IR 05000338/1987029
| ML20235T316 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 10/01/1987 |
| From: | Caldwell J, Cantrell F, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20235T309 | List: |
| References | |
| 50-338-87-29, 50-339-87-29, NUDOCS 8710130040 | |
| Download: ML20235T316 (12) | |
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P CEC UNITED STATES
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o NUCLEAR REGULATORY COMMisslON
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REGION ll I I b
101 MARIETTA STREET, N.W.
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I ATLANTA, GEORGI A 30323 s...../
i Report Nos.:
50-338/87-29 and 50-339/87-29-
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Licensee: Virginia Electric and Power Company-
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Richmond, VA 23261 Docket Nos.: 50-338 and 50-339 License Nos.:
NPT-4 and NPF-7 Facility Name: North Anna 1 and 2 Inspection Conducted: August 19 - September 17, 1987 Inspectors:
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/d2 9/29 87
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J. L. Caldwell, Sen~ior Resident Innpector Date Signed
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3 Nd-h5 0]
l L. P. Kirig, Resident Inspector Date Si'gned Approved by: C[MD
/M/ !f')
F. 'Caritrell, Section f
Datd Sitjn6d'
Division of Reactor P ects SUMMARY Scope:
This routine inspection by the resident inspectors involved the following areas:
plant status, licensee action on-previous enforcement matters, licensee event report (LER followup), monthly maintenance observation, monthly surveillance observation, ESF walkdown, operator safety verification, operating reactor events, TI-2500/19 and steam generator status.
During the performance of this inspection, the resident inspectors conducted reviews of the licensee's backshift operations on the following days - August 24, 25, 26
and 31 - September 1, 3, 4, 8, 9,-15 and 17.
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Results:
No violations or deviations were identified during this inspection.
l 8710130040 871002 PDR ADOCK 05000338 G
PDR l
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REPORT DETAILS
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1.
Persons Contacted Licensee. Employees
- E. W. Harrell, Station Manager
'R. C. Driscoll, Quality Control (QC) Manager
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- G. E. Kane, Assistant Station Manager
- M. L. Bowling, Assistant Station Manager R. O. Enfinger,. Superintendent, Operations
- M. R. Kansler, Superintendent, Maintenance
- A. H. Stafford, Superintendent, Health Physics
- J. A. Stall, Superintendent, Technical Services f
J. L. Downs, Superintendent, Administrative Services
- J. R. Hayes, Operations Coordinator D. A. Heacock,' Engineering Supervisor D. E. Thomas, Mechanical Maintenance Supervisor G. D. Gordon, Electrical Supervisor R. A. Bergquist Instrument Supervisor
- T. Johnson, QA Supervisor J. P. Smith, Superintendent, Engineering D. B. Roth, Nuclear Specialist J. H. Leberstein, Engineer
- G. G. Harkness, Licensing Coordinator Other licensee employees contacted included technicians, operators, mechanics, security force members, and office personnel.
- Attended exit interview 2.
Exit Interview (30703)
The inspection scope and findings were summarized'on September 17, 1987, with those persons indicated in paragraph 1 above.
The licensee acknowledged the inspectors findings.
The licensee did not identify as
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proprietary any of the materials provided-to or reviewed by the inspectors during this inspection.
3.
plant Status Unit 1
' Unit 1 began the inspection period in mode 5 (day 36 of the S/G. tube rupture outage).
On September 8 - the licensee attempted ' to. install a stabilizer in the cold leg side of "C" Steam Generator (SG) to. stabilize
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the U-bend section of the ruptured tube.
The licensee has experienced several problems with the stabilizer. installation and.is still evaluating -
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the problems (See section 11.for details). On September.10, a meeting was
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conducted in Bethesda, Maryland,. between the licensee and the :NRC to
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discuss the root cause and failure mec'h'anism of the ruptured tube' and-the.
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necessary actions for the ~ restart' of the.. unit.. Floyd Cantrell. and the North' Anna Resident Inspectors attended the meeting.
On September 15, the licensee issued an update to the tube rupture report for NRC review and to be used in preparing the Safety' Evaluation Report.
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.The licensee'.has completed the SG eddy current inspection on Unit 1 and is-
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. presently plugging the affected tubes.
As of the end of the inspection
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period the unit is' in day 65.of. the. tube rupture' outage and expects to restart sometime in late September of early October, depending on 'the.
outcome' of the evaluation and corrective. action for the-. stabilizer problem.
Unit 2 Unit 2 began the reporting period operating at approximately 63% power.
The unit continued ' power operation until August 23, when ~ the unit commenced a-scheduled shutdown to begin a 62 day ' refueling outage. The
' nit was off the grid with the. turbine ~ unlatched ' at approximately (
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1:00 a.m. (EDT) August 24, 1987. However, during the. continued shutdown, the reactor tripped due to failure of intermediate range NI N35. The unit was subcritical with D bank rods at approximately -3 steps when the trip-occurred.
The unit continued with cooldown and reached mode 5'on-August 25 at approximately 3:00 p.m. (EDT).
On September 8, while removing fuel from the vessel, the l.icensee damaged.
a fuel assembly. This damage, however, did not result in a breech of the i
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cladding integrity (see section' 8 for details).
The licensee completed
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the fuel off load on September 10.. On ' September 14 ' the. licensee recommenced loading fuel back -into the vessel and completed the fuel on-load on September 17.
The unit is presently in day 31 of a scheduled 62 day refueling outage.
Both-Units l
On August 19, the licensee identified a hot particle overexposure event.
A Region II inspector was sent to the site to evaluate the event and the licensee's actions (see inspection report 338,339/87-30).
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North Anna received full INPO training accreditation on August 26, 1987.
The licensee is now a full member of the National Academy for Nuclear Training.
4.
Licensee Action on Previous Enforcement Matters (92702).
(Closed) Violation 339/86-04-01:
Diesel Generator. 2J Electrically Overloaded during 2-PT-83.4.
The licensee provides a dedicated operator at the. emergency diesel generator to prevent overloads on the diesel. The dedicated operator will continue to be used until Colt has ' completed: the developnat of a modification that would limit' fuel rack travel during testing and automatically return the setting to its' normal,value following testing.
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I (Closed) Unresolved Item 338/87-19-03:
Potential violation for an inoperable recirculation spray pump due to degraded' seal package.
During this inspection period, the inspectors. reviewed the engineering justifications and conclusions relating to' operation of the ORSPs with indication in the control room that the seal head tanks for these pumps has either a high or low water level. The evaluation included a review of i
the following documents:
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North Anna Power Station FSAR, Section 6.2.2.3.
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Memorandum from J. A. Stall to SNSOC (Subject:
1-RS-P-2B) dated
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6 28-87,
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Memorandum from R. C. Sturgill to R. O. Enfinger (Subject:
Outside Recirculation Spray Pump Seal Head Tank Level Problems) dated 7-3-86.
Memordanum from D. W. Galaska to W. M. Adams (Subject:
Outside
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Recirculation Spray Pump Mechanical Seal) dated 8-13-87.
After review of the preceeding documents, the inspector discussed the j
possible causes of the seal head tank adnormal level conditions with station engineering.
The in_spector was informed based on licensee conversations with Steven Lenberger (Crane Senior Design Engineer) and t
Gorden Parks (Bingham Field Service Supervisor) on August 11, 1987, the seals could operate dry for at least.15 seconds and the. primary or
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secondary seal, if the primary seal leaked, wouY be immersed in pump
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discharge water in five to seven seconds after me pump started.
This would ensure that at least one of the seals would be adequately cooled even if either the head tank diaphram or one of the seals had failed, i
This discussion resulted in the following conclusions by the inspector:
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Operation of the outside recirculation spray pumps with a failed diaphram in the seal head tank or with a leaking upper or-lower pump
seal would not result in the pump becoming inoperable. However, long term operation or standby in this condition is not ' desirable and should be avoided if at all possible.
This was similar to the conclusion reached by engineering at the station.
In addition, maintaining operability of the pump with a failed pump
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seal would deviate from the FSAR with regard to the following statement: "Two mechanical seals are arranged in tandem with a fluid
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l seal between them.
The seal fluid is supplied from a reservoir arranged in such a manner that the pressure of the seal fluid is slightly above the pumped fluid at the inboard side of the inboard seal.
This arrangement is provided so that, assuming a single seal failure, seal fluid will leak through the failed seal and the other seal will remain available to prevent escape of pumped fluid.to the atmosphere.
A level alarm on the reservoir provides indication of seal failure."
This deviation from the FSAR was addressed via a 10 CFR 50.59 safety evaluation reviewed by the safety committee on
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June 28, 1987.
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The inspector discussed this condition with'the' licensee and the licensee intends to repair all leaking outside recirculation spray pump seals or seal head tank diaphrams-and verify operability of the level alarms prior to restart of either unit provided that parts are available to make the necessary repairs.
5.
Licensee Event Report (LER) Follow-Up (90712)
The-following LERs were reviewed and closed. The inspector verified-that reporting requirements had been met, that causes had been identified, that
t corrective actions appeared appropriate, that generic applicability had been considered, and that the LER forms were complete. Additionally, the inspectors confirmed that no unreviewed safety questions were involved and that violations of regulations or Technical Specification (TS) conditions had been identified.
(Closed) 10 CFR 21 86-02:
Kaman Mod KMG-HRH W/ detector Enhancement Mod KDGM-HR PT #95 2397-003 Does Not Meet Design Specs - Kaman To Request Each Power Station Conduct Tests To Determine Defects (CERCRS8604268). Kaman Model KMG-HRH with detector enhancement Model KDGM-HR is designed to measure fresh equilibrium noble gas fission products to 1 x 10 +5 microcuries/ cubic centimeter but will become saturated at 3 x 10 +3 microcuries/ cubic centimeter. Kaman Sciences Corporation has supplied and installed new software which allows the monitors to function over the entire range as required by Technical Specifications.
(Closed) 10 CFR 21 84-01:
Temperature Compensation Error, Barton j
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Transmitters.
The licensee has replaced all of the Barton transmitters j
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(Closed) LER 338/86-14:
Intermediate Range Reactor Trip. The licensee
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has completed a Human Performance Evaluation System report, HPES86-117,
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which recommends a procedural change and an EWR for changing the method of
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attaching jumpers. The possibility of a jumper coming loose still exists i
until the EWR has been performed.
6.
Monthly Maintenance (62703)
Station maintenance activities affecting safety related systems and components were observed / reviewed, to ascertain that the activities were
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conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with Technical i
Specifications.
In late August, at the beginning of the Unit 2 refueling outage, the licensee conducted eddy current inspection of the incore flux thimble tubes.
This inspection was performed as a result of the license learning of wall thinning of the flux thimbles in Europe and in a couple of plants in the United States, and as a result of the wall thinning discovered =in the Unit 1 flux thimble inspection (See the maintenance section of inspection report 338, 339/87-10).
The inspection revealed the following:
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thimbles had no detectable indications
-thimbles had. indications less than 30% wall thinning
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thimbles had indications greater than 30% but less than 40% wall thinning
thimbles had indications greater than 40% but less the 49% wall
thinning
thimbles had indications greater than 49%
Based on the results, the licensee will repair the 8 thimbles which had indications greater than 40% wall thinning.
This repair. consists' of removing approximately two inches of the thimble from the core, thus I
l placing new metal in the area where the thimble exits the core plate and l
enters the fuel assembly.
This is the area where the' wall thinning l
(fretting) has been occuring.
The three thimbles of the above 8 which indicate wall thinning greater than 49% will be isolated following the i
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repair procedure.
In September, the licensee conducted the six month piston pin bushing gap
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measurement on the Unit 1
"H" Emergency Diesel Generator (EDG) per
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Maintenance Procedure MMP-P-EG-1.5.
This EDG had been overhauled during j
l-the refueling outage including ccmplete replacement.of the position-pin l
I bushings and lube oil change out. The gap measurements did not reveal any j
change or degradation in the piston pin bushing, j
i The licensee also removed and inspected all of the upper. piston pin I
bushings and two of the lower piston pin bushings on the Unit 2
"H" EDG using Maintenance Procedure MMP-P-EG-4.
Thi s inspection, which was reviewed by both Trident Engineering and Colt Industries, showed the bushings to be in excellent condition.
This EDG had approximately 227 hours0.00263 days <br />0.0631 hours <br />3.753307e-4 weeks <br />8.63735e-5 months <br /> run time since the bushings had been placed in the engine and these
bushings had only been exposed to the Chevron Delo 6000 lube oil. These bushings were placed back into the EDG following the inspection.
On September 15, 1967, the inspector observed operation of 2H emergency diesel generator.
This operation was conducted in accordance with Maintenance Procedure MMP-P-EG-4, following the maintenance on the diesel.
On September 8,1987, during an entry by the inspector into the ' Unit 2 containment, the following work was observed:
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Virginia Power operators were removing fuel elements from the reactor j
vessel
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f.ddy current examination was progressing of "B" steam generator j
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Sludge lancing was taking place on the "A" steam generator i
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Installation of the head shield was progressing l
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Snubber surveillance was in progress l
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6 An entry was made into the "B" loop room cubicle inside containment. New lead blankets had been installed around the hand rails surrounding the Thot and T cold loop stop valves.
This was done as part of the ALARA program.
A tour was conducted with the health physics technician of various radiation areas inside the containment. ALARA signs were posted indicating to workers places where there was a low dose rate area.
No violations or deviation were identified, i
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7.
Monthly Surveillance'(61726)
i The inspectors observed / reviewed technical specification required testing
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and verified that testing was performed in accordance with adequate
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procedures, that the instrumentation was calibrated, that limiting
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conditions for operation (LCO) were met and that any deficiencies
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identified w6re properly reviewed and resolved.
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The licensee is conducting ultrasonic (UT) testing of both single phase l
and two phase flow feedwater and condensate piping.i n Unit 2.
The inspections are'approximately 91% complete and the licensee has identified a total of 39 components that will have to be replaced this outage. Seven of the replacements were identified in the single phase flow piping with
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the remaining 32 components located in the two phase flow regions.
The licensee plans to inspect approximately 191 single phase components and 91 two phase flow components.
On August 26 and 27, 1987, the inspectors witnessed the following surveillance on Unit 2 following the plant shutdown:
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2-PT-211.1 - Inservice Inspection Main Feedwater Check Valves.
2-PT-57.2 - Safety Injection Functional Test.
2-PT-83.1 - Simulated Blackout and ESF Signal - H Bus.
l 2-PT-83.2 - Simulated Blackout and ESF Signal - J Bus.
l 2-PT-158 - Valve Inservice Inspection - SI Functional Verification.
2-210.3 - Valve Inservice Inspection - LHSI Pump Check Valve.
No major problems were identified as a result of these tests.
The inspector reviewed portions of the completed surveillance 2-PT-66.3 CDA Functional Test.
As a result of the test, the following valves had work requests written to resolve the problems of either not closing or closing too slowly:
2-CC-TV-205B l
2-CC-TV202B 2-CC-TV-2020 2-CC-TV-201B L
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Also tha % per 2-HV-AOD-228-2 from the safeguards area failed to transfer presce.
The above items are scheduled - to be retested after the maintenance has been completed.
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l The following'procedur$s were reviewed by the inspectorsi
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I 1-PT-44.9 - PORV Instrumentation Functional Test.
This test demonstrates the operability uf the PORV instrumentation in
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accordance with TS 4.4.3.2.1.1. - Every 31 days.
3 1-PT-44.2.19 - PORV Instrumentation Calibration - every 18 months.
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1-PT-44.4.2
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i Overpressurization Protection Instrumentation
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Functional Test with PORV Operability Required overy 31 days while PORV is requir'ed.-
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Tests are required to ensure the system is operable while going'to cold
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shutdown.
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l No violations or deviations were identified.
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i 8.
OperationalSafetkVerification(71707)
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By observations during the inspection period, the inspectors verified that
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the control room manning requirements were being met.
In addition, the j
inspectors observed shift turnover to verify that continuity of system i
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status.was maintainedT The inspectors periodically questioned shift
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personnel relatNe to their awareness of plant conditions.
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Through log review and plant tours, the inspectors verified compliance with
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selected TecMical Specification (TS) and Limiting Conditions for
Operations.
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In the course _of the monthly activities, the resident inspector included a
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review of the licensee's physical set" city program.
The performance of
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various shifts of the security force was. observed in the conduct of daily activities to include:
protected and vital areas access controls,
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searching of personnel, packages and vehicles, badge issuance and i
retrieval, escorting of visitors, patrols and compensatory posts.
In addition, the resident inspectors observed protected a rea lighting, protected and vital areas barrier integrity and verified an interface
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between the security organization and operations or maintenance.
The inspectors kept informed, on a daily basis, of overall status of both units and of any significant safety matter related to plant operations.
Discussions were held with plant management ar.d ' various members of the operations staff on a regular basis. Selected portions of operating logs and data sheets were reviewed daily.
The inspectors conducted various plant tours and made frequent visits to the Control Room.
Observations included: witnessing work activities in progress; verifying the status of operating and standby systems and o____
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equipment; confirming valve positions, instrument and recorder readings,
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annuciator alarms, and housekeeping.
I The following comments were noted:
On September 5,1987, the licensee identified a problem associated with the Unit 2 head lift. The problem as documented on Deviation Report (DR)
87-1005, was the allowance of the vessel head to come in contact with and bend a transfer canal safety cable stantion during the movement of the head from the cavity to the storage area.
The head was repositioned and successfully placed in the storage area.
An inspection revealed no damage. The licensee attributed the problem to poor communication between the crane operator and the Westinghouse refueling supervisor due to respiratory equipment requirements.
l On September 8, 1987, the licensee informed the inspectors that fuel assembly V57 for Unit 2 had been damaged while attempting to place the
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assembly in the containment upender. The licensee had just commenced core off load for Unit 2. and V57 was.the fourth assembly removed from the vessel. At approximately 3:00 a.m.,
following the removal of the V57 fuel assembly from the vessel with the manipulator crane, the Westinghouse refueling operator was attempting to insert the assembly into the upender tube.
During the first attempt, the operator reportably experienced a large loss of load and pulled the assembly back up into the manipulator crane mast.
The crane index was then checked and the operator again attempted to insert the assembly into the upender tube.
This time the operator experienced a larger loss of load and the crane physically moved.
The operator then attempted to lift the assembly back up into.the crane mast but the crane went into overload. A visual inspection in the pool revealed that the assembly was outside of the upender tube toward the vessel wedged between the outside of the upender tube and the inside of the crane mast.
The manipulator crane was moved to free up the assembly and the assembly was placed back up into the crane mast.
The licensee reviewed the situation, operated the u; ender and crane again and was successful in placing assembly into the upender and transferring it into the fuel building.
Based on the lack of change in the radiation levels and a visual inspection of the fuel assembly, it appeared that no cladding barrier had been breached. However, the visual inspection did reveal that the number 2 grid strap from the bottom was severely damaged and several fuel pins were compressed together.
Therefore, the fuel assembly was not reusable and a core redesign had to be performed for the Urit 2 reload.
Prior to recommencing the core off load on September 9, the licensee reviewed the situation and began testing of the manipulator crane and the upender with the dummy fuel assembly.
This testing did not identify any problems associated with the equipment.
However, later during the core off load, the licensee discovered a relay on.the upender which intermittently prevented the. upender from reaching the full vertical position. This situation was easily identified by the upender operator on a visual inspection performed prior to the allowing the assembly to be lowered into the upender tube.
The relay was replaced and no other similar problems were experienced.
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Prior to recommencing the core off load following the damaged fuel assembly event, the licensee relieved all of the Westinghouse refueling operators and continued the refueling operations with VEPC0 operators.
These VEPC0 operators spent several hours refamiliarzing themselves with the refueling equipment using the dummy fuel assembly and then completed the core off load without further incident.
The ' licensee will complete the Unit 2 fuel movement evolution with VEPCO employees using the Westinghouse refueling supervisors as technical consultants.
During the Unit 1 outage, the licensee shipped approximately 76 Limitorque Mocor Operated Valve (MOV) operators to Babcock and Wilcox to set the spring pack and torque switch settings.
Recently, Babcock and Wilcox notified the licensee that there were inaccuracies in their test equipment and calibration data and forwarded corrected calibration data.
The licensee will be testing approximately 14 valves with MOVATS equipment to validate the corrected Babcock and Wilcox calibration data.
This effort which is presently taking place will determine 'if any additional corrective action will be required.
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No violations or deviations were identified.
9.
Operating Reactor Events (93702)
The inspectors reviewed activities associated with the below listed reactor events.
The review included determination of cause, safety significance, performance of personnel and systems, and corrective action.
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The inspectors examined instrumant recordings, computer printouts, j
operations journal entries, scram reports and had discussions with
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operations, maintenance and engineering support personnel as appropriate.
On August 24, 1987, at 1:11 a.m. (EDT) while Unit 2 was being shutdown and I
the generator was off the line with reactor power at 0%, the reactor
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tripped. The cause of the trip was on intermediate range hi flux due to a failure of the N35 detector.
The N35 detector is being replaced during the Unit 2 outage.
No violations or deviations were identified.
10.
Temporary Instruction 338, 339/TI 2500/19:
Inspection of Licensee's
Actions Taken to Implement Unresolved Safety Issue A-26:
Reactor Vessel Pressure Transient Protection for Pressurized Water Reactors.
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The inspectors verified that the licensee has an effective mitigation system for low-temperator overpressure transient conditions in accordance with their commitments concerning Unresolved Safety Issue A-26.
The inspectors reviewed the following areas:
Design - The Nuclear Engineering Department Technical Report #447
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" Revised Pressure / Temperature Limit Curves and Associated PORV
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setpoints for North Anna Units 1 and 2" dated April 1985 was reviewe.
This document-provided documentation for the revised pressure / temperature limit ' curves and the PORV setpoints. The RTNDT was recalculated.
Engineering supplied B&W with pin-by pin power distribution for cycles 1-5 for Unit 1 and 1-4 for Unit 2.
In addition, credit was taken for a reduction in the maximum heatup rate from 100 degrees F. to 60 degrees F.
The final PORV setpoints were determined using. a composite cooldown curve and uncertainties as described in section 5.2.2.2'of the UFSAR.
Drawings area available to show that the pressure protection system is designed to protect the vessel given a single failure in addition to the failure that initiated the pressure transient.
A bottled Nitrogen system from the gas supply area is used during solid water operation. Redundant Hydrogen reserve tanks are also provided in the
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event of a loss of bottled Nitrogen supply.
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l Administrative Controls and Procedures - Procedures exist for l
limiting operation of the reactor coolant pumps in a solid water condition. Pressurizer heaters are secured and the procedures limit the number of operable charging pumps to one.
Operators are alerted by an alarm of the automatic operation of the overpressure protection system when the PORVs are being used. When a pressurizer bubble is being used (on Unit 2) a separate alarm alerts the operator.
Training and Equipment Modification - All operators have received training on low temperature overpressure events.
The procedures require removal from service of potential sources of overpressure.
Pumps are put in pull-to-lock.and heaters de-energized. Alarms alert the operators of overpressure conditions. The design review process ensures that any changes to the system are reviewed in detail. The protection of the system is controlled by procedure by placing pumps l
in pull-to-lock and de-energizing heaters.
The inspectors consider this Temporary Instruction 2500/19 closed based on performing the preceeding review.
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11.
Steam Generator Status (62703, 61726)
l Unit 1 The Unit 2 eddy current inspection has been completet and the tube plugging list are being finalized.
The licensee is presently in the process of placing some of the plugs in the steam generators (SG) while waiting on the decision for the final plugging list.
The licensee is also attempting to stabilize the hot leg and U-bend portion of the ruptured tube in the "C" SG.
Several problems have been experienced during the installation of. the stabilizing spear on the cold leg side of the SG.
The first problem involved the inability of fully
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install the spear. Westinghouse technicians had to tap the bottom of the
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spear to force ~ several of the connection joints of the spear through the fifth and sixth support plates.
The spear was installed into the U-bend of the ruptured tube on September 10, 1987.
During the hydraulic expansion of the spear into the U-bend and support plates sections of the SG, the bladder ruptured in the vicinity of the seventh support plate.
Based on a fibsescopic inspection' of the spear, the licensee discovered that the spear had spilt just above the seventh support plate.
The licensee and -Westinghouse are evaluating the problem to determine necessary corrective actions.
On September 10,1987, VEPC0 met with the NRC in Bethesda, Maryland, to discuss the SG tube rupture event and their determination of the root cause and failure node.
Based on the licensee's and Westinghouse's investigation into the event, the failure mechanism'of the ruptured tube -
l was identified to be fatigue. The cause of the-fatigue was identified as I
a combination of the denting at the seventh support plate pinning the tube, the lack of support the U-bend section of the tube (i.e. no anti-vibration bars) and flow induced instabilities in the region of the
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U-bend. The licensee submitted the update to the tube rupture event on September 15, 1987, and expects to meet with the NRC again on September 21 in Bethesda to answer any questions resulting from the previous meeting on the 10th and the NRC review of the report update.
Unit 2 During the present Unit 2 refueling outage, the licensee will be performing several inspections, tests and maintenance items on the Unit 2 SGs.
These inspections, tests and maintenance items include eddy current inspections, secondary pressure tests, sludge lancing and row 2 U-bend heat treatment.
The initial test of the SGS at the start of the outage was a secondary side pressure test. This test consisted of pressurizing the secondary side of the SG and inspecting the primary side tube sheet for leaks. The results showed a number of leaking tubes in each the SGs, all in row one which have been previously plugged with explosive plugs. The only leaking tube not in row one was in the
"A" SG and that tube had been previously plugged with a mechanical plug.
l The Unit 2 eddy current inspection will consist of 100% inspection with
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the standard bobbin probe of the hot and cold leg sides of all the tubes not already plugged and an inspection with the 8x1 pancake probe of all tubes out to row 12 with a random sample of tubes beyond row 12.
The licensee has completed the stress relieveing/ heat treatment of the row 2 U-bends and the sludge lancing of all three Unit 2.SG's.
The results of the sludge lancing are as follows:
"A" SG - 270 pounds - 8 passes
"B" SG - 230 pounds - 8 passes
"C" SC - 265 pounds - 8 passes
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