ML20133G988

Insp Repts 50-321/96-14 & 50-366/96-14 on 961027-1207. Violations Noted.Major Areas Inspected:Operations, Maintenance,Engineering,Plant Support & Plant Status

ML20133G988
Person / Time
Site:	Hatch
Issue date:	01/06/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20133G985	List: ML20133G981 ML20133G986 ML20133G988
References
50-321-96-14, 50-366-96-14, NUDOCS 9701170012
Download: ML20133G988 (35)

See also: IR 05000321/1996014

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'U.S. NUCLEAR REGULATORY COMMISSION

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REGION II

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i Docket Nos: 50-321, 50-366

1 License Nos: DPR-57 and.NPF-5

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] Report No: 50-321/96-14. 50-366/96-14 i

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j Licensee: Georgia Power Company (GPC) l

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Facility

E. I. Hatch Units 1 & 2

Location: P. O. Box 439

i Baxley, Georgia 31513

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Dates

October 27 - December 7, 1996

! Inspectors: J. Moorman Senior Resident Inspector (Acting)

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E. Christnot. Resident Inspector

J. Canady. Resident Inspector

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G. Kuzo. Senior Radiation Specialist ,

(Sections R1. R3. R5. R7. R8)  !

j W. Kleinsorge. Reactor Inspector  !

J. Coley, Reactor Inspector

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, C. Rapp. Reactor Engineer

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i Approved by: P. H. Skinner. Chief. Projects Branch 2

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Division of Reactor Projects

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9701170012 970'106

PDR ADOCK 05000321

G PDR Enclosure 2

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EXECUTIVE SUMMARY

Plant Hatch. Units 1 and 2 -

NRC Inspection Report 50-321/96-14. 50-366/96-14

This integrated inspection included aspects of licensee operations,

engineering, maintenance, and plant support. The report covers a 6-week

period of resident ins)ection; in addition, it includes the results of

announced inspections )y a regional senior radiation specialist and two

regional reactor inspectors. An in-office review of open issues relating

to the Service Water System Operational Performance Inspection was also

conducted '

Ooerations

e The operator respon.se to the unexpected trip of the Unit 2 reactor

feed pump turbine was good. (Section 01.4)

e The inspectors concluded that the licensee was appropriately

monitoring the increased unidentified leakage rate observed in the

Unit 1 Drywell. (Section 01.5)

e Problem annunciators were resolved in accordance with the

appropriate procedures. The procedural reviews and evaluations

were conducted by appropriate operations personnel in a timely

manner. The supply of jumpers appeared to be adequately

maintained. (Section 01.6)

e The inspectors concluded that a review of the licensee's discovery

that a channel functional test of the reactor mode switch in the  ;

shutdown control rod block function had not been performed that j

included all required TS surveillances. The inspectors also -

concluded that the missed test was of minor safety significance.

(Section 03.1)

e The licensee's activities in the area of self assessment

demonstrated a safety conscious attitude and aggressive

involvement by site management. (Section 07.1)

e Although the licensee's transfer program (Technical Specification

Improvement Program) was not a formal. proceduralized program, the

licensee appropriately transferred actions and surveillance from

the Technical Specifications to the Improved Technical

Specifications procedures, manuals or programs. A few exceptions

were noted. (Section 08.1)

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! Maintenance

i e Maintenance activities observed by the inspectors were thorough.

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i e The work activities observed during the Unit 2. Loop B. Core Spray

1 outage were conducted in a safe and timely manner. Housekeeping

and implementation of Foreign Material Exclusion (FME) protection

i was excellent for the work activity performed on the Core Spray

l Test Valve. (Section M1.2)

e The licensee's preparations for cold weather were considered

j adequate. The inspectors noted a potential single failure

vulnerability in the freeze protection for the 1B Diesel

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Generator. (Section M2.1)

! e The licensee discovered that the instantaneous overcurrent trip

! setting for tne normal supply breaker to Motor Control Center

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1R24-5026 was improperly set. This is an example of a failure to

implement configuration control requirements. (Section M2.2)

e During observation of the Unit 1 High Pressure Coolant Injection

_ (HPCI) monthly surveillance test, the inspectors identified two

i potential deficiencies in the test procedure. These deficiencies

i are identified as Inspector Followup Item (IFI) 50-321,

366/96-14-04: Potential Deficiencies in the HPCI Surveillance

Procedure. (Section M3.1)

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Enaineerina

I e A recently installed nitrogen system relief valve lifted during a

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tank filling operation. This is an example of Violation (VIO)

50-321. 366/96-14-03: Failure to Implement Configuration Control

Requirements. (Section El.1)

e The licensee successfully tested the Unit 1 Main Steam Isolation

Valves while at power to demonstrate that they did not contain a

defective part identified by a recent Part 21 notice.

(Section E2.1)

e The engineering group's discovery of a deficiency involving the

normal supply breaker to a 1B diesel generator motor control

center was excellent. The temporary modification to correct the

deficiency was installed in accordance with an approved process.

(Section E2.2)

Enclosure 2

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i e The inspectors concluded that administrative procedures clearly

assign the system engineers the responsibility for trending

i repetitive equipment problems. Root cause analysis are performed

based on the category of events or at the discretion of  ;

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management. (Section E4.1).

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e A loss of power to the Reactor Protection System Bus 1B was caused

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by contractor personnel error. Contractor personnel had miswired

part of the current transformer circuit during a cable reroute.

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Engineering failed to find the error when the circuit was checked.

(Section E8.2)

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o Personnel conducting troubleshooting attempted to de-energize the

l 1G Torus-to-Drywell Vacuum' Breaker, by opening a control panel

link, which inadvertently de-energized the 1H due to an error in

the electrical connection drawing. This is an example of a

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failure to implement configuration control requirements.

(Section E8.4)

Plant Suocort

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l e Radiological controls for high and very high radiation areas were

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maintained in accordance with TS requirements. Area postings and

labels for containers of radioactive material were appropriate.

Improvements were noted for general housekeeping and cleanliness

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relative to observations made during a previous inspection. ,

(Section R1.2) l

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e Excluding two packaging Quality Assurance (0A) issues. I

transportation and packaging activities for radwaste and material

shipments met 10 CFR 71.5 and 49 CFR 100-179 requirements. The

revised Department of Transportation (DOT) guidance was

implemented, as applicable. Radwaste characterization was in l

accordance with 10 CFR 61.55. Two concerns were identified for i

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radwaste packaging quality control documentation. (Section RI.3) i

e Effluent release documentation and radiological environmental

monitoring program results were prepared in accordance with Off-

site Dose Calculation Manual (0DCM) requirements. The release

data and environmental monitoring results verified offsite

releases and resultant doses were a small fraction of the

allowable limits. (Section R3)

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o Hazardous material (hazmat) training provided to personnel

handling radioactive materials was conducted at the appropriate

frequency, and included recent changes to D0T regulations. The

training provided was effective as demonstrated by the knowledge

and proficiency of interviewed staff members. Identified issues

observed included training data base upgrades and timeliness in

completion of hazmat examination. (Section RS)

Enclosure 2

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i e Audits for the radwaste and effluent processing programs were .

! thorough and comprehensive, and met TS. 10 CFR Part 20 and '

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10 CFR Part 71 requirements. .The low-level waste characterization

study was identified as a lic '1see initiative to quantify and .

{ prioritize radwaste program activities. (Section R7.1)

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.e The licensee continues to experience delays entering the Emergency

l . Plan regarding toxic gases. During the nitrogen release event,

i they did not enter the Emergency Plan within a time frame

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considered reasonable. This is identified as a weakness.

(Section P4.1)

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Beoort Details

Summary of Plant Status

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

continued until November 3. when power was lowered to 70% to allow stroke

testing of main steam isolation valves. Power was returned to 100% the l

next day and was maintained at this condition for the remainder of the

report period except for routine testing activities.  :

Unit 2 began the report period at 100% RTP. The unit operated at that

power level until November 17 when power was reduced to 60% for repair  ;

work, rod sequence exchange, and scram time testing. The unit was l

returned to 100% on November 18 and operated at this power level

throughout the remainder of the report period except for routine testing

activities.

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01 Conduct of Operations

01.1 General Observations (71707)

Using Inspection Procedure 71707, the inspectors conducted

frequent reviews of ongoing plant operations. In general, the l

conduct of operations was professional and safety-conscious:

specific events and observations are detailed in the sections

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01.2 Use of Overtime

The inspectors reviewed the use of overtime and did not identify

any deficiencies. Appropriate measures were taken for the change i

from daylight savings time to standard time.

01.3 System Lineuos

The inspectors conducted a check of the major flow paths and

components of the Core Spray System for Units 1 and 2. The major

valves in the flow paths of the subsystems were in the correct

position for the operating condition. A limited walkdown of the ,

system was also performed to verify that the major manually

operated valves that are required to be locked by design drawings

were locked and in the correct position. The inspectors also

walked down the electrical lineup of the 1E 4160V/600V AC

electrical boards for Units 1 and 2. No discrepancies were found

during the walkdowns.

Enclosure 2

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01.4 Reactor Feed Pumo Turbine Trio

On November 17. during the power reduction for control rod .. ,

sequence exchange, the 2A Reactor Feed Pump Turbine (RFPT) tripped

due to. low bearing lube oil pressure. The low oil pressure

condition was caused by a clogged lube oil filter. No significant  ;

plant transient occurred since reactor power was at 67% RTP. The '

operators responded properly, the standby filter was placed in

service, and the RFPT was returned to operation. Personnel

attempted to replace the bad filter element but were unable to ,

isolate it. At the end of the report period licensee personnel i

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were_ reviewing the specific circumstances involving the clogging

of the filter, the relatively rapid decrease in oil pressure, and

the inability to isolate the filter. The licensee is monitoring

the filter differential pressure on an increased frequency.

01.5 Unit 1 Drywell Unidentified Leakaae

The inspectors observed and reviewed the increasing Unit 1 drywell

unidentified leakage rate. The inspectors attended management

meetings at which the increasing leakage rate was discussed. The

inspectors review of the daily operator logs indicated that on

September 24. the leakage rate was 0.1 gpm and at the end of the

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report period the rate was approximately 1.4 gpm. There were no

indications or activities that have been identified which would

have caused this change. The highest change in leakage rate,

observed by the inspectors, appeared to be approximately 0.5 gpm

per month. At this rate, the TS limit for unidentified leakage. 5

gpm, will be reached during June.1997. The licensee was

appropriately monitoring the increased leakage rate and was

evaluation actions to correct the problem.

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01.6 Review of Annunciator Control Book and Jumoer Storace l

The inspectors reviewed the Annunciator Control Logs and conducted  ;

a limited inventory of the jumper storage cabinets for Units 1

and 2. This review and limited inventory was conducted in

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conjunction with a review of procedures 30AC-0PS-009-05. Control

Room Instrumentation. Revision 4. and DI-0PS-31-0596N. General i

Guidelines for Use of Jumpers and Links. Revision 0.

The inspectors verified that the active control room prob'lem

annunciators were properly identified and labeled. Documentation

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was present in the Annunciator Control Books indicating that the

j Ar.nunciator Control Sheets were reviewed by Operations Supervision

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on a monthly basis. The documentation also indicated that the

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Manager of Engineering Support had been notified of problem

annunciators or evaluations older than three months and the Plant

! General Manager had been notified of those that were older than

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Enclosure 2

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six months. The appropriate compensatory actions were documented

where applicable.

With the assistance of the SS, the inspectors conducted a limited

inventory of.the storage cabinet that contained the jumpers used

by the operators. The jumpers within the cabinets were neatly

arranged and clearly labeled. No discrepancies were identified.

c. Conclusions on Conduct of Ooerations

The inspectors concluded that the control room operator response

to the unexpected tri? of the Unit 2 reactor feed pump turbine was

good. The shift supervisor mair.tained an awareness of the power

to flow map throughout the event.

The problem annunciators reviewed by the inspectors were resolved

in accordance with procedures. The documentation indicated that

procedural reviews and evaluations were conducted by the

appropriate operations personnel in a timely manner. The supply i

of jumpers in the jumper storage cabinet appened to be adequately

maintained.

03 Operations Procedures and Documentation

03.1 Surveillance reauirements not included in olant orocedures

a. Insoection Scoce (92901)

On October 22, 1996. licensee personnel determined that the

periodic channel function test of the Reactor-Mode-Switch-in-

Shutdown, control rod block function, was not in any surveillance

procedure and had not been performed. The functional test is

required by Unit 1 and Unit 2 TS Surveillance Requirements (SRs)

3.3.2.1.6. Perform Channel Function Test.

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b. Observations and Findinos i

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The inspectors observed that SR 3.0.1 requires. in part, that SRs

shall be met during the applicable modes or other specified

conditions. Table 3.3.2.1-1 lists the SRs with the applicable

modes or other specified conditions for the Rod Block Monitor. Rod

Worth Minimizer and Reactor Mode Switch-Shutdown Position. SR 1

3.3.2.1.6 is listed for the mode switch. The SR is not required

to be performed until one hour after the mode switch is in the

shutdown position. The given frequency is 18 months. The

inspectors also observed from information received from the i

licensee that SR 3.10.6.3 associated with LC0 3.10.6. Multiple

Control Rod Withdrawal - Refueling, was also not in any plant

procedure. This SR is only required to be met during fuel

loading; it requires the verification that assemblies are being

loaded in a spiral sequence: and has a frequency of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The inspectors determined from reviews and discussions with

licensee personnel that SR 3.3.2.1.6 should have been performed on

Enclosure 2

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both units during their last respective refueling outages, fall

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1995 for Unit 1 and spring 1996 for Unit 2. Also, during the

outages, plant conditions did not require a spiral fuel loading

i sequence and LCO 3.10.6 was not invoked by either unit. When the

! deficiencies were discovered, neither unit was in a mode or  ;

condition which required that the LCOs be invoked.

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Not performing the SRs during this period and/or not including the

SRs in applicable surveillance procedures was determined by the

j NRC resident staff to have had minimal safety significance.

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The inspectors reviewed procedures 34SV-C71-003-1S/2S " Reactor

Mode Switch in Shutdown Functional Test." Revision 4 for Unit 1

1 and Revision 3 for Unit 2. Revised on November 28. 1996, both

procedures contain the steps to perform the SRs.

c. Conclusions

l With the revision of the prc 7dures and the plans to perform the

SRs at the next opportunity, the licensee identified failure to

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include these SRs in applicable surveillance procedures is

identified as a Non-Cited Violation (NCV) 50-321, 366/96-14-01:

I Failure to include Surveillance Requirements in Applicable >

Procedures. consistent with Section IV of the NRC Enforcement

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Policy.

l 07 Quality Assurance in Operat.ons

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07.1 Licensee Self-Assessment Activities

a. Insoection Scooe (40500)

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l The inspectors reviewed and observed various self-assessment

activities.

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b. Observations and Findinas i

During the inspection period. the inspectors reviewed licensee

! self-assessment activities. Inspectors regularly attended the

Morning Management Meeting and t1e Plan of the Day r.eeting.

On October 27. at the Morning Management Meeting. . tams identified

, as Operations Open Issues were discussed. Among toe issues

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discussed were the following:

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the 2A RFPT duplex oil filter replacement

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the 1B RHRSW Heat Exchanger tube leak

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the deep well water pump power supply

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the 4160V switchgear circuit breakers

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the hydrogen recombiner controller.

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Each issue was discussed to determine current status and possible  ;

solutions. Focus on reactor safety during the meetings was good.

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The inspectors were informed that the Operations Open Issues would

be discussed each Friday.

Enclosure 2

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During the Plan of the Day (POD) meeting, the licensee discussed

ongoing Required Action Lists for both units. Fire Action List.

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and the status of ongoing approved corrective / preventive

maintenance work items. Specific items, depending on the day of

the week, were discussed as follows: Monday - deficient  :

annunciators and current caution tags: Tuesday - instrument out-

of-service reports: Wednesday - clearances currently in force and

i red circled readings (items identified as out of specifications

I during rounds): Thursday - temporary modifications currently in

plant systems: and Friday - forced outage work list.

The inspectors found that the items were discussed in detail:

specific individuals / groups were tasked with the responsibility

for each ittm: deficiencies in performance identified by

management we e discussed: deadlines and updates were established:

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and management expectations were outlined.

c. Conclusions

The inspectors concluded that licensee self assessment activities

conducted at routine meetings was effective in providing solutions

to short term problems as well as identifying potential

intermediate and long term problems.

08 Miscellaneous Operations Issues (92901) ,

08.1 Imoroved Standard Technical Soecification Imolementation Audits

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(Temocrary Instruction 2515/130)

a. ScoDe

The licensee transferred actions and surveillances from their

" custom" TSs to the Improved Standard Technical Specifications

(ITS) and other documents. This process was identified by the

licensee as Technical Specification Improvement Program (TSIP).

The results of TSIP were evaluated by the Office of Nuclear

Reactor Regulations (NRR) and documented in Safety Evaluation

Report (SER) related to Facility Operating License Amendment No.

195 for Unit 1 and No. 135 for Unit 2. To evaluate the

effectiveness of the process, the inspectors selected ten original

TSs for each unit and compared them with the new ITS. the TS

Bases, the SER. the FSAR. the Technical Requirements Manual (TRM)

and procedures, to verify that these requirements had been

transferred / relocated appropriately. The TS. ITS. TS Bases.

FSAR. TRM and implementing procedures reviewed are indicated in

Table 1.

The inspectors examined the licensee's implementation of the

controls of modifications to relocated requirements by evaluating

the implementation of those controls for the TS listed in Table 1.

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Enclosure 2

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Table 1 Transferred TS Examined.

Old TS New TS or Relocation Con- Implementing

Other Manual trol Procedures

2-3/4.1.3.1 2-3.1.3 10 CFR 50.92 34SV-C11-003-2S

42CC-ERP-011-0S

2-3/4.4.3.2 2-3.4.4 10 CFR 50.92- 34SV-SUV-019-2S

2-3/4.6.6.5 2-3.3.1.2 10 CFR 50.92 345V-C51-001-2S

57SV-C51-007-2S

345V-C51-006-2S

345V-SUV-019-2S

34G0-0PS-001-2S

3/4.5.2 2-3.5.1 10 CFR 50.92 345V-B21-003-25

42SV-TET-001-2S.

345V-821-004-25

345V-B21-004-2S

42SV-B21-003-2S

2-3/4.4.6.2 2-3.4.10 10 CFR 50.92 34SV-019-2S

2-3- 2-3.6.1.3 10 CFR 50.92 42SV-SUV-044-2S

4.6.6.5.2

2-3/4.9.12 2-3.9 10 CFR 50.92 34FH-0PS-001-0S

2- 2-5.5.8 10 CFR 50.92 00AC-REG-001-0S

3/4.11.1.4 64CH-ADM-001-0S

2-3/4.8.2.1 2-3.8.7- 10 CFR 50.92 34SV-SUV-013-05-

34G0-0PS-030-25

2-3/4.7.3 2-3.5.3 10 CFR 50.92 345V-E51-002-2S

34SV-SUV-019-25

34SV-E51-002-2S

34SV-E51-004-25

1-3/4.6.C 1-3.4.9.5.6.& 10 CFR 50.92 52GM-MME-004-1S

7 52GM-MME-015-15

34GO-0PS-015-15

1-3/4.6.G FSAR 4.10.3 10 CFR 50.59 34SV-SUV-019-1S

Procedures 42SV-T46-003-1S

1-3/4.6.H.1 TS Bases & 10 CFR 50.59 & 345V-B21-004-15

Procedures TS 5.5.11 52GM-B21-005-0S

1-3/4.6.I 1-3.4.2 & 10 CFR 50.92 & 34SV-SUV-023-15

Procedure 10 CFR 50.59

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Enclosure 2

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Table 1 Transferred TS Examined.

l Old TS New TS or Relocation Con- Implementing

Other Manual trol Procedures

1-3.6.K TRM 3.4.2 10 CFR 50.59 Numerous ISI & IST

1-3.6.K.a-c Program

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Procedures.

These Procedures

Were Not Verified.

l 1-3/4.6.L TRM P3.7.1 10 CFR 50.59 52-SV-SUV-001-0S

l 52-SV-SUV-002-0S

1-3/4.8.A.1 TRM 3.7.3 & 10 CFR 50.59 62RP-RAD-007-0S

Procedures 60AC-HPX-007-05

62RP-RAD-038-0S

l 1-6.9 Unit 2 FSAR 10 CFR 50.59 00AC-REG-001-0S

13.6.4 42CC-ERP-014-05

1-6.10 Unit 2 FSAR 10 CFR 50.59 20ADM-002-0S

13.6.5.A&B

1.6.13 5.5.2.b 10 CFR 50.92 52SV-E11-001-1S

52SV-E21-001-15

52SV-E21-002-15

52SV-E41-001-15

52SV-E51-001-15

52SV-G31-001-1S

To evaluate the licensee's corrective action program related to

the TSIP Process, the inspectors reviewed corporate and site

audits. Deficiency Cards (DCs). LERs and NRC inspection findings.

The inspectors reviewed licensee self-assessment audits. The

scope of the review included: verification of requirement

relocation: adequacy of procedures, programs, and manuals

supporting relocations: evaluation of implementation of controls;

and conversion verifications.

b. Observations And Findinas

Except as noted below, procedures, manuals and, programs

ap3ropriately implemented requirements transferred to ITS and

otler documents as authorized by NRR.

e Although Revision 11 of Procedure 64CH-ADM-001-0S Chemistry

' Program, relocates the requirements of the ITS Page 59 of 82

still references footnote "a" to the TS. This footnote was

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deleted in the transfer process and is not appropriate to the

ITS. The licensee indicated that the discrepancy would be

corrected with the next substantive change to the procedure.

Enclosure 2

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e Procedure 42SV-SUV-044-25. Stand-By Gas Treatment Excess Flow

Isolation Damper Surveillance. Revision 1. dated 12/5/89

references SR 4.6.6.5.2.a. the pre-TSIP identification. This

surveillance was transferred to ITS without change and is now i

identified as SR 3.6.1.3.13. The licensee indicated that the  !

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discrepancy would be corrected with the next substantive change

to the procedure.

e In Section 3/4.6.L of the old TS. a note at the bottom of page

3.6-10a for Unit 1 and page 3/4.7-11 for Unit 2 was deleted

when the requirements were relocated to the TRM. This deletion

was not justified in an applicable 50.59. The licensee issued

a DC C09604999 to correct this discrepancy. The note was ,

administrative in nature and of minor safety significance.  :

c. Conclusions

Although the licensee's transfer program was not formal and

proceduralized. the licensee appropriately transferred actions and

surveillances from the TS to the ITS', procedures manuals or

programs. A few exceptions were noted. An NCV involving

surveillances that were not transferred is documented in

Section 03.1. ,

08.2 (Closed) VIO 50-321/96-10-01: Inadequate Procedure for Verifying

Plant Service Water Pump Discharge Valve Positions.

This violation was identified when it was observed that the pump

discharge valve positions were not being verified in accordance

with the Improved TS. which were implemented in July. 1995.

The inspectors reviewed the response, dated September 23. 1996,

and observed that an inadequate procedure was stated as the reason

for the violation. The response indicated the following: the

valve positions not being checked as required for both units were

checked and found to be in their correct positions; procedures

34SV-SUV-012-15 and 25. Plant Service Water and Residual Heat

Removal Service Water Valve Position Verification, were revised to

include the required valve positions: and other procedures used to

check valve positions were reviewed and no additional problems

were found. The inspectors reviewed procedure 345V-SUV-012-15.

Revision 3. Plant Service Water and Residual Heat Removal Service

Water Valve Position Verification, and procedure 34SV-SUV-012-25.

Plant Service Water Residual Heat Removal and Standby Service

Water Subsystem Valve Position Verification. Revision 13. The

inspectors observed the changes made to the procedures and that

the effective date for both procedures was August 14. 1996. Based

on the licensee actions and inspector reviews, this violation is

closed.

Enclosure 2

1

.

i

.

9

,

08.3 (Closed) LER 50-321/96-04: Inadequate Procedure Results in l

Reactor Pressure Increase and Automatic Reactor Shutdown. l

This problem was discussed in IR 50-321.366/96-04. No new issues -l

were revealed by the LER. 1

!

.

II. Maintenance

M1 Conduct of Maintenance

M1.1 General Comments

a. Insoection Scooe (62703)

The inspectors observed all or portions of the following work

activities:

-

MWO 1-96-2889: 1C EDG End Turn Windings Inspection

-

MWO 1-96-2806: Lube Oil Replacement in 1C EDG Bearing

-

MWO 1-96-3011: Repair of 1C EDG Room Automatic Louvers

-

MWO 2-96-1442: Support Maintenance Engineering for VOTES

Testing

-

MWO 2-96-1868: Limitorque Operator Grease Inspection

b. Observations and Findinos

The inspectors found that the work performed during these

activities was thorough. All work observed was performed with the

work packages present and being actively used. The craft

personnel were knowledgeable of their assigned tasks. The

inspectors observed that supervisors and engineers monitored

specific work activities and routinely gave directions to craft

personnel. Quality control personnel were present during the

performance of Maintenance Work Order (MWO) 1-96-2889.

During the performance of MWO 1-96-2806. the inspectors observed

that the lube oil containers were clearly marked and labeled as

required.

The as-left static and dynamic Valve Operation Test and Evaluation

System (VOTES) testing was acceptable for 2E21-F0318. Core Spray

Minimum Flow Valve (MWO 2-96-1442). The dynamic VOTES testing

showed a large margin available for design operations. A small

amount of grease was added to the stem and drive sleeve of valve

2E21-F0158. Appropriate post maintenance tests were performed.

c. Conclusions on Conduct of Maintenance

Observed maintenance activities were generally completed

thoroughly. No deficiencies were identified by the inspectors.

Enclosure 2

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

l .

L

.

.

10

M1.2 Unit 2 Core Soray Looo B Maintenance Outaae

a. Insoection Scoce (62707)

The inspectors observed portions of the activities associated with

l the Unit 2 Core Spray Loop B outage. In addition to the

l observations the inspectors reviewed selected maintenance work

packages and procedures. Maintenance. engineering and operations

personnel involved with the work activities were interviewed.

b. Observations and Findinas

On November 17, the licensee began an online maintenance outage  ;

for selected components of the Unit 2 Loop B Core Spray System.

The scope of the work included the following for the selected

components:

-

Performance of 18 month grease inspection of limitorque

operators

. - - - . . - .

-

Cleaning and lubrication of valve stems and re-torquing of

valve packing as required

l

-

Changing oil in the pump motor and meggering the pump motor I

wiring  !

-

Installation of a new motor on the operator for Core Spray

Outboard Injection valve. 2E21-F004B

-

Replacement of thermal overload heater elements for the Core

Spray Test valve. 2E21-F015B. and Torus Suction valve.

2E21-F001B.

The inspectors observed removal of the spring pack on the

limitorque operator for the Core Spray Test valve. The 18-month

grease inspection was performed in conjunction with this activity.

The inspectors also observed the static VOTES testing on the

Minimum Flow valve. 2E21-F031. The inspectors determined from a

discussion with operations personnel and an independent review of

Technical Specification (TS) 3.5.1 that the applicable Required

Action Statement (RAS) was entered for the out of service Core

Spray loop.

The inspectors discussed the issue of clearance and tags used to

control the work activities with maintenance personnel.

Maintenance personnel indicated that most of the valve work was

performed by the use of personalized Danger Tags. The inspectors

i verified that the appropriate clearance tags were hung at the

1

Motor Control Center (MCC) and in the Control Room for the valves

being worked. The inspectors reviewed procedure 30AC-OPS-001-05.

Control of Equipment Clearances and Tags. Revision 15. No

discrepancies were found between the implementation of the Danger

Enclosure 2

.

. ,

,

11

Tags and the procedure. The inspectors also reviewed the

Clearance Index and Audit Sheet and found no discrepancies.

The inspectors reviewed work packages associated with the V0TES

testing of the Core Spray Minimum Flow valve: the 18-month grease

inspection on the valve operator for the Core Spray Test valve,

and the motor replacement for the Core Spray Outboard Injection

valve. 2E21-F004B.

The motor operator on the 2E21-F004B valve was replaced as part of

the licensee's on-going activities to replace shafts that are

susceptible to cracking. Similar problems were also identified in

Inspection Reports 50-321, 366/95-17.

Surveillance procedure 34SV-E21-002-25. Core Spray Valve

Operability. Revision 7 was satisfactorily completed on

November 19 and the system was returned to service.

c. Conclusions

The inspectors concluded that the work activities observed were

conducted in a safe and timely manner. Maintenance personnel

performing the tasks were conscientious. Housekeeping was

excellent. Excellent implementation of Foreign Material Exclusion

(FME) protection was observed for the work activity performed on

the Core Spray Test valve.

M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Cold Weather PreDarations

a. Inscection Scooe (71714)

The inspectors observed activities, performed walkdowns, and

reviewed documents and procedures associated with cold weather

preparations.

b. Observations and Findinas

Among the areas observed and reviewed were the following:

-

Review of procedures used to calibrate and test equipment

associated with heat tracing, space heaters and thermostats

-

System walkdowns to observe heat tracing, space heaters and

insulation installed on susceptible systems. Walkdowns were

also performed to observe the material condition of automatic

and manual louvers

-

Review of instructions and checklists used to implement

responses to actual cold weather conditions

-

Review of previous corrective maintenance and deficiencies

identified during the last cold weather period.

Enclosure 2

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

-

<

.

.

l

.

!

12

,

The inspectors reviewed maintenance procedure 52PM-MEL-005-05, l

Cold Weather Checks. Revision 9. and Operations Department

Instruction DI-0PS-36-0989N. Cold Weatler Checks. Revision 9. The  !

procedure and instruction provide for testing and repair of

'

equi) ment associated with cold weather protection as well as a l

chectlist to ensure exposed equipment was adequately protected i

during cold weather conditions.  !

,

l

The inspectors performed walkdowns of the Emergency Diesel

4

Generator (EDG) building, intake structure fire pump building,

service water valve ait, switchyard deluge buildings fire water

storage tanks, and a)ove ground piping systems. These areas

contain systems that are important to safety and/or could cause a

'

plant transient. During the walkdowns the inspectors observed the

following:

) -

Several heat trace indicating light lens were missing in the

l fire pump house storage tank, intake structure valve pit. and

EDG building areas

-

Insulation damage on the piping for the fire ptep suction,

mi.ssing insulation on a level switch on a fire pump storage

. tank, and insufficient insulation on the travelling screen wash

system

'

.

-

The automatic louvers in the EDG building appeared to close.

but may not be shut off completely. The manual louvers in the

! fire pump house appeared to have deteriorated and may not be

capable of being manually closed completely

,

-

The sensing lines for the fire main jockey pump and the

electric fire pump are located near a manually operated louver  ;

and appeared to be susceptible _ to freezing '

I -

A section of the fire pump house which contains fire main

piping does not have a space heater l

l

'

-

The inspectors questioned the installation of the freeze

protection system concerning single failure vulnerability

-

The inspectors observed that the freeze protection for the

service water system for the IB EDG appears to be supplied by

Unit 1 only although the EDG serves both units.

4

The inspector reviewed 8 MW0s and 3 Deficiency Cards (DCs) from

'

the previous cold weather period. The inspectors observed from

4 this review that the MW0s and DCs concerned heat trace problems.

! The inspectors also observed that once identified, these items '

were promptly corrected.

The observations made by the inspectors and the concerns were

discussed with licensee personnel. The licensee stated that

freeze protection systems had been evaluated in the 1979 time

Enclosure 2

l. j

l

l' l

'

l 13

frame but that the evalu tion did not include single failure l

vulnerability. '

1

c. Conclusions l

The inspectors concluded that the cold weather pre)aration program )

contains procedures for performing equipment opera]ility checks,

performing checks during actual cold weather conditions, and

'

correcting deficiencies when identified. The inspectors also

concluded that a loss of power from Unit 1 to the freeze

protection for the service water cooling piping to the 1B EDG ,

could impact the EDG's operability to support Unit 2 operation. l

At the end of the report period, no determination had been made

concerning single failure vulnerability of the EDG service water

freeze protection. This is identified as an Inspector Followup

Item (IFI) 321.366/96-14-02: Potential Single Failure

Vulnerability in the Freeze Protection System.

M2.2 Ad.iustment of MCC Breaker Trio Setooint for 1B EDG

a. Insoection Scope (92902)

1

The licensee determined that the trip setpoint for the normal l

supply breaker to MCC 1R24-5026. from the 1B EDG. was not set I

properly (Section E2.2). The inspectors reviewed circumstances

associated with the improper setting.

b. Observations and Findinas

The inspectors reviewed administrative procedures and documents

involving configuration control and maintenance. Among the

procedures reviewed were the following-

1

-

E.I. Hatch Nuclear Plant Configuration Management Program

Reference Manual

1

-

Procedure 10AC-MGR-015-05. Configuration Management Program. l

'

Revision 0

1

-

Procedure 40AC-ENG-003-05. Design Control. Revision 8  !

-

Procedure 50AC-MNT-001-05. Maintenance Program. Revision 24

The inspectors also reviewed maintenance procedure

52PM-R24-002-0S. Air Circuit Breaker. Type LA-600. Maintenance.

Revisions 0 and 1. and MWO 1-88-7355. From this review. the

inspectors determined that the MWO directed that the trip setpoint

for the MCC breaker be changed from the as found setpoint of 3X to

the required setpoint of 12X. as determined by corporate

engineering. The MWO also directed that the change be made in

accordance with LA-600. breaker maintenance procedure.

The inspectors found that the MWO clearly stated what activities

were to be performed and that the applicable procedure was

Enclosure 2

.

.

14

referenced. The inspectors also found that on November 6. 1996,

the licensee determined that the setpoint had been adjusted to 8X

instead of 12X. as directed by the MWO.

c. Conclusions

The inspectors concluded that the Configuration Management Program

Manual in conjunction with procedures 10AC-MGR-015-05.

40AC-ENG-003-05, and 50AC-MNT-001-0S established and implemented

the applicable requirements of 10 CFR 50, Appendix B.

Criteria III. Design Control.

The inspectors concluded that not adjusting the trip setting on

the MCC normal supply breaker in accordance with engineering l

requirements is an example of a failure to implement the '

configuration control process. This is identified as an example

of Violation 50-321. 366/96-14-03: Failure to Implement

Configuration Coritrol Requirements. l

i

M3 Maintenance Procedures and Documentation  !

l

'

M3.1 Surveillance Observations

a. Insoection Scooe (61726)

The inspectors observed all or portions of the following Unit 1

and Unit 2 surveillance activities:

- 34SV-E42-002-1S: HPCI Pump Operability

- 345V-E21-002-2S: Core Spray Valve Operability

b. Observations and Findinas

The inspectors observed during the performance of the Unit 1 High

Pressure Coolant Injection (HPCI) Pump Operability monthly

surveillance, two potential procedure deficiencies. The first

involved a high radiation alarm in the HPCI room and the second

the torus bulk average temperature.

The inspectors were informed during the pre-;iob briefing that the

hydrogen flow for the water chemistry systca would not be reduced.

Hydrogen injection significantly raises radiation levels of the

steam leaving the reactor. Shortly after the start of the HPCI

turbine, the HPCI room experienced a high radiation condition and

the area high radiation alarm was received. The Health Physicists

(HP) Technician at the scene reported that the steam supply line

to the turbine was reading one Rad on contact. The inspectors

reviewed the surveillance procedure and found that the procedure

did not discuss the alarm as an expected alarm during routine HPCI

surveillance testing. This appeared to be contrary to the concept

of ALARA and is identified as a potential procedure deficiency.

The inspectors observed that during performance of the .

surveillance, safety related recorder 1T48-R647. labeled TORUS I

!

Enclosure 2 I

!

.. - .-.

4

15

AVERAGE BULK WTR TEMP. indicated a temperature of 108 degrees

Fahrenheit ( F). The inspectors also observed that the Safety

Parameter Display System (SPDS) indicated a temperature of 93 "F.

Review of the HPCI surveillance procedure found that operators

were directed to use SPDS indication to determine torus

temperature, but the safety-related temperature recorder was not

addressed. The procedure stated that the average Suppression Pool

water temperature shall not exceed 105 *F. It also stated that

testing must be stopped if the 105 *F temperature was exceeded.

c. Conclusions

For the surveillance. all data was within the required range and

the equipment met the surveillance procedure criteria. The

performance of the operators and crews conducting the surveillance

was generally professional. A potential procedure deficiency was

identified during the Unit 1 HPCI surveillance and is identified

as Inspector Followup Item, 50-321. 366/96-14-04: Potential

Deficiencies in the HPCI Surveillance Procedure.

III. Enaineerina

El Conduct of Engineering )

On-site engineering activities were reviewed to determine their

effectiveness in preventing identifying, and resolving safety

issues. events. and problems.

El.1 Inadvertent Lift of Nitroaen System Relief Valve and NOVE

a. Insoection Scoce (37551) (92.902).0

While attempting to fill the Um t 2 nitrogen storage tank, a

relief valve on the fill line lifted. The discharae from the

relief valve was into the tank room, partially filling the room

with nitrogen. This resulted in the declaration of a Notification i

of Unusual Event (NOUE) due to release of toxic gas in accordance  !

with the licensee's Emergency Plan. The inspectors reviewed ,

operator logs. event reports and design documents. The inspectors  !

interviewed operators and engineers involved in the event.

b. Observations and Findinas

The inspectors reviewed circumstances associdted with the event.  !

On October 28. 1996. plant operators were conducting a routine

refill of the Unit 2 nitrogen storage tank in accordance with  ;

34S0-T48-002-25. Containment Atmospheric Control and Dilution

systems. Shortly after commencing the fill, a relief valve on the

plant side of the fill line lifted, discharging nitrogen into the

tank room. The inspectors determined that the relief valve lifted

within the tolerance of it's set pressure of 145 psig.

The inspectors determined that the relief valve was installed to

correct a discrepancy with the system drawing noted by the system

Enclosure 2

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

'

I

.

d

16

engineer during a system walkdown. During the walkdown, the

! engineer discovered that a ball valve was installed where the

'

system drawing indicated there should be a relief valve. The ball

valve was determined to have been installed outside of the Design

'

Change Request (DCR) process at some point prior to June 1987.

Since the drawing showed a relief valve, the engineer initiated a

Maintenance Work Order (MWO) to remove the ball valve and install

d

a relief valve. The design change process was not required to be

"

implemented in this case since the work involved restoration of

the original system configuration and not a design change. As a

. result, much of the independent review involved in the

installation process was not available to detect a problem.

When procuring the relief valve and determining its' lift

setpoint. the system engineer referenced the vendor manual for the

nitrogen system. The manual listed two values for the relief

valve lift setpoint. 150 psig on a drawing of the valve and 170

psig in a table listing all relief valves in the system. The

licensee later determined that the correct value was 170 psig. An

installed relief valve was set at 145 psig. It was during the

next fill of the tank that the relief valve lifted, resulting in

4 the NOUE.

The inspectors also observed that the system drawings did not

include the vent piping that had been installed by a previous

Design Change Notice (DCN) to allow nitrogen to vent outside of

the enclosure during relief valve lifts and normal system purges.

!

This vent piping was subsequently removed during the last

installation of the relief valve.

c. Conclusions

This failure to adequately control plant configuration is a

3

violation of the requirements of 10 CFR 50. Appendix B. Criterion

4 III. Design Control. This is an example of Violation 50-321,

366/96-14-03: Failure to Implement Configuration Control

Requirements.

.

E2 Engineering Support of Facilities and Equipment

.

E2.1 Main Steam Line Isolation Valve Soecial Test

a. Insoection Scooe (92903)

The inspectors observed a special test of the Unit 1 Main Steam

.

Line Isolation Valves (MSIV) on November 3.1996. The special

testing was performed in response to a 10 CFR 21 Potential Defect

Notification issued on October 28. 1996, by the valve vendor.

Automatic Valve.

b. Observations and Findinas

On November 3. the inspectors observed testing of the outboard and

inboard MSIVs on Unit 1. Unit power was reduced to approximately

70% rated thermal power (RTP) to conduct this test. The

Enclosure 2

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

.

1 f

.

,

17

inspectors observed that management was present during the entire

time of MSIV testing.

-

The inspectors reviewed Section 4.6.5 of the Final Safety Analysis

.

Report (FSAR) and determined that the MSIVs may be tested and

exercised individually to the fully closed position after reducing

reactor power to less than 75%.

'

This special test was performed to determine if the licensee had

4 any of the defective solenoid valves associated with the MSIVs

i that were described in the 10 CFR 21 (Part 21) Notification of

Potential Defect. The notification identified that plungers in

the defective solenoid valves had the incorrect length due to a

! machining operation error at the time of manufacture. Valves with

the defective plunger were found to have substantially longer  !

closure times at normal operating temperature.

'

<

The inspectors reviewed Special Purpose Procedure

34SP-103196-CM-1-15. Main Steam Line Isolation Valve Special Test.

The operators had this procedure in their possession during the

performance of the MSIV testing.

.

I

The 1821-F028A and 1821-F028C MSIVs experienced limit switch

problems during the test. The closed indicating light came on 1

-

when the respective valve received the close signal but the open i

-

indicating light did not extinguish. Operations personnel I

determined that the valves had closed based upon observation that

steam flow indication in the respective steam lines went to zero

while the flow indication in the remaining three steam lines

increased. Maintenance personnel entered the steam chase area to

make adjustments to the problem limit switch on each valve

i following the testing that resulted in dual light indications.

'

Testing of each valve subsequent to the limit switch adjustment  ;

demonstrated proper valve indication and acceptable stroke times.

'

i

The 1821-F022D inboard MSIV experienced limit switch problems 1

during testing similar to that which occurred during testing of

the F028A and F028C outboard MSIVs. The licensee observed the

time it took the steam flow indicator to decrease to zero once the

-

MSIV was given a closed signal. This timing 3rovided a reasonable

judgement as to how fast the valve closed. T1e licensee concluded

that the F0220 MSIV closed within an acceptable time.

<

The licensee entered Technical Specification (TS) Required Action

Statement (RAS) 3.3.3.1 for the inoperable instrumentation

associated with the MSIV. The inspectors determined that the

licensee's actions were appropriate.

c. Conclusions

Testing of the Unit 1 MSIVs demonstrated that the valves did not

contain the defective part described in the Part 21 notice. Power

was reduced to within the limits specified in the FSAR.

Maintenance coordination and support was timely. TS actions taken

Enclosure 2

, _ . ..

.

.

18

were appropriate. Management's presence enhanced the

effectiveness of coordination with offsite personnel and

facilitated the decision making process.

1

E2.2 Motor Control Center (MCC) Feeder Breaker Trio Device

c. Insoection Scoce (92902) l

l

The licensee determined tha; the trip setting for the normal

supply feeder breaker to the EDG 1B MCC. 1R24-S026. was incorrect

for the application (Section M2.2). This was identified during an

engineering walkdown.

b. Observations and Findinos

The inspectors reviewed information supplied by engineering

personnel and determined that the correct breaker for this

application would have a trip unit with a short and long time

delay overcurrent trip and no instantaneous trip. The breaker

that was found installed had a long time delay overcurrent trip

and an instantaneous overcurrent trip. The existing alternate

supply breaker had correct trip features.

The inspectors observed that two temporary modifications (TMs)

were initiated. One. 1-96-40 (TM40). was to install a breaker

with the acceptable trip features. The onsite engineering l

personnel identified a spare breaker in the warehouse with

applicable trip features. The other. 1-96-41 (TM41). was to

implement the following changes: Move the largest non-safety

load, the Technical Support Center (TSC) power feed, to another

MCC: disable the trips on the normal supply breaker; and adjust

the upstream 4KV overcurrent protective relays.

'

The inspector reviewed both TM40. which technically justified the

use of the spare breaker, and TM41. The review also included the

10 CFR 50.59 review. The testing activities for TM40 were

controlled by MWO 1-96-4267 and procedure 52PM-R24-002-05. Air

Circuit Breaker. Type LA-600. Maintenance. Revision 1. The

inspectors reviewed the MWO and procedure and did not identify any

deficiencies.

The inspectors observed the following circuit breaker tests: the

initial successful long time pick-up test corresponding to a 600

amp load; the unsuccessful short time pick-up test corresponding

to a 1500 amp load; and the unsuccessful long time pick-up retest.

l Site personnel could not determine why the short time test and

retest were not successful. The licensee had the breaker shipped

off-site to be tested. The licensee was subsequently informed

that the breaker could not be tested. The license canceled TM 40

and implemented TM 41.

( The inspectors reviewed the implemented TM 41 and observed that

I the TSC power feed was rerouted from 1B EDG MCC 1R24-S026 to the

1B EDG MCC 1R24-SO48. The inspectors also observed that the

Enclosure 2

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

.

-

,

,

, 19

l

j. restoration activities stated that the normal supply breaker would

l be replaced with a new breaker having the proper trip settings

l with the applicable trip features per a design change.

!

l c. Conclusions

4

i The inspectors concluded that the TMs were initiated. controlled

l and TM41 was implemented with engineering oversight Plant Review

l Board (PRB) approval, anc ooerattonal testing. The engineering

groups discovery of this deficiency was excellent. Until the

normal supply breaker to 1R24-5026 is replaced. this is identified

as IFI 50-321/96-14-05: Restoration of 1B EDG Motor Control

Center.

E4 Engineering Staff Knowledge and Performance

E4.1 Trendina Recetitive Eauioment Problems and Root Cause-

'

a. Insoection Scoce (92903)

The inspectors reviewed the licensee program for trending of

repetitive equipment problems and the analysis for root cause

program.

b. Observations and Findinas

The inspectors reviewed procedures and instructions that involved

trending and root cause. Among these were the following:

-

AG-ENG-04-0288N: Plant Performance Indicator Program

-

DI-ENG-41-1089N: Use of System Engineers

-

DI-ENG-45-1290N: Conduct of Engineering

-

AG-MGR-27-0687N: Root Cause Analysis

-

10AC-MGR-012-05: Event Review Program

The inspectors observed from the reviews that: procedure AG-ENG-

04-0288N. Revision 0, applies, in part, to all performance

indicator data submitted to the Plant Hatch Performance Trending

Program: instruction DI-ENG-41-1089N. Revision 4. applies, in

part to engineers assigned to the Systems Engineering Sections

and to other engineers assigned systems responsibilities:

instruction DI-ENG-45-1290N. Revision 0 applies. in part. to all

engineers, nuclear specialists and other personnel in the

Engineering Support Department; procedure AG-MGR 27-0687N.

Revision 3 provides a guideline in performing a methodical root

cause analysis and applies to any individual performing an

analysis; and procedure 10AC-MGR-012-05. Revision 3 applies to

category 1 and 2 events or any other event deemed by plant

management.

The inspectors observed Section 4.3. Duties and Responsibilities,

of DI-ENG-1089N Sub-Section 4.3.3. under Priority I, which states

the following:

Enclosure 2

__ _

- - .. - . - - _.

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

.

,

20

" Evaluate system performance to improve equipment reliability

and efficiency. This will normally include the trending of

selected system parameters to detect deteriorating system

performance and computation of unavailable figures for

, equipment. Significant changes or developing trends will be

! evaluated and reported to Engineering Supervision, along with

l any suggested corrective actions. A history of system

l

'

performance will be maintained so that the need for, and the

success of, corrective actions can be demonstrated."

The inspectors observed that DI-ENG-45-1290N discussed the conduct

,

of engineering in terms of goals, performance of engineering

l activities, and professional accountabilities.

l

The inspectors found from these reviews that the responsibility

for trending of repetitive equipment problems is assigned to the

system engineers. The inspectors also found that the type of

analysis for root cause is determined by event categories, which

are classified into four levels. The event classification is based

on the relative probability and the relative consequences.

Category 1. 2 and 3 events require a type of root cause analysis

and category 4 events are at management discretion.

c. Conclusions

The inspectors concluded that administrative procedures clearly

assign the system engineers the responsibility for trending

repetitive equipment problems. Root cause analysis are performed

based on the category of events or at the discretion of

management. j

E8 Miscellaneous Engineering Issues (92700) (92903)

E8.1 (Closed) VIO 50-321.366/96-07-02: Failure to Conduct Testing

Following Molded Case Circuit Breaker Instantaneous Trip Setpoint

Changes.

This violation was identified when. as a result of an inspector

identified issue, the licensee started adjusting the trip

setpoints on 577 molded case circuit breakers (MCCB). The

inspectors observed that post adjustment testing was not being

performed.

The inspectors reviewed the response, dated August 6.1996, and

observed that the use of an inaccurate value for motor locked

rotor amps for adjusting the setpoint was stated as the reason for

the violation. The response indicated that equipment was not

cycled after setpoint changes due to personnel incorrectly

cencluding that verifying the setpoint represented adequate post

maintenance acceptance criteria. The response stated that

personnel responsible for the error in the calculation and for the

assignment of the inappropriate functional test have been made

aware of their errors and the consequences of those errors.

Enclosure 2

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

.

4

.

21

The inspectors documented in irs 50-321, 366/96-07, 96-10. and

96-13 observations of licensee personnel changing setpoints and

performing post change testing in accordance with instructions.

The inspectors also observed operations involvement and

engineering oversight. Based on the actions of the licensee and

the observations by the inspectors, this violation is closed.

E8.2 (Closed) LER 50-321/96-05: Loss of Power to Reactor Protection

System Bus Results in Actuation of Engineered Safety Features.

This LER discussed the loss of power to the Reactor Protection

System (RPS) 1B on April 14. 1996, as a result of the opening of

the supply breaker to the 4160VAC/600VAC Station Service

Transformer 10.

The event was caused by personnel error. Contractor personnel had

miswired 3 art of the current transformer circuit during a cable i

reroute t1at was implemented in Design Change Request (DCR)94-044. . Licensee personnel had failed to identify the wiring

error when the circuit was checked (" red lined") following the

completion of the DCR work.

As corrective actions, the licensee implemented a Maintenance Work

Order (MWO) 1-96-1393 on April 15, 1996, to correct the wiring

error. The responsible personnel were counseled. The inspectors

reviewed MWO 1-96-1393, which indicated that the error in the l

transformer circuit was and corrected.

The failure to properly install DCR 94-044 in accordance with the

Hatch Nuclear Plant Configuration Control Program is a violation

of the requirements of 10 CFR 50. Appendix B. Criterion III. l

Design Control. This failure is identified as an example of VIO

50-321. 366/96-14-03: Failure to Implement Configuration Control

Requirements.

i

Based upon the inspectors * review. the licensee's corrective 1

actions, and the identification of this issue as an example of VIO

50-321, 366/96-14-03. this LER is closed.

E8.3 (Closed) LER 50-321/96-01: Clogged Servo Valve Strainers Result

in Turbine Control Valve Closure and an Automatic Reactor Scram.

This problem was discussed in IR 50-321, 366/95-27. No new issues

were revealed by the LER.

E8.4 (Closed) IFI 50-321/96-13-06: Additional Review of Wiring

Deficiency on Electrical Drawings.

This item was identified when licensee personnel discovered that

the wiring in control panels did not match the applicable

drawings. These wiring discrepancies did not result in the

licensee declaring any safety equipment inoperable. The IFI

documented a concern about the process for addressing wiring

discrepancies. The inspectors were informed that the Deficiency

Enclosure 2

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

.

l-

22

l Card (DC) system is the process used when wiring discrepancies are

l identi fied.

Additional reviews and observations by the inspectors and

information from the licensee indicated that an apparent error was

l

made during engineering specification implementation involving the

Torus-to-Drywell Vacuum Breakers. This resulted in personnel

inadvertently de-energizing the 1H Torus-to-Drywell Vacuum Breaker

indication instead of the 1G. The troubleshooting personnel were

using electrical connection drawing 17801, which indicated that

link JJ44 was in series with the 1G vacuum breaker. When the link

was opened the 1H vacuum breaker de-energized instead of the'1G.

Personnel restored the link and issued a DC. The error is

identified as an example of VIO 50-321. 366/96-14-03: Failure to

Implement Configuration Control Requirements. Based on the

issuance of the violation, this -IFI is closed.

,

E8.5 (CLOSED) IFI 50-321.366/94-01-01: Plant Service Water System Flow

Model Verification.

The licensee had conducted Plant Service Water (PSW) system flow

testing to obtain additional data for benchmarking of the PSW

system flow model. As a result of this testing, the licensee

identified and corrected fouling of the Unit 1 High Pressure

Coolant Injection cooler piping and a mispositioned throttle valve

l for Unit 1 Low Pressure Coolant Injection inverter room cooler.

Based on the results of this testing, the PSW system flow model

was updated. The inspector concluded the licensees actions were

sufficient.

E8.6 (CLOSED) URI 50-321.366/94-01-02: High Energy Line Break

Protection for Service Water Systems within the Containment

The licensee had conducted a study of service water system piping

inside containment and determined that twelve locations required

further analysis. These twelve locations were analyzed and found

to have sufficient margin for long term operation. The inspector

,

concluded the licensee had appropriately analyzed the locations in

l

question.

IV Plant Sucoort

.

R1 Radiological Protection and Chemistry Controls

R1.1 Observation of Routine Radiolooical Controls

l a. Insoection Scooe (71750)

General Health Physics (HP) activities were observed during the

report period. This included locked high radiation area doors,

proper radiological posting, and personnel frisking upon exiting

the Radiologically Controlled Area (RCA). The inspectors made

frequent tours of the RCA and discussed radiological controls with

Enclosure 2

-

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

.

.

.,

'

23

HP technicians and HP management. No deficiencies were

identi fied.

R1.2 Radiolooical Controls

a. Insoection Scoce (84750. 86750)

Radiological controls associated with radioactive waste (radwaste)

processing equipment and stora.ge areas were reviewed and

evaluated. In particular. housekeeping and cleanliness, area

postings. radwaste container labels, and controls for high and

very high radiation areas were reviewed for adequacy.

The inspectors made frequent tours of the RCAs. and reviewed and

discussed specific procedural guidance and selected survey results

with HP staff and supervisors,

b. Observations and Findinas

Locked high and very high radiation area controls were verified to

be implemented in accordance with Technical Specification (TS)

requirements. Posting of radwaste storage areas were proper and

in accordance with TS or 10 CFR 20 Subpart J requirements.

Overall, containers holding radwaste, materials or contaminated

equipment were labeled in accordance with 10 CFR 20.1904

requirements. Excluding some isolated examples of dirty floors,

e.g., the Unit 1 (U1) Waste Sludge Tank area, and a potential leak

in the U1 Laundry Drain Tank room. cleanliness and housekeeping

within the RCA and outside radwaste processing and storage areas

were considered to be acceptable.

c. Conclusions

Radiological controls for high and very high radiation areas were

maintained in accordance with TS requirements. Area postings and

labels for containers of radioactive material were appropriate.

Improvements were noted for general housekeeping and cleanliness

relative to observations made during a previous inspection

conducted July 29 through August 2. 1996, and documented in

Inspection Report 50-321, 366/96-10 dated August 30, 1996.

R1.3 Radioactive Waste and Material Transoortation Activities

a. Insoection Scoce (86750. TI2515/133)

The inspectors reviewed Radiological Control (RC) program

activities associated with the packaging and shipping of

radioactive material and waste to either vendor processing

facilities or directly to a licensed burial facility. The review

included evaluation and verification of radwaste classification

activities, and the subsequent packaging and shipping for the

radwaste shipments listed below. The inspection activities also

verified and evaluated implementation of revised 49 CFR Parts

100-179 and 10 CFR Part 71 regulations.

Enclosure 2

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

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

'

I

,

24

'

Records for radwaste and material shipments made between January 1

through November 12, 1996 were reviewed and discussed. In

particular, all documentation associated with the following l

shipments were reviewed and discussed with licensee '

representatives,

o Shipment No. 96-1020. Radioactive material. Low Specific j

Activity (LSA) n.o.s.: 7 UN2912. Fissile Excepted /RO. May 23.  !

1996.

-

o Shipment No. 96-1029. Radioactive material, n.o.s. 7 UN2982.

Fissile Excepted /RO August 7. 1996.

-

o Shipment No. 96-1020. Radioactive material. Low Specific i

Activity (LSA) n.o.s.: 7 UN2912. Fissile Excepted /RO. May 23. '

1996.

1

The following procedures were reviewed and discussed to determine

adequacy in relation to 10 CFR Part 20, 10 CFR Part 61.

10 CFR Part 71 the revised 49 CFR Parts 100-179 and 10 CFR Part 71

] regulations.

o Radiation Protection (RP) procedure. 62RP-RAD-011-05. Shipment

of Radioactive Material. Revision (Rev.) 8. effective April 1.

-

1996.

o 62RP-RAD-042-05. Solid Radwaste Scaling Factor Determination

and Implementation. Rev 3. effective March 26. 1996.

b. Observations

In general, licensee procedural guidance met applicable regulatory

requirements and recent revisions to 49 CFR Parts 100-179 and

10 CFR Part 71 regulations were implemented as required. No

concerns were identified for determination of radwaste scaling

factors. For the Type B radwaste shipments made, the inspectors

verified that licensee was a registered user of the shipping casks

used, and that the a3plicable Certificates of Compliance (C0C)

were maintained at t1e facility and used to develop licensee

procedures for packaging and shipping activities.

In general, shipping paper documentation was completed and

maintained as specified. One issue discussed with licensee

representatives for potential improvement was to enhance

visibility of the emergency phone number on the shipping paper

documentation. In addition, the following two concerns were

identified regarding shipping document Quality Control activities.

o For the Type B shipment documentation reviewed the inspectors

noted that not all of the routine determinations specified in

10 CFR 71.87 were documented as required by 10 CFR 71.91. In

particular the inspectors noted that records did not document

that any structural part of the package which could be used to

lift or tie down the package during transport is rendered

Enclosure 2

__

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

. I

4

.

d

25

' inoperable for that purpose. From discussion with responsible I

licensee representatives, the inspectors determined that all i

structures were rendered inoperable for the shipments made but i

that the determinations were not documented. Prior to the l

November 15. 1996, licensee representatives initiated a change l

to require the appropriate documentation on the Cask Users

4

Checkoff Sheet which is implemented in accordance with

62RP-RAD-011-0S.

o During review of C0Cs and associated documentation for package

type USA /5805/B( ) used for an August 7. 1996 Type B shipment

of irradiated hardware to a licensed burial facility, the

. inspectors noted pages missing in copies of the referenced

documents maintained by Radwaste personnel. The inspectors i

were informed that the noted documentation was received i

'

directly by the radwaste staff from the vendor. Subsequent

review of document control records failed to locate all of the

required documentation. From discussions with applicable

, licensee representatives and review of Administrative Control

Procedure (AP) 20AC-ADM-003-05. " Vendor Manual Review and .

Control." Rev. 4. effective January 22. 1996, the inspectors

verified that program controls were in place to meet the intent

of 10 CFR 70.113 for the packaging Quality Assurance (0A)

program. However, by the end of the onsite inspection.

'

licensee representatives had not determined if the vendor

documents used to make the subject shipment in the

USA /5805/B( ) cask were received, processed and maintained in

accordance with the applicable administrative procedure.

t c. Conclusions

4

Excluding two packaging 0A issues, transportation and packaging

activities for radwaste and material shipments met 10 CFR 71.5 and

49 CFR 100-179 requirements. The revised Department of

Transportation (DOT) guidance was implemented, as applicable.

Radwaste characterization was in accordance with 10 CFR 61.55.

Two concerns were identified for radwaste packaging quality

control documentation. Consistent with Section IV of the

.

Enforcement Policy, one issue corrected prior to the end of the

onsite inspection was identified as NCV 50-321. 366/96-14-06:

Failure to Maintain Records Required by 10 CFR Part 71.91 for

Routine Determinations Specified by 10 CFR 71.87 for a Type B

Shipment. Pending licensee record search, the second issue was

identified as Unresolved Item (URI) 50-321, 366/96-14-07:

Determine If Processing and Control of COC and Associated

Documents for Package Type USA /5805/B( ) Vendor Documents Were in

Accordance with AC Procedure 20AC-ADM-003-05. " Vendor Manual

i Review and Control ."

Enclosure 2

.

'

i

26

R3 Radiation Protection and Control Procedures and Documentation i

l

a. Insoection Scooe (84750. 86750)

)

The inspectors reviewed selected effluent release and radiological

environmental monitoring program data for January. 1995 through

October 30, 1996. Reviewed reports included the Plant Radioactive

Effluent Releases. January 1.1995 through December 31, 1995, and

Radiological Environmental Operating Report for 1995.

Also, selected radiation control /radwaste performance indicators

were reviewed and discussed with licensee representatives.

b. Observations and Findinas

'

For 1995 no abnormal effluent releases were identified. For 1995

and 1996 year-to-date data, dose estimates from effluents were

small percentages of the Offsite Dose Calculation Manual (ODCM)

limits. No significant trends or changes in radiological

environmental monitoring program sample radiological analyses were

identi fied.

c. Conclusions .

!

Effluent release documentation and radiological environmental

monitoring program results were prepared in accordance with ODCM

requirements. The release data and environmental monitoring

results verified offsite releases and resultant doses were a small

fraction of the allowable limits.

R5 Staff Training and Qualifications in Radiation Protection and

Chemistry

a. Insoection Scoce (86750. TI 2515/133)

The training provided to designated staff to meet the requirements

of 49 CFR Part 172 Subpart H. was reviewed and discussed with

licensee representatives. Further, training details provided to

staff regarding implementation of recent DOT changes to

49 CFR Parts 100-179 were evaluated.

From interviews and discussion with applicable Health Physics (HP)

staff members regarding shipping documents and procedures, the

inspectors evaluated the training effectiveness regarding

implementation of 49 CFR Parts 100-179 requirements.

b. Observations and Findinas

Review of training records verified that responsible Health

Physics staff members directly involved in handling and packaging

of radioactive materials were receiving hazardous material

(hazmat) training within the required frequencies. From review of

current training documents. the inspectors verified that recent

DOT changes to shipping and packaging requirements were covered in

Enclosure 2

_ _ _

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

..

.

,

'

27

the course material. From discussion of shi) ping procedures and

shipping papers, the inspectors determined tlat responsible

licensee representatives were knowledgeable of the recent DOT

,

changes.

From review of licensee's hazmat training base documents, the

inspectors identified two training program issues. The first

issue involved the lack of including all staff who had completed

the appropriate training, e.g. a first-line radwaste supervisor,

was not listed in the Hazmat training data base. In addition, the

inspectors noted that a time limit was not established for

completing and returning the training take-home exams provided by

a vendor. Several time periods exceeding one month between course

and satisfactory completion of take-home exams were identified.

Training representatives noted that the identified issues would be

addressed.

c. Conclusions

Hazmat training provided to 3ersonnel handling radioactive

materials was conducted at t1e appropriate frequency. and included

recent changes to DOT regulations. The training provided was

effective, as demonstrated by the knowledge and proficiency of

interviewed staff members. Identified issues observed included

training data base upgrades and timeliness in completion of hazmat

examination.

R7 Quality Assurance in Radiation Protection and Chemistry Activities

R7.1 Licensee Self-Assessment Activities

, a. Insoection Scooe (84750. 86750)

! During the inspection period, the following audit reports and

associated checklists regarding Radiation Control; and Radwaste

processing packaging and transportation program activities

recuired by TS 10 CFR Part 20. and 10 CFR Part 71 were reviewed

anc discussed with licensee representatives.

o Hatch Safety Audit and Engineering Review (SAER). Audit of the

Radioactive Waste Shipping Program. Report Number

(No.) 94-RW-1 dated November 10. 1994.

o Hatch SAER Audit of the Radioactive Waste Program. Report No.

95-RW-1. Dated October 5. 1995.

,

In addition. initial results of a Low Level Waste Characterization

Study, conducted by the Electric Power Research Institute, dated

May 1996. were reviewed and discussed.

b. Observations and Findinas

The audits addressed Process Control Program (PCP), waste

processing, chemistry, radiological controls, radwaste and

Enclosure 2

_ _.

.

.

28

transportation program guidance. implementation and documentation.

Both compliance-based and performance-based strengths, issues,

weaknesses and recommendations were documented. The audits

included review and followup of previously identified items. In

particular, the inspectors reviewed and discussed licensee

followup actions regarding labeling issues identified. No similar

issues were identified during the current review of radiation

control activities.

The low-level waste characterization study results provided

quantitative data regarding sources of radwaste generation and

cost-effective reduction efforts. The project evaluated existing

generation, minimization, processing, and disposal programs and

provided potential mechanisms for reducing costs. Licensee

management informed the inspectors that final results will be used

to focus on radwaste program initiatives.

c. Conclusions

Audits for the radwaste and effluent processing programs were

thorough and comprehensive and met TS. 10 CFR Part 20 and

10 CFR Part 71 requirements. The low-level waste characterization

study was identified as a licensee initiative to quantify and

'

prioritize radwaste program activities.

R8 Miscellaneous RP&C Issues l

a. Insoection Scooe (84750. 86750)

The status of selected radiation control and radwaste performance

indicators were reviewed and discussed with licensee

representatives.

b. Observations and Findinas l

Since 1993, annual dose expenditure per unit outage continued to

decrease and dose expenditures were met. As of November 12. 1996,

dose expenditure was approximately 422 person-rem relative to the

575 person-rem goal.

For 1995 and 1996 year-to-date (YTD) approximately 2.382 and

121.919 curies (Ci) of radwaste were sent to a licensed burial

facility for disposal. The majority of material buried consisted

of resins in 1995 and irradiated hardware in 1996. Waste disposal

volumes for 1995 and 1996 were 10.047 and 9.338 cubic feet (ft')

respectively.

No reduction in personnel contamination events. 177 reported in

1995 and 174 reported YTD in 1996. was observed.

c. Conclusions

No significant declining performance trends were observed for the

performance indicators reviewed.

Enclosure 2

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

- __ _ _

,

• i

l

l'

.

'

29

P4 Staff Knowledge And Performance In EP

P4.1 NOUE Associated with the Inadvertent Lift of Nitrocen System

Relief Valve

a. Insoection Scoce (71750)

On October 28, 1996, while attempting to fill the Unit 2 nitrogen

storage tank, a relief valve on the fill line lifted (See

Section E1.1). The valve discharged into the tank room, partially

filling the room with nitrogen. This resulted in the declaration

of a Notification of Unusual Event (NOUE) due to release of toxic

, gas in accordance with the licensee's EP. The inspectors reviewed

l control room logs and interviewed operators and members of the

emergency planning staff.

'

b. Observations and Findinas

On October 28, 1996, plant operators were conducting a routine

refill of the Unit 2 nitrogen storage tank in accordance with .

34S0-T48-002-25. " Containment Atmospheric Control and Dilution i

Systems." During the fill, a relief valve on the fill line

lifted, discharging nitrogen into the tank room. Partially

'

filling the room with nitrogen gas caused the conditions in the

room to meet the EP definition of " toxic gas release" This

resulted in the declaration of a NOUE. as defined by section 11.3. l

" Hazards to Plant Operation. Toxic Gas." of the licensee's EP.

The event occurred at approximately 11:00 A.M. The shift crew

began to take actions to secure the nitrogen release and re-

establish the appropriate atmosphere in the tank room. At

approximately 11:15 A.M. , the nitrogen release was secured. At

,

approximately 12:00 P.M. . the shift recognized that the conditions

i warranted entry into the EP. The NOUE was declared at 12:20 P.M. ,

and the initial notifications were made within the required time

frame. The NOUE was terminated at 1:04 P.M., when oxygen levels in

the room were determined to have returned to normal.

The inspectors reviewed the licensee's activities and procedures

associated with the event. In accordance with the requirements of

Section A of the EP, the licensee is responsible to " Recognize and

declare the existence of an emergency condition." Implicit in

this requirement is that a decision to enter the EP and classify

If the

.

! the emergency must be made in a timely manner.

'

classification is not made promptly, following the availability of

indications that an emergency condition exists, the goal of the

classification scheme is undermined and the intent of Emergency

l Preparedness regulations would not be met. During this event,

ample time and opportunity existed for the recognition and

declaration of the appropriate emergency classification. The

failure to recognize and declare the existence of an emergency in

a timely manner is a weakness of the implementation of this

portion of the EP.

Enclosure 2

I

l

l

!'

30

'

An event similar to this occurred on October 5, 1994. This event

involved the inadvertent release of carbon dioxide gas into the

control building which resulted in the declaration of a NOUE.

This event occurred at 9:55 A.M. , and the NOUE was not declared

until 11:13 A.M. Corrective action from this event included

training for operators on interpretation of the toxic gas

emergency action level (EAL) and an evaluation as to whether the

EAL was appropriately titled. The training for operators was

conducted in the first 1995 requalification training cycle.

c. Conclusion

While actions to implement the EP after declaration of the

emergency were good, the delay in recognition and declaration of

'

the emergency represents a weakness. This is especially

noteworthy since there had been corrective actions taken as the

result of a recent similar event.

S2 Status of Security Facilities and Eauioment

The inspectors toured the protected area and observed that the

perimeter fence was intact and not compromised by erosion nor l

disrepair. The fence fabric was secured and barbed wire was '

angled as required by the licensee's Plant Security Program (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 persoMel and packages entering the  ;

protected area were searched either by special purpose detectors 4

or by a physical patdown 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 concluded that the areas of the PSP inspected met

the PSP requirements.

V. Manaaement 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 that related to the areas inspected. The

inspectors verified that the UFSAR wording was consistent with the

observed plant practices, procedures, and/or parameters.

X.1 Exit Meeting Summary

The inspectors presented the inspection results to members of the

licensee management at the conclusion of the inspection on

Enclosure 2

.

.

.

31

December 19. 1996. The licensee acknowledged the findings

presented. ,

!

.The inspectors asked the licensee whether any materials examined

during the inspection should be considered proprietary. No

proprietary information was identified.

PARTIAL LIST OF PERSONS CONTACTED

Licensee

Anderson J., Unit Superintendent

Arnold. B., Chemistry Supervisor

Bennett. D., Health Physics Superintendent

Betsill . J. , Operations Manager

. Coggin. C. . Engineering Support Manager

Coleman. V., Chemistry Supervisor

Curtis. S. , Operations Support Superintendent

Davis. D., Plant Administration Manager

Fornel. P., Performance Team Manager

Fraser. 0. Safety. Audit and Engineering Review Supervisor

Hammonds. J., Regulatory Compliance Supervisor

Kirkley, W., Health Physics and Chemistry Manager

Lewis, J., Training and Emergency Preparedness Manager

Moore. C.. Assistant General Manager - Plant Support

Reddick J., Health Physics Supervisor

Reddick, R., Site Emergency Preparedness Coordinator

Roberts. P., Outages and Planning Manager

Smith D., Chemistry Superintendent

Sumner. H., General Manager - Nuclear Plant

Thompson. J. , Nuclear Security Manager

Tipps. S.. Nuclear Safety and Compliance Manager

Wells.. P. , Assistant General Manager - Operations

,

!

!

!

Enclosure 2 i

j

- = - - . . .. . . - - . . - - .. . -- . .- -.- - .-

L-  ;

,

32

l

l

INSPECTION PROCEDURES USED

IP 37551: Onsite Engineering  !

Effectiveness of Licensee Controls in Identifying,

'

IP 40500:

Resolving, and Preventing Problems i

IP 61726: Surveillance Observations  !

'

IP 62703: Maintenance Observations

IP 62707: Maintenance Observations

IP 71707: Plant Operations  !

IP 71714: Cold Weather Preparations l

Plant Support Activities

,

l IP 71750: <

l IP 84750: Radioactive Waste Treatment, and Effluent and j

l Environmental Monitoring

I

IP 86750: Solid Radioactive Waste Management and Transportation

of Radioactive Materials 1

IP 92700: Onsite Follow-up of Written Reports of Non-routine

Events at Power Reactor Facilities

! IP 92901: Followup - Operations

l IP 92902: Followup - Maintenance / Surveillance

IP 92903: Followup - Followup Engineering

l 2515/130: Im roved Standard Technical Specification

Im lementation Audit

! 2515/133: Im lementation of Revised 49 CFR Parts 100-170 and

,

10 CFR Part 71

'

ITEMS OPENED. CLOSED AND DISCUSSED

Ooened

50-321.366/96-14-01 NCV Failure to Include Surveillance l

'

Requirements in Applicable

Procedures (Section 03.1).

50-321.366/96-14-02 IFI Potential Single Failure i

'

Vulnerability in the Freeze

Protection System (Section M2.1).

'

50-321.366/96-14-03 VIO Failure to Implement

Configuration Control

Requirements - Multiple Examples

(Sections M2.2. E1.1. E8.2, and

E8.4).

50-321.366/96-14-04 IFI Potential Deficiencies in the

HPCI Surveillance Procedure

(Section M3.1).

l 50-321/96-14-05 IFI Restoration of 1B EDG Motor

Control Center (Section E2.2).

Enclosure 2

.

.

33

50-321.366/96-14-06 NCV Failure to Maintain' Records

Required by 10 CFR Part 71.91 for

Routine Determinations Specified

by 10 CFR 71.87 for a Type B

Shipment (Section R1.3).

50-321.366/96-14-07 URI Determine If Processing and

Control of C0C and Associated

Documents for Package Type

USA /5805/B( ) Vendor Documents

Were in Accordance with AC

Procedure 20AC-ADM-003-05,

" Vendor Manual Review and

Control" (Section R1.3).

Closed

50-321,366/96-14-01 NCV Failure to Include Surveillance

Requirements in Applicable

Procedures (Section 03.1).

50-321/96-13-06 IFI Additional Review of Wiring

Deficiency on Electrical Drawings

(Section E8.4).

50-321/96-10-01 VIO Inadequate Procedure for

Verifying Plant Service Water

Pump Discharge Valve Positions

(Section 08.2).

50-321.366/96-07-02 VIO Failure to Conduct Testing

Following Molded Case Circuit

Breaker Instantaneous Trip

Setpoint Changes (Section E8.1).

50-321/96-05 LER Loss of Power to Reactor

Protection System Bus Results in

Actuation of Engineered Safety

Featurer (Section E8.2).

50-321/96-04 LER Inadequate Procedure Results in

Reactor Pressure Increase and

Automatic Reactor Shutdown

(Section 08.3).

50-321/96-01 LER Clogged Servo Valve Strainers

Results in Turbine Control Valve

Closure and an Automatic Reactor Scram (Section E8.3).

50-321.366/94-01-01 IFI Plant Service Water System Flow

Model Verification (Section

E8.5).

Enclosure 2

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

= ,

, i

34

50-321.366/94-01-02 URI High Energy Line Break Protection

for Service Water Systems within ,

'

the Containment (Section E8.6),

LIST OF ACRONYMS USED .

!

l ALARA- As Low As Reasonably Achievable

AP -

Administrative Procedure

,

C1 -

Curie

!

CFR - Code of Federal Regulations

COC - Cartificate of Compliance

F - degrees Fahrenheit

DC - Deficiency Card  ;

DCN -

Design Change Notice i

'

DCR -

Design Change Request

DOT -

Department of Transportation

EAL - Emergency Action Level

EDG - Emergency Diesel Generator

EP -

Emergency Plan

EPRI - Electric Power Research Institute

ft -

foot (feet)

FME - Foreign Material Exclusion

FSAR - Final Safety Analysis Report

GPC - Georgia Power Company

gpm - gallons per minute

Hazmat- Hazardous Material

HP - Health Physics

HPCI - High Pressure Coolant Injection

IFI -

Inspector Followup Item

IP -

Inspection Procedure

IR -

Inspection Report

ISI - Inservice Inspection

IST -

Inservice Testing

Improved Standard Technical Specifications ~!

ITS -

KV -

kilovolts ,

LC0 - Limiting Condition of Operation i

LER - Licensee Event Report

LPCI - Low Pressure Coolant Injection

MCC - Motor Control Center

MCCB - Molded Case Circuit Breaker

MSIV - Main Steam Isolation Valve

MWO - Maintenance Work Order

NCV - Non-cited Violation

NOUE - Notice of Unusual Event

NRC - Nuclear Regulatory Commission i

NRR - Nuclear Reactor Regulation

ODCM - Offsite Dose Calculation Manual

PCP - Process Control Program

PCE -

Personnel Contamination Event

PDR - Public Document Room

PM -

Preventive Maintenance

POD - Plan of the Day

PRB - Plant Review Board

Enclosure 2

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PSIG - Pounds Per Square Inch Gauge

PSP - Plant Security Program

PSW -

Plant Service Water

QA -

Quality Assurance

OC -

Quality Control

RAS - Recuired Action Statement

RC -

Raciation Control

FCA - Radiological Controlled Area

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RCIC - Reactor Core Isolation Cooling

Rev - Revision j

RFPT - Reactor Feedwater Pump Turbine i

RG - Regulatory Guide

RHRSW- Residual Heat Removal Service Water ,

RPS -

Reactor Protection System l

RSDP - Remote Shutdown Panel i

RTP - Rated Thermal Power l

RWP - Radiation Work Permit  !

SAER - Safety Audit and Engineering Review ,

SER -

Safety Evaluation Report i

SPDS - Safety Parameter Display System i

SR - Surveillance Requirement

SS - Shift Supervisor

TCV - Turbine Control Valve

TM - Temporary Modification

TRM -

Technical Requirements Manual

TS - Technical Specifications ,

TSC - Technical Support Center  !

TSIP - Technical Specification Improvement Program  !

UFSAR- Updated Final Safety Analysis Report

URI - Unresolved Item  ;

VAC -

Volts Alternating Current l

VIO -

Violation

V0TES- Valve Operation Test and Evaluation System ,

YTD - Year-to-Date l

Enclosure 2

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ATTACHMENT 1

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PARTIAL LIST OF PERSONS CONTACTED

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PECO Enerav

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i R. Boyce, Plant Manager

j .W. Sproat, Director Engineer

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G. Johnston, Director Maintenance

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R. Bickhart, Lead Assessor, Nuclear Quality Assurance

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G. Bird, Manager, Emergency Preparedness

M. Karney, Manager, Security / Emergency Preparedness, Limerick

! D. LeQuia, Director, Site Support

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S. MacAinsh, Manager, Support Services

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C. Mengers, Manager, Limerick Quality Division

G. Stewart, Engineer, Experience Assessment

P. Berry, Manager, Technical Support ]

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W. Coyle, Manager Radwaste

D. DiCello, Radiation Protection Manager

M. Kaminski, Radwaste Engineer

NRC Reoresentatives

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R. Keimig, Chief, Emergency Preparedness and Safeguards Branch

N. Perry, Senior Resident inspector, Limerick

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F. Rinaldi, Limerick Project Manager

J. Shea, Peach Bottom Project Manager

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D. Jaffee, Acting Limerick Project Manager

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c. Conclusions  ;

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The inspector noted that management expected to complete reviews for the abandonment

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of selected radwaste equipment in December 1996. The updating of the UFSAR in

accordance with 10 CFR 50.71 (e) remains open pending additional NRC review.

R8.2 Plant Tour Observations

During the inspection, the inspector made various tours of the RCA. The inspector's

j review indicated an apparent need for improved housekeeping. During the tours, the

inspector noted oil leaks, wrenches on the floor, metal wire clippings, and rags left in l

! areas.

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The inspector noted plant personnel were preparing for a periodic station housekeeping

j activity.  !

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V. Manaaement Meetinas a

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j X1 Exit Meeting Summary  ;

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The inspector presented the inspection results to members of plant management at the

conclusion of the inspection on December 16,1996. The plant manager acknowledged

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the inspectors' findings. The inspectors asked whether any materials examined during the

j inspection should be considered proprietary. No proprietary information was identified.

l X2 Review of UFSAR Commitments

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A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR

description highlighted the need for a special focueed review that compares plant practices,

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procedures and/or parameters to the UFSAR description. While performing the inspections

discussed in this report, the inspector reviewed the applicable portions of the UFSAR that

related to the areas inspected. The inspector verified that the UFSAR wording was

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consistent with the observed plant practices, procedure and/or parameters, in addition, the  !

inspectors reviewed portions of the Emergency Plan, since the UFSAR does not specifically l

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include emergency preparedness matters. The inspectors specifically evaluated Section 5 1

concerning laboratory facilities and Section 6 concerning local support service personnel

training for proper implementation. No discrepancies between Plan wording and

i implementation were noted.

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