IR 05000416/1986032

Insp Rept 50-416/86-32 on 860908-1017.Violations Noted: Three Instances of Inadequate or Unauthorized Work Instructions & Failure to Make 4 H Rept to NRC

ML20213G228
Person / Time
Site:	Grand Gulf
Issue date:	11/04/1986
From:	Butcher R, Dance H, Will Smith NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20213G208	List: ML20213G206 ML20213G214 ML20213G228
References
50-416-86-32, NUDOCS 8611170393
Download: ML20213G228 (16)

Text

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p3 Eto UNITED STATES

/ oq'o NUCLEAR REGULATORY COMMISSION

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Report No.: 50-416/86-32 Licensee: Mississippi Power and Light Company Jackson, MS 39205 Docket No.: 50-416 License No.: NPF-29 Facility Name: Grand Gulf Nuclear Station Inspection Conducted: eptember - October 17, 1986 Inspectors: C M ri/ // f R C. Butc)eb, Senidr bsident Inspector 15at6 Si ed Mu ht/

W. F. Smith) Residerft Inspector A' k Da'te / Signed Accompanying Inspectors: (September 8-11,1986)

8. Wilson f- S D. Stadler

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Approved by: - e (12 A _ /t H. C. Dance, Sektion Chief Dite' Signed

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Division of Reactor' Projects

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SUMMARY Scope: This routine inspection was conducted by resident and regional based inspectors at the site in the areas of Licensee Action on Previous Enforcement Matters, Operational Safety Verification, Maintenance Observation, Surveillance Observation, Reportable Occurrences,' Operating Reactor Events, Inspector Followup and Unresolved Items, Design, Design Changes and Modifications, Refueling Activities, and Trainin Results: Two violations were identified. One violation had three examples of inadequate or unauthorized work instructions and one violation for failure to make a four hour report to the NR DR ADOCK 05000416 PDR

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REPORT DETAILS Licensee Employees Contacted

• J. E. Cross, GGNS Site Director

• C. R. Hutchinson, GGNS General Manager R. F. Rogers, Manager, Unit 1 Projects A. S. McCurdy, Manager, Plant Operations

• J. D. Bailey, Compliance Coordinator M. J. Wright, Manager, Plant Support

• L. F. Daughtery, Compliance Superintendent D. G. Cupstid, Start-up Supervisor R. H. McAnuity, Electrical Superintendent

• R. V. Mocmaw, Manager, Plant Maintenance W. P. Harris, Compliance Coordinator J. L. Robertson, Licensing Superintendent L. G. Temple, I & C Superintendent J. H. Mueller, Mechanical Superintendent L. B. Moulder, Operations Superintendent

• J. V. Parrish, Chemistry / Radiation Control Superintendent

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J. R. Elms, Special Projects Coordinator

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• J. W. Yelverton, Technical Assistant, Operations Other licensee employees contacted included technicians, operators, security force members, and office personne * Attended exit interview Exit Interview i

The inspection scope and findings were summarized on October 17, 1986, with

those persons indicated in paragraph 1 above. The licensee did not identify

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as proprietary any of the materials provided to or reviewed by the inspectors during this inspection, except for the loose parts analysis submitted by General Electric referenced in paragraph 13. The licensee had no comment on the following inspection finding /86-32-01, Unresolved Ite Scram discharge volume vent valve air supply isolation valve not on drawings or system operating instructio (Paragraph 5)

416/86-32-02, Inspector Followup Item (IFI). Step 5.1.2.c.(4) of SSW system operating instruction 04-1-01-P41-1 should be deleted to prevent an inappropriate operatio (Paragraph 5)

416/86-33-03, IF Identify cause of inverter 1Y87 being de-energized when opening DC breaker 72-11A0 (Paragraph 9)

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416/86-32-04, Violation. Two examples of inadvertent actuation of ESF due to inadequate work instructions, (Paragraph 9); one example of unauthorized modification of refueling platform main hoist (Para-graph 13).

416/86-32-05, Unresolved Item. Seismic qualification of PSW/SSW cooler nozzle (Paragraph 9)

416/86-32-06, IFI . DCP 81/5003: Isolation of the Division I remote shutdown panel from the control room. (Paragraph 11)

416/86-32-07, IF DCP 85/3100: Installation of alternate shutdown emergency lighting additions and modification (Paragraph 11)

416/86-32-08, IF DCP 85/4061: Provide heating and cooling to the remote shutdown panel room (Paragraph 11)

416/86-32-09, IF DCP 85/3122: Modify remote shutdown panels to human factors design review criteria (Paragraph 11)

416/86-32-10, IF DCP 82/0543: Installation of higher capacity turbocharger on Division 3 D (Paragraph 11)

416/86-32-11, IF DCP 84/4080-1: SSW Basin A pipe support modifi-cations as a result of soil structure interactio (Paragraph 11)

416/86-32-12, IFI. DCP 86/3008: Add keylock switch on remote shutdown panels for LPCI valves (E12-F042A and B). (Paragraph 11)

416/86-32-13, IFI. DCP 84/3029: Incorporate logic in Division 1 and 2 DG protective trips to trip only on engine overspeed and generator differential current under accident conditions. (Paragraph 12)

416/86-32-14, IF DCP 81/5007: Add _ redundant vent and drain valves to the scram discharge volume. (Paragraph 12)

416/86-32-15, Violatio Failure to report an ESF actuation within four hours, (Paragraph 9). The licensee did not consider the Standby Service Water actuation to be an ESF actuation. The licensee will evaluate this positio /86-32-16, IF Possible loss of a stainless steel pin in the reactor core during refueling operations. (Paragraph 13)

416/86-32-17, Unresolved Ite Environmental qualification of Limitorque motor operators. (Paragraph 10)

416/86-32-18, IF Closure of CAR 2151 with incomplete corrective action (Paragraph 14)

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3 Licensee Action on Previous Enforcement Matters (92702)

(Closed) Violation 416/86-11-02. Control Room Emergency Filtration System (CREFS) was not operated in the isolation mode with chlorine detectors inoperable. The licensee has revised System Operating Instruction 04-S-01-Z51-1 to require certain actions be taken when operating in the fresh air mode. Those actions require monitoring the fresh air intake when the unit is operated in the fresh air mode and require stationing personnel at the air intake or control building entrance for early detection of abnormal condition (Closed) Violation 416/86-11-03. The first example of this violation was withdrawn by NRC letter dated July 17, 1986. Regarding the Operations Shift Supervisor authorizing technicians to reset trip logic without an approved work instruction, the licensee has taken disciplinary action and issued a memorandum to all GGNS employees discussing their responsibilities during plant operatio (Closed) Violation 416/86-21-02. In the first example, Standby Liquid Control (SLC) pump discharge pressure instrument vent isolation valve C41-FX001 was found shut in violation of the SLC System Operating Procedure.

In the second example, Standby Diesel Generator (SDG) 12 was inadvertently started when an operator pushed the start pushbutton in lieu of the maintenance mode select pushbutton as required by the surveillance procedure. The licensee conducted a valve lineup of the SLC system and issued standing orders (No. 86-0010) to require dacumented controls over instrument root valves. Plastic covers were installed on the SDG start pushbuttons on the control room panel to clearly distinguish them from the maintenance mode select pushbutton . Unresolved Items *

Three new unresolved items identified during this inspection are discussed in paragraphs 5, 9 and 10.

' Operational Safety Verification (71707)

The inspectors kept themselves informed on a daily basis of the overall plant status and any significant safety matters related to plant operation Daily discussions were held with plant management and various members of the plant operating staf *An Unresolved Item is a matter about which more information is required to determine whether it is acceptable or may involve a violation or deviatio ,

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The inspectors made frequent visits to the control room such that it was visited at least daily when an inspector was onsite. Observations included instrument readings, setpoints and recordings, status of operating systems, tags and clearances on equipment controls and switches, annunciator alarms, adherence to limiting conditions for operation, temporary alterations in effect, daily journals and data sheet entries, control room manning, and access controls. This inspection activity included numerous informal discussions with operators and their supervisor Weekly, when the inspectors were onsite, selected Engineered Safety Feature (ESF) systems were confirmed operable. The confirmation is made by verifying the following: Accessible valve flow path alignment, power supply breaker and fuse status, major component leakage, lubrication, cooling and general condition, and instrumentatio General plant tours were conducted on at least a biweekly basis. Portions of the control building, turbine building, auxiliary building and outside areas were visited. Observations included safety related tagout verifi-cations, shift turnover, sampling program, housekeeping and general plant conditions, fire protection equipment, control of activities in progress, radiation protection controls, physical security, problem identification systems, and containment isolatio The following comments were noted:

On October 6, 1986, while reviewing the control room operator's log the inspectors noted that a problem was experienced while tagging out the Scram Discharge Volume (SDV) for a design modification to the vent and drain air-operated valves. The vent (C11-F010A) failed to close when the air was secured because a 1/2-inch manual valve directly upstream of the F010A air operator was tagged shut first, thus locking air pressure on the operator preventing the valve from closing. While following up, the inspectors found that the 1/2-inch valve did not have a number, nor was it identified in control rod drive hydraulic system operating instruction 04-1-01-C11-1, Revision 23, nor was it identified on P&ID M-1081 The licensee was requested to explain how this valve is controlled, due to its impact on the operability of the SDV, and if this condition exists on other safety related air-operated valves. This shall be Unresolved Item 416/86-32-0 On October 9.1986, while reviewing the status of the siphon line between

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Stanoby Service Water (SSW) basins A and B, the inspectors noted that a step in SSW System Operating Instruction 04-1-01-P41-1, Revision 22, can lead the operator into accepting an abnormal condition that may be indicative of SSW siphon inoperabilit Section 5.1.2.c of the procedure prescribes the venting of the siphon to ensure operability following a low level condition in the SSW basin. The procedure requires the operator to verify that the water level in the vent line is the same as both basins, and then to add water to the line if required. If the vent line water fails to seek and achieve the same level as the basins, this could be indicative of a problem

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such as siphon blockage. When the siphon is operative, there will normally not be a need to add water to the vent line while the vent valve F304 is ope Procedure step 5.1.2.c.(4), should be modified to require an evaluation if addition of water is require This was discussed with the licensee, and shall be tracked for correction as Inspector Followup Item 416/86-32-0 No violations or deviations were identifie . Maintenance Observation (62703)

During the report period, the inspectors observed portions of the main-tenance activities listed below. The observations included a review of the work documents for adequacy, adherence to procedure, proper tagouts, adherence to technical specifications, radiological controls, observation of all or part of the actual work and/or retesting in progress, specified retest requirements, and adherence to the appropriate quality control MWO EL1489, SSW System Train A fill tank outlet valve inspection MWO M65769, Replacement of grapple control air hoses on refueling platform main hoist MWO I66235, Replace level switch on Hydraulic Control Units 36-09 and 48-09 MWO ME0031, Overhaul Bettis actuator on valve M41-F007 No violations or deviations were identifie . Surveillance Observation (61726)

The inspectors observed the performance of portions of the surveillances listed belo The observation included a review of the procedure for technical adequacy, conformance to technical specifications, verification of test instrument calibration, observation of all or part of the actual surveillances, removal from service and return to service of the system or components affected, and review of the data for acceptability based upon the acceptance criteri ! 06-1C-1C11-R-0003, Rev. 23, Scram Hydraulic Control Unit Calibration 06-ME-1M61-V-0001, Rev. 28, Local Leak Rate Test of Containment Isolation Valve M71-F595 06-IC-1E12-M-0001, Rev. 23, Low Pressure Core Injection System Discharge I

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Line High/ Low Pressure Functional Test 06-0P-1P75-M-0001, Rev. 29, Standby Diesel Generator 11 Functional Test No violations or deviations were identifie .

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6 Reportable Occurrences (90712 & 92700)

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The below listed event reports were reviewed to determine if the information provided met the NRC reporting requirements. The determination included adequacy of event description and corrective action taken or planned, existence of potential generic problems and the relative safety significance of each event. Additional inplant reviews and discussions with plant personnel as appropriate were conducted for the reports indicated by an asterisk. The event reports were reviewed using the guidance of the general policy and procedure for NRC enforcement action The following License Event Reports (LERs) are close LER N Event Date Event

• 85-037 June 20, 1985 Control room remote indication for fire detector inoperable

• 86-014 April 11, 1986 Surveillance retest performed late

• 86-021 June 7, 1986 Unplanned RCIC isolation due to failed calibration unit power supply

• 86-028 August 25, 1986 Inadvertent load reject relay actuation causes automatic scram The event of LER 86-028 was discussed in inspection report 416/86-26.

No violations or deviations were identifie . Operating Reactor Events (93702)

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The inspectors reviewed activities associated with the below listed reactor event The review included determination of cause, safety significance, performance of personnel and systems, and corrective action. The inspectors examined instrument recordings, computer printouts, operations journal entries, and scram reports. The inspectors had discussions with operations, maintenance ar.d engineering support personnel as appropriat On September 23,1986, at 4:41 a.m. , the containment and drywell ventilation exhaust system Division 2 radiation monitors (B&C Channels) tripped on high-high radiation signal resulting in the isolation of containment cooling dampers M41-F017 and M41-F034 and placing the containment ventilation system in the containment cleanup mod The licensee took air samples and l background surveys were taken. The surveys indicated that radiation from l

the Residual Heat Removal (RHR) B line to the containment pool was i

sufficient to alarm the radiation monitors which are located on duct work l adjacent to the RHR B lin TS Table 3.3.2-1, item 1.g action states to i

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suspend core alterations, handling of irradiated fuel in the primary containment and operations with a potential for draining the reactor vesse The licensee complied with this action statement. TS Table 3.3.2-2, item 1.g requires the containment and drywell ventilation exhaust radiation high-high trip be < 3.6 MR/hr. The licensee had the monitors set to trip at 2.0 MR/hr. The licensee is proceeding to shield the radiation monitors from background radiation (i.e., the RHR piping).

On September 16,1986, at 4:45 a.m. while performing a tagout for design change package 84/5002, DC breaker 72-11A04 to inverter 1Y87 was opened which de-energized inverter 1Y8 This initiated a Division 1 secondary containment isolation, the standby gas treatment system started, and the control room standby fresh air units isolated. The operators restored from the tagout and realigned systems back to normal. The cause has not been determined. The loss of DC power to the inverter would not by itself cause an isolation. The licensee's review of tagouts showed the AC power supply breaker to 1Y87 was closed. The licensee's investigation is continuin This will be Inspector Followup Item 416/86-32-0 On September 17, 1986, at 10:30 a.m. while performing a modification per approved work document MWO 57689, an electrical lead from relay K110A was lifted. Lifting the lead de-energized relay K145A and resulted in the same automatic actuations as occurred on September 16, 198 The licensee relanded the lifted lead and restored systems to normal. The cause of this event was the inadequate work document that failed to recognize the lifting of the leads from relay K110A would initiate an ESF actuation. The licersee has established, for the duration of the outage, a special review team to independently review electrical tagouts and control room work packages for plant impac TS 6.8.1 requires written procedures be established, implemented and maintained covering the activities recommended in appendix A of Regulatory Guide (RG) 1.33, Revision 2, February 197 RG 1.33 recommends procedures for performing maintenance, repair, replacement and -

modification wor Section 6.1.2 of administrative procedure 01-S-07-1, Revision 17, Control of Work on Plant Equipment and Facilities implements this requirement through the use of Maintenance Work Orders. The work instructions, MWO 57689, for the activitie ; of September 17, 1986 noted above were inadequate resulting in the inauvertent actuation of the ES This is the first example of violation 416/86-32-0 On August 26, 1986, during the development of special instructions to test and flow balance Standby Service Water (SSW) Loop "A" following system modifications, it was discovered that an incorrect instrument coefficient was used during the flow balance of Loop "B" in November. 1985 following the Loop B modificatio This led to system flow checks using the proper coefficient. The checks revealed that SSW flow rates to the Division 1 and

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Division 2 ESF switchgear room coolers were below design values. Corrective actions and engineering design evaluations followed, which are described in detail in paragraph 9 of inspection report 416/86-26. As of the end of the last reporting period, the licensee had the concurrence of the NRC Region II staff, allowing continuation of refueling outage activities in plant conditions 4 or 5 with adequate SSW flow to all essential components in lieu

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of design flow stated in Operating License Condition 2.C.(20). This was documented by MP&L letter AECM-86/0283 of September 10, 198 By October 3,1986, the licensee reported that blockage was found in ESF switchgear room cooler piping consisting of iron salts and chemical deposition from the Plant Service Water (PSW) system. During normal plant operation these loads receive cooling water from PSW. A cross tie to the SSW system is provided as a cooling water source during emergency conditions. Flow was improved by flushing and throttle valve positioning but some ESF switchgear room coolers remained below design flow values. To ensure that this flow blockage problem was not generic to all SSW components, selected SSW components and large process piping (20 and 24 inch) not supplied by PSW were opened and inspected. The blockage observed in the ESF switchgear room coolers was not found in these components and piping. The licensee concluded that blockage in the ESF switchgear room coolers piping was the result of PSW water quality combined with the design low flow through the coolers, compounded by the lower flow set up by the use of incorrect instrument coefficient Division 1 (SSW Loop A) small diameter piping was hydrolased to remove the blockage, and at the same time modifications were made to facilitate easier future access through mechanical piping connections, and to permit flow measurement without having to secure the system for flow instrument installatio Upon completion of the cleaning and modifications, a final flow balance was completed on SSW Loop On October 7, 1986, the licensee reported that design flows in all SSW Loop A components had not been achieved, and that either final or interim disposition of the ficw condition in each of these components had been established except in the case of control room air conditionin The control room air conditioning unit condenser requires a design flow of 161 gallons per minute (gpm). After the flow balance only about 122 gpm was achieved. Initial assessments indicated the reduced flow to be caused by an inadequately sized piping run between the SSW A header, which is on the South side of the auxiliary building, and the control room unit, which is on the North side. Blockage similar to that found in the ESF equipment room coolers was not found; however, normal

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internal pipe corrosion which occurred since the last flow balance became a significant flow resistance factor, due to the length of the pipin In like manner to the disposition of flow conditions associated with the i cleaned piping to the ESF equipment room coolers, the licensee reassessed heat loads in the control room envelope, obtained vendor information on the

. air conditioning unit's performance with SSW flow rates less that 161 gpm, established maximum control room temperatures (considering human factors and equipment performance). Based on this assessment, the licensee established a minimum acceptable flow rate of 122 gpm to ensure the control room envelope can be maintained at or below the most limiting temperature criteri In order to proceed with scheduled work on SSW Loop B, the licensee discussed the existing conditions with the NRC Region II staf The Region II staff concurred with allowing continuation of refueling outage activities in plant conditions 4 and 5 with the above noted flow to the control room air conditioner and with that flow being periodically monitored

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for degradatio This was documented by MP&L letter AECM-86/0319, dated October 8, 198 On October 10, 1986, the licensee reported a potential seismic qualification deficiency with the ESF equipment room cooler nozzles (SSW water connections to the cooling coils). While conducting a design review of ESF equipment room coolers as part of the above flow problem activity, the licensee discovered that the engineering standards used by the architect-engineer on the original design might not preclude overstressing of the nozzles on equipment room coolers during a design seismic even The licensee has since conducted reevaluations using specific loading limits obtained from the cooler vendor, American Air Filter. To date the results were that the following four room coolers did not meet design seismic criteria, but are acceptable for normal loads:

T51B007A (el.166) FPCCU pump room Di T458001A (el.139) ESF Switchgear Di T468005A (el.166) ESF Switchgear Di T4680058 (el.166) ESF Switchgear Di At the time this was discovered, the plant was in operational condition 5, (refueling) but no core alterations were in progress. The refueling cavity was drained to the reactor vessel flange with miscellaneous instrument work and inservice inspections being performed. On October 12, 1986, the cavity was refilled to above the 22 feet 8 inches level. The licensee has committed to keep the NRC staff informed and not to conduct core alterations until this issue is resolved on an interim or final basi This is Unresolved Item 416/86-32-0 On October 8, 1986, while testing the Standby Diesel Generator (SDG) 11 tachometer circuit, a simulated rpm signal was input to the circuit. When a simulated 220 rpm was reached, the Division 1 Standby Service Water (SSW)

system initiated and began supplying cooling water. The apparent cause of this inadvertent ESF actuation was due to an inadequate work instructions, MWO E6673 This is a second example of inadequate work instructions resulting in an ESF actuation cited in violation 416/86-32-04 abov CFR 50.72(b)(2)(ii) states any event or condition that results in manual or automatic actuation of any ESF is reportable to the NRC within four hours. According to Section 7.3.1 of the GGNS UFSAR, SSW is an ESF syste This system was also included when ESF systems were reviewed by the NRC as documented in NUREG-0831, Safety Evaluation Report for GGNS, Section The licensee failed to make a 4-hour report of this ESF actuation to the NRC in accordance with 10 CFR 50.72 (b)(2)(ii). This is a violation (416/86-32-15). It should be noted that the licensee did not consider the SSW to be an ESF system and therefore this event was not reporte _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _-_

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10. Inspector Followup and Unresolved Items (92701)

(Closed) Inspector Followup Item 416/86-04-02. Potential 10 CFR 21 report regarding B&B Promatech fire seal. The licensee documented on Material Nonconformance Report (MNCR) 0129-86 the potential problem with B&B

Promatech fire seal Nuclear Plant Engineering (NPE) reviewed the penetration closures used at GGNS compared to the B&B Promatech config-uration that failed. Based on previous testing of GGNS penetration closures and analytical evaluations, the licensee concluded that the GGNS config-urations are acceptable.

(Closed) 86-IN-81, Broken inner-external closure springs on Atwood &

Morrill Main Steam Isolation Valves (MSIVs). Atwood and Morrill issued a letter to all affected licensee's and GE issued information letter SIL 442, e:h recommending certain actions be performed. IE Notice 86-81 stated that ther recommendation was adequate for Boiling Water Reactors (BWRs). The

. :censee conducted a visual inspection on the accessible portions of the inner and outer closure springs as recommended in SIL 442. No cracks or broken springs were found. Nuclear Plant Engineering issued a memorandum to the plant manager dated July 23, 1986, recommending all MSIV replacement springs be subjected to a specific 5% overload test prior to installation on the valves. The licensee has included a special requirement on the requisition for purchasing recurring items ir the MSIV inner and outer springs that requires springs be tested at Si overloa (Closed) Inspector Followup Item 416/85-36-01. Discrepancies in the Standby Gas Treatment System (SGTS) procedures and drawings. The licensee modified System Operating Instruction 04-1-01-T48-1 to correct noted discrepancie An information tag was attached to breaker 08-1Y75-24 in the 1Y75 cabinet explaining what equipment the breaker controls. Drawing M-1102A, SGTS, was revised. The inspectors will check the SGTS versus the revised drawing in future system walkdown (Closed) Inspector Followup Item 416/86-02-02. Replacement of High Pressure Core Spray generator with a modified generator during the first refueling outage. The inspectors witnessed portions of the installation and retesting of the replacement generator during the current refueling outage.

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On August 19, 1986, Region II's Atlanta based personnel contacted the i licensee concerning their 10 CFR 50.49 Limitorque Motor-0perated Valves (MOVs) with regard to IEN 86-03, Potential Deficiencies in Environmental

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Qualification of Limitorque Motor Valve Operator Wiring. The licensee was requested to advise the Region of the action they had taken with regard to IEN 83-72, Environmental Qualification Notice No. 24, and the above IEN (86-03) and, if required, to provide a Justification for Continued Operation (JCO). A followup letter from the licensee dated August 29, 1986, and telephone conversations indicated that 31 Limitorque operators in contain-i ment, supplied through the architect-engineer, were reinspected in light of IEN 86-03. All operators inspected in this sample were satisfactory. In addition, all of the NSSS vendor-supplied operators, (a total of 7) were inspected in light of IEN 86-0 Six of these operators contained wires k

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that were questionable. As a conservative measure, the questionable wires were replaced with wire documented to be qualified. Grand Gulf shut down September 5,1986, for a refueling outage and the remaining 10 CFR 50.49 Limitorque operators will be inspected to confirm their qualificatio Since there is some question involving interpretation of 10 CFR 50.49 and its 1985 deadline, this is an unresolved item identified as 416/86-32-17, Environmental Qualification of Limitorque Motor Operator . Design, Design Changes and Modifications (37700)

The inspectors conducted document reviews and hardware inspections to ascertain that design changes and modifications associated with TS License Conditions were in conformance with the requirements of the TS and 10 CFR 50.59. The following Design Change Packages (DCPs) were reviewed:

DCP 81/5003, License Condition (LC) 2.C.(22): Installation of transfer switch panel (1QH 22-P152), cabling, raceways and raceway supports to allow isolation from the effects of a control room fire, those functions utilized on the Division 1 remote shutdown panel. The inspectors observed portions of the installation work while in progress. This DCP will be followed to completion and tracked as Inspector Followup Item 416/86-32-0 DCP 85/3100, LC 2.C.(22): Installation of alternate shutdown emergency lighting additions and modifications. The inspectors reviewed the DCP and walked down the installation to verify proper incorporation of the emergency lighting. One discrepancy noted was the emergency lighting on the turbine

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building floor, elevation 166, area 6, was directing light in the wrong i direction. The licensee corrected the noted discrepancy. The close out of this DCP will be followed as Inspector Followup Item 416/86-32-0 DCP 85/4061, LC 2.C.(33)(a): Provide heating and cooling to the remote shutdown panel rooms, OC-208 and OC-208A, to maintain the remote shutdown panel rooms at an ef fective temperature condition of 85 F. The inspectors have reviewed the DCP and observed portions of the ir.stallation work. The followup of this DCP will be Inspector Followup Item 416/86-32-0 DCP 85/3122: The GGNS Safety Evaluation Report (SER), NUREG -0831, Appendix E, Part A.1.6, documented the control room human factors design review / audit finding that the top row of meters on each of the remote shutdown panels is

! located higher than the recommended maximum height of 70 inches for reading by a 5th percentile operator. This DCP lowers the existing instrumentatio The inspectors observed portions of the rework as directed by the DCP. The

! followup of this DCP will be Inspector Followup Item 416/86-32-09.

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DCP 82/0543, LC 2.C.(25)(a): Installation of higher capacity turbocharger

! and improved turbocharger spring drive gear, to improve reliability of the

! Division 3 High Pressure Core Spray Diesel Generator. The inspectors witnessed portions of the installation and retesting, and reviewed l documentation. The first retest indicated a problem with scavenging air.

l The cause was inadvertent reversal of the new turbochargers, i.e., the A turbocharger was installed on the B engine and the B turbocharger was i

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installed on the A engine. The licensee's representative explaired that even though the installation procedure identified the correct turbocharger for each engine by serial number, installation personnel failed to double-check the serial numbers. Normally there is a second verification check point in the procedure for this nature of work; however, in this case there was none. The turbochargers were correctly reinstalled, followed by a satisfactory retest. Additional followup of DCP closecut will be tracked under Inspector Followup Item 416/86-32-1 DCP 84/4080-1, LC 2.C.(6): SSW Basin A pipe support modifications as a result of soil structure interaction. The inspectors observed installation of the pipe support modifications and reviewed documentation. Additional followup on DCP closeout shall be tracked under Inspector Followup Item 416/86-32-11. SSW Basin B pipe support modifications were completed by DCPs 84/4080 and 82/5020 during the fall, 1985 outag DCP 86/3008, LC 2.C.(18): Add keylock switch on remote shutdown panels for LPCI valves (E12-F042A and B). The inspectors observed portions of the modification to the remote shutdown panel Followup will be tracked as Inspector Followup Item 416/86-32-1 . Facility Modifications (37701)

The inspectors conducted document reviews and hardware inspections to ascertain that facility modifications that required prior review and approval from the commission, pursuant to 10 CFP 50.50, were completed in conformance with requirements in the facility license, TS, 10 CFR and applicable codes and standards to which the facility was built. The following DCPs were reviewed:

DCP 84/3029, LC 2.C.(37)(c): Reconlection of diesel generator ground overcurrent relays 151GD (Divisions 1 and 2) to prevent a trip during accident conditions. The inspectors observed portions of the work and retesting, and reviewed documentation for Division 1 only. Further followup for Division 2, which is not yet complete and review of the closed DCP documentation shall be tracked as Inspector Followup Item 416/86-32-1 DCP 81/5007, LC 2.C.(15): Scram discharge volume modifications to add redundant air operated vent and drain valves, and diverse and redundant scram instrumentation for each instrument volume, including differential pressure sensors and float sensors. The modification is nearing completio This shall be Inspector Followup Item 416/86-32-1 . Refueling Activities (60710)

The first refueling outage commenced with a reactor shutdown on September 6, 1986. The inspectors routinely monitored refueling activities in progres The primary objectives of this inspection were to ascertain whether pre-refueling activities specified in the TS have been completed and whether refueling activities are being controlled and conducted as required by TS and approved procedure The following comments were noted:

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On September 17, 1986, the inspectors noted that the operators on the refueling platform were experiencing difficulty with the main hoist. There appeared to be an interference being caused by the grapple air hoses. A clamping device which was designed to keep hose tension stresses isolated from the hose connectors was not properly installed, and as such a cable which secures the clamp was apparently interfering with freedom of movement of the hoist. The cable was designed to be secured to the mast by a 3 inch stainless steel pin, which was missing. Efforts to find the pin yielded no results, and it was presumed, pending additional document reviews that the pin was not installed since the reactor head was removed. Without proper authority, licensee contract personnel removed the clamp completely, then resumed moving fuel assemblies with the clamp not installed. TS 6.8.1.a, Procedures and Programs, requires written procedures to be esteblished, implemented and maintained covering this maintenance activity as recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978, Section 9. Section 6.1.2 of administrative procedure 01-S-07-1, Revision 17, Control of Work on Plant Equipment and Facilities, requires all maintenance work to be accomplished using written and approved work documents, including troubleshooting activities which create a maintenance alteratio Removal of the grapple air hose clamp without an approved work document is a violation of these requirements. This is the third example of violation 416/86-32-0 On September 28, 1986, while inspecting incore nuclear instrument guide tubes for proper engagement with the upper core plate in accordance with a General Electric service information letter, the refueling team noticed the presence of wire, clips and vibration sensors in the area of one of the three removed fuel assemblies that had been instrumented with vibration sensors during the past fuel cycle. Subsequent examination of the channels from the three instrumented fuel assemblies indicated a significant amount of wire, clips and sensors had been stripped from the channels and were probably left in the core. Fuel assembly 33-34 was missing 12 clips and one ~

small wire; 51-34 was missing 37 to 42 clips, all wires, and five sensors; and 59-34 was nissing 27 to 32 clips, three short lengths of wire, and two sensors. The exact number of missing clips did not appear to be know Retrieval of the missing parts was accomplished using an underwater vacuum cleaner and air-driven plier Fuel assemblies surrounding the previously instrumented assemblies were removed from the core to provide for access, and inspection was performed using an underwater television camera. Six

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control rods surrounding assemblies 51-34 and 59-34 were removed and the

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guide tubes inspected. Only one clip and one small piece of wire was found in the bottom of the guide tube for control rod 52-33. One clip was found in the relief grcove between Local Power Range Monitor (LPRM) 58-35 and the core plat It could not be remove The licensee had indicated that another attempt would be made when the upper fuel cavity was drained to the reactor vessel flange when better access could be obtained. However, this was not attempted during the subsequent draining due to time constraints. A total of 19 to 37 clips and possibly some short pieces of wire remained unaccounted for. General Electric has performed an analysis which concluded that leaving these loose parts in the core will have no detrimental effect on the operation or integrity of the core during power operation. Since

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there were no other loose parts visible in the core, it is possible they are located in the bottom of the spent fuel pool and/or the containment fuel storage area, which would have no impact on operatio The above loose parts analysis also addressed the stainless steel pin which was found missing from the hose clamp cable discussed above. The pin assembly is about three inches long and 0.3 inches in diameter. Efforts to i find the device or prove it had never been installed failed, indicating that the pin could have dropped into the bottom of the core or in the reactor shroud annulus. The above loose parts analysis conducted by General Electric declared the pin as not being detrimental to reactor operation or

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safety to any significance, however, the inspectors expressed concern over

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the presence of foreign material of such dimension The inspectors requested Region II management to assist in determining the acceptability of the licensee's actions. This shall be Inspector Followup Item 416/86-32-1 . Training (99024)

l An inspection was conducted September 8-11, 1986, by Regional Office inspectors in the area of training. This inspection was conducted in response to a concern (RII 86-A-0153) expressed to Region II. The inspection consisted of a review of training procedures and records, Plant Quality Deficiency Reports (PQDRs), Corrective Action Reports (CARS),

individual training records, and various letters and document The inspectors interviewed a number of individuals including personnel from i

training, quality assurance, and plant management. Conflicting information provided by persons interviewed made the results of this inspection somewhat inconclusive. There were indications that irregularities may have existed in the licensee's internal processes involving several areas. These areas include training procedure and job description adherence and revision, the awarding and administration of training contracts, and the disciplinary,

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termination and hiring proces The potential irregularities observed l during the inspection, however, were within the licensee's internal policies and did not appear to violate any NRC regulations or negate any commit-ments. In several instances the inspectors could not identify any objective i

evidence for concerns that had been expressed to the NRC. One training CAR reviewed by the inspectors appeared to have been closed by Quality Assurance (QA) without adequate resolution. A QA audit conducted April 1, through May 3, 1985 (85-0053) identified that all plant sections did not have directives (procedures) which specified the qualifications / certifications

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for personnel in accordance with Administrative Procedure 01-S-01-4, Qualifica-I tions/ Certification for Professional and Supervisory Personne A CAR (2151) was generated as a result of these audit findings. Item (D) of CAR 2151 identified that " Training Section Directive 14-S-01-9, Rev. 3, Instructor Qualification and Certification, dated July 26, 1984, does not address qualifications and certifications for training supervisory personnel."

A July 30, 1985, letter from the plant manager to QA indicated that this item in the CAR could be closed on the basis of a Revision to 14-S-01-9 dated June 5, 1985. On August 1, 1985, the Manager of Nuclear Site QA replied that this procedure revision still did not specify the qualifications for

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t training supervisory personnel and the CAR item could not be close Following a response extension granted by QA, a letter dated October 2, 1985, indicated that Revision 7 of 14-S-01-09 had been issued to meet the corrective actions required by CAR _2151, Item (D). On November 13, 1985, QA closed CAR 2151 on' the basis that all required corrective actions were completed. Administrative Procedure 01-S-01-4, Revision 4, requires that each plant section superintendent shall certi fy the qualification of supervisory personnel in applicable section directive The procedure

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further requires that both the ANSI 18.1, 1971, and the company required qualifications to be described in the section directive for each supervisory position. The inspectors reviewed Revision 7 of the Training Procedure, which was the basis for closure, and noted that only the ANSI qualifica-tions, and not the company required qualifications had been incorporate In comparison, Operations Prccedure 02-S-01-7, Operations Personnel Qualifi-cations, clearly states the ininimum qualifications for each position from shift supervisor to auxiliary operator. These qualifications are not stated

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in the detail of job description, but include essential areas such as license, education, and experience levels. On re-review of the CAR, the QA inspector and a QA supervisor concurred that the corrective actions required by Item D were incomplete, and the CAR was improperly closed.

Pending licensee resolution of this procedural deficiency and the inadequate I

CAR closure this will be an Inspector Followup Item 416/86-32-18.

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