ML20204K117

Insp Rept 50-341/88-21 on 880716-0831.Violations Noted. Major Areas Inspected:Action on Previous Insp Findings, Operational Safety,Maint,Surveillance,Followup of Events, LER Followup,Personnel Qualifications & Regional Requests

ML20204K117
Person / Time
Site:	Fermi
Issue date:	10/12/1988
From:	Cooper R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20204K112	List: ML20204K108 ML20204K117
References
RTR-NUREG-0737, RTR-NUREG-737 50-341-88-21, NUDOCS 8810250349
Download: ML20204K117 (18)

See also: IR 05000341/1988021

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U.S. NUCLEAR REGULATORY COMMISSION

REGION III

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Report No. 50-341/88021(DRP)

Docket No. 50-341 Licerise No. NPF-43

Licensee: Detroit Edison Company

2000 Second Avenue

Detroit, MI 48226

Facility Name: Fermi 2

Inspection At: Fermi Site, Newport, Michigan

Inspection Conducted: July 16 through August 31, 1988

Inspectors: W. Rogers

T. Silko

S. Stasek

K. Ridgeway

Approved By: R. Cooper 5

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ReactorProjectsSection3B Date

Inspection Summary

Inspection on July 16 to August 31, 1988 (Report No. 50-341/88021(DRP))  ;

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Areas Inspected: Action on previous inspection findings; operational safety;

maintenance; surveillance; followup of events; LER followup; startup test  !

observation; personnel qualifications; regional requests; and review of

allegations.

Results: Two violations were identified (Paragraph 3). One unresolved

item Ta's identified (Paragraph 6) and four open items were identified ,

(Paragraphs 3, 4, 7 and 10).

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8910250349 881014

DR ADOCK0500gg41

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DETAILS

1. Persons Contacted

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a. . Detroit Edison Company

• P. Anthony, Licensing

i L. Bregni, Senior Licensing Engincor

R. Bryer, Safety

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• S. Catola, Vice President, Nuclear Engineering and Services  !

T. Dong, Safety '

C. Gelletly, Nuclear Engineering General Supervisor

• D. Gipson, Plant Manager i

• L. Goodman, Licensilig i

D. Grimes, Fluids Systems Engineer  !

G. Hunt, MTE Support

R. Lenart, Nuclear Engineering General Director

P. McComish, Safety

R. Matthews, I&C General Superintendent

T. Meesseman, Training

• W. Orser, Vice President, Nuclear Operations

, *G. Preston, Operations Engineer

i *T. Riley, Supervisor Compliance l

, J. Sabo, Plant Engineer l

1 H. Sierra, Technical Staff Engineer i

• R. Stafford, Director NQA and PS J

W. Terrasi, General Supervisor Chemistry i

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• W. Tucker, Operations Superintendent

J. Wald, Production Quality Assurance Supervisor

E. Wilds, Lead Engineer Fluids

L. Wooden, Nuclear Engineering Staff

! b. U.S. Nuclear Regulatory Commission

K. Ridgeway, Senior Resident Inspector, Lacrosse

• W. Rogers, Senior Resident Inspector

T. Silko, Inspector

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• S. Stasek, Resident Inspector

• Denotes those attending the exit meeting on September 20, 1988.

The inspectors also interviewed others of the licensee's staff during

this inspection.

2. Followup on Inspector Identified Items (92701)

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a. (Closed) Unresolved Item 341/88003-07: Adequacy of locked valve i

guidelines. In a previous inspection, the inspector questioned

why Valves B21-F077A/B, 821-F104A/B/C/D, P44-F400A/B and numerous i

other valves were not identified in the licensee's locked valve  :

program. The inspector requested that the locked valve guidelines

be provided. The guidelines provided were from Procedure 21.000.14,

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"Locked Valve Guidelines." This procedure stated that val'es v

without position indication in the control room in ESF systems

where misalignment could defeat the safety function of the system

or decrease its capacity or state of readiness should be in the

program. The valves identified by the inspector met this criteria

but were not in the program. This procedure was used to implement

a NUREG-0737 item as disCJssed in the FSAR Section H.II.K.1.5.3.

Therefore, this is considered a violation (341/88021-01) of

Technical Specification 6.8.1.b for failure to implement Fermi 2

cotlitments made in response to NUREG-0737 requirements. Presently, '

the licensee is reviewing ESF systems versus the locked valve

criteria,

b. (Closed) Unresolved Item 341/87009-02: Testing of main steam

isolation valve leakage control system (MSIVLCS) deactivate

circuits. The inspector requested NRR review of this circuit

as to is applicability under Technical Specification surveillance

testing. In a memorandum dated June 12, 1988, NRR responded that

the circuit is required to be tested under Technical Specification

requirements. The inspector informed the licensee of this position

which the licensee acknowledged and showed the inspector a revised

surveillance procedure reflecting appropriate circuit testing. The

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procedure had been revised and performed prior to issuance of the

NRR letter. Since the matter was corrected and did not appear to

have generic significance, this matter is considered resolved.

c. (Closed) Unresolved Item 341/87026-05: UFSAR accuracy. The

licensee reviewed the Safety Evaluation. Logs for 1985, 1986 and 1987 l

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and determined that 87 entries needed further review to determine

whether they were incorporated into the UFSAR. Four entries were

determined to need incorporation. The inspector determined that

these actions were sufficient to resolve the inspector's concerns.

d. (Closed) Open Item 341/80003-03: Feedwater control system problems.

The licensee discovered and repaired a large oil leak and performed

troubleshooting / tuning of the control system circuitry. Following

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these actions the licensee was able to successfully pass feedwater

control testing. This matter is considered closed.

e. (Closed) Unresolved Item 341/88003-04: Independent verification

deficiencies. Violations 88012-02 and 10 superseded this matter

by eleveting independent verification concerns to the violation

category. This matter is considered closed based on issuance of

these violations.

f. (0 pen) Open Item 341/87020-01: EX0-Sensor Action Plan. To resolve

reliability concerns reported under a Part 21 report, the licensee

1 implemented an action plan to assure operability of the drywell

H2/02 sensors in the Post Accident Monitoring System. This plan i

consisted of:

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(1) Performing a function test of the sensors every 31 days.

(2) Changing out the sensore every six months.

(3) Reducing sensing line heat trace temperature ?.0+F to reduce

loss of electrolytes. .

. (4) Pursuing with the vendor a new membrane made of a different

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material.

Monthly functional tests conducted during 1988 have shown no problems

with the sensors; however, several procedural problems had to be

resolved during this periou. Deviation Event Report (DER) 88-1237,

was issued on June 29, 1988, when the six month changeout of the H2

sensor could not be made since it was on a QC hold because the vendor

source surveillance check had not been completed prior to delivery.

It was returned to the vendor for the source check, but it was not .

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available at the site in time to meet the scheduled six month

replacement. A change in the vendor's ownership in late 1987 has

complicated the quality control, and a. vendor inspection by.DEC0

when the sensor was returned showed several deficiencies in the

new vendors quality program. Corrective actions'are underway.

The reduction in sensing'line neat tracing temperature has

been initiated to decrease the loss of sensor electrolyte.

The electrolyte loss for the first sensor exchange in July

was not yet available. '

Discussions have been held with the' vendor on possible new membrane

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material, but this will be a long term item. *

g. (Closed) Unresolved Item 341/86039-05: Emergency core cooling flow

control setpoints. In Inspection Report No. 86039, the inspector - ,

documented that the licensee considered the ECCS flowrates in the  !

Technical Specifications as nominal values instead of absolute

values. As such the licensee did not account for instrument

inaccuracy in assuring the appropriate flowrate was achieved.

to the reactor vessel for HPCI & RCIC. The inspector requested

confirmation from NRR that the Technical Specification values

were absolute instead of nominal. In a memorandum dated June 22, l

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1988, NRR confirmation was received which stated in part "All numbers

in the TSs should be considered absolute unless otherwise noted." i

Therefore, the licensee did not meet Technical Specification

Surveillance Requirement 4.5.1.a.3 for having the HPCI flow i

controller in the correct position or 4.7.4.a.3 for the RCIC flow

controller. The difference was 40 gpm for RCIC and 200 gpm for

HPCI. This is considered a violation (341/88021-02) of Technical

Specifications 4.5.1.a.3 and 4.7.4.a.3. The generic implication of

using nominal in lieu of absolute values for establishing controller ,

setpoints is also of concern.

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No other violations or deviations were identified in this area. I

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3. Operational Safety Verification (71707)

The inspectors observed control room operations, reviewed applicable

als and conducted discussions with control room operators during the

period from July 16 through August 31, 1988. The inspectors verified

the operability of selected emergency systems, reviewed tagou'; records

and verified proper return to service of affected components. Tours of

the reactor building and turbine building were conuucted to observe plant

equipment conditions, including potential fire hazards, fluid leaks, and

excessive vibrations and to verify that maintenance requests had been

initiated for equipment in need of maintenance.

The inspectors, by observation and direct interview, verified that the

physical security plan was being implemented in accordance with the

station security plan.

The inspectors observed plant housekeeping / cleanliness conditions and

verified implementation of radiation protection controls. During the

inspection, the inspectors walked down the accessible portions of the

standby gas treatment and standby liquid control systems to verify

operability by comparing system lineup with plant drawings, as-built

configuration or present valve lineup lists; observing equipment

conditions that could degrade performance; and verified that

instrumentation was properly valved, functioning, and calibrated.

The inspectors also witnessed portions of the radioactive waste system

controls associated with radwaste shipments and barreling.

These reviews and observations were conducted to verify that facility

operations were in conformance with the requirements established under

Technical Specifications, 10 CFR, and administrative procedures.

During these reviews:

a. A discussion was held between the inspector and the licensee

regarding HPCI and RCIC oil sampling. At the time of the discussion,

if an oil sample showed a high particle count, instructions would be

provided to operations for a method of cleaning the oil, but guidance

was not offered as to whether the system should be declared

inoperative. Procedure 71.000.15, Attachment 2, "Oil Change Data

Sheet," was revised such that if the results of the oil sample show

a particle count greater than that specified in the "out of

specification" range, the system is to oe declared inoperative per '

Technical Specifications by the NSS, until such time that oil purity

has been restored to at least the "requiring purification" range.

The inspector has no further questions in this area,

b. The inspector discussed with the licensee the placing of the HPCI

and RCIC pumps physically inoperative when the external purifier

(non-seismic) is added to the system. The licensee is considering

declaring the system administratively inoperative rather than

physically removing the system from service and declaring the

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system inoperative when the external purifier is in use. The

inspector concurs that administrative 1y declaring the system out

of sarvice, rather than physically removing the system from service

is a more prudent action and will increase the availability of the

system to perform its intended safety functions. The. inspector

has no further questions in this arec.

c. The inspector noted during walkdowns in the con',ro' room, that area

lighting levels varied significantly shift to s' rt. When questioned

about the variance, operatcrs stated that nn " s was currently

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provided and, therefore aach shift adjustas .evel of lighting l

to that which seemed mos,t appropriate and c ,rtable. Some shifts

preferred subdued lighting levels to allow toe easier identification

of indict. ting light status on the panels while others preferred more ,

light to better read equipment tags and indicators / recorders. Also,

the operators indicated that due to the design and/or placement of

the temperature controller (s) in the CCHVAC system, area temperature

levels become uncomfortably low at times and that by adjusting ,

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lighting levels, an alternate method of temperature control could be

achieved. The inspector then questioned licensee management whether.  :

this situation was in accordance with the guidance in NUREG-0700 or

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with the licensee's Detailed Control Room Design Review (DCRDR)

conducted previously. In response, an evaluation of control room

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lighting was initiated, illumination limits were established and [

operators were instructed on maintaining lighting within the

appropriate limits. The evaluation was conducted by engineering

and new limits communicated to the operators via a plant night

order. This will remain an open item pending inspector review

of the newly specified limits and of the results of the licensee's

DCRDR relative to this concern (341/880021-03 (DRP)).

d. At 0020 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />, July 23, 1988, with the reactor at approximately

90 percent power, a power reduction / shutdown was initiated due

to increasing Drywell (0/W) unidentified leakage. At 0106 hours0.00123 days <br />0.0294 hours <br />1.752645e-4 weeks <br />4.0333e-5 months <br />,

calculated D/W unidentified leakage exceeded the Technical

Specification limit of 5.0 gpm (actual 5.4) and at 0505 hours0.00584 days <br />0.14 hours <br />8.349868e-4 weeks <br />1.921525e-4 months <br />,

in accordance with the licensee's approved Emergency Plan, an

Unusual Event was declared. At 1516 hours0.0175 days <br />0.421 hours <br />0.00251 weeks <br />5.76838e-4 months <br />, the reactor was

manually scrammed from 10 percent power. The licensee subsequently

determined the source of the leakage as the RCIC Inboard Steam t

Supply Isolation Valve and the RWCU vessel drain line valve (G33-F100). l

The inspector observed various stages of the reactor S/D and verified  ;

licensee actions as being in accordance with Technical Specifications. t

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During the react)r shutdown, the inspector discussed the following l

issues with the ifcensee:

(1) Drywell de-inerting via the Torus-to-Orywell vacuum Breakers. I

Whilo at approximately 10 percent power, the licensee planned I

to enter the D/W and investigrte the source of the leakage.

Failure to de-inert the D/W due to an inoperable T4803-F602 l

"D/W Exhaust Inboard IsolatNn Valve," rendered D/W access j

wcile in Modes 1 and 2 impos e le. )

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Due to the inoperative F602, Primary Containment was inerted

on May 17, 1988, via the process of opening the D/W to torus-

vacuum breakers (refer to Inspection Report No. .50-341-88012)

and adding nitrogen to the torus free air space. Inerting the

Drywell via this flow path is discussed in a note to Technical t

Specification 3.6.4.1 which allows:"the suppression chamber  ;

Drywell. vacuum breakers be manually opened for.inerting

containment," but does not state the appropriateness of

this flow path to de-inert. The Office of Nuclear Reactor e

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Regulation (NRR) was. contacted for an interpretation of this

noie. NRR's interpretation was that under the current 3.6.4.1

Technical Specification, the Drywell-to-Torus' vacuum breakers

will not be used during the de-inerting process. This

interpretation was discussed with, and acknowledged by

the licensee.

(2) Requirement for Containment Airborne Particulate Monitoring.

During the reactor S/D, the inspector questioned an apparent

disciepancy between the UFSAR Appendix A, Technical

Specifications, and Regulatory Guide 1.45 regarding airborne

particulate monitoring of the primary containment atmosphere.

The UFSAR states that in accordance with Regulatory Position 3 '

of Regulatory Guide 1.45, containment monitored parameters

include, but are not limited to, sump level, sump level flow,

and airborne particulate rates. In actuality, no on-line

containment ] articulate monitor exists. Further investigation

determined t1at a July 1981 Fermi Safety Evaluation Report '

(SER), NUREG-0998, discussed on Pages 5-18 and 5-19 the subject <

of leakage monitoring. The SER acknowledged that monitoring of '

airborne particulate is not performed, but that other systems

being used are sufficient to meet the intent of Regulatory

Guide 1.45. The other systems used to monitor for leakage

are (1) sump level and flow monitoring, (2) a supplementary

Drywell sump level monitor, and (3) airborne gaseous

radioactivity monitoring.

The inspector concluded that the above monitoring methods with *

the stated alternative comply with the intent of Regulatory

Guide 1.45. Additionally, pressure temperature, and humidity j

measuringdevicesarealsousedtoIndicatetheexistenceof '

leakage.

The licensee identified to the inspector that a clarification ,

of the UFSAR was previously identified as documented in i

UFCN 88-068 drafted June 7, 1988. UFCN 88-068 was reviewed

by the inspector and it adequately addressed the requi'ed

clarification and was currently in the normal approvai

process.

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(3) Weaknesser, in the coordination in determining the leakage

I source. The licensee also recognized that the organizational i

response to leaks needed improvement in the radiochemistry

analysis area and the communication of that analysis to the

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JN'SS and plant management. Numerous procedure changes were ,

enacted to provide clearer direction to personnel taking the

samples and what to evaluate the samples for and from what ,

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location samples should be extracted. Personnel were briefed-

on thir, event to provide a stronger perspective as to what is

needed.

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No violations or deviations were identified in this area '

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4. Monthly Maintenance Observ'ation (62703)

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, Station maintenance activities on safety-related systems.and components

listed below were observed to ascertain that they were conducted in

accordance with approved procedures, regulatory guides and industry

codes or standards and in conformance with Technical Specifications.  ;

The following items were considered during this review: the limiting

conditions for operation were met.while components or systems were

< removed from service; approvals were obtained prior to initiating the ,

.work; activities were accomplished using approved procedures and were

' inspected as applicable; functional testing and/or calibrations were

performed prior to returning components or systems to service; quality

control records were maintained; activities were accomplished by

, qualified personnel; parts and materials used were properly certified; .

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radiological controls were implemented; and fire prevention controls

were implemented.

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Work requests were reviewed to determine the status of outstanding jobs

and to assure that priority is assigned to safety-related equipment  !

maintenance which may affect system performuce. e

The following maintenance activities'were observed: l

• Troubleshoot and repair Drywell Exhaust Inboard Isolation i

Valve T4803-F602 (WR 02280517).

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• Troubleshoot.and repair Drywell Vent / Inboard Isolation i

Valve T4803-F601 (WR 00180728). i

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• Leak repair to RCIC steam supply inboard Isolation l

Valve E61-F007.

• Troubleshooting of B Recirculation pump discharge ,

Valve B31-F0318 failure to close from the Control '

Room (WR 00380828).

- * Troubleshooting activities into the cause of the scram of l

24 control rods (WR 002B0802). j

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Following completion of maintene ce on tiie RCIC valve, the inspectors

verified that the system had bevi returned to service properly. j

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While observing post-maintenance testing on the High Pressure Coolant

Injection (HPCI) System, the inspector noted the verification of

system operability was conducted using certain sections of Operating

Procedure 23.202, "High Pressure Coolant Injection System." However,

since 23.202 is a system operating procedure and provides no step-by-step

signoff of the activities the control room operator needed to do as part

of the test, the operator with the concurrence of the Nuclear Assistant

Shift Supervisor (NASS) utilized appropriate portions of Surveillance

Procedure 24.202.01, "HPCI Pump Operability and Flow Test at 1000 psig

and Valve Operability" to document the test performance. The decision

to do this was made at the time the test was tc be performed and

subsequently resulted in the operator working with two procedures  !

simultaneously; 23.202 to conduct the test and 24.202.01 to document the ,

test. The inspector had two concerns with this approach. First, the use  ;

of two procedures simultaneously to perform testing could lead tc confusion

on the part of the operator. Second, due to the lack of specific i

instructions or preplanning provided by the work package to properly r

conduct the test, the operator (with the NASS) developed, on the spot,

a means of conducting a test by using segments of two existing procedures. ,

The licensee recognizes the potential for error using such an approach to l

testing and is currently evaluating whether alternate methods may be l

better suited in the future. This is considered an open item pending '

completion of licensee actions (341/88021-04(DRP)).

No violations or deviations were identified in this area. j

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5. Monthly Surveillance Observation (61726)

The inspectors observed surveillance testing on the high pressure cooling

system per Procedure 24.202.01, "HPCI Pump Operability and Flow Test at

1000 psig and Valve Operability" required by Technical Specifications and

verified that: testing was performed in accordance with adequate

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procedures, test instrumentation was calibrated, limiting conditions

for operation were met, removal and restoration of the affected components

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were accomplished, test results conformed with Technical Specifications ,

and procedure requirements and were reviewed by personnel other than the i

individual directing the test, and any deficiencies identified during the '

testing were properly reviewed and resolved by apropriate management

personnel.

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The inspectors also witnessed portions of the following test activities:

i 24.413.03 Control Room Emergency Filter Monthly Operability

Test.

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24.404.02 SGTS Filter Ponthly Operability Test.

No violations or deviations were identified in this area,

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6. Followup of Events (93702)

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During the inspection period, several events occurred, some of which

required prompt notification of the NRC pursuant to 10 CFR 50.72. The

inspectors pursued the events onsite with licensee and/or other NRC

officials. In each case, the inspectors verified that the notification

was correct and timely, if appropriate, that the licensee was-taking  ;

prompt and appropriate actions, that activities were conducted within

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regulatory requirements and that corrective actions would prevent

future recurrence. The specifit, events are.as follows:

50.72 Events ,

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• July 19, 1988 ESF actuation when RPS "B" EPA breaker opened

i and deenergized RPS Bus "B".

• July 21, 25, Reports on inaccessible or unsatisfactory l

, 26, 28 and testing of flanges from West Jersey '

August 4, 1988 Manufacturing Company.

• July 23,1988 Determined unidentified drywell leak based on

i 30 minute sample of 5.4 gpm. Reduced reactor

, power; leak based on one hour sample of 5.6 gpm.

Unusual event declared.

• July 23, 1988 Reactor placed in shutdown condition by manual i

scram due to unidentified leakage in drywell. t

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i * July 24, 1988 Terminated unusual event. Preparing to place i

plant in shutdown cooling.  !

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* July 25, 1988 Retractio1 of April 9,1988, event report af ter l

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being determined not reportable.  !

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• July 27, 1988 FSF actuation when I&C repairman shorted across

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two terminals and caused an auto initiation of

Div 1 EECW.

l * July 27, 1988 HPCI E41 F006 valve open circuit grounded

preventing operation. l

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• August 14, 1988 Trip of main turbine generator causing a reactor

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• August 21, 1988 Declaration of Unusual Event and initiation

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of a plant shutdown due to recirculation Pump B  ;

discharge valve being inoperable. '

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• August 22, 1988 ESF actuation when RWCU system pumps tripped l

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on low flow. G33-F001 and G33-F001 valves

closed upon receipt of delta flow isolation

signal. ,

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• August 28, 1988 Declaration of Unusual Event and initiation of

a plant shutdown due to recirculation Pump B

discharge valve being inoperable.

On July 25, 1988, via the ENS, the licensee retracted the April 9,

1988, 10 CFR 50.72 event notification on loss of RHR cooling which

occurred when the shutdown (S/D) cooling injection valve (E11-F015B)

automatically closed. The licensee determined this event was not

reportable because the closure signal for the F015B valve did not i

originate from ESF logic. The inspector discussed with the licensee

that although the event was not reportable as an ESF activation, the

event is reportable as loss of residual heat removal. The inspector

noted under 50.72 (b)(2)(iii)(B), that any event that alone could have

prevented the fulfillment of the safety function of' structures or systems

that are needed to remove residual heat is reportable as a four-hour

report. The inspector identified two additional items that raise the

significance of this event: (1) the loss of S/D cooling on the "B" loo

i occurred at a time when the "A" loop of 5/D cooling was out-of-service,p

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(2) the loss of S/D cooling occurred for 30-35 minutes prior to being

identified by the control room operators. Following the discussions,  ;

the licensee agreed to submit an LER on the event. '

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Following the main turbine trip that occurred on August 14, 1988, the '

inspector noted that credit was taken for performance of Surveillance l

Procedure 24.109.001 "Turbine Steam Valves Weekly Test" due to the event.

When questioned about the advisability of doing this, licensee management

i responded that a review was performed at the time and the Technical

, Specification surveillance requirements which POM 24.109.001 implements

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were verified as having been met. Additionally, it was stated that this

1 was not the first time this philosophy was implemer+ed and that the

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licensee intended to continue the practice. The in vector expressed

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concern that a surveillance procedure may address surveillance '

requirements / commitments beyond those in Technical Specifications and

r as such, if credit is to be taken for performance of a surveillance as ,

i a result of an operational event, all portions of the procedure need

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addressingIonsurveillancerequirements.not

Specificat just those

The inspector portions directly relating t

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24.109.001 and, in that case, found no additional requirements beyond

those the licensee had verified in accordance with the Technical '

Specifications. However, the inspectors will continue to review

this practice as future examples occur. l

j Deviation Report Events  !

The inspector revieved DER 88-1520 which identified that a HPCI

discharge valve had not been tested at the required time interval for t

alert testing. Thr6 inspector confirmeo through discussion with licensee

perronnel that the ASME Section XI for valve testing had not been

proporly implemented for the HPCI discharge valve. The inspector

evaluated this violation to 10 CFR 2, Appendix C V.G. and determined: l

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a. The violation was identified by the licensee,

b. The violation did not render the HPCI system incapable of

injecting the required water flow into the reactor vessel

in the required maximum permissible time frame,

c. At the end of the inspection period the time frame for

LER submittal had not expired.

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d. Corrective actions were still being formulated.

e. A violation of similar nature had not occurred in the

last two years.

This matter is considered unresolved (341/88021-05) contingent upon

corrective action review and LER submittal.

No violations or deviations were identified in this area.

7. Licensee Event Reports Followup (92700)

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Through direct observations, discussions with licensee personnel,

l and review of records, the following event reports were reviewed to

determine that reportability requirements were fulfilled, immediate

corrective action was accomplished, and corrective action to prevent

recurrence had been accomplished in accordance with Technical

l Specifications,

a. (Closed) LER 88002: Main steam line radiation monitor surveillance

procedure inadequacy causes MSIV closure. This event which was

l described in detail in Inspection Report No. 50-341/88003 was caused

by accidental snorting of a fuse in the MSIV DC logic while changing

another adjacent fuse. The I&C technician who replaced the fuse

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was not awsre that the circuit needed resetting and the MSIV DC half

I closure trip logic was in effect when a surveillance to check the

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functioning of the high radiation closure of MSIVs was started the

following day. The technician performing this test misinterpreted

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the step in the procedure to verify that amperage was present on

l both the DC and AC circuits before proceeding. The actions taken

to prevent recurrence of this condition were threefold.

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First,

surveillance procedure 44.101.028 was revised to assure that there

is current on both the AC and DC circuits if the HSIVs are open;

this has been completed by Revision 22 to the abcVe procedure.

l In addition, 52 of the MSIV surveillance procedures were revised

i to remove similar ambiguities. The second corrective action was

i to place labels on Panels R325064B and R3250618 to indicate that

Circuits 2 and 11 power MSIV logic and to notify the Nuclear Shift

Supervisor if they are or have been deenergized. The inspector

l verified the installation of the labels. The third corrective

action was to improve I&C technician training. The "lessons

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learned" from this event were reviewed by all I&C personnel;

and in addition, after reviewing the I&C training program, it

was decided that:

(1) I&C training course CP-IC-336 would be implemented in

August 1988.

(2) The on-the-job I&C course, CP-IC-331 would be revised to include:

(a) emphasizing the initial conditions prior to testing,

(b) actions to be taken if initial conditions cannot be met,

and (c) action to be taken when one channel inadvertently trips

while testing the other channel. This course is to be complete

by the end of 1988.

(3) The I&C repairman oualification program description, PD-IC-720,

will be revised to mandate completion of 1 above and applicable

portions of 2 above prior to performing surveillances. This

change is in the approval chain.

Since the corrective actions appear to be adequate to prevent

recurrence of this type of event the LER was closed; however,

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the completion of the I&C training will remain an open item

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(341/88021-06) until the changes to the training program have

been completed.

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b. (Closed) LER 88003: Setpoints and Head Correction incorrect for

Residual Heat Removal (RHR) Interface Valves. During a review to

verify pressure monitor setpoints in response to a previous

violation (87006-01) and the I&C surveillance procedure improvement ,

program, the pressure alarm setpoints in TS 3.4.3.2-2 RHR Low

Pressure Cooling Injection and RHR Shutdcwn Cooling were found to

be higher than the relief valve settings. On January 6, 1988, the

q licensee proposed an emergency TS change to lower the alarm setpoints

and on the same date a TS Temport ry Waiver of Compliance was issued

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by NRR. On January 13, 1988, Amendment No. 14 was issued which

changed the setpoint in Tables 3. 4.3.2-2. In reviewing the

surveillance procedures for functional and calibration checks ,

of these pressere alarms, the inspectors found that the procedures j

had been revised to include the adjusted setpoint pressures. ,

c. (Closed) LER 86027: Vacuum Breaker Valve Failure. Followup to

this LER was previously documented in Inspection Report No. 87022.

As a result of that review, violation 87022-01 was issued. The

< violation corrective actions are adequate to complete followup on '

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this LER. Therefore, this LER is closed and the final corrective l

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actions will be inspected in the followup to violation 341/87022-01,

d. (Closed? LER 85080-01: Failure to place a radiation monitor

in serv <ce while re Masing liquid effluent.

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, In addition to the review criteria stated above, the LERs were reviewed

for potential violations of regulatory requirements. The results of

that review identified that a violation of Limiting Conditions for

Operation was associated with LER 85080-01. This violation occurred

during the same time frame and was of the same type as the violations

identified in Inspection Report No. 50-341/85040. As indicated in

Paragraph 9.d. of Inspection Report No. 50-341/86019, the escalated

enforcement actions of Inspection Report No. 50-341/85040 adequately

address this violation and no citation will be given,

j No oth6r violations or deviations were identified in this area.  :

8. Startup Test Observation (72302)

The inspectors reviewed portions of startup test procedures, toured the

areas containing system equipment, interviewed personnel, and observed

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test activities. While observing startup tests the inspector verified

that the established testing prerequisites were met, testing was performed

in accordance with adequate procedures, limiting conditions for operation

were met, test personnel were knowledgeable of the test, data was 7

accurately taken, and special test equipment required by the procedure  ;

J was calibrated and in service.

Th inspector observed the performance of the following startup tests: I

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e STUT 03B.023 Feedwater System level Setpoint Changes. e

i * STUT 06B.030 Recirculation System One and Two Pump Trips.

* STUT 06C.016 Selected Process Temperatures - Recirculation Pump

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Trip Data.

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• STUT 04B.019 Core Performance - Process Computer Determination. l

j * STUT 04A.030 Recirculation System - System Performance. '

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l During performance of STVT 068.030 on August 21, 1988, attempts to

l close reactor recirculation Pump B discharge valve (B31-F0B18) were ,

unsuccessful and the licensee commenced a reactor shutdown in

l accordance with Technical Specifications and entered the Emergency  !

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Plan. Suts,quently, troubleshooting of the motor operator revealed

I three loose terminations to the valve's torque switch. The terminations l

were tightened, the valve tested and found to stroke properly, and the  ;

{ unit returned to power.  ;

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i On August 28, 1988, test conditions were reestablished to complete t

! STVT 06B.030. Again when B31-F031B was directed to close from the

j thevalvefailedtostroke. The reactor was shutdown, ,

i control room}ng of the sotor operator was conducted, and torque switch

troubleshoot

J settings found to be incorrect. Two NRC Region III inspectors were

subsequently dispatched to the site to review licensee corrective

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actions (Reference Inspection Report No. 341/88025(DRS)). '

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i The inspector also reviewed the completed results of STVT 06B.019, i

{ Core Performance - Process Computer Determination, and determined j

j that the test was satisfactory. l

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No violations or deviations were identified.

9. Personnel Qualifications

During the inspection pericd, the licensee changed the "Engineer in

Charge." The new individual is holding this position until a permanent

replacement is acquired. The interim individual's qualifications were

reviewed against the applicable ANSI 18.1 standard revision and found

to meet the qualification requirements.

No violations or deviations were identified.

i 10. Regional Requests

l During the inspection period, the inspector continued to pursue the

i regional request dated September 24, 1987, dealing with preventive

maintenance activities associated with the GE AKF-2-25 circuit breakers,

previously discussed in Inspection Report No. 341/88006.

i Deviation Event Report DER No. 88-0290 was istJed tc address the corJerns

j noted in the above report that were contrary a ?.: recommendations in

NRC Information Notice 87-12 and GESIL 448.

a. The breaker inspections were scheduled '.or every other refueling

instead of annually or every refueling.

l b. There were no plans to disassemble and overhaul the breaker at

five year intervals.

l The inspectors found that Maintenance Instruction MI-M037, Rev 2,

Recirculation Pump Generator Field Breaker (GE Type AKF) General

Maintenance, had been approved March 14, 1988. This procedure deals with

the cleaning, inspection, lubrication, adjustment and operational checks

of the AKF type breakers. The revision included the SIL recommendations

concerning approved lubricants. The other recommended actions of the SIL

above had not been addressed so this will be carried as an Open Item

(341/88021-07).

11. Review of Allegations

(Closed) Allegation No. RI11-88-A-0022: Concerns regarding the process

for updating the Updated Final safety Analysis Report (UFSAR). On

February 16, 1988, the Senior Resident Inspector was contacted by an

anonymous alleger who provided four allegations regarding the UFSAR

updating process as outlined below:

Allegation 1: There was no revjew or approval by Licensing of changes

, to the FSAR when it was updated the first time.

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Allegation 2: Anyone can change the UFSAR based on filling out a form.

These forms receive no review before incorporation into

the UFSAR.

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Allegation 3: The form specified in interfacing Proceoure 11.000.121

is not the correct form to be used. A lady in Licensing

informed the alleger not to use that. form but to use

another form not approved that'has been made up by

Licensing.

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Allegation 4: The alleger was told by a supervisor not to write a DER

on this situation and that the supervisor did not want

any DERs associated with the UFSAR update activities.

The alleger indicated that if the alleger wrote a DER ,

there would be adverse personnel action taken against

him/her.

The NRR Project Manager conducted a review of the FSAR change files and

the program, including directives and procedures, implemented by the

licensee to implement FSAR changes. Discussions were conducted with

the cognizant Licensing personnel.

For the first FSAR update, Procedure NOIP-11.000.121-NS, "Updated Final

Safety Analysis Report and Environmental Peport Revisions," Revision 3,

issued in 1985, was-used to provide input to Licensing on proposed FSAR

changes. This procedure contains a form entitled, "UFSAR Change Notice

(UFCN)," which provides blocks to describe the change, the basis for the

change, and who initiated, reviewed and approved or concurred in the i

change. The form provides space for several approvals in Block 8; however, '

a review of the first FSAR update UFCN forms on file indicated that the

forms did not always reflect those approvals because the procedure did

not mandate that Block 8 must be completed. However, the UFCNs on file

did have documents attached to them which indicated who had reviewed and

approved the changes reflected on the form. The reviews were conducted

by Engineering, Operations, Licensing and the Independent Safety

Engineering Group (ISEG). Engineering usually initiated the change

proposal, but others were not prohibited from doing so. The QA

i organization does not review UFCNs. The ISEG reviewed those change

packages which contained safety evalustions (SEs) since, procedurally,

ISEG reviews all SEs whether associated with an FSAR change or other

plant change. The FSAR change initiator does not get involved in ths ,

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proposed change review process, unless the matter is technically I

complicated, c9ntroversial, or the initiator is questioned by ISEG l

during the SE review. The proposed FSAR change must be accepted by 1

the initiator's first line supervisor before it is sent to Licensing.  ;

The UFCNs received by Licensing are sent to a Subject Matter Expert

(SME) who is responsible for reviewing the change for technical ade l

and necessity, and who usually finalizes the SE which ISEG reviews.quacy The

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SHE is the individual assigned responsibility for a specific section of

the UFSAR.

N0!P-11.000.121, Revision 4, dated February 1988, is the current procedure

in use for making UFSAR changes for the second update. This revision

mandates that approvals be reflected in Block 8 of the UFCN. Licensing

is now playing a greater role in reviewing and assessing the technical l

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adequacy of proposed changes. For the first update, contractor support j

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was more extensively used to provide the Licensing overview. A review ,

of FSAR change packages processed for the second update indicates an

improvement over the packages oa file for the first update.

The FSAR change program and related procedures are undergoing further

changes as part of the licensee's effurts to upgrade the quality and ,

accuracy of plant procedures. Directive FMD-RA2, "Licenses, Plans, and

l Programs," Revision 0, issued in January 1988, establis.es requirements '

for control of amendments to licenses, plans, and programs, and as;igns

l responsibility for implementing those requirements, which includes the

l annual update of the FSAR. Under the new system a procedure will be '

l issued,FIP-RA201-SQ,"AmendmentstotheOperatIngLicense,UFSAR

and NRC Approved Plans and Programs." This will replace

Procedure N0!P-11.000.121. Licensing has in place a data table for

tracking FSAR changes which will be enhanced to reflect the new system. ,

The licensee expects to have the new programmatic and procedural changes

related to the FSAR updates luplemented by fourth quarter of CY 1988.

NRC Conclusions: ,

Allegation 1: Licensing does not approve FSAR changes. Licensing  :

coordinates and keeps trcck of propostd changes and l

, assures that appropriate approvals are obtained before j

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Deing incorporated in the FSAR. There was no evidence f

that the changes incorporated in the first FSAR update

did not receive appropriate reviews and were not

approved. This allegation was not substantiated.

Allegation 2: It is true that anyone can initiate a FSAR changa and l

the UFCN form is used for that purpose. However, the

change requires first line supervisor acceptance before

it gets into the system. When received by Licensing,

it is directed to the SME for review to ensure that '

the proposed change is acceptable. The fact that

j anyone can change the FSAR was substantiated; however,

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the proposed change is reviewed and approved before

l incorporation as concluded under Allegation 1.-

Allegation 3: It is true that the interfacing procedure and UFCN

form have undergone a few revisions; however, there

was no evidence that any unapproved form or procedure

was used in the FSAR updating process. This

allegation was not substantiated.

Allegation 4: The NRC did not pursue this allegation in that the

alleger was anonymous and did not identify the supervisor

involved. The DER procedure in effect on February 2,

1988, was FIP-cal-01-SQ, Revision 0, "Deviation and

Corrective Action Reporting." Paragraph 2.1.1 requires,

in part, that procedural noncompliance including

violations of procedures having nuclear safety significance,

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be documented as a DER.- It is noted that the DER originator

and his supervisor are required to sign the DER. Issuance

of a DER would not have been appropriate in this case in i

that no procedural noncompliance was idertified.

No violations or deviations were identified.

11. Unresolved Items ,

Unresolved items are matters aboat which more information is required I

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in order to ascertain whether they are acceptable items, violations

or deviations. An unresolved item disclosed during the inspection

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( 12. Open Items

Open items are matters which have been discussed with the licensee, .

I which will be reviewed further by the inspector, and which involve some  :

action on the part of the NRC, or licensee, or both. Open items disclosed .

during the inspection are discussed in Paragraphs 3, 4, 7 and 10.  !

13. Exit Interview (30703)

The inspectors met with licensee representatives (denoted in Paragraph 1)

on September 20, 1988, and informally throughout the inspection period 1

and summarized the scope and findings of the inspection activities.

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The inspectors also discussed the likely informational content of the

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inspection report with regard to documents or processes reviewed by the

inspectors during the inspection. The licensee did not identify any

such documents / processes as proprietary. The licensee acknowledged  ;

the findings of thc inspection.  !

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