ML20134P155

Insp Repts 50-324/96-18 & 50-325/96-18 on 961208-970118. Violations Noted.Major Areas Inspected:Operations, Maintenance,Engineering & Plant Support

ML20134P155
Person / Time
Site:	Brunswick
Issue date:	02/14/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20134P125	List: ML20134P121 ML20134P136 ML20134P155
References
50-324-96-18, 50-325-96-18, NUDOCS 9702250160
Download: ML20134P155 (25)

See also: IR 05000324/1996018

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U. S. NUCLEAR REGULATORY COMMISSION

REGION II

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Docket Nos: 50-325, 50-324

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License Nos: DPR-71, DPR 62

Report No: 50 325/96-18, 50 324/96-18 [

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, Licensee: Carolina Power & Light (CP&L)  ;

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! Facility: Brunswick Steam Electric Plant. Units 1 & 2

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Location: 8470 River Road SE ,

4 Southport, NC 28461  !

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Dates

December 8, 1996 - January 18, 1997 ,

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Inspectors: C. Patterson, Senior Resident Inspector

. M. Janus, Resident Inspector ,

E. Brown Inspector In Training  ;

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Approved by: M. Shymlock, Chief. Projects Branch 4 ,

Division of Reactor Projects  ;

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Enclosure 2

9702250160 970214

PDR ADOCK 05000324

0 PDR

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EXECUTIVE SUMMARY

Brunswick Steam Electric Plant Units 1 & 2

NRC Inspection Report 50 325/96-18, 50 324/96-18

This integrated inspection included aspects of licensee operations,

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

period of resident inspection.

Operations

An Updated Final Safety Analysis Report (USFAR) discrepancy was

identified concerning physical marking of voltage rating on cable trays.

(Section 02.1). This issue will be tracked as part of an unresolved

item concerning UFSAR discrepancies.

A noncited violation for failure to have a procedure for filling the

aneumatic nitrogen storage tank resulted in a loss of pneumatic nitrogen

leader pressure. (Section 02.3). The licensee initiated corrective

action to look at all contractor supplied services.

Maintenance

A personnel error resulted in an inadvertent engineered safety feature

actuation during performance of a surveillance test. (Section M1.1). A

test meter switch was in the wrong position while taking a reading. The

licensee initiated actions to add precautions to the procedure and

reported this event.

The licensee identified that inadequate tensioning of a diesel generator

head gasket following maintenance was the result of interchangeable tool

parts on similar size tools. The problem was identified and corrected

after a maintenance test prior to declaring the diesel operable.

(Section M1.2).

A violation was identified when gauges that were out of calibration were

used in a surveillance test. (Section M1.3). The licensee reperformed

the test using calibrated test gauges.

The inspectors determined that many of the scoping determinations

reviewed for nonsafety systems did not contain adequate justification

for a Structures, Systems, and Components (SSCs) inclusion or exclusion

from the Maintenance Rule. (Section M1.5). A violation was identified

for the failure to include required nonsafety SSCs in the scope of the

Maintenance Rule in accordance with 10 CFR 50.65(b).

Enaineerina

The Nuclear Assessment Section Independent Review Program was reviewed

and found to be ineffective. (Section E7.1). Trends have not been

identified and reports have repeatedly identified difficulty in

obtaining required review items.

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Plant Sucoort

The site security force conducted thorough searches of personnel

. entering the plant during a power outage although normal detection

devices were not operable. (Section S1).

A fira drill was conducted in a realistic and challenging manner for the

fire';rigade. (Section F5.1).

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Report Details

Summary of Plant Status

Unit 1 operated continuously during this period without any significant

problems. At the end of the inspection period the unit had been on line r

72 days. Although a 5% power uprate was approved for the unit, the ~

licensee committed to hold the unit at the new 95% power level pending

resolution of questions.

Unit 2 operated continuously during this period without any significant

problems. At the end of the inspection report, the unit had been on-

line 127 days.

I. Operations

01 Conduct of Operations

02- Operational Status of Facilities and Equipment

02.1 Cable Trays Walkdown

a. Inspection Scope (71707)

The inspector reviewed the identification markers and loading of ,

electrical cable trays as described in the Updated Final Safety Analysis

Report (UFSAR).

b. Observations and Findinas

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The inspector reviewed UFSAR section 8.3.1.3. Physical Identification of

Safety Related Ecui ment, and section 8.3.1.4.3, Cable Tray Fill and l

Cable Routing. hal(downs were performed of the service water building,

diesel generator building, and cable spreading rooms on January 7,1997. i

The UFSAR describes a unique color coding system for cable trays along '

with markers for tray number, voltage, and division. The inspector

inspected the cable trays and found the physical identification of cable

trays consistent with the UFSAR description with one exception. No

voltage identification markers could be found. This item will be

identified as part of URI 325(324)/96 05-02, UFSAR Discrepancies. ]

The cable tray loading was found to be consistent with the UFSAR loading

description. For example, 4 kilovolt cables were limited to a single

layer of cables. The inspector found for the 4 kilovolt service water

pump motors one layer of cable in the cable trays. Smaller diameter

cables or lower voltage cable had multiple layers of cables in the cable

trays. Cables containing 125 VAC and 120 VAC circuits were limited by

the UFSAR to a tray loading where the total square inch cross sectional

area of the cables in the tray shall not exceed 75 percent of the total

area of the tray.

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c. Conclusions  !

In general, cable tray identification markers and loadings were found

consistent with the UFSAR. One exception was noted in that the cable  !

trays did not contain any voltage identification markings.

02.2 Special UFSAR Review

A recent discovery of a licensee o>erating the facility in a manner

contrary to the UFSAR description lighlighted the need for a special

focused review that compares plant practices, procedures, and/or

parameters to the UFSAR descriptions. 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 l

observed plant practices, procedures, and/or parameters.

The UFSAR discrepancy discussed in paragraph 02.1 was identified by the

inspector concerning lack of voltage designation of cable trays

identification markers. This item will be identified as part of URI

325(324)/96 05 02, UFSAR Discrepancies.

The inspector also noted a Condition Report (CR) 97-00033 concerning the

licensee's UFSAR review programs. The CR was the result of a Nuclear

Assessment Section (NAS) audit. The concern was that the review

activities to identify UFSAR discrepancies had not been of sufficient

depth to establish and maintain the integrity of the UFSAR. Review of

the resolution of this CR will also be part of URI 50-325(324)/96-05 02,

UFSAR Discrepancies.

02.3 Control of Pneumatic Nitroaen Tank Fillina

a. Inspection Scope (71707)

The inspectors reviewed the events surrounding low aneumatic nitrogen

(PN) header pressure during contractor filling of tie PN tanks.

b. Observations and Findinas

On December 17, 1996. Unit 2 control room received annunciators

indicating PN system header pressure had decreased below 105 psig.

Header pressure was normally maintained above 150 psig, below 105 psig

would have required entrance into an abnormal operating procedure, and a

decrease below 95 psig would have required a manual scram. Failure of

the PN system would affect the nitrogen for various pneumatically

operated components in the drywell including the Inboard Main Steam Line

Isolation Valves, Recirculation Pump Seal Injection and Safety Relief

Valves. An auxiliary operator was dispatched to the PN storage tank

skid and observed a contractor tilling the pneumatic nitrogen storage

tank. Local pressure readings indicated 105 110 psig. The contractor

was informed of the pressure requirement and promptly raised pressure

above 150 psig.

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The inspector discussed the event with the licensee. The licensee

identified that PN tank filling guidance was included in a standing

instruction but not in the system operating procedure. The inspector

reviewed CR 96 4078, associated annunciator and Operations procedures,

and could not locate any guidance for the PN system tank filling

evolution. Currently, Standing Instruction SI 96166 requires an

auxiliary operator to be present during the PN system filling evolution.

The licensee indicated that a change would be instituted to make the SI

requirements part of the system operating procedures. In addition, the

licensee indicated that a review would be performed to assess the

adequacy of licensee contractual requirements for contractors during

routine o)erational activities. The failure to have a procedure to

control t1e filling of the Pneumatic Nitrogen Storage Tank was

identified as a violation of Technical Specification 6.8.1 which

requires procedures be maintained for activities defined in Appendix A

to Regulatory Guide 1.33. This licensee identified and corrected

violation was treated as a Non-Cited Violation, consistent with Section

VII.B.1 of the NRC Enforcement Policy. This Non Cited Violation was

identified as NCV 50-325(324)/96 18-01, Failure To Establish Procedures

For Nitrogen Tank Filling.

On December 29, 1996, the inspector observed contractor replacement of

PN system tank pressure instrumentation. Maintenance personnel were

present to provide oversight and verification of contractor activities.

Auxiliary operator support was not required for this evolution.

Satisfactory communication was maintained with the control room

throughout the activity.

c. Conclusions

A noncited violation was identified for failure to have a procedure

governing the filling of the pneumatic nitrogen storage tank which

resulted in a loss of header pressure.

08 Miscellaneous Operations Issues (92901)

08.1 (Closed) LER 1-95 08: Spurious Actuation of the Primary Containment

Isolation System (PCIS) Group 6, Containment Atmospheric Control (CAC)

Valves.

On May 13, 1995, between 8:00 pm and 12:00 am, Unit I received saurious

Group 6 isolation signals. Initially, the Group 6 Systems and t1e

Reactor Building Ventilation Systems (RBVS) isolated and both trains of

the Standby Gas Treatment System (SBGT) automatically started.

Subsequent isolation signals caused no additional plant effects due to

the licensee maintaining the RBVS isolated and SBGT running until the

cause could be determined. The licensee investigated existing plant

conditions and identified no actual trip or isolation conditions that

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would initiate the isolation signals. Further licensee testing

concluded that the isolations were tne result of spurious de-

energization of the X82 relay located in the Reactor Building

Ventilation Radiation Monitoring subsystem.

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The licensee tested the relay and could not determine a reason for the i

spurious relay de-energization. The relay was replaced and sent to the

vendor for testing. The vendor could identify no reason for the

spurious de-energizations. The inspectors reviewed Licensee Event ,

Report (LER) 1 95 08. Based on the completion of the committed

corrective actions, continuing trending through the Maintenance Rule and

no reoccurrences of the event this item is closed.

II. Maintenance

M1 Conduct of Maintenance

M1.1 Inadvertent Enaineered Safety Feature (ESF) Actuation Durino Conduct of

Maintenance Surveillance Test (MST).

a. InsDection Scope (61726)

In response to an inadvertent ESF Actuation, the inspector reviewed the

actions, systems responses and causal factors associated with this

event.

b. Observations and Findinas

On December 13, 1996, Unit I was operating at 95% power when it received

an invalid Division 1 Loss of Coolant Accident (LOCA) signal. The i

signal resulted in the following automatic actuations: start of Diesel

Generators (DGs) 1, 2. 3, and 4: start of Unit 1 Core Spray Pump 1A:

start of the Unit 2 Nuclear Service Water Pum) 2A: a Group 10 Division  :

1, actuation, isolating pneumatic valves to t1e primary containment: and  !

, closure of the Unit 1 Reactor Building Closed Cooling Water Heat

Exchanger Service Water Inlet valve. Subsequent event investigation

revealed that the signal was the result of an error made during the

conduct of Maintenance Surveillance Test (MST) OMST-RHR21Q, Residual  ;

Heat Removal-Low Pressure Coolant Injection (RHR-LPCI), Core Spray

System (CSS) and High Pressure Coolant Injection (HPCI) Drywell Pressure

Trip Unit Channel Calibration. '

During the performance of this MST, the technician was required to l

verify voltage between two terminal points in the relay logic. Prior to i

verifying the voltage, a questionable reading caused the technician to

sto) the test and remove his instrument leads from the relay. The l

4 tec1nician identified the problem through a continuity check of his test '

instrumentation. After verifying continuity, the technician reconnected

his test leads to the relay. On connecting the meter, the circuit was I

com)1eted, causing the various actuation signals to occur. The

tec1nician failed to verify that the meter wn correctly set on the

voltage scale prior to reconnecting his test instrumentation. When the l

meter was reconnected, it was on the resistance scale, which completed l

the circuitry resulting in the invalid LOCA signal and subsequent i

actuations.

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Following verification that it was not a valid LOCA signal, the

operators immediately secured the running equipment and restored the

plant to its normal configuration. All systems responded as expected,

and no adverse impacts occurred as a result of this event. The

inspector responded to the control room following the event, determined

what had happened, the probable cause, and verified that all appropriate ll

actions and responses had occurred. The ins j

did not start as expected on a LOCA signal. The pector noted discussed

inspector that a RHR pump .

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this fact with the control room operators and licensee management. 1

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Based on their reviews, the licensee determined that the pump did not 2

start as expected because of the short being located downstream in the

logic circuity. The inspector reviewed the circuit diagrams and the .

licensee's explanation and determined that their explanation was

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reasonable. The inspector did not identify any other problems with the

operators recovery from the event. The inspector verified that the

licensee made the approariate 10 CFR 50.72 notification to the NRC.

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, Immediately following t1e event, the HST was secured, and the licensee

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initiated an event team investigation.

In reviewing this event, the inspector identified that this was not the

first time this type of event / error occurred. The inspector identified i

that a similar error had occurred on December 15, 1994, during the '

l performance of IMST RHR21M, High Drywell Pressure Calibration and  ;

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Channel Functional Test on Unit 1. During this event, the technician  !

inadvertently switched a Simpson model 260 volt ohm meter (V0M) with a

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tone test function to the incorrect setting, (tone test) causing an

inadvertent ESF actuation. This event was documented in LER 1-94 15,

1 dated January 16, 1995. In the LER, the licensee determined that the

Simpson Model 260 V0M with the tone function would no longer be used for

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relay contact checks in MSTs. As a corrective action, the licensee

removed all Simpson model 260 metert with the tone test function from

use or issuance on site. While the most recent event did not involve a i

Simpson model 260 meter with tone test function, the corrective actions '

taken did not preclude the type of personnel switch positioning error

encountered.

The inspector reviewed procedure OMST RHR210, Revision 0, dated

September 12, 1996, used during the December 13, 1996, event and

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verified that the tools required section only specified V0M.

Additionally, the inspector reviewed the procedure and verified that it

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did not provide any special guidance, notes or cautions on the use of a  ;

V0M for taking voltage readings in the relay logic trains. The  ;

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inspector also reviewed Work Request / Job Order (WR/J0) AFZH014 which

controlled this test activity, and identified that it did not provide

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its use.

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The inspector reviewed the licensee's root cause determination which

concluded that personnel error was the primary cause of this event. The  !

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licensee determined that the technician failed to self check his

switches and instrumentation prior to recommencing the test procedure. l

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As a result of this event, the licensee developed the following

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corrective actions which are documented in LER 1-96 17, dated

January 13, 1997: appropriate administrative action was taken with the

technician involved; maintenance and I&C technicians were briefed on

this event prior to the performance of further field work; work

expectations were provided to Maintenance and I&C personnel providing

actions to be taken when problems are encountered during the performance

of surveillances, including an inde>endent review of test equipment

configuration prior to restart of t1e test; the use of Simpson model 260

V0Ms for circuit checks in MSTs has been restricted to require

supervisor concurrence prior to being issued for use: MST procedures

will be revised by December 18, 1997 to delineate those for which the '

use of the Simpson model 260 V0M is inappropriate; and MST 3rocedures

with the potential to cause Emergency Core Cooling System (ECCS)

actuation; from a single contact closure will be revised by March 1,

1997 to provide specific warnings prior to the critical steps and

require independent review of test equipment configuration prior to

restart of test activities if the test is stopped for any problems; and

the development of a training module to be incorporated into the

existing Maintenance ECCS training by March 21, 1997, enhancing

technician knowledge and understanding of the effects of test equipment

misalignment.

c. Conclusions.

The inspector reviewed this event and others that have happened in the

past and concluded that the licensee's root cause determination of

personnel error was correct. The inspector notes that the licensee's

corrective actions are enhancements to the. testing process, and provide

additional steps which should enhance self checking and attention to

detail.

M1.2 Diesel Generator (DG) Num_br 2 :vlinder Liner Replacement Outaae.

a. Insoection Scope (62707)

The inspector reviewed the work activities and problems associated with

the completion of the DG Number 2 cylinder liner replacement outage.

b. Observation and Findinas

As part of scheduled DG maintenance activities, the licensee removed DG

2 from service on January 6,1997 for the replacement of cylinder

liners. The inspector observed the work activities associated with the

DG outage on several occasions. On January 8, 1997, the licensee

finished the work activities and was in the process of performing the

maintenance / break in runs on the DG when a problem was identified.

During the break in runs two and three, small pulses of black smoke were

observed coming from the base of the 1 Right cylinder head. During the

fourth run, more aulses were observed and the licensee identified a

cylinder head gas (et leak on the 1 Right cylinder.

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On identification of the leak, Maintenance and Engineering immediately

secured the fourth break in run to identify and correct the cause of the

leakage. When the cylinder head studs were detensioned, it was

identified that one stud was tensioned 700 pounds per square inch less

than the other three studs. The inspector questioned these results, and

reviewed the head installation procedure completed on January 7,1997.

The inspector verified that the Quality Control sign offs were

completed, verifying that the studs had been tensioned to the correct

value. Based on finding the one bolt at a lower tension than the

others, the licensee initiated an investigation to determine the

possible causes of this problem. Examination of the head gasket

revealed the presence of carbon indicating a leak. The mating surfaces

and gasket were examined and no abnormalities were identified which

could have caused the leak. The cylinder head was cleaned and

reinstalled using a new head gasket.

The licensee determined that the wrong size stud tensioning tool had

been used. There were two different size (3.5 and 4.0 inch) . stud

tensioning tools with interchangeable inserts which looked identical. A

3.5 inch tool was for the cylinder head and a 4.0 inch tool was for the

main bearings. The inspector witnessed a demonstration of this problem

in the clean maintenance shop. This was a unique problem not readily

apparent to the mechanics or QC inspector. The licensee revised their i

procedure to check for the proper tools and stamped the tools for easy

identification. The operability of the DG was not effected because the

head gasket leak was identified in a maintenance run prior to declaring

the DG operable.

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During the removal of the rocker box assembly to examine the cylinder

head, the push rod tappet socket dislodged from the exhaust valve rocker

arm. On examination of the exhaust valve rocker arm and tappet

assembly, it was identified that the tappet socket had been staked in

place as opposed to the design required .005 to .0025 of an inch

interference fit. Measurements of the rocker arm bore indicated an

oversize condition. The licensee contacted the vendor, who verified

that staking was not an acceptable method of securing the tappet socket

to the rocker arm. A rocker box assembly was obtained from another

utility, inspected and installed on the engine. In response to this

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finding, the licensee examined all other rocker arm tap >ets on DG 2  ;

prior to restarting the maintenance runs. No other pro)lems were I

identified. The licensee plans to examine the remaining DGs during i

their upcoming maintenance outages. The licensee examined all DG i

maintenance records and did not identify any work which would have l

repaired or replaced this rocker arm assembly. The licensee believes

that this part was from original engine assembly. Other DG owners were

contacted and no similar problems were identified. Problems with the

loose tappet socket were not communicated directly to the control room

for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This delay in reporting equipment problems

was documented by the licensee in CR 97-164.

On January 10, 1997. DG E was returned to service following successful

completion of the remaining maintenance break-in runs and operability

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test. No further problems were identified. The licensee documented j

, these problems in CR 97-180. '

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c. Conclusions

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The ins)ector concluded that an improperly tensioned head bolt was

caused )y similar size tensioning tools having interchangeable parts. l

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Operability of the DG was not impacted. The licensee identified a delay i

in communicating a potential generic issue to the control room. i

M1.3 Unit 2 RHR Full Flow Testina

a. Insoection Scope (61726)

The inspector observed the performance of Periodic Test (PT) OPT- 1

08.2.2c, LPCI/RHR System Operability Test - Loop A for Unit 2.

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b. Observations

On December 12, 1996 the inspector observed the performance of OPT-

8.2.2c. This procedure was performed to verify that the "A" loop of the

RHR system was capable of being started from the control room and

developed adequate flow needed during LPCI and suppression pool cooling.

Additional requirements included American Society of Mechanical

Engineers (ASME) check valve and aump vibration testing. The inspector

observed acceptable procedural ad1erence and self-checking by the

licensee staff. Also, satisfactory communication was maintained between

the control room and the auxiliary operator positioned locally.

During the check valve portion of the Periodic Test (PT), indications

were observed of leakage past the RHR pump discharge check and the RHR

minimum flow check valves (2 E11 F031A and the 2 E11-F046A), therefore

the PT was not completed satisfactory. A work request / job order (WR/J0)

was initiated and subsequent trouble shooting quantified the leakage and

determined that no operability concern existed since the leakage was

within the make up capabilities of the RHR keepfill system. l

c. Findinas

The inspector reviewed the PT to ensure satisfaction of the description

and requirements as specified in the Technical Specification (TS) and

UFSAR. The TS required that the RHR pumps developed a total flow of at

least 17,000 gpm against a system head corresponding to a reactor vessel

pressure of greater than 20 psig and that system check valves were

satisfactorily exercised to their closed or opened position. Standing

Instruction (SI) 96 150 issued in November 1996, directed the use of

temporary gauges for the "A" and "C" RHR pumps suction and discharge

pressure instrumentation during performance of this PT. Further

investigation revealed that the SI was a result of CR 96-2826. IST Local

Gauge Problems dated August 8, 1996, which discussed the existing drift

problem affecting the calibration of the permanently installed gauges.

The inspector determined that temporary gauges were installed on the

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suction side, but no gauges were installed on the discharge side. In

addition, the inspector identified problems with the calibration of the

RHR discharge pressure gauges 2-E11 PI R003A(C) as prescribed in the

Special Tools and Equipment section. The inspector discussed these

issues with the licensee.

The licensee initiated CR 96 4147 to document the failure to install the

test gauges. The licensee performed a calibration check on the existing

installed discharge pressure gauges under WR/JO 96 AJQN1 to determine

if the data obtained from the existing installed instrumentation was

still valid. The calibration check on the 2 E11 PI R003A(C) discharge

pressure gauges revealed that the gauges did not meet the ASME Section  ;

XI calibration requirement of *0.5% full scale. The failure to assure

4 that gauges used in activities affecting quality were properly

calibrated to maintain accuracy within necessary limits is identified a

violation of 10 CFR 50, Appendix B, Criterion XII. Control of Measuring

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and Test Equipment. This violation is identified as 50-324/96 18 02, 1

Testing Using Uncalibrated Gauges.

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A review of other completed periodic tests was performed to identify-

other possible errors. No similar errors were identified in the other

. pts performed. The licensee repeated PT 08.2.2c on January 10-11, 1997

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and the 2C RHR pump was placed in the alert range which required

doubling of the testing frequency until the cause of the deviation is

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determined and the condition corrected. Upon review of the second test

results, the inspector concluded that the test had been adequately

performed and had used properly calibrated instrumentation.

d. Conclusions

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During loop "A" full flow testing, leakage was identified past the RHR

, discharge and minimum flow check valves, subsequent trouble shooting

quantified the leakage and determined that no operability concern

existed since the leakage was within the make up capabilities of the I

keepfill system. The inspector identified a violation when the licensee  ;

performed the "A" loop full flow test with uncalibrated discharge

pressure gauges.

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M1.4 Unit 2 RHR Testina - Looo B

a. Insoection Scope (61726)

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The inspector ooserved all or a portion of the following surveillances:

OPT 08.1.3c Remote Shutdown RHR System Flow Indicator Channel Check Test

OPT-08.1.4b RHR Service Water System Operability Test Loop B

OPT 08.2.2b LPCI/RHR System Operability Test Loop B

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i b. Observations and Findinas  !

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The inspector attended the pre-job brief on January 9, 1997, prior to

the performance of the surveillances. The three procedures were

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performed together. The RHRSW was placed in service and maintained in

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operation while the RHR-system was operated. RHR system flow indication  !

was checked at the remote shutdown panel while the RHR system was in

4 operation. During verification of kHR system flow the RHRSW system '

pressure was maintained higher than RHR system pressure to prevent

inleakage of suppression pool water (potentially contaminated) into the l

RHRSW system.

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The inspector locally witnessed the starting of RHRSW pumps 2B and 2D _

from the reactor building. The inspector observed the operating pumps,

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checking oil flows, suction and discharge pressure test gauge reading,  ;

and pump vibration. No equipment problems were noted.

Next, the inspector verified that calibrated test gauges were installed

for RHR pump operation per OPT 8.2.2b. Test gauges were installed on

j the suction and discharge for each pum). The problem identified with

uncalibrated test gauges used during RiR loop A (paragraph M1.3) was not

repeated. The inspector verified, in the control room, that each pump

developed a flow of at least 7,700 gpm (torus cooling) and both pumps ,

. developed a total flow of at least 17,000 gpm (LPCI).

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In addition, the inspector verified that the RHR flow was indicated on ,

the remote shutdown panel during RHR pump operations. This was the i

acceptance criteria for a channel check of the flow indicator for OPT-  :

08.1.3c. ,

c. Conclusions I

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The inspector concluded that each of the surveillances were adequately

performed.

M1.5 Maintenance Rule Nonsafety SSCs Scooina

a. Insoection Scope (62707)

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The inspectors reviewed the adequacy of the licensee's program for

compliance with the 10 CFR 50.65 (Maintenance Rule) requirements

concerning the scoping of nonsafety related structures, systems, or

components (SSCs) relied upon to mitigate accidents, transients or are I

included in the Emergency Operating Procedures (E0Ps).  !

b. Observations and Findinas

The inspectors initially reviewed Emergency Operating Procedures OE0P-

04 RRCP, Radioactivity Release Control Procedure and E0P 03 SCCP,

Secondary Containment Control Procedure and selected several SSCs for

verification of status with respect to the Maintenance Rule. Among the

SSCs selected included the Ambient Chlorine Detectors, Communications.

Emergency AC & DC Lighting, Process Radiation and Area Radiation

Monitoring Systems. Nuclear Generation Group Standard Procedure ADM-

NGGC 0101 established the program for the implementation of the

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

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Maintenance Rule which included Maintenance Rule scoping of all plant ,

structures, systems, and components. .

Ins)ector review indicated that the Communications, and Emergency AC &  !

DC _ighting Systems were excluded from the sco)e of the Rule. Review of  !

various plant emergency procedures including A> normal Operation i

Procedure 0A0P 5, Radioactive Spills High Radiation, and Airborne l

Activity 0A0P 34 Chlorine Emergencies, OEOP-01-AEDP, Alternate  !

Emergency Depressurization Procedure, OEOP-01 PCFP, Primary Containment  !

Flooding Procedure revealed that the public address system was relied i

upon to communicate emergencies, abnormal conditions, and evacuation  !

instructions. In the event of a station blackout, normal AC lighting  ;

would be lost and while on station batteries DC lighting would be relied -i

upon for illumination, until restoration of AC lighting. Recent ';

performance >roblems with the DC Lighting were noted in Condition Report  !

(CR) 97 85 w1en several of the Emergency DC lighting elements'were found

to have deficiencies requiring impairments. The inspector determined j

that all were relied upon to mitigate accidents or transients during the  ;

performance of abnormal or emergency arocedures. The failure to, include  ;

the Communications Emergency AC and X' Lighting in the scope of the  ;

' Maintenance Rule is the first example of a violation of 10 CFR 50.65(b)'  !

and is identified as VIO 50 325(324)/96 18 03, Required Nonsafety SSCs i

Excluded from Maintenance Rule Scope.  ;

I

In reviewing ambient chlorine detector performance since March of 1995, l

the inspector discovered a long history of poor performance. The '

inspector identified 5 separate instances of multiple detector failures.  !

The performance history, including Licensee Event Reports (LERs) and NRC  :

violations, for these detectors is further described in LERs 1 95-02, i

1 96 05, 1 96 12, and Inspection Reports 50 325(324)/96 15 and  :

50 325(324)/96 05. The ambient chlorine detectors provided isolation of l

the control room to protect the operators from the effects of a toxic '

release as directed in 0A0P 34. Inspector review of nonsafety system j

scoping for the Control Building Heating, Ventilation, and Air-  :

Conditioning and Chlorination Systems indicated that despite the  !

Chlorination System being included in the scope, the ambient chlorine i

detectors were not. J

1

The inspector reviewed several work tickets for the turbine ventilation i

radiation monitor and Inspection Report 50 325(324)/96 15 which revealed

violations issued for improper Area Radiation monitor setpoints and

inadequate performance of area radiation monitor response checks.

Various Reactor Building Area Radiation. Turbine Building Ventilation,

Service Water Effluent, and Main Steam Line Radiation Monitors, function

to record local radiation levels and annunciate when radiation setpoints

are exceeded. These monitors were used in the E0Ps as entry conditions

for radioactive release control procedure OE0P 04-RRCP, and in

secondary containment control procedure OE0P 03 SCCP to direct control

room operators in the assessment of Emergency Action Levels. In

addition the Turbine Ventilation Monitor is also L ed by the E0Ps

through the plant emergency procedures to calculate offsite dose release

rates. The inspector reviewed the Process and Area Radiation scoping

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12

forms and determined that these monitors had not been designated in the

scope of the Maintenance Rule. The failure to include the Ambient

Chlorine Detectors. Turbine Ventilation, Service Water Effluent, Main

Steam Line and various Reactor Building Area Radiation monitors in the

scope of the Maintenance Rule is the second example of a violation of 10

CFR 50.65(b) and is identified as VIO 50-325(324)/96 18-03, Required

Nonsafety SSCs Excluded from Maintenance Rule Scope.

The inspector determined that many of the scoping determinations

reviewed did not appear to contain adequate justification for a SSC's

inclusion or exclusion from the Rule. The inspector discussed the

adequacy of those scoping reports with the licensee, and those systems

identified have been scheduled for review during the next Maintenance

Rule Expert Panel.

c. Conclusion

The inspector reviewed a sample of systems for correct scoping in

accordance with the requirements of 10 CFR 50.65. The inspector

determined that many of the scoping determinations reviewed did not

appear to contain adequate justification for a SSC's inclusion or

exclusion from the Rule. A violation was identified for the failure to

include required nonsafety SSCs in the scope of the rule in accordance

with 10 CFR 50.65(b).

MB Miscellaneous Maintenance Issues (92902)

M8.1 (Closed) Violation 50-325/95 10 02: Failure to Control Contracted

Services - Pins and Rollers Project.

This violation was issued as a result of'four events associated with the

Unit 1 Pins and Rollers project. During the course of this project,

four separate events involving contractor work in the s)ent fuel pool

occurred. These events involved a drop p d control rod alade from the

curb hanger; an unhooked control rod blade while in transit in the spent

fuel pool; the loss of the plexiglass view window into the spent fuel

pool skimmer surge tank; and the failure to perform independent

verification of spent fuel pool location prior to removing a control

blade from the pool. All of these events resulted from the licensee's .

failure to monitor and control the effectiveness and quality of I

contracted services.

The licensee's initial response to this violation dated June 22, 1995,

denied this violation, based on their contention that they had provided

a)propriate measures to assure proper conformance to the contract

t1 rough self identifying problems and implementing corrective actions. i

The NRC in a letter dated August 28, 1995, replied to the denial,

finding that CP&L did not provide any information that was not already ]

considered in determining the significance of the violation. The

.

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violation was upheld, with the NRC concluding that CP&L was charged with  ;

establishing measures which were effective and assuring that activities i

1

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

13

were controlled, and that these controls were not adequate due to the

unsatisfactory results displayed.

In a letter dated September 26, 1995, the licensee committed to

implement the following corrective actions: terminating the Pins and

Rollers Project: development of a dedicated refueling floor organization

to provide consistent improvement of floor activities, monitoring to

ensure contractor compliance with licensee procedures: development of an j

incentive and penalties program for contracted services based on  ;

performance; development of a refueling floor project implementation  ;

plan for use in future outages; and incorporation of a milestone for l

issuance of this plan in the outage planning schedule.

The inspector monitored the performance of the licensee's refueling

floor activities during the last two outages. The inspector focused ,

attention on the ..antrol of contractor services. Improved performance

was observed in tM: area, demonstrating the effectiveness of the >

licensee's corrective actions. Additionally, NRC Inspection Report 50-

324,325/96 15, issued on November 22, 1996, documented reactor shroud

and vessel inspections conducted in an exemplary manner by knowledgeable l

and qualified contractors. No further problems have been observed in  ;

the control of contract services for refueling activities. This item is '

considered closed,

i

M8.2 (Closed) LER 1-95 16: Engineered Safety Feature Actuation Due to l

Malfunction of Reactor Protection System Electrical Protection Assembly

Logic Card

On July 21, 1995, at 12:26 pm, Unit I received a Division II Reactor

Protection System (RPS) trip, Primary Containment Isolation System  ;

(PCIS) Groups 1, 2, 3, and 6, Reactor Building Ventilation and Secondary i

Containment isolation signals, and a start of both trains of the Standby  ;

Gas Treatment System. These actuation signals were consistent with the  !

'

failure of the RPS Bus B Electrical Protection Assembly Breaker No. 4

(EPA-4). The affected systems were returned to the normal configuration

and RPS Bus B was realigned to the alternate source. At 7:33 pm, during

troubleshooting activities, RPS B was realigned to the normal source and '

subsequently the EPA 4 tripped again resulting in the same isolations

and actuations. The EPA 4 card was replaced and further troubleshooting  ;

by the licensee and the vendor was performed.

Licensee investigation revealed that the EPA 4 logic card undervoltage f

and underfrequency setpoints had drifted outside of the acceptable

range. Further vendor testing did not conclusively identify the cause

of the setpoint drift. The inspector reviewed LERs 1 95 16 and 1-95 16- 1

01. Based on the replacement of the card and no evidence of recurrence

this item is closed. i

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III. Enaineerina

E7 Quality Assurance in Engineering Activities

E7.1 Independent Review Procram

a. Insoection Scope (37551. 40500)

The inspector reviewed the Nuclear Assessment Section Independent Review

Program. This program is a requirement of TS 6.5.4.

b. Observations and Findinos

TS 6.5.4.1 requires that NAS shall function to provide independent

review of significant plant changes, tests, and procedures: verify that

REPORTABLE EVENTS are investigated in a timely manner and corrected in a

manner that reduces the probability of recurrence of such events: and

detect trends that may not be apparent to a day to day observer.

The inspector used the recent repeat violation for failure to take

corrective action in IR 96 15 and LER 1-96 012 as an example for

reportable events. The inspector discussed this issue with NAS and

found that NAS did not do technical trending. The only trending

performed was overall trending. The program was implemented by

procedure NUA NGGC-1520, Independent Safety Review (ISR) Progran. This

procedure requires a quarterly trend report be prepared.

The inspector reviewed the two cuarterly trend reports that were

available. In the reports datec September 11, 1995, and January 5,

1996, no discernable trends were identified. The licensee initiated CR

9700266 dated January 15, 1997, concerning one quarterly report for the

NAS manager's review which was not submitted, and the current report was

,

late at 103 days instead of the required 92 days.

. Following these two reports, the requirement was fulfilled by monthly

reports. The inspector noted that five reports dated June 3, 1996: July

10, 1996: August 13, 1996: September 11, 1996: and October 2, 1996

contained a statement that some items required to be reviewed could not

be. Each report contained a statement that, until failure modes were

identified in CRs, the corrective actions could not be evaluated for

effectiveness in preventing recurrence of the events. Until failure

modes are captured for trending, trends not apparent to the day to day

observer (reference TS 6.5.4.1) may go undetected.

Also, report dated October 2, 1996, referenced three CRs - 96 00535,

96 02677, and 96 02921 - which were written because some procedures that

required an ISR review were not forwarded to ISR for review. This was

characterized by the report as examples of failure to comply with TS 6.5.4.9.a that could result in enforcement action if identified by

someone else. This was seen as an ineffective corrective action for the

first CR 96 00535 and was identified by the ISR as an adverse trend.

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These~ issues were discussed with NAS management on January 17, 1997.

c. Conclusions - l

The inspector concluded that the ISR program function was ineffective.

Independent reviews have not detected trends that may not be apparent to

a day to day observer or verified that required review items are <

investigated and corrected in a manner that reduces the probability of l

recurrence of such t; vents. A prime example of this was the repetitive

LERs associated with the chlorine. detection failures. Difficulty in i

obtaining required review items was noted repeatedly by NAS in reports  !

-and CRs without correction or resolution of the problems.  !

E8 Miscellaneous Engineering Issues (92903)  !

E8.1 (Closed) VIO 325(324)/95-20 01013: Design Review Renders RHRSW Valves

Inoperable ,

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(Closed) EEI 325(324)/95-20 03: Design Review Renders RHRSW Valves  !

Inoperable

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(Closgl) LER 1-95-019: Improper Material Configuration Results in

Inoperable RHR Service Water Valves

The licensee responded to this violation on December 18, 1995, admitting  !

the violation. A supplemental response was provided on January 19, i

1996, to address the adequacy of corrective actions implemented for  !

engineering products and a problem with a modification for the DG i

governor

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First, the RHRSW valve problem was a Severity Level III violation for

inadequate design control concerning the material selection of valve

parts. The licensee had, in an attempt to eliminate erosion concerns

with valve retainers, replaced the nickel-aluminum bronze retainers with

inconel retainers. However, a potential galling problem with the

inconel retainers and inconel disc was not. recognized. This lead to

failures of the valves during a surveillance test when the valves were

. stroked in a dry environment only. The licensee addressed the failures

by either replacing the inconel retainer with a refurbished nickel-

aluminum bronze retainer or installing a hardened disc. The licensee

had an independent review of the failure mechanism performed to confirm

that the valves were functional and that the failure would occur in a

dry environment. Other actions taken by the licensee were an

engineering stop work order, two day engineering stand down, quality

affirmation program, and a review of other material evaluations

performed on other risk significant systems during 1992 through 1994.

In the sup)lemental response, the licensee committed to three items to

evaluate tie effectiveness of the corrective actions. These items were

an independent third party review for selected Unit 2 modifications,

corrective action program trend reviews, and independent interviews of

engineering personnel to determine understanding of expectations and

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_ . _ _ _ _ . _ _ _ . . _ . _ _ _______ _ _ _ _ _ . . _

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accountabilities. The results of these tnree actions would be the basis

I for rescinding the stop work order.

s

The inspector reviewed each of the three action items taken and

concluded that it was difficult to determine if the actions taken had

j significantly improved engineering performance.

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The engineering stop work order was 11fted on June 21, 1996. Further

oversight by the Nuclear Safety Review Committee (NSRC) was established

i

to have a standing agenda item to review engineering )erformance. -In a l

meeting of the Brunswick NSRC on April 17, 1996, the (SRC concluded j

i that, although the actions taken to date appear to be adequate, there  !

i was insufficient basis from the available performance indicators to .

conclude that a significant, long term improvement in the quality of- ,

,

engineering 3roducts had been achieved. NSRC provided other comments

concerning t1e difficulty of making judgements on engineering progress,

. but concluded the continuation of the stop work order would serve no i

! further purpose. Further monitoring of engineering progress would be by H

a standing agenda item at each NSRC meeting.

l

l The inspector concluded'that the licensee's actions addressed the valve

! failures. The effectiveness of improvement in engireering performance 1

j had not been established and needed further monitoring. The inspector

. reviewed the NSRC meeting minutes for April 17, 1996, and NSRC agenda

! for November 20, 1996. The effectiveness and performance of engineering

was discussed in each meeting. The NSRC continues to provide this

oversight. Based on the licensee actions these items are closed.

i E8.2 (Closed) Violation 50 325(324)/95 01 03: Inadequate Corrective Action

for Previously Identified Violation.

This violation was cited in response to the licensee's inadequate

.

corrective actions associated with Violation 50-325/94-31 01. 0ne of

a the corrective actions taken for this previous violation was to perform

!

a review of previous safety evaluations, particularly those associated

with the minor modification process. Contrary to the completion of this

action, the inspector identified that Field Revision 32 of Plant

i Modification 93 40 failed to address the impact on seismic

j qualifications of two Class 1 seismic structures. The reviews performed

in response to violation 94-31-01, failed to identify the missed seismic  !

evaluations associated with this work. j

c I

In response to this violation, the licensee implemented the following

corrective actions: re review of previously prepared minor modifications

,

for design adequacy; implementation of the Engineering Service Request  ;

5

process for new modifications, which provided guidance on inter- 1

E discipline reviews: training for Engineering on the 10 CFR 50.59 process-

and details required for acceptable safety review packages:

L establishment of a design review team to provide closer scrutiny of ,

1 design products prior to approval; changes to the Corrective Action _

Program to require root causes for all significant CRs

closeout of all

, remaining shell modifications: revision to the excavation work procedure  ;

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0 CMP-12. Excavation and Backfill, to include adequate controls to

protect safety related structures and components: and communication of

management expectations to Design Engineering personnel regarding

acceptable work practices and design reviews.

The ins)ector reviewed the completed corrective actions, and finds them

accepta)1e for the closure of this item.

E8.3 (Closed) URI 325(324)/96 04 07: USFAR Discrepancies

LClosed) URI 325(324)/96 10 03: USFAR Discrepancies Concerning Radwaste

Process

(00en) URI 325(324)/96 05 02: FSAR Discrepancies

These three URIs track UFSAR discrepancies. Two are closed and all

UFSAR discrepancies will be tracked under one URI. Pending completion

of the licensee's UFSAR review program scheduled for completion July 1,

1997, all licensee identified and NRC identified discrepancies will be

reviewed for resolution of the URI.

IV. Plant Support

R2 Status of Radiological Protection and Chemistry Controls (RP&C)

Facilities and Equipment

R2.1 Locked Doors

a. Insoection Scope (71750)

The inspector checked locked high radiation area doors.

'

b. Observations and Findinas

During routine tours of the reactor, turbine and radwaste buildings, the

inspector checked a sample of doors required to be locked. No unlocked

doors were found.

c. Conclusions

No doors required to be locked were found unlocked.

R2.2 Postina of Notices to Workers

a. Inspection Scope (71750)

The inspector verified that NRC Form 3 and a recent violation involving

radiological working conditions were posted in accordance with 10 CFR

19.11.

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b. Observations and Findinas

The inspector checked the primary and secondary plant access points for  ;

proper posting of NRC Form 3. Also, violation 50 325(324)/96 16 02 '

concerning failure to implement a radiological control procedure

consistent with federal regulations was on a bulletin board in clear

view.

C. Conclusions

The inspector concluded that required posting was correctly implemented.

R2.3 Increase in Number of Personnel Contamination Events (PCE)

a. Inspection Scope (71750)

The inspector reviewed a recent increase in the number of personnel '

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contaminations.

b. Observations and Findinas

On January 8, 1997, the inspector entered the radiological control area

in route to the control room. At the personnel monitor at the control

room access, contamination was detected on a shoe. The licensee health

physics technician responded and determined a small particle reading

1200 cpm was on the outside of the shoe. The licensee wrote CR 97-00276

to document this problem. ,

Later in the evening, the inspector learned his contamination event was

one of three that occurred t' hat night. One event involved a radioactive

particle found inside a person's shoe that had apparently been taken i

off site without being detected. These issues were discussed with l

licensee management. On January 19, 1997, the licensee issued CR 97-

00261 to document the trend in PCE's.

Followup discussion with the licensee indicated a root cause was being

prepared on the particle inside the shoe and a common cause for the

increase in particles- These issues would be discussed with the

.

inspector at the completion of the licensee's review. l

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c. Conclusions

The inspector concluded there has been an increase in the number of

radioactive particles being found in clean areas of the plant. The

licensee was aware of these issues and was taking action to address  !

them.

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R8 Miscellaneous RP&C Issues (92704)

R8.1 (Closed) LER 1 95 017: Unalanned Engineered Safety Feature Actuation

While Obtaining Main Stac( Effluent Gas Sample

This event resulted from flow oscillations that occurred during

sampling. The licensee attributed this problem to an inadequate '

sam) ling 3rocedure. Procedure E&RC-2002. Sampling of Radioactive

Air >orne Effluent Releases, was revised to minimize flow oscillations

while removing the sampler. The inspector reviewed the LER and

procedure changes. The old procedure had the grab sample removed and

then closed the sampler inlet and outlet valves of the sample line. The

new procedure required the inlet and outlet valves of the sample line be

, closed and then remove the sample. Also, the procedure was revised to

bypass the actuation logic prior to sampling. Additional corrective

action included a review of other arocedures for similar problems. No

other problems were identified. T1e inspector concluded these actions

were ap3roariate to prevent this type of inadvertent actuation. No

3 actual lig1 radiation condition existed and these events had minimal  ;

safety significance, this item is closed.

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, S1 Con 1uct of Security and Safeguards Activities

a.

'

P,soection Scoce (71750)

The inspector observed personnel access into the site protected area

'

during a power outage.

b. Observations and Findinci

On January 16, 1997, an electrical power outage caused a loss of power

to the plant access building. Power was not available to the plant

explosive detector, x-ray detector, or metal detectors. All personnel

entering the plant that morning were searched using a pat down by the

security force. The inspector noted that all personnel were thoroughly

searched. Carry-in items were opened and searched. Each person

'

received a thorough pat-down and items in pockets were questioned. All

hats were required to be removed as well as outer coats.

, c. Conclusions

.

'

The ins)ector concluded that the licensee's security force conducted

thorougl searches for people entering the plant protected areas although

normal equipment was unavailable due to a power outage. Although normal

,

plant entrance time was greater, security measures were not reduced.

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F5 Fire Protection Staff Training and Qualification

F5.1 Fire Drill

a. Inspection Scope (71750)

On December 23, 1996, the inspector observed a fire drill,

b. Observations and Findinas

The fire area was in the number six deluge valve pit. The drill

involved a fire in the ait with the rescue of a person in the pit. The

licensee used a dummy t1at weighed the same as an average size man, and

a device that produced fog for simulation of smoke.

The licensee's fire brigade responded to the scene with the licensee's '

on site fire truck. The pit was evacuated with a blower and exhaust

trunk. A tripod was erected above the pit entrance for removal of the

injured person. Fire brigade members entered the pit area to combat the

fire and rescue the injured person.

The inspector observed the drill controllers at the site directing the

fire drill. The drill was conducted using procedure 0FPP 052, Emergency '

Response Drills,

c. Conclusions ,

The inspector concluded the drill was performed in a controlled manner

and provided realistic training for the fire brigade. The drill

scenario was challenging.

V. Manaoement Meetinas )

XI . Exit Meetina Summary l

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The inspector presented the inspection results to members of licensee l

management at the conclusion of the inspection on January 24, 1997. The  ;

licensee acknowledged the findings presented. The licensee did not 1

identify any materials used during the inspection as proprietary l

information.

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

G. Barnes, Manager Training

A. Brittain, Manager Security

'

W. Campbell, Vice President Brunswick Steam Electric Plant

N. Gannon, Manager Maintenance

J. Gawron, Manager Nuclear Assessment

>

W. Levis, Director Site Operations

R. Lopriore, General Plant Manager

l J. Lyash, Brunswick Engineering Support Section

l C. Pardee, Manager Operations

l R. Schlichter, Manager Environmental and Radiation Control

M. Turkal, Supervisor Licensing and Regulatory Programs

!

Other licensee employees or contracters included office, operation,

maintenance, chemistry, radiation, and corporate personnel.

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E. Brown

M. Janus

C. Patterson

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INSPECTION PROCEDURES USED ,

i'

IP 37551: Onsite Engineering ,

IP 40500: Effectiveness of Licensee Controls in Identifying. Resolving, and '

Preventing Problems

IP 61726: Surveillance Observations

IP 62707: Maintenance Observations

IP 71707: Plant Operations '

IP 71750: Plant Support Activities

IP 92901: Followup Operations

IP 92902: Followup Maintenance

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IP 92903: Followup - Engineering

j IP 92904: Followup - Plant Support

ITENS OPENED, CLOSED, AND DISCUSSED

Opened

3

50 325(324)/96 18 01 NCV Failure to Establish Procedures for Nitrogen

Tank Filling (paragraph 02.3)

'

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50 324/96 18-02 VIO Testing Using Uncalibrated Gauges (paragraph j

M1.3)

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50 325(324)/96 18-03 VIO Required Nonsafety SSCs Excluded From

,

Maintenance Rule Scope (paragraph M1.5) l

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Closed

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i 50 325/1 95 08 LER Spurious Actuation of the Primary Containment i

Isolation System (PCIS) Group 6 Valves i

j (paragraph 08.1)

-

50-325/95 10-02 VIO Failure to Control Contracted Services Pins

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and Rollers Project (paragraph M8.1) ,

50 325/1 95 16 LER Engineered Safety Feature Actuation Due to

Malfunction of Reactor Protection System

Electrical Protection Assembly Logic Card

. (paragraph M8.2)

I 50 325(324)/95 20-03 EEI Design Review Renders RHRSW Valves Inoperable

1

(paragraph E8.1)

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50 325(324)/95 20 01013 VIO Design Review Renders RHRSW Valves Inoperable

1 (paragraph E8.1)

. 50 325(324)/1-95 19 LER Improper Material Configuration Results in

J Inoperable RHR Service Water Valves (paragraph

E8.1)

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50-325(324)/95 01-03 VIO Inadequate Corrective Action for Previously

Identified Violation (paragraph E8.2)

50 325(324)/96 04-07 URI USFAR Discrepancies (paragraph E8.3)

l 50 325(324)/96 10 03 URI USFAR Discrepancies Concerning Radwaste Process

(paragraph E8.3)

50 325(324)/1-95 17 LER Unplanned Engineered Safety Feature Actuation

While Obtaining Main Stack Effluent Gas Sample

(paragraph R8.1)

,

50-325(324)/96-18 01 NCV Failure to Establish Procedures for Nitrogen

Tank Filling (paragraph 02.3)

Discussed ,

!

50 325(324)/96 05 02 URI FSAR Discrepancies (paragraph E8.3)  !

50-325/1-96-17 LER Inadvertent ESF Actuation During Conduct of

Maintenance Surveillance Test (paragraph M1.1)

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