IR 05000338/1979020
| ML19249B403 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 06/08/1979 |
| From: | Kellogg P, Kidd M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML19249B359 | List: |
| References | |
| 50-338-79-20, 50-339-79-28, NUDOCS 7909040376 | |
| Download: ML19249B403 (19) | |
Text
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Report No.
50-338/79-20 and 50-339/79-28 Licensee: Virginia Electric and Power Company P. O. Box 26666 Richmond, Virginia 23261 Facility Name: North Anna Units 1 and 2 Docket Nos.
50-338 and 50-339 License Nos.
NPF-4 and CPPR-78 e ear M'neral, Virginia Inspection at Nortic An[na S
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Inspector:
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Approved by:
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9 on Chief, ROSS Branch Day'e Si{gfed'
f P. J. p 3G_SE SLTiARY Inspection on April 2 - May 11, 1979 Areas Inspected This routine inspection by the resident inspector involved 99 manhours onsite of previously identified events, response to IE Bulletin 79-06A, and plant tours.
Unit 1 Findings No apparent items of noncompliance or deviations were identified.
Unit 2 Areas Inspected This routine inspection by the resident inspector involved 31 manhours onsite of previously identified open items; plant tours; reports per 10 CFR 50.55(e) and/or 10 CFR 21; and plant status regardir.g readiness for operation.
Unit 2 Findings Of the 4 areas inspected, no apparent items of noncompliance or deviations were identified in 3 areas. One apparent item of noncompliance was identified in one area (inf raction - f ailure to disseminate a deviation report on Unit I to persons responsible for reviewing the problem for reportability on Unit 2 paragraph 6.g.).
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DETAILS 1.
Persons Contacted Licensee Employees
- W.
R. Cartwright, Station Manager
- E. W. Harrell, Superintendent of Maintenance
- S. L. Harvey, Operating Supervisor
- J. D. Kellams, Superintendent of Operations E. G. Lif rage, Project Engineer P. A. Slatter, Resident QC Engineer - Construction
- E. R. Smith, Superintendent of Technical Services
- B. R. Sylvia, Director of Nuclear Operations Other licensee employees contacted included ten operators, three engineers, three mechanical maintenance foremen, three quality assurance engineers, and three office personnel.
- Attended one or more exit interviews.
- Contacted by telephone May 17, 1979.
2.
Exit Interview The inspection scope and findings were summarized on April 20 and 27 and May 4 and 11, 1979, for the persons denoted in paragraph 1.
The apparent infraction defined in paragraph 6.g., was discussed by telephone with B. R. Sylvia on May 17, 1979.
3.
Licensee Action on Previous Inspection Findings Not inspected.
4.
Unresolved Items Unresolved items were not identified during this inspection.
5.
Followup on Previously Identified Open Items - Unit 1 a.
Overweight Check Valves (338/79-15-03)
A verbal report of this fourteen day Licensee Even Report (LER) was received March 21, 1979.
A written report per 10 CFR 21, serial number 189 (Unit 2) was dated March 26, 1979, and the written LER (79-35) per Unit 1 Technical Specifications was dated April 2, 1979.
Incorrect weights were given on drawings for several six inch check valves manuf actured by Velan and supplied by Vestinghouse for use in safety injection (SI) systems for Units 1 and 2.
This discovery led to reanalysis of piping and support loads for systems in which these valves were used. For Unit 1, six instances of nonconservative strerses were calculated, requiring modifications to pipe supports and hangers.
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-2-The most severe case involved support FPH-SI-21-3 on six inch SI line SI-21-1502-Q1, the low head SI hot leg injection line for reactor coolant locp "A".
In this case, stresses exceeded code allowable, but were within material certification strengths for the piping used. The other five modifications involved strengthening of a support baseplate (FPH-SI-131-1), replacement of springs in two spring bangers, and adj us tment of spring settings for two other hangers. These modifica-tions were implemented per Unit 1 Design Change 79-518 and field changes to it per Section 3 of the Nuclear Power Station Quality Assurance Manual (NPSQAM) and were completed April 12, 1979. On that same date, the inspector observed the modifications to supports FPH-SI-21-3 on 6"-SI-21-1503-01 and FPH-SI-131-1 on 6"-SI-131-1502-Q1 and ascertained that they had been cocpleted in accordance with Design Change 79-S18 and its field changes.
A review of the package for 79-S18 on April 19, 1979, revealed signoffs and other documentation to be in order. Review of the co=pleted I.ER 79-35 revealed no discrepancies, thus there were no further questions regarding these six inch check valves in Unit 1.
VEPC0's response to IE Bulletin 79-04, letter no. 221A dated May 3, 1979, states that some three inch check valves by Velan in use in Units 1 and 2 were also found to have incorrect weights.
They were assumed to weigh 60 pounds, but actually weigh 85 pounds. A reanalysis of the impact of this difference in weight was continuing at the conclusica of the inspection.
Open items 338/79-15-04 and 339/79-21-03 remain open.
b.
Recirculation Spray Coolers On February 5,1979, VEPC0 notified IE of a potential problem involving hydraulic transients on the recirculation spray heat exchangers for Unit 2.
A written report per 10 CFR 21 was submitted February 9 (letter 080), an interim report per 10 CFR 50.55(e) was submitted on March 2 (letter 080A), and a final report per 10 CFR 50.55(e) (letter 080B) was submitted on April 10, 1979.
These Unit 2 reports and supporting evaluations by the Joseph Oat Corporation, manufacturer of the coolers, were reviewed and discussed in IE Report 339/79-23, wherein open item 339/79-12-05 was closed.
During the current inspection, cor re sponder.c e involving Unit I was reviewed. This included a letter of March 28, 1979, f rc:: S&W (number 11,432) to VEPC0 transmitting the evaluation by Joseph Oat and stating that the evaluation demonstrated that present design was acceptable and a letter from R. M. Berryman of VEPC0 Engineering to the Station Manager also stating that the design was acceptable.
Based on the review of the analysis discussed in Report 339/79-23 and review of the Unit I correspondence, the inspector had no further questions on the Unit I coolers.
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-3-Reactor Vessel Lower Head Insulation (79-05-01)
c.
As noted in IE Report 50-338/79-05, Unit 1 LER 78-100 reported that when a previous modification had been made to the supports for the reactor vessel lower head insulation, a seismic reanalysis had not been performed to verify that stresses on the incore guide tubes, used for support of the insulation, were within limits.
A subsequent analysis showed that six guide tubes would be overstressed under certain conditions but would not yield.
Design change 79-508 was implemented on Unit I to support the insulation from the bottom end of the neutron shield tank using angle iron supports to traverse the lower vessel head underneath the insulation.
Review cf the design change package, through Field Change (revision) four on April 23, 1979, revealed that the modification had been completed except for painting of certain hardware.
The inspector questioned whether a check for proper clearances between the insulation and guide tubes would be performed after heatups. Station management stated that such inspection would be made with the reactor in Mode 3 (Hot Standby)
an during startup from the shutdown existing at that time. A review of the Unit 1 Action Statement Status Log, 1-LOG-11, for May 1, 1979, revealed that this had been inspected on that date while in Mode 3.
Open item 338/79-05-01 is closed. The Unit 2 open item on this matter, 339/78-24-02, was discussed in IE Report 50-339/79-23, and was left open pending a reinspection during precritical testing to confirm no thermal growth interference exists.
d.
Reactor Coolant Pump Flow Straightening Devices (79-15-06)
As discussed in IE Report 50-339/79-21, Details paragraph 9.d., cracks were found in the flow splitter plates for one of the Unit 2 reactor coolant pumps on March 21, 1979. Because Unit 1 employs the same type flow splitters, the conditions of those in Unit I were questioned.
IE Report 50-338/79-17 discussed the ultrasonic techniques used to inspect the Unit 1 splitters. Results of those inspections were presented by Westinghouse Electric Corporation (Westinghouse) and VEPCO to Nuclear Reactor Regulation (NRR) and IE in a meeting in Bethesda, Maryland on April 12, 1979. That meeting was attended by this inspector. Additional information regarding effects of possible failure of a flow splitter plate was provided by VEPC0 for NRR to review on April 16, 1979. On April 27, NRR issued Amendment 10 to the Unit 1 Technical Specifications to require operability of the Unit 1 RCS loose parts monitoring system (3.3.3.9), place limitations on reactor coolant pump vibrations (3.4.10.1.d),
and require peri Jic surveillance of the flow splitters (4.4.10.1).
Discussions with operators and supervisors and review of the required reading file for operations personnel on April 30 revealed that operators had been made aware of these changes to Technical Specifications. The inspector had no further questions and station management was informed that open item 338/79-15-06 was considered closed.
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Licensee Event Reports - Units 1 and/or 2 The following reportable events or problems were reviewed to verify that reporting requirements had been met, causes had been identified, corrective actions appeared appropriate, generic applicability had been considered, and the Unit 1 LER forms were complete. Additionally, for Unit 1 it was verified that the licensee had reviewed each event, corrective actions had been taken, no unreviewed safety questions were involved, and any violations of Technical Specifications, other license conditions, or regulations had been identified.
Inside Recirculation Spray Motor Bearing Tolerances (LER 74-043)
3.
On April 11, 1979, VEPC0 reported that General Electric, the supplier of the North Anna 1 and 2 inside recircalation spray (IRS) pump motors, had informed them of an apparent design error in bearing tolerances.
A situation had been found wherein bearing failure could occur if the motor shaft tolerances were near the high end (largest dimension) of its band and the lower radial bearing was at its smallest possible dimension.
This discovery followed the failure of a Unit 2 motor bearing which was reported verbally per 10 CFR 50.55(e) on April 6, 1979, and by written report on April 6 (serial no. 255), per 10 CFR 21. Also, an interim report per 10 CFR 50.55(e), serial no. 255A, was submitted on May 4,1979.
At the time of the discovery of this problem Unit I was in cold shutdown (Mode 5) and VEPCO stated that the Unit 1 motors would be tested to verify lack of a tolerance problea prior to returning the Unit to power operation. A special test procedure, 1-ST-7, was approved by the Station Nuclear Safety and Operating Committee (SNSOC) April 13 for use in conducting these tests, which involved erection of a temporary dike around the containment sump and operating the pumps on recirc flow to and f rom the sump. Bearing temperatures were monitored by use of thermocouples inserted in the lower bearing grease relief plug and upper grease fitting. The tests were completed April 20 and reviewed that same date by the inspector after a review by the SNSOC, which found them to be satis f a cto ry.
Test data revealed that the lower bearing tecperatures peaked af ter some five hours for pump "A" (maximum of 172 f) and "B" (maximum of 155 F).
Each pump was operated an additional six to seven hours with no further increase in bearing temperature, indicating that the bearings installed were sufficiently
" loose" to preclude seizure of the shaft due to heatup.
Station management was informed there were no further questions on Unit I at that time, but that Unit 2 would be reviewed at a later date (open item 339/79-28-03).
As noted in the LER, Unit 1 bearings will be replaced during the first refueling outage to further assure that bearing tolerances are proper. This will be reviewed at a later date (open item 338/79-20-01).
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Piping Stress Analysis Errors (I.ER 79-052)
On April 11, 1979, the licensee reported verbally per 10 CFR 50.55(e)
that incorrect assumptions had been made for the Unit 2 main steam valve house (MSVH) displacements under seismic conditions, thus giving potentially nonconservative stresses on piping and supports in that complex.
While evaluating this problem, Stone and Webster (S&W)
discovered that incorrect building displacements had also been used in certain Unit 1 MSVH piping stress problems. This was reported by VEPCO on April 20, 1979, as prompt report LER 79-052 (written LER dated May 3) and as a 10 CFR 21 item by letter no. 306, dated April 27, 1979. New calculations using correct building displacements revealed four piping supports on safety injection (SI) systems which required strengthening to meet design standards for stress margins.
Those modifications were implemented by Design Change DC 79-529, and were completed on April 27, 1979. The inspector verified on that same date by observation of the supports that the modifications required by DC 79-529, including field changes (revisions) had been completed. No discrepancies were noted. Station management was informed that there were no further questions at that time on Unit 1, and that Unit 2 modifications, if required, would be reviewed at a later date (open item 339/78-28-04).
c.
Regenerative Heat Exchanger Supports (LER 79-047)
On April 12, 1979, \\TPC0 reported per Unit 1 Technical Specifications that Westinghouse had discovered that the chemical and volume control system regenerative heat exchanger nozzle loads were excessive and that failure due to nozzle cracking could occur after numerous years of operation. During discussions between VEPCO management and IE:II management on April 19, it was agreed that the Unit I heat exchanger support:: would be modified prior to returning Unit 1 to operation.
Design Change DC-79-S26 was approved April 12 to implement modifications to the heat exchanger supports based on recommendations f rom Westinghouse and Joseph Oat Corporation, manufacturer of the exchangers. DC-79-S26 was completed April 29 and the inspector verified by observation of the heat exchanger supports on that date that they had been modified in accordance with DC-79-S26 through Revision 5.
Licensee management was informed that there were no further questions on Unit 1.
This same problem was reported under 10 CFR 50.55(e) for Unit 2 on April 16 and will be inspected at a later date (open item 339/79-28-05).
d.
Service Water Piping Expansion Joints (LER 79-056 and 50.55(e))
On April 24, 1979, station management informed the inspector that the twelve rubber expansion joints in the service water supply and return lines for the four Units 1 and 2 component cooling heat exchangers were misaligned beyond their tolerances due to shifting of the service water lines. This was reported as a prompt LER and 10 CFR 21 item (letter no. 340) for Unit I and per 10 CFR 50.55(e) snd 10 CFR 21 for Unit 2 (joint report per letter no. 327 dated May 2, 1979). As noted in the Unit 1 confirming event report, realignrent was to be accomplished
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-6-prior to Unit I startup from the shutdown existing at that time.
The cause of misalignment was attributed to installation error wherein only two tie rods were installed across each expansion joint instead of the minimum of three required by station drawings.
Realignment of the SW lines and replacement of the expansion joints was performed under the station caintenance program defined in section 16 of the Nuclear Power Station Quality Assurance Manual (NPSQAM).
Two maintenance procedures were approved April 21, 1979, for conduct of the rework:
MMP-C-P-3,
" Mechanical Maintenance Procedure For Installation of Expansion Joints (Piping-Rubber)" and MMP-C-P-2,
" Mechanical Maintenance Procedure For Positioning Service Water Piping For Proper Flange Alignment".
A sepa rate M'iP-C-P-3 and Maintenance Report (MR) was used for each expansion joint. MR-N1-79-04211118 was used with MMP-C-P-2 to control realignment of the supply and return b e.4 d e rs.
Portions of the maintenance effort, conducted by S&W and supervised by VEPCO, was witnessed by the inspector on April 25, 27, and 28.
The following items were observed during witnessing of the maintenance and review of associated procedures and MR's:
1)
The approved procedure, MR's and associated Tagging Records were used to control the activity.
2)
A sampling of valves selected were found to be in the positions required by the Tagging Record in effect on April 25.
3)
The maintenance conducted did not invalidate test results on either unit.
4)
Receipt inspections were performed and documented for the new expansion joint <:.
The " certificate of performance" referred to Specification NAS 279, the station specification for the original expansion joints.
5)
Review of each completed MR and procedure on April 30 revealed paperwork to be in order except for final signoffs after cleanup of the work area and reviews by Maintenance supervision and Quality Conttol.
6)
Flange and bolt alignment data recorded in each procedure met the acceptance criteria provided in each procedure.
7)
Four tie-bolts were installed on each expansion joint as committed to in the LER.
Review of the written Unit 1 LER, dated May 4, 1979, and the Unit 2 report per 10 CFR 50.55(e) and 10 CFR 21 resulted in no cc::.ments.
Station personel were informed that there were no further questions on this particular problem.
joints were used elsewhere in the plant,During discussions on whether.sim station personnel stated that the only other application was in the gaseous waste system, a very low pressure system.
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-7-Spent Fuel Pit Cooling Capacity (LER 79-044)
e.
On April 3, 1979, the licensee informed NRC that due to a projected increase in service water temperatures for multi unit operation under certain accident conditions the ability of the spent fuel pool cooling system to maintain the pool temperatures given in Section 9.1.3.1 of the Unit I and 2 FSAR would be impaired. The conditions assumed for peak service water temperatures are given in LER 79-044, dated April 17, 1979. Analysis of this problem had not been ccepleted at the time LER 79-044 was submitted, but it was known that maintaining pool temperatures within limits would not be a problem until refueling of Unit 2, currently projected for late 1980 or early 1981. This matter will be reviewed further when the licensee analysis is complete (open item 338/79-20-02).
Other problems associated with the projected increase in service water temperature were discussed in IE Report 50-338/79-15, Details paragraph 5.c.
Station management assured the inspector that all ramifications of the service water temperature increase had been analyzed by S&W and that all potential problems had been identified.
f.
Foreign Substance in Valve MOV-RS-100B (Unit 1)
On April 11, 1979, during local leak rate testing of Unit I containment isolation valves, casing cooling valve MOV-RS-1003 (FSAR Figure 6.2-73)
failed its test. Upon disassembly of the valve, licensee personnel discovered a wax-like substance on the valve seat and disc.
The inspector observed the disassembled valve and discussed the finding with plant management.
Im. mediate corrective actions included replace-ment of the valve and successfully conducting a leak rate test on the replacement.
Station canagement stated that they were coniident that this was the only valve involved because of the construction history of the system, inspection of other valves, and discussions with the individual who apparently placed the foreign material in the valve.
This event will be reported as a thirty (30) day LER (79-048) per Unit 1 Technical Specifications and will be reviewed further (open item 33S/79-20-03).
g.
Diesel Generator Cooling Exhaust Ducting (Units 1 and 2)
Station management reported on May 4,1979, that it had been discovered that temporary angle iron braces used in construction fitup of the Units 1 and 2 emergency diesel generator exhaust cooling ducts had been left in place.
The potential existed for failure of the tack welds holding the braces, allowing them to fall onto the exhaust fans and damaging them.
Through discussions with operating personnel and review of the shift supervisor's log entries for May 3 and 4, it was ascertained that the angle irons had been removed from the Unit I ducts by May 4.
A written report per Unit 1 Technical Specifications to be submitted by May 17, 1979.
This matter will be reviewed was further (open item 338/79-20-04).
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-8-On May 16 and 17, 1979, the inspector discussed this problem on Unit 2 with corporate stafi members of the Power Station Engineering (PSE)
and Nuclear Operations departments to determine whether it was deemed to be a reportable item for that Unit.
It was learned that a copy of the Unit 1 Deviation Report (DR) had not been received by PSE to trigger a review for reportability under 10 CFR 50.55(e) or 10 CFh 21 for the Unit under construction. Licensee personnel were informed on May 17 that the failure to disseminate the required information to PSE in order that a timely review for reportability be conducted appeared to be in noncompliance with Criterion XVI of Appendix B to 10 CFR 50,
" Corrective Action" as implemented by paragraph 16.6.1.4.q(2) of the Nuclear Power Station Quality Assurance Manual (NPSQAM). The referenced NPSQAM paragraph states, in part:
" Deviation reports originating at operating stations which are reportable will be telecopied to the Director of Nuclear Operations soon as reportability is determined. The Director of Nuclear as Operations or his designee will determine if the deviation is considered potentially reportable for construction units, the deviation form and any additional information will be hand carried to the Project Ensineer for stations under construction and the Executive Manager - Licensing & Quality Assurance (EM - LQA)."
This is to ensure that a timely review for reportability for the Unit under construction can be accomplished per section 5.13.6 of the VEPCO Quality Assurance Manual - Engineering and Construction. This apparent infraction is identified as item 339/79-28-09.
h.
Reserve Station Transfer Buses (Units 1 and 2)
Station management informed the inspector on April 24, 1979, that it had been discovered that the Units I and 2 electrical transfer buses D, E, and F were not rated to carry the potential full load current for both Units. These transfer buses supply power to Units 1 and 2 normal and emergency A.C. buses froa the reserve station se rvice trans fo rmers when the unit generator (s) are not operating and are described in FSAR Section 8.3.1.1 and Figure 8.3.1-1.
The immediate concern was to limit Unit 2 loads to permit Unit 1 operation such that the bus ratings would not be exceeded during Unit I startups or aiter trips from power. This was accomplished by disconnecting the Unit 2 normal 4160V buses from the tranfer buses and limiting the Unit 2 emergency bus loads on the transfer buses.
On April 28, Standing Order No. 28 was issued to control the loads on Unit 2 and assign responsibility for shutting down equipment if Unit I were to trip.
The inspector verified on April 28 that the rese rve t rans fo rme rs ammeters had been marked to denote maximum continuous loads based on newly calculated bus ratings.
The Unit 2 normal bus feeder breakers had been opened, and a status log for Unit 2 emergency loads had been posted. There were no further questions at that time, but a permanent solution must be effected prior to operation of Unit 2.
As noted in 7,
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-9-Unit 1 LER 79-057, dated May 4,1979, an analysis to determine a final solution was being pursued.
This problem was also identified as a deficiency per 10 CFR 50.55(e) for Unit 2 (open items 33E/79-20-05 and 339/79-28-10).
i.
Environmental Qualifications of Containment Isolation Valves (Units 1 and 2)
Station management inforced the inspector on May 7,1979, that evalu-ation of environmental qualifications of Unit I class IE equipment as reluired by IE Bulletin 79-01 had resulted in the discovery of a potential problem with six sampling system isolation valves. These are solenoid operated valves and the mechanism which could create a problem is a plastic plug wnich could block an air port in the solenoid actuator preventing proper operation. The solenoids in question are manufactured by ASCO (Model No. 8320A102). The valves are normally opened only when samples are required and are designed to fail in the closed position.
This matter was reported as a prompt LER and as a
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twenty-four (24) bour report per IEB 79-01. A written report is to be submitted by May 21, 1979. This matter will be reviewed further at a later date (open item 338/79-20-06).
This matter was also reported as a 10 CFR 50.55(e) for Unit 2 on May 11,1979, and is identified as open item 339/79-28-11.
7.
Follevup of IE Eulletin 79-06A IE Bulletin 79-06A, " Review of Operational Errors and System Misalignments Identified During the Three Mile Island Incident", was issued for action to all licenseec with an operating pressurized water reactor designed by West-infaouse on April 14, 1979, and was followed by Revision 1 on April 18, 1979. VEPC0's response to this Bulletin for North Anna 1 and Surry 1 and 2 was letter no. 274 dated April 24, 1979.
On April 21, an NRC presentatica of the sequence of events and related information on the Three Mile Island (TMI) incident, along with a review of IEB 79-06A, was given in two sessions for licensed and non-licensed operators and other persons associated with the operation of Units 1 and 2.
This inspector participated in those presentations.
During the period May 1-11, 1979, this inspector, in conjunction with other inspectors of the Region II IE office as noted below, performed a review of licensee responses to the Bulletin, reviewed procedures and valve lineups for engineered safety features (ESP) equipment, and independently verified the alignment of accessible ESF components for operation of Unit 1.
Specific inspection functions were as follows:
Review of Operator Training a.
In addition to the NRC presentation of April 21, licensed operators attended training sessions conducted by the Operating Supe rvisor May 4-8, 1979.
One session, conducted May 8, was attended by this o
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-10-inspector. Based on observations in that session, discussions with at least two licensed operators per shif t, and review of a ca.c.orandum by the Quality Supervisor dated May 10 documenting these training sessions, the inspector concluded that the operators had been trained as requested by the IEB.
Specific items covered included:
1)
Changes to emergency, abnormal, and annunciator procedures.
2)
Restoration of equipment to operable status after testing or maintenance.
3)
Rest;ictions on overriding automatic functions of ESF equipment.
4)
Review of automatic actions initiated by reset of ESF actuation signals, which could affect the control of radioactive liquids and gases, namely none.
For NortF Anna 1 and 2, reset of SI or containment depressurization actuat (CDA) does not change any O
valve positions, but allows manaal actua; ion of them.
5)
Conditions which require notification of N90.ud-tablishing an open line to Region II. it was noted that no additionai telephone equipment was felt neede. at that time.
6)
Tripping of the presso izer low level protection channels and provisions for retur.ing sem to normal while conducting surveil-lance tests on them and the pressurizer pressurc channels.
7)
Means of determining seturation temperature in the reactor coolant system.
8)
Requirements for testing redundant ESF components prior to taking another out of service.
In addition to specific training sessions for licensed operators, IEB 79-06A and Revision 1, along with revised procedures, were placed in the required reading file for all operators. Also, licensed operators were scheduled to attend simulator training at Surry where the TMI accident would be simulated. All shifts were scheduled to attend this training in May.
Plant management's participation in the review of the IEB and VEPCO's response to it, along with procedure changes resulting from the IEB was documented in SNSOC meeting minutes for April 16,17,18, 23, and 30,1979.
b.
Inspection of ESF and Related Procedures On May 1-4, 1979, this inspector reviewed valve and breaker / switch lineup procedures for all Unit 1 ESF equipments / systems in conjunction with a Region II inspector.
These were compared to station flow and single line diagrams to verify adequacy of the alignment procedures.
Approximately fif ty (50) valve checklists, breaker checklists, startup checklists and operating procedures were reviewed.
All lineups were found to be adequate, although errors such as incorrect valve numbers,
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-11-missing vent or drain valve numbers, and lack of reference by a control-ling checklist to a system checklist were identified and discussed with station personnel. The comments were acknowledged and provisions for correcting the errors found initiated.
Details a. e given in IE Report 50-338/79-21, Details paragraph 6.
Administrative controls for procedure content, given in sections 5.5.5.8 and 16.6.5.4 of the NPSQA'!, were reviewed to determine whether they require that maintenance and test procedures provide for returning systems to an operable condition af ter the test or maintenance activity.
It was found that such provisions are given for maintenance operating procedures (MOP) and periodic test (PT) or surveillance procedures, but not for startup test (SU) or special (ST) procedures.
Station personnel acknowledged this apparent deficiency and stated that it would be studied to determine if changes were needed. This matter will be reviewed further and is designated as open items 338/
79-20-07 and 339/79-28-12.
Licensee startup procedures were reviewed to assure that ESF systems are returned to operable status following outages.
The following procedures were reviewed:
1)
1-0P-1.1, " Unit Startup From Cold Shutdown Condition (Mode 5)
< 140 F With The Primary System Drained To Cold Shutdown Condition (Mode 5) $ 200 F" - Revision 4 dated December 26, 1978 2)
1-OP-1.2, " Unit Startup From Cold Shutdown Condition (Mode 5)
< 200 F With A Steam Bubble In The Pressurizer To Cold Shutdown Conditica (Mode 5) $ 200 F" - Revision 3 dated June 6,1978.
3)
1-0P-1.3, " Unit Startup From Cold Shutdown Condition (Mode 5) To Hot Shutdown Condition (Mode 4) $ 350 F" - Revision I dated January 6,1978.
4)
1-0P-1.4, " Unit Startup From Hot Shutdown Condition (Mode 4) To Hot Standby Condition (Mode 3) At 547 F" - Revision 5 dated March 12, 1979.
5)
1-0P-1A,
'Tre-Startup Checkof f List" - Revision 0 dated Oct ober 6, 1976.
6)
1-0P-1B,
" Containment Checklist" - Revision 0 dated December 6, 1976.
7)
1-0P-1E,
"Containcent Integrity Checklist" - Revision 4 dated October 9, 1978.
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-12-It was found that the above procedures, in conjunction with system checklists referenced in 1-0P-1A, return all ESF systems to an operable status after outages, with one exception.
Checklist 1-OP-1A did not reference 1-0P-7.7A, the refueling water storage tank (RWST) valve checklist. A change to 1-OP-1A vas initiated immediately, thus the inspector had no further questions at that time. As noted in paragraph 7.c, all RWST valves were found to be in their proper positions.
Current revisions of surveillance (PT) and maintenance (MOP) proce-deres for all ESF systems / components were reviewed to assure that they contain steps to return systems / components to operable conditions after cocpletion of the test or maintenance activity. This effort was in conjunction with Region II inspectors and is documented in IE Report 50-338/79-25 No significant problems were identified.
The most recently completed surveillance tests (PT) lor EdF systems and components were reviewed to determine whether acceptance criteria were met. This effort is documented in IE Report 50-338/79-25, including problems noted.
Item 3 of the IEB and Revision 1 of the IEB required that the low pressurizer level bistables feeding SI logic be tripped for those plants which use low pressurizer level in conjunction with low pressur-izer pressure to automatically initiate SI (such as North Anna 1 and 2).
On May 4, 1979, the inspector verified by observation of the Unit I alare and annunciator panels that all three level channels had been tripped.
Also, the PT's for pressurizer level and pressure channels functional tests were reviewed to determine whether instructions had been included to control the status of the level channels during and af ter conduct of the tests. Procedures reviewed included:
1)
1-PT-31.5.1,
" Pressurizer Pressure Channel I (P-455) Functional Test" - Revision 6 dated May 2,1979.
2)
Similar procedures, 1-PT-31.5.2 and 1-PT-31.5.3 for Channels II and III, dated May 2,1979.
3)
1-PT-31.7.1,
" Pressurizer Level Channel I (L-459) Functional Test" - Revision 5 dated May 2,1979.
4)
Similar procedures, 1-PT-31.7.2 aad 1-PT-31.7.3 for Channels II and III, dated May 2,1979.
The level channel procedures were found to return the channel involved to a tripped condition af ter completion of the functional test. The pressure channel procedures instruct the performer to return all three level channels to normal until each pressure channel has been tested, then all three are returned to a t ripped state.
This was noted to be in conformance with VEPCO's response to the IEB, thus the inspector had no questions at that time, wp >q 7 4 u t.r w m
-13-c.
Inspection of ESF components On May 4, the inspector compared valve positions in the auxiliary feedwater system (AFW) for Unit I which station drawings (FM-70A, Revision 8 and FM-74A, Revision 10) and valve checklists (1-0P-31.2A and 1-0P-28A, both dated October 30, 1978) indicated should be locked open or closed to the procedural and drawing requirements.
All AFV valves for the two motor driven pumps were found to be locked as required. One anomaly was observed on the steam driven pump 1-FW-P-2.
The turbine casing drain valves, 1-MS-338 and 422 are shown as locked open on FM-70A, but were not locked in the field, although they did appear to be partially open.
The valve checklist 1-0P-28A did not require that they be locked.
Station personnel were evaluating this matter at the conclusion of the inspection.
It was noted that purco performance has been satisfactory during surveillance tests. Inspector followup of this matter will be per an open item identified in IE Report 50-338/79-25, Details paragraph 6.
During the week of May 7,1979, this inspector assisted two Region II inspectors in verifying the accuracy of valve and breaker lineups for accessible ESF systems.
The lineups and checklists discussed in paragraph 7.b, were used to determine accuracy of observed lineups.
No significant anomalies were found. Details of this effort are given in IE Report 50-338/79-25.
d.
Associated Operating Practices and Procedures During the interviews of operators discussed in paragraph 7.b, and discussions with other station operating personnel, the following subjects were covere'd:
1)
Partial Actuation of SI The North Anna 1 and 2 SI logic is such that pushing either of the two SI buttons per Unit will result in full SI actuation, thus the term " partial" actuation is not relevant (see FSAR Figure 7.2-8).
The discussions did reveal, however, that the operators would not hesitate to start a ;econd charging pump (high head SI) in order to assist in maintaining pressurizer level, if necessary.
2)
Securing Reactor Coolant Pumps The following erergency and abnormal procedures vere revised May 2, 1979, to inco rpora te changes required by IEB 79-06A, in:1uding the requirement for operating at least two RCP's given in item 7.c, of the IEB:
a)
1-EP-2, " Loss of Reactor Coc. ant Accident"
b)
1-EP-4, " Steam Generator Tube Rupture"
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-14-c)
1-EP-3, " Main Steam Line Rupture" d)
1-AR-2, " Panel IB - Main Control Board" (Annunciator response procedures)
Also, a new procedure, 1-AP-44, " Loss of Reactor Coolant System Pressure", was approved on that date. All of these except 1-AR-2 require two RCP's to be operated as long as they provide forced flow if an SI due to low pressure has occurred. Procedure 1-AR-2 was revised to require closure of the pressurizer power operated relief isolation valves if the relief fails to close. Operators interviewed were f amiliar with and understood the new requirements.
3)
Securing Safety Injection The procedures listed in 7.d.(2) were also revised to restrict the termination of SI if it occurred due to low pressure.
The requirements of items 7.b.(1) and 7.b.(2) of the IEB were repeated verbatim in each procedure except 1-AR-2.
Operators interviewed understood these requirements and were knowledgeable in the method of determining saturation temperatures of the hot and cold legs. A temperature / pressure template was provided for operator use in the Unit I control room.
4)
Feeding Dry Steam Generators (SG)
North Anna has no procedure for feeding a dry SG.
Operators interviewed felt that there would never be a need for doing this in that it is not probable that all three SG's would be boiled dry, but stated that it would be done if necessary. The inspector was advised by a member of station management that such a pro-cedure was being developed by Westinghouse.
5)
Tagging on Control Boards Past observations by the inspector plus discussions with licensed operators revealed little potential for obscuring control board indications due to placement of tags on the boards on the operating unit.
To assure uni f o rmity among shifts and centrol usage of tags during shutdowns, station management stated that instructions on placement of tags would be Eenerated. This will be reviewed further and is designated open items 338/79-20-08 and 339/79-28-13.
8.
Unit 2 Status - Readiness for Operation On May 14, 1979, the inspector was informed that VEPCO's revised estimate of Unit 2 readiness for fuel loading was June 26, 1979. As of May 11, 29 of the total number of 95 preoperational tests had been completed, reviewed and approved by VEPCO. Another 27 had been completed and were under review, with 39 either in progress or not started.
In IE Report 50-339/79-21, Details paragraph 8, a listing of problems to be completed or otherwise resolved prior to IE:II making a finding that Unit 2 would be ready for an o 1-eq * o o b w _ L'
-15-operating license was given.
The following listing is an update based on development of new problems, resolution of certain old ones, and other modifications based on discussions with IE:II.
Items are categorized as requiring resolution prior to issuance of the operating license, prior to initial criticality, or later milestones.
a.
Items to be Resolved Prior to Operating License Issuance 1)
Surveillance of settlement of Class I structures is hampered by lack of baseline or continuous data (78-32-03).
2)
Resolution of Quality Assurance program outstanding items (IE Report 339/79-11).
3)
Resolution of cracks in a reactor coolant pump flow straightening device (79-21-05).
4)
Completion of preoperational testing and resolution of significant test deficiencies and Master Deficiency List items.
5)
Complete development of operational procedures recommended by RG1.33 and startup test procedures. One startup test and four surveillance test procedures remain to be approved.
6)
Complete implementation of industrial security program in accordance with the North Anna Modified Amended Security Plan.
7)
Modify the electrical transfer buses to eliminate overloading during two unit operation (LER 79-57/0IT-0; 79-28-10).
b.
Items to be Resolved Prior to Initial Criticality 1)
Completion of modifications to the outside recirculation spray system to preclude NPSlf problems (78 05-04).
2)
Installation of reactor vessel shielding to prevent excessive radiation levels in containment (78-12-02).
3)
Verify adequacy of service water and component cooling water pipe supprts to resist thermal loadings over service water temperature range (78-36-01).
4)
Installation of caps on outside end of spare containment piping penetrations (78-36-02).
5)
Resolution of break in fiberglass service water spray pond piping
.
(78-36-05).
6)
Verify service water flow to charging pump coolers is sufficient (79-12-01).
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Determine if atypical weld material was used in the reactor vessel seam welds (IE Bulletin 78-12A).
8)
Revise operating procedures and system drawings to assure electrical independence between redundant subsystems for control room air conditioning (79-12-02).
9)
Demonstration of operability of AC and DC solenoid valves which may have parts missing (79-21-02).
10)
Complete modifications to control room air conditioner chillers required as a result of the increase in projected service water temperature resulting f rom reevaluation of the spray pond ef ficiency (79-21-01).
11)
Resolution of lack of seismic supports and missile protection for the emergency diesel generator exhausts and muf flers (79-12-05).
12)
Resolution of f ailure of a Klockner-Moeller motor control center starter due to shorting between phases (79-21-06).
13, Resolution of error found in DNBR analysis for single dropped ontrol rod event (79-28-01). This was the subject of a 10 CFR T.55(e)/10 CFR 21 report dated April 6,1979.
14)
Replacement of rusted incore flux tt imble tubing (79-28-02).
This was reported per 10 CFR 50.55(e)/10 CFR 21 on April 9,1979.
15)
Reanalysis of main steam valve house piping and support loadings following discovery of building displacement assumption error (79-28-04). Report per 10 CFR 50.55(e) and 10 CFR 21 dated April 16, 1979.
16)
Modification to regenerative heat exchanger supports to assure proper sizing for all loads (79-28-05). Report per 10 CFT, 50.55(e)
and 10 CFR 21 dated April 20, 1979.
17)
Verification that pipe support base plates using concrete expansion anchor bolts are adequate in accordance with IE Bulletin 79-02 (79-28-06).
18)
Verification of adequate seismic stress analysis of safety related piping per IE Eulletin 79-07 (79-28-07).
19)
Completion of acticas required by IE Bulletin 79-09 regarding GE Type AK-2 circuit breakers (79-28-08).
20)
Verification that no mechanical interferences exist between incore guide tubes or mdified insulation supports and the reactor vessel lower head insulation due to therul growth during pre-critical testing (78-24-02).
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Verification of operability of hydraulic snubbers during precritical testing (79-26-02).
22)
Verification that piping and support loads are within limits for systems sherein erroneous Velan check valve weights were assumed (79 21-03 and IE Bulletin 79-04).
23)
Resolution of inside recirculation spray pump motor bearing f ailure due to shaf t seizure (79-28-03).
Items Requiring Resolution Prior to Exceeding 25% Power c.
1)
Verify environmental qualification class of IE electrical components inside containment (IE Circular 78-08/78-28-01 an IE Bulletin 79-01).
2)
Development of surveillance program for fiberglass spray pond and piping and supports comparable to that of RG 1.72 (78-28-02).
9.
Plant Tours Tours of selected plant areas were conducted on April 3, 6, 11, 25, and 27, 1979, in conjunction with other inspection functions or while escorting site visitors such as from the NRC Office of Inspector and Auditor on April 3 and the Office of Management and Budget on April 6.
During those tours the following items, as available, were observed:
a.
Fire Equipment Operability and evidence of periodic inspection of fire suppression equipment.
b.
E usekeeping Minimal accumulations of debris and maintenance of required cleanliness levels in systeras under or following testing.
c.
Equipment Preservation Maintenance of special preservative measures for installed equipment as applicable.
d.
Ccaponent Tagging Implementation and obs e rvance of equipment tagging for safety or equipment protection.
e.
Communication Effectiveness of public address system in all areas toured.
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.
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f.
Equipment Controls Effectiveness of jurisdictional controls in precluding unauthorized work on systems turned over for ir.itial operations or preoperational testing.
g.
Foreign Material Exclusion Maintenance of controls to assure systems which have been cleaned and flushed are not re-opened to admit foreign material.
h.
Security Implementation of security provisions for both Units.
Within the above areas, no items of noncompliance or deviations were observed when compared to the applicable station programs and procedures.
On April 11, it was observed that the new fuel assemblies for Unit 2 stored in the spent fuel pool did not have any rigid protective covering over them which might protect them from falling objects. This observation was given to station management for their consideration.
Later in the inspection period, plywood sheets wrapped with fire resistant "herculite" were placed over the assemblies.
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