Text

Insp Repts 50-373/85-23 & 50-374/85-18 on 850610-0724 & Enforcement Conference on 850624.Violations Noted:Failure to Have Adequate Operability Test & Failure to Incorporate Design Document Changes Into Site Drawings
	ML20134M816
Person / Time
Site:	LaSalle
Issue date:	08/16/1985
From:	Wright G; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:	;
Shared Package
ML20134M805	List: ML20134M801; ML20134M816;
References
	50-373-85-23, 50-374-85-18, NUDOCS 8509040278
	Download: ML20134M816 (12)
	v • d • e

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U. S. NUCLEAR REGULATORY COMMISSION

REGION III

Reports No. 50-373/85023(DRP); 50-374/85018(DRP)

Docket Nos. 50-373; 50-374 Licenses No. NPF-11; NPF-18

Licensee: Commonwealth Edison Company

, P. O. Box 767

Chicago, IL 60690

Facility Name: LaSalle County Station, Units 1 and 2

Inspection At: LaSalle County Station, Marseilles, IL

Inspection Conducted: June 10 through August 15, 1985

Enforcement Conference At: LaSalle County Nuclear Station

Marseilles, IL on June 24, 1985

Inspectors: M. J. Jordan

J. C. Bjorgen

R. A. Kopriva

Approved By: . igh , Chief 8[/[0[h

Reactor Projects Section 2C Date

Inspection Summary

Inspection on June 10 through July 24, 1985, and Enforcement Conference

on June 24, 1985 (Report No. 50-373/85023(DRP); 50-374/85018(DRP))

Areas Inspected: Special unannounced inspection by resident inspectors of

activities surrounding the inoperability of all three divisions of Emergency

Core Cooling on Unit 2 and improperly piped RHR shutdown cooling isolation

switches on Unit 1. The inspection involved a total of 41 inspector-hours

onsite by three ir.spectors including 11 inspector-hours onsite during

off-shifts. The Enforcement Conference involved a total of 70 hours8.101852e-4 days 0.0194 hours 1.157407e-4 weeks 2.6635e-5 months by ten NRC

personnel.

Results: Nine violations were identified (five - Limiting Condition for

Operations; two - failure to have an adequate operability test; one - failure

to incorporate design document changes into the site drawings; and one -

failure to have inspection activities verify conformance of as-built drawings).

8509040278 850821 7

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hDR ADOCK 05000373

PDR

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DETAILS

1. Persons Attending Enforcement Conference

Commonwealth Edison

B. L. Thomas, Executive Vice President

C. Reed, Vice President of Nuclear Operations

D. P. Galle, Division Vice President and General Manager for Nuclear

Stations

L. O. DelGeorge, Assistant Vice President of Licensing & Engineering

D. Farrar, Director of Nuclear Licensing

B. B. Stephenson, Manager of Production - Nuclear Stations

W. P. Worden, BWR Operations Manager

M. S. Turbak, Operations Plant Licensing Director

G. P. Wagner, PWR Operations Manager

F. A. Palmer, Director of Nuclear Safety

N. E. Wandke, Assistant Vice President - Nuclear Stations

L. F. Gerner, Superintendent - Regulatory Assurance

P. G. Kuhel, RPIP Staff Engineer

W. L. Duke, Administrative Service Director - Nuclear Stations

J. S. Abel, Station Nuclear Engineering Manager

R. F. Janecek, Station Nuclear Engineering, LaSalle Station Project

Engineer

L. W. Rainey, Supervisor, Office of Nuclear Safety, LaSalle Station

E. D. Eenigenburg, Maintenance Manager, Nuclear Stations

R. D. Bishop, Services Superintendent, LaSalle Station

W. R. Huntington, Assistant Superintendent - Operations, LaSalle Station

C. E. Sargent, Production Superintendent, LaSalle Station

D. S. Berkman, Assistant Superintendent, Technical Services, LaSalle

Station

P.~ F. Manning, Technical Staff Supervisor, LaSalle Scation

J. V. Schmeltz, Operating Engineer, LaSalle Station

R. H. Raguse, Operations Engineer, LaSalle Station

W. E. Sheldon, Assistant Superintendent of Maintenance, LaSalle Station

E. E. Boyd, Master Mechanic, LaSalle Station

H. Mulderink, Master Electrician, LaSalle Station

F. W. Baker, Station Construction Site Superintendent, LaSalle Station

R. M. Jeisy, Station Quality Assurance Supervisor, LaSalle Station

NRC Representatives

J. G. Keppler, Regional Administrator

C. E. Norelius, Director, Division of Reactor Projects

N. J. Chrissotimos, Chief, Projects Section 2C

W. H. Schultz, Enforcement Coordinator

E. A. Hare, Project Inspector, LaSalle Station

B. Berson, Regional Counsel

M. Jordan, Senior Resident Inspector, LaSalle

J. Bjorgen, Resident Inspector, LaSalle

, A. Madison, Senior Resident Inspector, Quad Cities

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S. G. DuPont, Regional Inspector

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2. Sequence of Events

On June 10,1985 at 11:30 a.m. , the licensee informed the NRC Resident

, Inspector that for approximately five days Unit 2 had been without

Energency Core Cooling System (ECCS) capability, and that for approxi-

, mately three days during this period the plant had been without secondary

containment integrity.

Unit 2 has been in an outage since February 1985 for installation of

environmentally qualified electrical equipment and perfonnance of the

eighteen month surveillances required by the Technical Specifications.

The following table is a listing of the ECCS sequence of events to install

environmentally qualified switches:

Date Event

March 1985 Division III taken out-of-service

April 29,1985 Division I taken out-of-service

June 4, 1985 Modifications to Division I were completed

(1:00 a.m.) and division declared operable although the

licensee unknowingly had two level switches

piped bac.kwards. (This would have prevented

the Division I pumps from automatically

starting on a low reactor water level signal.)

June 5, 1985 Division II taken out-of-service

(3:30 a.m.)

June 10, 1985 Mispiped switches for Division I identified

(11:25 a.m.) during normal verification of excess flow

check valves prior to leak rate testing.

June 10, 1985 Jumpers installed to trip level switches

(12:10 p.m.) logic for Division I making it operable.

The following table is a listing of the Reactor Building ventilation

sequence of events for a modification:

Date Event

June 3, 1985 System taken out-of-service

(3:30 a.m.)

June 8, 1985 System returned to service

(5:30 p.m.)

The inspectors reviewed the safety-related modification package

(M-1-2-84-136) for the replacement of Barton switches with environ-

mentally qualified (EQ) Static 0-Ring (SOR) switches on Unit 2. Two of

the switches (2821-N037AA and 2B21-N037AB) were discovered, by the licensee

to have been piped incorrectly, resulting in the switches being inoperable.

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The design function of the switches was to provide: a Division I Low

Reactor Vessel Water Level permissive for the Automatic Depressurization

System; initiation for the Low Pressure Core Spray; initiation for the "A"

Low Pressure Coolant Injection System; and a permissive for the Reactor

Core Isolation Cooling System.

The configuration required for the switches to perform their design

function was: the reactor pressure vessel level reference leg piped to

the instrument's high pressure connection, and the reactor pressure

vessel level variable leg piped to the low pressure connection. However,

the reference and variable legs were reversed to 2B21-N037AA and

2B21-N037AB during installation of the modification (M-1-2-84-136).

Technical Specification 3.3.3.b states that with one ECCS actuation

channel inoperable, place the inoperable channel in the tripped condition

within one hour or declare the associated system inoperable.

Contrary to the above, inoperable Channel A went undetected from 1:00 a.m.

on June 4, 1985 until 11:25 a.m. on June 10, 1985 without the channel

being tripped or the system being declared inoperable. This is considered

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to be a violation (373/85023-01A(DRP); 374/85018-01A(DRP)).

Technical Specification 3.5.2 requires at least two Emergency Core Cooling

Subsystems to be operable in the shutdown condition. With no subsystems

operable, one subsystem shall be restored to operable status within four

hours or Secondary Containment Integrity shall be established within the

next eight hours.

Contrary to the above, Unit 2 was without Emergency Core Cooling

capability from 3:30 a.m. on June 5,1985 until 12:10 p.m. on June 10,

4 1985, and without secondary containment from 3:30 a.m. on June 3, 1985

until 5:30 p.m. on June 8, 1985. This is considered to be a violation

(373/85023-01B(DRP);374/85018-01B(DRP)).

The review of the modification revealed that several errors contributed

to the erroneous configuration:

a. Inadequate Control of Design Drawings

The design drawings referenced by modification, M-1-2-84-136, were

initially in error for the reference and variable legs connection

configuration when the modification was released on April 1,1985

to Morrison (contractor) for installation. The error on the design

drawings (Sargent and Lundy drawing M-1303, Sheet 42, General Electric

drawing 12101916TD, and Morrison isometric drawings 2828-NB-062 and

2828-NB-066) was discovered on April 4,1985 by the licensee's site

personnel and corrected by a Field Change Request (FCR 85-123).

Even though the licensee had corrected the configuration error on the

drawings and had included FCR 85-123 as a design drawing, the iso-

metric drawings being used to install the modification were not

corrected. Because the drawings used in the field did not contain

FCR~ 85-123, the configuration of the reference and variable legs was

installed incorrectly.

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10 CFR Part 50, Appendix B, Criterion VI, as implemented by the

licensee's Quality Assurance Manual, Quality Requirement 6.1

states, "A document control system will be used to assure that

documents such as specifications, procedures, instructions, and

drawings are reviewed for adequacy and approved by authorized

personnel...such documents will be distributed to and used at the

locations where the prescribed activity is performed."

Contrary to the above, measures did not assure that the design change

document, Field Change Request 85-123, issued to correct an error in

Modification M-1-2-84-136, was distributed to and used at the location

where the prescribed activities were performed. This is considered

to be a violation (374/85018-01C(DRP)

b. Inadequate Inspection

In addition to the error in the design drawings, the contractor's

quality control did not have inspection hold points for either

electrical or piping connections on any of the 22 instruments

replaced by modification M-1-2-84-136, including 2B21-N037AA and

2B21-N037AB. Because of the lack of witness points, the adequacy of

the installation was not verified against the design documents. Such

a verification could have detected the failure to implement the design

drawing change or the configuration error of the installation.

10 CFR 50, Appendix B, Criterion X, as implemented by the licensee's

Quality Assurance Manual, Quality Requirement 10.1 states, " Quality

Assurance inspection and testing will be conducted....at the site

during.... modification activities to verify conformance to applicable

drawings, instructions..."

Contrary to the above, the program for inspection of activities

affecting quality was inadequate and did not verify conformance of

the M-1-2-84-136 activity to documented instructions and drawings.

This is considered to be a violation (373/85023-01D(DRP);

374/85023-01D(DRP)).

c. Inadequate Modification Test Control

In addition to the problems discussed above, the licensee's opera-

tional function test of the instruments, after the completion of the

modification, failed to detect the inoperability of 2B21-N037AA and

2B21-N037AB. The test performed, LIS-NB-204, only verified the -

permissive and initiation calibration set points and did not

demonstrate the operability of the system in light of the work

actually performed by modification M-1-2-84-136.

The modification had re-routed the reference and variable legs to

the instruments, replaced the instruments with a different manufac-

turer component (Static 0-Ring replaced the initially installed

Barton), and re-connected the electrical connections. The test

functionally verified only the instrument and electrical connections.

In light of the the work actually performed, the piping configuration

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of the reference and variable legs was required to be verified by a

pre-test walkdown. However, the walkdown was not performed. The

licensee stated, in the letter to J. M. Taylor, Director, Office of

Inspection and Enforcement (NRC) from C. Reed, Vice President (CECO)

dated April 19, 1985, that measures had been developed to ensure that

the post maintenance test adequately demonstrates system operability

in light of the work actually performed.

10 CFR Part 50, Appendix B, Criterion XI, as implemented by the

licensee's Quality Assurance Manual, Quality Requirement Q.R.11.1

states, "The (test) program will include ... those tests applicable

involving and following plant maintenance or modifications."

Contrary to the above, the test conducted, after completion of

modification M-1-2-84-136, did not demonstrate system operability

in light of the work actually performed. This is considered to be

a violation (374/85018-01E(DRP)).

The licensee walked down all safety-related systems modified during the

Unit 2 outage to verify that the actual installation matched the planned

modification. Completion of the walkdown on the two Shutdown Cooling

pump suction high flow isolation switches (2E31N012AA, and AB) identified

no problems. After the walkdown, a review of data associated with

excessive flow check valve testing (LISNB-215, performed prior to the

walkdown) identified a problem with the connection of the lines to the

switches. An additional review of the data and a rewalkdown of the

system identified that these two switches were pipe backwards. Technical

Specification 3.3.2 did not require these switches to be operable in

Modes 4 or 5, which the plant was in. However, the walkdown of the

piping system to ensure correct installation was considered part of the

operability test for these two switches; therefore, again the operability

test was not performed satisfactorily. This is considered another example

of inadequate measures to ensure that post maintenance test adequately

demonstrates system operability in light of work actually performed. This

isconsideredaviolation(373/85023-01F(DRP);374/85018-01F(DRP)).

As a followup to these programmatic problems, the licensee initiated a

system operability testing program on Unit 1 for all safety systems

affected by the installation of environmentally qualified instruments.

This testing was initiated on July 16, 1985 while Unit I was in a short

outage for minor valve repairs. The environmentally qualified

instruments had been installed on Unit I during a maintenance outage

completed in April 1985.

On July 17, 1985 the special test (LST 85-88) found that the four Unit 1

shutdown cooling pump high suction flow alarm and isolation switches

(IE31N012AA, AB, BA, and BB) were piped backwards. These switches had

also been previously walked down to confirm that they were piped

correctly. The licensee's investigation determined that the modification

package (M-1-1-84-091) utilized for the switch installation required the

use of drawings that did not reflect the as-built condition of the plant.

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During original Unit 1 construction (May 1982), the flow sensing lines

had been found reversed inside the suppression pool. Rather than reroute

the piping, the licensee exchanged the piping connections at the

instrument rack (modification M-1-1-82-054). A Drawing Change Request

(DCR 7383) was then issued to update the appropriate drawings. Due to an

administrative error, this DCR was closed prior to being incorporated

into the affected drawings. Accordingly, the drawings used to install

the replacement switches per modification M-1-1-84-091 were incorrect.

This is considered another example of inadequate measures to ensure that

a design change document, Drawing Change Request 7383, issued to document

a piping change to Modification M-1-1-82-054 was distributed to and used

in the development of a Modification. This is considered to be a

violation (373/85023-01C(DRP)).

During the review of this event, it was noted that again the post

installation testing, including a system walkdown, failed to identify

that the switch piping was incorrect. This is considered another

example of inadequate measures to ensure that the testing performed,

following the completion of Modification M-1-1-84-091 did not detect that

the RHR pump suction high flow isolation switches were piped backwards

prior to returning the instruments to service. This is considered to be

a violation (373/85023-01E(DRP)).

Since these switches had been piped backwards and, therefore, were

inoperable since the Unit I startup on April 7, 1985, the Limiting

Condition for Operation of Technical Specification 3.3.2 was exceeded.

Technical Specification 3.3.2 requires the isolation actuation

instrumentation channels listed in Table 3.3.2-1 to be operable with

their trip setpoints set consistent with the values in Table 3.3.2-2.

With less than the required number of isolation channels operable,

Technical Specification 3.3.2.c requires that the affected trip system be

placed in the tripped condition within one hour. Action Item 25 of

Technical Specification Table 3.3.2-1 also requires that the associated

valves be locked in the closed position and the associated system be

declared inoperable within one hour. These requirements apply in

Operating Conditions 1, 2, and 3.

Contrary to the above, the actions required by Technical Specification 3.3.2 were not taken when the Unit 1 RHR shutdown cooling pump high

suction flow isolation channels were inoperable from April 7,1985 until

the unit was placed in Cold Shutdown (Condition 4) on July 12, 1985.

This is considered to be a violation (373/85023-02A(DRP)). ,

In addition, since the applicable valves are required for primary

containment integrity, the Limiting Conditions for Operation for the

primary containment were also exceeded.

Technical Specifications 3.6.3 LC0 for primary containment isolation

valves states, in part:

"With one or more primary containment isolation valves inoperable

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a. Maintain at least one isolation valve operable in each affected

penetration that is open and within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months either...

(1) Restore the inoperable valve (s) to operable...

(2) Isolate each affected penetration by deactivating

automatically actuated valves

(3) Isolate each affected penetration by closing manual valves

b. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

and in COLD SHUTDOWN within following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ."

Contrary to the above, with the Group 6 isolation system valves ,

inoperable due to the RHR pump high suction flow isolation not being

operable, the above action was not taken on those valves. This is

considered a violation (373/85023-02B(DRP)).

The plant Technical Specifications also limit plant startup or certain

power changes when otherwise not in compliance with the Tt:chnical

Specifications. Unit I was started up on April 7, 1985 and underwent

several startups and shutdowns until shutdown for maintenance on July 12,

1985. Technical Specification Section 3.0.4, Limiting Conditions for

Operations Applicability states, in par:: " Entry into an operational

condition or other specified condition shall not be made unless the

conditions for the LC0 are met without reliance on provisions contained

in the action requirements."

Contrary to the above, Unit 1 mode changes were made when other LC0 !

requirements were not met. This is considered a violation

(373/85023-02C(DRP)).

Since the plant was operated with the RHR pump suction high flow isolation

inoperble, the shutdown cooling mode was technically inoperable during the

period from startup on April 7,1985 until reaching Cold Shutdown on

July 12, 1985. When in Operation Condition 3 (Hot Shutdown), Technical

Specification 3.4.9.1 requires the shutdown cooling loops to be operable.

Technical Specifications 3.4.9.1 for RHR when in Condition 3 states, in

part:

"With less than the required RHR shutdown cooling mode loops

operable, immediately initiate corrective actions ..... Be in at

least Cold Shutdown within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

With no RHR shutdown cooling mode loop in operation, immediately

initiate corrective action .... Within one (1) hour establish

reactor coolant circulation by an alternate method ....."

The licensee entered Condition 3 for the first time following the Unit I

scram on April 11, 1985. Contrary to the above, each time the unit

entered Condition 3, the shutdown cooling loops were technically

inoperable according to Technical-Specification 3.3.2 and the action

required by Technical Specification 3.4.9.1 was not taken. This is

considered a violation (373/85023-02D(DRP)). i

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The safety significance of this violation was reduced because of the

number of backup isolation signals available to isolate the shutdown

cooling mode of RHR. The redundant isolations include:

a. Reactor vessel level - low, level 3

b. Reactor pressure - high

c. RHR area temperature - high

d. RHR equipment area differential temperature - high'

These redundant signals provide the same isolation function as the

inoperable high flow isolation. This sequence of events, however,

continues to illustrate a breakdown in management controls.

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3. Confirmatory Action Letters

A Confirmatory Action Letter was issued to the licensee on June 17, 1985

stating the action needed to be taken prior to startup and long range

l actions being taken to prevent recurrence of this problem.

The following actions were to be taken prior to startup of Unit 2:

a. Review, for all safety-related electrical and mechanical modifica-

tions, made or planned during this outage, all packages to ensure

that modifications properly implement the design concept and that

drawings to be used by operational personnel- accurately reflect the

modification.

b. Physically walkdown all safety-related systems modified during the

outage to verify that the actual installation matches the planned

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modification. This walkdown is limited to physically accessible

items.

c. Review tests performed on all safety-related systems on which

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modifications or maintenance was performed during this outage to

assure that testing adequately demonstrated operability in light of

the work actually performed. Perform additional tests as required.

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d. Test all level switches, modified during the outage by:

(1) Up to instrument block---vary actual level and verify proper

response to level change.

(2) From instrument block to instrument---physically walkdown to

verify proper alignment for operation.

e. Review all safety-related mechanical and electrical operational

checklists to verify proper alignment of plant systems. This effort

will provide an extra level of assurance on both systems that were

modified and those that were not subject to modification during the

outage.

f. Provide test results, your conclusions, and a sunmary of corrective

actions to the NRC resident office. This action will be followed by

openitem(374/85018-02(DRP)).

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The followup inspection addressing items a. through e. was completed in

Inspection Report 374/85020.

The following actions were also to be taken by the licensee after startup

of Unit 2:

a. Prior to initiation of any further safety-related modifications by a

contractor, review and revise, as required, the current Quality

Control guidance for safety-related modifications in the areas of

drawing updates, QC hold points, and operability tests, and assure

that the contractor involved has complied with these changes. This

will be followed by open item (374/85018-08(DRP)).

b. By August 1, 1985, review all contractor Quality Control programs to

assure that program modifications in the areas of updating field

drawings, QC coverage during installation, and conduct of adequate

construction tests are instituted by all contractors in light of

lessons learned during this event. This action will be followed by

openitem(374/85018-09(DRP)).

Subsequent to the additional problem identified on Unit 1 on July 17,

1985, another Confirmatory Action Letter was issued on July 19, 1985 to

address the additional actions to be taken prior to startup of either

unit:

a. Review the entire list of Drawing Change Requests (DCR's) and

determine those DCR's that have been rejected or cancelled

(373/85023-03(DRP);374/85018-05(DRP)).

b. Review all rejected or cancelled DCR's and determine the status of

their disposition (373/85023-04(DRP); 374/85018-06(DRP)).

c. For those DCR's which have been rejected or cancelled or for which

the dispostion is unknown, verify that critical drawings onsite are

properly annotated to show the present status of the associated

system and/or that drawing aperature cards show they are affected by

a DCR. All remaining open DCR's will be reviewed within two weeks

of startup. Completion of this action will be tracked as open item

(373/85023-05(DRP);374/85018-07(DRP)).

d. Implement a documented review of all EQ work requests prior to

performing the work to ensure that qualification is preserved. This

review applies to all EQ work requests initiated subsequent to July

19, 1985, and will continue until the maintenance procedures have

been updated to reflect EQ requirements. Completion of this action

will be tracked as open item (373/85023-06(DRP); 374/85018-08(DRP)).

e. Implement a documented review of surveillances on EQ equipment prior

to performance to ensure that qualification is preserved. This

review applies to all surveillances on EQ equipment initiated

subsequent to July 19, 1985, and will continue until the surveillance

procedures have been updated to reflect EQ requirements. Completion

of this action will be tracked as open item (373/85023-07(DRP);

374/85018-09(DRP)).

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f. By August 5,1985, complete a documented review of one EQ component

of each type for all EQ binders that have been issued to the site

and for which a site review has been performed. This review will

ensure that all appropriate EQ requirements were accomplished during

installation. Completion of this action will be tracked as open

item (373/85023-08(DRP);374/85018-10(DRP)).

g. By September 2, 1985, complete a documented review of all EQ binders

that have been received by the site, but that have not yet been

reviewed, and ensure that appropriate EQ requirements were

accomplished during installation. Completion of this action will be

tracked as open item (373/85023-09(DRP); 374/85018-11(DRP)).

The immediate actions required prior to startup were completed and Unit 2

was authorized to startup on July 20, 1985.

4. Summary

The safety significance of the events described in this report are

minimized by the fact that Unit 2 was in cold shutdown during the

evolutions. Notwithstanding the above, it is of significant concern to

the NRC that the licensee allowed the condition of the unit to degrade to

a point where ECCS systems would not have automatically responded to a

reactor level transient. Additionally, secondary containment integrity

was not maintained as required due to the licensee's failure to recognize

its necessity. During the time when all ECCS systems were degraded and

secondary containment integrity was not established, the primary

containment was open to the secondary containment as such if a leak had

occurred there existed a potential for release of radioactive material to

the environs.

As previously noted, the safety significance of the improperly piped

isolation switches on Unit I was also minor due to the redundant

isolation features available. The affected valves are also normally

closed during power operation.

These events illustrate a significant and continuing breakdown in manage-

ment controls. Region III has repeatedly expressed concerns for similar

LC0 violations and repeated modification problems. Specifically, the

October 1984 problems associated with a loss of Standby Gas Treatment

(SBGT) and the resultant Civil Penalty, (373/84-036), the April 17, 1985

discovery of miswired switches for Automatic Depressurization (ADS) and,

more recently, the May 3,1985 discovery of miswired temperature

detectors affecting RCIC operability. It is apparent that licensee

management is not effectively addressing these concerns as witnessed by

these continuing problems nor are they meeting their commitment in

response to identified violations. The CECO April 19, 1985 response to

the SBGT event stated: "In order to preclude this type of problem in the

future, LaSalle Station will require that a test be conducted to

demonstrate operability anytime a safety-related system is returned to

service. A Post Maintenance Operational Test Checklist has been

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developed to ensure that the post maintenance test specified adequately

demonstrates system operability in light of the work actually performed.

, Nuclear Station Division has directed that each CECO Nuclear Station

review this checklist for applicability."

5. Open Items

Open Items are matters which have been discussed with the licensee, 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 Paragraph 3.

6. -Enforcement Conference

The NRC staff met with licensee representatives (denoted in Paragraph 1)

for an Enforcement Conference on June 24, 1985 at LaSalle County Nuclear

Power Station. The Conference was held to review the circumstances that

led to the inoperability of all three ECCS divisions during the period

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June 3-10, 1985 and the loss of secondary containment during the period

June 5-8, 1985. The licensee stated they believed the problems were due

to three principal causes: (1) errors in production drawings, (2) lack

of adequate QC involvement, and (3) inadequate testing because there was

no requirement for system walkdowns. The licensee's staff proposed

eleven corrective actions that they believed would resolve these

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problems. Some of the more significant proposals included: (1) implement

i a maintenance and operation checklist for post maintenance testing prior

to return to service, (2) u

hold point utilization, (3)pgrade station

upgrade and contractor

contractor productionquality

drawingcontrol

control,

and (4) revise station modification procedure to clarify physical walkdown

requirements. The staff also discussed the likely informational content

of the 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.

12

L 4

ML20134M816

Text

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