Data Analysis
!
e
-
.
'
l
)
-
-'
- - -
-
-
.._
.
.
'""' ' ' * " '
.w
.w
.
_
.,%.
.ww,
%
,,,
..
..
..
^
-
'
Data Analysis Equipment
'
Digital Data Analysis Station
.
HP Computer
.
Data Cartrige Recorder e
Analysis Software e
.
Printer
Recording Media Data Tape Cartridges - Stores Digital Data
'
.
Data Disks - Stores Analysis Results e
Hard Copy Printouts
e Analysis Results
.
Lissajous Traces of Flaws e
.
,
,-.
..
. ~...
... _.
,+.,.._._.n-
..--n
, _.
.:
..
)
'
Data Analysis Guidelines Specifies Appropriate Data Analysis Practices Based
.
On:
Previous Unit Experience
.
Industry Experience
'
.
Laboratory Studies
.
Pulled Tube Destructive Examination
-
e
-
..
-Provides Qualified Knalyst With Optimum Methods
.
of Recognizing and Reporting Eddy Current Data I
Ensures Data ic Analyzed and Reported in Consistent e
and Repeatable Manner Assist the Analyst in Analyzing Complex Unit 2 Eddy
.
'
Current Data But Are Not Requirements
.
-
--
____an__.._._
.._..1
.. _... _ - - -. - -
-
-
.
,
-
.
'
' Plant Specific Data Analyst
' Training and Qualification (Analysts Not Previously Qualified at Millstone)
,
Day 1
'
I Steam Generator Design
.
Steam Generator History
.
Data Analyst Responsibilities
.
General Data Analysis Guidelines
.
Day 2 Full Length Analysis Guidelines
.
Part Length Analysis Guidelines (Copper Suppression)
.
-
Day 3 i
Part Length Data Analysis (Dent /Tubesheet l
-
.
Suppression)
Day 4
-.
Reporting Requirements Independent Data Analysis Criteria l
.
Day 5-One Hour Written Examination
.
Seven Hour Practical Examination
.
,
L
-
--
-- -
..
,
.
.
,
'
'
Plant Specific Data Analyst Training and Qualification (Lead Analysts and " Specialty Test" Analysis)
.
Day 1
.
Bobbin Coil Analysis Training
.
(Highlights of Changes Since Previous Exam)
Advanced Mixing Techniques
.
Day 2 Bobbin Coil Written and Practical Examinations
.
Day 3
.
Computer Data Analysis Training e
Computer Data Analysis Written and Practical Exam e
'
Day 4 MRPC Analysis Training
.
,
MRPC/ Bobbin Comparison Training e
Day 5 Sleeve Analysis (Segmented Bobbin Probe) Training e
Segmented Bobbin Probe Written and Practical Exam
.
l Day 6 Sleeve Analysis (Crosswound Probe) Training e
Crosswound Probe Written and Practical Exam
.
fl'
~
.
'
.
\\
\\
)
-
l
,
'
Benefits of Analyst Training
'
~
i l
Allows Analyst to Become Familiar With Complex
.
Unit 2 Data, Prior to Beginning Field Job Faster Analysis at Start of Job e
Less Confusion at Start of Job
=
Provides the Analyst with Knowledge Gained Over
)
e The Life of The Plant
.
Types of Flaws To Expect
.
Differences Between Flaw and Nonflaw Signals
.
Practical Demonstration Prmides Assurance That
.
'
Only Qualified Analysts Are Allowed to Perform Data Analysis
,
- _ - _ _
V
.
,
L
-
.
'
P Independent Data Analysis i
)
Primary Analysts Secondary Analysts i
l Review Data and Review Data and Report Results Report Results I
I I
i Data Management Compares Primary and Secondary Re-sults and Develops List of
Discrepancies Lead Data Analysts Review Data When:
Primary and Secondary Depth Estimates Differ e
by_t 10%
A Repairable Indication is Reported
- - An Anomalous Indication is Reported Primary and Secondary Analysts Disagree on e
-
Existence of a Flaw
.
m
--_-______________--__m__m.__--.__m____m__
_________.-_m2__..-_
..
_ - - _ - _ _ _ _
- _
%
,.
CO$ PARIS 0NOFMANUALDATAAWALYSISWITHCOMPUTERDATAANALYSI
'
-
PLANT UNIT 5/8 LEC REEL 10 REEL DATE
.
HP I!
D0 24
1 HOT H114 H12401/19/28 SG LIN R0W VOLTS DEG 5 CHf LOCATION EXTENT
'
I 11 93 18 7.28 151 29 M 1 HTS
+
0.2 HTS 11 94 to 11.94 157 23 M 2 HTS
+
0.1 HTS 11 95 28 HTS
!
11 96 30 6.37 134 43 M 2 HTS
+
0.2 H1 11 97 34 6.33 134 27 M 3 HTS
+
0.3 H1 11 98 38 5.81 134 27 M 3 HTS
+
0.2 HTS j
.
11 99 4011.37130 30 M 3 HTS
+
0.2 HI
!
11 100 42 5.41 132 29 M 3 HTS
+'
0.2 H1 l
11.101 50 HTS 11 102 54 H1 11 103 80 H1
,
'
..
.
.
.
,
MANUAL ANALYSIS
,
_ _.
_.
PLANT UNIT $/G LEE REEL TO REEL DATE MP 11 DD-124CDS
1 HOT H124 H12401/19/88 5G LIN R0W VOLT 3 DEG 5-CHf LOCATION EXTENT 11 93 18 7.38 153 27 M t HTS
+
0.4 HT5+45 l
11 94 to 11.90 158 23 M t HTS
+
0.4 HTS +35
HTS 11 95 28 11 96 30 7.36 130 19 M 3 HTS
+
0.3 H1 il 97 34 5.69 146 34 H 1 HTS
+
0.4 H1 t
11 98 38 7.35 156 25 M 2 HT5
+
0.4 HT5+35
'
0.t H1 11 99 40 11.19 128 31 M 3 HTS
-
11 100 42 5.09 130 19 M 3 NTs
+
0.3 H1 HT5+35 11 101 so H1 11 102 54 N1 11 103 60
l COMPUTER ANALYSIS
"
~
C - -___________:_
-
.'
'.
.:
'
Computer Data Analyis
-
A Computer Program Was Written Based on hiillstone
.
Unit 2 Data Analysis Guidelines
'
Computer Analysis Technique Was Qualified on the
.
,
Analyst Qualification Test (Test Score
. 967(
,
Benefits of Computer Analysis Include:
e
.
Consistent, Repeatable Results
.
Elimination of Analyst Fatigue Factor e
Reduction in Analyst Staffing (By Nine)
e Factor of Two Increase in Analysis Rate For e
Part Length Tests High Probability of Not Missing a Repairable e
Defect (Primary Purpose of Secondary Data Review)
-
Negative Aspect - Potential For Falsely Calling Non
.
l Defect Signals as Defects l
l l
=:
--
- - - - - -
--
=
.
- - - -- - - - --
_
' '
.
.
,y
.g.
'
~
"
Data Management
.
Three Separate Databases - One Source of Input
-
Vendor Work Control e
NUSCo - Examination Analysis and Backup to NNECo e
NNECo - Progress Monitoring and Final Repair List -
.
L Available for NUSCo Backup if needed Vendor Data Management System Requirements
,
-
.
Detailed Procedures
.
Personnel Training e
Specific Requirements for Data Disk Correction
.
Data Management System Test
.
Comply.With Analysis Guidelines e
'
Data Validated on Upload
.
.
M M.44 9 444
s,
w e
g-e..w
-
. <,.
w
= -
,,-
l
-.
e+
O
- "
.=
PLANT UNITS S/G LEG REEL TO REEL DATE MP-2 DD-05P
1 INLET H105 10/28/86 SG LIN ROW VOLTS DEG
%,
CHs, LOCATION
'
EXTENT MCKEE E.
H10S PRI'A6004FLCRMNG 10/28/a6
63
H1
64
6.36 121 36 M3 HTS
+
0.2 H1
{
,
11.
53 INC HTS +21 i
4.28 129 28 M 3 HTS
+
0.1 HTS +21
65
1.21 137 33 M2 HTS
+
4.6 H1
65
4.08 119 D-S M2 HTS
+
6.7 H1 11)
47 H1
-
t
.
65
INC HTE+1b HEADER NEWELL T.
H105 PRI A6004FLCRMNG 10/29/86
65
5.09 115 41 M3 HTS
+
0.3 H1
65
7.01 131 LAR M2 HTS
+
7.2 H1 NEW PROBE
.
65
PLG
.
65
3.42 137 33 M2 HTS-5.8 H1 I
.
-
.
MAURER R.
H105 FIN AG004FLCRMNG 11/03/86
'11
43 3.42 100 49 M3 HTS
+
0.1 H1
65
2.66,133 35 M3 HTS
+
0.8 H1
.
'
.
.
Eddy Current Data Report
- 11 -
,,
_
.
.
_
... _ _ _ -. _.....
m.
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.
_ _ _ _ - - - _ -. _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _.
__
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,Q di f i
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- Pu m a wereTA
- Pu a e euroT6 ejeeere NPl -- Mtwo p-g t t e ty 19 p peig a
XY_ DISPLAY bT5 am
-
i CHAe4# -- M 2 til
.W t42 CHANS - 1-5 q
y SPAN
H3
"
ROTATION - 299 DEO h4 N
LETT STRIP CHAPT
-
"
~
ti6 Efsy :- n av ~
H7 CHAHS - 1-5-G 7......
....... <
gppy gg
.J ROTATION - 299 DEO
-
,
,
b
RIGHT STRIP CHART i
N
-
~6I4fd4#~~- M SV Q2 PR!# 2 CHANS - 2-6 SEC# 13 gppy gg j
gg....
...
..
l.05 VOLTS 113 ggg 31 g ROTAT!0H - 183 DEO
'
g7g g
SYSTEM CONFIGURATION
NAME - tF2 F/L i
- of CHAN 8 18:36:29 PM
'
"
JANUARY 14 1988
.
00' L#
FFE0 112 3 4 5
7
+
+
".
- W< m
?
200
4 100 E
!
j t
7 e
PLANT UHIT S/0 1.E0 DATE BLK# 18137 J
MP-II DD-112CDS
1 HOT 81/14/98 110:36:29 PM JAf4UAFY 14 1988 l H7
+ 17.1 l SO 11 L1H 112 ROW - 61
CHAN# -- 8 l
CHAN# -- M 1 CHAN# -M2 CHAN#
-
CHANS - 1-3 CHANS - 1-5 FR E Q ---- 400 kHz FREQ 200 kHz l
SPAN
SPAN to SPAN -- -
SPAN - -
j ROTATION - 310 ROTATION - 299 ROTATION - 292 POTATION - 29
<
j ef a
]b
'
O.72 Y tee E 39B 1.0s v 113 E 31E 1,53 V 136 E 25E 2.58 Y 90 E 32E I H7
+ 17.1 l
CHAN# - 5 CHAN# -- M 3 CHAHe -- 6 CHAN# -- 8 FREO --- 100 kHz CHANS -- 2-6 FREQ 160 kHz FREQ -- 25 kHz SPAN ---
SPAN ---- 10 SPAN St SPAH -----
ROTATION - 131 POTATION - 103 ROTATION - 293 ROTATION - 33 f
'
x
>
>
O 2.12 V 63 56E 0.87 Y 354 e5 3.55 V 43 0 0'.
1.83 Y 84 K OE PLANT UNIT S/0 LEO DATE BLk# 18137 MP-II D0-132CD$
B2
HOT 01/14/88