ML20247E744

Insp Rept 50-416/89-04 on 890114-0217.Violation Noted.Major Areas Inspected:Operational Safety Verification,Maint Observation,Surveillance Observation,Procedures & Records & Preparation for Refueling

ML20247E744
Person / Time
Site:	Grand Gulf
Issue date:	03/16/1989
From:	Cantrell F, Christensen H, Mathis J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20247E718	List: ML20247E711 ML20247E732 ML20247E744
References
50-416-89-04, 50-416-89-4, NUDOCS 8904030228
Download: ML20247E744 (15)

See also: IR 05000416/1989004

Text

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NUCLEAR REGULATORY COMMISSION

REGION 11

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j[ 101 MARIETTA ST., N.W.

e,,,, ATLANTA, GEORGIA 30323

Report No.: 50 .6/89-04

Licensee: _ System Energy Resources, Inc.

Jackson, MS 39205

Docket No.: 50-416 License No.: NPF-29

Facility Name: Grand Gulf Nuclear Station )

' Inspection Conducted: January 14 - February 17, 1989

Inspect rs: / e _3 !/ 6 f(Y

% H. 0. Ch'ristensen, Senior Resident Inspector Date Signed

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L P AL

J. L. Math'e, Resident Inspector

3/a/n

Date Signed

Approved by: 244-- '. 3 [4 /85

/-F. S. /Cantrell Section Chief, Date Signed

Division of Reactor Projects

SUMMARY

Scope: The resident inspectors conducted a routine inspection in the following

areas: Operational safety verification; maintenance observation; surveillance

observation; surveillance procedures and records; engineering safety features

(ESF) system walkdown; preparation for refueling; action on previous inspection

findings; document control program; and evaluation of licensee self-assessment

capability. The inspectors conducted backshift inspections on January 12, 26

and February 2, 12, 1989.

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Results: Within the areas inspected, one violation and one unresolved item was

identified: Failure to perform a safety evaluation for the storage of EC0DEX

resin inside containment, paragraph 9. The walkdown of the RCIC system

indicated a number of labelling errors, particularly in the electrical panel

area, paragraph 7. The surveillance procedures and records program appears

adequate with no major deficiencies.

8904030228 890316 ,

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REPORT DETAILS

l 1. Persons Contacted

Licensee Employees

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• M. Bakarick, Superintendent, System Support

J. G. Cesare, Director, Nuclear Licensing i

W. T. Cottle, Vice President of Nuclear Operations

• D. G. Cupstid, Superintendent, Technical Support

L. F. Daughtery, Compliance Supervisor

• J. P. Dimmette, Manager, Plant Maintenance

S. M. Feith, Director, Quality Programs

• C, R. Hutchinson, General Manager GGNS

R. H. McAnulty, Electrical Superintendent

• R. V. Moomaw, Technical Assistance, Plant Maintenace Manager

A. S. McCurdy, Technical Asst., Plant Operations Manager .

L. B. Moulder, Operations Superintendent

J. H. Mueller, Mechanical Superintendent

• J. C. Roberts, Manager, Performance and System Engineering

J. V. Parrish, Chemistry / Radiation Control Superintendent

• J. L. Robertson, Superintendent, Plant Licensing

R. F. Rogers, Manager, Special Projects

S. F. Tanner, Manager, Quality Services

L. G. Temple, I & C Superintendent

F. W. Titus, Director, Nuclear Plant Engineering

M. J. Wright, Manager, Plant Support

• J. W. Yelverton, Manager, Plant Operations

Other licensee employees contacted included technicians, operators,

security force members, and office personnel.

• Attended exit interview

2. Plant Status

Unit 1 began and ended the inspection period operating at approximately

100% power. The licensee had several surveillance electronic time

response test failures and functional test failures. However, corrections

were made without interruption of plant's operation. The next refueling

outage is scheduled for March 17, 1989.

3. Operational Safety Verification (71707)

The inspectors were cognizant of the overall plant status, and of any

significant safety matters related to plant operations. Daily discussions

were held with plant management and various members of the plant operating

staff. The inspectors made frequent visits to the control room.

Observations included the verification of instrument readings, setpoints

and recordings, status of operating systems, tags and clearances on

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equipment controls and switches, annunciator alarms, adherence to limiting .

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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 supervisors.

On a weekly basis selected engineered safety feature (ESF) systems were

confirmed operable. The confirmation was made by verifying that accessible

valve flow path alignment was correct; power supply breaker, and fuse

status was correct; and instrumentation was operational. The following

systems were verified operable: Containment spray, and standby gas

treatment system (Train B). Additionally, the inspectors conducted a

modified system walkdown on the low pressure core spray system, high

pressure core spray system, emergency electric power system, suppression

pool makeup system, and the automatic depressurization system. The

walkdowns used the Grand Gulf Probabilistic Risk Assessment Based System

Inspection Plan as a guide.

General plant tours were conducted on a weekly basis. Portions of the

control building, turbine building, auxiliary building and outside areas

were visited. The observations included safety related tagout

verifications, shift turnovers, sampling programs, housekeeping and

general plant conditions, the status of fire protection equipment, control

of activities in progress, problem identification systems, and containment i

isolation. Additionally, the licensee's onsite emergency response

facilities were toured to determine facility readiness.

The inspectors observed health physics management involvement and

awareness of significant plant activities, and observed plant radiation

controls. The inspectors verified licensee compliance with physical

security manning and access control requirements. Periodically the

inspectors verified the adequacy of physical security detection and

assessment aids.

During the week of January 31, 1989, a Regional security inspector

reviewed (see Inspection report 416/89-03) the licensee's progress of

enclosing Unit 2 within the protected area. A number of items required

i completion before activating the new boundary area. The resident

inspectors verified that these items were completed before the new

protected area boundary was activated on February 9, 1989.

On February 10, 1989, the licensee identified that a SERI employee

unintentionally took a handgun into the protected area. Upgraded X-ray

machines have been put in service since this incident occurred. This

incident was called in to NRC in a one-hour report and documented in

Incident Report 89-2-3. Further investigation by the licensee is on-going

and will be followed by Regional based security inspectors. l

The inspectors reviewed safety related tagout 18443, to prevent operation

of RHR valve E12-F052 A and B. The review ensured that the tagout was

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properly prepared and performed, and the tagged components were in the

required position.

The inspectors verified that the following containment isolation valves

were in there correct lineup; E61-F002A (combustible gas control) and

C41-F006 (standby liquid control).

No violations or deviations were identified.

4. MaintenanceObservation(62703)

During the report period, the inspectors observed portions of the

maintenance activities listed below. The observations included a review

of the maintenance work orders (MW0s), and other related documents for

adequacy; adherence to procedure, proper tagouts, technical

specifications, quality controls and radiological controls; observation of

work and/or retesting; and specified retest requirements.

MWO # Description

M86133 Perform TBCW C Pump Overhaul per Procedure.

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ME0802 Take RCIC Lube Oil Sample

ME0800 Inspect and Lubricate Throttle and Linkage i

(RCIC)

ME0796 Lubricate Pump Coupling (RCIC)  !

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ME0804 Clean and Replace Inlet Air Filter

ME0803 Lubricate RCIC Coupling

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ME0797 Check RCIC Oil for Moisture

ME1436 Replace RCIC Filters

ME0795 RCIC Bearing Oil Change

On January 31, 1989 the inspectors witnessed portions of MW0 ME0795, which

j consisted of a periodic oil change of the bearing sump for the RCIC pump.

The procedure, 07-S-14-87, required that one quart of solvent be used to

flush the bearing housing and specified that one quart of oil be used to

fill the bearing housing; however, only one pint of solvent and oil were

used. The licensee identified this discrepancy with the procedure and

wrote a QDR. The licensee contacted the vendor and determined that

flushing the bearing housing with a solvent is not required, and confirmed

that one quart of oil would overfill the bearing housing. The licensee

committed to revise the procedure to reflect the vendor recommendations.

This will be identified as inspector follow-up item 89-04-01.

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No violations or deviations were identified.

5. Surveillance Observation (61726)

The inspectors observed the performance of portions of the surveillance

listed below. The observation included a review of the procedure for

technical adequacy; conformance to technical specifications and limiting

conditions for operations (LCOs); verification of test instrument

calibration; observation of all or part of the actual surveillance;

removal from service and return to service of the system or components;

and review of the data for acceptability based upon the acceptance

criteria.

06-EL-1E31-M-0001 Revision 24, RCIC Main Steam Tunnel Isolation Delay

Timer Channel B.

06-0P-1E51-Q-0003 Revision 25, RCIC System Quarterly Pump Operability

Verification.

06-EL-1821-M-0001 Revision 27, ADS Timer Functional lest and

Calibration Channels B and F.

06-IC-1C11-R-0003 Revision 23, Scram Hydraulic Control Unit Calibration.

06-10-1E31-R-0025 Revision 22, Main Steam Line B High Flow (PCIS)

Electronics Time Response Test, Channel D.

17-S-02-203 Revision 0, TIP System Calibration

On January 13, 1989 during the performance of surveillance procedure

06-RE-1C51-0-0001, Revision 27, LPRM Calibration, the traveling in-core

probe (TIP) C output saturated high in channel 4. A maintenance work

order was written for trouble shooting, and the cable was determined to be

bad. Special instructions were written for the removal and replacement of

the TIP detector. A special ALARA meeting was held prior to replacing the

detector to coordinate the job and to adhere to ALARA principle. Once the

detector and cable were replaced, applicable steps of procedure

17-S-02-203, Tip System Calibration, were performed to check out the

system. The post maintenance insulation resistance (IR) was lower by a

factor of two than the GE recommended acceptance criteria (greater than

10E8 ohms). An MWO was written to investigate this lower IR value. The

retest performed on February 8, 1989 was satisfactory and determined

satisfactory.

No violations or deviations were identified.

6. Surveillance Procedures and Records (61700)

The inspectors verified that 35 selected TS and ISI surveillance test were

covered by properly approved procedures and that these procedures specified

prerequisites and preparations, acceptance criteria, and instructions to

restore the system to operation following testing.

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Technical Specification 4.6.4.2 requires that each automatic isolation

valve shown in Table 3.6.4-1 shall be demonstrated operable during cold

shutdown refueling at least once per 18 months by verifying that on an

isolation test signal each automatic isolation valve moves to its

isolation position. Technical Support Procedure 09-S-05-7, Revision 16,

GGNS Technical Specification / Surveillance Program Master Cross-Index, list

all procedures that meet each required TS. A review of the five

procedures; 06-0P-1B21-R-0006, 06-0P-1P75-R-0003, 06-0P-1P75-R-0004,

06-0P-1P81-R-0001, and 06-0P-1821-V-0001; that addressed TS 4.6.4.2,

indicated that two valves, E12-F028A and B, RHR heat exchanger to

containment spray sparger inlet valves, were not included in the five

referenced procedure. The licensee determined that the requirements for

TS 4.6.4.2 was met by Surveillance Procedure 06-0P-1E12-R-0022, RHR

Containment Spray Initiation Logic System Functional Test. The licensee

agreed to issue a procedure change to include the surveillance in the

" master cross-index" and to reflect the TS requirement in

06-0P-1E12-R-0022.

The inspectors questioned whether the intent of TS 4.6.4.2 was being met

for the main steam line isolation valves. Surveillance procedure

06-0P-1821-V-0001, MSIV Operability Test, strokes the valves closed by

using each valve individual manual handswitch while the plant is in

operational condition 2 above 600 psig. The licensee stated that they

believed the intent of the surveillance requirement was being met by the

above procedure. In discussion with NRR representatives, use of the

manual handswitch was determine acceptable because the manual switch

operates the same relays that the isolation signal operates. No other

deficiencies were identified.

Twenty-one completed surveillance tests were reviewed to determine that

the tests were in conformance with TS, ISI program, and procedural

requirements; tests had been reviewed as required by administrative

procedure 01-5-06-12, Revision 15, Grand Gulf Nuclear Station Surveillance

Program; tests had been performed within the time frequencies specified by

the TS or ISI program; appropriate action had been taken for any item

failing acceptance criteria; and test were performed by qualified

individuals.

A review of the Battery 1A3 Performance Discharge Test, 06-EL-1L21-0-0001,

conducted during the second refueling outage indicated that the

surveillance was performed correctly, but the data sheet had been filled

out incorrectly. The electrical superintendent stated that training will

be conducted in the proper way to conduct and document the battery .

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performance discharge test.

Overall, the surveillance program appear adequate and meets the

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No violations or deviations were identified.

7. Engineered Safety Features System Walkdown (71710)

The inspectors conducted a complete walkdown on the accessible portions of

the reactor core isolation cooling (RCIC) system to verify the following:

Confirm that the system lineup procedure matches the plant drawing and the

as-built configuration; identify equipment condition and items that might

degrade plant performance; verify that valves in the flow path are in

correct positions as required by procedure and that local and remote

position indications are functional; verify the proper breaker position at

local electrical boards and indications on control boards; verify that

instrument calibration dates are current.

The residents walked down the system using system operating instruction

04-1-01-E51-1, Revision 30, Reactor Core Isolation Cooling and Piping, and

instrument diagram (P&ID) M-1083A, Revision 24 and M-1083B, Revision 26.

The operating instruction electrical lineup checksheet, Attachment III,

component description differed from the actual equipment label as follows:

Breaker No. Component Description Breaker Label

52-153129 RCIC STM SPLY ORWL OTBD ISOL STM SPLY OTBD ISOL

52-1P53108 MOTOR AND COMPRESSOR HEATERS SPARE

52-1P53118 VALVE MOTOR HEATER MOV HTR VERTICAL

SEC I

52-1P53116 VALVE MOTOR HEATER M0V HTR VERTICAL

SEC J

52-1P53112 VALVE MOTOR HEATER MOV AND STARTER

SPACE HTR

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52-1P51104 VALVE MOTOR HEATER MOV AND STARTER

SPACE HTR

( 52-1P56120 DIV 1 RCIC CONTROL POWER CR PGCC PANEL

1H13-P632 LK DET

SYS

52-1P56112 DIV 1 TRIP UNIT ISOLATOR CR PGCC PANEL

POWER SUPPLY 1H13-P629 LPCS

52-1P56117 RCIC 1 TEST CKTS AND CR PGCC PANEL

STATUS LIGHTS 1H13-P601 RCIC

F066 LIMIT SWITCH 1

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52-IP66108 DIV 2 TRIP UNIT ISOLATOR CR PGCC PANEL

ISOLATOR POWER SUPPLY IH13-P618 RHR

52-1P66112 DIV 2 TEST CKTS CR PGCC PANEL

AND STATUS LIGHTS 1H13-P601 RCIC

52-IP66111 DIV 2 RCIC CONTPOL POWER CR PGCC 1H13-P642

LK DET SYS

72-11B13 AIR TO A-F004 TURB EXHAUST DRAIN 72-11813E51

AIR TO A0-F025 TURB STEM LINE PGCC 1H13-P600

DRAIN A0-F004 LIMIT SWITCH

A0-F025 LIMIT SWITCH

72-11BSo DIV 2 TRIP UNIT ISOLATCR POWER 72-11835E21

PGCC 1H13-P618

72-11B39 DIV 2 RCIC RELAY LOG PGCC IH13-P618

72-11B14 DIV.2 TRIP UNIT 72-11B14312

ISOLATOR POWER PGCC PNI 1H13-P618

72-11A39 TURB GOV VALVE LIMIT SWITCH 72-11A39E51

TURB TRIP AND THROTTLE LIMIT PGCC PNL 1H13-P601

SWITCH A0-F026 LIMIT SWITCH

A0-F005 LIMIT SWITCH

A0-F0054 LIMIT SWITCH

AIP 10 A0-F026 STM LINE DRAIN

AIR TO A0-F006 TURB EXHAUST DRAIN

72-11A24 RCIC TURB SPEED CONTROL POWER 71-11A24E51

DIV 1 RELAY LOGIC POWER SUPPLY PGCC PNL 1H13-P621

RCIC TURB REMOTE TRIP POWER SUPPLY

72-11A32 RCIC TURB FLOW CONTROLLER POWER PGCC PNL 1H13-P632

72-11A18 DIV 1 TRIP UNIT ISOLA 5OR POWER 72-11A18E21

SUPPLY PGCC PNL 1H13-P629

72-11A3B DIV 1 TRIP UNIT ISOLATOR POWER 72-11A38E12

SUPPLY PGCC 1H13-P629

72-11A16 RCIC STM SPLY TO PCIC TURB 72-11A16E51

RCIC VALVE F045

72-11A21 RCIC TURB TRIP AND THROT-VLV RCIC TURB TRIP ,

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52-1P31210 120 Vac INST BUS CR PGCC PNL

1H13-P632

LK DCT SYS

52-1P11305 LEAK DETECTION S0Vs 1H22-P176

POWER SUPPLY

08-1Y71-12 RCIC TEST RTN FCV TO CST B0P PROCESS

INSTRUMENT CAB

1H13-P843N5

52-1P56115 120 Vac FEEDER TO K500 AND K501A LOCAL CONTROL

POWER SUPPLIES PANEL REMOTE SD

SYSTEM

The RCIC annunciator panels were reviewed using the System Operating

Instruction, Attachment IV, System Alarm Index. The following differences

were noted:

Alarm Name Panel Grid Actual Grid

Rr.C DIV 1 1H13-0601-21A A2 Al

STM SPLY PRESS L0

RCIC VAC BRKR 1H13-P601-21A E3 04

ISOL VLV F078

NOT FULLY OPEN

The following Alarm was not on the alarm index:

Alarm Name Panel Grid

RCIC GL SEAL 1H13-P601-21A El

AIR PRESS HI

The folic'.-ing Alarm label differed from tLe SOI.

Panel Name In 501 Actual Name

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1H13-P601-21A-E4 RCIC TURB OIL PRESS L0 RCIC TURB

BEARING OIL PRESS

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The inspectors were informed that the licensee is implementing a new

labelling program, procedures are being developed, and that they are

walking down the safety related systems to determine labelling

deficiencies. The licensee stated that full implementation of this

program will take several years, including the B0P portion of the plant.

The inspector stated that this was not an acceptable schedule for

safety-related systems. This is identified as an inspector follow-up item

(416/89-04-02).

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The following deficiencies were identified during the system walkdown:

-Instrument taps, PP-N400, N401, N402, N403 are missing caps.

-Valve F022, RCIC inboard test return to CST, local indicator indicated

10 percent open, a normally closed valve.

-Valve F045, RCIC steam supply to RCIC turbine local indicator 1-dicated

30% open, a normally closed valve.

-Valve F046, RCIC water to turbine lube oil cooler, actuator has a small

oil leak.

-RCIC governor valve has water leaking from the valve spring area.

-The lube oil cooler area is dirty.

-The area under the minimum flow line next to the RCIC room wall is

dirty.

-Valves F251 and F252, minimum flow line to suppression pool drain

valves, are locked closed valves, the 50I has them as closed valves.

The correction of the above deficiencies will be an inspector followup

item. (416/89-04-03).

The inspectors reviewed M0 VATS test data and limit switch setting for five

RCIC valves. The review ensured that the M0V limit switch settings were

set to the requirements of IE Bulletin 85-03, Motor Operated Valve Common

Mode Failures During Plant Transients Due to Improper Switch Settings.

During the MOVATS testing of E51-F045, RCIC steam supply to RCIC turbine

valve, the as-found closing torque switch trip thrust was 98,675

lbs-force. The licensee adjusted the torque switch setting to reduce the

torque below the valve's limiting thrust of 58,000 lbs-force and wrote a

material non-conformance report (0520-87). The MNCR required the key

brushing set screws to be replaced and to inspect the yoke arms for

cracking. The actions of the MNCR were completed under MWO-M77365.

The inspectors reviewed GE Service Information Letters (SIL), IE Notices

and Bulletins applicability to the RCIC system. The following were

reviewed:

IEN 82-16 HPCI/RCIC High Steam Flow.

IEN 82-26 RCIC and HPCI Turbine Exhaust Check Valve Failure.

IEN 88-69 AFW (RCIC) Turbine Overspeed Trip (Polyurethane

Tappet).

IEN 88-08 Reduced Reliability of Steam-Driven Auxiliary

Feedwater Pumps Caused by Instability of Woodward

PG-PL Type Governors.

GE SIL #336 Surveillance Testing Recommendations for HPCI and

RCIC Systems.

GE SIL #393 RCIC Turbiae Journal Bearing Locating Pin.

GE SIL #351 HPCI and RCIC Turbine Control System Calibration.

GE SIL #319 HPCI and RCIC Turbines Drive Gear Assembly.

The licensee has reviewed the above IENs and SIls for applicability to the

RCIC System. GE SIL 319 recommended that the drive gear assemblies

(gears, shaft bushing and thrust washer) on the RCIC turbines be inspected

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for evidence of wear and overheating. MWO M64978 was initiated to perform )

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the inspection per procedure 07-S-14-301. The work was completed

satisfactory on September 8, 1986. Additionally, GE recommended this

inspection be performed every 6 months or after 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> accumulated run

time which ever comes first. SERI records show that this inspection has

been performed only once since the SIL came out. Telephone conversation

with GE by SERI System Engineer revealed that a revision to SIL 319 is

being issued soon to recommend a 18-month inspection of the turbine drive

gear assembly. The licensee has initiated a preventive maintenance task

card for inspecting the turbine drive gear assembly every 18 months per

procedure 07-S-14-301. This item will be tracked as inspector followup

item 89-04-03.

The RCIC system appears to be in good condition and the plant has taken

appropriate actions to maintain the system in a ready state.

No violations or deviations were identified.

8. Preparation for Refueling (60705)

On January 20, 1989, Grand Gulf received a load of new fuel for the third

refueling outage. The first shipment of Advance Nuclear Fuel was in

crates containing two fuel bundle per crate. Fuel receipt was performed

in accordance with procedure 17-S-02-110, Revision 0, New Fuel Processing.

The inspectors reviewed the shipping documentation and inspected tne

shipment to ensure that it complied with the shipping papers (Packing

List Bill of Lading, etc.). The fuel crate accelerometers were verified

to be untripped prior to inspecting the fuel assembly by licensee. The

fuel assemblies were inspected in accordance with procedure 17-S-02-110.

After inspection, the fuel was channeled prior to storage in the spent

fuel pool.

No violation or deviations were identified.

9. Action on Previous Inspection Findings (92701,92702)

(0 pen) Inspector Followup Item 416/86-36-01, Establish criteria for

determining when to clean ESF switchgear room coolers piping. Criteria

were placed in procedures 04-1-03-T46-1 and 04-1-03-T46-2 for the A and B

ESF Switchgear Room Coolers Flow Test respectively. If any flows are less

than the criteria listed, the cooler is to be declared inoperable and TSPS

101 followed. The criteria for cleaning the room cooler was satisfactory.

However, steps 7.4.1.C of the revised procedures instructed the operator

to follow TSPS 101 for any coolers found inoperable. NRC letter dated

January 25, 1989 to SERI discussed a problem area of GGNS Technical

Specification 3/4.8.3. The ESF room coolers specified in position

statement 101 serves the Divisional I and II electrical switchgear and

electrical penetration rooms. When the ESF room coolers are declared

inoperable, the MCC and LCC would be declared inoperable, and the action

statements associated with this equipment must be followed. The action

statements for TS 3/4.8.3 specifies an allowable outage time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />

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rather than the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> listed in the TSPS (72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> was used based on

the action statement for standby service water). The TSPS and the present

TS for standby service water reflects a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> outage time which is in

conflict with the Technical Guidance provided in the letter dated

January 25, 1989. This item will remain open.

(Closed) Unresolved Item 416/88-25-01, Review the safety evaluation for

storing Ecodex resin in containment. An evaluation of Ecodex storage in

containment and the auxiliary building on January 16, 1989 showed that

Ecodex storage in containment presented a potential Seismic II/I hazard to

small diameter lube oil tubing required for continued operation of the

drywell purge compressor.

FSAR section 6.2.5.2.1, states that the drywell purge system is provided

to purge the hydrogen produced within the drywell into the larger

containment volume in order to maintain the drywell hydrogen concentration

below the flammability limit. The Ecodex seismic hazard could have

affected one train of a two train drywell purge system. Each train is a

100% capacity system. The Ecodex was removed from containment when it was

initially brought to their attention and a temporary change notice was

issued to system operating instruction 04-1-01-G33-1, Revision 33, Reactor

Water Cleanup, to remove all Ecodex boxes and bags from containment on

completion of resin changes. The licensee was informed that failure to

perform an initial safety evaluation on the storage of Ecodex in

containment is a violation of the requirements of 10 CFR 50.59

(416/89-04-04). Unresolved item 88-25-01 is administratively closed and

any additional corrective action will be tracked under the violation.

10. Document Control Program (39702)

The resident inspectors reviewed the licensee program for safety-related

drawira control. Administrai.ive procedure 01-5-05-6, Revision 23,

Receipt, Distribution and Maintenance of Plant Drawings, provides guidance

for the receipt, distribution, maintenance, and use of plant drawing. The

review process consisted of review of critical drawings, review of drawing

change process, and as-built verification.

a. Review of Critical Drawings

Drawings that the licensee considers to be critical for use by

operations or TSC personnel in plant operations or emergencies are

I identified in attachment 1 of procedure 01-S-05-6. The manager of

plant operations, in conjunction with the director of nuclear plant

engineering, identify the as-built drawings to be maintained on the

control room and TSC stick files. Presently there are approximately

50 sets of system drawings the licensee considers operations

critical. The safeguards drawings identified as operation critical

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are maintained separately in the document control safeguards file.

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The inspectors reviewed several of the critical drawing in the TSC

and control room for legibility and confirmed the revision of the

drawings at each location was the current approved revision,

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Document control marks drawings in red (on aperture cards and on l

hardcopy drawing) to indicate any changes that are due incorporation

(CNS, DCP drawings, DRNS, Engineering Markup Attachments, Temp Alts) 3

and places the changes behind the appropriate drawings on the stick

file and in the aperture card file. Overall, the licensee program l

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for maintaining legible drawing and latest revisions to operation

critical drawings is satisfactory. The only illegible drawing

reviewed was in the control room. Drawing E1163 sheet 34 (revision

7) consisted of a tabulation for GE HFA Relays. Area D-1 of this

drawing was not legible, however the TSC drawing was legible. The

only other discrepancy identified in this area was on drawing E1163

sheet 51 (revision 8). -An outstanding change was stamped on the ,

drawing which referenced DCP 83-3025. The change to the drawing I

appeared to have already been incorporated in the drawing and the '

effected drawing (E1163) should not nave been stamped.

The inspectors interviewed an operation staff member to demonstrate

the process of determining whether a drawing represents the most

current plant configuration. The operator was knowledgeable of the

drawing program. These discrepancies appeared to be isolated areas,

b. Review of the Drawing Change Process

The licensee's drawing change process was outlined in Administrative ,

Procedure 01-5-05-6. Document control verifies semi-annually that the

plant staff, NPE, and PM&C drawing are current. In the future, the

control room and TSC will receive priority over other area for

updating the controlled drawing. If a controlled drawing is revised

or changed, document control notifies the holders within two working

days after acceptance of the revision / change document by sending them

a change notification sheet. Prior to using a drawing, the drawing

holders are responsible for verifying that all drawings are current

with the changes reflected and the approved "as-built" configuration.

Except for the control room, document control will not update or

revise controlled drawings unless they are returned for validation.

NPE Administrative Procedure 315, Revision 7, Updating /As-Built

GGNS Design Document, states, the cognizant principle engineer should

attempt to ensure that closecuts are done in a timely manner to

support a 14 day incorporation target to reflect "as-built"

conditions following changes to existing plant systems, structures,

components, or records. All outstanding DRNs must be incorporated

into a drawing anytime any of the following conditions exists:

(1) Three DRNs have been issued against the drawing.

(2) Ninety calendar days have elapsed since the issue of the first

DRN against the current revision of an " operation critical" e

" operation sensitive" drawing.

(3) The drawing is revised and issued for any reason. 4

No violation or deviation were identified.

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11. Evaluation of Licensee Self-Assessment Capability (40500)

The inspectors evaluated the effectiveness of the licensee's >

self-assessment programs. The inspection focused on determining whether

the licensee's program contribute to the prevention of problems by

monitorir:g and evaluating plant performance, communicating assessments and

findings, and following up on corrective action recommendations.

On January 17,1989, the inspectors attended a quarterly Safety Review

Committee (SRC) meeting. The SRC is the TS required offsite review

committee. The committee had the required member composition and quorums.

The SRC conducted the following activities: Reviewed and approved past

SRC meeting minutes; summarized plant operating experience; reviewed

reports of significant operating abnormalities; reviewed SRC open action >

items; reviewed investigations of violations of codes, regulations,

orders, TS, license requirements or internal procedures having nuclear

safety significance; reviewed audits and corrective actions; reviewed PSRC

meeting minutes and 10 CFR 50.59 safety evaluations; and assigned new SRC

action items.

The dicussion of SRC topics appeared to be candid and open. The use of

consultants, as required by TS, appears to be benificial to the SRC in

dicussing topic from various points of view. The SRC appears to be

fulfilling its intended function.

No violatiens or deviations were identified.

12. Exit Interview (30703)

The inspection scope and findings were summarized on February 17, 1989

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

identify as proprietary any of the materials provided to or reviewed by

the inspectors during this inspection. The licensee had no comment on the

following inspection findings:

Item Number Description and Reference

!

89-04-01 (IFI) Review the revised RCIC periodic oil

change procedure 07-5-14-87

89-04-02 (IFI) Revise in procedures or on equipment

labels to assure that the same

nomenclature is used on both.

l 89-04-03(IFI) Review the licensee corrective action

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on RCIC labeling and system walkdown

I deficiencies.

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89-04-04(IFI) Review the revised procedure to

incorporate GE-SIL 319 recommendations

into the preventive maintenance

program.

89-04-05 (VIO) Failure to perform a safety

evaluation on the storage of EC0DEX

resin inside containment.

'13. Acronyms and Initialisms

CNS - Change Notices

DCP - Design Change Package

DG -

Diesel Generator

DRNS - Drawing Revision Notices

ESF - Engineering Safety Feature

GGNS - Grand Gulf Nuclear Station

HPCS - High Pressure Core Spray

HPU - Hydraulic Power Unit

I&C - Instrumentation and Control

LCC - Load Control Center

LER - Licensee Event Report

LPCS - Low Pressure Core Spray

MCC - Motor Control Center

MNCR - Material Nonconformance Report

MWO - Maintenance Work Order

NRC - Nuclear Regulatory Commission

P&ID - Pipiag and Instrument Diagram

PDS -

Pressure Differential Switch

PSW - Plant Service Water

QDR - Quality Deficiency Report

RCIC - Reactor Core Isolation Cooling

RPS - Reactor Protection System

RWCU - Reactor Water Cleanup

'RWP - Radiation Work Permit

SERI - System Resource Incorporation

501 - System Operating Instruction

TCN - Temporary Change Notice

TSC - Technical Support Center

TSPS - Technical Specificaiton Position Statement

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