ML20236D873

Insp Rept 50-312/87-13 on 870418-0529.Violations Noted. Major Areas Inspected:Areas of Operational Safety Verification,Maint,Surveillance & Followup Items

ML20236D873
Person / Time
Site:	Rancho Seco
Issue date:	07/14/1987
From:	Dangelo A, Ivey K, Myers C, Pereira D, Perez G, Qualls P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V)
To:
Shared Package
ML20236D845	List: ML20236D841 ML20236D863 ML20236D873
References
TASK-A-26, TASK-OR 50-312-87-13, GL-85-06, GL-85-6, IEIN-85-023, IEIN-85-091, IEIN-85-23, IEIN-85-91, IEIN-86-025, IEIN-86-25, NUDOCS 8707310094
Download: ML20236D873 (26)

See also: IR 05000312/1987013

Text

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U. S. NUCLEAR REGULATORY COMMISSION

REGION V

Report No:

50-312/87-13

Docket No.

50-312

License No. DPR-54

Licensee:

Sacramento Municipal Utility District

P. O. Box 15830

Sacramento, California 95813

Facility Name:

Rancho Seco Unit 1

Inspection at:

Herald, California (Rancho Seco Site)

Inspection conduct :

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Inspectors:

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entbr Resident Inspector

Date Signed

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C. N f Myers

'denf Inspector

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e ident Inspector

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D. Pere

a, Regio 1 Inspector

Date Signed

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Reg' al Inspector

Date Sig'ned

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K. I#y, Resident inspector, Palo Verde

Date' Signed

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Accompanying Personnel:

D.,Bax}er,INEL

Approved By:

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L. (f. Miller,(phief, Reactor ProjectsSection II

Date Signed

Summary:

Impection between April 18 and May 29, 1987 (Report 50-312/87-13)

Areas Inspected:

This routine inspection by the Resident Inspectors and by

Regional Inspectors, involved the areas of operational safety verification,

maintenance, surveillance, and followup items.

During this inspection,

Inspection Procedures 25573, 30702, 30703, 37701, 37703, 39702, 61726, 62702,

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62703, 71707, 71710, 72701, 90713, 92700, 92701, 92702, 92703, 93702, 92712,

and 94703 were used.

Results:

In the areas inspected, three violations were identified:

Failure

to use an approved replacement filter element (Severity Level V), failure to

inspect the replacement filter work area for cleanliness (Severity Level V),

and failure to use an appropriate liquid penetrant test procedure for a spent

fuel pool liner inspection (Severity Level IV).

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DETAILS

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Persons Contacted

a.

Licensee Personnel

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C. Andognini, Chief Executive Officer, Nuclear

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• W. Bibb, Deputy Restart Implementation Manager

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G. Coward, Assistant General Manager, Technical and Administrative

Services

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• B. Day, Nuclear Plant Manager

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J. McColligan, Director, Plant Support

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J. Vinquist, Acting Licensing Manager

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D. Army, Nuclear Maintenance Manager

• B. Croley, Nuclear Plant Manager

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G. Cranston, Nuclear Engineering Manager

• J. Grimes, Planning Supervfsor

W. Kemper, Nuclear Operations Manager

J. Shetler, Director, Administrative Services

T. Tucker, Nuclear Operations Superintendent

L. Fossom, Deputy Implementation Manager

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• R. Colombo, Regulatory Compliance Superintendent

• J. Field, Nuclear Technical Support Superintendent

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S. Crunk, Incident Analysis Group Supervisor

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F. Kellie, Radiation Protection Superintendent

• 15. Knight, Quality Assurance Manager

C. Stephenson, Senior Regulatory Compliance Engineer

B. Daniels, Supervisor, Electrical Engineering

R. Wichert, Instrumentation and Control Maintenance Superintendent

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J. Irwin, Supervisor, Instrumentation and Control Maintenance

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C. Linkhart, Electrical Maintenance Superintendent

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R. Cherba, Quality Engineering Supervisor

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T. Shewski, Quality Engineer

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J. Robertson, Licensing Engineer

• F. Hauck, Licensing Engineer

• R.

Lawrence,

• J. Delezenski, Nuclear Licensing Analyst

• W. Koepke, Quality Control Manager

Other licensee employees contacted included technicians, operators,

mechanics, security and office personnel.

• Attended the Exit Meeting on May 29, 1987.

1 Management Analysis Company (MAC) Personnel

2.

Operational Safety Verification

The inspectors reviewed control room operations which included access

control, staffing, observation of decay heat removal system alignment,

and review of control room logs.

Discussions with the shift supervisors

and operators indicated understanding by these personnel of the reasons

for annunciator indications, abnormal plant conditions and maintenance

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work in progress.

The inspectors also verified, by observation of valve

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and switch position indications,:that emergency systems were properly

aligned for the cold shutdown condition of the facility.

This included

verification of incore; thermocouple operability during a dual train decay

heat system outage.

Tours of;the auxiliary, reactor, and turbine buildings, including

exterior areas, were made to assess equipment conditions and plant

-conditions.

Also the tours were made to assess the effectiveness of

radiological controls and adherence to regulatory requirements.

The

inspectors ~also observed plant housekeeping and cleanliness, looked for-

potential fire and safety hazards, and observed security and safeguards

practices.

The following activities were followed up by the . inspector:

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a.

Loss of S]A inverter causing the loss of Safety Features Activation

System (SFAS) channel and Reactor Protection System:(RPS) trip.

No

abnormal system response was observed,

b.

Unexplained wire cutting in the 480 volt west switchgear room on

April 27, 1987, affecting SFAS valve SFV-25003, "A" train Borated

Water Storage Tank (BWST) suction to High Pressure Injection / Low

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Pressure Injection (HPI/LPI) header.

Thfs occurrence'is still under

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review and will be further documented in subsequent inspection

reports.

c.

Dual train decay heat system outage (continuous through. inspection

period).

In discussions with licensee management, the inspector expressed

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concern during the common decay heat system train outage about'the

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use of the plant 4 KV bus for load testing.. The inspector was,

concerned'that the testing might' jeopardize the' availability of both

redundant. electrical trains during the common decay heat :,ystem

outage.

Licensee representatives explained that adequate isolation

and protection was established during the conduct of the testing to

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preclude impact on the reliability of electrical power during the

outage.

The inspector concluded this explanation was satisfactory,

d.

Geological review by NRR consultant of foothills fault region on

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May 7, 1987.

No conclusions were reached by the inspector during

this review.

e.

Health Physics Drill on May 7, 1987.

During this drill, the

inspector observed as many as twenty-six people. in the control _ room;

These people were involved with Emergency Feedwater Isolation and-

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Control (EFIC) installation, operator requalification testing, and

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the drill.

The inspector brought to the plant manager's attention

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that-the amount of people present in the control room needed to be

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better controlled, and that a. crowded control could make the

operators duties of monitoring the plant very difficult.

The plant

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manager agreed with these observations and stated that appropriate

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steps will be taken to prevent this type of overcrowding from

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occurring in the future.

3.

Monthly Maintenance Observation

Maintenance activities for the systems and components listed below were

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observed and reviewed to ascertain that they were conducted in accordance

with approved procedures, regulatory guides, industry codes or standards,

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and the Technical Specifications (TSs).

The following items were considered during this review:

The limiting

conditions for operation were met while components or systems were

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removed from service; approvals were obtained prior to initiating the

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work; activities were accomplished using approved procedures and were

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inspected as applicable; functional testing or calibration was performed

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prior to returning components or systems to service; activities were

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accomplished by qualified personnel; radiological controls were

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implemented; and fire prevention controls were implemented.

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a.

Transamerica Delaval Diesel (TDI) Load Testing

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On May 6, 1987, the inspector observed a brace on the "A" and "B"

TDI diesel generators. . Licensee personnel explained that the brace

had been temporarily added during acceptance testing to reduce

unacceptable turbocharger vibration during TDI operation.

However,

the analysis of the effect of the brace on the turbocharger during

operation could not be retrieved by the licensee or the vendor

during this inspection.

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The inspector was concerned that acceptance testing was being

conducted without the diesel generators being in their_ final

configuration prior to turnover to operations.

Furthermore, the

inspector questioned the licensee as to the deportability of the

turbocharger vibration problem under 10 CFR 21.

The licensee

acknowledged the inspector's concerns and indicated that both issues

would be addressed in the evaluation of the permanent brace to be

installed prior to turnover to operations.

b.

QCI-12 Prioritization Review

As part of the licensee's Performance Improvement Program, QCI-12,

entitled Plant Performance and Management Improvement Program, was

established to investigate, validate, approve, implement and close

recommendations for performance improvement.

As part of the

validation phase, the Recommendation, Review and Resolution Board

(RRRB) forwards validated recommendations for specific systems to

the Systems Engineer to determine its priority using the following-

criteria:

Priority 1 - Restart

Actions to be initiated and' completed prior to restart on

completion of the Restart Test Program to,

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(1) assure plant remains in' post-trip window,

(2) assure compliance with TSs, and

(3) minimize the need for operator' action outside the control

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room within the'first,10 minutes of an event.

Priority 2 - Near Term

Actions to be promptly initiated but not necessarily completed

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prior to restart to,

(1) enhance ability to remain in post-trip window,

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reduce reactor trips,

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(3) reduce challenges to safety systems,

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(4) produce near-term programmatic benefits.

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Priority 3 - Long Term

Actions not to be initiated prior to restart to,

(1) improve reliability,

(2)

improve availability,

(3) major programmatic enhancements.

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The Pe~ ormance Analysis Group (PAG) reviews, and approves the

priority for scheduled implementation of each item.

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The Implementation Group assigns a Work Request priority designator

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of "006" for Work Requests to be completed prior to restart and

"000" for non-restart Work Requests.

All Priority 1 items resulting

from the QCI-12 process are designated as 006 Work Requests.

Work

requests written subsequent to the QCI-12 process are evaluated by

Implementation to establish the restart priority.

The inspector reviewed the status of the current backlog of

corrective maintenance Work Requests (CMWRs) to determine the

prioritization criteria.which the licensee established for working

off the backlog prior to restart.

The inspector found that a total

of approximately 4000 work requests were currently open including

not only individual deficiencies requiring corrective maintenance,

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but also associated support activities, preventative maintenance,

modifications and general facility work activities.

Of the 4000

Work Requests, the licensee. estimated that 2000 Work Requests were

corrective maintenance activities, with 1150 ~ of them prioritized for

completion prior to restart.

The licensee currently reviews the

remaining 850 non priority Work Requests for performance within the

clearance boundary. established for scheduled priority work and

includes the feasible non priority Work Requests within the work

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schedule.

The inspector determined that the licensec wes unable to

specifically identify which non priority Work Requests would not be

completed prior to restart.

Furthermore, the criteria for selection

of non priority work requests for work off prior to restart was not

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proceduralized with either the licensee's QCI-12 process or AP.3.

As a result, the inspector was unable to evaluate the

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appropriateness of the non-restart Work Request backlog.

The inspector brought these weaknesses to the attention of licensee

management who acknowledged the need for additional clarification

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and . identification of the CMWRs backlog.

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This issue will be addressed in future inspections of the licensee's

maintenance activities prior to restart.

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c.

Concentrated Boric Acid Storage Tank (CBAST)

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On April 22, 1987, the inspectors were informed of the draining of

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19,000 gallons of liquid from the CBAST.

The leakage appears to

have occurred from the drain of the CBAST filter which had been

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connected by temporary plastic tubing to the floor drain near the

filter.

The floor drain drained into the radwaste sump and the

water from the sump was then pumped to the spent regenerative tank.

The inspector reviewed the auxiliary operators' logs for the period

of April 13, 1987, to April 21, 1987, for the CBAST level.

The

inspector identified missing information on the CBAST level for one

shift on April 13, 1987, and one shift of April 21, 1987, and could

not locate the entire log for the day of April 17, 1987.

It was

identified that the CBAST level on April 16, 1987 was 11.48 ft on

the first entry and 11.44 ft on the last of the three entries.

No

information was available for April 17, 1987, and on the first entry

for April' 18, 1987, the CBAST level had dropped to 11.00 ft.

The

level continued to drop until April 22, 1987,.when Operations had a

drain valve, BWS-056, closed and stopped the apparent leak pathway.

For a period of approximately five days the operations staff was

apparently unaware of the draining of.the CBAST, even though the

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staff had taken, on each shift, recordings of the CBAST level.

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was evident that the CBAST level recordings were'not being compared

to previous readings, expected values, and were not trended.

The inspector's investigation into the draining of water from the

CBAST tank did not identify whether or not there was a continuous

draining of water from the CBAST tank through the CBAST filter drain

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into the radwaste system.

However, the licensee did identify the

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CBAST draining problem from the trending of the liquid waste sump

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pump operating times.

The licensee has begun an Incident Analysis

Group (IAG) investigation of the incident.

The licensee committed

to make the inspector aware of their findings and the inspector will

review the licensee's corrective actions during the followup of the

violations discussed below.

The licensee identified that the only work performed on the CBAST

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during this period was a CBAST filter replacement and the

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installation of a temporary cleanup demineralized.

In reviewing the

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Work Request for these two items, two apparent violations of work

control procedures were identified:

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Work Request #125548, "CBAST Filter F-711," directed work to change

out the filter element from.the CBAST filter.. The filter.is

identified as a Quality Assurance (QA) Class.1 piece of equipment

and the Work Request form was marked QA Class 1.

10 CFR 50 Appendix B, Criterion VIII, " Identification and Control.

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of Materials, Parts, and Components,"' states, in part:. " Measures.

shall be established for the identification'and control of-

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materials, parts, and components....These. identification and control

measures shall be designed to prevent the use of incorrect or

defective material, parts, and components."

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In addition, QA Procedure 6, Revision 3, "QC Inspection," states, in

part: ." Class 1, EQ and commercial grade items shall-be released-

from the warehouse only if they have 'SMUD ACCEPT l tag unless

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otherwise exempted per paragraph 5.6."'. Paragraph.5.6 states that

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the Quality Manager shall issue a list of items which are exempt

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from the "SMUD ACCEPT" tag policy.

AP.605, Revision 12, " General Warehousing," states, in part 3.5.2.1:

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"Any item released from the warehouse for Class.l.and EQ use. shall

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have a SMUD Accept Tag (shown in QAP-16) installed by QC.

Note:

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" Exempt Items, as determined by QA, are excluded from this

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requirement."

On April 9,1987, under Work Request #125548, the replacement filter

element was issued out of the warehouse without.a SMUD ACCEPT tag.

After the filter element had been issued, it appears licensee

discussions occurred on whether it was acceptable to install the

. filter element, without the SMUD ACCEPT. tag, into the CBAST filter

housing.

The work request' continuation form for Work Request #125548 documents a telecon from a maintenance engineer

authorizing to "...use a filter element not Green Tagged for CBAST

filter per telecon 4/11/87."

Administrative procedure, AP.605, " General Warehous'ing," Revision 3,

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Section 3.5.5, " Items Without SMUD ACCEPT Tag and Not Inspected

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Using RIDR (Receipt Inspection Data' Report)," states, in part:

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" Procurement Engineer shall prepare a RIDR..-..The Item shall'then be

receipt inspected....If the: item is acceptable, QC shall put SMUD

ACCEPT Tag on the item....If the item is unacceptable, QC shall

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place a Hold Tag (in accordance with QAP-16) on all items inspected

on the RIDR.

Warehouse is responsible to keep the item'in

quarantine until the item is. removed from Rancho:Seco or until means

are established to segregate the' items from those designated'for

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Class 1 or EQ use...."

QA procedure, QAP.17, " Nonconforming Material Control," Revision 5,

Section 4.4, " Conditional Release," states, ~1n part:

"An item

identified as nonconforming by NCR may be conditionally released for-

installation and testing, provided it is stipulated that the item-

may not be put in service prior to closure of the NCR."

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Contrary to the above, on April 9, 1987, under Work Request #125548,

replacement filter element (stock code number #005617) was issued

without a SMUD ACCEPT tag and on April 11, 1987, the replacement

filter element, stock code #005617 for the CBAST filter F-711 was

installed without the appropriate SMUD ACCEPT tag, a RIOR or an NCR.

This is an apparent violation (87-13-01).

The inspector also observed Technical Specifications Section 6.8,-

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" Procedures," requires, in part:

" Written procedures shal be

established, implemented and maintained covering the acti' 't e3

referenced below:

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The applicable procedures recommended in Appendix "A'

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Regulatory Guide 1.33, November 1972."

Regulatory Guide 1.33, November 1972 requires, in part:

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Procedures for Performing Maintenance.

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Maintenance whnh can

affect the performance of safety-related equipment should be

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properly preplanned and performed in accordance with written

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procedures."

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In addition, Plant Maintenance procedure M.114, " Maintenance

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Cleanliness Control," Section 3.0, " Limitations and Precautions,"

require, in part that:

"3.1

This procedure shall be used when

opening any portion of the following systems...BWS (Borated Water

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System)....Use of this procedure is not required for activities such

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as replacing filter elements...provided that the component and area

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cleanliness and the replacement part/ parts cleanliness as detailed

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by the Cognizant Engineer is verified by an authorized Inspector's

signature on the Work Request."

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Contrary to the above, Work Request #125548 was written for

replacement of a filter element in the BWS system and the additional

provisions of procedure M.114 were not implemented which required

inspections for area cleanliness and an authorized inspector's

signature on the Work Request.

This is an apparent violation

(87-13-02).

d.

Control of Maintenance Tools, Wooden Support

On April 13, 1987, the inspector identified a wooden support bracing

the nitrogen supply line to the Condensate Storage Tank.

No

markings or tags existed on the support and no apparent work was

observed in progress.

The inspector brought the support to the attention of various

licensee managers and requested an explanation of why the support

was installed and what administrative controls were associated with

it.

No licensee representatives were able to clearly explain the

origin of the support.

The support was later removed.

After further inspection, the inspector located a Work Request #119506 which replaced a nitrogen supply pressure regulator on the

nitrogen line.

This work was performed on March 5, 1987.

Licensee

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personnel stated that on this job, the maintenance crew placed the

support under the nitrogen line during the work activity and did not

remove the support when the work was completed.

The job was

inspected by the licensee on March 6, 1987, and that inspection also

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failed to identify the support for removal.

The inspector discussed

the principle that if the work required the installation of

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temporary supports, the work control package should have a method to

identify the items for removal after the job is completed.

Licensee

representatives acknowledged these comments at the Exit Interview.

The inspector also identified some drawing discrepancies in the

isometric drawing 35890-2-HE for the nitrogen supply line.

These

discrepancies made it difficult to correctly delineate the Class 1

and Class 2 portions of the piping line.

However, the Master

Equipment List (MEL) did correctly identify the quality

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classification.

The licensee committed to clarify the plant

drawing.

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e.

Nondestructive Testing Records Review (Spent Fuel Pool)

The inspector reviewed work associated with the licensee's

examination of welds of the spent fuel pool liner.

This work was

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part of the licensee's effort to locate and identify areas of

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leakage in the spent fuel pool liner,

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Work Request #131557 was written for Mechanical Maintenance to

" support QC for the PT (liquid penetrant test) of the spent fuel

pool liner welds above the water level." The Work Request was

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written for the equipment identification of SFC-3, meaning spent

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fuel cooling system, Quality Class 3.

However, the inspector

identified that the liner was actually classified as QA Class 1 as

denoted on SMUD Drawing C-613.

The liner was not identified on the

licensee's MEL which is normally referred to by the licensee for

equipment identification and classification.

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A liquid penetrant test (LPT) was performed by the licensee on

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March 26, 1987, on accessible welds of the spent fuel pool liner.

Work Request #131557 was written only for craft support of the LPT

and not to control the test.

The inspector noted that the licensee procedure, NDEI #8, " Liquid

Penetrant Examination Requirements," established the' method and

criteria for liquid penetrant examinations.

However, no work

control document was written that referenced the NDEI #8 procedure

or that referenced the qualitative or quantitative criteria to be

used for the LPT process.

10 CFR 50, Appendix B, Criterion IX, " Control of Special Processes,"

states, in part:

" Measures shall be established to assure that

special processes, including ... nondestructive testing, are

controlled and accomplished by qualified personnel using qualified

procedures in accordance with applicable codes, standards,

specifications, criteria, and other special requirements."

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QA Policy Section IX, Revision 0, " Control of Special Process,"

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states in part:

" Appropriate procedural methods shall be prescribed

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and implemented to assure tnat special processes, equipment and

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personnel are controlled and accomplished by qualified personnel and

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procedures."

Contrary to the above, the liquid penetrant test, a special process,

performed on the Spent Fuel Pool Liner was not controlled by a work

document or procedure which included the appropriate quantitative or

qualitative acceptance criteria for determining that important

activities have been satisfactorily accomplished or other special

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requirements.

This is an apparent violation (87-13-03).

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The inspector also reviewed QA Surveillance #859 which stated in the

summary section that the PT examination of the liner was performed

per NDEI #8, "for information only."

The inspector observed that

the weld would have been rejected if the NDEI #8 acceptance criteria

had been applied.

However, the QA surveillance concluded that the

process was performed "in an acceptable manner." The inspector

brought to the attention of the licensee the need to be more

thorough in their surveillance.

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4.

Monthly Surveillance Observation

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Technical Specification (TS) required surveillance tests were observed

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and reviewed to ascertain that they were conducted in accordance with

these requirements.

Tle following items were considered during this review:

Testing was in

accordance with adequate procedures; test instrumentation was calibrated;

liaiting conditions for operation were met; removal and restoration of

the. affected components were accomplished; test results confirmed with TS

and orocedure requirements and were reviewed by personnel other than the

individual directing the test; the reactor operator, technician or

engineer performing the test recorded the data and the data were in

agreement with observations made by the inspector, and that any

deficiencies identified during the testing were properly reviewed and

resolved by appropriate management personnel.

Portions of the following tests were observed by the inspectors and D.

Baxter, NRC consultant:

STP-1057 8 - Component Cooling Water Performance Test

STP-1009 A - New Diesel Generator GEA2 Engine Integrated System

Phase 2 Testing

The following test outlines were reviewed by D. Baxter, NRC consultant,

and the inspectors:

STP.1064 A,B,C

Waste Water Disposal System Operational Test

RT-RCS-002

Refueling Outage RCP Failure (Undercurrent) Relay

Test

STP.983

Plant Phone Appendix R Upgrade

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STP.433

Post Accident Sampling System RCS Sample Functional

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Test

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SP-485A/SP-485B

Refueling Interval Control Room / Technical Support

Center Essential Filtering System Train "A"/ Train

"B" Surveillance

STP.10338

DHS Pump P-261B Performance

STP.1033A

DHS Pump P-261A Performance

STP.1065 Rev 1

Flow Path Verification of the Waste Water System

Piping Modifications

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STP.984-

UHF Radio Modification

STP.1020

Main Feed Pump Protection Test

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STP.666

EFIC Cold Functional Test

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STP.778

Integrated Control System Functional Test

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Special Test Procedures

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The following STPs were reviewed by the ir.Jpectors and D. Baxter, NRC

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consultant:

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STP.1074A Rev 1

Demonstration of Alternate Decay Heat Removal Methods

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STP.977

4160 VAC Bus 4A Isolation Control Switch Test

STP.978

4160 VAC Bus 4A2 Isolation Control Switch Test

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STP.792

"A" HPI Pump Lube Oil Modification Test

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STP.432

Post Accident Sampling System Gaseous Functional Test

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STP.787A

SFAS Analog Channel "A" Module Removal Interlock

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Verification

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STP.1071

Post Tie-In Functional Test of the Diesel Driven Air

Compressor with a Gradual Loss of IAS

STP.979

480 VAC Bus 3A2 Isolation Control Switch Test

STP.980

4160 VAC Bus 4A2 Load Shedding Isolation Control

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Switch Test

STP.1075

Diesel Driven Air Compressor Fire Suppression Sys.

Functional Test

STP.981

4160 VAC Bus 4A Load Shedding Isolation Control.

Switch Test

STP.1049

HV-26007 Differential Pressure Stroke Test

STP.1050

HV-26008 Differential Pressure Stroke Test

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STP.1027

Auxiliary Feedwater System SRS to AFW Suction Flow

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Test

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STP.970

Diesel Generator (G-886A) Synchronization Check Relay

Functional Test

STP.1032

Nuclear Service Cooling Water (NSCW) Component Flow

Verification

STP.7878

SFAS Analog Channel "B" Module Removal Interlock

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Verification

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STP.787C

SFAS Analog Channel "C" Module Removal Interlock

Verification

STP.1040

Turbine Bypass Valve Cold Functional Test

STP.790

RPS Module Removal Interlock Verification

No violations or. deviations from NRC requirements were identified.

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5.

Review of Problem Statement Prioritization (0 pen)

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Action Plan Prioritization Review

The inspector reviewed the licensee's " Action Plan for Performance

Improvement" and the System Status Report (SSR) for the Nuclear Service

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Cooling Water System and sampled approximately thirty problem statements

contained within those documents for acceptability as a post-restart

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item.

The inspector's criteria for acceptability as a post-restart item

was whether all regulatory requirements related to the item would be met

even if the item were not performed prior to restart.

The Action Plan used three priorities for classification of items.

The

priorities were implemented as follows:

Priority 1 is a restart item,

Priority 2 is a near-term item, and Priority 3 is a long-term item.

The

licensee has committed in the Action plan to complete all Priority 1

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items prior to restart.

The inspector reviewed various Priority 2 and 3

items identified in the licensee's Action Plan and SSR.

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a.

The licensee had difficulty in providing a package that encompassed

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the item.

For example:

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(1) Some items had no QCI-12 reference number, (4B.9.2.3,

4B.12.2.1, 4B.12.3.1, 4C.1.f.1.d)

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(2) Some of the QCI-12 referenced items provided by the licensee

for the Action Plan items did not correlate.

(4B.12.3.3 was

not applicable to QCI-12 #20.04.52, 4C.2.a.1.c.3 was not

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applicable to 15.0426.A.)

(3) Some of the Action Plan items appeared to involve many QCI-12

items as references.

(4.B.2.3.1 was referenced to QCI-12 #(S)

20.0112, 20.0127, 20.0351, 20.0393, 20.0411, 21.0050.C,

21.0082, 21.0089, 21.0182, 26.0688, and 26.0689.)

These problems made it difficult to audit the priority

classifications, and to determine what actions will eventually

be needed to close the item,

b.

The inspector reviewed Action Plan Item #4c.12.2.1, titled:

" Engineering is to review design philosophy for suction valve

interlocks and alarms on critical pumps and identify appropriate

modifications, QCI-12 #15.0070," a Priority 1 item.

The inspector

concluded this item was properly prioritized.

This item, however, contained an apparent typographical' error in

that the PAG minutes of 86-047 had assigned a priority of 2 but the

QCI Tracking System improperly recorded the priority for this item

.as 1.

This discrepancy had already been identified by the licensee

and corrected on the data base.

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The inspector's concern with the typographical error is that within

the licensee's tracking system, identified problem statements are

grouped together based on problem subject.

In this review, Item

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1. 15.0070 (discussed above), which is called a " Valid Item," is the

lead item of the group which also includes the following items:

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15.0071, 15.0072 and 16.0002.B which are called " Valid Covered

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Item." The tracking system would then track the group of items

(15.0070, 15.0071, 15.0072 and 16.0002.B) by the Valid Item,

1. 15.0070, i.e., these items were " covered" by Item 15.0070.

All of these items dealt with the loss of the makeup pump during the

December 16, 1985 event when water supply was secced, and with

assuring uninterrupted water supply to the makeup pump.

The inspector noted that, in this case, when the lead item of the

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group was changed from Priority 1 to 2, when the typographic error

was identified and corrected, all other items associated with the

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lead item were similarly changed (in effect).

The lead item, which

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was now a Priority 2 became a post-restart item along with its

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associated higher priority items.

When these grouped items are

recalled from the tracking system, the lead item which is a Priority

2 would not be required to be completed prior to restart.

The

associated items involved here were all classified as Priority 1.

The licensee had identified this anomaly concurrently with the

inspector and has discussed the need for a program to review and

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correct errors which may exist in the QCI-12 Tracking System.

The

licensee stated at the May 29, 1987 exit meeting that this program,

called the True Up Program, was in the process of being implemented.

The inspector will continue to monitor the program.

c.

The inspector reviewed Action Plan item 4.B.10.2.2, " Implement

Vendor Data Program, enhancements identified to achieve the program

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objectives (Priority 2) QCI-12 #21.0267," and referenced QCI-12 item

(21.0267).

The inspector first found that 21.0267 was a Priority 3

item even though the Action Plan item was listed as Priority 2.

The

licensee was unable to identify the cause for this inequality.

)

The licensee's input for QCI-12 #21.0267 consisted of various

1

licensee personnel interviews, during the interview process of the

QCI-12 programs.

A review of the interviews indicated an

insufficient vendor material control program which could possibly

provide inappropriate information for maintenance and surveillance

procedures and therefore potentially affect the operability of

various plant components and systems.

The licensee was requested to provide their justification for

determining that this item does not have to be completed prior to

restart.

d.

In discussions with the licensee, the inspector identified that

there remain approximately 850 items that have been identified but

have not gone through the PAG review process.

Of these there were

approximately 100 proposed Priority 1 items. The inspector

determined that the licensee had not yet developed a process that

would enable a valid Priority 1 item to be included in the written

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system status reports which'are used for, among.other uses, the

development of the' system functional tests.

Nuclear Service Cooling Water System (NSCW) Status Report Review.

The inspector noted that the NSCW system status report. identified-

eight problems, of which one was to.be corrected prior to restart,

,

one was determined invalid, one was' considered a Priority 2 item and

the remaining five were Priority 3.

The item that was determined to

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be Priority 1 entailed fifteen Work Requests that were to be

completed prior to startup.

The Priority 2 item dealt with three

Work Requests identified on the open Work Request list that were

considered Priority 2, and one Priority 3 item dealt with fourteen

Priority 3 Work Requests.

The priority classification of Work

Requests is reviewed in Section 3 of this report.

The remaining

Priority 3 items appeared to be appropriately classified.

The inspector was concerned that NCR 5-3709 (dispositioned in 1984)

had not been closed and had been classified as Priority 3 (long-term

resolution). .The inspector questioned a QA representative who

agreed to determine why the NCR had not been closed.

This will be'

inspected in a-future inspection.

6.

NRC Open Items

Deviations

86-07-10 (Closed) " Control Cable Shielding Not Protected At Underground

End"

The remaining issue for closeout of this deviation was a licensee

reinspection walkdown and rework, as necessary, of suspect cables

identified by the Bechtel Power Corporation.

The licensee's Quality

Control (QC) and Electrical Maintenance personnel completed walkdowns.of

the 188 cables identified by Bechtel and discovered nine instances where

ground shield terminations were uninsulated. The licensee initiated work

requests to rework the terminations and expected completion within.a

month.

Based on the licensee's walkdowns and initiation of corrective

actions, this item is closed.

86-07-10

Enforcement Items

83-34-03 (Closed) " Failure to Follow Abnormal Tag Procedure"

This violation was for the improper closeout of two abnormal tags.

In

response, the licensee reinstructed maintenance personnel on the

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requirements of AP.26 " Abnormal Tag Procedure" and verified the status.of

all abnormal tags existing at'that time.

Subsequently, the' licensee

revised AP.26 to include monthly reviews by responsible departments to

ensure the up-to-date status of all abnormal tags. .The inspector

reviewed AP.26 and, on 'a sample basis, abnormal tag reports, monthly

review reports, and abnormal tags in.the field.

The inspector concluded.

that this item was resolved and closed.

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However, the inspector noted that there were 133. abnormal tags issued for-

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over one year that were still in use and that'some had been issued as far

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back as 1982.

At the exit meeting, the inspector raised this concern to.

the licensee and questioned the' temporary nature of. the tags.

The

licensee responded that they have improved the abnormal tag procedure to

include supervisory reviews of the tags and are currently in the process

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of reviewing the. outstanding tags with a goal of significantly reducing

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the number of tags by restart.

86-30-05 (Closed) " Failure to Maintain Radiograph Records"

The. licensee used a radiograph taken for "Information Only" as a basis

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for. determining Decay Heat Removal (DHR) pipe thickness and did not

retain these records as required by their 0A program.

!

As a result of.this occurrence, the licensee revised Nuclear Engineering

Procedure, NEP 4106, section 5.2, to add.the requirement that all input-

.

data for engineering calculations be from approved district procedures

and that documents stamped "Information Only" shall not be used in

developing calculations.

This procedural change should prevent a

recurrence of this problem as the approved procedures'would ensure that

required data be retained.

This item is. closed.

86-30-06 (Closed) " Improper Method of Determining Pipe Thickness"

The licensee agreed that the method of radiography that they used to

determine the DHR pipe thickness was.not proper and stated in a letter to

the NRC dated November'26, 1986 that in the future they would use only,

approved.and qualified procedures employing ASME accepted-techniques for

the determination of pipe wall thickness.

The licensee also reviewed 200

of 3659 NCRs written during the past 5 years to determine if a radiograph

had been used to determine pipe adequacy.

No additional examples were

found.

This item is closed.

Followup Items

85-04-02 (0 pen) " Licensee Review and Verification of Past Commitments and

Design Implementation"

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This item was previously reviewed in IE report number 50-312/86-38.

The

remaining open issue was the implementation of a' procedure to identify

,

and assure completion of all prior commitments made by the licensee.

The licensee was in the process of creating a Commitment Management

Program which included a procedure to followup on past commitments.

Completion of the procedure was scheduled for July 1987.

This item will

remain open pending NRC review of the completed procedure.

85-36-01 (Closed) " Fire Protection Administrative Procedures"-

The licensee,.in August of 1985 for the'10 CFR 50, Appendix R inspection,'

had available copies of revised fire protection' program administrative-

procedures which had not completed the review process.

The-. inspector

noted that these procedures had not been approved on January 16, 1986.

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The inspector reviewed a sampling o'f the revised fire protection

administrative procedures consisting of AP.29, AP.63, AP.18, AP. 34A and

AP.60.

The procedure revisions were all effective in the May - June'

timeframe of 1986.

The inspector, while reviewing these procedures,

noted no deviations from the guidelines given in the Standard Review Plan

(SRP) Section 9.5.1.

This item is closed.

86-13-02 (0 pen) " Lack of Proper Corrective Actions When Identified Valves

Not on P& ids"

One'of the corrective actions the licensee performed due to the.

October 2,1985, cooldown event was .to walkdown sixteen important to

safety and non-safety-related systems and identify any configuration

discrepancies;'for instance, valves ~in the as-built systems but not on

the Piping and Installation Diagrams (P& ids) for'the systems.

,

Subsequently, the licensee identified discrepancies which were not found

during the walkdowns.

This item was initiated to follow the licensee's

actions in response to the identified discrepancies and. remained open

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-pending the licensee's review of the:new discrepancies a more generic

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review of the actions taken subsequent to the' sixteen system walkdowns,

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and verification that the findings have been incorporated into the

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configuration control system.

In response to this item, the licensee initiated a program to walkdown

selected important secondary systems for valve inconsistencies.

This

program was defined in procedure AP.73, " System, Print, Valve Lineup

Verification Program," and included. thirteen of the sixteen systems

identified.in the October 2, 1985, " Action Plan." Discrepancies'

identified under this program were documented by nonconformance, reports

(NCRs) to incorporate the findings into the' configuration control system.

This program included the depiction of root valves andLinstrument

isolation valves on the P& ids,-which previously were not included.

The-

licensee utilized the system walkdown effort to' add these. valves. to the

system' lineups. 'At.the time of this inspection the licensee had

completed the walkdowns but had not incorporated.all of.the findings into

the P& ids and procedures.

The remaining three systems identified in the " Action Plan," but not

covered by the AP.73 program, were included in a separate system

verification program to be completed by the licensee.

This program is

defined in procedure AP.93, " System Status and. Investigation Reports,"

which includes system walkdowns to ensure conformance to design drawings.

.

From discussions with licensee personnel, review of controlling

procedures and associated documentation, and review.of the licensee

progress to date, the inspector concluded the following:

The licensee reviewed the discrepancies, involved with this item'and

completed corrective actions; including revisions to the P& ids;

The licensee has established programs to ensure that any

discrepancies, which were not identified during the original sixteen

system walkdowns, are identified-and incorporated into the

configuration control system; and

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This item will remain open pending verification that the findings

from the walkdowns have been incorporated into the P& ids and

applicable procedures. The licensee has planned to complete the

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AP.73 program prior to restart.

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Generic Letters

85-06 (Closed) " Quality Assurance Guidance for ATWS rouipment That is not

Safety-Related"

On June 1,1984, the Commission approved publication of a Final Rule,

10 CFR 50.62, regarding the reduction of risk from anticipated transients

without scram (AfWS) events for light-water cooler' nuclear power plants.

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Section 50.62(d) required that each licensee devo or and submit a

proposed schedule for meeting the requirements of the rule with 180 days

after issuance of QA guidance. Scheduled implementation was to be no

later that the second refueling outage after July 26, 1984. On

February 24, 1987, the NRC extended the deadline for implementation to

no later than the third refueling outage after July 26, 1984. This

Generic Letter (GL) was issued April 16, 1985 to provide the QA guidance

for non-safety-related equipment encompassed by the rule.

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The licensee providad their initial response on September 30, 1985, and

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stated that the modifications could be completed by the cycle 9 outage

which is the third refueling outage after July 26, 1984. This schedule

was consistent with the new NRC implementation date. The licensee's

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design for the ATWS modifications was to be based on the Babcock and

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Wilcox (B&W) Owners Group ATWS Standing Committee generic design basis

which was undergoing NRC review for acceptance. The licensee committed

to submit the plant specific design description within six months after

completion of the NRC review.

The inspector verified that the licensee's review and response to this GL

was adequate and timely. Therefore, this item is closed.

Information Notices

IN-85-23 (Closed) " Inadequate Post Modification and Post Maintenance

Testing

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The Information Notice addresses inadequate component testing after

modification or maintenance. As a part of the restart effort, the

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licensee has established the System Review and Test Program. This

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program includes a multi-discipline, multi-level review of testing by

individuals experienced in different aspects of testing. A major

objective of this program is to develop and implement a test program to

_

adequately demonstrate system and component functions important to the

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safe operation of the plant. This program appears to address the

)

concerns identified by the Information Notice. This item is closed.

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IN-85-91 (Closed) "EDG Load Sequencers"

The licensee received this Notice and conducted an analysis to determine

if they were susceptible to the same type concern described in the

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Notice, i.e., that a single failure could result in ESF loads being

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applied as a single block to the EDG's vice being sequenced onto the

Diesel Bus as designed. This event could cause loss of both EDGs. The

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licensee determined that under some circumstance, this event is possible

at their facility. Upon determining that a design problem existed the

licensee issued LER 87-08 on February 13, 1987. .This LER identifies the

problems identified and the solutions proposed by the licensee. Since

the licensee has completed evaluation of the Notice and corrective

actions are to be tracked by the LER, this item is closed.

IN-86-25 (Closed) " Fastener Traceability"

The Information Notice and Supplement i to the Notice describe

traceability problems with bolting materials which have been discovered

at other nuclear power plants. Supplement 1 to the Notice specifically

identifies a problem with SAE J429 GR 8 and 8.2 bolting. The licensee

did not discover, during their records search, that they had ever stocked

these materials.

The original Notice discusses the need to conduct

receipt inspections and to maintain QA traceability records. The

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licensee program does this as part of their QA program.

This item is

closed.

Temporary Instructions

TI 2500/19 (Closed) " Inspection for Unresolved Safety Issue'A-26,

Low-Temperature Over Pressure Transient"

The purpose of this inspection was to verify that the licensee has an

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effective mitigation system for the low-temperature overpressure

,

transient conditions in accordance with their commitments concerning

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Unresolved Safety Issue (USI) A-26.

The background of USI A-26 is that a technical issue was identified

i

concerning the safety margin-to-failure for pressurized water reactors

(PWR) should they be subject to severe pressure transients while at a

relatively low temperature. The majerity of the transients that occurred

'

were during startup and shutdown operations when the reactor coolant

system (RCS) was in a water-solid condition (i.e., no steam bubble

present in the pressurizer to act as a surge volume). During such

conditions, the-RCS is susceptible to a rapid increase in system pressure

through thermal expansion of the RCS water or through injection of water

into the systems without adequate relief capacity or discharge flow path

to control the pressure increase.

Plants receiving an operating license before March 14, 1978, committed to

design reviews, procedure changes, equipment modifications, operator

training, and surveillance using a combination of operator personnel and

automatic equipment.

The Rancho Seco's Low-Temperature Overpressure (LTOP) system design

consists of both an active and passive subsystem. The active subsystem

utilizes the ElectroMatic Operated Valve (EMOV) which provided

overpressure protection during normal plant operation. The EMOV

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actuation circuitry has been modified to provide a second setpoint

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(500 psig) that is used during low-temperature operations. The low

setpoint is manually enabled at 350 F by positioning a key-operated

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switch in the Reactor Control Room. An alarm will sound in the Reactor

Control Room if the reactor coolant pressure falls below 450 psig and the

key-operated switch is not selected for low-temperature operation. After

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selection of low-temperature operation, additional alarms will occur if

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either Seal Injection Flow is greater than 42 gpm or makeup flow is

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greater that 135 gpm; if HPI valves are open; and if the EMOV block valve

HV-21505 is closed.

The passive subsystem is based on the plant design and operating

philosophy that precludes the plant from being in a water solid condition

,

(except for system hydro tests). The Rancho Seco RCS always' operates

with a steam or gas space in the pressurizer; the steam bubble is

replaced with nitrogen during plant cooldown when system, oressure is

reduced. The requirements for a maximum pressurizer level provides for a

sufficient vapor space in the pressurizer to retard the rate of increase

of RCS pressure, as compared to a water solid system for all mass and

heat input transients.

In this manner, the operator will have time to

recognize that a pressure transient is in progress and take action to

mitigate the incident.

For the above reasons the pressurizer water level

will be maintained at or below 220 inches at system pressures above

100 psig.

In conjunction with the enablement of LTOP at 350'F and the subsequent

restriction on pressurizer level, analysis has shown that the HPI system

is not needed when RCS temperature falls below 350 F.

The requirement

for a maximum makeup tank level limits the mass input available from the

tank should the makeup valve fail open.

When the LTOP system is required to be in service, only one of the two

HPI pumps or the makeup pump will be allowed to operate.

Rancho Seco

normally operates with the makeup pump supplying makeup and seal

injection by procedure and by TS. However, in the unlikely event

degradation of the makeup pump should occur while using the the LTOP

system, it would be necessary to start one of the HPI pumps before

stopping the makeup pump. However, because the operator is aware of the

LTOP conditions, it is expecced that this brief transition stage would

not signtficent?y increase the level of the pressurizer and the

probability of an overpre',surization incident.

Separate power supplies are provided for the EMOV circuitry and LTOP

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drains which alert the operator of an overpressurization event so that a

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single power source failure will not disable the EMOV and the LTOP

alarms. These alarms are high pressurizer level, high-high pressurizer

level, and high makeup tank water level. The alarms assure that the

operator is alerted so he can take action to terminate an event even if

the EMOV is disabled.

The inspector reviewed the design of Rancht Seco's LTOP system and

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verified that the system is designed to protect the vessel given a single

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failure in addition to a failure that initiated the pressure transient.

The LTOP system has separate power supplies which prevents a single power

source failure from disabling the EMOV and the LTOP alarms. The;LTOP

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system is designed to prevent exceeding 10 CFR 50, Appendix G limits for

the reactor pressure vessel during plant cooldown or startup, and is not

vulnerable to an event that causes a pressure transient and a failure of

equipment needed to terminate the transient. The inspector reviewed the

licensee's evaluation discussion and correspondence between the licensee

and the NRC which finally supported the conclusion that 500 psig was an

acceptable setpoint. This conclusion was documented in the NRC letter to

the licensee dated February 25, 1985.

The inspector reviewed the Administrative Controls and Procedures for the

LTOP system and determined the following items:

a.

The licensee's procedures allow the plant to be operated only with a

steam or nitrogen blanket in the pressurizer at all times except for

hydrostatic tests. This effectively minimizes the time in a water

solid condition. This is stated in the Operatin

" Pressurizer and Pressurizer Relief Tank System,g Procedure A.3,

in

paragraph 3.1.10.

b.

The licensee's procedures restrict the number of HPI pumps to no

more than one when the RCS is in the LTOP condition. Operating

Procedure B.4, " Plant Shutdown and Cooldown," paragraph 5.28:

provides RCS overpressure protection by tagging out the HPI pumps

and their associated isolation valves.

c.

Licensee operators are alerted since an alarm will sound in the

Control Room if the LTOP system is not enabled or if the PORV

isolation valve is not open when the RCS pressure drops below

500 psig,

d.

Amendment 82 to the TSs provides justification that the

plant-installed system is in accordance with the plant license.

The inspector reviewed the training and equipment modifications

concerning LTOP and determined the following:

a.

All operators as of the time of this inspection had received

training concerning LTOP event causes, the operation and maintenance

of the system that investigates the event and the consequences of

inadvertent actuation. The inspector interviewed the instructors,

examined their lesson plans, and interviewed operators. No problems

were discovered.

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b.

Permanent modifications and procedural changes have been made that

result in a system that provides mitigation for RCS LTOP events. A

permanent second setpoint of 500 psig has been inst lled on the EMOV

Relief Valve, PSV-21511, and procedural changes have been added to

Operations Procedure B.4 to establish RCS overpressure at 350*F and

tag out two out of three HPI pumps, as well as shutting the

isolation valves to the HPI pumps.

The inspector reviewed the surveillance activities associated with the

LTOP system and determined that the EMOV operability test is to be

performed via special procedure SP.90, "Special Frequency LTOP

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Operability Test," which was just being issued at this tise of

inspection. This test will verify EMOV operability prior to cooling the

RCS below 350 F'per the TSs Table 4.1-2, item 15. . Special procedure

SP 200.20 provided EMOV position indicator. calibration once each

refueling interval.

The inspectors' concluded, based on this review, that Rancho Seco 'as'an

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effective mitigation system for LTOP transient conditions in accordance

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with their commitments r.oncerning USI A-26. .TI 2500/19 is closed.

Part 21

85-20-P (Closed) "GE AK and AKP Circuit Breakers"

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The. licensee,:after receiving the Part 21 Report, revised maintenance

procedure, EM 175, " Control- Rod Drhe Low Voltage Power Circuit-

Maintenance,".to include steps to check for and remedy the items listed

in the report beginning in December of 1985. All breakers on site have

been checked for their defects.

This item is closed.

Licensee Event Report (LER)

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LERs 85-01-L2 and 85-01-L3 (Closed) "H

M nitor System Containment

2

Isolacion Valves Found Open for 7 Days

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Revision 3 to this LER identitics that revision 1, which was closed in

inspection report 50/312/86-38, was misnumbered and should have been

Revision 2.

Therefore,IER 85-01-L2 is closed.

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The inspector reviewed revision 3 and verified that the changes were

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non-technical in nature and did not enange the status or significance of

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the event. LER 85-01-L3 is qlosed.

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LERs 85-22-L0 'and 85-22-L1 (Closed) "Open Pressurizer Valve"

The inspector reviewed licensee Operating Procedure A-11, Revision-21,

and verified that 1) Personnel are required to verify that enclosure 8.1,

" Normal Valve Line-11p," is complete prior to sampling, 2) A-11 has been

rewritten and includes specific valves to be manipulated by operators and

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chemists for each sample taken, 3) A-11 now requires the control room to

log-process sample start and stop' times, and 4) A-11 now 1 requires valves

to bel returned to their normal position'and the breaker be racked out and

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verified after completion of sampling.

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The licensee also. issued Special Order 87-1 to remind Operations

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personnel of the requirements and importance of logging valve status.

Licensee Special Order 86-29 was issued tu instruct operators of the

importance of each shift turning over important evolutions to oncoming.

crews.

The licensee has completed their corrective actions to prevent recurrence

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of this event. The inspector concluded that these correctf ve cetions

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adequately addressed this LER. These items are, closed.

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85-32-01 (Closed), LER 85-22 " Root Cause Analysis"

The inspector reviewed LER 85-22 and revisions 1 and 2.

The inspector

then reviewed the root cause evaluation performed by the licensee.

The

evaluation appeared adequate to identify the problems which caused the

event and the recommended corrective measures appeared to be adequate to

preclude a recurrence of the event.

This item is closed.

LERs 85-07-LO, 85-07-L1 and 85-07-L2 (Closed) "41.60 KV Bus Undervoltage

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Relay Setpoints

The inspector reviewed the licensee's root cause evaluation for the

improper relay settings.

The evaluation appeared to be adequate to

determine the cause of the event.

The licensee is making some electrical

circuit modifications to prevent a recurrence of this problem.

Included

in these is a modification to supplement existing inverse relay ITE 27

with an in-line backup ITE 27N which is a definite time relay.

This

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modification is being made to provide a second level of protection and

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enhance system reliability.

The licensee also determined that the

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definite time relay will make unnecessary their proposal to increase

surveillance frequency of the ITE 27 relays.

The licensee is tracking this edification on the restart items list and

is requiring that it be completed prior to plant restart.

The

modifications not yet completed are in ECN-R-1045.

This item is closed.

LER 86-14-L1_fClosed) " Decay i; eat Pump Casing Drain Line Eibow Weld Leak"

Revision 0 to this LER was cl.osed in Inspection Report 50-312/86-07.

The

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inspector reviewed this revision versus the original issuance and

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verified that there were no significant changes to the event description.

This issuance, however, provided a more detailed analysis of the event

and a summary of the failure analysis performed on the event.

This

information was reviewed in the closeout of revision 0.

LER 86-14-L1 is

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closed.

LER 86-15-LO (Closed) "RM-80 Printed Circuit Board Workmanship"

The licensee reported that during cold shutdown conditions on

September 21, 1985, two trace solder pads were dislodged from a printed

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' circuit board during repair'of the Radiation Monitor Computer (RM-80)

communication board for radiation monitor R-15050.

The glued-on solder

pads were dislodged when they were touched with a hot soldering iron,

Glue attachment of tha solder pads is normal technique in the licensee's

General Atomics (GA) circuit boards and is more heat sensitive than would

be expected with a plated attachment.

This finding was considered a voluntary LER because the pads in question

were used as filler only and were not in any circuit on the board.

The

' licensee issued the LER to notify the NRC and other utilities of the.

potential for glued-on solder pads on GA Radiation Monitor circuit boards

to become detached.

Additionally, the licensee determined that this

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radiation monitor was not a basic component as defined in 10 CFR Part 21

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and, therefore, this incident was not reportable pursuant to that Part.

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The inspector verified that the licensee had addressed the work related

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aspects of this incident.

Instrument and Control (I&C) Technicians were

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advised of this problem and training sessions were given to the

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technicians on the appropriate methods and precautions for soldering

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processes.

In addition, the licensee was working on an Electrical

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Standard methods' document and precautions for this incident were to be

added to it.

This LER is closed.

The inspector noted, however, that the licensee had not been in contact

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with the vendor (GA) about the generic aspects of this item.

The

inspector was concerned that other GA monitors in use at the plant could

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be basic components as defined by 10 CFR Part 21 and, therefore, this

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item could be reportable.

This item remained open pending NRC review of

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its deportability in accordance with 10 CFR Part 21.

(0 pen Item

87-13-04).

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LERs 86-21-L0 (Closed) and 86-21-L1 (0 pen) " Failure to Implement

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Inservice Testing of Certain Safety-Related Valves"

The inspector reviewed this LER and verified that it was issued in a

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timely manner and included the required information.

Revision 1 was

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issued, as committed by the licensee, to supplement the original

information.

The revision included 5 additional valves that were

identified during the licensee's corrective actions.

The corrective

actions are in progress and the licensee has committed to complete them

prior to restart.

The inspector verified that the revision included all

information from the original LER and provided the additional information

that they committed to provide.

Therefore, LER 86-21-L0 is clr .ed.

LER 86-21-L1 will remain open to followup on the licensee's corrective

action implementation.

LER 86-30 (0 pen) " Decay Heat System Isolation During Transformer Switch"

The licensee reported that during cold shutdown conditions on

December 8, 1986, a loss of the 4A bus power, attendant diesel generator

start, and DHS isolation occurred during the transfer of the source

transformer.

The cause was attributed to a procedure deficiency along

with less than adequate job preparation by the performing operator.

The inspector noted that the licensee's corrective actions appeared to

address the concerns of the LER.

However, these actions were not

complete at the time of this inspection and only one action was scheduled

for completion by restart.

The inspector noted that, in the LER, the

licensee comnitted to revise procedure A.58, "4.16 KV Electrical System,"

prior to January 17, 1987.

At the time of this inspection, the procedure

revision was still in draft form.

At the exit meeting, the inspector discussed the.importance of meeting

commitment dates and noted that this item was similar to events detailed

in Inspection Report 50-312/87-11.

This item remains open pending the

completion of licensee corrective actions and subsequent NRC inspection.

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Special Reports

83-31-X0 ' Closed) "CBAST Boron Concentration"

On August 22, 1983, the licensee took a boron sample from the CBAST which

exceeded the TS level of 8500 ppm.

The plant operators then added

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1750 gallons of demineralized water to the CBAST. The resultant boron

concentration was 7914 ppm.

It was expected that it would take

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3450 gallons of water to lower the concentration to 8000 ppm. Upon

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further evaluation the licensee determined that the initial boron

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concentration never exceeded 8451 ppm but resulted from inadequate

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mixing, hence the TS limit was not exceeded.

In the LER the licensee did

identify that there was an excessive amount of time from discovery of the

out-of-specification sample until the plant control room operators were

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cognizant of the possible out-of-specification chemistry sample. The

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licensee revised AP.306,Section VIII, to require that chemists report

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immediately to the control room any out-of-specification sample, and when

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a TS or process standard out-of-specification condition exists, to

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require an Out-of-Specification Notice be initiated. This action

appeared to be adequate to prevent a recurrence of this event. This item

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is closed.

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84-03-X0 (Closed) " Defective Switch Jaws"

While performing testing of protective and control relays (EM.144), the

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licensee identified five relays, Westinghouse type MG-6 Relay mounted in

an FT-22 case, with identically defective switch jaws. The licensee then

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examined all Flexitest switch installations on site and found a total of

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9 identical defects out of 235 installations. The licensee then

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discussed the problem with the Westinghouse Coral Springs QA Department.

Westinghouse revealed that this problem had been previously identified,

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that the cause had been determined and that the problem was related to

only those relays with a 1969 production date. The licensee has since

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replaced all relay, with defective jaws and 1969 production dates. This

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item is closed.

84-04-X0 (Closed) "Electromatic Relief Valve Leaking"

On August 7,1984, Electromagnetic Relief Valve PSV-21511 had enough seat

leakage to cause a Pressurizer Safety Valve Open alarm. RCS pressure at

this time was 221 psi. Correspondence with the manufacturer indicated

that this leakage could be caused by pilot valve spring fatigue. The

licensee replaced the pilot valve springs with springs from the

manufacturer which have a higher spring rating and should not leak until

RCS pressure drops to about 50 psi.

This item is closed.

Region V Items

RV-E-13 (Closed) " Examine 03erator Reference to Stri) Charts vs. Safety

Parameter Display Sy* tem (S)DS) for Steam Generator

evel"

This item was previously reviewed in IE report numbers 50-312/86-07 and

87-08.

The remaining open issue was to determine to what extent the SPDS

operating manual contained incorrect information. The issue arose from

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an observation that the SPDS operating manual description of a steam

generator levol algorithm was in error.

The licensee received the

algorithm from a vendor in 1984 and the description was in error at that

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time.

The error was not discovered by the licensee at the time of the

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algorithm implementation.

In February, 1987, the licensee notified the vendor of the manual error

and initiated a change to be completed as part of other SPDS changes for

modifications.

At the time of this inspection, the manual change was in

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draft form pending management reviews.

To assure that other errors did

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not exist in the manual, the licensee contracted to have an inciependent

verification performed on the manual contents.

This review was in

progress at the time of the inspection.

The licensee has committed to

complete the SPDS validation and verification and a detailed acceptance

test on the modifications prior to restart.

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Based on the licensee's actions and the commitments for verification,

this item is closed.

7.

Management Changes

On May 4, 1987, the SMUD Board announced the replacement of John Ward,

Deputy General Manager, Nuclear, by G. Carl Andognini as the Chief

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Executive Officer, Nuclear.

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Exit Meetina

The inspector met with licensee representatives (noted in Paragraph 1) at

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various times during the report period and formally on May 29, 1987. The

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scope and findings of the inspection activities described in this report

were summarized at the meeting.

Licensee representatives acknowledged

the inspector's findings and violations identified.

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