ML14181A885

Insp Rept 50-261/97-01 on 961229-970208.No Violations Noted. Major Areas Inspected:Operations,Maintenance,Engineering & Plant Support

ML14181A885
Person / Time
Site:	Robinson
Issue date:	03/06/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML14181A884	List: ML14181A883 ML14181A885
References
50-261-97-01, 50-261-97-1, NUDOCS 9703270304
Download: ML14181A885 (34)

See also: IR 05000261/1997001

Text

U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket No:

50-261

License No:

DPR-23

Report No:

50-261/97-01

Licensee:

Carolina Power & Light (CP&L)

Facility:

H. B. Robinson Unit 2

Location:

2112 Old Camden Rd.

Hartsville, SC 29550

Dates:

December 29, 1996 - February 8, 1997

Inspectors:.

B. Desai, Senior Resident Inspector

J. Zeiler, Resident Inspector

C. Payne, Region II Inspector (Sections 01.2,

05.1)

W. Rankin, Region II Inspector (Sections R1.1,

R1.2, R1.3, R1.4)

Management:

R. Crlenjak, Acting Deputy Director, Division of

Reactor Projects, Region II

J. Jaudon, Director, Division of Reactor Safety,

Region II

B. Mallett, Director, Division of Nuclear

Material, Region II

K. Barr, Branch Chief, Plant Support Branch

Approved by:

M. Shymlock, Chief, Projects Branch 4

Division of Reactor Projects

Enclosure 1

9703270304 970306

PDR

ADOCK 05000261

G

PDR

EXECUTIVE SUMMARY

H. B. Robinson Power Plant, Unit 2

NRC Inspection Report No. 50-261/97-01

This integrated inspection included aspects of licensee operations,

maintenance, engineering, and plant support. The report covered a six-week

period of inspection. In addition to inspections conducted by resident

inspectors, it includes the results of an effluents inspection conducted by a

regional inspector, and an operator requalification program inspection

conducted by a regional inspector.

Operations

The plant was operated in a safe manner. A power reduction and

subsequent increase was appropriately conducted. Power was reduced to

approximately 65 percent to accommodate testing of the Turbine.governor

and stop valves (Section 01.1).

The conduct of operations in the control room was professional and.well

managed. The operators were-alert'and attentive to their duties. Shift

turnover process and associated meeting were effective and efficient

tools for transferring control of.plant operations from one crew to the

next. Though in effect for over one year, the operator workaround

associated with the Inventory Critical Safety Function Status Tree did

not impose undue operational difficulty or complexity for the operators

(Section 01.2).

A walkdown and assessment of the readiness of the Residual Heat Removal

(RHR) System to perform its Emergency Core Cooling System function

determined that the system was well maintained, conformed with plant and.

Updated Final Safety Analysis Report piping drawings, and was aligned in

• accordance with applicable operating procedures. A weakness was

identified in the corrective actions for addressing chronic seat leakage

problems with the RHR heat exchanger control and bypass valves.

(Section 02.1).

Several factors including weak procedures and lack of attention to

detail and self-checking resulted in a Containment gaseous release

• without a source check. However, the effluent release was monitored by

operable instrumentation and the conditions did not significantly change

in the Containment. The safety significance was minor and this issue

was classified as a Non-Cited Violation (NCV) (Sections 03.1 and 08.1)

The License Operator Requalification program continued to meet the NRC

requirements of 10 CFR 55.59. Licensed operator and instructor

performance was satisfactory. The training and evaluation simulator

scenarios were comprehensive and challenged the knowledge, skills, and

abilities of the operators. The training staff was effective at finding

weaknesses in the operator's technicalskills; however, additional

emphasis on correlating training and evaluation with actual plant

operations and management expectations is needed. The Nuclear

Assessment Section assessment was an adequate sampling of the Training

department performance and that the weakness identified with exam

2

security was not an initial or requalification training compromise issue

.(Section 05.1).

The onsite review functions of the Plant Nuclear Safety Committee were

conducted in accordance with Technical Specifications, were well

coordinated, and meeting topics were thoroughly discussed and evaluated

(Section 07.1).

Maintenance

The licensee failed to adequately evaluate and take timely corrective

actions for a degraded Reactor Protection System (RPS) relay problem

prior to its'eventual failure. This issue was identified as a NCV.

Concern was noted with the lack of adequate engineering involvement and

work priority scheduling when repeated anomalous RPS relay operation

occurred during previous testing. A detailed failure investigation

effectively determined the cause of the relay failure. While several

minor work practice deficiencies associated with the relay maintenance

was identified, licensee corrective actions were comprehensive and

included actions to address these deficiencies (Section M1.2).

The planning, preparations, and actual replacement activities associated

with a.failed test relay in the Engineered Safety Features Actuation

System (ESFAS) logic circuitry was conducted in a controlled and safety

conscious manner. The Plant Nuclear Safety Committee was thorough in

its review of.the safety impact of performing the replacement on-line

and installing a jumper in the ESFAS logic circuitry to maintain Train B

ESFAS available during the replacement evolution. Good management

oversight of all phases of the evolution was observed (Section M1.3).

Continued managementattention, including permanent resolution,.is

warranted on flow instrument FI-110 which continues to experience

repetitive failures. However, capability of the boron injection path

through the line was not impacted (Section M2.1).

The failure to adequately implement Technical Specification Surveillance

requirements for testing the Nuclear Instrumentation Power Range

Channels was identified as a NCV (Section M8.1).

Engineering

A 10 CFR 50, Appendix J related issue pertaining to the personnel

airlock testing was identified by the licensee and was determined to be

an example of good questioning attitude. However, it surfaced a

weakness in the modification evaluation process. The personnel airlock

was immediately leak rate tested with satisfactory results. The failure

to test the air lock in accordance with 10 CFR 50, Appendix J was

considered a NCV (Section E2.1).

The identification of the testing inadequacies related to the Auxiliary

Feedwater (AFW) pumps was considered as an example of good questioning

3

attitude. The failure to test the AFW pumps in accordance with the

requirements of ASME Section XI was considered a NCV (Section E2.2).

The Robinson Engineering Site Services organization was realigned such

that the engineering manager now reports to the Director of Site

Operations (Section E6.1).

Plant Support

Primary and Secondary water chemistry parameters were being maintained

well below regulatory and administrative limits (Section R1.1).

An effective program continued to be maintained to monitor and control

liquid and gaseous effluent to small percentages of regulatory and

administrative limits, thereby minimizing the potential dose at the site

boundary (Section R1.2).

The program for monitoring external exposure and tracking dose within

the Radiation Controlled Area (RCA) was determined to be effective.

However, for outside the RCA, one Unresolved Item (URI) was identified

based on the failure to adequately demonstrate accurate and reasonable

dose monitoring and dose assignment practices and procedures for

radiation workers onsite (Section R1.3).

)

The radiological controls program was being effectively implemented with

.good occupational exposure controls demonstrated. The As Low As

Reasonably Achievable (ALARA) program was effectively reducing total

site dose which achieved in 1996 a record low level for the site in an

outage year. The licensee experienced a relatively high level of

personnel contamination events in 1996 which represents a continuing

challenge in the licensee's radiological control program (Section R1.4).

An URI relative to RCA quarterly survey data and the consequences

involved was identified (Section R1.5).

2

The inspector observed shift turnover in the control room and attended

associated shift turnover meetings. Operators were noted to arrive

30-45 minutes before their shift to familiarize themselves with current

plant conditions and shift activities that had occurred since they last

operated the plant. The inspector observed that these reviews were

thorough, comprehensive and included a complete control board walkdown.

The shift turnover meetings were chaired by the offgoing Shift

Supervisor and participants included all members of the oncoming shift.

These meetings were well run by the Shift Supervisor and were observed

to be informative, succinct and brief. Typically, the meetings lasted

no longer than 15 minutes.

The inspector reviewed the operator workaround that exists relative to

the Reactor Coolant System (RCS) Inventory CSFST. The condition

periodically manifests when power is below approximately 70 percent and

it involves the RCS Inventory CSFST turning into "YELLOW" path (priority

lower than 'RED" which requires immediate operator attention) and is

indicative of the RCS dynamic head below 100 percent. The condition

becomes an operator workaround because it requires manual inventory

tracking, by the operator, of the inventory CSFST. The inspector

determined that procedures were in place to check the validity of all

off-normal CSFSTs. The inspector did note.that dne recently certified

Shift Technical Advisor (STA) was not aware that this workaround was in

effect and was unfamiliar with the circumstances associated with its

cause. During interviews, the inspector determined that control room

operators (including the STA noted above) would respond properly when

this situation arises. This problem is scheduled for corrective action

by June 1, 1997.

c. Conclusions

The inspector concluded that the conduct of operations in the control

room was professional and well managed. The operators were alert and

attentive to their duties. The inspector also concluded that the shift

turnover process and associated meeting were effective and efficient

tools for transferring control of plant operations from one crew to the

next. Though in effect for over one year, the inspector concluded that

the operator workaround associated with the Inventory CSFST did not

impose undue operational difficulty or complexity for the control room

operators.

02

Operational Status of Facilities and Equipment

02.1 Engineered Safety Feature System Walkdown of Residual Heat Removal

a. Inspection Scope (71707)

The inspector performed a walkdown of accessible portions of both trains

of the Residual Heat Removal (RHR) System. The actual plant

configuration was compared to plant drawings, the Updated Final Safety

Analysis Report (UFSAR) description, and system lineup procedures. RHR

System lineup procedures completed prior to startup from the previous

3.

refueling outage were reviewed to ensure that the system had been

aligned properly. The status of outstanding maintenance was reviewed to

verify RHR System readiness for performing its Emergency Core Cooling

System (ECCS) function.

b. Observations and Findings.

The inspector performed a walkdown of accessible portions of the RHR

System to compare the actual plant configuration with plant piping

drawing No. 5379-1484, Rev. 33 and UFSAR.Figure 6.3.2-2, Flow Diagram

Safety Injection System, Sheet 2. Each accessible valve in the RHR

System flowpath was verified from Control Board indication or by field

visual observation to be in its proper position as specified by

operations lineup procedures. The applicable procedures for placing the

RHR System in its ECCS standby mode included Operating Procedure

(OP)-201, Residual Heat Removal System, and General Procedure (GP)-02,

Cold Shutdown to Hot Subcritical at No Load Tavg. The inspector

reviewed the completed copies of these procedures to verify that they

had been properly performed prior to startup from the previous refueling

outage. No discrepancies were identified from these reviews.

The inspector noted no significant material condition problems during

walkdowns of accessible portions of the RHR System. A minor boric acid

buildup and small liquid buildup just below the "A" RHR Pump vent line

was identified and discussed with operations personnel.

The licensee

initiated a work request to investigate and repair this leak.

The inspector reviewed all open work items (Action and Work Requests)

for the RHR System. There were a total of 12 outstanding items, the

majority of these involved minor insulation and/or boric acid buildup

problems. None of these items were considered to be significant enough

to present any system performance problem.

The inspector witnessed portions of the Ticensee performance of

Inservice pump and valve testing for the "A" RHR Pump. Testing was

performed in accordance with Operations Surveillance-Test (OST)-251-1,

RHR Pump A and Components Test, Rev. 3. The inspector reviewed the pump

operating data collected during the test and verified that it met the

procedure acceptance criteria. All of the pump operating parameters

were well within their acceptance values indicating good pump

performance.

During review of OST-251-1, the inspector learned that the RHR heat

exchanger outlet and bypass valves, HCV-758 and FCV-605, were

experiencing a high amount of seat leakage. HCV-758 controls flow

through the heat exchangers and FCV-605 controls flow that bypasses the

heat exchangers. These valves are used to control the cooldown and

heatup rates during decay heat removal mode of RHR operation. The

leakage would not result in any degradation of the safety-related

accident mitigation function of the RHR system. Based on discussions

with the operators, this chronic -seat leakage problem had existed for

years and the operators had repeatedly identified the condition as

4

causing RHR temperature control complications. While this problem had

been tracked by operator workarounds in the past, it was currently not

on the work around list. The inspector discussed this problem with.the

RHR system engineer and licensee management. It was learned that the

licensee had made several attempts over the years to reduce the leakage

with little success and had decided to cope with the problem as it

existed. The inspector noted, however, that operating procedures and

operator training materials failed to account for this problem. This

leakage problem has contributed to at least one event where

inappropriate operator actions to compensate for the leakage caused the

Low Temperature Overpressure Protection system to actuate. The

inspector concluded that the licensee failure to consider these

procedural and training changes to be a weakness when it was decided to

cope with the leakage condition. The licensee initiated CR 97-00284 to

address the inspector's concern.

c.

Conclusions

The inspector determined that the ECCS function of the RHR System was

well maintained,-conformed with plant and UFSAR piping drawingsiand was

aligned in accordance with applicable.operating procedures. The

inspector identified a weakness in the licensee's corrective actions for

addressing chronic seat leakage problems with the RHR heat exchanger

control and bypass valves.

03

Operations Procedures and Documentation.

03.1 Gaseous Release Without Appropriate Source Check on Radiation Monitor

a. Inspection Scope (71750 and 71750)

The inspector reviewed, discussed, and assessed the circumstances

surrounding a Containment gaseous release that was made on January 10,

1997, without performing a source check on Containment Radionoble Gas

Monitor (R-12), as required by Technical Specification (TS) 4.19.2.1.

CR 97-00059 was generated by the licensee as a result of this incident.

Licensee Event Report (LER) 50-261/97-01-00, TS Violation Due to Missed

Surveillance Requirements, was submitted as a result of this incident.

b. Observations and Findings

Outside air temperature variations and its effect on Containment

pressure/temperature and instrument air bleed, necessitates periodic

venting of Containment atmosphere. TS 3.6.2 requires that Containment

pressure be maintained less than 1.0 psig. Control room operators

monitor containment pressure and when the need arises, vent the

Containment using Operations Procedure (OP)-921, Containment Air

Handling, and Effluents Monitoring Procedure (EMP)-022, Gaseous Waste

Release Permits. The containment air is then vented through the plant

vent and is accomplished by opening the Containment Pressure -Relief

Switch as-directed in OP-921.

15 4.19.2.1, requires that a source check

be performed on R-12 prior to initiating the release to ensure accurate

5

monitoring of the ongoing release. The source check is performed using

EMP-022.

On January 10, 1997, the Containment was vented (release # 97-0010-G)

without the performance of a source check on R-12 as required by

TS 4.19.2.1. The venting lasted several minutes before the operator

performing the evolution realized that the required source check had not

been performed. The source check was subsequently completed

satisfactorily. The failure to perform a source check as required by

TS 4.19.2.1 prior to.a release is considered a violation.

A licensee investigation determined that several factors contributed to

the problem. These included:

procedural weakness in that OP-921 did

not specifically require verification that a source check has been

performed prior to initiating the release; .layout and sequence of steps

in EMP-022 such that the step associated with the source check was not

obvious to the operator performing the evolution; the unfamiliarity with

the evolution on part of the operator who had recently been licensed;

and the lack of an operations crew brief prior to initiation of the

release.

The licensee initiated several corrective actions to preclude recurrence

of this incident. These included, planned revision to EMP-022 and

OP-921 to better reflect the need for the source check. The inspector

confirmed that there was no significant change in Containment

radiological conditions during the release. Further, R-14 (Plant Vent

monitorlocated down stream of R-12), R-11 (Containment particulate

monitor), as well as R-12 were operable, including the capability to

automatically isolate the Containment release if activity above pre-set

limits was detected.

c. Conclusions

The inspector concluded that several factors including weak procedures,

and a lack of attention to detail resulted in a Containment gaseous

release without a source check. However, the effluent release was

monitored by operable instrumentation and the conditions did not

significantly change in the Containment. Consequently, the safety

significance was minor. Licensee corrective actions were prompt and

adequate. This licensee-identified and corrected violation is being

treated as a Non-Cited Violation (NCV) consistent with Section VII.B.1

of the NRC Enforcement Policy. This NCV will be documented as NCV.

50-261/97-01-01: Failure to Perform A Source Check Prior to Gaseous

Release.

6

05

Operator Training and Qualification

05.1 Licensed Operator Regualification Training

a. Inspection Scope (71001)

The inspector reviewed the licensee's requalification program for

licensed reactor operators and senior reactor operators. The inspector

also reviewed and discussed the Nuclear Assessment Section (NAS)

Training and Qualification Assessment report (R-TQ-96-01) dated

January 16, 1997.

b. Observations and Findings

LICENSED OPERATOR REQUALIFICATION (LOR).

The inspector observed the

licensed operator requalification annual operating and biennial written

examinations for shift and staff operators. The inspector noted that

the evaluation scenarios were well developed and exercised the operators

on a wide variety of normal, abnormal, and emergency conditions. The

inspector noted that both Operations, and Training department managers

were actively involved in evaluating operator performance during the

simulator scenarios. The inspector also observed .that the post-scenario

critiques by the training staff were generally accurate and identified

significant performance deficiencies, as appropriate. A good practice

was noted involving the use of specific examples being listed to

describe individual operator errors or weaknesses. This practice helps

the operator to better relate his actual performance to management's

standard or expectation.

Several areas for improvement were identified by the inspector and

communicated to Training management. The inspector noted a difference

in operator communications during simulator scenarios and the cues given

i-n job performance measures (JPMs). For example, an operator was

observed during the simulator examination giving the Inside Auxiliary

Operator (AO) an order to locally start the "B"

EDG by "placing the

control switch to local and punch the start button." In contrast,

JPM-IP-048 (rev. 4) is the same task but directs the operator to

"locally start 'B'

Emergency Diesel Generator (EDG) and energize

emergency electrical bus E-2 in accordance with procedure EPP-1,

Attachment 6."

Attachment 6 contained many more actions and alternative

actions for the operator to perform than just going to local control and

pushing the START button. The expected level of operator performance

was significantly different for each of these orders, yet they were both

intended to accomplish the same action. This inconsistency has the

potential for providing negative operator training. Similarly, the

inspector noted that role play of operator communications was not always

conducted during performance of the inplant JPMs. When role play was

done, management expectations and standards for communications were

reinforced with the operators. When role play was not done,

communications were poor and conduct of the JPM was awkward. The

inspector also identified that the initiating cue for JPM-IP-026

.

(Rev. 5), "Establish Charging Flow to the RCS per DSP-002" was

7

incomplete. The cue stated that Auxiliary Building actions of DSP-002

were complete up to step 19. In fact, the actions of DSP-002,

Attachment 3, were complete up to step 19. This oversight did not cause

any noticeable operator performance problem because the operator was

handed a copy of the attachment as a part of the JPM.

SIMULATOR FIDELITY. The inspector identified one simulator fidelity

problem and an administrative oversight during the inspection. During

Resident Inspector review of the RHR System (see Section 02.1), it was

noted that the RHR heat exchanger bypass and outlet valves were

experiencing a high amount of seat leakage. The licensee had made

several attempts to reduce this leakage with little success, and had

determined to cope with the problem as it existed. The inspector found

that the licensee's training materials and simulator modeling failed to

account for this problem. Operator training did not adequately prepare

the operators for handling the condition. The licensee submitted a CR

in response to this finding and initiated efforts to upgrade the

training materials and simulator modeling. This was one example of poor

interdepartmental communications and poor recognition of the impact of

an equipment problem on operator performance.

Training Administrative Procedure TAP-409, (rev. 1), "Conduct of

Simulator Training and Evaluation", paragraph 8.7.7 required a periodic

control room review to ensure that control room equipment that will be

out of service, or has special operating requirements, for longer than

90 days, was identified and reflected in the setup of the simulator.

The inspector identifi.ed that control room "blue dots" were not

evaluated .for applicability contrary to Training management expectation.

The licensee submitted a Condition Report in response to this finding

and initiated a review of control room blue dots for applicability and

scheduled training of the instructors regarding the scope of this

requirement.

NAS ASSESSMENT. The Nuclear Assessment Section issued a report (R-TQ-.

96-01) on January 16,'1997 documenting the findings of their review of

the Robinson Training and Qualification Program. Three weaknesses were

identified in the report. The inspector noted that the third weakness

concerned the potential of compromising exam security, or the perception

of it, due to Robinson's Training management practices. Of the three

examples discussed, one was an interpretation error of examination

security made by supervision that was corrected by management the same

day. A second example involved the use of a training instructor as a

simulator operator during requalification examinations, thus violating

the exam security agreement. The inspector determined that this issue

was not an exam security problem because the simulator operators have no

control over the content of the examination. Training management has

modified their 'training instructions to correct this confusion in the.

exam security agreement. The last example entailed the availability of

the exam banks to the operators. The inspector found that only the

open-reference question bank (Part B) was actually made available.

Existing NRC guidance from NUREG-1021, "Operator Licensing Examiner

Standards" allows exam banks to become uncontrolled (i.e., do not have

8

to impose extraordinary control or security measures) once the Part B

bank reaches 350 questions. The Robinson Part B bank was 800 questions.

NUREG-1021 does not-preclude release of licensee exam banks to their

operators. The report also noted that both Brunswick and Harris nuclear

plants have discontinued releasing their banks. This inconsistency

between corporate licensees should be resolved. The NRC does not

encourage release of examination banks to the operators because it could

lead them to "study to the bank" rather than learning and understanding

the lesson material.

c. Conclusions

The inspector concluded that the licensee's LOR program continues to

meet the NRC requirements of 10 CFR 55.59. Licensed operator and

instructor performance was satisfactory. The training and evaluation

simulator scenarios were comprehensive and challenged the knowledge,

skills and abilities of the operators. The training staff was effective

at finding weaknesses in the operator's technical skills; however,

additional emphasis on correlating training.and evaluation with actual

plant operations and management expectations is needed.* The inspector

concluded that the NAS assessment was an adequate sampling of the

Training department performance and that the weakness identified with

exam security was not an initial or LOR training compromise issue.

07

Quality Assurance In

Operations

07.1 Plant Nuclear Safety Committee Meeting

.a. Inspection Scope (40500)

The inspector evaluated certain activities of the Plant Nuclear Safety

Committee (PNSC) to determine whether the onsite review functions were

conducted in accordance with TS and other regulatory requirements.

b. Observations and Findings

The inspector periodically attended PNSC meetings during the report

period. The presentations were thorough and the presenters readily

responded to .all questions. The committee members asked probing

questions and were well prepared. The committee members displayed

understanding of the issues and potential risks. The inspector

considered that the chairman appropriately limited discussion to the

issues and their safety ramifications.

c. Conclusions

The inspector concluded that the onsite review functions of the PNSC

were conducted in accordance with TSs. The PNSC.meeting attended by the

inspector was well coordinated and meeting topics were thoroughly

discussed and evaluated.

9

08

Miscellaneous Operational Issues (92901)

08.1 (Closed) LER 50-261/97-01-00, TS Violation Due to Missed Surveillance

Requirements: This LER was issued on February-9, 1997 because a source

check was not performed on RMS-12 prior to a containment pressure relief

on January 10, 1997. The details associated with the event are

discussed in Section 03.1 of this report. The LER is closed.

II.-Maintenance

M1

Conduct of Maintenance

M1.1 General Comments

a. Inspection Scope (61726 and 62707)

The inspector observed all or portions of the following maintenance

.related WRs/JOs and surveillances and reviewed the associated

documentation:

OST-401-2

Emergency Diesel Generator B Slow Speed Start,

Rev. 2

OST-251-1

RHR Pump A and Component Test, Rev. 3

WR/JO 97-AAGX1

Replace RPS Relay TR-2

WR/JO 96-AGJCI

Troubleshoot and RepairESFAS Relay TC-412C1

• X(B)

OST-201-A & B

MDAFW System Component

OST-202

SDAFW System Component Test

EST-10

Containment Personnel Airlock Leakage Test

E

MST 20 & 21

Reactor Protection Logic Train A & B At Power

• (Monthly)

b. Observations and Findings

The inspector observed that these activities were generally performed by

personnel who were experienced and knowledgeable of their assigned

tasks. Work and surveillance procedures were present at the work

location and being adhered to.

Procedures provided sufficient detail

and guidance for the intended activities. Activities were properly

authorized and coordinated with operations prior to start. Test

equipment in use was calibrated, procedure prerequisites were met,

system restoration was completed, and surveillance acceptance criteria

were met.

c. Conclusions

The inspector concluded that maintenance and surveillance activities

were performed satisfactorily. More specific details and observations

made of these activities were documented in other sections of the

report.

10

M1.2 Reactor Protection System Relay Coil Binding Failure

a. Inspection Scope (62707)

The inspector reviewed the events, causal factors and corrective actions

taken in response to the abnormal operation of the Reactor Protection

System (RPS) relay associated with Loop 1 Overtemperature Delta

Temperature (OTDT) beginning December 27, 1996, the relay's subsequent

failure on January 15, 1997, and eventual replacement on January 16.

b. Observations and Findings

On January 15, Instrumentation and Control (I&C) personnel were

performing MST-021, Reactor Protection Logic Train "B"

At Power

(Monthly)*.

This test verifies the proper operation of Train B.RPS logic

in accordance with the surveillance requirements of TS Table 4.1-1.

During testing, the Loop 1 OTDT reactor trip bistable failed to actuate

when the test signal was initiated. While repeating this portion of

testing two additional times-without success, I&C personnel observed

that the associated Train B RPS relay (TC-412C1-X(B)) for Loop 1 OTDT

failed to "drop out" as expected.. This was determined via .visual

observation that the relay's mechanical plunger remained in the

retracted position.

The on-call manager and I&C Supervisor were contacted and a decision was

made to replace the relay. Following this decision, I&C personnel

noticed that a paper label surrounding the relay plunger was peeled up

and was in contact with the plunger. I&C personnel believed that this

paper could have interfered with the operation of the plunger. With

permission of the Shift Supervisor, the paper was removed. When the.

plunger was touched while removing the paper, the relay dropped out.

The relay was tested repeatedly with successful results. Following

discussions with the on-call manager and I&C Supervisor, it was decided

not to replace the relay. Train B RPS was restored to normal after

completing testing in accordance with MST-021 successfully.

.The next morning, licensee management decided that further analysis of

the relay was necessary and directed the relay to be replaced. When the

first relay electrical power lead was lifted during the replacement

activity, the relay failed to drop out as expected. The relay changed

state as the second lead was lifted.

The relay was sent offsite for a detailed materials analysis to

determine the cause of the failure. The results of this analysis

determined that the failure was caused by internal binding of the

relay's contact assembly due to an.attachment pin contacting the inside

surface of the relay casing, and not the paper label.

This pin is used

to attach the contact assembly to the moving core and was most likely

positioned incorrectly during initial manufacture and had gradually

worn.

On January 21, the inspector reviewed the maintenance activities

conducted the night of January 15 and discussed these activities with

the individuals involved. The inspector identified the following

maintenance work practices deficiencies/concerns associated with these

activities as follows:

Engineering was not contacted and involved in the relay failure

discussions and subsequent.maintenance troubleshooting,

A work request was not initiated and planned for use at the work

site for the activities performed by maintenance personnel.

While

I&C personnel later documented the removal of the paper around the

relay plunger under an existing work request (96-AGJC1), this work

request had not been at the job site during the conduct of the

activity,

Work Request 96-AGJC1 was initiated on December 27, 1996, for a

previously identified problem with the relay, but had not been

coordinated with the scheduling of relay testing,

Contact cleaner used to spray safety-related electrical equipment

was not controlled under the licensee's chemical.control program

and apparently had not been evaluated for use in safety-related

applications,

The Control Room operator's logs stated that the test switch

associated with Loop 1 OTDT was sprayed with contact cleaner when

in fact the RPS relay had been sprayed,

After discussing these problems with the Plant Manager, licensee

management directed that the "non-significant" Condition Report

(97-00092), which was initiated by operations when the relay failed, be

upgraded to "Significant." A team was formed to investigate the events

and decisions leading to the relay replacement. The inspector reviewed

CR 97-00092 and determined that the licensee had thoroughly reviewed

this incident and had initiated or planned comprehensive corrective

actions which included the issues identified by the inspector.

Licensee investigation of the relay failure revealed that problems had

been experienced with the relay operation prior to its failure on

January 15. Details of these occurrences are discussed as follows:

On December 27, 1996, while operations was performing testing

associated with procedure OST-005 to verify proper reactor.trip

bistable operation, there was a delay of approximately one minute

between'when Loop 1 OTDT trip bistable switch was taken from trip

to normal and when the bistable light extinguished. The bistable

was placed in the trip condition and the evolution was repeated

with similar delay in bistable light response. Since no delay in

bistable light illumination was noted each time the bistable was

tripped, the operators-considered Loop 1 OTDT still operable.

Work Request 96-AGJC1 was initiated to investigate/repair the

12

problem and the on-call Manager was notified, however, engineering

personnel were not alerted to the incident. Work Request 96-AGJC1

was placed on the Emergent Work List on December 30, 1996, but was

subsequently removed the following day due to the assumption that

the problem was only with the relay picking up on re-energization.

On December 31, similar delay in Loop 1 OTDT bistable light

response was observed when maintenance was conducting routine

testing in accordance with Maintenance Surveillance Test (MST)-003

to verify proper Tavg and Delta-Temperature RPS channel response.

The evolution was repeated with similar but less delayed bistable

light response.

On January 11, 1997, during testing associated with OST-005,

normal bistable light response was reported for Loop 1 OTDT.

On the morning of January 15, the delayed response was observed

while maintenance was performing MST-003.

The inspector concluded from the above occurrences that the licensee had

not been sensitive to indications of relay degradation prior to the

failure on January 15. Operations did not recognize the potential for

relay failure and assumed that the observed delays in the relay picking

up was not a condition that could have resulted in relay failing to

perform its safety function. The inspector considered it a weakness on

the part of operations that this decision regarding relay operability

was made without the benefit of -engineering support.

c. Conclusions

The failure to adequately evaluate and take timely corrective actions

for a degraded RPS relay is considered as a violation. This licensee

identified violation is being treated as a Non-Cited Violation,

consistent with Section VII.B.1 of the Enforcement Policy. This item

was identified as NCV 50-261/97-01-02: Inadequate Corrective Actions

for RPS Relay Degradation. The inspector was concerned with the lack of

adequate engineering involvement and work priority scheduling when

repeated anomalous relay operation was observed during testing. The

licensee performed a detailed failure investigation and effectively

determined the cause of the relay failure. The inspector identified

several minor work practice deficiencies associated with the relay

maintenance on January 15.. Licensee corrective actions were

comprehensive and included actions to address the inspector identified

deficiencies.

M1.3. Replacement of Failed Reactor Safeguards Test Relay TR-2

a. Inspection Scope (61726 and 62707)

The inspector reviewed the licensee's activities associated with the

failure and subsequent replacement of Train B Engineered Safety Features

13

Actuation System (ESFAS) test relay TR-2 associated with the Main .Steam

Isolation logic circuitry.

b. Observations and Findings

On January 16, maintenance personnel were performing routine

surveillance testing of the Train B ESFAS logic circuitry. During this

testing, test relay TR-2, associated with the Main Steam Line Isolation

logic, failed. While failure of this test relay did not result in Train

B ESFAS being inoperable, it prevented the completion of TS required

monthly testing of the Train B Main Steam Isolation logic circuitry.

The licensee determined that the relay needed to be replaced, however,

based on the ESFAS wiring configuration, power could not be removed from

the test 'relay without deenergizing most of the other Train B ESFAS

logic circuitry. In addition, the licensee's TSs did not provide an

allowable outage time for a train of ESFAS to be inoperable. The

licensee recognized that in order to replace the relay, the action

requirement of TS 3.0 would have to be entered since Train B ESFAS would

be considered inoperable.

As a conservative measure, the licensee determined that a jumper could

be placed around the test relay during the replacement evolution to

preclude the actual loss of electrical power to the rest of Train B

ESFAS circuitry. This jumper would allow all but the Main Steam

Isolation function of Train B ESFAS to be capable of operating.

Engineering developed Special Procedure (SP)-1389, Installation of

Jumper for Replacement of Relay TR2, to control the replacement

activity. The inspector reviewed SP-1389 and its associated safety

evaluation. The procedure contained detailed step-by-step instructions

• and precautions for controlling the evolution. The safety evaluation

thoroughly considered the safety impact of installing the jumper,

potential for the jumper to fall off, size of the jumper wiring, etc.

The licensee determined that there would be no impact on the ability of

the opposite train of ESFAS performing its safety function during the

evolution. Based on discussions with engineering personnel

knowledgeable of the ESFAS circuitry and an independent .review of the

ESFAS logic circuitry, the inspector concluded that the licensee had

adequately evaluated the impact of installing the jumper.

A special PNSC meeting was convened at 7 p.m. on January 21 to discuss

the relay replacement activity and draft copy of SP-1389. The inspector

attended the meeting and noted that management.thoroughly discussed the

safety impact of performing the activity on-line. Several good

enhancements were identified to SP-1389. As an added conservative

measure, management directed the relay replacement activity to be

treated as an infrequently performed evolution requiring a Management

Directed Monitor (MDM) to oversee the evolution. The Manager of

Operations was selected as the MDM.

On January 22, the inspector witnessed activities associated with the

relay replacement. The inspector determined that activities were well

14

controlled and had a high level of management attention and oversight.

Personnel responsibilities, precautions, and contingency plans for

unexpected responses, were thoroughly discussed at a pre-job briefing

that was held in the Control Room by personnel involved in the

evolution. The MDM monitored and provided oversight of activities from

the Control Room. The inspector determined that the actual replacement

activity was performed by knowledgeable maintenance personnel who

properly followed SP-1389 and other applicable maintenance requirements.

No problems were encountering during the replacement evolution.

Continuous communication was maintained throughout the activity between

personnel in the Control Room and ESFAS relay room. Good sensitivity

was evidenced by both maintenance and operations personnel involved with

the replacement activities to limit the amount of time in TS 3.0 while

still expediting the completion of work. The total time TS 3.0 was

entered was only one hour and 35 minutes. As required by NRC reporting

requirements, the licensee planned to submit an Licensee Event Report

for the TS 3.0 entry. The day after the relay was replaced, the

licensee identified a minor documentation problem associated with

maintenance personnel failing to update the PMTR database following work

completion.

The inspector examined the failed relay after it was removed. The

relay's control wiring at the junction of the coil housing was badly

burned. The system engineer believed that the relay coil had shorted as

a result of failed control wiring insulation. The failed relay was sent

offsite for further investigation into the cause of the coil failure.

The inspector planned to review the results of the licensee's

investigation as part of followup to the LER.

.c. Conclusions

The inspector concluded that the licensee's planning, preparations, and

actual replacement activities associated with the failed test relay in

the ESFAS logic circuitry were conducted -in

a controlled and safety

conscious manner. The PNSC was thorough in its review of the safety

-impact of performing the replacement on-line and installing a jumper in

the ESFAS logic circuitry to maintain Train "B" ESFAS available during

the replacement evolution. Good management oversight of all phases of

the evolution was observed.

M2

Maintenance and Material Condition of Facilities and Equipment

M2.1 Control Room Emergency Boration Flow Indicator Maintenance Issues

a. Inspection Scope (62707)

During the course of routine plant tours and meeting attendance, the

inspector noted that there appeared to be repetitive problems with the*

control room emergency boratioh path Flow Indicator (FI)-110.

15

b. Observations and Findings

The inspector noted that FI-110 had failed several times in the last

month. A review of maintenance history confirmed that FI-110 had a

history of failures, primarily attributable to boric acid buildup and

its affect on the flow transmitter. Robinson utilizes highly

concentrated boric acid (approximately 20,000 ppm boron) in the Chemical

and Volume Control System (CVCS). FI-110 indicates emergency boration

flow in the control room and is -utilized in the Emergency Operating,

Procedures following a reactor trip, as well as in response to an

Anticipated Transient Without a Scram (ATWS). The inspector expressed

concern to the Plant Manager with regard to the repetitive failures.

Additionally, the inspector discussed the issue with the Maintenance

Rule engineer to assess implications.

The inspector was informed that the problems with the flow indications

did not result in the emergency boration flow path being inoperable and

the alternate paths as well as alternate means of determining flow .

through the emergency boration flowpath were available. Further, the

EOPs, were structured such that not having FI-110 operable in the

control room did not significantly impair recovery actions.

Consequently, licensee process associated with the maintenance rule did

not affect FI-110 related problems. However, the licensee is carrying

this item as a subset of other issues pertaining to the Boric Acid

System in the "TOP TEN" equipment issues list for appropriate

prioritization and attention.

c.

Conclusions

The inspector concluded that continued management attention, including

permanent resolution, is warranted on Fl-110 which continues to

experience repetitive failures.

M8

Miscellaneous Maintenance Issues (92902)

M8.1

(Closed) LER 50-261/96-01-00, Condition Prohibited by Technical

Specifications Due to Inadequate Testing of Nuclear Instrumentation

Power Range channels: This issue involved the licensee's identification

of a discrepancy.in the surveillance tests for the Nuclear

Instrumentation (NIS) Power Range (PR) channels. TS Table 4.1-1,

Item 1, required a bi-weekly continuity check of the NIS PR channel

signals to the RPS Delta-Temperature input circuitry. Due to a

misinterpretation of the surveillance requirement, this testing was not

being completed properly. While licensee procedures tested the

operation of the bistables for Delta-Temperature, the actual signal

being sent from the NIS channels to the Delta-Temperature circuitry was

not being checked. On February 13, 1996, the associated circuitry was

tested and found to be operable.

The licensee revised all surveillance test procedures intended to

perform this overlap circuitry check. The inspector reviewed these

procedures and verified that the changes had been completed. This

16

included a review of Operations Surveillance Test (OST) procedures

OST-001, -002, -003, -004, and -005. No discrepancies were identified.

The licensee determined that this missed surveillance was an isolated

occurrence. The inspector noted that this surveillance discrepancy was

identified by the Team tasked with converting the current TSs to the

improvedStandard Technical Specifications. As part of the Team's

activities, the adequacy of all other TS Table 4.1 instrumentation

surveillances were reviewed. This review was completed in 1996. While

several other minor problems were identified during this review, there

were no other missed TS surveillances or items of non-compliance

identified. This LER was closed.

The inspector determined that licensee's failure to perform bi-weekly

checks of the signal from the NIS PR channels to the Delta-Temperature

circuitry was a TS violation. This licensee-identified and corrected

violation is being treated as a NCV, consistent with Section VII.B.1 of

the NRC Enforcement Policy. This issue was identified as NCV 50-261/97

01-03:

Failure to Adequately Implement TS Surveillance Requirement.

III. Engineering

E2

Engineering Support of Facilities and Equipment

E2.1

Containment Airlock Testing

a.

Inspection Scope (37551)

On January 10, 1997, the licensee identified that the Containment

Airlock (personnel hatch) had not been tested in accordance with the

requirements of 10 CFR 50, Appendix J. Upon discovery, a condition

report (97-00063) was initiated and TS 4.0 was invoked, which required

the testing to be successfully completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The airlock

was satisfactorily tested on January 10, 1997 and compliance with 10 CFR

50 Appendix J was achieved. LER 50-261/97-02-00 was submitted on

February 10, 1997 as a result of this condition.

b. Observations and Findings

Technical Specification 6.12 requires that a containment leakrate

testing program be established to implement the requirements of 10 CFR

50 Appendix J. 10 CFR 50 Appendix J, Containment leakage testing.

requirements include Type B,-local leakrate testing of the Containment

Airlock. These include, the leakrate test prior to initial fuel

loading, at 6-month intervals, and following opening the airlock when

containment integrity is required'. Additionally, per section

III.D.2.(b).(ii) of 10 CFR Appendix J, if the airlock is opened during

periods when containment integrity is not required by plant TS (for

example during certain periods of a refueling outage), then the airlock

is required-to be tested at the end of such periods at pressure not less

than Pa (40 psig) utilizing a full volume test.

17

Prior to the 1996 refueling outage (RFO 17), Robinson utilized the

continuous Penetration Pressurization System (PPS) as an alternative to

full-volume testing required by 10 CFR 50, Appendix J, Section

III.D.2.(b)(ii).

This methodology was accepted by the NRC, as stated in

correspondence from the NRC Office of Nuclear Reactor Regulation to the

licensee in a letter dated August 14, 1989.

A plant modification was implemented during the 1996 refueling outage

that modified the PPS system from a continuous to an intermittent

monitoring system. This modification was performed, primarily due to

maintenance and upkeep related problems with the PPS system. The 10 CFR

50.59 evaluation associated with the modification did not appropriately

interpret and incorporate the basis for the PPS system and its use as an

alternate to the testing requirements of 10 CFR 50, Appendix J, Section

III.D.2.(b)(ii). When the PPS system was modified, the reinstatement of

the requirement to perform a full-volume test as required.by Section

III.D.2.(b).(ii) was not recognized. Consequently, following RFO 17,

the containment airlock was not subjected to a full volume test.

Upon discovery of non-compliance on January 10, 1997, TS 4.0 was entered

which required that the volume test be successfully completed within 24

hours. The licensee successfully tested the airlock utilizing procedure

EST-10, Containment Personnel Airlock Leakage Test (Semiannual).

Following the test, the total Type B and C leakage was 55,276.5 sccm.

The acceptance criteria is less than .6La of 85,629 sccm.

Though the results were within the acceptance criteria, the leakage

through the airlock was noted to be above what the licensee had been

noting during the similar test that is performed at a six-month

frequency. Consequently, the licensee performed troubleshooting to

identify the source of the increased leakage. No direct source.was

identified. Additionally, during the performance of EST-10, the

licensee noted that the administrative acceptance criteria was.set

conservatively based on historically low leakage through the airlock.

This administrative limit was not met; however, as mentioned above, the

total leakage remained below the Appendix J limit of'.6 La.

c.

Conclusions

The inspector concluded that the identification of this issue was an

example of good questioning attitude. However, it surfaced a weakness

in that the modification evaluation was not thorough. The licensee

aggressively performed troubleshooting to identify the potential source

of increased leakage through the airlock. The 10 CFR 50 Appendix J

.

leakage limits were met. The failure to test the airlock in accordance

with Appendix J Section III.D.2.(b)(ii) was identified as a violation.

This licensee-identified and corrected violation is being treated as a

NCV, consistent with Section VII.B.1 of the NRC Enforcement Policy.

This issue was documented as NCV 50-261/97-01-04:

Failure to Conduct

Containment Airlock Testing.

18

E2.2

Auxiliary Feedwater Pump Testing

a. Inspection Scope (61726, 37551, and 40500)

On January 15, 1997, the licensee identified that the two Motor Driven

Auxiliary Feedwater (MDAFW) pumps and the one Steam Driven Auxiliary

Feedwater Pump (SDAFW) had not been appropriately tested in accordance

with American Society of Mechanical Engineers (ASME)Section XI

requirements. An operability evaluation was performed which concluded

that the pumps were operable. Condition Report 97-00081 was initiated

by the licensee to resolve this issue.

b. Observations and Findings

The AFW pumps are tested on a monthly and refueling basis, as required

by TS 4.8, to demonstrate operability. Further, TS 4.0.1 requires that

the test be performed in accordance with ASME Section XI, Article

IWP-3000, Inservice Test Procedures. With regard to the test method,

IWP-3000 requires that the system resistance be varied until either the

measured differential flow or the differential pressure equals the

corresponding reference value. The reference value is established

during pre-operational testing or during the initial inservice run

during power.operation. All subsequent test results are then compared

to the reference value, and any change from the reference value is

requiredto be evaluated for possible indication-of pump degradation.

Additionally, TS 4.8 Bases states that the AFW pumps will be tested by

recirculation.

Testing.procedures OST-201-.A & OST-201-B, MDAFW System Component Test

Train "A" & Train "B", and OST-202, SDAFW System Component Test

accomplish the monthly testing.requirements at Robinson. The A-MDAFW

pump was run with a forward flow of approximately 100 gpm established

through Flow Transmitter (FT)-1424. FT-1424 measures forward flow to

the three Steam Generators (S/Gs). A minimum flow recirculation line

(to the Condensate Storage Tank) upstream of FT-1424 was maintained open

during the performance of OST-201. This minimum flow recirdulation line

did.not have any flow indication. Similarly, the B-MDAFW was tested

utilizing FT-1425 and the flow through the minimum flow recirculation

was not being.measured. After establishing forward flow, the pump

suction and discharge pressures as well as other pump data were

obtained. The SDAFW pump was tested with all flow directed through the

recirculation line, i.e.,.no forward flow to the S/G. The SDAFW pump

utilizes the same recirculation line (i.e. without flow indication) as

the MDAFW pumps. The pump speed, differential pressure, and vibration

data were obtained. AFW pump tests during the refueling outage are

performed through-procedures OST-206, and OST-207 for the MDAFW and

SDAFW pumps. The refueling pump tests comprises of a full flow (to the

S/G), and similar to the monthly tests, the recirculation flow was not

being measured.

The problem with the MDAFW pump testing-methodology was that though a

reference value of 100 gpm was established each time during pump

a *19

testing, the recirculation flow during the pump run was not measured.

Consequently, if that unmeasured recirculation flow changed, potential

pump degradation would not have been detected as required by ASME

Section XI.

With regard to the SDAFW flow, pump speed was utilized'as

the reference value, which was not commensurate with the recommendations

of ASME section XI, IWP 3000. The failure to test the A and B MDAFW

pumps and the SDAFW pump in accordance with ASME Section XI is

considered a violation.

The licensee formally evaluated the testing methodology to determine

operability of the pump. Based on historic test data, the licensee had

confidence that the pumps had not exhibited indications of degradation.

Notwithstanding, an Engineering Service Request (ESR 9700028) was

originated to determine operability.

The monthly test data reviewed

from March 1992 (from 56 tests) for the A MDAFW pump indicated that the

pump differential pressure had been measured between 1391.5 gpm and

1421.7 psi.

No discernable trends were noted, in the oil analysis, or

vibration and temperature data. Similarly, no discernable trends were

noted on the B MDAFW and the SDAFW pumps. Further, the licensee

reviewed the full flow test results performed during refueling with

similar conclusions. Based on this review, the licensee concluded that

the two MDAFW and the SDAFW pumps were operable.' However, the current

flow rates through the recirculation line remained indeterminate.

To obtain current recirculation flow rates, the licensee installed an

externally mounted "Controlotron" flow measuring devise and performed

OST 201-A&B and OST 202. Current licensee plans to comply with the ASME

section XI code are to revise the monthly test procedures, OST 201 and

OST 202, to measure and trend recirculation flow data through the

Controlotron flow device. -For the MDAFW pumps, pump data will be

collected prior to establishing forward flow.

Further, the licensee plans to establish pump flow reference points

during the next refueling outage or an event requiring shutdown.

Following the establishment of.the reference point, the licensee will

utilize the guideline established by NUREG-1482, Guidelines for

Inservice Testing at Nuclear Power Plants, Position 9. This will allow

the licensee to measure the recirculation.flow only during the refueling

tests. The licensee will then continue to perform the monthly tests as

they had prior to the identification of this issue.

The licensee also discussed the circumstances surrounding this issue

with the NRC staff during the IST workshop held in Region II on

February 5, 1997. The NRC staff may incorporate this issue as an

example in the guidance that is planned to be issued relative to IST.

c. Conclusions

The inspector concluded that licensee identification of this issue is

considered as an example of good questioning attitude. The failure to

test the AFW pumps in accordance with the requirements of ASME

Section XI is identified as a violation. This licensee-identified and

20.

corrected violation is being treated as a NCV, consistent with

Section VII.B.1 of the NRC Enforcement Policy. This issue was

documented as NCV 50-261/97-01-05:

Inappropriate Testing of the AFW

pumps.

E6

Engineering Organization and Administration.

E6.1 Engineering Management Realignment

Effective, February 3, 1997, the Robinson Engineering Support Section

(RESS) organization was realigned such that the RESS Manager now

directly reports to the Site Operations Director.

E7

Quality Assurance in Engineering Activities

E7.1 Special UFSAR Review

.A recent discovery of a licensee operating their facility in a manner

contrary to the UFSAR description highlighted the need for a special

focused review that compares plant practices, procedures and/or

parameters to the UFSAR descriptions. While performing the inspection

discussed in this report, the inspector reviewed selected portions of

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

that for the select portions of the UFSAR reviewed, the UFSAR wording

was consistent with the observed plant practices, procedures and/or

parameters.

E8

Miscellaneous Engineering Issues (92903)

E8.1 (Closed) LER 50-261/97-02-00, Technical Specification Violation Due to

Inadequate Surveillance Test: This LER was issued by the licensee on

February 9, 1997 due to a discovery by plant engineering personnel on

January 10, 1997 regarding a 10 CFR Appendix J required surveillance not

being conducted. The details associated with the issued are discussed

in Section E2.1 of this report. This LER is closed.

IV. Plant Support

R1

Radiological Protection and Chemistry Controls

R1.1 Water Chemistry Controls

a. Inspection Scope (84750)

The inspector reviewed implementation of the licensee's water chemistry

control program for monitoring primary and secondary water quality. The

water chemistry program was evaluated against the specific requirements

of TS 3.1.6 which specifies concentrations of dissolved oxygen (DO) and

chloride in the Reactor Coolant System (RCS), TS 3.1.4 which specifies

that total specific activity of the reactor coolant be limited to less

than or equal to one microcurie/gram dose equivalent iodine (DEI), and

21

Table 4.1-2 of TS 4.1 which specifies required sampling frequencies for

these parameters. Licensee implementation of a Secondary Water

Chemistry Program in accordance with Section 3.G (1) of the Plant

Operating License was also evaluated.

b. Observations and Findings

The inspector reviewed Carolina Power and Light Chemistry Procedure

CP-001, "Chemistry Monitoring Program", Revision No. 42, dated

October 5, 1996, and determined that it included provisions for sampling

and analyzing reactor coolant at the prescribed frequency for the

parameters required to be monitored by TSs. Action levels and responses

for out of limit secondary chemistry parameters were also reviewed -as

described in licensee procedure CP-005, "Secondary Chemistry Corrective

Action". These procedures included provisions for monitoring primary

and secondary water quality based on established industry guidelines and

standards. Although the Electric Power Research Institute (EPRI)

guidelines for PWR primary and secondary water chemistry are not

requirements, the inspector used these guides as references for

evaluating the effectiveness of the licensee's program. The inspector

noted that the referenced licensee procedures .listed the sampling

frequency and typical values for each parameter to be monitored. Action

levels applicable to various operational modes were given where

appropriate. Guidance was also provided for actions to be taken if

analytical results exceeded prescribed limits. The inspector determined

that the above guidance and procedures were consistent with applicable

TS requirements and EPRI guidelines.

The inspector also reviewed chemistry statistical analysis reports,

primary and secondary chemistry data, and related data trend plots and

records of analytical results for selected parameters at power

operations during the period July 6, 1995 through December 1996. The

parameters selected included dissolved oxygen, chloride, fluoride,

sulfate, and dose equivalent lodine-131 in reactor coolant, and

dissolved oxygen, iron, sodium, hydrazine, and sulfate in secondary

systems. Those parameters were maintained well within TS limits,

licensee administrative limits, and within EPRI guidelines for the

specific chemistry parameters examined during power operations.

c. Conclusions

Based on the above evaluation, the inspector concluded that the

licensee's water chemistry control program for monitoring primary and

secondary water quality at specified surveillance frequencies had been

implemented in accordance with the licensee's TS requirements for PWR

water chemistry.

• . 2

22

R1.2 Semiannual Radioactive Effluent Release Report

a. Inspection Scope (84750)

TS 6.9 requires the licensee to submit periodic Semiannual Radioactive

Effluent Release Report covering the operation of the facility during

six months of prior operation. Data on solid radwaste shipments was

also provided in the report and evaluated. The inspector evaluated the

data to identify adverse effluent trends and increases in estimated

,doses to the public from effluents, if any, and explain these trends in

the context of operational experience.

b. Observations and Findings

The effluent data presented below were compiled from the licensee's

effluent release reports for the years 1994, 1995, and 1996. The

inspector evaluated the supporting raw data for the effluent release

report covering the years 1994, 1995, and 1996 with emphasis on

identifying any elevated release trends or data anomalies. As shown in

the effluent release summary below, the amount of actiVity released

during 1994, 1995, and 1996 in liquid effluent streams remained

relatively stable, at low levels, and well within release limits. The

amounts of activity released during 1996 as fission gases, iodides, and

particulates in gaseous effluents was also at low levels and within

release limits. Minor variances in gaseous effluent parameters within

operational limits were identified between 1995 and 1996 indicative of

normal steady state power operations. The small increase in gaseous

particulate curies between 1995 and 1996 is attributable to chipping and

painting in various rooms of the plant. No abnormal releases were

identified during the period.

Robinson Radioactive Effluent Release Summary

1994

1995

1996

Abnormal Releases

Liquid

0

0

0

Gaseous

0

0

0

Activity Released (curies)

a.

Liquid

1. Fission and Acti-

5.32E-2

8.76E-2

7.97E-2

vation Products

2. Tritium

2.16E+2

9.93E+2

9.89E+2

3. Gross Alpha

< LLD

< LLD

< LLD

b.

Gaseous

1. Fission and Acti-

5.70E+1

2.67E+0

1.27E+1

vation Gases

2. Iodides

8.18E-7

1.35E-5

3.59E-7

3.-Particulates

2.53E-6

7.74E-6

3.58E-5

4. Tritium

5.58E+0

1.47E+1

. 16E+0

23

The inspector evaluated 1995 and 1996 hypothetical maximum annual dose

estimates to a member of the public located .at the site boundary from

radioactive materials in gaseous and liquid effluents. The doses for

1996 from airborne and liquid effluents were calculated at 1.62E-1 mrem

and 6.82E-3 mrem to the airborne and liquid effluent critical organs,

respectively. The total body dose attributable to liquid effluents for

1996 is 4.90E-3 mrem. These doses were extracted from the licensee's

1995 annual Radiological Environmental Operating Report and from

preliminary dose calculations for 1996 completed in January 1997. The

inspector reviewed the data collection and analysis methodology used by

the licensee in compiling the effluent data with no concerns noted. The

annual average radiation dose to a hypothetical exposed individual from

liquid and gaseous effluents was-less than two tenths of a millirem

which represents a small percentage of the annual limit.

During 1995, the licensee made 87 radwaste disposal shipments, involving

50 cubic meters and 46.85 curies of solid radwaste. During 1996, the

.licensee made 59 waste disposal shipments, involving 26.76 cubic meters

containing 66.74 curies of radwaste. Volume reduction initiatives

included removing "clean" trash drums from the RadiationControl Area

(RCA).

Individuals were required to remove their own trash as they exit

the RCA using the small article monitor for release. Also, chemistry

made improvements in waste water processing that prolonged the life of

waste water resins which further reduced resin radwaste volume.

c. Conclusions

Based on the above evaluation, the inspector concluded that the licensee

had maintained an effective program to monitor and control liquid and

gaseous radioactive effluents-and thereby limited doses to members of

the public to a small. percentage of regulatory limits. Specifically, the

release of radioactive material to the environment from effluents for

1996 was a small fraction of the 10 CFR 20, Appendix B and 10 CFR 50,

Appendix I limits. The projected offsite dose commitments which

resulted from plant effluents were well within the limits specified in,

the TSs and the Offsite Dose Calculation Manual (ODCM). Radwaste volume

reduction from 1995 to 1996 was determined to be on a favorable reducing

trend.

R1.3 External Occupational Exposure Control and Personal Dosimetry

a. Inspection Scope (83750)

The inspector evaluated the adequacy 'of the licensee's program for

monitoring occupational exposures during normal power operations and the

adequacy of the licensee's site dosimetry program. The inspector

evaluated the licensee's monitoring of occupational dose to radiation

workers in buildings close to but outside the RCA, i.e., within the

licensee's protected and controlled areas, to ensure compliance with 10

CFR 20.1502 monitoring requirements.

24

b. Observations and Findings

The inspector reviewed area Thermo Leuminacent Dosimeter (TLD) results

for1996 with focus on exposures in buildings occupied by personnel

within the protected area boundary fence. A review of these TLD results

averaged for a 2080 hour0.0241 days <br />0.578 hours <br />0.00344 weeks <br />7.9144e-4 months <br /> work year indicated several work areas with

elevated doses above natural background but within the regulatory public

dose limit of 100 millirem per year. The inspector's evaluation of the

licensee's dosimetry, monitoring, and general radiation control

procedures indicated the licensee did not treat dose to occupational

workers in buildings outside the RCA as occupational dose and licensee

procedures were generally silent in this regard. However, as defined in

regulation, dose which is received by a worker in the course of

employment during which the.worker's assigned duties involve exposure to

radiation from licensed sources is occupational dose. The licensee was

aware that some workers outside of the RCA were receiving low level

occupational doses incidental to their occupational activities but the

licensee had concluded that these workers were receiving less than the

public dose limit and, therefore, there was no requirement for-the

monitoring of radiation workers in these areas.

The inspector reviewed available dose data for radiation workers outside

the RCA and determined that no workers were exceeding regulatory limits.

However, the inspector reviewed dose monitoring procedures as well as

dose records of other categories of individuals including members of the

public, casual visitors, and the exposure monitoring

practices/procedures for declared pregnant women. No concerns were

identified with respect to public or casual visitors. Under certain

circumstances a situation could be postulated where a declared pregnant

woman may exceed the 50 millirem monitoring limit depending on

background dose subtraction methodology, i.e., subtract from assigned

worker dose less than 100 percent of "background" dose as detected at

the primary access point to the RCA (note discussion of licensee

background dose subtraction practices below). However, no.actual

examples were identified that required monitoring based on a review of

declared pregnant women dose records during the inspection..

.The inspector evaluated the licensee's procedures and practices with

respect to the monitoring and tracking of occupational dose for

radiation workers. The licensee required, by procedure, all radiation

workers entering the RCA to be monitored, is a larger population of

radiation workers than required by regulation. The monitoring of all

workers inside the RCA for dose of record purposes exceeds regulatory

requirements in that.only a fraction of the workers who actually enter.

the RCA will exceed the 500 millirem threshold requiring monitoring.

The licensee was unable to demonstrate adequately during the period of

inspection that occupational dose received by workers outside the RCA

(restricted area) was being considered in the prospective analysis used

to determine if workers required monitoring in accordance with the

requirements of 10 CFR 20.1502. Radiation workers who are required to

be monitored for radiation work in restricted areas, i.e., workers who

are likely to receive greater than 500 millirem in a year based on a

25

prospective analysis of likely dose, are also required to be monitored

for occupational dose received in licensee controlled areas outside the

restricted area. The licensee was unable to produce records or

reference procedures which demonstrated full compliance with the

requirements of 10 CFR 20.1502 for monitoring occupational exposure in

this regard. Additionally, the licensee was asked to demonstrate that

the current dosimetry practice of subtracting 100 percent of

"background" dose from the site wide personnel TLDs stored in badge

racks at the primary access point to the RCA was consistent and within

,regulatory requirements. Since area TLD readings at the badge racks had

millirem readouts higher than area TLD readings at more distant

locations within the controlled area, the inspector concluded some dose

component of what the licensee characterized as "background" was more

accurately described as dose attributable to power operations. Although

the amount of dose in question was at low levels at RNP and of minimal

radiological safety significance, the inspector indicated to the

licensee that this practice was non conservative with respect to the

accurate reporting of dose both in terms of cumulative site dose and

individual dose assignments. The licensee was unable to provide

sufficient data to demonstrate.this was conservative safety practice

during the week of inspection.

The licensee indicated further evaluation and time to .prepare a response

was necessary, due in part to the need to coordinate a response with

corporate dosimetry personnel who were housed offsite in the Harris

Energy and Environmental Center at New Hill, N. C.. These inspection

concerns were unresolved at the end of the inspection and will require

further evaluation of licensee data which the licensee committed to

prepare as a corporate response which would address the specific

concerns identified. Furthermore, licensee nuclear generation group

procedures did not adequately address these specific issues

procedurally. These issues regarding demonstration of accurate and

reasonable dose tracking and dose assignment practices and the lack of

related procedures were identi'fied to the licensee as an Unresolved Item

(URI) 50-261/97-01-06: -Demonstrate Accurate Dose Monitoring and Dose

Assignment Practices and Procedures.

c. Conclusions

The licensee's program for monitoring external exposure and tracking

dose within the RCA was determined to be effective. Outside the RCA,

however, licensee dosimetry procedures were deficient in that the

monitoring and tracking of occupational dose was not adequately

addressed in procedure. Specifically, procedures which require

monitoring of dose in the controlled area for workers who are required

to be monitored in the RCA and practices for adjusting radiation worker

dose assignments to eliminate all "background" dose, which contains an

operational dose component, were identified to the licensee as issues

requiring further evaluation and procedural treatment as appropriate.

These issues are an Unresolved Item with respect to dose tracking,

assignment of dose, and related procedural improvement.

26

R1.4 Radiological Controls During Power Operations

a. Inspection Scope (83750)

The inspector evaluated the adequacy of licensee radiological controls

with emphasis on external occupational exposure controls during normal

plant operations. The inspector evaluated adequacy of radiological

controls for an Independent Spent Fuel Storage Installation within the

licensee's protected area. Other areas inspected included radiation

area postings, radiation work permit controls, and effectiveness of the

ALARA program. The inspector made tours of the radiation controlled

area, observed compliance of licensee personnel with radiation

protection procedures for routine work evolutions, and conducted

interviews with licensee personnel with respect to knowledge of

radiological controls and working conditions.

b. Observations and Findings

The inspector verified observed controls for external occupational

exposures met applicable regulatory requirements and were designed to

maintain exposures ALARA. The inspector reviewed several radiation work

permits (RWPs) utilized to control ongoing work within the

radiologically controlled area and noted that the controls observed were

appropriate for the described tasks and radiological conditions.

Interviews were conducted with radiation workers in order to determine

the level of understanding of radiation work permit requirements from a

representative cross-section of-plant workers. The workers interviewed

were verified to have signed onto an RWP, were wearing dosimetry

appropriate to their work'activities within the RCA in accordance with

plant procedures, and were performing specific work activities on

appropriate RWPs. The questions asked included the RWP number of the

RWP signed in on, electronic dosimetry dose limits, and general.

radiological working conditions for the areas worked in. A good

knowledge of RWP requirements and of radiological working conditions,

generally, was demonstrated.

The inspector noted significantly upgraded and improved posting

practices throughout the plant. During a tour of the Spent Fuel Pool

the inspector observed no items hanging from the side of the pool and

good radiological controls in place in this area overall. The inspector

observed the decontamination prior to rail shipment of an IF 300 Cask

with good contamination and radiological controls. Radiation workers

during peak traffic periods were observed exiting the RCA fully in

accordance with procedures for frisking out of the RCA to include

properly clearing small articles with the small articles monitor. Pre

job RWP work planning and ALARA briefings for observed ongoing work

evolutions were found to be conducted in an effective manner. During

tours of the plant, the inspector observed RC technicians performing

radiation and contamination surveys in accordance with procedure. Also,

during inspection of the tool issuance rooms, good controls for slightly

contaminated tools inside the RCA and for clean tools outside the RCA

were noted. The inspector performed approximately twenty eight

27

independent contamination surveys (swipes) of areas within the RCA with

relatively high potential for loose contamination to verify that clean

areas within the RCA were being maintained clean. The licensee

continues to be challenged with respect to the effectiveness of

contamination controls based on the relatively high.number of Personnel

Contamination Events (PCEs)-incurred during Refueling Outage (RO) 17

(207 PCEs total for 1996) and based on recent independent nuclear

assessment findings which identified multiple examples of smearable

contamination above contamination control limits in clean areas.

However, during this inspection, all of the swipes were counted and

determined to be within the licensee's procedural limits for loose

contamination. The licensee's ALARA program continues to be effective

in achieving reductions in site exposure. The licensee achieved 166.56

person rem for 1996 against.a goal of 211 person rem which was a record

low for the site during a refueling outage year. The licensee.achieved

63 person rem in 1994 during a non outage year and has established a

1997 site goal of 25 for 1997, also a non outage year. Through

January 28, 1997, the licensee had achieved a site dose of 1.239 rem

against a target dose of 1.901 rem.

The inspector evaluated the adequacy of radiological controls for the

Independent Spent Fuel Storage Installation (ISFSI).

Independent

radiation surveys were taken inside the ISFSI RCA and at the fence line

surrounding the facility. Swipes were taken inside the ISFSI RCA to

determine levels of smearable contamination. The inspector determined

that the radiation levels detected and the smearable contamination

levels identified were within the limits specified in the licensee's

E&RC Surveillance Test Procedure RST-025, "Surveillance of the

Independent Spent Fuel Storage Installation" with no regulatory concerns

noted.

c. Conclusions

The radiological controls program was being effectively implemented with

• good occupational exposure controls observed during normal plant

operating conditions. Good radiological control performance.was

• apparent in the occupational exposure activities observed by the

inspector. Independent contamination surveys identified no loose

contamination levels above contamination control limits. The ALARA

program was controlling site exposures to record low levels for the

site. No regulatory concerns were identified with respect to the

adequacy of controls for the ISFSI facility with the radiation and

contamination levels independently inspected determined to be within

procedural limits.

R1.5 Up-to-Date Radiological Survey Data not Posted at RCA Entrance

a. Inspection Scope (71750)

While conducting a walkdown of the RHR pump room with an auxiliary

operator, the inspector noted that the most current radiological survey

data was not used by a radiation control (RC) technician to inform the

28

inspector and operator of the radiological conditions in the room.. In

addition, RWPs located at the entrance to the RCA did not contain the

most current quarterly radiological survey data reports.

b. Observations and Findings

On February 8, the inspector accompanied an auxiliary operator

conducting a weekly check of equipment status in the RHR pump room.

Before entering the room, the shift RC technician explained the

radiological conditions using what he thought was the most current

radiological survey data report for the room. Routine radiological

surveys of the RCA are conducted at various frequencies; the RHR pump

room was one of 38 areas routinely surveyed every quarter. The

inspector noted that the survey report used by the technician was dated

October 18, 1996. The inspector questioned whether this was the most

current survey since it appeared to be outside the quarterly required

frequency.

After exiting the room, the inspector discussed the survey report again

with the RC technician. At this time, the inspector was shown a more

current quarterly survey report dated January 7, 1997. This survey

report was obtained by the technician from the RWP file folders

maintained in the shift RC desk. The technician indicated that he had

obtained the October survey report from the RWP posting board located at

the entrance to the RCA. This board contains a listing of all "Special"

RWPs. The workers are expected to read and follow the requirements of

these RWPs prior to performing work covered by them. Attached to the

RWPs were area survey reports which provided the radiological conditions

of the RCA areas covered by each RWP. Based on a review of some of the

RWPs, it appeared that all of the quarterly survey reports were from the

previous quarter. Many of the Special RWPs had specific instructions

requiring the worker to review the survey reports attached to the RWP

for the current radiological conditions. Based on.this, the inspector

considered it important that correct and up-to-date survey information

be included so that workers are properly informed of work area

radiological conditions and hazards. While local area maps at the

entrance to RCA rooms and areas also show the current radiological

conditions, the inspector believed that it could be confusing to workers

if conflicting radiological information existed.

The inspector reviewed the January 7 survey record of the RHR room and

determined that radiological conditions had actually improved since the

October survey was performed, In addition, the local survey map located

at the entrance to the RHR pump room had been updated with the most

recent radiological data from the January 7 survey results. Based 6n

this, the inspector determined that there had been no actual

radiological safety consequence in having used the out-dated survey

data. However, the inspector was concerned that there were other

quarterly surveyed areas where the radiological conditions had degraded

since the previous quarter.

30

PARTIAL LIST OF PERSONS CONTACTED

Licensee

H. Chernoff, Supervisor, Licensing/Regulatory Programs

J. Clements, Manager, Site Support Services

D. Crook, Senior Specialist, Licensing/Regulatory Compliance

M. Herrell, Training Manager

C. Hinnant, Vice President, Robinson Nuclear Plant

J. Keenan, Director, Site Operations

B. Meyer,'Manager, Operations

G. Miller, Manager, Robinson Engineering Support Services

R. Moore, Manager, Outages/Scheduling

J. Morris, Acting Maintenance Manager & Electrical / I&C Superintendent

J. Moyer, Manager, Maintenance

D. Stoddard, Supervisor, Operating Experience Assessment

R. Warden, Manager, Nuclear Assessment Section

T. Wilkerson, Manager, Regulatory Affairs

D. Young, General Manager, Robinson Plant

.

NRC

B. Desai, Senior Resident Inspector

J. Zeiler, Resident Inspector

31

INSPECTION PROCEDURES USED

IP 37551:

Onsite Engineering

IP 40500:

Evaluation of Licensee Self-Assessment Capability

IP 61726:

Surveillance Observations

IP 62707:

Maintenance Observation

IP 71707:

Plant Operations

IP 71001:

Licensed Operator Requalification Program Evaluation

IP 71750:

Plant Support Activities

IP 84750:

Radwaste Treatment, Effluent & Environmental Mon.

IP 83750:

Occupational Radiation Exposure

IP 92901:

Followup - Operations

IP 92902:

Followup - Maintenance

IP 92903:

Followup - Engineering

ITEMS OPENED, CLOSED, AND DISCUSSED

Oened

Type

Item Number

Status

Description and Reference

NCV

50-261/97-01-01

Closed

Failure to Perform A Source Check Prior to

Gaseous Release (Section 03.1)

NCV

50-261/97-01-02

Closed

Inadequate Corrective Actions for RPS

Relay Degradation (Section M1.2)

NCV

50-261/97-01-03

Closed

Failure to Adequately Implement TS

Surveillance Requirement (Section M8.1)

NCV

50-261/97-01-04

Closed

Failure to Conduct Containment Airlock

Testing (Section E2.1)

NCV

50-261/97-01-05

Closed

Inappropriate Testing of the AFW pumps

(Section E2.2)

URI

50-261/97-01-06

Open

Demonstrate Accurate Dose Monitoring and

Dose Assignment Practicesand Procedures

(Section R1.3)

URI

50-261/97-0I-07

Open

Complete Review of Licensee Controls of

Radiological Survey Data (Section R1.5)

32

Closed

LER

50-261/96-01-00

Closed

Condition Prohibited by Technical

Specifications Due to Inadequate Testing

of Nuclear Instrumentation Power Range

Channels (Section M8.1)

LER

50-261/97-01-00

Closed

TS Violation Due to Missed Surveillance

Requirements (Section 08.1)

LER

50-261/97-02-00

Closed

Technical Specification Violation Due to

Inadequate Surveillance Test (Section

E8.1)