ML20214L283

Insp Rept 50-416/86-21 on 860715-0808.Violation Noted: Failure to Follow Sys Operation Procedure,Causing Isolation of Standby Liquid Control Sys Pressure Instrument & Surveillance Procedure Re Standby Diesel Generator

ML20214L283
Person / Time
Site:	Grand Gulf
Issue date:	08/22/1986
From:	Butcher R, Dance H, Will Smith NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20214L275	List: ML20214L273 ML20214L278 ML20214L283
References
50-416-86-21, NUDOCS 8609100053
Download: ML20214L283 (9)

See also: IR 05000416/1986021

Text

UNITED STATES

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NUCLEAR REGULATORY COMMISSION

REGION 11

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g j 101 MARIETTA STREET.N.W.

• t ATLANTA. GEORGI A 30323

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Report No.: 50-416/86-21

Licensee: Mississippi Power and Light Company

Jackson, MS 39205

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

Facility Name: Grand Gulf

Inspection Conducted: Jul 15 - August 8, 1986

Inspe 'tors: - 7/

R. s Butcher, Seni<0E.Re'sident Inspector D&t Signed

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W. F. Sniith, Resident 9(spector

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Okt Signed

App ved by: h- 1 f[

H. C. Dance, Section Chief 0%te Sfgned

Division of Reactor Projects

SUMMARY

Scope: This routine inspection was conducted by 'the resident inspectors at the

site in the areas of Licensee Action on Previous Enforcement Matters, Operational

Safety Verification, Maintenance Observation, Surveillance Observation, ESF

System Walkdown, Reportable Occurrences, Operating Reactor Events, Inspector

Followup and Unresolved Items, Design Changes and Modifications, Performance

Indicator Trial Program, Preparation for Refueling, and Refueling Activities.,

Results: One violation with two examples was identified: 1) Failure to follow a

system operating procedure in that'a Standby Liquid Control (SLC) system pressure

instrument was found isolated and 2). Failure to follow a surveillance procedure

thereby causing an inadvertent start of Standby Diesel Generator (SDG) 12.

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8609100053 860825

PDR ADOCK 05000416

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REPORT DETAILS

1. 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 Operaitons

• J. D. Bailey, Compliance Coordinator

M. J. Wright, Manager, plant Support

• L. F. Daughtery, Compliance Superintendent

D. G. Cupstid Start-up Supervisor

R. H. McAnulty, Electrical Superintendent

R. V. Moomaw, 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

Other licensee empioyees contacted included technicians, operators, security

force members, and office personnel.

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• Attended exit interview

2. Exit Interview (30703)

The inspection scope and findings were summarized on August 8,1986, 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. The licensee had no comment on the

following inspection findings:

a. 416/86-21-01, Inspector Followup Item. Discrepancies between system

operating procedure requirements, Piping and Instrument Diagram (P&ID)

requirements, and actual valve positions in SLC System (paragraph 7).

b. 416/86-21-02, Violation. First example: Failure to follow a system

operating procedure in that a SLC system pressure instrument was found

isolated (paragraph 7). Second example: Failure to follow a surveil-

lance' procedure thereby causing an inadvertent start of SDG 12

(paragraph 9).

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3. Licensee Action on Previous Enforcement Matters (92702)

(Closed) Deviation 416/84-16-02. Inspection report 416/86-13, paragraph 9,

documents the review cf maintenance personnel training and no adverse

findings were noted. Administrative Procedure (AP) 01-S-07-1 was revised to

require the discipline maintenance supervisor / superintendent to determine

4 whether special training or direct supervision is required by craft

personnel to perform specific work. AP 01-S-07-33 was revised to define the

requirements for the qualification and certification of contract personnel.

No further action is required.

(Closed) Violation 416/84-16-03, Maintenance Contractor Certification

Program. See corrective action for deviation 416/84-16-02 above.

(Closed) Violation 416/84-16-04, Maintenance Personnel Qualifications. See

corrective action for deviation 416/84-16-02 above.

4. 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 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 such that it was visited at least daily when an inspector was onsite.

4 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

supervisors.

Weekly, when or. site, selected ESF systems were confirmed operable. The

confirmation was made by verifying the following: Accessible valve flow

path alignment, rnwer supply breaker and fuse status, major component

leakage, lubricatior., cooling and general condition, and instrumentation.

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 verifica-

tions, 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 isolation.

No violations or deviations were identified.

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5. 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 controls.

MWO 12C929, Replace Inadequate Conductivity Transmitters and Elements

in FPCC System (DCP 82/3659).

MWO EL1018, HPCS Pump Room Cooler Motor, Megger Motor and Clean Breaker

52-170117.

MWO ME1648, Inspection and Lubrication of Auxiliary Refueling Platform

and Hoist.

MWO IN3729, Calibration of FPCC Holding Pump Suction Pressure

Transmitter.

No violations or deviations were identified.

6. Surveillance Observation (61726)

The inspector observed the performance of portions of the surveillances

listed below. 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 criteria.

06-IC-SP64-SA-1001, Rev.22, PGCC Halon System Detectors and Supervisory

Panels Functional Test.

06-0P-1T48-M-0001, Rev.26, Standby Gas Treatment Operability.

. 07-S-53-109, Rev.4, Calibration of United Electric Pressure Switch for

CRDH Pump Suction Backwash Filter.

06-IC-1821-M-1002, Rev.25, Reactor Vessel Hi/ Low Pressure (RPS/RHR

Isol) Functional Test.

No violations or deviations were identified.

7. Engineered Safety Feature System Walkdown (71710)

A complete walkdown was conducted on the accessible portions of the Standby

Liquid Control System (SLCS). The walkdown consisted of an inspection and

verification, where possible, of the required system valve and breaker

alignment, including valve power available and valve locking where required;

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instrumentation valved in, functioning, and significant process parameter

values are consistent with normal expected values; electrical and instrumen-

tation cabinets free from debris, loose materials, jumpers and evidence of

rodents; and system free from other degrading conditions.

The SLCS was found to be operational such that it would perform its intended

function should it be called upon; however, there were discrepancies

identified by the inspectors as discussed below:

a. During the comparison between the SLC System Operating Instruction,

(S0I) 04-1-01-C41-1, Revision 20, and the SLCS P&ID M-1082, Revision

15, the inspectors found that inboard isolation, valve C41-F151, is

required to be locked shut by the valve lineup. However, Attachment I

of the SOI and the P&ID show the same valve locked open. The valve was

properly positioned. The inspectors also noted during the system

configuration inspection that the outboard stop check handwheel valve

C41-F006 was required to be open by the SOI, but the valve was in fact

locked open. The valve was in its correct position. The inspectors

informed the licensee of the above discrepancies. This shall be

tracked for correction under inspector followup item 416/86-21-01.

b. On July 29, 1986 the inspectors found valve C41-FX001, root valve for

pressure gage R003 and pressure transmitter N004, shut when it should

have been open in accordance with the above SOI. The pressure gage

indicated 425 psig, which was abnormal for SLC pump discharge pressure

(pressure should be nearly zero when the system is not pumping). The

SLCS pressure indicator in the control room indicated zero pressure.

When the valve was opened, the gage continued to indicate 425 psig. A

work request was initiated and the gage was subsequently repaired.

Technical Specification (TS) 6.8.1 states that written procedures shall

be established, implemented and maintained covering the applicable

procedures recommended in Appendix A of Regulatory Guide (RG) 1.53,

Revision 2, February 1978. Section 4.d in Appendix A of RG 1.33 lists

the SLCS as one of the recommended systems. Failure to follow SOI

04-1-01-C41-1, resulting in the isolation of SLC pump discharge

pressure instrumentation, is the first example of the violation of

TS 6.8.1 (86-21-02).

8. Reportable Occurrences (90712 & 92700)

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 actions.

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The following License Event Reports (LERs) are closed.

LER No. Event Date Event

• 83-185 December 1, 1983 Loss of power to Division I ESF

Bus & B0P loads86-008 February 24, 1986 Complete response time of

EOC-RPT System not measured

86-010 April 3, 1986 Inadvertent isolation of

Primary and Secondary

Containment

• 86-011 April 7, 1986 TS Shutdown due to open Safety

Relief Valves

• 86-020 June 3, 1986 Non-Qualified Relay could cause

Loss of SGTS

The event of LER 86-020 was discussed in Report 50-416/86-17 and is

inspector followup item 416/86-17-05.

The event of LER 86-011 was discussed in Report 50-416/86-11 and violation

416/86-11-03.

No other violations or deviations were identified.

9. Operating Reactor Events (93702)

The inspectors reviewed activities associated with the below listed reactor

events. 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, scram reports and had discussions with operations maintenance and

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engineering support personnel as appropriate.

a. On July 11, 1986, while preparing to perform Surveillance Procedure

(SP) 06-0P-1P75-M-0002, Standby Diesel Generator (SDG) 12 Functional

Test, the SDG 12 was inadvertently started. Paragraph 5.2.2 of SP

06-0P-1P75-M-0002 states to place SDG 12 in maintenance mode and

simultaneously press the remote (located on panel P864 in the control

room) and local (located on panel P401 in the SDG room) maintenance

mode select pushbuttons. The control room operator inadvertently

pushed the SDG 12 start button instead of the maintenance mode select

button. The SDG started and was immediately shut down. TS 6.8.1

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states that written procedures shall be established, implemented and

j maintained covering surveillance and test activities of safety related

equipment. The failure to follow SP 06-0P-IP75-M-0002, resulting in

the inadvertent start of SDG 12, is the second example of the violation

of TS 6.8.1 (86-21-02).

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b. At 3:20 p.m., on July 25, 1986, with the reactor at 885 MWe the reactor

scrammed on a Scram Discharge Volume (SDV) high-high water level. The

reactor operators carried out the scram procedure and all systems

operated as designed. A few minutes prior to the scram an operator had

noticed residual heat removal train A high conductivity alarm and the

alarm cleared with downscale indication on the conductivity meter.

Shortly thereafter, the plant chiller trip alarmed, circulating water

makeup flow was oscillating, several Division I valves on panel P870

had no valve position indication, plant service water header pressure

was high, and the scram pilot valve header pressure low alarmed on the ,

P680 panel. The control room operator started the Unit 1 instrument

air compressor and sent operators to the instrument air compressors to

verify local valve positions. The operator noticed reactor vessel

water level had dropped to +20 inches and was prepared to manually

scram the reactor when the automatic scram on SDV high-high level

occurred. When investigating the reason for the loss of valve position

indication noted above, the operators found main power breaker

52-153102 on panel 15831 open. Closing breaker 52-153102 restored the

instrument air and plant service water systems. Investigation revealed

several modification workers were working on a panel next to breaker

52-153102 and it appeared that someone inadvertently moved the breaker

to the open position. The opening of breaker 52-153102 resulted in

various auxiliary building Division I isolation valves going closed

which caused the 1oss of instrument air and plant service water. The

loss of instrument air eventually allowed the scram valves to open

which permitted control rods to start scramming individually. When the

scram discharge volume water level reached the high-high level a scram

signal was generated and all remaining control rods scrammed. The

operator had armed the manual scram push buttons and was preparing to

manually scram the reactor when the automatic scram occurred. The

alarm typewriter data indicates that the first rod scram valve opened

at 3:20 p.m., and the automatic scram was initiated 43 seconds later.

Data traces from the General Electric Transient Analysis Recorder

System (GETARS) show a perceptible decrease in power (MWe) approxi-

mately 15 seconds prior to the automatic scram. At that same time the

narrow range water level started trending down while feed water flow

and reactor core flow started increasing. The cause of the event is

the inadvertent opening of breaker 52-153102 by personnel working in

the area. The operators responded to the event, the plant recovery was

normal and all systems functioned as designed. The Site Director

stopped modification work in sensitive plant areas and before work can

resume, operations must review the work area with the appropriate

supervisor to ensure proper precautions are in place prior to starting

work. The reactor had been operating approximately 105 days contin-

ucusly at the time of the scram.

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c. At 9:54 p.m. , on July 30, 1986, the reactor operator was withdrawing

control rod 20-45 from notch 08 to notch 10 in a single notch

withdrawal. Rod 20-45 continued to slowly withdraw past notch 10 and

eventually stopped at full out (notch 48). The operator attempted to

stop rod 20-45 by giving an insert signal. This appeared to have

momentarily slowed the withdrawal motion but did not stop the

withdrawal. The rod was de-selected and reselected and the rod select

clear button was pushed during the withdrawal with no effect. During

the withdrawal sequence a rod drift alarm occurred and a rod block was

received. Also, the operators reduced reactor power to approximately

62% during the rod withdrawal. The rod withdrawal event took approxi-

mately three minutes. When the rod reached notch 48 a coupling check

was performed and then the rod was placed at notch 46 to verify the

ability to insert. It was verified that rod 20-45 was separated from

all other inoperable withdrawn control rods by at least two control

cells in all directions which satisfied Technical Specification 3.1.3.1

action statement for an inoperable control rod. To balance core power

distribution the three symmetrical control rods for rod 20-45 were also

pulled to notch 46. The licensee then decided the most conservative

action would be the alternate action discussed in Technical Specifi-

cation 3.1.3.1, and that was to drive rod 20-45, and the corresponding

symmetrical control rods, to full in (notch 0). Rod 20-45 was then

hydraulically isolated by shutting valves C11-F103 and C11-F105. On

July 31, 1986, after discussions with GE, the licensee replaced the

withdraw solenoid valve C11-F422 and cycled rod 20-45 through several

single notch withdraw and insert cycles successfully. The licensee has

subsequently revised emergency operating instruction 05-1-02-IV-1,

Control Rod / Drive Malfunctions, giving operators instructions for

actions to take in case a control rod continues to withdraw with no

withdraw command present. Inspection of the removed C11-F422 valve did

not reveal the cause of the withdrawal event. The licensee concluded

that debris trapped under the seat of the C11-F422 valve during the

original notch withdrawal cycle would allow drive water pressure to

hold the collet fingers out, thus allowing rod 20-45 to drift by its

own weight to the full out position, and subsequent cycling of C11-F422

had flushed out the seating surface and permitted normal operation

later.

10. Inspector Followup And Unresolved Items (92701)

(Closed) 85-28-03, Inspector Followup Item. The licensee has installed

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redesigned covers on the concrete pits which contain fuel oil fill and drain

valves for the Division I, II & III diesel generators. The new covers

should prevent excessive water from entering the pits.

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11. Design, Design Changes and Modifications (37700)

The inspectors reviewed Design Change Package (DCP) 84/3516 which replaced

existing time delay relays in the control room heating, ventilating and air

conditioning (HVAC) system with qualified time delay relays. Maintenance

Work Orders (MW0s) P61345 and P61346 were the work control documents used

for this modification. The documentation was properly signed and readily

retrievable. A completed 10 CFR 50.59 safety evaluation was in the package.

The listed drawings were verified to have been updated to reflect this

modification. An appropriate operability retest was accomplished prior to

returning the system to service.

No violations or deviations were identified.

12. Performance Indicator Trial Program (25580)

NRC Temporary Instruction 2515/80, Data Collection for the Performance

Indicator Trial Program, was issued on June 27, 1986, to provide guidance

for the collection of plant data in support of the performance indicator

trial program. This data would be used to augment the Systemmatic

Assessment of Licensee Performance (SALP) process and provide a more timely

identification of declining performance. Grand Gulf was chosen to be

included in this trial program of data collection. The resident inspectors

collected the data requested and forwarded it to regional management.

No violations or deviations were identified.

13. Preparation For Refueling and Refueling Activities (60705 & 60710)

The inspectors reviewed selected refueling procedures for technical adequacy

and incorporation of technical specification requirements. The licensee has

not completed issuing final versions of many refueling procedures at this

time. The licensee was interviewed regarding lines of supervision and

responsible people have been assigned in given areas. Also, the licensee

will issue a refueling organization chart which will be available to plant

personnel defining areas of responsibility during the refueling outage. A

refueling outage work schedule has been issued that defines what emergency

core cooling systems or shutdown cooling systems are required during defined

outage work stages, what work will occur in what order / time frame and

assumptions used to construct the schedule are defined in notes. New fuel

was received and stored onsite several years previously so review of new

fuel receipt and inspection was not conducted at this time.

No violations or deviations were identified.