IR 05000321/1982009

IE Insp Repts 50-321/82-09 & 50-366/82-09 on 820121-0301. Noncompliance Noted:Failure to Isolate & Declare Instrument Channel W/Nonconservative Setpoint Inoperable & Failure to Follow QC Procedures

ML20058G695
Person / Time
Site:	Hatch
Issue date:	05/17/1982
From:	Brownlee V, Rogers R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20058G617	List: IR 05000321/1982009 ML20058G611 ML20058G620 ML20058G630 ML20058G645 ML20058G665 ML20058G679
References
50-321-82-09, 50-321-82-9, 50-366-82-09, 50-366-82-9, NUDOCS 8208030397
Download: ML20058G695 (7)

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1. 'o UNITED STATES g

g NUCLEAR REGULATORY COMMISSION

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t; e REGION 11 e # 101 MARIETTA ST., N.W., SulTE 3100 ATLANTA, GEORGIA 30303

Report Nos. 50-321/82-09 and 50-366/82-09 Licensee: Georgia Power Company P. O. Box 4545 Atlanta, GA 30302

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Facility Name: Hatch 1 and 2 Docket Nos. 50-321 and 50-366 License Nos. DPR-57 and NPF-5 Inspection at Hatch site near Baxley, Georgia and Licensee requested management meeting at NRC Re ion II O fice, Atlanta, Georgia Inspector: /g/NU4W&- (// //M R6 ogers y ,7 'Date Signed Approved by:  !. '

t V. L. Bfownlee, Section Chief, Division of [j]Sgned ate Resid'ent and Reactor Project Inspection SUMMARY Inspection on January 21,1982 - March 1,1982

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Areas Inspected This inspection involved 180 inspector-hours on site in the areas of Technical Specification compliance, housekeeping, operator performance, overall plant operations, quality assurance practices, station and corporate management practices, corrective and preventive maintenance activities, site security procedures, radiation control. activities, surveillance activities, a refueling activities and twenty hours during the management meeting on April 2,198 Results Of the 11 areas inspected, no violations or deviations were identified in 8 areas; four violations were identified in three areas (Failure to follow procedures - three examples, paragraph 6; Failure to isolate and declare inoperable an instrument channel with a non conservative setpoint, paragraph 8; Failure to report within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, paragraph 8; Failure to follow procedure - QC hold tags, paragraph 5) and one deviation was identified in one area (control rod ,

withdrawal speeds paragraph 6)

8208030397 820723 PDR ADOCK 05000321 G PDR

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DETAILS Persons Contacted Licensee Employees

• • J. T. Beckham, Vice President and General Manager, Nuclear Generation

• • H. C. Nix, Plant Manger

• • R. W. Staffa, Manager of Quality Assurance

• • E. F. Cobb, Manager of Nuclear Planning and Control

• T. Greene, Assistant Plant Manager

• T. Jones, Assistant Plant Manager

• S. Baxley, Superintendent of Operations R. Nix, Superintendent of Maintenance

• C. Coggins, Superintendent of Engineering Services

• W. Rogers, Health Physicist

• C. Belflower, QA Site Supervisor Other licensee employees contacted included technicians, operators, mechanics, security force members, and office personne * Attended site exit interviews

• • Attended the management meeting on April 2,1982 Exit Interviews

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! The inspection scope and findings were summarized on February 11,19, and 26, 1982, with those persons indicated in paragraph 1 abov ' Licensee Action on Previous Inspection Findings

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Not inspecte . Unresolved Items Unresolved items were not identified during this inspection.

j Plant Tours (Units 1 and 2)

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The inspector conducted plant tours periodically during the inspection

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interval to verify that monitoring equipment was recording as required, equipment was properly tagged, operations personnel were aware of plant conditions, and plant housekeeping efforts were adequate. The inspector also determined that appropriate radiation controls were properly estab-i lished, critical clean areas were being controlled in accordance with procedures, excess equipment or material is stored properly and combustible i material and debris were disposed of expeditiousl During tours the inspector looked for the existence of unusual fluid leaks, piping vibra-tions, pipe hanger and seismic restraint settings, various valve and breaker positions, equipment caution and danger tags, component positions, adequacy of fire fighting equipment, and instrument calibration dates. Some tours were conducted on backshif t _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

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On January 21, 1982, the inspector noted on a tour of the warehouse that approximately one hundred QC parts were not properly tagged with QC Hold tags in accordance with HNP-822, Materials Inspection Request. The tags had been filled out for the Johnson pump parts involved, but had not been affixed as required by step C.1.a. of the procedure. This is a violation (321 and 366/82-09-01). Warehouse personnel promptly placed the tags on the affected part . Refueling Activitie, The inspector examined the approved procedures for the reciept, inspection and storage of new fuel. There were no violations or deviations identifie The following new fuel related procedures were reviewed for technical adequacy; HNP-1-9102 and HNP-2-9102, Receiving New Fuel HNP-1-9104 and HNP-2-914, New Fuel Inspection HNP-1-9105 and HNP-2-9105, Storage of New Fuel The procedures reviewed appeared adequat The inspector examiend the HNP-1-9104 data package completed October 10, 198 The inspector verified that each new fuel bundle identified on th7 Site Inspection Master Check Off List was inspected by licensee personnel certified to G.E. P/FQP 8. The inspector reviewed several approved refueling related procedures. The inspector verified that a NRC approved technical specification change describing the revised core physics parameters for the present Unit 1 and Unit 2 cores were issued prior to their respective cycle start-ups. There were no violations or deviations identifie The following refueling related procedures were reviewed for technical adequac HNP-1-9100 and HNP-2-9100, Criticality Rules HNP-1-9152 and HNP-2-9152, Use of Fuel Preparation Machine HNP-1-9205 and HNP-2-9205, Use of Underwater Camera HNP-1-9208 and HNP-2-9208, LPRM Operational Status HNP-1-9209 and HNP-2-9209, Core Loading Verification HNP-1-9301 and HNP-2-9301, SRM&FLC Core Monitoring Check HNP-1-9302 and HNP-2-9302, Fuel Movement Operation HNP-1-9401 and HNP-2-9401, Shutdown Margin Determination The procedures reviewed appeared adequat As a result of the Oyster Creek misorientation in January,1980, NRC recom-mendations lead to a revised Oyster Creek core verification procedur HNP-1-9209 and HNP-2-9209, Core Loading Verification did not meet the new guidance and revised procedural requirements in that they did not provide

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for a final review of the core verification video tapes by Quality Assurance personnel. Discussion with the licensee indicates that this procedural requirement will be incorporated into HNP-1-9209 and HNP-2-920 The inspector verified that the licensee was maintaining a LPRM Status Log per HNP-1-9208 and HNP-2-920 The inspector examined HNP-1-9401 and HNP-2-9401 data packages completed

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April 27, 1981 and February 19, 1981, respectively. The inspector verified that the determined shutdown margins were in agreement with the technical j specification limit The inspector reviewed HNP-1-9404 CRD Timing, data packages completed on l April 25, June 4 and June 14, 1981. The CRD timing data package completed April 4,1981 indicated that 68 of 137 CRD's failed to meet the acceptance l

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criteria of 40-60 seconds for CRD withdraw time and 40-60 seconds for CRD insert time. Subsequent corrective actions and retesting completed June 4, 1981 indicated that nine CRD's remained outside of the acceptance criteria.

j Another retest completed June 14, 1981 resulted in eight CRD's that were i unable to meet the withdraw time acceptance criterion. Each withdraw time was measured to be less than the 40-60 second acceptance ban l The June 14 retest was the final CRD timing test performed during the

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outage. The unit was restarted with the CRD withdraw times at core loca-tions 10-43, 26-11, 38-43, 30-47, 42-27, 34-39, 30-39 and 46-11 less than the acceptance criterio The FSAR, section 3.4.5.4.2 states that the withdrawal speed control valve is set to give the control rod a shim withdrawal speed of 3 inches per

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second. Assuming 144 inches of rod travel, the nominal full core withdrawal time is 48 seconds. Unit operation with CRD's outside of the withdrawal l time acceptance band is a deviation (321/82-09-03).

The inspector also noted that the reactor engineer should have submitted a

nonconformance report in accordance with HNP-801, Nonconformances, Step F.1.

which requires a report when nonconforming activities are noted on safety related system Submittal of such a report is necessary for the plant safety committee to be aware of potential safety issues. This is part of a violation (321 and 366/82-09-02).

! On February 2,1982, the inspector attempted to retrieve the CRD timing data for the Unit I spring refueling outage from plant records. The data package obtained was dated complete on June 14, 1981 and contained the results of only 51 of the required 137 CRD's tested. Further inquiry revealed that the

June 14 data package was for a CRD timing retest and the original data i

package dated April 4, 1981 could not be located in plant records. On I February 4, 1982, the April 4 CRD timing data package along with a June 6,

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1981 retest was located in the Reactor Engineers office. The April 4 test

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and June 6 retest had never been forwarded to plant records upon their completion in accordance with Plant Procedure HNP-820, Plant Records Manage-ment, Paragraph E.2. This is part of a violation (321 and 366/82-09-02).

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4 Technical Specification Compliance (Units 1 and 2)

During this reporting interval, the inspector verified compliance with selected limiting conditions for operations (LC0's) and results of selected surveillance test These verifications were accomplished by direct observations of monitoring instrumentation, valve positions, switch positions, and review of completed logs and records. The licensee's compliance with selected LCO action statements were reviewed on selected occurrence as they happene . RCIC High Steam Flow Isolation Setpoint (Unit 2)

On February 9,1982, the licensee submitted a LER (50-366/1982-5) which detailed the discovery by a plant engineer of a design change (DCR 79-376)

to reset an unconservative high steam flow isolation signal on the reactor core isolation cooling (RCIC) steam supply inboard valve. The discovery was made on January 11, 1982 and the instrument was reset that day. The design change had been outstanding for approximately two and one-half years and had apparently been " forgotten" by the licensee. The setpoint changed from +133 inches of water to +111 inches of water. This lower setpoint corresponds to the 300% steam flow isolation setpoint described in Technical Specification table 3.3.2-1 paragraph 5.a., Table 3.3.2-2 paragraph 5.a. and discussed in Technical Specification Paragraph 3. This Technical Specification requires that the RCIC system be isolated and declared inoperable if the 300% limit cannot be met. Contrary to Technical Specification requirements, the licensee failed to recognize the significance of this item in 1979, report it to the NRC in accordance with Technical Specification 6.9.1. and reset the RCIC instrument at the time. Through serious deficiencies in management controls systems, this condition presisted for over 2 years and when it was discovered, it was again not reported to the NRC per 6.9.1. (or 6.9.1.B.f.) which requires a prompt report (within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />). The failure to comply with technical specifications limits for an extended period of time is a violation (366/82-09-04). The failure to properly report this occurrence on both occasions is a violation (366/82-09-03). The safety significance of the nonconservative setpoint was that on a steam line break in the RCIC system, the inboard valve would not have shut until approximately 360% steam flo The redundant outboard valve should have closed at 300%.

Meanwhile, an instrument technician again performed the calibration check on the RCIC steam flow instrument on January 28, 1982. This calibration was performed per HNP-2-3410, RCIC Steam Line Delta P Instrument Functional Test and Calibration. The Procedure, HNP-2-3410, had not been revised from the January 11, 1982 occurrence. The instrument technician, finding the instru-ment set at +111 inches, set the instrument back to +133 inches (the previous incorrect valve) in accordance with the procedure. The procedure change was finally approved on February 4, 1982. When HNP-2-3410 was again performed on February 8, 1982, the setpoint was set back to +111 inches and another thirty day LER generated (50-366/1982-16 dated March 10,1982). The instrument was set with the incorrect setpoint for a total of 10 days in this inciden . _ - - _ - -_ . . . -_ . - - _. _

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When the second LER on this instrument was reviewed by the on-site safety committee, it was recognized as a prompt reportable event and the NRC was notified within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (LER 50-366/82-10 dated March 18, 1982). The i setting of the RCIC steam flow D/P cell to a nonconservative value on January 28, 1982 for a 10 day interval is part of a violation (366/82-i 09-04).

, When the inspector reviewed the revised HNP-1/2-3410 procedures for both ,

units while following up on the above event, it became apparent that anomalies existed which could confuse a technician. In HNP-2-3410 which was formally revised on February 4, 1982 as a result of the January 11, 1982 disclosures, the inspector found that Step F.2.o. required the instrument to be set at s + 142 5", Step F.3.a required the instrument to be set at $126"

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with an expected value of 120 5". A review of the Unit 1 procedure HNP-1-3410 showed setpoint tolerances of 3 inches or 4 inches depending on

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where one looke l According to the licensee, the same Barton guages are used in the same j

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applications under the same environmental conditions on both plants. The tolerance dif ferences could not be justified by the licensee's technical staf The failure to properly maintain this procedure by allowing an incorrect setpoint to exist is part of a violation (321 and 366/82-09-02)

procedure was approved in response to the precursor January 11, 1982 discovery that the setpoint in question was in error and, in fact, needed correcting throughout the procedur A meeting was held in Region II on April 2,1982 between Georgia Power Company (GPC) and NRC. The meeting was requested by GPC to review the conditions and circumstances surrounding the erroneous RCIC inboard steam line isolation valve problem. The licensee concluded that the mishandling of DCR 79-376 in 1979 was the direct result of the loose control system for handling engineering documents in place at that time. The licensee believes that the tighter controis implemented to correct the violations identified in NRC Report 81-28 will eliminate this type of problem. The resident i

inspector agrees that some improvement in the control of safety-related information provided by internal and external sources has occurre . Plant Operations Review (Units 1 and 2)

The inspector periodically during the inspection interval reviewed shift

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logs and operations records, including data sheets, instrument traces, and records of equipment malfunctions. This review included control room logs and auxiliary logs, operating orders, standing orders, jumper logs and

equipment tagout record The inspector routinely observed operator alertness and demeanor during plant tours. During normal events, operator performance and response actions were observed and evaluated. The inspector conducted random off-hours inspections during the reporting interval to

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assure that operatoins and security remained at an acceptable level. Shift turnovers were observed to verify that they were conducted in accordance with approved licensee procedures.

Within the areas inspected, no violations or deviations were identified.

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10. Physical Protection (Units 1 and 2)

The inspector verified by observation and interviews during the reporting interval that measures taken to assure the physical protection of the facility met current requirements. Areas inspected included the organiza-tion of the security force, the establishment and maintenance of gates, door and isolation zones, in the proper condition, that access control and badging was proper, and procedures were followe Within the areas inspected, no violations or deviations were identifie .

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