ML20134D377

Insp Repts 50-321/96-11 & 50-366/96-11 on 960804-0914. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20134D377
Person / Time
Site:	Hatch
Issue date:	10/11/1996
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20134D372	List: ML20134D370 ML20134D374 ML20134D377
References
50-321-96-11, 50-366-96-11, NUDOCS 9610220090
Download: ML20134D377 (38)

See also: IR 05000321/1996011

Text

.. ._. . _ _ _ . .

.

.

U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos: 50-321, 50-366

License Nos: DPR-57 and NPF-5

Report No: 50-321/96-11, 50-366/96-11

Licensee: Georgia Power Company (GPC)

Facility: E. I. Hatch Units 1 & 2

Location: P. O. Box 439

Baxley, Georgia 31513

Dates: August 4 - September 14, 1996

Inspectors: B. Holbrook, Senior Resident Inspector '

J. Moorman, Senior Resident Inspector l

(Acting) l

E. Christnot, Resident Inspector

G. Salyers, Emergency Preparedness

Specialist (Sections P2, P3, PS, P6,

P7, P8)

J. Canady, Resident Inspector

l

l

Approved by: P. Skinner, Chief, Projects Branch 2

Division of Reactor Projects

Enclosure 2

9610220090 961011

gDR ADOCK 05000321

PDR

_.

. .. . -- _ _ - _ - - . _ - - - . . - - . . - . . _. - .

.

.

i

EXECUTIVE SUMMARY

Plant Hatch, Units 1 and 2

l NRC Inspection Report 50-321/96-11, 50-366/96-11

!

l This integrated inspection included aspects of licensee

operations, engineering, maintenance, and plant support. The

report covers a 6-week period of resident inspecticn; in addition,

it includes the results of an announced inspection ay a regional

emergency preparedness specialist.  !

l

Operations l

e The inspector concluded that operator response to the

l Reactor recirculation pump tr p on August 20, was excellent.

l

Actions taken were prompt, deliberate, and in accordance

with plant procedures. The immediate observations by the

Shift Technical Advisor to assist the operators in use of

the power / flow operating map was excellent (Section 01.2).

• The inspector reviewed a special report dated July 30, 1996,

involving an inoperable reactor vessel water level flood-up

range instrument. The report did not clearly indicate how

to compensate for the lack of monitoring capability above

+60 inches should this be required during post accident

conditions. However, the lack of clarity was not considered

significant. The licensee is considering a TS amendment to

address this issue (Section 02.1).

• The license conditions required for the Technical

Specification Improvement Program (TSIP) implementation for

Unit 1 and Unit 2 are complete with the exception of the

ten-year surveillance requirements for the emergency diesel

generators (Section 03.1).

• A Safety Review Board (SRB) meeting was attended on

September 12. The inspectors concluded that the meeting met

the applicable requirements and that the SRB is providing

adequate review and auditing functions (Section 07.1).

• The licensee activities involving the river conditions

demonstrated a , pro-active attitude on the part of plant

management and is considered a strength (Section 01.1).

o Operation and Maintenance Department personnel routinely use

a risk matrix to perform an assessment of the total plant

equipment out of service to determine the overall effect on

performance of safety functions per' 10 CFR 50.65 (a) (3) ,

" Requirements for monitoring the effectiveness of

maintenance at nuclear power plants" (Section 01.1).

l Maintenance

e Maintenance and surveillance activities were performed

thoroughly and professionally. The inspectors observed that

personnel were knowledgeable in the assigned task;

l procedures were in use; activities were well documented; and

j administrative controls were implemented.

.

,

. l

i

GPC 2

l

Encineerino

e VIO 50-321/96-11-02: Failure to Perform an ASME Code- l

Required VT-3 Inspection on High Pressure Coolant Injection

(HPCI) Valve 1E41-F006, was identified. The failure to l

perform an American Society of Mechanical Engineers (ASME) l

Code-required VT-3 inspection on a safety related component l

was considered significant (Section E2.2).

• The inspectors conducted followup inspections on licensee

activities with respect to the Unit 2 Station Service l

battery. No immediate operability concerns were identified. I

Onsite engineering was taking appropriate pre-installation

measures to ensure replacement battery cells remained in the

proper condition (Section E7.1).

Plant Support

• A Non-Cited Violation (NCV), 50-366/96-11-03, for failure to

follow valve line-up procedures when performing a torus

water sample was identified (Section R1.2).

• Poor sampling technique was the most likely cause for the

stored fuel oil analysis results that were out of

specification on August 8. Attention to detail during the

sample analysis collection process may prevent similar

problems. This was identified as an area for improvement in

the chemistry sampling process (Section R4.1) .

• The Emergency Preparedness (EP) facilities and equipment

were at a satisfactory level for operational readiness;

Emergency Operating Facility (EOF) ventilation was tested

and maintained adequately; and the tone alert radio system

was reliable, tested and maintained (Section P2).

• The licensee's review process for EP procedures and

documents was satisfactory and met the requirements of

10 CFR 50.54 (q) . The declaration of the Notification Of

Unusual Event (NOUE) on March 20, 1996, was properly

classified and the applicable Emergency Implementing

Procedures (EIP) were implemented (Section P3).

e The licensee maintained a satisfactory EP training program

and satisfactorily met their drill requirements

(Section PS).

• No significant personnel changes were made since the last

inspection (April, 1995) that would effect the performance

or maintenance of the EP program (Section P6).

• An audit was not conducted in accordance with the Audit

Planning Matrix, however, the aggregate of the audit

elements satisfied 10 CFR 50.54 (t) (Section P7).

!

l

[

Enclosure 2

.

GPC 3

• Quality Assurance (QA) auditors were qualified and EP issues

were satisfactorily trackei. and resolved in a timely manner

(Section P7).

• Tne inspectors' review of the status of plant security

f acilities and equipmer.t did not identify any deficiencies ,

(Section S2). i

!

l

l

l

l

Enclosure 2

_- . . _ - _ . .. . . - - - . ~ . - - . _ - . - - . - - . . _ - . . . ._ ~ - ._-

'

1

. 1

GPC 4

Report Details

Summary of Plant beatus

l

Unit 1 began the report period at 100% rated thermal power (RTP). '

On August 20, power was reduced to about 30% RTP due to a trip of I

a reactor recirculation pump motor generator (MG) set and a l

subsequent runback. The trip occurred when the air high '

temperature switch was bumped during housekeeping activities and

the runback was due to the quick opening of a reactor feed pump

minimum flow valve (paragraph 01.2). Power was returned to RTP

and the unit operated at 100% RTP for the remainder of the report

period except for routine testing activities.

Unit 2 operated at 100% RTP throughout the report period except

for routine testing activities.

I. Ooerations

l

!

l 01 Conduct of Operations

l 01.1 General Comments

a. Insoection Scoce (71707)

Daily reviews of plant operation were conducted using

Inspection Procedure 71707, Plant Operations. The conduct

of operations was generally professional and safety-

conscious. Specific events and noteworthy observations are

detailn: in the section below.

b. Observations and Findings

The inspectors discussed the electrical harmonics observed

, on the Units 1 and 2 Emergency Diesel Generator (EDG) 4160

l

volt (V) switchgear (Reference paragraph E2.1) with licensee

personnel. The inspectors reviewed the EDG surveillance

procedures. The operators are instructed by the procedures

to quickly load the EDGs once they are in parallel with the

grid. The inspectors observed that there was no discussion

in the procedure about the harmonics and the possible effect

on the reverse power trip. The inspectors also observed

that there was no discussion about the possibility of a

reverse power trip while unloading the EDGs in preparation

! for removal from the grid. The inspectors were informed

I

that the Engineering Department was performing a review of

the effects of the electrical harmonics.

The inspectors monitored the licensee's activities involved

with the river water level, temperature, and the debris

being pulled into the cooling water systems. The licensee

contracted to have the area in front of the intake structure

Enclosure 2

_

- . . . . __ _ .._ _ - . _ _ . _ . _ _._ _ _ _ _ _ _ _ _ _ _ _ . . . _ . . . _ .-

i

I .

GPC 5

dredged. Divers were also contracted to clean sediment and l

debris from the bottom of the intake water bays. The

inspectors were informed that algae and floating moss were

clogging various chiller systems and cooling water heat

exchangers. The inspector attended meetings at which these

problems were discussed. The licensee developed an action

i plan to better cope with the algae and the floating moss.

l Parts of the plan called for closer monitoring'of chiller

l systems and cooling water heat exchanger performance.

One portion of the maintenance rule, 10CFR50. 65 (a) (3 ) ,

l states, in part, "an assessment of the total plant equipment

that is out-of-service should be taken into account to

determine the overall effect on performance of safety

functions." On several occasions the inspectors observed

l licensed' operators using a matrix governed by Procedure

l 90AC-OAP-002-OS, Scheduling Maintenance. The matrix

l provides Technical Specification (TS) and risk-informed

l guidance to be used when removing combinations of equipment  ;

l from service. The matrix indicated that if a Control Rod )

'

l Drive (CRD) pump was out-of-service it would be a medium

l risk to take the HPCI out-of-service and it would be a low .

l risk to take out a loop of core spray. The matrix also 1

'

l' indicated that if the HPCI was out-of-service, it would be a

high risk to remove a loop of Low Pressure Coolant Injection

, (LPCI) from service and a medium risk to remove a Residual

'

Heat Removal Service Water (RHRSW) pump. The instructions

on the matrix indicated the.following:

-

For a high risk removal from service (Required Action

Statement (RAS) 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or less, or Risk Achievement

!" orth (RAW) equal to or greater than 10), a risk

evaluation was required, and approval by the operations

manager was required.

-

For a medium risk (Limiting Condition for Operation (LCO)

l

less then 7 days, or RAW more than 5 but less then 10)

the approval by the operations manager was required.

-

For a low risk (LCO equal to or more then 7 days, or RAW

1ess then or equal to 5) the approval by the

Superintendent On Shift (SOS) was required.

Two laminated copies of the matrix were available in the

Control Room.

c. Conclusions on General Comments

The inspectors considered the EDG harmonic item to be a

potential for possible erroneous reverse power trips, which

i

could lead to operator confusion.

!s

!

} Enclosure 2

i

- -- - , ,- .,

. -. , ~ . . . . - . - - - _ - . . - .-. - - - - - - . - - - - . .. -- - - - - .

.

.

1

GPC 6

'

The licensee activities involving the river conditions l

demonstrated a pro-active attitude on the part of plant

management and is considered a strength.

Use of the matrix to evaluate risk associated with removing

i various combinations of equipment from service is consistent

i with the maintenance rule. This and other aspects of the

l licensee's implementation of the maintenance rule will be

inspected further in the near future.

01.2 Transient Due to Recirculation Pumo Trio and Runback (Unit

11

a. InsDection Scoc? (71707)

At 9:12 a.m. on August 20, with Unit 1 operating at 100%

RTP, the 1A Reactor Recirculation (RR) Pump tripped. An

inspector responded to the control room to assess operator

actions and unit response. The inspector observed operator

monitoring of annunciators and parameter trends.

Communications, supervisory control, and the use of

procedures were also observed. Among the procedures used by

the operators were:

-

34AB-C51-001-1S: Reactor Power Instabilities, Rev. 3

l

'

-

34SV-SUV-023-1S: Jet Pump and Recirculation Flow

Mismatch Operability, Rev. 6, Edition 1 j

-

34SO-B21-001-1S: Reactor Recirculation System, Rev. 4, 1

Attachment 6, Power Versus Flow Map

-

34GO-OPS-065-1S: Control Rod Movement, Rev. 14

-

34GO-OPS-055-OS: Power Changes, Rev. 18

b. Observations and Findinos

The operators immediately implemented and appropriately used

applicable procedures in response to the transient. At

about 9:16 a.m. the Shift Technical Advisor (STA) identified

and reported to the crew that the unit was within the region

of potential instability. Reactor power had decreased to

69% RTP with 49.8% core flow. At STA and Shift Supervisor

(SS) direction, flow was increased slightly on the 1B RR

pump. At 9:21 a.m. the STA informed the shift that the

region of potential instability had been exited.

In preparation to start the tripped pump, control rods were

inserted to get below the 55% load line, as required by

procedure. As operators prepared to place the 1A Reactor

Feed Pump Turbine (RFPT) in standby, a runback on the 1B RR

pump occurred due to low reactor water level. The operators

noted that the runback occurred in conjunction with the 1A

Reactor Feedwater Pump (RFP) minimum flow valve opening.

The region of potential instability was again entered.

l

l

l

l Enclosure 2

i

I

. - , _-- - .

. - _ _ - _ .__ . _ _ - . _ . . ~ . _ _ _ _ - . _ __ _ __ _ . _ _ . _ _

.

.

GPC 7

Control rods were inserted and the region was exited in

about eight minutes.

The licensee determined that the 1A RR pump trip was caused

by a painter performing work in the recirculation pump Motor

Generator (MG) set room. A high MG set air temperature

switch was bumped and caused a trip of the MG set.

Maintenance personnel tested the switch to verify proper

operation and no deficiencies were observed.

Systems were placed in service and unit RTP was reached at

about 7:45 p.m.

c. Conclusions

The inspector concluded that operator response to the

transient was excellent. Actions taken were prompt,

deliberate, and in accordance with plant procedures. The

immediate observations by the on-shift STA to recognize the

reactor was in the area of potential instability was

excellent. The RFP minimum flow valve problem continues to l

l contribute to unplanned plant transients. The inspectors

'

will review additional information on the minimum flow

valves.

02 Operational Status of Facilities and Equipment

02.1 Inocerable Reactor Flood-Un Rance Reactor Water Level ,

Instrument Unit i l

a. Insoection ScoDe (92901)

The inspector reviewed a special report dated July 30, 1996,

involving the reactor vessel water level flood-up range

instrument, 1B21-R605.

b. Observations and Findinas

On July 21, 30 days had elapsed since flood-up range reactor

vessel water level instrument 1B21-R605 was declared

inoperable. The inspectors reviewed the licensee's special

report dated July 30, 1996, submitted to meet Technical

Specification (TS) requirements. The TS required that a

report be submitted within the following 14 days. The

inspectors found from this review that the report was

submitted within the time frame of the specifications. The

TS further states that the report shall outline the

preplanned, alternate method of monitoring, the cause of the

inoperability, and the plans and schedule for restoring the

instrumentation channels of the function to operable status.

The inspectors observed that the report stated the cause of

the inoperability appeared to be the result of a reduction

in the instrument reference leg water level. This was due

Enclosure 2

_ - .-- .-. .-

l

l

'

l

1

GPC 8

l to a packing leak on the equalizing valve for the

I transmitter of instrument 1B21-R605. The leak was repaired

I

'

and the condensation in the reference leg condensing pot was

expected to refill the leg. This did not occur and proper

instrument function was not restored.

The licensee did not determine why the condensing pot failed

to refill the reference leg. The report further stated that

to refill the reference leg by injecting demineralized water

would impose a risk to the instrumentation that could cause

a plant transient.

The report contained plans and a schedule for restoring the

instrument channel to operable status.

The inspectors found that the report did not directly

address the preplanned alternate method of monitoring. The

report stated that the flood-up instrument was indicating 29

to 30 inches higher than actual level as measured by other I

instruments. The method discussed in the report involved I

other instrumentation that only indicate up to +60 inches.

This indicated to the inspector that for post accident

,

monitoring purposes, water level can only be monitored up l

l +60 inches. The report did not clearly state that between

+60 inches and +400 inches no alternate method of monitoring

was available.

The inspectors discussed the report with licensee personnel.

The inspector observed that the licensee issued a temporary

change to the Unit 1 scram procedure, 34AB-C71-001-1S,

Revision 6, that reduced the required Main Steam Isolation

Valve (MSIV) closure on high level from +100 inches to +60

inches. This would help protect Emergency Core Cooling

Systems (ECCS) steam-driven turbines.

l

The licensee informed the inspectors that, even though the

instrument was listed as a TS post accident monitoring

instrument, the non-redundant instrument was not intended to

be used during post accident conditions. The instrument was

to be used only during refueling conditions when water level

is raised to flood the refueling cavity. The inspectors

reviewed licensee-supplied documentation that supported the

intended use of the instrument. The licensee was evaluating

this problem for a TS amendment.

c. Conclusions

l

The inspectors concluded that the report did not clearly

indicate the lack of monitoring capability during post

accident conditions above +60 inches. However, the lack of

clarity was not considered to be significant. The

inspectors viewed a proposed TS amendment as appropriate.

The revision to the scram procedure was also appropriate.

4

Enclosure 2

.. - - -. . . . - . _ _. . . , ~ . . . . .-.

.

.

GPC 9

03 Operations Procedures and Documentation

03.1 License Conditions for TSIP Imolementation Units 1 and 2

a. Inspection ScoDe (92901).

License condition 2.C. (2) for Units 1 and 2 states, in part:

The Surveillance Requirements (SRs) listed are not required

to be performed immediately upon implementation of

Amendments No. 195 for Unit 1 and No. 135 for Unit 2. The

SRs listed shall be successfully demonstrated prior to the

time and condition specified for each.

b. Observations and Findinos

The inspector observed that license condition 2.C.(2)a)

stated that the listed SRs shall be successfully

demonstrated prior to entering MODE 2 on the first plant

startup following the sixteenth refueling outage for Unit 1

and the twelfth refueling outage for Unit 2. The license

condition listed the SRs for both units, Unit 1 only and

Unit 2 only as follows:

Listed for both units:

- 3.3.2.2.2 Perform channel calibration for the Feedwater

and Main Turbine Trip High Level

Instrumentation.

.

- 3.3.2.2.3 Perform logic system functional test for the

! Feedwater and Main Trip High Level

Instrumentation.

- 3.3.3.2.2 Verify each required control circuit and

transfer switch is capable of performing the

intended function for the Remote Shutdown

System.

l - 3.3.8.1.4 Perform logic system functional test for Loss of

l Power Instrumentation.

- 3.7.7.2 Perform a system functional test for the Main

Turbine Bypass System.

- 3.7.7.3 Verify the Main Turbine Bypass System response

time is within limits.

Listed for Unit 1 only:

- 3.3.1.1.15 Perform logic system functional test for

Reactor Protective System Instrumentation.

,

f

Enclosure 2

{

1

. . . _ _ _ - --

.

.

GPC 10

- 3.3.1.1.16 Verify the RPS response time is within ,

(Function 9) limits for the turbine control valve fast I

closure, trip oil pressure - low.

- 3.3.6.1.6 Perform logic system functional test for

(Function 1.f) Turbine Building Area Temperature - High.

Listed for Unit 2 only:

- 3.6.2.4.2 Verify each spray nozzle is unobstructed for the

Residual Heat Removal (RHR) Suppression Pool

Spray System.

License condition 2.C.(2)b) stated that the listed SRs shall

be successfully demonstrated at their next regularly

scheduled performance. The license condition listed the SRs

for both units and Unit 2 only as follows:

Listed for both units:

- 3.8.1.8 Verify each EDG operating at or less than a

specific power factor and does not trip and

adequate voltage is maintained following a load

reject of a specified kilowatt (kw) load.

- 3.8.1.10 Verify on an actual or simulated ECCS' initiation

signal that each EDG auto-starts from the

standby condition and in a specified time after

auto-start achieves adequate voltage and, after

steady state conditions are reached, maintains

an acceptable voltage; in the same time after

auto-start achieves adequate frequency and after

steady state conditions are reached, maintains

an acceptable frequency; and operates for at

least 5 minutes.

- 3.8.1.12 Verify each EDG operating at a specified power

factor for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; for at least 2

hours loaded at a high kw; for the remaining

hours of the test loaded at lower kw.

- 3.8.1.13 Verify that each EDG starts and achieves, in

equal to or less than 12 seconds, voltage equal

to or greater to 3740 V and frequency equal to

or greater than 58.8 hertz (Hz); and after

steady state conditions are reached, maintains

voltage between 3740 V and 4243 V and frequency

between 58.8 Hz and 61.2 Hz.

- 3.8.1.18 Verify, when started simultaneously from standby

condition, that all of the Unit 1 and all of the

Unit 2 EDGs achieve, in less than or equal to 12

seconds, voltage greater than or equal to 3740 V

and frequency greater than or equal to 58.8 Hz.

Enclosure 2

- - . _ _ _ . _ _ _ _ _ _ . _ -_- . - _ _ _ . - . . _ _ _ _ _ ._ ___ -

,

'

l

'

.

GPC 11

Listed for Unit 2 only:

- 3.8.1.9 Verify on an actual or simulated loss of offsite

(for EDG 2C) power signal: De-energization of emergency

busses; load shedding from emergency buses; the

EDG auto-starts from standby condition and;

energizes permanently connected loads in a

specified time, energizes auto-connected

emergency loads through automatic load sequence

timing devices, achieves adequate steady state )

voltage, achieves adequate steady state I

frequency, and supplies permanently connected

and auto-connected emergency loads for at least

5 minutes.

-

3.8.1.17 verify that on an actual or simulated loss of l

(for EDG 2C) offsite power signal in conjunction with an

actual or simulated ECCS initiation signal that

the EDG meets the same requirements as that of

the above listed SR 3.8.1.9.

License condition 2.C.(2) c) stated that the listed SRs will

be met at implementation for the secondary containment

configuration in effect at that time. The SRs shall be

successfully demonstrated for the other secondary

containment configur4tions prior to the plant entering.the

LCO applicability for that configuration. The license

condition listed the SRs for both units as follows:

- 3.6.4.1.3 Verify required Standby Gas Treatment (SGT)

subsystem (s) will draw down the secondary

containment to greater than or equal to 0.20

inches of vacuum water gauge in less than or

equal to 120 seconds.

- 3.6.4.1.4 Verify required SGT subsystem (s) can maintain a

greater than or equal to 0.20 inches of vacuum

water gauge in the containment for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at a

flow rate greater than or equal to 4000 cubic

feet per minute (cfm) for each subsystem.

The inspectors observed that the license conditions for both

units covered a total of 32 SRs. To determine the

I compliance to the license conditions 2.C.(2) a) and b) the

inspectors were provided information in the form of two

matrices, one for each unit. The matrices listed the TS

surveillance requirement, commitment number, responsible

group, procedure (s) performed to meet the requirement (due

by plant condition, such as prior to Mode 2), date completed

and any comments. For license condition 2.C.(2) c), which

l involved the secondary containment, the inspectors were

! provided with dates on which the applicable surveillances

were performed.

f

!

4

Enclo.3ure 2

- - . - . -. . . ~ -. . -- . - - . - . .. - ..- .- - .

1

1

l

i

.

GPC 12

1

The inspectors reviewed the matrices and observed that the

i surveillance requirements for license conditions 2.C.(2) a)

j and b) corresponded to the applicable plant procedures. The l

,

requirements for Unit 1 were performed during spring 1996 '

i refueling outage and for Unit 2 during the fall 1995 i

i refueling outage. The inspectors observed that the  ;

4

completed procedures were_the applicable procedures for the l

license conditions. However, SR 3.d.1.18, a simultaneous

l start of all the respective EDGs for both units was not

performed. This SR has a frequency of 10 years. The due

l date for Unit 1 is March 1, 2003 and for Unit 2 is i

a February 1, 1997. The inspectors observed that the required

surveillance for the license condition 2.C. (2) c) were also

performed as required for both units.

! The inspectors documented SR activities associated with the

.

TSIP and sections of the license conditions in irs 50-321,

! 366/95-08, 95-22, and 95-23.

!

, c. Conclusions

i

i The inspectors concluded that license conditions 2.C.(2).a)

and c) are fully closed for both units. License condition

2.C. (2) b) will be fully closed when SR 3.8.1.18 is

performed for the respective units.

07 Quality Assurance in Operations

07.1 Licensee Self-Assessment Activities (40500)

On September 12, the Hatch SRB convened meeting H96-03 at '

Plant Hatch. The meeting was conducted in accordance with

the requirements of the Hatch Final Safety Analysis Report

(FSAR) and QA Manual. The board discussed the status of

previously-opened items and determined which items should be

closed. Much of the discussion centered on the past l

problems experienced by the Operations and Engineering

Departments and their solutions. New issues were identified

and assigned to the copropriate manager for resolution.

There was some discussion involving the quality of

contractor work, particrictly that of the plant's Nuclear

Steam Supply System (NSSS) vendor. Various problems were

discussed, along with solutions and ways of avoiding future

problems. The inspectors concluded that licensee efforts in

this area for self-assessment were effective.

08 Miscellaneous Operations Issues (92901)

08.1 (Closed) Unresolved Item (URI) 50-321.366/96-07-01:

Determine Safety Significance and Testing Requirements for

Unit 1 and Unit 2 Containment Isolation Status Panel.

The inspector reviewed Abnormal Operating Procedure,

34AB-C71-001-1S and 2S, Scram Procedure, Revision 6, for

Enclosure 2

_ - . _ . _ . _ . _ _ _ __ - _~__ _ _. _ _ . - _ _ . _ _ _ _ _ _ . _ . .

1

a *

-

'

GPC 13

i

both units. The procedures made a general reference that

isolation status could be found on Panel 1/2-H11-P601

i vertical display. The procedures also listed other

+

locations, such as the Safety Parameter Display System

(SPDS) where system isolation indications could be located.

.

.

The inspectors reviewed both the Unit 1 and 2 UFSARs to

i determine the isolation panels description and use. Unit 1

i FSAR Section 5.2.3.5.2 states in part, "A mimic display

J

board for only isolation valves provides indication of

l isolation valve position. When isolation has occurred, all

, energized lights of the display are green".

i I

] The UFSAR for Unit 2, Section 7.3.2.2, System Description - 1

i Primary Containment and Reactor Pressure Vessel Isolation l

} Control System; Subsection 7.3.2.2.7, Testability, states, l

'

in part, " Isolation valves can be tested to ensure that they

l are capable of closing by operating manual switches in the

j Main Control Room (MCR) and observing the position lights

i-

'

and any associated process effects". The subsection directs

the reader to "See also figure 7.3-2 (Nuclear Boiler System

- Functional Control Diagrams)." The inspector reviewed the

figure and observed that it contained 12 sheets of logic

diagrams with control switch and indicating light MCR panel

locations. The diagrams for the isolation valves clearly

showed indication lights for both the opened and closed

positions on the graphic display located on MCR panel i

2H11-P601. I

From reviews, observations, and discussions with licensee

personnel, the inspectors found that the isolation status

panels were used by the operators to verify isolation

status; are being maintained current with plant design

changes; and are referenced in plant procedures and the

UFSARs for both units.

The inspectors did not locate any procedure that required

testing or verification that the isolation panel indications

correctly reflected system status or isolation condition.

The inspectors frequently observed operators monitoring the

isolation panel during normal panel observations. The

inspectors also observed that Design Changes (DCs) were

initiated when required to properly maintain the panels. ,

'

The inspectors were not aware of any discrepancy between the

isolation panel indications and plant systems.

The inspectors observed that Operations management issued an

operating order instructing control room operators to

observe and record light indications that could be monitored

from the isolation status panel for all valves that were

cycled. Also, plant procedures were to be revised to

include verification of indication response for valves

Enclosure 2

_ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ - _ . _ . _ _ _ _ _ . _

-- -_

- . _ .. _ _ _ _ _.- _.__ _ - _ _ _ . _ . _ _ _ _ . _ . _ . . _ . _ _ _ . - .__.. _ _ -

1

-

' GPC 14

, located on the isolation status panel. Most of the checks

<

will be conducted during unit cold shutdown conditions.

The inspectors determined that although the failure to test

or verify the isolation valve indications on the isolation

status panels was an oversight, no regulatory violation had

occurred. Based upon this review URI 50-321, 366/96-07-01

is closed.

b. Conclusions

Systems that are used by the operators to verify the status

of safety-related systems and are discussed in the UFSAR

should be tested or verified periodically.

'

08.2 (Closed) Licensee Event ReDort (LER) 50-321/96-011:

Inadequate Procedure Results in Missed Technical

, Specifications Surveillances. This problem was discussed in

j Inspection Report (IR) 50-321, 366/96-10. No new issues

were revealed by the LER.

i

08.3 (Closed) Violation (VIO) 50-321/95-23-01: Operators'

Failure to Follow Procedure While Transferring Diesel Fuel

011. This violation was identified when operators were

receiving new fuel oil from a tanker truck. Due to a valve

lineup, not in accordance with procedure, 300 gallons of

>

fuel overflowed a day tank. The inspector reviewed the

) licensee's response, dated January 2, 1996. The response

indicated that administrative personnel action was taken and

that procedure changes were being considered. The

- inspectors reviewed the EDG procedure 34SO-R43-001-1S,

Revision 18, and observed procedure changes. These changes

included a simplified drawing of the fuel oil system piping

and valves. This drawing was to aid personnel in

determining the correct valve line up for the activity to be

performed.

08.4 (Closed) VIO 50-366/95-26-01: Inability to Safely Shutdown

'

,

Unit 2 from the Remote Shutdown' Panel in the Event of a Fire

in the Main Control Room. This violation was identified

when operators attempced to perform a surveillance on the

Unit 2 Remote Shutdcwn Panel (RSDP). The surveillance was

being performed for the first time because of the TSIP.

Prior to the implementation of the TSIP, testing of the RSDP

'.

was not required. The inspectors reviewed the licensee's

response, dated February 12, 1996. The response indicated

that failure to perform periodic testing, as well as

inadequate design and design change functional testing,

contributed to the violation. This item was initially

documented in IR 321,366/95-23. Subsequent licensee and

inspector activities were documented in irs 321,366/95-26

and 95-27. These activities included observed licensee

corrective actions involving system testing, maintenance and

Enclosure 2

,

R

.+-

-

- - , - , n , - - - . , --,--e . , - - -,e-. ..,-.4 - - -

1

l

l

.  :

.

GPC 15

l

modification work. The inspectors concluded that the

licensee's corrective actions had been appropriate.

1

l

08.5 (Closed) VIO 50-321.366/95-18-02: Failure to Follow

Procedure, Second Example. This example was identified when 1

operators failed to follow a procedure while performing. l

hydrogen water chemistry flow changes. This resulted in

'

unnecessary exposure to personnel performing maintenance in

the condenser bay. The inspectors reviewed the licensee's

response dated October 26, 1995. The response indicated

that a less-than-adequate operating procedure and less-than- l

adequate training contributed'to the violation. The

response stated that personnel were counseled regarding

their actions, training material would be revised, and

procedure changes would be made. The inspectors reviewed

the revised material and procedure changes and concluded

that the licensee's corrective actions had been appropriate.

II. Maintenance

M1 Conduct of Maintenance

M1.1 General Comments

a. Inspection Scoce (62703) (62707)

The inspectors observed all or portions of the following

work activities:

-

MWO 2-96-2492: . Replace seal on 2B Plant Service Water

(PSW) Pump

-

MWO 2-96-2586: Insulation inspection of Reactor

Protection System (RPS) MG Set 2A

-

MWO 2-96-2131: RPS MG Set Minor Design Change (MDC)

95-5037 Implementation

b. Observations and Findinas

The inspectors found that the work was performed with the

work packages present and being actively used. The

inspectors observed that during the implementation of the

MDC the system engineer was present at the job site.

Appropriate post-modification and maintenance tests were

performed. These tests consisted of operating the equipment

following the completion of work activities.

c. Conclusions on Conduct of Maintenance

Maintenance activities were generally completed in a

thorough and professional manner. No deficiencies were

identified.

Enclosure 2

,-- , . - - - . - - ~ - - . _. - - . -..- - . . . . ~ - - . . - --.

l

!

!

l

l GPC 16

l

l

M3 Maintenance Procedures and Documentation

l

l M3.1 Surveillance Observations

l

l a. Inspection Scoce (61726)

The inspectors observed all or portions of the following

Unit 1 and Unit 2 surveillance activities:

- 34SV-R43-004-1S: Diesel Generator 1A semi-annual test

- 34SV-E41-002-2S: HPCI Pump operability l

b. Observations and Findings

The HPCI surveillance observed was the three-month

operability test to meet TS and AMSE Code In-Service Testing l

requirements. Data was collected on system valve stroke i

times and pump operating characteristics. A pre-evolution I

! briefing was conducted by the licensed operator performing ,

l the surveillance. All personnel involved were in I

attendance.

The diesel surveillance was performed without problem and

all parameters were within specification.

c. Conclusions l

l For both surveillances, all data was within the required ,

!

range and the equipment was determined to pass the

surveillance. The performance of the operators and crews

conducting the surveillances was generally professional and

competent. No deficiencies were identified.

M8 Miscellaneous Maintenance Issues (92700) (92902)

M8.1 (Closed) LER 50-366/96-03: High Pressure Coolant Injection

i System Temporarily Inoperable Following Engineering Safety

I

Feature Actuation. The cause of this problem was a physical

" slip" that occurred when a technician was manipulating a

piece of test equipment during surveillance testing

l

'

activities. The system responded as expected. As part of

the corrective actions, management discussed the problem

with the technician and suressed the importance of caution

when performing test act.vities. The system was realigned

to the operable (standby' condition.

M8.2 (Closed) VIO 50-321,366/95-18-02: Failure to Follow

Procedure, First Example. This example was identified when

divers entered the intake structure pump pit area to perform

inspection activities without the use of a procedure. A

service water pump was declared inoperable when a section of

the diver's life, air and communication line entered the

suction of the pump. The inspector reviewed the licensee's

response dated October 26, 1995. The response indicated

Enclosure 2

l

l

.. ._ __ _. _ _ _ _ . . ._. _ __ . _ _ . _ _ _ _ _ .

.

'

.

4

GPC 17

that miscommunications among personnel regarding the use and

i applicability of a procedure contributed to the violation.

The response stated that administrative personnel action was

taken, procedure changes would be made and signs would be

posted. The inspectors reviewed the procedure changes and

observed the posted signs. The inspectors concluded that

the licensee's corrective actions had been appropriate.

III. Encineerina

E2 Engineering Support of Facilities and Equipment

,

E2.1 Harmonics on Safety Related EDG 4160 V Switchaear

,

a. Insoection Scope (92903)

i The inspectors performed followup activities involved with

,

4

electrical harmonics discussed in IR 50-321, 366/96-06.

i

b. Observations and Findinas

} The inspectors observed electrical data supplied by licensee

personnel. The data clearly indicated the presence of

]

harmonics on both Unit 1 and Unit 2 EDG 4160V switchgear.  ;

, The harmonics appeared to be identical on all safety-related

j 4160V switchgear on both units.

The inspectors discussed the harmonics with licensee

personnel. The inspectors were informed that the harmonics

=

could possibly cause reverse power trips of the EDGs when

they were in parallel with the grid and operating at low

power. The inspectors were also informed that the manner in

e

which the switchgear was instrumented, on what phases the

i voltage and current were sensed, could be changed to help

prevent unnecessary reverse power trips. Under current

j conditions the CR operators could possibly have erroneous

, indication on an EDG and due to the harmonics get a reverse

j power trip.

i

'

c. Conclusions

, The engineering group was actively pursuing a solution to

j ~

the effects of the harmonics on EDG operation and testing.

At the end of this report period, the inspectors concluded

i

that the information about the effects of the harmonics had

not been forwarded to the Operations Department.

Recommendations to assist the operators in mitigating the

harmonic effects on EDG operation had also not been

i forwarded. EDG reverse power trips during surveillance

1

testing has been a problem at the site. Some of the reverse

, power trips were due to personnel error and inattention to

detail while the root cause of others was inconclusive. The

inspectors were informed that the potential harmonic effects

on EDG operations was being reviewed by the Engineering

.

Enclosure 2

.

.

GPC 18

Department. The results of the review will be forwarded to

the Operations Department. This is identified as Inspector

-

Followup Item (IFI) 321, 366/96-11-01: Review of

Engineering Report on the Effects of Harmonics on EDG

Operation.

E2.2 ASME Code Insoection Not Performed

a. Inspection Scope (92903)

The inspectors followed up the licensee activities involving

a missed ASME code-required inspection of Unit 1 HPCI

injection valve, 1E41-F006.

b. Observations and Findinas

, The inspectors identified a violation in IR 50-321,

366/96-06 involving activities associated with missed VT-3

inspections for three valves. The VT-3 inspections were

required by procedure but only the HPCI valve required a

VT-3 inspection in accordance with the ASME code.

During the inspectors' initial review of the problem, the

inspectors were informed that a VT-3 inspection was

performed on HPCI valve 1E41-F006, in conjunction with a

cleanliness inspection conducted by contract personnel. The

inspectors reviewed licensee-supplied documents and agreed

with the licensee's assessment that an adequate VT-3

inspection had been performed.

On August 12, the licensee informed the inspectors that new

information had been received from the contract personnel

who performed the cleanliness inspection. This led site

personnel to conclude that an adequate VT-3 inspection had

not been completed. As a result, an ASME code-required post

maintenance VT-3 inspection was not performed.

The inspectors reviewed the licensee's testing of the valve

and the valve's performance since the completion of the

maintenance activities and the missed VT-3 inspection. No

deficiencies were identified. Cognizant licensee personnel

stated that they planned to disassemble and complete a VT-3

inspection of the valve during the next scheduled refueling

outage.

The licensee provided the inspectors with information which

indicated that the root cause of the missed VT-3 inspection

was an inadequate resolution to the Quality Control

Inspection Report (QCIR) that identified the original

problem. The QCIR did not specify that a VT-3 inspection

should be performed after completion of maintenance.

As a result of this problem, the inspectors conducted i

review of maintenance and engineering activities that

Enclosure 2

_ . _ . _ - _ _ _ . . _ . . . . _ _ _ _ . _ _ . . _ . _ . _ _ _ . _ _ _ . _ _ _ _ _

.

.

GPC 19

occurred during the last two refueling outages to determine

l if other code-required VT-3 inspections were missed. The

!

inspectors review included Safety Audit and Engineering

l Review (SAER) audits, Design Change Requests (DCRs), DCs, ,

i Maintenance Work Orders (MWOs), SORc, work records, Quality l

' Control (QC) documents, and discussions with licensee ,

management personnel. The inspectors did not identify other j

examples of missed code-required VT-3 inspections. The

inspectors also reviewed the licensee evaluation, dated

August 12, 1996, which concluded that there was no valve

operability concern.

The failure to perform an ASME code-required VT-3 inspection

on a safety related component was considered significant.

,

'

Lack of thoroughness in determining post-maintenance testing

requirements centributed to this problem. The failure to

complete a code-required VT-3 inspection was identified as

VIO 50-321/96-11-02, Failure to Perform an ASME Code-

Required VT-3 Inspection on HPCI Valve 1E41-F006.

c. Conclusions j

l

The inspectors concluded that an operability concern did not i

exist for the HPCI injection valve. The inspectors did not i

identify other examples of missed code-required VT-3

inspections and concluded this was not a recurring problem.

E7 Quality Assurance in Engineering Activities

E7.1 Unit 2 Station Service Batteries

a. Insoection ScoDe (92903)

The inspectors continued to monitor the licensee activities

involved with the sediment in the Unit 2 Station Service

(SS) Battery cells. Previous inspector observations are

documented in IR 50-321,366/96-07. The inspectors were

informed that 52 of 120 cells had sediment in the bottom of

their jars. -

b. Observations and Findinos

The inspectors observed the preparation of a new battery

receiving and storage area in an onsite warehouse. This

area was constructed so that replacement batteries received

on site could be stored in an area that has battery charging

capability as well as temperature and cleanliness controls.

The new cells can be maintained fully charged for

replacement when required.

l c. Conclusions

At the end of this report period, the inservice SS battery

,

capacity exceeded TS requirements. Increased battery

Enclosure 2

__

i

l

l

e

1

'

l

l

GPC 20

monitoring and testing continued and no immediate

operability concerns were identified. Onsite engineering I

was taking appropriate pre-installation measures to ensure  !

adequate replacement battery cell condition.

E8 Miscellaneous Engineering Issues (92700) (92903)

E8.1 (Closed) VIO 50-321/95-16-01: Contract Personnel Failure to l

Follow Procedure While Performing Maintenance on Valve 1

1E41-F003. This violation was identified after contract '

personnel performed GL 89-10 activities on valve 1E41-F003, ,

HPCI Steam Isolation Valve. The contractors were under the

control of site engineering personnel. The inspector ,

"

reviewed the response from the licensee dated September 28,

1995. The valve was repaired. The licensee counseled site '

contractor representatives on the importance of following l

procedures. The inspectors reviewed records which indicated '

that all contractor valve technicians received procedure  ;

training. The inspectors concluded that the licensee's 1

corrective actions were appropriate. I

JV. Plant Suonort

R1 Radiological Protection and Chemistry Controls

R1.1 Observation of Routine Radiolocical Controls

a. Insoection Scoce (71750) j

General Health Physics (HP) activities were observed during

the report period. This included locked high radiation area i

doors, proper radiological postings, and personnel frisking l

upon exiting the Radiologically-Controlled Area (RCA). The

inspectors made frequent tours of the RCA and discussed

radiological controls with HP technicians and HP management.

No deficiencies were identified.

1

R1.2 Misalioned Sucoression Pool Sample Valve

)

a. Insoection Scoce (71750)

The inspectors discovered Suppression Pool Sample Valve

2P33-F364 to be open on August 14. The valve is located on l

Sample Panel 2P33-P101 in the Reactor Building. I

b. Observations and Findinas

l

During a routine tour of the Reactor Building, the '

inspectors observed a steady stream of water flowing from

the Suppression Pool Sample Valve, 2P33-F364.

The inspectors reviewed the applicable plant procedure, l

64CH-SAM-004-OS, " General Chemistry Sampling," Rev.5, Ed. 1, '

dated November 7, 1995, and Piping and Instrumentation

} Enclosure 2

4

.

GPC 21

Diagram (P&ID) which indicated that the normal position of

the valve was closed. FSAR section 9.3.2, Process Sampling ,

System, did not specifically indicate the normal position of '

the valve but stated that the sampling valve is for drawing

process fluid into a closed sample container. l

l

The inspectors discussed the problem with chemistry g

personnel. The inspectors were informed that sampling flow J

through this sample valve and the corresponding valve on

Unit 1 was, as a matter of routine, left running because of

problems encountered with sample line blockage due to i

sediment buildup. The inspectors were not able to find any I

procedural guidance that allowed the continuous flow of I

sampling streams to prevent line blockage for these valves.

l

1

The licensee took immediate corrective action by returning j

the valve to its normal position as specified by procedure. 1

The licensee stated they would monitor the buildup of

sediment in the sample lines. In the future, if conditions j

warrant, a procedural change will be initiated prior to

leaving any sample valves open to prevent line. blockage.

The inspectors verified that the corresponding suppression

pool sample valve on Unit 1 was in the closed position,

c. Conclusions

This NRC-identified failure to follow procedure is being

treated as an NCV consistent with Section IV of the NRC

Enforcement Policy. NCV 50-366/96-11-03, Failure to Follow

Procedure for Sample Valve Lineup, was identified.

R4 Staff Knowledge and Performance j

1

R4.1 Samolino Analysis Collection Technicues (71750)

1

On August 8, Chemistry Department personnel informed the d

operations Department that fuel oil samples collected on EDG

1A and 1B fuel oil tanks and the diesel-driven fire pump

fuel oil tank were not within specifications. Analysis

indicated particulate at 16 milligrams per liter (mg/1) and

11 mg/l for the 1A and 1B EDG, respectfully. The fire pump

fuel oil analysis indicated particulate at 55 mg/1. TS 3.8.3.D for stored fuel oil requires total particulate to be

less that or equal to 10 mg/1. The Operations Department

immediately entered the appropriate TS LCO for the systems.

The out-of-specification tanks were immediately re-sampled

and the samples sent offsite for analysis. On August 9, the

re-analysis indicated satisfactory results. Chemistry

personnel investigated the problem to determine the root

cause for the discrepancy and identified areas for

improvement in the collection techniques. Licensee l

l

i

Enclosure 2 l

l

!

l

!

_ . _ _ . _ _ _ _ . . _ . _ _ _ _ _ _ _ . _ _ _ __ _

,

.

o

CPC 22

l representatives stated that they believed personnel

collecting the samples stirred up the bottom of the tanks

resulting in non- representative samples. Poor collection

,

-

techniques were also suspected as a problem during

subsequent backup sample collections.

Personnel who collected the samples were qualified in

collection techniques but had not recently performed the

task. As part of the corrective actions, management

cautioned personnel of the importance of obtaining

representative samples and the impact and consequences of

.

poor sampling techniques.

The inspectors reviewed and discussed the problem with

4

licensee management, reviewed applicable sampling procedures i

l

.

' and the licensees corrective actions. The inspectors

concluded that poor sampling techniques were probably the

root cause of the problem. More attention to detail during

the sample collection process may prevent similar problems.

This was identified as an area for improvement in the

chemistry sampling process.

P2 Status of EP Facilities, Equipment, and Resources

'

P2.1 Facility Insoection

'

a. Inspection Scoce (82701)

The inspectors toured the facilities to determine whether

! key facilities and equipment were adequately maintained in

accordance with the site Emergency Plan.

i

b. Observations and Findinas

The inspectors toured the Technical Support Center (TSC)

Emergency Operations Facility (EOF) , and Operational Support

Center (OSC). The inspectors witnessed the testing of

selected telephones, fax machines, Safety Parameter Display

System (SPDS), Non-Regulated Emergency Response Data System

(ERDS), Dose Assessment Computer, and the Emergency

Notification Network (ENN) phone. The equipment operated

properly. No significant changes had been made to the

. facilities.

i The inspectors reviewed documentation that indicated

'

surveillance of emergency equipment and verification of

communications capability were performed at the frequencies

specified in 73EP-TET-001-OS, Control And Testing Of

Emergency Communication Equipment, Revision 4 Ed. 1,

Effective Date June 9, 1994. The inspectors noted that

deficiencies were resolved in a timely manner.

The inspectors reviewed documentation that indicated

] facility supplies were being inventoried and maintained in

4

i

Enclosure 2

i

-

.

. . . . - - . - . - - - - .. - . _ - . . - - - , ..

l

l

-

l

.

GPC 23

accordance with the requirement in 73EP-INS-001-OS,

Emergency Equipment Inventory, Revision 1, Effective Date

April 27, 1996. The inspectors randomly selected facility

cabinets and audited emergency supplies and tested

equipment. No discrepancies were identified by the

inspectors.

c. Conclusion

The inspectors concluded that the licensee maintained the

facilities and equipment at a satisfactory level of

I operational readiness.

P2.2 Emercency Response Dose Assessment Cacabilities

a. Inspection Scoce (82701)

Dose assessment capabilities were inspected to verify that

the licensee maintained continuous dose assessment

capabilities which used real time meteorological and

radiological data. Also, the inspectors reviewed the

licensee's computerized dose assessment system to evaluate

the training required to operate the system, the capability

of the system, and verify that the licensee's system had

been compared to Radiological Assessment System for

Consequence Analysis (RASCAL).

b. Observations and Findinos

l

'

The licensee's Meteorological Information and Dose

Assessment System (MIDAS) program was installed on

designated personal computers in the TSC and EOF and if

needed, the program could be loaded on other personal

computers. Real time radiological and meteorological data

was input to the computer. The program used default values

,

'

from WASH 1400 for the source terms and did not have the

capability of using actual isotopic analysis data from a

Post Accident Sampling System (PASS) sample. MIDAS had the

capability to use field team radiological data to back

l calculate a source term.

The inspectors observed the licensee perform several dose

assessment calculations using MIDAS. The inspectors

observed that the computer dose assessment system was user

friendly and did not require extensive training to obtain a

dose assessment.

The Senior Reactor Operators (SROs) and Reactor Operators

(ROs) were trained to do on-shift dose assessment using the

" Prompt offsite dose assessment" version of MIDAS. This was

i

a simplified version of MIDAS which used some default

l values. The operators received MIDAS training as part of

l licensed operator training.

Enclosure 2

- _ . - - . - . - . - . . - - . - . - _ - - ~ . ~ - - - . - . . .-..-_ .- .

.

A

GPC 24

The inspectors verified that the licensee had compared dose

j

assessment calculations from MIDAS to calculations from

NRC's RASCAL and that the results were comparable,

i

c. Conclusion

l

The inspectors concluded that licensee personnel were

capable of performing on-shift dose assessments using real

l time meteorology. The licensee's MIDAS dose assessment

l calculation program was user friendly and results were

l

,

comparable to those from RASCAL.

P2.3 Emeroency Operations Facility - Emeroency Ventilation System

I a. Insoection Scoce (82701)

The inspectors reviewed the EOF Emergency Ventilation System

L and its testing to determine if the licensee was maintair.ing

the system in accordance with Emergency Plan requirenents.

b. Observations and Findinas

'

The EOF was not designed as a hardened facility and the

l licensee maintained a fully equipped backup EOF. The EOF's

l Emergency Ventilation System was a zero pressure system with

j High-Efficiency Particulate Air (HEPA) Filters and no carbon

.

filter. In the emergency mode of operation, the Emergency

ventilation System isolated outside air and recirculated air

in the EOF through HEPA filters. The inspectors interviewed

the system engineer responsible for the system, performed a

walkdown of the system, and observed an operational

demonstration of the system. All components (dampers) and

instrumentation worked properly.

! c. Conclusion

l

The inspectors concluded that the licensee was testing and

maintaining the EOF Emergency Ventilation System adequately.

!

P2.4 Tone Alert Radios. Public Alert And Notification

Caoabilities

a. Insoection Scone (82701)

This area was inspected to determine if the licensee's

method of notifying the public in the event of an emergency

was in accordance with the site Emergency Plan. In

addition, the inspectors reviewed the system's procedures,

l configuration, and reliability. j

l

\ l

!  !

!

l

Enclosure 2

l

I

l

l

i - _ _ . _ . - - - - . . . . . .

. __ _ . . . .- _ _ . . _ . _ _ _ .__ _ _ __ - _ _ _ _ . . . _ . _

!

.

! .

]

GPC 25

]

! b. Observations and Findinos

!

The inspectors reviewed licensee's documentation and

<

discussed with the licensee, their public alert and

notification process. The licensee's system for alerting

and notifying the public used approximately 2900 Tone Alert

Radios located within about a ten mile radius of the plant.

i The licensee maintained accountability of local business and

4

residence within the ten-mile Emergency Preparedness Zone

i (EPZ) that needed Tone Alert Radios with the aid of the

i local electrical power companies. When a local business or

resident changed their electrical power services, the

utility notified the licensee.

i

i

In September 1995, Plant Hatch's National Oceanographic &

Atmospheric Administration (NOAA) service was discontinued

from the Savannah, Georgia weather station and service was

updated and switched to the National Weather Service (NWS)

.

in Jacksonville, Florida. The primary communication was

'

from Jacksonville and utilized a leased line from

Jacksonville to the Brunswick micro-wave tower, then the

Georgia Power Company (GPC) micro-wave system to the site.

'

A secondary line was a leased land line from Jacksonville to

1 Plant Hatch. The radios were operationally tested each

'

Wednesday when the NWS station generated a tone which was

transmitted from the Plant Hatch NWS transmitter to activate

-

the tone alert radios. In addition to the testing, there

were numerous instances in 1995 and 1996 in which the system

was activated for severe weather conditions. The inspectors

reviewed the 1995 annual report for the Tone Alert Radios.

The report and supporting data indicated a 99 percent

i ava: lability factor for 1995. There were two instances of

minor losses of services during the year, one for 50 minutes

! and another for 22 minutes.

c. Conclusion

The inspectors concluded that the Tone Alert Radio system

had been demonstrated to be reliable through testing and

actual actuation, and the system was being adequately

maintained.

P3 EP Procedures and Documentation

P3.1 Maintenance of th3 Emeroency Plan and Procedures

a. Insoection Scone (8?701)

The inspectors reviewed the licensee's process for making

changes to the Emergency Plan and Emergency Implementing

Procedures (EIPs). The inspectors reviewed changes to the

EIPs and verified that changes to the EIPs were in agreement

with and implemented the Emergency Plan.

Enclosure 2

i

j

.

J

j

_ . . .

__ _

l

e

l

.

-

.  :

1

'

GPC 26 I

i

b. Observations and Findinos 1

. Procedures were revised in accordance with administrative

'

,

procedure 10AC-MGR-003-OS, Preparation and Control of 4

Procedures. Proposed changes to the Emergency Plan and EIPs I

received a 50.59 evaluation and a review by the Plant Review

t

Board. The inspector reviewed the licensee's documentation

4 for four EIP changes. The inspectors reviewed the changes

to evaluate the licensee's evaluation of the changes, and to

i independently evaluate the changes for the intent of the

.

change and to verify that the change continued to

I implemented the plan. A review of licensee records

indicated that the revisions to the EIPs were satisfactory

and were submitted to the NRC within 30 days of the

implementation date, as required. l

l Controlled copies of the EIPs in the EOF and TSC were

l reviewed and determined to be maintained up to date.

1

c. Conclusion

i

The inspectors concluded that the licensee's review process

was satisfactory and met the requirements of

10 CFR 50.54(q).

j P3.2 Use Of The Emeroency Implementino Procedures

a. Insoection Scoce (82701)

The inspectors reviewed the licensee's event declaration to

verify that the event was properly classified and the

Emergency Implementing Procedures were properly implemented.

b. Observations and Findinos

! The inspectors reviewed the licensee's one event declaration

since the last inspection conducted in April 1995.

On March 20, 1996, a NOUE was declared due to a

contaminated, injured individual being transferred off-site

, to a local hospital.

I c. Conclusion

,

The inspectors concluded that the event was properly

classified, the notification was made in a timely manner,

! and the applicable EIP was implemented.

i

a

I

1

i

l Enclosure 2

J

!

l

.

GPC 27

P5 Staff Training and Qualification in EP

PS.1 Trainino of Emercency Response Personnel

a. Inspection Scoce (82701)

The inspectors reviewed the Emergency Response Training

Program and verified that emergency response personnel were

initially trained and retrained annually to maintain their

training current.

b. Observations and Findinos

The inspectors reviewed Plant E.I. Hatch System Master Plan

for Emergency Preparedness Training. The Master Plan

described the program, position, qualification requirements,

required job performance task, and initial and continuing

training requirements. Emergency Response Organization

(ERO) training consisted of completing job task, classroom

training, and self study. The inspectors selected two

lesson plans and their associated exams from the Master Plan

for review. The inspectors concluded from the review that

the lesson plans satisfactorily covered the information

necessary for the position; the lesson plans were organized

and contained the appropriate depth of material; and the

exams were challenging.

The inspector selected six individuals within the ERO from

the current revision of the Emergency Response Position

Matrix and reviewed their training records against their

required training. All of the individual qualifications

reviewed by the inspectors were up-to-date,

c. Conclusion

The inspectors concluded that the licensee maintained a

satisfactory Emergency Preparedness training program.

P5.2 Emeroency Plannino Drills

a. Insoection Scope (82701)

The inspectors compared the licensee drill commitments to

the actual drills performed, and evaluated the quality of

those drills.

b. Observations and Findinos

The inspectors reviewed and compared the licensee's drill

documentation to Section N, Exercises and Drills of their

Emergency Plan, and the requirement in 73EP-ADM-001-OS,

Maintaining Emergency Preparedness, Revision 3, Effective

Date April 9, 1996. The inspectors found the licensee's

documentation to be well-organized. The licensee's drill

Enclosure 2

. -- . - .- - . - _ - _ - _ _ _ - - . . .~ - .

.

.

'

i-

GPC 28

scenarios were satisfactory, the critiques were objective,

and the drill comments or action items were well-documentad

and tracked.

I c. Conclusion

l

l The licensee satisfactorily met their its drill commitments.

P6 EP Organization and Administration

a. Insoection Scoce (82701)

The inspectors reviewed this area to determine if any

changes in management or personnel had occurred which would

affect the efficiency or performance of the ERO.

b. Observations and Findinos

The inspectors reviewed the licensee ERO structure and

discussed the current ERO with the Emergency Preparedness

Coordinator.

c. Conclusion

The inspectors concluded that since the last inspection in

April 1995, no onsite management or significant personnel

changes had occurred which would affect the performance or

maintenance of the Emergency Preparedness Program.

P7 Quality Assurance in EP Activities

P7.1 Recuired 10 CFR 50. 54 (t) Audit Of Emeroency Preparedness

Procram

a. Inspection Scoce (82701)

The inspectors reviewed this area to assess the quality of

the required audit, the qualifications of the auditors, and

verify that the audit met the requirements of

10 CFR 50.54(t).

b. Observations and Findinos

The inspector reviewed SAER-07, " Hatch Project Safety Audit

And Engineering Review Procedure For SAER Audits", Revision

8, dated December 12, 1995. The procedure required an

" Audit Planning Matrix" to be prepared once per year for the

upcoming year and the final revision to be distributed to

the SRB. The Audit Planning Matrix was to list the Audit

Area Titles and a breakdown of the Audit Elements. Lead

Auditors were to use the Audit Planning Matrix to prepare an

audit plan and checklist.

Enclosure 2

__. _ _ _ _ . _ __ _ _. __ . . . . _ . - __ _ _ _ _ . _

.

.

1

'

GPC 29

'

The inspectors reviewed the Audit Planning Matrix for the

Emergency Plan. The matrix listed fifteen areas which '

I

corresponded to the titles of each chapter in the Emergency )

Plan. l

The inspector reviewed Audit 95-EP-2, which was a three-

person audit conducted between November 13, and December 13,

1595.

,

-

The audit was considered by the licensee to be the I

annual Emergency Preparedness. Audit required by l

10 CFR 50.54(t). The cover letter stated that the audit was

based upon completing the fifteen elements specified in the

Audit Planning Matrix. The inspectors reviewed each

auditor's checklists and noted that the audit was not based

upon or conducted in accordance with the Planning Matrix or

as specified in the report cover letter. The actual audit

was performed using the guidance in an Institute of Nuclear l

Power Operations (INPO) document,85-014, " Generic Guidanco I

For Emergency Preparedness Review." The auditors' checklist

and notes mirrored the elements, A through G, and the

elements breakdown in the INPO document. The audit

contained 118 element breakdowns. In reviewing the

auditors' notes, the inspectors noted that, for some issues,

the auditors relied on discussions with EP staff but did not

independently verify their results.

One element breakdown questioned whether the EIPs provided a

space for a check mark or initial to indicate that the step

had been complete. The audit result indicated that the

procedures did provide a space. The inspectors independently

reviewed approximately five different EIP's and did not

observe any such provision in the EIPs.

There were no issues identified by the licensee in the Audit

report.

The inspector reviewed the audit to verify that the elements

identified in 10 CFR 50.54(t) were addressed. The

inspectors noted that Audit 95-EP-2 did not address the

requirement in 10 CFR 50.54 (t) for " Adequacy of interface

with State and local governments." After discussions with

the licensee, it was determined that the element was covered

in an independent Corporate audit, Audit Report No. 96-3.

The inspectors reviewed the qualification requirements for

an auditor and lead auditor and concluded that the program

qualification requirements were in accordance with American

National Standards Institute, Inc. (ANSI)-N45.2.23. The

inspectors reviewed each auditor's qualification card and

noted that their qualifications were satisfactorily

completed and up-to-date.

Enclosure 2

. ~ . . . . --. - - . . ~ ---- . . - . ~ . - - .- -. -.- - . -

.

.

GPC 30

c. Conclusion

The inspectors concluded that the audit performed did not

independently verify some conclusions and at least one audit

finding was incorrect. Although the audit was not conducted

,

in accordance with the Audit Planning Matrix, the aggregate

j

of the audit elements satisfied the 10 CFR 50.54 (t)

requirement for an annual independent. audit of the~EP

program. The inspectors concluded that the auditors l

,

'

qualification program was satisfactory and the auditors were

qualified.

I

P7.2 Licensee's Corrective Action Procram For Drill Comments and

Issues

a. Insoection Scoce (82701) l

The area was inspected to evaluate the licensee's corrective

. actions to comments and issues identified in their drills.

J

b. Observations and Findinas

The inspectors reviewed the licensee's drill documentation

and verified that significant critique comments were being

tracked and resolved. Emergency Preparedness issues were

.

tracked on-the licensee's Action Item Tracking (AIT) system.

For each issue, the AIT gave a description of the issue,

identified the responsible group and person, and indicated

J. its status and estimated completion date. Individuals

, maintained a file on the issues assigned to them, and when

{ the AIT was updated, the individual was responsible to

review the status of their issues. The inspectors noted

-

from the review of the AIT that there were few issues older

than one year old,

c. Conclusion

The inspectors' review concluded that the emergency

preparedness issues were satisfactorily tracked and resolved

in a timely manner. The licensee's resolution of items

tracked was adequate.

,

P8 Miscellaneous EP Issues

P8.1 (Closed) Follow-uo Item 50-321.366/95-09-01: Correction of

discrepancies between the Plan and EIPs regarding follow-up

i

notifications to the State and counties at the Alert level

and above. The inspector reviewed and verified that

procedures 73EP-EIP-004-OS, Duties Of Emergency Director,

Revision 5, Effective Date July 26, 1995 and

^

73EP-EIP-073-OS, Offsite Emergency Notifications,

+

Revision 11, Effective Date July 19, 1995, had been revised

i to correct discrepancies regarding follow-up notifications

to State and local officials during declared emergencies.

i

!

Enclosure 2

a

f

.

l

l

l

. I

i

l

GPC 31

l

The applicable emergency preparedness training material was l

'

revised to reflect the changes to the procedures. Both  !

procedures had been changed to require follow-up

notifications to be performed " periodically."

P8.2 Conclusion / Assessment

i

The licensee Emergency Preparedness Program plan and l

procedures, training equipment, and response facilities were l

being satisfactorily maintained. The licensee properly

classified an event and made the necessary notifications in

a timely manner. Licensee personnel were capable of

performing on-shift dose assessments. The tone alert radio

system was reliable and adequately maintained. Licensee

drill comments were satisfactorily resolved in a timely

manner. 1

S2 Status of Security Facilities and Equipment

The inspectors toured the protected area and coserved that

the perimeter fence was intact and not compromised by

erosion nor disrepair. The fence fabric was secured and

barbed wire was angled as required by the licensee's Plant

Security Plan (PSP). Isolation zones were maintained on

both sides of the barrier and were free of objects which

could shield or conceal an individual. The inspectors

observed that personnel and packages entering the protected

area were searched either by special purpose detectors or by

a physical search for firearms, explosives and contraband.

Badge issuance was observed, as was the processing and

escorting of visitors. Vehicles were searched, escorted,

and secured as described in the PSP. The inspectors

verified that the security procedures addressed suspension

of safeguards during emergencies in accordance with 10 CFR

50. 54 (x) and 50. 54 (y) .

The inspectors concluded that the areas of the PSP inspected

met the PSP requirements.

V. Manacement Meetinas

X. Review of UFSAR Commitments

A recent discovery of a licensee operating its facility in a

manner contrary to the Updated Final Safety Analysis Report

(UFSAR) description highlighted the need for a special

focused review that compares plant practices, procedures

and/or parameters to the UFSAR description. While

performing the inspections discussed in this report, the

inspectors reviewed the applicable portions of the UFSAR

l that related to the areas inspected. The inspectors

verified that the UFSAR wording was consistent with the

l observed plant practices, procedures, and/or parameters.

!

i Enclosure 2

.

.

• GPC 32

X.1 Exit Meeting Summary

The inspectors presented the inspection results to members )

of licensee management at the conclusion of the inspection

on September 20, 1996. The license acknowledged the

findings presented. An interim exit was conducted on

August 30, 1996.

The inspectors asked the licensee whether any materials  ;

examined during the inspection should be considered

proprietary. No proprietary information was identified.

X.2 Other NRC Personnel On Site

On August 19-20, 1996, Mr. P.H. Skinner, Chief Reactor i

Projects Branch 2, visited the site. He met with the l

resident inspector staff and discussed plant issues,

licensee performance, and generic issues. He also attended l

licensee management meetings and met with licensee  !

management to discuss licensee performance and regulatory l

issues. l

l

PARTIAL LIST OF PERSONS CONTACTED l

Licensee

Anderson, J., Unit Superintendent i

Betsill, J., Operations Manager l

Coggin, C., Engineering Support Manager l

Curtis, S., Operations Support Superintendent I

Davis, D., Plant Administration Manager l

Fornel, P., Performance Team Manager

Fraser, O., Safety Audit and Engineering Review Supervisor

Hammonds, J., Regulatory Compliance Supervisor l

Kirkley, W., Health Physics and Chemistry Manager

Lewis, J., Training and Emergency Preparedness Manager

Moore, C., Assistant General Manager - Plant Support l

Reddick, R., Site Emergency Preparedness Coordinator

Roberts, P., Outages and Planning Manager

Sumner, H., General Manager - Nuclear Plant

Thompson, J., Nuclear Security Manager

Tipps, S., Nuclear Safety and Compliance Manager

Wells, P., Assistant General Manager - Operations

INSPECTION PROCEDURES USED

IP 37551: Onsite Engineering

IP 40500: Effectiveness of Licensee Controls in

Identifying, Resolving, and Preventing Problems l

IP 61726: Surveillance Observations l

IP 62703: Maintenance Observation l

IP 62707: Maintenance Observation l

IP 71707: Plant Operations l

IP 71750: Plant Support Activities

Enclosure 2 :

1

!

1

_

.-.-.-.-. _ -. . - - _ ..-.- .-_ - -. - . .- _ ..- .-.- _ .-....~. _ ._ .. - . - ._. .

-

1

'

i

GPC 33  !

IP 82701: Operational Status Of The Emergency Preparedness

Program

IP 92700: Onsite Follow-up of Written Reports of Nonroutine

r

'

Events at Power Reactor Facilities

IP 92901: Followup - Operations

p IP 92902: Followup - Maintenance / Surveillance

NIP 92903: Followup - Followup Engineering

ITEMS OPENED, CLOSED, AND DISCUSSED

!

! Opened

I

! 50-321,366/96-11-01 IFI Review of Engineering Report

l on the Effects of Harmonics on

EDG Operation (Section E2.1).

50-321/96-11-02 VIO Failure to Perform an ASME

Code Required VT-3 Inspection

on HPCI Valve 1E41-F006, was

identified (Section E2.2).

$ Closed

l

50-321,366/95-09-01 IFI Correction of discrepancies

l between the Plan and EIPs

regarding follow-up

notifications to the State and

counties at the Alert level

and above (Section P8.1).

50-321/95-16-01 VIO Contract personnel failure to ]

follow procedure while  !

performing maintenance on  !

i

valve 1E41-F003

! (Section E8.1).

50-321,366/95-18-02 VIO Failure to follow Procedure. I

!

First example (Section M8.2).

Second example (Section 08.5).

50-366/95-26-01 VIO Inability to safely shutdown

Unit 2 from Remote Shutdown

Panel in the event of a fire

in the Main Control Room

(Section 08.4).

50-321/95-23-01 VIO Operators' failure to follow

procedure while transferring

diesel fuel oil

(Section 08.3).

.

!

i Enclosure 2

l

l

.

wwa - r- , ,w 4 e- + - -r iw-- e-wi ,- >w-w, e- -

-g,+y9

. _ .. ~ . - - - - - - - - . _ _ _ - - - ..- - . - .- ._ - . .. -.. _ ..- -. ..-. - . .

1

- j

-

l

GPC 34

50-366/96-03 LER High Pressure Coolant

Injection System Temporarily

Inoperable Following

Engineering Safety Feature

l Actuation (Section M8.1) .

50-321,366/96-07-01 URI Determine Safety Significance

and Testing Requirements for

Unit 1 and Unit 2 Containment

Isolation Status Panel

(Section 08.1).

50-321/96-11 LER . Inadequate Procedure Results

in Missed Technical

! Specifications Surveillances

(Section 08.2).

50-321,366/96-11-01 NCV Failure to Test or Verify the

Function as Described in USFAR

of the Isolation valve

Indication on the Containment

,

'

Isolation Status Panels

(Section 08.1).

50-366/96-11-03 NCV Failure to Follow Procedure

for Sample Valve Lineup

(Section R1.2).

LIST OF ACRONYMS USED

AIT -

Action Item Tracking

ASME - American Society of Mechanical Engineers

I cfm -

cubic feet per minute

CFR -

Code of Federal Regulations

CR -

Control Room

l CRD -

Control Rod Drive

! DC -

Design Change

DCR -

Design Change Request

ECCS - Emergency Core Cooling Systems

EDG -

Emergency Diesel Generator

EHC -

Electro Hydraulic Control

l EIP -

Emergency Implementing Procedures

ENN -

Emergency Notification Network

EOF -

Emergency Operating Facility

EP -

Emergency Preparedness

EPZ -

Emergency Preparedness Zone

ERDS - Emergency Response Data System

l ERO -

Emergency Response Organization

i FSAR - Final Safety Analysis Report

(

'

GPC -

Georgia Power Company

HEPA - High-Efficiency Particulate Air Filters

, HP -

Health Physics

HPCI - High Pressure Coolant Injection

I

j Enclosure 2

- . . . . - . . --

_ _ _ . _ . _ . _ - - _ _ - . - _ . _ _ . _ _ . _ . _ _ _ _ _ _ . . . . _ - . - . . . _ _ . _ _ . _ . _ -

=

,\<: .

i j Ii

J 11 5illl

GPC 35 ig;

f (' It'

, Hz -

hertz i

l

IFI -

Inspector Followup Item

INPO - Institute of Nuclear Power Operations

IR -

Inspection Report

kw -

kilowatt

1 -

liter

LCO -

Limiting Condition of Operation

LER -

Licensee Event Report

LPCI - Low Pressure Coolant Injection

MCR -

Main Control Room

MDC -

Minor Design Change

mg -

milligram

l

MG -

Motor-Generator

j MIDAS- Meteorological Information and Dose Assessment

l System

MSIV - Main Steam Isolation Valve

MWO -

Maintenance Work Order

NCV -

Non-Cited Violation

NOAA - National Oceanographic & Atmospheric Administration

NOUE - Notice of Unusual Event

l NRC -

Nuclear Regulatory Commission

'

NRR -

Nuclear Reactor Regulation

I NSSS - Nuclear Steam Supply System

NWS -

National Weather Service

OSC -

Operations Support Center

P&ID - Piping and Instrumentation Diagram

PASS - Post Accident Sample System

PDR -

Public Document Room

PSP -

Plant Security Plan

PSW -

Plant Service Water System

QA -

Quality Assurance

QC -

Quality control

QCIR - Quality Control Inspection Report

RAS -

Required Action Statement

RASCAL- Radiological Assessment System for Consequence

Analysis

RAW -

Risk Achievement Worth

RCA -

Radiological Controlled Area

RFP -

Reactor Feedwater Pump

RFPT - Reactor Feedwater Pump Turbine

RHR -

Residual Heat Removal

RPS -

Reactor Protection System

RR -

Reactor Recirculation

RTP -

Rated Thermal Power

SAE -

Site Area Emergency

SAER - Safety Audit and Engineering Review

SGT -

Standby Gas Treatment

SOS -

Superintendent On Shift

SPDS - Safety Parameter Display System

SR -

Surveillance Requirement

SRO -

Senior Reactor Operator

SS -

Station Service 7

TS -

Technical Specifications

TSC -

Technical Support Center

Enclosure 2

._- . -

_. , _ . _ . . _ _ _ ._.

f i .

.

1 .

GPC 36

TSIP - Technical Specification Improvement Program

UFSAR- Updated Fina) Safety Analysis Report

URI -

Unresolved item

VIO -

Violation

l

1

l

I

1

l Enclosure 2

'