ML20199D521

Forwards Trip Rept Documenting NRC Evaluation of Six Wrong Unit/Wrong Train Events Studied During 851112-15 Site Visit

ML20199D521
Person / Time
Site:	LaSalle
Issue date:	03/17/1986
From:	Adensam E Office of Nuclear Reactor Regulation
To:	Farrar D COMMONWEALTH EDISON CO.
References
NUDOCS 8603240154
Download: ML20199D521 (2)

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NRC POR

-NUCLEAR REGULATORY COMMISSION

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W ASHINGTON, D. C. 20555 March 17, 1986

-- PRC System Docket Nos. 50-373/374 Mr. Dennis L. Farrar.

Director of Nuclear Licensing Commonwealth Edison Company Post Office Box 767 Chicago, Illinois 60690

SUBJECT:

Transmittal of Trio Report Documenting Visit to Evaluate Wrona Unit / Wrong Train Events at LaSalle and D. C. Cook Re:

La Salle County Station, Unit Nos. 1 and 2 Enclosed is a report documenting the staff's evaluation of six La Salle wrong unit /wrono train events studied during a site visit on November 12 to 15, 1985.

It is being forwarded to you for information purposes only and no response is required.

Sincerely, Lb -4eud '

j Elinor Adensam, Director BWR Dro.iect Directorate No. 3 Division of RWR Licensing

Enclosure:

Trip Report cc w/ enclosure:

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s Mr. Dennis L. Farrar la Salle County Nuclear Power Station Commonwealth Edison Company Units 1 & 2 cc:

Philip P. Steptoe, Esquire John W. McCaffrey Suite 4200 Chief, Public Utilities Division One First National Plaza 160 North La Salle Street, Room 900 Chicago, Illinois' 60603 Chicago, Illinois 60601 Assistant Attorney General 188 West Randolph Street Suite 2315 Chicago, Illinois 60601 Resident Inspector /LaSalle, NPS U.S. Nuclear Regulatory Commission Rural Route No. 1 Post 0Ffice Box 224 Marseilles, Illinois 61341 Chaiman La Salle County Board of Supervisors La Salle County Courthouse Ottawa, Illinois 61350 Attorney General 500 South 2nd Street

-Springfield, Illinois 62701 Chairman Illinois Commerce Commission Leland Building 527 East Capitol Avenue Springfield, Illinois 62706 Mr. Gary N. Wright, Manager Nuclear Facility Safety Illinois Department of Nuclear Safety 1035 Outer Park Drive, 5th Floor Springfield, Illinois 62704 Regional Administrator, Region III U. S. Nuclear Regulatory Commission 799 Rossevelt Road Glen Ellyn, Illinois 60137

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NUCLEAR REGULATORY COMMISSION e

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3 ms mum.o.c.ma JAN l'0 1985 MEMORAhDUM FOR: Harold R. Bocher, Chief Maintenance and Training Branch Division of Human Factors Technology, NRR Frank H. Rowsome, Chief Human Factors Issues Branch Division of Human Factors Technology, NRR Kathleen M. Black, Chief Nonreactor Assessment Staff Office for Analysis and Evaluation of Operational Data James E. Lyons Chief Technical and Operations Support Branch Planning and Program Analysis Staff, NRR FROM:

Ann Ramey-Smith, Engineering Psychologist Human Factors Issues Branch Division.of Human Factors Technology, NRR drewPersinko,MaintenanceandSurveillanceEngineer Maintenance and Training Branch Division of Human Factors Technology NRR

SUBJECT:

TRIP REPORT FOR LASALLE AND D. C. COOK SITE VISITS REGARDING WRONG UNIT / WRONG TRAIN EVENTS This memorandum documents the activities and findings of an NRC staff visit to the LaSalle and D. C. Cook sites on November 12-15, 1985. Members of the NRC team for this visit included A. Ramey-Smith (DHFT) and D. Persinko (DHFT). The site visit was conducted as part of the short-tem effort to determine whether simple, low cost improvements can be identified and implemented to reduce the frequency of wrong unit / wrong train events occurring at nuclear power reactor facilities. Upon completion of all site i

visits, the factors contributing to the events will be evaluated and a report issued which discusses causes and recommendations. Long tem assessment will be addressed as part of the Maintenance and Surveillance Program Plan being conducted by DHFT.

General Information The LaSalle site is located 11 miles southeast of Ottawa, 1111noist There are two reactors, LaSalle 1 and LaSalle 2, located at the site, each of which has a maximum dependable capacity (net) of 1078 MWe. LaSalle 1 was placed C,~Js i l '7M/q7 g

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into commercial operation on January 1,1984, and LaSalle 2 on October 19, 1984. Both units are General Electric BWRs and the architect /

engineer for both units was Sargent and Lundy. The licensee is Commonwealth.

Edison.

The D. C. Cook site is located 11 miles south of Benton Harbor, Michigan, and has two reactors, Cook 1 and 2.

Both units are Westinghouse PWRs and the architect / engineer for both units was the American Electric Power Service Corporation. Cook I has a maximum dependable capacity (net) of 1020 MWe and was placed into comercial operation on August 27, 1975. Cook 2 has a maximum dependable capacity (net) of 1060 MWe and went into comercial operation on July 1, 1978. The licensee is Indiana and Michigan Electric.

Site Visit Agenda The discussions and in-plant observations centered around six' wrong unit / wrong train events that occurred at LaSalle between 1983 and 1985, and four that occurred at Cook between 1981 and 1985. The LER numbers for these events at LaSalle are 373-83-140 and 84-017,84-072, 85-012 and 85-020 and at l

Cook are 315-81-005,83-009, 83-048, and 84-014. Also discussed at Cook was the occurrence discussed in the Daily Report of 4/25/85. During both site visits, the NRC team inspected the locations of the reported wrong unit / wrong i

train events to the extent possible, and discussed the events with plant management as well as many of the individuals directly involved with the event. Enclosures I and 2 provide the sequence of events resulting in the LERs at LaSalle and Cook, respectively, the licensee's conclusions regarding the event, and NRC staff observations.

Observations at LaSalle Color Coding.

LaSalle utilizes a color coding scheme of light tan for Unit 2 and white for Unit I which are painted on the floors of the respective units. The team notes that because of the similarities in the two colors, I

one cannot easily distinguish between the colors to determine unit except at the dividing line between the units where the two colors meet and provide a discernible contrast.

l Plant Labeling.

Component labels do not correspond to the unit color coding scheme but rather, denote systems (e.g., safety, nonsafety, water, air).

Metal embossed tags attached to valves are used for valve identification I

(Figure 1) with plastic engraved tags and black stenciled labels used to

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. identify electrical cabinets and other components (e.g., chain operators)

(Figures 2 and 3). Stenciled black labels are also used on the outside of doors throughout the plant to aid in the identification and location of equipment located beyond the door (Figure 4). Additionally, because of the similarity of equipment in the electrical equipment room, a map showing the location of the equipment within the room is presented as one enters the room (Figure 5). Below the map is a listing of the panel numbers and a description of the panels.

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3 Except for a few operating procedures, most operating procedures apply to both units with Unit 2 component designations listed after Unit 1.

When asked their opinion regarding contributing factors to WU/WT events, a Conmonwealth Edison staff member believed that connunications breakdowns and a lack of attention were the dominant contributors.

Because Comonwealth Edison is the licensee for both Dresden and LaSalle, matters directed from the corporate headquarters such as the investigation of events involving human error and training are handled identically for both LaSalle and Dresden and have been previously described in the staff's WU/WT trip report for Dresden (memo dated June 11, 1985, from Virgilio to Edison, Regan,Booher, Black).

Observations at D. C. Cook Philosophy. As stated by D. C. Cook personnel, a goal for the plant is to reduce the probability of human error and minimize their effects when they do occur. The programs discussed below provide examples of how D. C. Cook is trying to implement this philosophy.

Color Coding. A color code is being implemented to differentiate between the t

two units, with Unit 1 being orange and Unit 2 being blue. The cabinets and panels are being painted, doonvays are color coded and signs are provided, and tank bands have been painted (see Figures 6, 7 and 8). Labels are color i

coded by train and channel for safety grade equipment; channel 1 is orange, I

channel 2 is blue, channel 3 is white, and channel 4 is yellow.

I&C procedures are color coded by protection channel.

Plant Labeling. The D. C. Cook staff indicated that everything on flow prints and everything that has a human interface will be labeled. Cook has selected aluminum tags for labeling components as follows: orange - Unit 1 mechanical components outside of containment; blue'- Unit 2 mechanical I

components outside containment; and, green - mechanical components on shared I

systems outside of containments. Stainless steel tags will be used for labeling mechanical components inside both containments or in adverse environments outside containments. The readability of the aluminum tags has been enhanced by increasing the contrast between the tag lettering and the tag background. This was done by filing the raised letters to remove the color and contrast with the colored tag backgrounds (see Figure 9). The same technique would not work with the stainless steel tags, resulting in what the NRC staff considered tags with very poor readability.

Each component is assigned a unique mark number. The first digit is the unit designation; in the second series of digits, the first letter is the sy' stem, the second is the type of device (e.g., if an instrument), and the third letter would indicate whether, for example, the component is a switch. The facility database contains the official noun name of devices which will be used on all procedures and drawings. A list of standard abbreviations was

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developed during conduct of the control room design review. The Cook personnel saw the plant labeling process as an on-going, iterative process.

A procedure exists for maintaining labels, and plant maintenance procedures include a check-off for the adequacy of labels on the equipment being maintained. An operator aids procedure has also been developed to control the quality of operator aids.

D. C. Cook personnel also described an effort underway to provide pipe labeling on all plant systems. These labels (see Figure 10) are color coded

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according to unit and train and include flow arrows. The Cook staff indicated that this pipe labeling has been approved for use on stainless steel piping, but had not yet been approved for use in containment.

Electrical cabinets will be labeled inside as well as outside per a comitment to INPO. The Cook staff indicated that a circuit directory will also be prominently placed inside the cabinet door or nearby if no door is present.

During the tour of the facility, the NRC staff was stunned by the gross lack of pemanent labels in some areas of the plant and yet impressed at the stark 1

difference between those areas that had been upgraded and those yet to be done. Components in areas where permanent labels had not yet been installed

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were identified with duct tape and magic marker lettering.

i Print Program.

In mid-1982 D. C. Cook initiated its Regulatory Perfomance Improvement Program (RPIP). As part of that effort, a crew of plant 4

personnel, including those with drafting experience, started " walking down" prints. The following were the major aspects of that program:

1)~ to identify sequence of connection errors in which notes and references guide the user to the wrong next drawing; 2) identify components on the flow prints without unique component numbers and input the unique number to the facility database; and 3) clarification of drawings to identify those that are not easy to understand. To assist instrumentation people and aid in labeling, Engineering Control Procedures were developea to augment information on flow prints. A unique numbering convention was developed.

Previous to establishment of the numbering scheme, construction numbers were used, a practice that did not address the users' needs. The Cook staff indicated that the present numbering scheme is much more user friendly.

Sealed Valve Program. Cook has instituted a sealed valve program to protect and give administrative control over manual valves.

If a valve can inhibit a safety injection flow path, it gets a color coded (by unit) safety seal that is uniquely numbered.

(Fire protection seals are red.) Periodically, the positions of these valves are verified. A procedure or clearance is re. quired to change the position of these valves.

Computerized Clearance Permits.

D. C. Cook personnel indicated thht a computerized clearance permit system was being established. At the present time, repetitive clearances have been computerized. Eventually, all

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5 clearances will be incorporated into a computer system which will have the capability to check the clearance against the facility data base and will print out tags.

Miscellaneous. The D. C. Cook staff provided a hand-out that sumarized the activities completed or underway to reduce the frequency of events in which human error is a major contributor. That list is provided as Enclosure 3 to this report.

Exit Meetings At the exit meetings at both sites, the NRC team expressed its appreciation to the LaSalle and Cook staffs for their cooperation in planning the visit.

coordinating the tour and discussions and providing pertinent inforretion.

These actions made the site visits informative and productive.

The team would like to note that the staff at Cook was extremely well prepared for our visit. The handouts, containing labeling samples supplemented by the well-prepared presentations, assisted the staff greatly in understanding the WU/WT events at Cook and Cook's initiatives to reduce hur..an errors.

The team also expressed its appreciation to the Resident Inspectors at LaSalle and Cook for their assistance. Mike Jordon, the Senior Resident Inspector at LaSalle, was extremely helpful in arranging discussions with the licensee.

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Ann Ramey-Smith, Engineering Psychologist Human Factors Issues Branch Division of Human Factors Technology, NRR At4T?

Drew Persinko, Maintenance and l

Surveillance Engineer i

Maintenance and Training Branch Division of Human Factors Technology, NRR

Enclosures:

As stated cc: See'next page

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J. Funches F. Hebdon G. Cwalina E. Trager V. Benaroya A. Bournia D. Wigginton.

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4 WU/WTEVENTSATLASALLE(DOCKETNO.50-373 Unit 1)

(DOCKET NO. 50-374 Unit 2)

I.

LER 373-83-140 IncorrectJumperInstallation(WrongUnit)

A.

The following event information was provided by the licensee in the LER:

"On November 16, 1983 during removal of unit separation jumpers prior to perfoming LES-PC-02 and LES-PC-10, an incorrect jumper installation was identified. The jumper was installed on September 15, 1983 in accordance with LAP 240-3. Attachment B. Jumper and Block installation form.

"The jumper should have been installed between terminals CC-79 and CC-80 in Panel IPA 14J to prevent a Unit 2 isolation signal from automatically starting the Standby Gas Treatment System. The jumper was actually installed between terminals CC-79 and CC-80 in Panel 2PA14J which prevented. Unit 1 and Unit 2 Standby Gas Treatment Systems from l

automatically starting on a Unit 1 Division 1 isolation signal. The jumper was immediately removed and a Deviation Report was initiated.

"LaSalle Unit I was in Cold Shutdown when the incorrectly placed jumper was identified. During the time that the jumper was in place, LaSalle.

Unit I was in start-up testing at power ' levels between Cold Shutdown and 100%.

" Electrician installing the jumper failed to note that the jumper form.

LAP 240-3. Attachment B specified that the jumper was t'o be placed in Panel IPA 14J instead of Panel 2PA14J. He was in the process of placing numerous jumpers in the Unit 2 pa'nels to prevent spurious starts of-shared' safety related equipment caused by invalid signals "from Unit 2 i

(Unit 2 is in a pre-fuel load status).'

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"The operator that verified the jumper installation did not understand the significance of independent verification with respcct to this job and failed to notice the "1" on the panel EPN.

In addition, the operator that verified the jumper installation was with the electrician when the jumper was being installed which defeats the purpose of independent verification.

"A Daily Order book entry was made by the Unit Operating Engineer on November 28, 1983 outlining the problem that had occurred and directing

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the Shift Engineers to begin implementing a time separation for independent verification of jumpers imediately.

"A letter is being issued by the Station Superintendent to all department heads re-emphasizing the requirement for independent verification of items as specified in LAP 240-6 Temporary System Changes and LAP 900,-4, Equipment Out-of-Service Procedure.

"A discussion was held with the individuals involved with respect to ensuring that jumpers are installed in the correct location and the necessity for independent verification.

"A discussion was conducted by the Master Eltetrician on November 29, 1983 with the Electrical Maintenance Department with respect to this event. The importance of ensuring that jumpers are properly installed and for independent verifications was stressed to all individuals."

B.

NRC Discussions with Plant Staff During the site visit, the NRC team spoke with a member of the LaSalle staff about the event.

From that discussion, it was learned that the incident occurred at a time when Unit I was in operation a'nd Unit 2 was under construction. The valves in question were part of a"comon isolation group whereby the valves from both units close upon a signal from either unit. The purpose of the jumpers was to prevent a Unit 2 l

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, signal from affecting Unit 1.. The logic is such that in order to bypass Unit I valves from being operated by a Unit 2 signal, the jumper should have been installed in'a Unit 1 electrical panel. The panels, located in separate rooms, were labeled on the front but it was unclear whether l

they were also labeled in the back where the jumpers were installed.

The electrician involved was considered to be experienced. The independent verification perfonned was actually dual verification due to a lack of understanding about " independent" verification by the independent verifier.

Currently, a separate procedure is used for each unit and the procedures now provide unit number cautions. Additionally, the panels are identified on the backside as well as the front. Panel identification also exists on the inside of the rear door so that one will know the panel number even with the door open.

The NRC team was able to view the panels where the jumper was inadvertently installed and the panel where it should have been installed.

II. LER 373-84-071 Inadvertent Closure of Reactor Water Cleanup Outboard Isolation Valve (Wrong Component)

A.

The following event infonnation was provided by the licensee in the LER:

"On 10/24/84 at 1330, the Unit 1 Reactor Water Cleanup system (RWCU, CE)

Outboard Isolation Valve, IG33-F004, inadvertently closed, due to a Group 5 Isolation Signal (JM) generated during the logic testing of the Primary Containment Isolation System (PCIS). At the time of the.

occurrence Unit I was in Cold Shutdown. LES-PC-10, Primary Containment Isolation Manni Initiation Logic Test, required that specified control power breakers to valves be opened prior to testing the PCIS Manual

,' Initiation logic, to prevent spurious isolation of the systems during testing. These breakers were specified by the Shift Foreman on Attachment A of LES-PC-10. During the testing of the Division 1 PCIS Manual Initiation logic, the RWCU Outboard Isolation Valve, IG33-F004, unexpectedly isolated upon PCIS initiation.

"The RWCU Outboard Isolation Valve closed on the manual initiation signal because the wrong control power breaker had been opened.

Attachment A of LES-PC-10 had specified that breaker A4 at MCC 134X-1 be opened for 1G33-F004, instead of the correct breaker E5 at MCC 135X-1.

The reason for the wrong breaker being identified on the Attachment is due to the closeness in the equipment number of 1G33-F004, instead of the Attachment is due to the closeness in the equipment number of 1G33-2001-4 which is fed from MCC 134X-1, A4, and an error made when the control power checklist was initially developed.

" Operating Equipment Attendants (Non-Licensed Operators) have been instructed to look at the equipment name labels identified on the MCC breakers, as well as the MCC number and breaker identified by a checklist when removing and returning equipment from service.

Additional emphasis has been placed on the importance of independence of the second verification."

B.

NRC Discussions with P7 ant Staff From discussions with the plant staff, it was learned that the shift foreman who generated the list of valve breakers to be operated during this surveillance mistakenly listed the power supply for valve number IG33-2004 instead of 1G33-F004. The error was attributed to the closeness of the two numbers. The list had been generated from.

electrical drawings each time the surveillance was to be performed; however, subsequent to the event, a standardized list has bien l

developed. The plant staff member indicated that developing standardized outage lists is still in its infancy at LaSalle.

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5-The NRC team did rot view these breakers because physical location was not a contributor to this incident.

III. LER 374-84-017 ReactorScramonLossofFeedwater(WrongComponent)

A.

The following infomation was provided by the licensee in the LER:

"The Unit 2 Reactor was scramed manually on 5-3-84 at 2340 when it becameapparentthattheMotorDrivenReactorFeedPump(SJ)couldnot be resta:ted and reactor vessel level could not be maintained above 12.5 inches. At the time of the event, the unit was proceeding with a normal shutdown to obtain data for the Start-Up Test Program.

"The NSO (Licensed Operator) on the unit decided that at that point in the shutdown, it was convenient to close all the Reactor Feed Pump.

Warming Line Valves. These valves provide a flow path to the Reactor Vessel even though the discharge valve on the Reactor Feed Pump is closed. With any Waming Line Valve open on any of the Reactor Feed-Pumps, it provides enough make-up to the vessel that make-up would P

l exceed blowdown during low power operation and vessel level would rise at a rapid rate, which is not desirable. Therefore, the NS0 on the unit instructedanEquipmentAttendant(EA)(Non-LicensedOperator)toclose

-the warming line valves on all three feedwater pumps. The warming line valves on -the 2A and 28 TDRFP were correctly valved out.

Imediately after, the Equipment Attendant valved out the Balancing Line Valve 2CBG37 on the Motor Driven Reactor Feed Pump instead of the Warming Line Valve 2FWO37. The Motor Driven Reactor Feed. Pump tripped and could not be restarted. Both valves, the Balancing Line Valve 2C8037 and the I

Warming Line Valve 2FWO37, are in the same room and about five (5) feet apart.

"The Equipment Attendant who closed the Balancing Line Valve' 2C8037 l

instead of the Warming Line Valve 2FWO37 indicated that he thought he was on the correct valve because the number "37" caught his eye on the l

valve Equipment Part Number. He did not read the entire noun name of the valve that was indicated on the associated valve tag. The Equipment Attendant also thought he was on the correct valve when he read the number "37" on the valve tag because he had just closed the Warming Line Valves on,the A and B Turbine Driven Reactor Feed Pumps and there was similarity associated with the piping and valves between the Turbine Driven Reactor Feed Pumps and the Motor Driven Reactor Feed Pump. The Equipment Attendant was not given any indication that a Balancing Line Valve 2CB037 existed or the consequences if it were closed."

The following corrective actions were taken:

"1.

A. Caution Card was placed immediately on the Balancing Line Valve 2CB037 with instructions indicating that it should not be closed unless the Motor Driven Reactor Feed Pump is to be taken out of service (for both Units 1 and 2).

2.

Work Request L36421 was initiated so that repairs could be made to the Motor Driven Reactor Feed Pump.

(Repairs have been completed and the Motor Driven Reactor Feed Pump is back in operation.)

3.

Signs were placed on both Unit I and 2 Balancing Line Valves 1CB037 and 2CB037 indicating that the valves should not be closed unless the pump is out of service. This replaced the Caution Cards.

4.

AIR 01-84-67076 was submitted to ensure personnel (Equipment Attendants and License Personnel and all new Equipment Attendants) were trained on the purpoit 4f the Motor Driven Reactor Feed Pump Balancing Line.

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5.

The following procedures were reviewed to ensure that the Reactor Feed Pump Wanning Lines were in the proper position for the plant

. condition:

a.

LOP-FW-01M U-1 FW Mechanical Checklist b.

LOP-FW-02M U-2 FW Mechanical Checklist c.

LOP-FW-01 Feedwater System Filling and Venting d.

LOP-FW-02 Feedwater System Draining e.

LOP-FW-03 Start-Up of Motor Driven Reactor Feed Pump -

Change submitted i

f.

LOP-FW-06 Shutdown of Motor Driven Reactor Feed Pump to Hot Standby - Change submitted g.

LOP-FW-04 Start-Up of a Unit 1 TDRFP - Change submitted h.

LOP-FW-05 Shutdown of a TDRFP - Change submitted

i. LOP-FW-07 Preparation for TDRFP S/U with Main Steam System Pressurized

j. LOP-FW-08 Condensate Recirc to Condenser via Heater Drain System k.

LOP-FW-09 TDRFP Exhaust Duct Isolation During Unit 4

Operation 1.

LOP-FW-11 Start-Up of Unit TDRFP - Change submitted m.

LGP-1-1 Normal Unit Start-Up - Change submitted n.

LGP-1-2 Unit Start-Up to Hot Standby - Change submitted o.

LGP-1-3 Unit Start-Up from Hot Standby to Power Operation - Change submitted l

p.

LGP-2-1 Nonnal Unit Shutdown - Change submitted q.

LGP-2-2 Shutdown to Hot Standby - Change submitted r.

LGP-3-2 Reactor Scram - Change submitted The above procedure changes will be tracked by AIR 01-84-67077. In addition, the procedures were reviewed to ensure correct reference and use of the Balancing Line Valves."

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8 B.

NRC Discussions with Plant Staff Plant staff told the NRC team that this is not the first time this event has happened. The waming lines which were to be closed wam the reactor feedwater pump casing to reduce thermal stresses in the casing which are developed from the high temperature (approx. 350*F) developed in the reactor feed pump. The balancing lines, one of which was incorrectly closed, keep the motor driven reactor feedwater pump thrust bearing in position.

At the time of the event, the valves were labeled with metal embossed identification tags; it is unclear whether these tags were the new or old tags. The equipment attendant (EA) indicated that this was the first time he performed this action and the training he received did not cover this plant action and specifically, did not cover the differences between the waming and balancing lines. The operator was considered a good operator.

As a result of this event, this plant action is covered in classroom and 1

on-the-job training. Caution cards have been installed on pump control switches which indicate when the waming valves are closed and signs warning not to close the balancing valves with the pump running have been installed on the valves. The procedures in use did not say specifically which valve to close and required operators to look on i

drawings for the valves whereas now, procedures call out the valve to be closed. Additionally, instead of specifying FWO37 to be closed, another valve (FW115) in series with FWO37 has been specified. The FW115 designation does not resemble FWO37 and this valve is physically located outside of the room containing the waming line valves.

The NRC team was able to view valve FW115; however, due to radiological consideration, was not able to view the warming line valves'or balancing line valves involved in this incident.

1

i The NRC team observed that metal embossed tags are difficult to read unless lighting conditions are good due to very little contrast between the raised identification numbers and the background.

IV. LER 374-84-072 VR Isolation Damper Closure on Wrong Unit A.

The following information was provided by the licensee in the LER:

"On 10/29/84 at 1952 hours0.0226 days <br />0.542 hours <br />0.00323 weeks <br />7.42736e-4 months <br /> an Equipment Attendant (nonlicetzed operator) closed the Unit 2 Reactor Building Ventilation (VA, VR) isolation dampers 2VR04YB and 2VR05YA. This caused the Unit 2 Reacter Building Ventilation system to shutdown. The Equipment Attendant had been instructed to open the Unit 1 Reactor Building Ventilation dampers IVR04YA, IVR04YB, IVR05YA, and IVR05YB but inadvertently closed dampers on the other unit. The Unit 2 dampers were reopened and the Unit 2 Reactor Building Ventilation system was restarted at 1953 hours0.0226 days <br />0.543 hours <br />0.00323 weeks <br />7.431165e-4 months <br />.

"At the time of the incident Unit I was in cold shutdown and Unit 2 was in the "Run" mode at 73% power. The Reactor Building differential pressure with respect to outdoors was being maintained by Unit 2 VR.

Unit 1 VR had been shutdown so that LaSalle Operating Procedure LOP-RP-01 could be performed. This was used so electrical power could be transferred from Reactor Protection System (EE, RPS) "B" Motor Generator Set to Alternate Power. As a precaution against momentarily losing power to Unit 1 RPS the Unit 1 VR system was shutdown and secondary containment isolation dampers IVR04YA, IVR04YB, IVR05YA, and IVR05YB closed.

If power were to be momentarily lost to the damper actuators during the tranIfer the isolation dampers would fail closed and shut.

i "After the power has been successfully transferred the Unit 1 Control Room Operator (NS0) instructed an Equipment Attendant (EA)-tb open the Unit 1 VR isolation dampers so the system could be restarted. The EA inadvertently went to the Unit 2 isolation damper control panel 2PL27JB

located in the Auxiliary Building (NF) and closed dampers 2VR04YA and 2VR05YA. The dampers promptly closed shut causing Unit 2 VR to shutdown. The EA still in the Auxiliary Building called the NSO who infonned him that he had closed the dampers on Unit 2 instead of opening the dampers on Unit 1.

The NSO told the EA to open the Unit 2 dampers and then go over to the Unit 1 isolation damper control panel and open the Unit 1 dampers. The EA opened the Unit 2 dampers and Unit 2 VR was restarted at 1953 hours0.0226 days <br />0.543 hours <br />0.00323 weeks <br />7.431165e-4 months <br />. The EA then went over to the Unit 1 VR damper control panels IPL27JA and IPL27JB and opened dampers IVR04YA, IVR04YB, IVR05YA, and IVR05YB as originally instructed. Unit 1 VR was then started up at approximately 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br />.

"The station initiated an investigation and detennined the incident was the result of an error made by the Equipment Attendant when he closed the dampers on the wrong unit. The damper control panels were labeled correctly and did not contribute to the error made."

B.

NRC Discussions with Plant Staff As stated in Section A, the EA was supposed to open Unit 1 VR isolation dampers, per verbal instructions from the control room operators, and i

~instead, went to Unit 2 and closed the Unit 2 'VR isolation dampers. The dampers are operated locally from the auxiliary building, which is common to both units. The controls for both units are on the same elevation with Unit 2 controls located on the north end of the auxiliary building and Unit I controls on the south end. The outside of the damper control box is shown in Figure 2 and upon opening the door, the controls which the operator inadvertently closed are shown in Figure 11.

The operator manipulated two U' nit 2 control room damper boxes which were approximately ten feet apart. At the time of the incident, the boxes were labelled with the plastic identification tags shown in Figure 2.

No independent verification was perfonned as the control roo'm operator caught the error from a warning light in the control room shortly after the incident occurred. No explanation into the cause was put forth

l' I

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_ ma Figure 11. LaSalle: LER 374-84-072 Inside of Damper Control Box.

I a

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other than the operator must have had in his mind that he was required to change position of the dampers, whereupon after entering the wrong unit, the change in position closed the dampers. The NRC team observed i

the color coding described above which was painted onto the floor of the auxiliary building at this level.

V.

LER 374-85-012 Inadvertent RHF Shutdown Cooling Isolation (Wrong Component)

A.

"At 1103 hours0.0128 days <br />0.306 hours <br />0.00182 weeks <br />4.196915e-4 months <br /> on March 31, 1985, with LaSalle Unit 2 in Cold Shutdown.

a Residual Heat Removal (RHR, 80) Shutdown Cooling isolation occurred during the perfonnance of surveillance procedure. LIS-RH-10. "LPCS/RHR Injection Line Integrity Monitor Calibration and Functional Test.

• ~

"A Group 6, Division 2 Primary Containment Isolation (PCIS, JM) occurred on an apparent RHR suction high flow signal. The RHR Suction Inboard Isoiation Valve, 2E12-F009, automatically closed. All other Group 6. Division 2, isolation valves had been previously closed. The operating RHR pump, 2E12-C002A, tripped as required on the closure of valve 2E12-F009.

"The Instrument Maintenance Technician perfonning surveillance LIS-RH-10 j

promptly notified the Unit Nuclear Station Operator (NS0) of an instrument valving error. This was identified as the cause of the j

isolation; RHR Shutdown Cooling piping integrity was verified, and the RHR loop was returned to operation at 1107 hours0.0128 days <br />0.308 hours <br />0.00183 weeks <br />4.212135e-4 months <br /> on March 31, 1985.

"The 2E12-F009 isolation occurred due to the valving out of instrument 2E31-N0128. Under LIS-RH-10 instrument 2E12-N0298 was to be valved out j

but the Instrument Maintenance Technician performing the surveill,ance l

incorrectly traced the. piping from instrument 2E12-N129B and without l

looking at the tag on the instrument isoir. tion valve, mistalcealy l

1solated a line to instrument 2E31-N0128.

l

\\

"2E31-N0128 is a Barton 288A Differential Pressure Indicating Switch

-(DPIS) and is physically located next to 2E12-N0298, another Barton 288A DPIS. 2E31-N0128 senses differential pressure caused by flow through the RHR Shutdown Cooling suction piping. When the low pressure sensing line to 2E31-N0128 was mistakenly isolated, a lower than actual pressure was sensed at the low side of 2E31-N012B. With the high pressure side unchanged, a high differential pressure (high flow) condition was simulated and 2E31-N0128 actuated.

"The Instrument Maintenance Technician's incorrect tracing of the piping

~

from instrument 2E12-N029B and failure to read the valve tag before moving the valve caused the March 31, 1985 occurrence.

"An investigation followed this occurrence and a meeting was set up between the Instrument Maintenance Technician involved, the Foreman in charge of the work, and the Assistant Superintendent of Maintenance.

The events of this occurrence were discussed and the need for attention to detail was stressed.

l "The Instrument Maintenance Department will be trained on this occurrence with a focus on positive identification of instruments to be valved out. The completion of this training is being tracked by AIR 01-85-67055."

)

B.

NRC Discussions with Plant Staff The NRC team was unable to view the instrurnent lines involved in this event due to radiological considerations; however, the team was able~to view a typical instrument rack located on the CRD system. Through discussions with the plant staff, the team learned that the instruments on the rack sit close together; however, the area is not very crowded.

Although the instruments and the valves are labeled, the valve labeling is not used because they are not considered to be trustworthy. As a result, the instrument maintenance technicians are instructed to hand trace the lines, a process which is done frequently. The instrument

s I

maintenance technician, in this case, was relatively new with less than j

1 year experience, and may have been nervous due to the high consequence of error (reactor trip). As a result of the event, training now covers hand tracing.

.The team notes that although the LER attributes not looking at the instrument valve tag as a contributor, such practice was connon because the tags were considered unreliable. Had the tags been maintained and considered reliable by the technicians, they may have been used whereupon, a discrepancy between hand tracing and the valve tag most likely would cause a technician to check out the discrepancy before proceeding with his intended functions. The plant staff indicated an i

intent to eventually upgrade instrument valve ta'gs so that they are l

considered reliable.

VI. LER 374-85-20 Missed Service Water Sample (Wrong Component)-

A.

The following information was provided by the licensee in the LER:

l

" Unit 2ServiceWater(KG)PRM(IL)wasdeclaredinoperableduetolow i

sample flow at approximately 1830 hours0.0212 days <br />0.508 hours <br />0.00303 weeks <br />6.96315e-4 months <br /> on April 23, 1985. A sample was not obtained until 0620 hours0.00718 days <br />0.172 hours <br />0.00103 weeks <br />2.3591e-4 months <br />, April 24, 1985. This was contrary to Technical Specification 3.3.7.10 which requires samples to be taken at least once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. At the time of this event Unit 2 was in l

Mode 4 at 0% power.

l CAUSE i

!l An investigation was conducted as a result of the missed sample from the

)

Unit 2 Service Water PRM. The Unit 2 "A" RHR (81) Service Water.PRM was mistakenly sampled instead of the Service Water PRM.

According to,a Unit 2 log entry made at 1830 hours0.0212 days <br />0.508 hours <br />0.00303 weeks <br />6.96315e-4 months <br /> on April 23, 1985, the Unit 2 Service Water monitor was declared inoperable due to a low l

l

_14 flow alarm with no adjustment for higher flow. The Center. Desk Log entry made at the same time essentially said the same thing.

"According to a log entry made at 1830 hours0.0212 days <br />0.508 hours <br />0.00303 weeks <br />6.96315e-4 months <br /> on April 23, 1985, by a Rad Chem Technician (RCT), the Unit 2 Service Water PRM was declared INOP as of 1830 hours0.0212 days <br />0.508 hours <br />0.00303 weeks <br />6.96315e-4 months <br />.

"The responsible Rad Chem Foreman was coming on shift and was taking a turnover when the call came in. The RCT who took the call showed the 1

Foreman the log entry and was acknowledged. About'5 minutes later, the Foreman called the hot lab and spoke to the RCT on duty. Direction was given to the RCT to sample and analyze the Unit 2 "A" RHR Service Water PRM instead of the Unit 2 Service Water PRM. This was done, and the Unit 2 Service Water PRM sample was not taken.

"During subsequent shift turnover around 0605 hours0.007 days <br />0.168 hours <br />0.001 weeks <br />2.302025e-4 months <br /> on April 24, 1985, the mistake was discovered by the oncoming Rad Chem Foreman. An RCT was imediately dispatched to take a Unit 2 service water sample. This was completed at 0620 hours0.00718 days <br />0.172 hours <br />0.00103 weeks <br />2.3591e-4 months <br />.

"The cause of this missed sample could be attributed to failure to pay attention to detail.

Ineffective comunication was also a contributing factor.

"The responsible Rad Chem Foreman was counseled by the Rad Chem Supervisor as to the Foreman's responsibilities when comunicating a verbal message.

In addition, the Rad Chem Supervisor will issue a department memo providing additional guidance for effective verbal i

l comunication. This will be tracked by AIR 374-200-85-00066.

B.

NRC Discussions with Plant Staff

./

Through discussions with the plant staff, it was learned that RHR service water sampling was routinely performed whereas service water L

radiation monitoring was not. As a result, the rad chem foreman developed a mindset and ' transmitted instructions to monitor the RHR l

service water system.

9 i

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- ENCLOSURE 2 WRONG UNIT / WRONG TRAIN EVENTS AT D. C. COOK 1.

LER-315-81-005 - Safety Injection Valve Breaker (Wrong Unit)

The following event infomation was provided by the licensee during the site visit:

"An auxiliary eouipment operator with approximately 1 1/2 years of experience was dispatched by the Unit Two supervisor to hang a clearance on a series of motor operated valves for the Unit Two Safety Injection pump. The operator then mistakenly went to Unit One and opened the breakers for the specified valves. This error was innediately recognized by the Unit One control room supervisor and power,was restored in approximately two minutes.

a "This event occurred on the afternoon shif t at about 10:30. The operator involved had not worked any overtime during the time surrounding the event. The area this event occurrea n was the Auxiliary Building Basement. This area is a well lit, controlled (radiologically) and spacious area in which to work. At this time the Motor Control Centers involved were the same color on both units. The only labelling that existed at this time was black component tags for each breaker and these were not con-sistently available for all breakers.

"As a result of this event an operations memo was sent to,411 shifts concerning operator attentiveness. The intended function of the ECCS system was not inhibited by this event."

l '

1 In discussions during the site visit, the licensee's staff indicated that the auxiliary equipment operator ( AEO) had been interrupted during the task of hanging the clearance tags. The AE0 had gone to the Waste Disposal System (WDS) because an alarm had sounded there. He spent five to ten minutes handling the situation there before returning to the tag hanging task. The breaker panel that he mistakenly went to (Unit 1) is located near the WSD. The AE0 realized his mistake as he walked to the Unit 2 area to perform his next task and realized that he had manipulated the breakers on Unit 1 rather than Unit 2.

It was the opinion of the licensee staff involved or familiar with the event that the interuption of the flow of work was the major contributor to the error. Another possible contributor discussed include the reliance on magic marn labels at that time, many of which did not provide complete unit or system designations.

2.

LER-315-83-009 - Spray Additive Tank Outlet Valve.(Wrong Unit)

The following event information was provided by the licensee during the site visit:

"During a routine tour an auxiliary equipment operator discovered that the Unit 1 spray additive tank outlet valve was sealed closed. Further investigation of this event disclosed that this valve was inadvertently left closed following the performance of 1-OHP 4030.STP1007 (Unit One Containment Spray System Surveillance.) The AE0 who performed the independent verifica-tion initially looked at the wrong unit's valve. Realizing his mistake he i

checked the correct unit's seal number but failed to verify the 9alve position.

This in turn caused the loss of both trains of Containment Spray to utilize the Spray Additive tank.

"Several reasons can be traced to explain this event. The Spray additional tank room contains both unit one's and unit two's spray additive tank. The AE0 involved in the initial lineup had been working on other major surveillance procedures during the shift. The Reactor Operator involved was assigned to the other Unit and crossed units to work on the lineup and the general work load of the shift was heavier than normal.

"As a result of this event, procedures were split up and re-scheduled to aid reducing work load, an operations memo on shift manpower was distributed, and labelling enhancements of the area were made."

In discussions during the site visit, the licensee's staff indicated that the procedures being run at the time of the event were time consuming and involved as many as five people to run one pump. As indicated, that procedure was subsequently broken into smaller procedures. Other potential contributors to this event exist as well. The second verifier was to verify valve position and seal number. The independant verifier i

originally went to the Unit 2 additive tank rather than the Unit 1 tank.

He became concerned that a mistake had been made when hanging the other tags. Then realizing his error, he then went to the Unit 1 tank and verified that the valves had the correct seal number. What he did not check was whether the valve was in the correct position (which it was not). The course of events that led to the valve not being in the correct position was described as follows. The valves in question are difficult to operate l

in that it is difficult to " break the seal"; but when the seal is broken.

l the valve stem suddenly spins free. When the AE0 involved in the origintil l

l 1

r valve lineup manipulated the valve, the sudden free spin of the valve caused the AE0 to loose his-balance somewhat and the seals in his pocket to spill on the floor. He picked up the seals and placed the seal on the valve with-out completing the task of opening the valve. Another potential contributor to the errors involved in this event is the independent verification process in place at the time. The licensee's staff indicated that at the time of the event it seemed that there was as much emphasis put on recording the seal number as checking the position during verification tasks. Now the independent verification practice has been changed such that seal numbers.are recorded 1

on a weekly seal tour, rather than when the independent verification is being performed..This has shifted the emphasis back to verifying posit 11on.

3.

LER-315-83-048 - Containment Spray Heat Exchanger (Wrong Train) t The following event information was provided by the licensee during the site visit:

" Surveillance test procedure 2-OHP 4030.STP.007 requires that the inlet and outlet valves be tagged closed on the Containment Spray Heat Exchanger under test.

"Two operators (one AE0 and one RO) utilizing the independent verification system closed the inlet valve on the heat exchanger not under test. Since the outlet valve on the heat exchanger under test was closed, both trains were simultaneously inoperable.

1 i

"The Containment Spray Heat Exchangers are located on the 609' elevation via the Aux Building. The heat exchanger rooms are mirror images; that is, both rooms have exactly the same components t

but are positioned opposite of each other.

J "The valves are labelled and sealed in their respective positions.

4 "Several factors contributed to this event taking place:

1) The Auxiliary Equipment Operator involved was inexperienced (first time on the job) on the surveillance test.

2) The work load on the shift was heavy and the second verifica-tion was performed by an operator assigned to another job. He i

aided the AE0 in the valve manipulation inadvertently adding to the error.

3) A third verification was performed by the Unit Supervisor who discovered the error and corrected the problem.

The time that both heat exchangers were out of service was approxi-mately 15 minutes."

Discussions with the licensee's staff indicated that the AE0

_ who manipulated the wrong valve was tired, was on the first night of the 12:00 midnight to 8:00 a.m. shift, and had not had much sleep the night before. The error occured at approximately 4:00 a.m.

In addition, the individuals involved were in a hurry and "way behind schedule."

The valve in question is inside containment and requires the use of a reach rod to manipulate it. The operator involved had traced out the reach rod but to the wrong valve. The operator manipulated the valve and t, en.

h went to check whether the valve had moved. The position of the valve was hard to see from the platform and there was no rising stem on the valve. It did not i

seem to the operator that the valve had moved so he checked the same valve on

the other unit. When the valve from the other unit was conpared to the valve in question, the two valve positions were different. The operator assumed that the valve he had manipulated was open. It did not occur to the operator that he was on the wrong train.

Labeling available to the operator could have been improved. The reach rod had a tag on it, but a more easily readable large, magic marker label was printed on the wall. This label did not contain the train designation.

In talking to the operator who was doing the dual verification, he indictted that he does not believe that he looked at the label because he had done the procedure before. He also was not there when the other operator, who had hurried on ahead, manipulated the valve. Consequently, he had not provided a dual verification. The independent verification performed later did find the error.

4.

LER-315-84-O'14 - Safety Injection Pumps (Wrong Train)

The following event infomation was provided by the licensee during the site visit:

"An Auxiliary Equipment Operator while in the process of performing a surveillance test (1-OHP 4030.STP.005) on the' South safety injec-tion pump inadvertently isolated the North' safety injection pump.

Since the Reactor Operator had isolated the South pump in the control room, this rendered both safety injection pumps inoperable.

"The safety injection pumps are located in two adjoining rooms and are designated North and South. At the titae this surveillance -

was conducted, this area was contaminated and required anti contami-nation clothing.

---

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i i

1 "The event was caused by personnel error primarily due to the breakdown in comunication.

1) The Reactor Operator involved in performing this test was I

doing so for the first time. Evidence of ineffective comunication between the R0 and AE0 which included uncertainty as to which pump was to be isolated led to the occurrence of this event.

2) Also the procedure utilized did not differentiate between trains except for brackets which were placed around South / West train com.

ponents.

3) As a. result this procedure has been divided into independent train procedures. This will aid in minimizing the chances for i

crossing trains during surveillance testing."

The event was discussed with plant personnel familiar with or involved in it. potential contributors to the wrong-train error that were discussed are as follows.

It was a very hot night with inside temperatures estimated at j

about 100 degrees, and the AE0 had to wear anticontamination clothing. It was 4:30 er 5:00 a.m., and the AE0 had not had a break. Because of the temperature, valves were turning hard. The control room operator had never run this l

l procedure before, a very long and complex procedure. The AE0 had also never l

run this procedure. General practice is for the AE0 to complete his/her tour l

l prior to running any procedures. Before the AE0 had completed tour, the control room operator called the AE0 from the control room to begin manipulating valves as called for in the procedure. The procedure involved is referred to as a l.

" double star" procedure which means that the AE0 must carry a copy of,the procedure l

when working on that procedure. The AE0 did not have a copy of the procedure so returned to the control room to get a copy. The control room operator did not mark up the procedure, which entails customizing it for the train being tested, by crossing out the component identifiers for the other train.

i

i I The control room operator had apparently been anxious about running this procedure. He was trying to hurry the AE0 along, but the valves were turning hard which slowed the work. The AE0 pot to a point in the procedure that had not been marked-up to indicate the proper train. Rather than call the control room operator, the AE0 assumed which valve was supposed to be manipulated and turned the wrong one (i.e. the North train). The AE0 had worked on the North train the night before, but the procedure being run the night of the event was for the South train. The error was discovered when the AE0 called the control room operator and told which valve had been operated.

The NRC staff agrees with the licensee that the major contributor to this event was poor communication. That poor connunication was evidenced by the lack of discussion of the procedure before the procedure was initiated, the lack of properly' marked-up procedures for the use of the AEO, the frustrated and harried atmosphere developed as a result of verbal communications between the AE0 and control room operator, and the AE0's decision not to call the control room operator to get clarification of the valve to be manipulated.

Sr. Event Report C/R 02-04-85-836 - Containment Spray (Wrong Unit)

The following event information was provided by the licensee during the i

site visit:

5 1

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5 i

"An Auxiliary Equipment Operator was assigned to place a Clearance on the Unit 1 West Containment Spray pump.

The operator correctly placed the tags on the Control Room switches and the pump breaker in the switchgear room.

The operator then proceeded to the auxiliary building to hang the remainder of the tags.

Once in the hallway which separates the Unit 1 and Unit 2 containment spray pumps the operator went to the Unit 2 side via the Unit 1 side.

The operator then closed the manual valves via the remote operators which protrude into the hallway.

Then the operator went into the pump room to hang a tag on a motor operated valve handwheel.

After the operator entered the room he noticed that the motor operated valve was open when it should I

have been closed since the valve was closed prior to hanging the tag on the control switch in the Control Room.

The operator not-realizing his error, went to the control Room informed the Unit Supervisor of a possible limit switch problem.

The Unit Supervisor asked the operator if he went to the right Unit.

The operator was sure he had and so it was decided to write a Job i

Order on the limit switch.

When the operator went to hang the Job Order, he discovered his error.

At this point, approximately 15 minutes after the error, the Control Room was informed and the Unit 2 valves were opened.

"The hallway where the error occurred was well lighted and was not in a contamination area.

The entrance ways to the pump rooms are painted blue and orange, and the valves were clearly labelled.

" A contributing factor to this error is that the operator was working non-routine hours in that he was coming in at 0330 and working until 1130 as an extra person during what normally would have been a training week. "

1 f

- - ~ ~ ~ - - ~ - ' " - - - - ~ ~ " - ' - - ~

Enclosunt 3 s

Provided by D. C. Cook ENHANCEMENTS TO PRECLUDE HUMAN ERROR TYPE EVENTS 1.

Color coding the Plant units.

(Unit 1 orange, Unit 2 blue.)

• Carried out through tags, labels, job orders, considering for procedure.

2.

Independent Verification Program.

1 3.

Electrical / wiring drawing enhancement.

4.

Revision to piping flow diagrams being redrawn for clarity.

Creating many accuratescontrolled drawings for where none i

existed.

(Fire protection, Plant air, turbine fluid control, I

etc.)

5.

Procedures being identified by color (Unit 2 cover sheet yellow).

Considering changing cover sheet color to i

correspond to unit color.

6.

Job Order revised with a

'2' superimposed on the Job Order i

for Unit 2 jobs.

7.

Labeling and walkdown program, Operator aids program.

8.

Full page' change sheets instead of pen and ink.

l 9.

Reducing complex procedures into several more distinct and applicable ones.

10.

Personnel Error Forms for Condition Reports.

Opportunity to discover contributing factors such as human factors 1

contribution.

I 11.

Opening of Condition Report process to identification of drawing discrepancies.

Statistics available.

12.

Prohibition of shift people assigned to one unit.from working on other unit except under prescribed conditions (certain tours and independent verification are cross unit).

13.

Issue of Unit one and Unit Two procedures versus 12.

14.

Facility data base effort.

15.

Computerized clearance' Permit Program and creation of.

computerized " standard" clearance boundaries for. standard repeat type jobs.

(Saves time and decreases opportunity for error.)

l l

i

i s'

i ENHANCEMENTS TO PRECLUDE HUMAN ERROR TYPE EVENTS 16.

Creation of master clearance on which all work needing to be

'done is collected, rather than issuing / hanging individual clearance / tags for each work item.

(Equal protection, saves i

time, reduces chance for error.)

17.

Increased mobility of personnel among departments particularly licensed operators transferred to Planning, QA, etc. for benefit of that training / experience to others efforts.

18.

Use of Department Outage Coordinators and much more attention put on planning / coordinating jobs to reduce confusion / error.

19.

Use of experienced revision SROs or Operations Outage coordinators.

Reduces outage load on shift Supervisors and improves coordination of outage activities with operating unit, Tech. Specs., etc.

20.

(Future) Definition _within Plant systems of " maintenance areas

• to which job orders will be keyed by computerised job order system and for which standard clearance boundaries will l

be computerised.

i.

l 21.

Direction given "If it isn't labeled, confirmable on an approved drawing:

i a) cannot operate it, put at least a temporary tag on b) cannot use for isolation point" l

l t

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