IR 05000321/1993002
| ML20034G040 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 02/22/1993 |
| From: | Christnot E, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20034G036 | List: |
| References | |
| 50-321-93-02, 50-321-93-2, 50-366-93-02, 50-366-93-2, NUDOCS 9303080087 | |
| Download: ML20034G040 (19) | |
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UNITED STATES
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fg NUCLEAR REGULATORY COMMISslON
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REGION li
,. E 101 MARIETTA STREET.N.W.
's ATLANTA, GEORGI A 30323
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Report Nos.:
50-321/93-02 and 50-366/93-02
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Licensee: Georgia Power Company P.O. Box 1295
Birmingham, AL 35201-j r
Docket Nos.:
50-321 and 50-366 License Nos.: DPR-57 and NPT-5
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Facility Name: Hatch Nuclear Plant
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Inspection Conduct d: January 10 - February 06, 1993 Inspectors:
. 2M 2//9 /91 Leonard DgeTt, Jr., Sr. Resident Inspector Date Signed 0(A/
a/n/9?
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% Edward F.
pstnJ,ResidentInspector Date Signed ec 2L /
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Approved by:
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Pierce H. Skinner, Chief, Date Signed
Project Section 3B,
Division of Reactor Projects
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I SUMMARY
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Scope:
This routine, announced inspection involved inspection on-site in j
the areas of operations, surveillance testing, maintenance activities, modifications, review of clogging of a residual heat removal service water system flow control valve, and review of open items.
Results: One unresolved item and one inspector followup item were
identified:
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The unresolved item (URI) addressed the clogging of a Unit 1 residual heat removal service water (RHRSW) flow control val'ce which resulted in the inoperability of one RHRSW loop. The root cause of
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the fouling was still under investigation at the end of the report
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period (URI 321/93-02-01: Clogging of RHRSW Flow Control Valve, q
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paragraph 6).
The inspector followup item (IFI) addressed deficiencies identified during a review of the licensee's annunciator control program. The
problems involved primarily non-safety related annunciators and
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individually were not significant. Collectively, the deficiencies indicated that the procedural guidance was not being followed'(IFI 321/93-02-02: Annunciator Control Deficiencies, paragraph 2b).
9303000087 930224 PDR ADOCK 05000321 G
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i REPORT DETAILS
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1.
Persons Contacted Licensee Employees
- J. Betsill, Unit 2 Operations Superintendent
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- C. Coggin, Training and Emergency Preparedness Manager
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D. Davis, Plant Administration Manager'
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- P Fornel, Maintenance Manager
- 0. Fraser, Safety Audit and Engineering Review Supervisor
- G. Goode, Engineering Support Manager
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- J. Hammonds, Regulatory Compliance Supervisor
- W. Kirkley, Health Physics and Chemistry Manager
J. Lewis, Operations Manager
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- C. Moore, Assistant General Manager - Plant Support
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- J. Payne, Senior Engineer Nuclear Safety & Compliance
- D. Read, Assistant General Manager - Plant Operations
- P. Roberts, Acting Outages and Planning Manager
- K. Robuck, Manager, Modifications and Maintenance Support
H. Sumner, General Manager - Nuclear Plant i
J. Thompson, Nuclear Security Manager
- S. Tipps, Nuclear Safety and Compliance Manager
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- P. Wells, Unit 1 Operations Superintendent
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Other licensee employees contacted included technicians, operators,
mechanics, security force members and staff personnel.
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NRC Resident Inspectors
- L. Wert
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- E. Christnot
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Attended exit interview l
Acronyms and abbreviations used throughout this report are listed in the
last paragraph.
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l 2.
Plant Operations (71707)
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a. Operational Status l
Both units operated at full rated power for most of the report period.
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The inspectors reviewed plant operations throughout the reporting i
period to verify conformance with regulatory requirements, TSs, and
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administrative controls. Control room logs, shift turnover records,
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temporary modification logs, LCO logs and equipment clearance records l
were reviewed routinely. Discussions were conducted with plant'
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operations, maintenance, chemistry, health physics, I&C, and NSAC
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personnel.
The inspectors also continued to periodically monitor the i
ongoing SFP cleanup project.
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Activities within the control rooms were monitored on an almost daily
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basis.
Inspections were conducted on day and on night shifts, during j
weekdays and on weekends. Observations included control room manning,
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access control, operator professionalism and attentiveness, and
adherence to procedures.
Instrument readings, recorder traces, l
annunciator alarms, operability of nuclear instrumentation and reactor l
protection system channels, availability of power sources, and f
operability of the Safety Parameter Display System were monitored.
I Control Room observations also included ECCS system lineups, i
containment integrity, reactor mode switch position, scram discharge J
volume valve positions, and rod movement controls. Numerous informal l
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discussions were conducted with the operators and their supervisors.
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Some inspections were made during shift change in order to evaluate
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j shift turnover performance. Actions observed were conducted as j
j required by the licensee's administrative procedures.
The complement i
i of licensed personnel on each shift met or exceeded the requirements j
of TSs.
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During a routine review of 10 CFR 50.72 reports, it was noted that a
j reactor facility similar to Hatch had reported a period of operation l
j above design reactor power.
The problem was caused by the RWCU system j
flow indication not being restored to the plant computer heat balance
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calculation after RWCU was returned to service.
The inspectors
i verified that procedural controls were in place to reduce the
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probability of such an error at Hatch.
Procedures 34S0-G31-003-1 and
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25 contain specific requirements to inform the STA of restoration or
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removal of RWCU flow so that consideration can be given to the effects on the heat balance calculation. The alarm response procedures for
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isolation of the RWCU system did not have any such requirements; but
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l leaving the flow signal input in the calculation when there was no l
actual RWCU flow would make the calculated power level conservative.
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j The controls were discussed with the STA on duty.
He clearly j
J understood the importance of providing correct information into the j
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calculation.
The inspectors concluded that adequate procedural
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9uidance was in place to minimize the possibility of this error j
causing inadvertent operation above rated power at Hatch.
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Several active safety-related equipment clearances were reviewed to
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confirm that they were properly prepared and executed.
Applicable j
circuit breakers, switches, and valves were walked down to verify that i
l clearance tags were in place and legible and that equipment was j
properly positioned.
Equipment clearance program requirements are j
specified in licensee procedure 30AC-0PS-001-05, " Control of Equipment j
Clearances and Tags." No discrepancies were identified.
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Selected portions of the containment isolation lineup were reviewed to i
confirm that the lineup was correct.
The review involved verification l
of proper valve positioning, verification that motor and air-operated l
valves were not mechanically blocked and that power was available
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l (unless blocking or power removal was required), and inspection of f
piping upstream of the valves for leakage or leakage paths.
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Plant tours were taken throughout the reporting period on a routine i
basis. The areas toured included the following:
Reactor Buildings Station Yard Zone within the Protected Area Turbine Building l
Intake Structure
Diesel Generator Building f
Fire Pump Building l
Radwaste and Radwaste Addition Buildings
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Waste Gas Treatment Building l
During the plant tours, ongoing activities, housekeeping, security,
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equipment status, and radiation control practices were observed.
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Due to the high level of the Altamaha river and recent problems
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involving the traveling water screens (IFI 321/92-32-03:. Intake
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Traveling Water Screen Issues), the inspectors frequently monitored
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conditions in that area. No significant problems were noted.
The inspector performed a survey as directed by NRC management l
involving the strainers installed on the torus suction piping for
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the LPCI, core spray, and HPCI systems. The survey requested
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specific plant information involving the type of drywell insulation, i
the insulation manufacturer, and the main steam valves discharge j
path. Additionally, information regarding alternate water sources i
available for ECCS was provided.
No deficiencies or potential problems were identified.
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b.
Annunciator Controls i
The inspectors reviewed the implementation of the annunciator.
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control program. A detailed examination of the annunciator control j
logbooks for both units was conducted. Additionally, walkdowns of
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the CR annunciator panels and several local alarm panels were completed. During the review it was noted that the licensee's usual i
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practice of aggressive pursuance of lit CR annunciators continued.
Usually, very few (1-3) or no illuminated annunciators are present on each unit. Only on a few occasions have the inspectors noted that actions could have been more prompt with regard to lit CR annunciators. Recent examples were a RWCU room high temperature alarm (Inspection Report 321,366/92-15) and a MFWPT vibration alarm (Inspection Report 321,366/92-32).
The controls associated with annunciators are established in procedure 30AC-0PS-009-05: Control Room Instrumentation.
Corrective actions for nuisance, problem, or inoperable annunciators are included.. Additionally, the procedure addresses compensatory actions and administrative reviews.
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At the time of the review, 17 annunciator cards were removed from l
service (pulled) an Unit I and 10 were pulled on Unit 2.
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annunciator controi sheets were correctly filled out and labels i
marked the associated alarm windows.
Of the 27 total pulled cards,
8 were pulled over a year ago. Only 3 of the Unit 2 pulled cards
were less than 3 months old.
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The following discrepancies were identified during the review:
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Of the 8 annunciator cards which were pulled over 1 year ago, 2 (control sheets 1-90-22P and 1-91-52P) did not have adequate
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justification or resolution plans documented.
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annunciators were not safety related.
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Step 8.8.3 of 30AC-0PS-009-05 requires Operations supervision i
to review the engineering evaluations for problem annunciators
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each month and ensure they are still applicable. Step 8.8.2 l
l requires Operation supervision to inform the Operations Manager
of any problem annunciators or evaluations older than 3 months.
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The Operations Manager is to notify the Manager of Engineering
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j Support of problem annunciators or evaluations older than 3 l
months.
The General Manager is to be notified of those older i
than 6 months. Within 1 month, Engineering is required to l
provide an evaluation on each reported problem annunciator.
Although the reviews were conducted and the required
.t notifications were made, several problems involving non-safety
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related annunciators were noted. The inspector identified 2 I
problem annunciators which did not have any engineering
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evaluations despite being designated over 5 months ago.
l Another card which had been pulled on August 3, 1992, had just
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had an evaluation completed on January 4,1993. One of the l
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completed evaluations for a problem annunciator over 5 months
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old was inadequate. Additionally, several examples of (
evaluations which had not been updated / reviewed in over 3
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months were noted. The inspector concluded that engineering i
management had not ensured that procedural requirements were
met despite being informed that actions were necessary.
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Step 8.7.9.12 of 30AC-0PS-009-0S states that an annunciator i
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card may not be temporarily restored for more than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
The inspector noted one example (control sheet 1-92-64P) where i
the annunciator had been temporarily restored for a period of
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several days. The involved annunciator was not safety-related.
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During review of a aulled annunciator associated with the 2C
EDG jacket water 1 vel / pressure (control sheet 2-92-70P), the i
inspector noted a discrepancy with the associated compensatory l
actions. The annunciator card for the jacket water level alarm
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(local alarm in the EDG room) was pulled on December 10, 1992,
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awaiting parts to repair a level switch. This annunciator is
safety related and a safety evaluation and PRB review were completed prior to the card being pulled. The evaluation
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stated that compensatory action would be taken consisting of monitoring jacket water pressure at 10 minute intervals during EDG operation.
This alarm function is specifically addressed in section 8.3.1.1.3.I of the FSAR. On January 2,1993, a Unit I shift supervisor terminated this compensatory action.
The inspector noted that the portion of the control sheet required to be completed by the SS when compensatory actions are terminated was not completed. The compensatory action sheet number had been lined out and the sheet apparently removed from the file. The inspector immediately informed the Unit 1 SS of his concern. The compensatory action was activated again.
Subsequent review identified that errors were made during the preparation of the safety evaluation.
Apparently, personnel thought that the card for the alarm on the CR panel (a single indicator which illuminates on either level or pressure problems) was pulled. Compensatory action for the jacket water pressure was not necessary since the annunciator was operable. The evaluation was being revised at the end of this reporting period.
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Step 8.5.2.4 of 30AC-0PS-009-0S requires that if a nuisance annunciator is deactivated, a compensatory action to determine if the condition prompting the annunciation has cleared must be performed at least once per shift.
The inspector noted several annunciator control packages involving pulled cards identified as nuisance alarms which indicated that this was' not completed.
It appeared that most of the examples involved documentation which incorrectly classified the alarms as nuisance alarms instead of problem annunciators. While this check process was being performed on several of the pulled annunciator cards, it was not scheduled once per shift.
In several areas, the inspector did not note any discrepancies. The monthly Operations supervision reviews of the program were conducted at the required interval and appeared to be thorough.
No weaknesses were identified in the safety evaluations for safety related annunciators. The inspector did not identify any incorrectly classified (non-safety or safety related) pulled annunciator cards.
Procedural requirements were met prior to or within the prescribed time period of the annunciator being disabled.
Compensatory actions were completed in accordance with the active compensatory action sheets.
The inspector concluded that the overall controls on those annunciators considered as safety related were implemented appropriately.
The above discussed issue involving a compensatory
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action was the only exception noted and it was primarily an administrative problem.
The inspector concluded that several procedural requirements involving annunciators considered as non-safety related were not met.
Engineering evaluations were not completed or updated as
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safety significant, collectively they indicated that the procedural
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controls on annunciators were not being followed. This issue is identified as IFI 321/93-02-02: Annunciator Control Deficiencies.
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One inspector followup item was identified.
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3.
Surveillance Testing (61726)
Surveillance tests were reviewed by the inspectors to verify procedural and performance adequacy. The completed tests reviewed were examined for
necessary test prerequisites, instructions, acceptance criteria,
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technical content, authorization to begin work, data collection, independent verification where required, handling of deficiencies noted,
and review of completed work. The tests witnessed, in whole or in part,
were inspected to determine that approved procedures were available, test l
equipment was calibrated, prerequisites were met, tests were conducted
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according to procedure, test results were acceptable and systems j
restoration was completed.
t The following surveillances were reviewed and witnessed in whole or in
part:
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34SV-Ell-004-IS-RHRSW Pump Operability 42SV-R42-007-OS:
Battery Charger Capacity Test
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The licensee had established a task force to review a recently identified series of missed TS surveillances.
Inspection Report 321,366/92-34
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contains a detailed discussion of the inspector's review of this problem.
The task force consisted of supervisors from on-site organizations such as maintenance, planning and control, operations, SAER and Compliance.
The task force held three meetings, and reviewed a total of 20 examples l
of TS non-compliance over a two year period. The task force determined that the most frequent cause was personnel error, and the second most common cause was less than adequate procedures. The task force determined there were no programmatic deficiencies within the TS surveillance program that contributed to the overall surveillance non-compliance. On January 21, 1993, the task force presented plant
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management the results of the reviews.
Six items, consisting of observations and recommendations, were discussed. The items addressed actions involving deferred compliances, use of editorial changes, implementing TS changes, getting information to the field about ongoing problems that occur on-site, and use of innovative techniques to
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reemphasize attention-to-detail.
The inspector attended the licensee i
meetings and reviewed the results of the reviews.
Based on the attendance and reviews, the inspector concluded that site management is involved in activity pursuing corrective actions involving the missed surveillances.
IFI 321,366/92-34-02: Missed TS Surveillances remains open. The inspector will continue to monitor the licensee's activities in this area.
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No violations or deviations were identified.
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Maintenance Activities (62703)
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Maintenance activities were observed and/or reviewed during the reporting
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period to verify that work was performed by qualified personnel and that approved procedures in use adequately described work that was not within the skill of the trade.
Activities, procedures, and work requests were
examined to verify proper authorization to begin work, provisions for j
fire, cleanliness, exposure control, proper return of equipment to
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l service, and that limiting conditions for operation were met.
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The following maintenance activities were reviewed and witnessed in whole f
or in part:
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MWO 2-92-4247:
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i MWO 2-92-6507:
Perform 1 Year PM, Meggar and Oil Change on CS Pump l
MWO 2-92-4246:
i MWO 1-92-4086: Diesel Driven Fire Pump Yearly Inspection I
No violations or deviations were identified.
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5.
Modification Review (37828) (37001)
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The inspectors reviewed the implementation of temporary design change 92-162 which involved the turbine building and control building HVAC
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systems.
During the hot summer months the turbine building HVAC system
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is heavily taxed and extra air handling capacity to assist in air turnover would be beneficial. Also, recently there has been an excessive
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amount of noble gases detected in the turbine building, placing an
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additional burden on workers and the health physics department.
This DCR was intended to improve the conditions in the TB.
The DCR consisted of a temporary ventilation system that removes air from the turbine building
through two roof openings.
Temporary ductwork was used to route air from J
the roof openings to the spare control building ventilation system standby exhaust fan.
The inspectors reviewed and observed the licensee's activities involved with the installation of this temporary design change.
The inspection
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effort involved review of the design package including the safety
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evaluations. Additionally, TS requirements and the applicable FSAR sections were reviewed in detail. Work observed included installation of temporary transition pieces, removal of a permanent duct work transition
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piece, the installation of portable duct work, and installation of
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temporary anchors.
The inspectors discussed the methods of operation of the temporary system
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with various licensee personnel. The discussions included the
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contingency plan for monitoring of releases if the system was breached and plans for periodic inspections to ensure the system was intact.
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While the inspectors concluded that the overall control and implementation of the modification was adequate, it was noted that the safety evaluation for the modification should have included additional
details. The evaluation did not specifically address why the replacement of several tornado vents with the ductwork was acceptable.
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inspectors noted that section 9.4.4 of the FSAR states that the TB
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ventilation exhaust is filtered. The modification results in some
exhaust being unfiltered. The evaluation should have addressed this. The i
inspectors noted that the exhaust will still be monitored. The FSAR also states that under normal conditions one TB exhaust fan is running and the
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other will automatically start on loss of running fan.
The modification
removed the standby fan availability to the TB ventilation system. The i
DCR as reviewed did not specifically address this issue. These observations were discussed with on-site personnel involved in
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modifications. The inspectors concluded that while the evaluation should have been more detailed, no unreviewed safety question existed and the
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implementation of the modification was not a safety concern.
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No violations or deviations were identified.
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RHRSW Flow Control Valve Clogging (71707) (37001) (37828) (Unit 1)
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On January 22, 1993, the "A" loop of the Unit 1 RHRSW system was placed in the torus cooling mode of operation in preparation for a routine HPCI surveillance test. The operators noted that with one RHRSW pump running
the pump discharge pressure indicated 450 psig, but that the flowrate j
indicated only 2900 gpm with the RHR heat exchanger discharge valve fully opened.
This flowrate did not meet the TS 3/4.5.c.1.b requirement of 4000 gpm. The operators noted that the pressure drop across the strainer j
in service at the time was less than one psig'and that the pressure drop
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i across the "A" RHR heat exchanger was approximately five psig.
It was
suspected that a blockage was present downstream of the heat exchanger.
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Loop A of RHRSW was declared inoperable and the appropriate seven day LCO l
was entered.
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The operators suspected that blockage had occurred in valve 1 Ell-F068A, i
the RHR heat exchanger discharge flow control valve which controls RHRSW
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pressure in the heat exchanger. This valve has an internal flow
control / cavitation component, and is commonly referred to as a DRAG
valve.
In order to disassemble the valve to investigate the internals, a
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blank flange had to be installed since the discharge lines of the 2 RHRSW loops are connected together. This resulted in declaring both RHRSW loops inoperable for several short periods and entry into the appropriate
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to shutdown LCO. At 2.:45 p.m., on January 22, the LCO was
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entered and the mechanical maintenance group installed the blank flange
and removed the valve internals. The shutdown LC0 was exited at 4:43
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p.m.
One of the inspectors observed the maintenance activities and noted
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that the necessary work was adequately planned and expeditiously carried j
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Upon disassembly of the valve, the flow diffuser portion (a stack of
discs with small flow passages) was discovered clogged with debris such
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as small pieces of wood, seed pods, small stones, plastic, and dead
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insects. The maintenance personnel also disassembled the RHRSW strainer
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which was in service at the time.
No structural failure or abnormal amount of debris were noted. The 1 Ell-F068 flow diffuser was replaced (with a new disc assembly) and the valve was reassembled. On January 23,.
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the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> shutdown LCO was entered due to both l
loops of RHRSW being declared inoperable in order to remove the blank
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flange. The LCO was terminated at 5:45 p.m. the same day.
Subsequent-operation of the system for several minutes indicated that the
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replacement flow diffuser also became clogged. On January 24, 1993, at i
12:05 p.m. EST, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LC0 was again entered to disassemble valve
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IEll-F068A and remove the flow diffuser. The replacement diffuser was
also clogged.
The valve was then reassembled without the diffuser disc
assembly in place (as directed by the vendor manual for the valve) and a special purpose flush procedure was performed. The LC0 was terminated at
3:20 p.m.
Special purpose flush procedure 34SP-012493-CL-1-IS:
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Pipe Flush, was approved and completed at 1:00 a.m. on January 25. The test primarily involved operating the 1A RHRSW for IE minutes at a flowrate of 3700 gpm. After completing the flush, the operators initiated another 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LCO at 2:25 a.m., on January 26, 1993, and the
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flow diffuser assembly was reinstalled in the valve. The LCO was exited at 6:00 a.m. the same day.
Later that day, surveillance procedure 355V-
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E11-004-15:
RHRSW Pump Operability, was satisfactorily completed and the
seven day LCO on the "A" loop of RHRSW was exited. Throughout this
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period, the
"B" loop of RHRSW was operable. The RHRSW valves on Unit 2 i
have not yet been modified.
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The inspectors observed and reviewed various activities over this four
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day period. The observations included the initial installation of the
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blank flange, the disassembly of valve IEll-F068A, the cleaning of the
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clogged diffuser, and the operability testing.
It was noted that.the t
operators tested both loops and obtained similar results.
Loop B with both pumps running indicated a total flow of 7800 gpm and Loop A
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indicated a total of 7700 gpm. On Loop A, with the 1A pump running at a
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flowrate of 4000 gpm, the IE11-F068 valve controller and the local
valving position both indicated the valve was approximately 54 percent
open. Operation of the IC RHRSW pump achieved similar results. The
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licensee initiated actions to ensure that the positioning of the E11-F068
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valves during testing of the RHRSW system will be monitored, possibly f
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providing some advance warning of future clogging problems.
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Because the clogging of the valve had resulted in the unexpected
inoperability of an RHRSW loop and the root cause was not fully i
understood,.the inspectors closely reviewed the issue. DCR 1-90-130
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Installation of DRAG Valves in RHRSW was implemented in October 1991.
i The DCR replaced the IE11-F068 valve with the present Control Components Inc. DRAG valve. This modification was implemented in order to correct a flow erosion problem and other problems associated with the previous type
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of valve.
Indications are that the replacement valve design resulted in i
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improved performance in those areas. The inspectors noted that section
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3-1 of the vendor manual for the lEll-F068 valve states that the disc stack serves as a protective strainer, preventing particles from entering
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the disk stack and possibly causing damage to internal parts. The
upstream RHRSW strainers have holes which are 3/16 inches in diameter l
while the valve disks contain inlet holes which are approximately 0.2
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inches wide and 0.4 inches long. The inspectors noted that long narrow j
shaped objects which can fit through the strainer openings may not
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negotiate the sharp turns in the valve disk passageways and could become trapped.
In turn, smaller debris could then become entrained at the disk
assembly and blocking of flow could occur. One of the inspectors closely l
examined the debris removed from the valve disks.
It appeared that at i
least some of the debris were bigger than the openings on the strainers.
l The inspectors have noted in the past that failures of the RHRSW strainers have occurred.
In several cases, the bottom of the strainer
'
became separated from the side of the strainer. This results in the contents of the strainers being emptied into the system.
Records
indicate that at least some of these failures occurred after the valves
were modified.
l With this information in mind, the inspectors reviewed the 10 CFR 50.59 i
evaluation for the modification. The inspectors were initially concerned
that the modification had, in effect, added " strainers" that were more
'
efficient than the strainers located in the intake.
It was noted that
.
the subject of fouling or clogging was not addressed in the evaluation.
l This was discussed with on-site personnel.
Subsequently, on the
!
afternoon of February 3, the inspectors were verbally informed that the
,
potential for clogging had received attention during the modification
'
process.
On February 4, the inspectors were provided with documentation
which indicated that significant effort had been expended during the
!
review process to address the potential clogging problems.
In fact, the original order for the valves was modified to provide disk assemblies with larger flow passages.
At the close of the inspection period, the inspectors were continuing to
question the licensee regarding the cause of the clogging and the future j
susceptibility of the RHRSW system to this problem. Although, to date, j
no problem with the "B" RHRSW loop has occurred, until the root cause of
'
the clogging is determined, that loop may also be considered as
,
susceptible to the problem. The ability of RHRSW to perform its long-l term cooling functions should be reviewed. On February 4, the inspectors
were informed that the "A" loop was operated for at least 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br /> prior to the clogging. The inspectors noted that the initial replacement disk i
assembly clonged very rapidly. The potential effect of the repetitive l
failures of the strainers and their apparent inability to remove some
.
objects which may clog the valves needs to be examined. While some initial investigative efforts had been initiated, on February 4, the licensee decided to assign a formal Event Review Team to this matter.
The inspectors will continue to monitor the licensees actions. This
)
issue is identified as URI 321/93-02-01:
RHRSW Flow Control Valve
Clogging.
One URI was identified.
j
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_
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._
_
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,
,
I q
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7.
Inspection of Open Items (92700) (90712) (92701)
l The following items were reviewed using licensee reports, inspection,
[
record review, and discussions with licensee personnel, as appropriate:
'
a.
(Closed) URI 321,366/92-22-04:
Design of Switches for Dampers 2T41-l
'
F003A/B and 2T41-F023A/B.
This unresolved item addressed questions regarding the design of the control switches for these 2 secondary
containment isolation dampers. An operator error and lack of l
adequate administrative controls resulted in the switches being
'
incorrectly positioned to the "open" position instead of the
" automatic" position. The dampers did not shut as required on a low l
reactor water level following a scram.
Inspection Report
,
321,366/92-22 discussed the scram and the damper problem in detail.
!
Violation 321,366/92-22-01:
Inoperable Secondary Containment
i
Ventilation System Isolation Dampers addressed the failure to meet
'
the TS reciuirements. During discussions of the safety significance
.l
of the issue it was decided that additional review of the design of
,
the switches should be conducted. The primary question involved
!
whether a design which permitted such a simple inadvertent switch
j
mispositioning to render an ESF component inoperable was permitted.
i
The design did not incorporate a keylock switch or a " spring return"
l
to the automatic position which is usually employed in such a
j
switch,
j
i
The inspectors reviewed numerous documents for applicable regulatory
!
requirements. Section 8.3.1.2 of the FSAR addresses compliance with
l
industry standards and regulatory requirements regarding the
electrical systems. Sections 7.1-.2.1 addresses how IEEE Standard
j
279-1971 vas met regarding the design of the protection systems.
l
The Hatch Unit 2 SER specifically refers to this IEEE Standard.
l
This standard establishes the minimum requirements for the
!
functional performance and reliability of protection systems.
It is
!
applicable to all devices in the circuitry of reactor scram and
l
engineered safeguards systems. The most applicable portion of the
t
standard (to this issue) involves the design, control, and
indications of bypasses. The requirements address bypassing of
+
channels or the protective function.
After close review, it was
i
concluded that the standard does not exclude such switch designs on
i
individual components.
It was noted that the standard does discuss
!
administrative controls on permissible bypass features.
The inspectors reviewed the requirements of NUREG 0737 applicable to
this issue.
IEB 79-08 and the licensee's response to that IEB were
{
reviewed.
Questions 5 and 6 of IEB 79-08 were examined in detail.
Questiov 5 involved overriding of an ESF by operator action, but
addressed deliberate actions, not inadvertent switch manipulations
of individual components.
Question 6 required all safety-related
valve positions, positioning requirements, and controls be reviewed
to ensure that valves remain positioned to ensure proper operation
l
of ESFs. Additionally, it required review of the periodic checks
j
which ensure the valves are returned to their correct position
'
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_
."
.
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l
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following necessary manipulations. The licensee's response focused
,
on maintenance and surveillance activities associated with the
'
valves and did not address control switch positioning.
The
inspectors reviewed TI 2515/19 which verified the licensee's actions
in response to IEB 79-08 and the supplemental responses.
Although
mispositioning of ESF components was discussed, the emphasis was on
,
valve and breaker position, not control switch design.
The NRC
,
stated in an SER dated December 21, 1979, that the Hatch response to
IEB 79-08 was acceptable.
With the assistance of several Region II personnel, additional
effort was expended in attempts to identify regulatory requirements
!
applicable to this issue. The design of the damper switches appears
to unnecessarily permit and even increase the probability of an
!
cperator error which would render the ESF component inoperable. The
inspectors could not locate any specific regulatory guidance which
,
would exclude such a design.
The inspectors concluded that the
licensee must ensure that administrative controls are adequate to
prevent such an occurrence.
Virtually any ESF component could be
rendered inoperable by incorrect positioning of switches and/or
!
breakers. As discussed in Inspection Report 321,366/92-22, in this
case the controls were inadequate.
In the response to Violation
321,366/92-22-01 the licensee stated that a design change will be
l
implemented by May 31, 1993, which will remove the ability to
'
override the automatic isolation function for the dampers when the
switches are in their open position. The licensee is also
performing additional review into this matter.
Based on this
review, URI 321,366/92-22-04 is closed.
Violation 321,366/92-22-01
,
will be used for review of the licensee's additional actions on this
'
issue.
t
b.
(Closed)
LER 321/92-01: Component failure Causes an Unplanned
!
Safety Feature Actuation. This LER addressed a ESF actuation
!
involving the area radiation monitoring system. On January 13,
1992, at 4:48 p.m. ARM ID21-K601D tripped and the main control room
t
environmental control system automatically transferred to the
pressurization mode. The problem was traced to a fluctuating power
supply (lD21-K603A). The power supply was replaced and the set
l
points for each of ten ARMS powered by ID21-K603A were checked and
adjusted as necessary.
It was determined that the fluctuations in
the DC power module was enough to change the set point on 1021-K6010
l
and cause the ARM to trip. No additional problems involving the
,
power supplies have occurred since this incident.
Based on this
review of the licensee's action, this LER is closed.
c.
(Closed) LER 3f6/92-01:
Errors in Plant Drawings and FSAR Result in
l
Missed Technical Specifications Surveillance.
The LER addressed a
i
license identified item involving a spare primary containment
Plant drawing S-28719 incorrectly showed the
penetration as having a welded cover when the actual installation is
'
a bolted cover.
The discovery of this item was the result of a
similar hardware configuration which was discussed in Inspection
- - -
Report 50-321,366/91-18 and LER 366/91-18
321,366/91-34
review of this event.contains a detailed description of thInspection Report
.
NCV 366/91-34-01:
e inspectors
deficiency.and Visual Verification of a Containment PenetrationFailur
penetration was to be Type A tested rather than theTh
, addressed this
test (Local Leak Rate Test).
successfully on January 10, 1992.The licensee performed a Type B LLRTrequir
Unit 2 refueling outage. licensee initiated and installed DCR 9
e fall 1992
pipe and replaced it with a seal welded plateThis design change rem
and the review documented in Inspection Report Based on this review
item is closed.
321 366/91 3-4, this
.
,
d.
(Closed) LER 366/92-02:
Personnel Error Results in an Unplanned
ESF Actuation.
The LER addressed an ESF actuation due to personn
error.
On January 27, 1992,
while instrumentation and co t
technicians were performing surveillance proced
e
n rol
Calibration, a jumper installed as part of the pR
est and
became disengaged, and caused a logic closure sigrocedure wa
affecting a Group 5 PCIS valve.
nal to be generated
personnel involved were counseled.The valve closed as designed.
not an issue in this event. involved were connected by banana c
The
e equipment was
Based on this review, the LER is closedto personnel er
ave occurred.
.
(Closed) LER 321/92-0a:
e.
This LER audressed a failed relay which caused a
Actuation.
,
PCIS valve to shut.
i
The relay was subsequently replaced and
)
successfully tested later that day.
roup 2
the inspectors concluded that no additional actiAfter review of the inciden
t
Based on the replacement of the defective relay and thi
{
ons were necessary.
LER is closed.
s review, the
f.
(Closed) LER 366/92-03:
Inoperable Due to Component failure and Procedural D fiHigh
I
{
March 5,1992, reactor water level transmitter 2821 N0
e ciency.
On
Model 764) developed an oil leak.
{
-
958 (Barton
modification was immediately installed which place
{
(
A temporary
of the affected ADS and HPCI logic circuits and allo
.
j
a trip in each
t
wed the ADS and
I
cccasions the lack of established procedures to acThe inspectors have
l
actions.
removed and the trip channels were declared operablT
complish such
i
this event, on March 9, 1992, the water level i di
n was
e.
Subsequent to
same level transmitter drifted low.
n
cation from this
the drift.
modification to trip the affected logic channel a dThe o
directed by TS LCOs.
y
Followup troubleshooting discovered an
n
responded as
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,
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,
)
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electrical wire from the transmitter to the electro-magnetic
interference filter was touching a portion of the metal filter
i
assembly. The partial grounding of the signal caused a lower than
j
actual water level indication.
Reviews indicated that the wire had
'
been installed inadequately due to a procedure problem. Section
l
4.2.2.9 of procedure 57CP-CAL-103-2S:
ITT Barton Model 764
i
Differential Pressure Transmitter, stipulated the use of heat shrink
!
tubing which was slightly too large for the EMI filter connection.
!
When this tubing was used it resulted in the wire becoming uncovered
l
and it eventually came in contact with the filter assembly. The
procedure has been enhanced to require proper size tubing. The wire
-
and EMI filter were replaced and the transmitter declared operable.
i
Based on the correction of the procedure and replacement of the EMI
filter, this LER is closed.
The performance of routine surveillance
has not disclosed any additional problems with the connections in
other safety related transmitters.
,
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<
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g.
(Closed) LER 321/91-001:
Remete Transmission Line Failure Coupled
l
With Switchyard Failure Causes Reactor Scram. This issues of this
i
LER were reviewed in detail during several previous inspections.
!
Inspection Report 321,366/91-01, contains the initial review of the
j
In July, 1991, during the EDSFI (Report 321,366/91-202) it
t
was identified that the root cause of the switchyard breaker
,
malfunction had not been determined. On August 9, 1991, PCB 179500
!
again failed during a scram.
LER 321/91-13 and Inspection Report
"
321,366/91-21 addressed the scram.
During the inspector's review of
I
LER 321/91-13 it was noted that the PCB failure was not discussed.
l
Revision I to LER 321/91-13 was issued on October 9, 1991, and
,
addressed the cause of the PCB failure in detail. Additionally, the
l
inspectors have noted that controls over switchyard activities and
!
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i
communications involving those activities were strengthened since
!
this event.
!
j
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>
During the January 1991 scram, manual control was taken of the HPCI
-
!
system due to flow oscillations in automatic. This issue was
recently resolved by a dedicated HPCI task force and implementation
i
l
of SIL 480 modifications.
IFI 321,366/92-05-03: Resolution of
d
Degradations Involving Safety Systems, remains open to follow
long-term corrective actions in this area.
During the post scram transient, the RCIC discharge valve (IE51-
F013) failed to close due to a blown fuse in the control circuit.
No conclusive cause other than fuse failure was determined. No
l
other problems involving this valve have occurred since this event.
i
A RB exhaust ventilation damper (IT41-F043B) failed to close due to
a water accumulation over the years which caused an actuator
l
problem. A requirement to perform a complete disassembly / inspection
of these dampers every 6 years was implemented. A new procedure for
testing (including timing) of the dampers was developed.
Some
information indicated that moisture in the IA system may have
i
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,
.
_ - _ _ _ _ - _
_ _ _
_ _ - _ _ _ _ _ _.
'.
. -
i
contributed to this problem. The IA system was substantially
improved since this event.
The inspectors concluded that each significant issue in the event
was satisfactorily addressed. Based on the review discussed in the
i
Inspection Reports listed above, and this review of the overall
!
actions, this LER is closed.
h.
(Closed) LER 366/91-004: Component Failure in Generator Exciter
Causes Turbine Trip And Reactor Scram. This LER addressed a failed
circuit card in the main generator exciter system.
Inspection
Report 321,366/91-04, contains a detailed discussion of the
inspector's review of the event.
Several of the SRVs did not lift
within their TS setpoint band. This is discussed in several LERs
and addressed by IFI 321,366/91-04-03: SRVs Not Lifting at TS
Setpoints, which was recently closed out in Inspection Report
321,366/92-34. The failed circuit card was replaced. Additionally,
during the transient recovery, HPCI was placed in manual control due
l
to flow oscillations in automatic.
This issue has also been
addressed in several LERs and has recently been resolved by a
dedicated HPCI task /orce.
Inspection Report 321,366/92-05 also
discussed this issue.
IFI 321,366/92-05-03: Resolution of
Degradations Involving Safety Systems, remains open to follow
long-term corrective actions in this area. The scram was also
discussed in a meeting with Region II management on March 14, 1991.
The failed card was tested by GE, but no additional information was
obtained.
Based on the reviews discussed in Inspection Reports
321,366/91-04, 92-34 and 92-05, and this review of the licensee's
actions, this LER is closed.
i.
(Closed) LER 366/91-07: Unknown Inadequacy in Jumper Connection
Results in Scram During Surveillance in Cold Shutdown. This LER
addressed an RPS jumper problem which caused a full scram signal
during testing of an SRM functional test. Although the
investigation of the event did not conclusively determine the
specific problem with the jumper, corrective actions to prevent
l
reoccurrence were completed. The inspectors reviewed some of the
I
data collected, and concluded the investigation thoroughly examined
the jumper problem.
The use of a different type connection plug or-
sliding links for the connections was reviewed in detail.
It was
concluded that the use of other connection methods was not
appropriate. The inspectors noted that the testing procedure was
revised on May 22, 1991, such that the use of only one jumper
(versus four) was required. No other ESF actuations involving
jumper equipment problems were noted recently (LER 366/92-02
addressed a personnel error involving jumpers during testing).
Based on this review of the licensee's actions, this LER is closed.
J.
(Closed) LER 321/91-29:
Malfunctioning MOV Results in Group I
Isolation During Plant Shutdown.
This LER addressed a problein with
throttling main steamline drain valve IB21-F020 during attempts to
limit cooldown rate.
The main steam line drain had to be isolated
_-___-
___- _____-__-__-__-_____ - __
- - _ _ -
_
__
.
and the resulting loss of condenser vacuum caused a Group I
isolation.
As discussed in Inspection Report 321,366/91-34, this
event was reviewed previously by the inspectors.
The inspectors
identified that the most probable cause of the valve problem was
personnel error that resulted in an incorrectly set torque switch.
A revision to the applicable valve maintenance procedures was
completed to provide better guidance to prevent future errors.
After additional review, Revision 1 to the LER was issued on March
30, 1992; this revision addressed the personnel error and discussed
appropriate corrective actions. Additionally, the torque switch
settings for such valves are now promulgated in procedure 53GM-MNT-
001-0S:
Limitorque Torque Switch Settings for Non GL 89-10 MOVs.
No other similar problems involving incorrectly set torque switches
have been noted by the inspectors.
Based on the review discussed in
Inspection Report 321,366/91-34 and this review of the licensee's
actions, this LER is closed,
k.
(Closed) IFI 321,366/92-21 03:
Improperly Controlled CR Panel
Electrical Outlets. This item addressed the identification of
several improperly installed outlets on CR panels.
The inspectors
primary concern involved wiring in safety related CR panels which
was not as depicted on drawings. Use of the improperly installed
outlets could cause the loss of important indications.
Additionally, it appeared that Class IE power circuits might have
been effected by some of the outlets. The licensee investigated all
electrical outlets in CR panels. A total of 25 panels were
involved. Only two of the outlets (on panels 2Hil-P601 and 2N62-
P600) were found to be connected to Class IE equipment and those
outlets were removed in November 1992. These specific outlets are
discussed in Inspection Report 321,366/92-21. ABNs were issued
where necessary to include outlets on drawings.
Additionally,
appropriate labels were placed on the outlets. The inspectors
observed several of these corrective actions as they were performed
and noted the labeling of the outlets.
The inspectors concluded the
licensee's actions were adequate to ensure no safety problems would
occur involving the outlets.
Based on this review, this item is
closed.
1.
(Closed) LER 321/92-06: High Pressure Coolant Injection Inoperable
Due to a Less Than Adequate Procedure. This LER addressed a
condition involving the HPCI system which occurred during testing.
On February 26, 1992, upon manual initiation of the system, it
reached rated conditions and then became unstable, with flow
oscillating from 3000 to 5000 gpm and the discharge pressure
oscillating from 600 to 1500 psig.
The problem was attributed to
the fact that procedure 57CP-CAL-044-lS did not specifically address
tuning the system for optional stability. The licensee checked the
Unit 2 HPCI system and the Unit 1 and Unit 2 RCIC systems and
decided to tune the controls for all four systems.
The licensee
'
changed the flow control settings on the self synchronizing flow
control unit, 1E41-K615, to provide more stability. Additional
changes to both units HPCI and RCIC procedures were made to achieve
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optional stability in these four systems. As discussed in
Inspection Report 321,366/92-05, a task force was established to
address the specific HPCI issues.
This resulted in significantly
increased performance levels of the HPCI systems. Based on these
improvements, this LER is closed.
IFI 321,366/92-05-03:
Resolution
i
'
of Degradations Involving Safety Related Systems, remains open to
follow overall corrective actions in this area.
m.
(Closed) P2191-05:
Potential 10 CFR 21 Condition on SMB 00 Torque
Switch Roll Pin failures.
This issue involved the potential failure
of roll pins on certain MOV actuators equipped with heavy spring
!
packs. Apparently the pins may fail after as few as 11 manual
declutching operations from a torque seated condition. A total of
i
119 valves are potentially effected at Hatch.
Hatch does not often
i
manually declutch a valve after it is torque seated.
Some problems
with these pins have been noted, but no valve failures.
A memo was
!
issued and training conducted to inform personnel of the issue and
further reduce the occasions of manual declutching from the seated
position. Additionally, replacement roll pins, ethich are rated for
i
as many as 600 declutching cycles, were recently obtained. The
l
affected valves, which are classified as either GL 89-10 valves or
l
environmentally qualified valves, are scheduled to have the roll
!
pins replaced during the next refueling outage. The pins on other
valves will be replaced as maintenance is performed on those valves.
.
The responsible on-site engineer _ verified that work requests
,
requiring the roll pin replacement were initiated. This item is
closed.
.l
!
8.
Exit Interview
j
The inspection scope and findings were summarized on February 5, 1993
j
with those persons indicated in paragraph I above.
The inspectors
j
described the areas inspected and discussed in detail the inspection
'
findings. The licensee did not identify as proprietary any of the
j
material provided to or reviewed by the inspectors during this
inspection.
i
Item Number
Status
Description and Reference
l
t
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321/93-02-01
Open
URI - RHRSW Flow Control Valve
Clogging, paragraph 6.
]
321/93-02-02
Open
IFI - Annunciator Control
Deficiencies, paragraph 2b.
9.
Acronyms and Abbreviations
ABN - As Built Notice
- Alternating Current
ADS - Automatic Depressurization System
A/E - Architect Engineer
AGM-P0- Assistant General Manager - Plant Operations
i
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l
.
'
.
AGM-PS-Assistant General Manager - Plant Support
BWR - Boiling Water Reactor
CFR - Code of Federal Regulations
CR
- Control Room
CS~
CST - Condensate Storage Tank
- Deficiency Card
DCR - Design Change Request
ECCS - Emergency Core Cooling System
EDG - Emergency Diesel Generator
EDSFI-Electrical Distribution System Functional Inspection
- Electro - Magnetic Interference
ERT - Event Review Team
ESF -
Engineered Safety Feature
EST - Eastern Standard Time
FSAR - Final Safety Analysis Report
FT&C - Functional Test and Calibration
- General Electric Company
GPM - Gallons per Minute
.
- Health Physics
HPCI - High Pressure Coolant Injection System
HVAC - Heating, Ventilation and Air Conditioning
'i
1&C -
Instrumentation and Controls
IFI
-
Inspector Followup Item
.
'
IEB -
Inspection and Enforcement Bulletin
IN
-
Information Notice
IRM -
1CO -
Limiting Condition for Operation
i
LER - Licensee Event Report
,
LLRT - Local Leakrate Test
i
LOCA - Loss of Coolant Accident
!
'
LPCI - Low Pressure Coolant Injection
LPRM - Local Power Range Monitor
MFP - Main Feed Pump
MFWPT-Main Feedwater Pump Turbine
!
- Motor Generator
MOV - Motor Operated Valve
,
MSIV - Main Steam Isolation Valve
l
MWE - Megawatts Electric
MWO - Maintenance Work Order
NCV - Non-cited Violation
l
NRC - Nuclear Regulatory Commission
!
NRR - Office of Nuclear Reactor Regulation
NSAC - Nuclear Safety and Compliance
PCB - Power Circuit Breaker
PCIS - Primary Containment Isolation System
PE0 - Plant Equipment Operator
- Preventive Maintenance
PRB - Plav Review Board
PSIG - Pounds Per Square Inch Gauge
PSW - Plant Service Water System
- Reactor Building
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RCIC - Reactor Core Isolation Cooling System
RFP - Reactor Feed Pump
RFPT - Reactor Feed Pump Turbine
RHR - Residual Heat Removal System
RHRSW-Residual Heat Removal Service Water System
RPS - Reactor Protection System
RTP - Rated Thermal Power
RWCU - Reactor Water Cleanup System
Rx
- Reactor
SCS - Southern Company Services
SER - Safety Evaluation Report
S/F - Single Failure
SFP - Spent Fuel Pool
SIL - Service Information Letter
SNC - Southern Nuclear Company
SOR - Significant Occurrence Report
SOS - Superintendent of Shift (Operations)
- Suppression Pool
SRM - Source Range Monitor
- Shift Supervisor
- Turbine Building
TI
- Temporary Inspection
TS
- Technical Specifications
- Unresolved Item
,
I
!
l
,
.
,
_
.