ML20245E681

Insp Rept 50-344/89-10 on 890326-0513.Violations Noted. Major Areas Inspected:Operational Safety Verification,Maint, Surveillance,Event Followup & Open Item Followup

ML20245E681
Person / Time
Site:	Trojan File:Portland General Electric icon.png
Issue date:	06/05/1989
From:	Mendonca M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V)
To:
Shared Package
ML20245E670	List: ML20245E667 ML20245E676 ML20245E681
References
50-344-89-10, NUDOCS 8906270382
Download: ML20245E681 (16)

See also: IR 05000344/1989010

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T' 'O. S. NUCLEAR REGULATORY COMMISSION

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C, h LReport No.' .50-344/89-10 L , y <

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f',' Docket.No.< 50-344

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License No.- .NPF-l'-

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K' Licensee: I fortland~ General Electric Companj ,

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' Facility Name: Trojan

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> ; Inspection at: Rainier,E Oregon

Inspection conducted: March 26'- May 13,.1989

@ t Inspectors: R., C'.'Barr . .

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Senior Resident Inspector

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, 'G. Y. Suh

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Resident Inspector

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Aoriroved;By: ..  %' ' ' '

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O M. M. Mendonca, Chief- Date Signed

hs Reactor Projects'Section 1

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' Summary:

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p ,.. Inspection on March 26 - May'13, 1989 (Report 50-344/89-10)

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-' Areas Inspected:

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4* Routine-inspection of, operational. safety verification.

. maintenance,-surveillance, event follow-up, and open. item follow-up.

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Inspection procedures 30702, 30703, 61726, 71707, 90712, 92700, and 93702 were

i Lused as' guidance'during the conduct of.the inspection,

,> 4Results:

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iThis' inspection identified two' violations of NRC requirements. Paragraph 3

discusses a repeat. violation in that information required to be recorded in

the Control Room Log was not entered. Paragraph Sa, discusses vibration

' monitoring performed on the "A" Containment Spray Pump that used a vibration

, monitoring device that did not meet code accuracy requirements. A non-cited

violation for failure to follow procedure during removal of the equipment

' hatch was identified and reviewed during this inspection period.

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S 'i!. DETAILS '

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f L 3 Psrsons Contacted

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<*D.;W. Cockfield,-Vice President, Nuclear

• C. P. Yundt,- Plant General Manager

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T. D. Walt,. General. Manager, Technical Functions

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l';e . *D. ~ L. Nordstrom, Acting Manager, Nuclear Quality AssuranceT

! !' s *R. P. Schmitt', Manager,;0perations and Maintenance

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G. A. :Zimmerman, Manager,-Nuclear Safety and Regulation Department

., A. N. Roller, Manager, Nuclear Plant Engineering.

• D..W. Swan, Manager, Technical Services

. *M. J. - Singh, Manager, Plant Modifications-

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• J. D. .Reid, Manager, Quality Support Services

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.J. W.' Lentsch, Manager, Personnel Protection

A. R. Ankrum, Manager, Nuclear Security.

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• R. E. 'Susee, Manager, Planning and Scheduling

-J. M. Anderson, Manager, Trojan Materials

E. B. James, Outage Manager

'.P. A.lMorton;-Branch Manager, Plant Systems Engineering

R.,L. Russell, Branch Manager,' Operations-

- T. 'O. Meek, ' Branch Manager, Radiation Protection

Di L. Bennett, Branch Manager, Maintenance

r S. A. Bauer, Branch Manager, Nuclear Regulation

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R. C..Rupe, Acting Operations Branch Manager, Quality Assurance

R. H.' Budzeck, Assistant Operations Supervisor

R. A. Reinart, Instrument;and Control Supervisor

.A..M..Puzey, Office Supervisor--

M.~D. Gatlin,. Warehouse Supervisor

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F. Levin, Supervisor, Plant Modifications,

R. Pre'witt, Quality Systems Supervisor

.D. A. Desmarais, Mechanical < Engineer, NPE

The. inspectors also interviewed and'. talked with other-licensee employees

during the course of the. inspection. .These included shift supervisors,

reactor and auxiliary operators, maintenance personnel, plant technicians-

and engineers, and quality assurance personnel. -v

• Denotes those attending the exit interview.

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' 2. Plant' Status

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, The plant operated at 100% power from March 26, 1989, until April 6,

.1989,1when the reactor was shutdown to begin the 1989 Refueling Outage.

' Major activities planned for the Outage, scheduled for sixty-five days,

were refueling, eddy current examination of incore flux thimbles'and all

tubes of all four steam generators, reactor vessel inservice inspection,

replacement of hee degraded electrical cabling, main generator

inspection and high pressure turbine inspection. Thusfar, outage

inspections have identified an indication on the

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"A" Reactor Coolant Hot

Leg Nozzle that appears to be within code allowable; a potential'10 CFR

21 issue with Amphenol (Bunker-Ramo) containment electrical penetrations

in that.some 14 gauge wires appear not to have been properly crimped and

pulled out of the penetration: connector; and; abnormal wear of the main

-generator rotor windings.

3. Operational- Safety Verification- (71707)

During this inspection period, the inspectors observed and examined

activities.to verify the operational safety of the licensee's facility.

The observations and examinations of those activities were conducted cn a

daily, weekly or biweekly basis.

Daily the1 inspectors observed control room activities to verify the

licensee's adherence to limiting conditions for operation as prescribed

in the facility Technical Specifications. Logs, instrumentation,

recorder traces',, and other operational; records were examined to obtain

information on plant conditions, trends, and compliance with regulations.

On occasions with a' shift turnover in progress, the turnover of

information on plant status was observed to determine that pertinent  !

information was. relayed to'the onconiing shift personnel.

Each week the inspectors toured the accessible areas of the facility to

observe the following items:

(a); General. plant'and. equipment conditions.

(b) Maintenance requests and repairs.  !

(c)' Fire hazards'end fire fighting equipment. j

(d) Ignition sources and flammable material control. '

(e) Conduct of activities in accordance with the licensee's

administrative controls and approved procedures.

(f) 7nteriors of electrical and control panels.

(g) Implementation of the licensee's physical security plan.

(h) Radiation protection controls.

(i) Plant housekeeping and cleanliness.

(j) Radioactive waste systems.

(k) Proper storage of compressed gas bottles.

Weekly, the inspectors examined the licensee's equipment clearance

control with respect to removal of equipment from service to determine

that the licensee complied with technical specification limiting

-conditions for operation. Active clearances were spot-checked to ensure

that their issuance was consistent with plant status and maintenance

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evolutions. Logs of jumpers, bypasses, caution and test tags,were

examined by the, inspectors. , ]

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In a review of plant-logs of the' scheduled shutdown refueling outage,'the,

inspectors noted that entry into Mode 2 was not' noted in the _ control room .

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- log or in the shift supervisor turnover checkoff list. Discussions ~ with

the involved operations shift crew indicated they were aware of the mode ~

change. The operators attributed the failure;to record the mode chang'e.

q primarily to the occurrence of the feedwater isolation event"(discussed i

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in section 5) which required various operatoF response _ actions. The.' i

y'a inspectors considered the apparent failure to" document thi's change in

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plant condition to be an apparent violation of procedural requirements

. outlined ir Administrative Orders A0-3-6, Revision 17, titled " Conduct of "

f Operations, Shift Records"-(50-344/89-10-01). Insp'ection/ report '

50-344/89-05 documented a failure to record a containment entry iri the

control room log. These two instances indicate the need for inc'reased

management attention. ,

Each week the inspectors. conversed with operators in the control room and

with other plant personnel. The discussions centered on pertinent topics

relating.to general plant conditions, procedures, security, training and

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-other topics- related to in progress work activities.

The inspectors examined the licensee's nonconformance reports (NCRs) to

confirm that deficiencies were being identified and tracked. Identified

nonconformances were being tracked and followed to the completion of

- corrective actions.

Routine inspections of the licensee's physical security program were

performed in the areas of access control, organization and staffing, and

detection and assessment systems. The inspectors observed the access

control' measures used at the entrance to the protected area, verified the

integrity of portions of the protected area barrier and vital area

barriers, and observed in several instances the implementation of

compensatory measures upon breach of vital area barriers. Portions of  ;

the isolation zone were verified to be free of obstructions. Functioning

of central and secondary alarm stations (including the use of CCTV

monitors) was observed. On a sampling basis, the inspectors verified

that the required minimum number of armed guards and individuals

authorized to direct security activities were on site.

The inspectors conducted routine inspections of selected activities of

the licensee's radiological protection program. A sampling of radiation

work permits (RWPs) was reviewed for completeness and adequacy of

information. During the course of inspection activities and periodic

' tours of plant areas, the inspectors verified proper use of personnel

monitoring equipment, observed individuals leaving the radiation

controlled area and signing out on appropriate RWP's, and observed the

posting of radiation areas and contaminated areas. Posted radiation

levels at locations within the fuel and auxiliary buildings were verified

using both NRC and licensee portable survey meters. The involvement of

health physics supervisors and engineers and their awareness of

significant plant activities was assessed through conversations and

review of RWP sign-in records.

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dne vio'lation and no deviations were identified.

4. Maintenance (62703)

'The inspectors _ performed a documentation review of selected maintenance

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requests (MRs) associated with containment electrical penetration module

seal . replacements and selected maintenance requests for the pull testing

of 14 gauge wire on various Bunker-Ramo (Amphenol) electrical containment

. penetration modules, and observed selected wire pull tests.

During.a November 1988 forced outage'some containment electrical

- penetrations were observed to exhibit greater than expected local leak

. rates. Additionally, during excessively cold periods during the

1988-1989 Operating Cycle'several containment electrical penetrations

exhibited very high local leak rates. The licensee in response to the

high leak' rates planned to clean or replace the seals of these electrical

. penetrations during the 1989 Refueling Outage. The inspectors reviewed

MR 89-0917 and.MR 89-0918 whose scope was to inspect, clean and/or

replace seals for containment electrical penetration BZ01 and BZO3,

respectively. The inspectors noted pen and ink changes to the work

' instructions that were initialed, however not by any of the original

signators of the work request, but not dated. Industry. practice suggests

either the work group supervisor or the originator of the maintenance to

, initial and date the changes to documentation. Trojan Administrative

Order (AO), "Maintenace Requests" does not address changes in scope of

MRs. In.this case the change in scope was more conservative in that

instead of cleanF.g the seals the seals were to be replaced. Also,

requirements fce post maintenance testing changed during the course of

the maintenance.

During the replacement of the seale t3r containment electrical

penetration BZO3,,the maintenance aftsman'noted a disconnected wire.

The-craftsman contacted the cogniz.nt engineer for evaluation. The

evaluation concluded the wire had been previously recognized and

docun,ented as being disconnected; however, the . reason for the wire being

disconnected was unknown. During the course of the evaluation, the

cognizant engineer on Wednesday, April 26, 1989, without consulting

management or having a work request to permit troubleshooting of the  !

problem, pulled on oth'er 14 (AWG) gauge: wire in the G module of

containment penetration BZ03 to ascertain if other-wires were loose. In

fact, other wires in this ' module did pull out. The engineer then

reported his findings'to his'immediate supervisor _for resolution. On

Sunday, Apri1 ^ 30,1989, the licensee'made a courtesy Emergency

Notification System'(ENS) report to,the NRC and informed the Resident

Inspector of the potential concern over the electrical integrity of the

- Bunker-Ramo (Ampbenol) containment' electrical penetrations. On Monday,

May 1, 1989, the inspectors met with plant managers to obtain additional

background information on this event. The inspectors expressed concern

that troubleshooting of a problem was being conducted without an approved

maintenance request, knowledge of operations shift management or plant

management. The Manager, Technical Services stated that the j

investigation conducted by the engineer was within the scope of the j

. engineer's authority, that the cables within that penetration were

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de-energized and there was no safety implication. The inspectors also

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questioned the channels of communication in that plant management was not

notified of.the problem until Saturday, April 29, 1989.

During the week of' April 30, 1989, a plan was drafted to pull test

various 14 and larger AWG wires of the containment electrical

penetrations. The scope of the wire pull tests was to pull test enough

wires to have a high confidence about the integrity of the wire

connections. The tests were documented on maintenance requests for each

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penetration. The inspectors observed selected pull tests and found the

tests were planned, had quality coverage and were documented. The pull

test for the 14 AWG and larger wire was conducted using a spring scale

device. The pull tensions used were based on the wire size. The

inspectors in discussion with an engineering supervisor concluded that

the pull tests may not be testing the integrity of the electrical

connection but Nsy only be testing the adhesion between the wire ,

insulation ano L e Soft epoxy seelant of the penetration module.

At the conclusion of the inspection period, the licensee was continuing

to pull test the 14 AWG and larger wire and was considering testing of

smaller gauge wire. Additionally, the licensee was considering, based on

the findings of the pull tests, submitting a 10 CFR 21 report (such a

report has been submitted subsequent to the end of the inspection

period). The scope of the pull testing had expanded during the course of

the testing because additional wires continued to pull free from their

connection. This is an open item based on resolution of troubleshooting

without an approved maintenance request, the need to understand the basis

for the pull test and the safety significance and corrective actions for

the problem (50-344/89-10-02).

5. Surveillance (61726)

Main Steam Line Safety Valve Testing

The inspectors observed portions of inservice testing of main steam line

safety valves PSV-2213, PSV-2233, PSV-2253, and PSV-2273. Safety valve

lif t set points were determined by in place testing with pneumatic assist

equipment. The testing was performed in accordance with applicable

sections of Maintenance Procedure MP-7-1, Revision 17, titled " Main Steam

Safety Valves Inservice Testing," and controlled by maintenance requests

MR 88-6946, MR 88-6947, MR 88-6948, and MR 88-6949. The work was

performed by a maintenance valve crew. The inspectors observed test

engineering and quality control coverage during performance of the valve

set point testing and verified that test instrumentation calibration was

current. A review of maintenance records and discussions with

engineering personnel indicated that required surveillance test frequency -

for main steam line code safety valves was being met.

Inservice Testing of Containment Spray Pumps

Unresolved item 50-344/89-05-02 dealt with review of inservice testing of

the "A" Containment Spray Pump (CSP). The inspectors questioned whether

the accuracy of the instrument used to measure vibration amplitude met

ASME Boiler and Pressure Vessel Code Section XI requirements. The

inspectors noted that calibration checks of the hand held vibration meter

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used in the-' inservice test observed by the inspectors specified a ,

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1 tolerance of plus.or.minus one mil. . The inspectors understood-the -!

reference:value as defined in Section.XI for. vibration for this pump was

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e . one mil.- This'would in turn require an instrument accuracy of plus or

6 minus 0.15 mil per paragraphs.IWP-4110'and IWP-4120 of Section XI. For, .i

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thellatest calibration check of vibration: monitor T-5410 as documented on

an I&C Form 6 approved December 16, 1988, the as-found and as-left

accuracy differed. from the desired output by 0.28 to 0.55~ mils at the a

five calibration check points. 'In addition, the inspectors understood-  :)

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i from discussions'with' maintenance and test engineering personnel that the 1

L - manufacturer * s stated accuracy of- the vibration instrument and associated j

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J. , - probe. ap' pear to be .in this case less the requirements 'of Section XI. This .I

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is an apparent violation (50-344/89-10-03). l

0 The inspect $rs discussed the other; concerns outlined in the unresolved l i

item with test; engineering personnel ~and a NRR representative. Licensee :f

' representatives stated that the applicable data sheets will be revised to 't

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explicitly date the ' allowable value'for

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bearing. temperature. With

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. regard to the analysis of test data within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> per paragraph

- IWP-3220. of Section XI; the inspectors understood that the licensee

., p.rogram ' consisted of compar,ing test-values against required action ranges

- within .96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> and'against alert. ranges,in a manner to require ' that -

alert testingcis performed on a. timely basis. The inspectors considered

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. that-this was not cle'arly inconsistent with Section XI requirements.

< This item was discussed with a regional specialist inspector. for possible

follow-up;in routine inspections. Based on the above, unresolved Item

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50-344/89-05-02 is considered closed.

- One' apparent violation and no deviations were identified.

6. Event Follow-u'p'(93702, 92701)

During the scheduled shutdown and in the time period shortly following

entry into Mode 5, Cold Shutduwn, the plant experienced the events which

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are summarized below.

Feedwater Isolation

L On April 6,1989, during the planned annual refueling outage shutdown, a

lc feedwater isolation event occurred shortly after the control operator

tripped the main turbine per plant shutdown procedures. ' Turbine bypass

- valve.PCV-507A failed open, apparently due to a failed pneumatic

- controller associated with the valve. This resulted in a high-high water

level in-the "C" steam generator. Per design, a feedwater isolation

occurred which in turn resulted in the trip of the operating main

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- feedwater pump. With both main feedwater pumps tripped, the auxiliary

feedwater system automatically started and resulted in the isolation of

steam generator blowdown valves. The licensee initiated an internal

event report for the occurrence and made a timely ENS report for an

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engineered safety feature actuation.

H The inspectors reviewed plant records, discussed the event response with

, involved operators, and subsequently reviewed the licensee's preliminary l

< . event evaluation with plant management during an April 10, 1989 meeting.

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During the event, an air li' en' connected to the pneumatic controllers s-

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associated.with PCV-507A-failed. Based on the-sy' stem engineer's event,

? observations and preliminary evaluation, the licensee-believed the. air

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iline failure resulted.from und was.not the cause of1the' valve l failure. 7A

maintenanc'e request was written for the pneumatic' contro11es. PCV-507A-

. was quarantin'ed for failure analysis, and metallurgical evaluation of the

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failed'11ne was planned as well as inspection of similar salves for *

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!g'eneric' problems. : The licensee is planning to replace th'e' rigid: air;11ne

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gjShutdown Bank "A" Fail'ure to' Manually Drive-In

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While manually inserting control rod banks in accordance with the

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shutdown. procedure 'the operators were unable to insert Shutdown Bank "A"-

, and a-rod control. system urgent' failure alarm'was received. At the time,

all other centroitrods in control banks and shutdown banks were' fully

inserted; ,After. consultation with. maintenance personnel, operators

manually; opened.the reactor trip breakers and all withdrawn rods fully-

i~' inserted.- At the: time.of inspection, the cause of this event had not 4

been determined. .The licensee's evaluation included a r'eview of past

maintenance records and consultation with the vendor. Further

' examination.will'. be performed when the rod control system is re-energized

prior-to reactor startup. Repair and understanding of this event is a

, -licensee ready'for startup item.

Main Steam (MS) Drain Valve Failure"to Isolate on Auto-Isolation Signal

In' Mode 3 while performing surveillance testing on the "A" main steam

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-line~, drain valve CV-2297 failed to close on a '!B" train steam line

isolation signal. '

The licensee preliminarily identified the cause'as a

failed solenoid valve on ~ the instrument air.line to the valve operator

and-issued a maintenance request for the' component. Main steam line

drain valves.for the other three main steam lines (CV-2294, CV-2295, and

CV-2296) closed on testing but reopened when the actuating switch was

released by theioperator. Within four hours, required by Technical

Specifications for. containment isolation valves, operations personnel

declared'the valves inoperable and secured the valves in the closed

position through~the use of clearance danger tags. Licensee review of

electrical drawings showed that the applicable "B" train circuits had-no

seal-in relay for valve closure-in contrast to those associated with an

"A". train steam line isolation signal. 'In discussions with'the '

inspectors,' plant management representatives indicated that there may be

an engineering basis for the lack of "B" train seal-in relays, and that

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the valves would remain closed on a "B" train l isolation signal as long as -

s- the signal was present. The licensee planned to evaluate whether a

design change would be. required, and, if not, to provide a documented '

basis for the lack of '!B" train seal in relays.

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.a Failure of Control Room Ventilation Dampers to Close within Surveillance

fp Time Requirements t ,

g- In Mode 3, Hot Standby, while performing response' testing of various. _

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engineered safety features, control room ventilation dampers DM 10501 A/B

j :and DM 10504 A/B failed to close within the. Technical Specifications

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required three seconds.in. response'to a safety injection signal. The

, -dampers ~1s'olated in approximately four seconds. These four air operated

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dampers. isolate the normal control'. room ventilation system, CB-2, from

? the control room envelope. In response, the licensee declared.both-

I trains of the' emergency' control room ventilation system, CB-1, to be

v  ; . inoperable given the effect of CB-2 isolation on th'e ability of CB-1 to

L' 1 pressurize the control room envelope. With both. trains of CB-1

inoperable, the: licensee entered technical specification 3.0.3., secured .)

s. the.four dampers in the closed position, and made timely ENS report to

p' 'the NRC.; The inspectors discussed the event with_ involved operators'and

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.the' system engineer,-and verified that adequate controls were established" '

N .in a timely manner,for the isolation dampers. At the time'of inspection,

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the licensee was reviewing previous test data on the dampers,. conducting

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i -additional testing and reviewing testing methods and the basis for the d

te.,t'. acceptance criteria. This item is identified as a ready for startup

item for' resolution.

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Containment. Spray Header Structural Support Elements

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With the plant.in Mode 4, Hot Shutdown, the.l'icensee declared both trains

of the Containment Spray. System inoperable; based'on. engineering j

evaluation of an inspection of structural elements which support J

. containment spr5y sys' tem headers _atithe 205 foot elevation of l

containment. With both' trains inoperable,fthe plant entered technical

speci fi cation m3. 0. 3.' In respons , the licensee made an ENS report to the

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NRC.-and placed the plant in Mode 5. The, limited' inspection found'that

certain supporting, legs of the eight containment: air coolers located ~

.inside containmentfwere not supported as expected on their respective

structural channels. #These" channels also providedJsupport to'the spray

headers of the Containment Spray System. Antengineering evaluation by

licensee and architect-engineer personnel concluded on a conservative

basis that the"unsxpected loading! configuration could affect the seismic

response capabilityfof both the co'tainment

n air coolers, which are.

required in Modes'1 through 3, and the' Containment Spray System. 1he

( evaluation also concluded that' the as-found conditions did not create

f Seismic II/I concerns for equipment located below the 205 foot elevation.

Based on discussions'with the engineers involved in the inspection and

review of applicable drasings, the' inspectors understood that the

engineering evaluation was based on a limited scope inspection, to be

augmented by additional detailed inspections, and was primarily based on

, engineering judgment pending further analysis and stress calculations.

On a preliminary basis, the licensee attributed design or construction

error as the cause of this event. The inspections were performed as part

.of the continuing followup to the licensee's pipe support verification

program which was implemented in response to pipe support issues

. identified during the 1987 Refueling Outage. Nonconformance report NCR

- 89-095.was. initiated to evaluate the inspection findings. In an exit

~ meeting with Plant Management held on April 14, 1989, the inspectors

indicated NRC interest in this event and the results of the licensee's ,

' eval uati on. The inspectors will continue to follow licensee actions and

consider this to be an open item (50-344/89-10-04).

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Minor Radiation Release during Containment Equipment Hatch Removal

,In 'the. process of opening.the containment equipment hatch, the auxiliary j

j. ' building-ventilation system process radiation monitors alarmed at their

j

alarm setpoints. Containment atmosphere pressure'was approximately 0.6

'

psig at'the time of the event. Preliminary licensee evaluation indicated

'that the refueling vendor crew failed to leave four equally spaced bolts,

as specified in the applicable maintenance procedure, in removing the z

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equipment hatch bolts,-which resulted in the formation of an  ;

approximately one to two inch gap between the top of the hatch and its <

seating surface. With containment at a relative positive' pressure, ai'r

flow occurred from. containment atmosphere into.the auxiliary and fuel

buildings. In response to the process radiation monitor alarms, the-

licensee restricted access the auxiliary building and rebolted.the hatch

with four evenly spaced bolts. The inspectors verified.in discussions

with chemistry personnel that Ter nical Specifications' release limits

were not exceeded. In discussicas with, plant management, the inspectors

understood that the licensee was evaluating the performance'of the work

at the given~ containment' atmosphere. pressure and additional work control

aspects of the event. This violation is not being cited because the

criteria specified in Section V.G. of the Enforcement Policy were

.

satisfied (NCV 89-10-05).

Failure of RHR Suction Isolation Valve Permissive / Interlock'

!

During surveillance testing in Mode 5, Cold Shutdown, motor operated

valve MO-8702, t ocated on the Residual Heat Removal System suction line

from reactor coolant system (RCS) loop 4 hot leg, failed to isolate on a

simulated RCS pressure signal of 600 psig. Valve MO-8701 located in

series on the same suction line tested satisfactorily. Preliminary

~1icensee evaluation identified an apparent polarity reversal in the

wiring between the instrument loop and bistable module PB-405 A/B, i'

apparently resulting from.1988 Refueling Outage work related to

modifications on the remote shutdown station. The polarity reversal made

ineffective interlock and permissive features for MO-8702 which isolates

, the valve on an increasing RCS pressure at 600 psig and which allows the

opening of the valve on a decreasing RCS pressure at about 425 psig.

Immediate operator action in response to this event was placen:ent of the

control switch for M0-8702 in the pull-to-lock position with the valve

open. In discussions with Plant Management, the inspectors understood

that post modification testing for remote shutdown station related work

failed to identify this problem and was considered a startup hold for the

current refueling outage. Inspection of this event was documented in

Special Inspection Report 50-344/89-13.

For events discussed in this section, the licensee had initiated internal

event reports to forther evaluate each event. Critques with involved

personnel werE also held by the licensee shortly af ter event occurrence

.to develop initial evaluation results. The inspectors met with plant

management on April 10, 1989, to discuss each event and the results of

the event evaluations available. The inspectors will continue to follow

these items in the course of routine inspections.

One violation and no deviations were identified.

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Follow-up of Licensee Event Reports'(90712)-

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J a.- The following LERS were closed based on in-office review, inspector

verification. of the(implementation of selected' corrective actions

. . .

...

Jand licensee: commitment to perform future. corrective actions:

&

".LER'88 19. Revision 2, (Closed),=" Surveillance Required by

Technical. Specification Not' Performed Following Containment

Hydrogen Vent System Adsorber Replacement". This-revised LER-

'provided> additionalt information concerning an event in which the

1. ; .wrongladsorber(bed df the Hydrogen Vent wasl replaced.resulting in.

the t'B" Train ' Containment hydrogen vent system being inoperable ~ for .  !

l eleven' days. :The . licensee concluded the cause ofithe event was 'j

procedural: noncompliance and procedural inadequacy. Some corrective-  ;

.-actions the lice'nsee has taken are_ revising Administrative Order l

% (AO) 3-9 " Maintenance Requests" to discontinue the practices of- 1

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having' multiple work items on a single maintenance request and ' ]

attaching corrective maintenance items to a preventive maintenance 1

- work request, training maintenance personnel on properly documenting )

verbal instruction. and requiring the ' labeling of sample. The i

licensee did.not. improve the halide testing method for evaluating i

the efficiency of,the charcoal adsorber, therefore, it is likely

future testing of the. charcoal adsorber beds will have to be i

reperformed.

LER 88-31, Revision 1, (Closed), "Of fsite Power Sources Not-

Demonstrated Operable Per Technical Specification - Personnel

' Error". This revised LER provided additional information on the

'

intended corrective actions to prevent event recurrence. By June

30, 1989,- the licensee wi1* implement ~ a new procedure on shift

turnover to' prevent' future missing of surveillance.

LER 88-36, Revision 1, (Closed), " Personnel Error.Causes Partial

Containment Isolation Signal Lock-in". This revised LER provided

. additional information clarifying why the event was not initially-

recognized as reportable. As corrective action the licensee will

revise Nuclear Division Procedure (NDP)~600-3, " Event Reports" as to

what constitutes an Engineered Safety Features Actuation.

'

LER 89-02, Revision 0, (Closed), " Steam Generator

Pressure / Temperature Surveillance Not Performed - Procedure Not

Followed". This LER described a licensee identified event in which  !

primary pressure was recorded once every eight hours vice every hour

as required by Technical Specifications. Surveillance procedure,

POT' 24-1, "Shif t Operating Routines," required hourly reading;

p- however, due to RCS temperature instruments being out of service an

alternate (nonrepresentative) temperature indicator was used. The

' indicator, a thermocouple mounted on the shell of the steam

generator, did not provide an accurate indication of primary

temperature. Additionally, the Operations Organization did not

properly deviate the surveillance procedure as required by

. administrative procedures nor was an engineering evaluation

performed on the appropriateness of the alternate temperature

indicator. Historically, the licensee has had a casual approach to

,

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procedure' compliance and, even though the licensee has increased:

emphasis'in this area, based on.recent events, increased _vigilence

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b -is warranted. As corrective actions the' licensee has clarified the

-

surveillance procedure'and issued a Lessons' Learned Summary that

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- , . highlights:the casual approach to. procedure. compliance 1and described

4 the desired-response. : The. inspectors verifled the surveillance

'

,

procedure had been changed'and the Lessons. Learned Summary was

placed in Operator Required Reading.

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..'LER 89-03, Revision'0 and Revision 1 (Clos'ed), " Spurious Chlorine

J

4' ' Monitor Signal- Causes Control Room Ventilation Isolution

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' Actuation". This LER and its revision described an event in which.

both trains'of the Control Room Emergency Ventilation' System were

'

rendered inoperable while performing surveillance testing. The

licensee concluded that inadequate work instruction permitted th.e.

H mixing of chemicals in the vicinity of both' chlorine sensing

'

devices,!and.that this' resulted 'in the isolation of both trains of

,, the Emergency Control Room Ventilation System. .As corrective action

H ;the surveillance . procedure was changed to provide definitive

guidance on where and how chemicals are to be mixed, a training

,

sesision on chlorine detectors and their impact on emergency. control

, room ventilation'is. planned and.a design change is being evaluated

~

,

, ,

' to enable ^ overriding of the. toxic' gas interlock on the CB-1 outside

air dampers.. The inspectors attended the critiques concerning'this

~

event, verified the surveillance' procedure had been revised and

_ ,  : observed the, performance of the revised procedure.

'

LER 89-04, Redision 0, (Closed), " Lack of Procedure Causes

- Containment Ventilation Isolation Signal on Iodine Background

Increase in Containment". This LER describes an event in which a

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'

Containment. Ventilation Isolation Signal-resulted.from not having a

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requirement to periodically adjust alert and' alarm setpoints of'the

iodine '(PRM-1B) radiation monitor. as background radiation levels , ,

increased. Additionally, administrative practices of' recording as '

left-as found setpoints and operators knowing the; settings'.for the3,

alert and' alarm setpoints were weak. As corrective action; the

'

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~ , licensee. issued Operations Procedure OM-5-1-3 that required process '

%: 1 radiation monitors-(PRMs) setpoints periodically be compared with' '

g,4 actual background levels and adjusted when levels. change by greater ,, ,'

53= than 25L The inspectors verified Operating. Procedur'e 0M-5-1-32had

"

,

been implemented, that setpoints were being. recorded and plant *

1 operators were knowledgeable of the new requirements. Additionally,

the inspectors attended the licensee critiques of the event 'and

discusses corrective actions and concerns with licensee management.

.e

LER 89-05,' Revision 0, (Closed), "High Energy Line Break Barrier ,

This LER described an

' '

Non-Functional - Af fects Both Safety Trains".

event in which Technical Specification 3.0.3. was entered for

approximately thirty-five minutes due to a high energy line break

and fire door (door 131)'not latching because an abnormal

ventilation line-up existed. As corrective action the licensee is

processing a design change to reverse the opening direction of the

door so that air flow will force the door shut vice open.

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~ Additionally, the licensee evaluated all facility doors for this

( anomaly and will perform appropriate design changes.

b. The following'LERs are closed based on inspector follow-up that

included discussions with licensee' representatives,' detailed event

evaluation, verification of appropriateness and implementation of:

corrective actions and licensee commitment to perform future

corrective action:

LER 87-33, Revision l'(Closed),' Main Steam Pressure Transmitters

Out-of-Calibration: Revision 0 to LER 87-33 discussed several

potential causes.for this event in.which all 12 main steam line-

E pressure' transmitters were found to have' a zero shift of 21 to 50

psig in October.1987 In response to ah NRC request for

information with regard to the licen.se'e, continuing evaluation,

' Revision.1,was^ submitted,which stated that'the observed zero shift i

was;the; result of instrument drift. The-inspectors reviewed a  :

portion if the' licensee evaluation result's'and discussed the results

.

'

with. licensee engineers, maintenance itersonnel, and licensing

representatives. The inspectors understoo'd that the. evaluation

concluded that although personnel error in the calibration process

could not be definitely. eliminated as a potential cause, it was not

the likely cause given that two different technicians _were involved

in the initial calibrations of the transmitters when they were

installed during the 1987 refueling outage. Licensee and vendor

review of the instructions for checkout, testing, and initial

~

transmitter calibration did not identify deficiencies which would

have' caused the observed zero shift. In addition, licensee "

i

engineers concluded that the new transmitters had been cycled three

times prior to installation per the vendor instruction manual. The  ;

licensee's determination of instrument drift as the event cause was l

based on results of its continuing monitoring program since October t

1987 of the main steam line pressure transmitters which has shown a j

continued tendency for negative instrument drift. Observed drift,

however, has been less than that observed in October 1987-and less l

than the: manufacturer's specified 1% per year drift limit. Licensee  ;

review of information from the Nuclear Plant Reliability Data System  ;

..

'

showed a number of reported instances of instrument drift for the

applicable transmitter. In the review of Revision 1 of the LER, the

inspectors noted that the component failure information requested on

the LER form apeared to be incorrect. .This was discussed with the l

LER writer for accuracy of future reports. Although the inspectors  ;

do not necessarily agree with the determination of the event cause, i

the inspectors considered that the licensee had evaluated other

potential causes and had implemented a monitoring program, as

described in Revision 1, with the purpose of providing confidence

that the pressure transmitters would continue to fulfill their

safety functions. This item is closed. i

No violations or deviations were identified.

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8. Followup of Open Items (9?700) ,

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. Temporary Instruction 2515/101 (Closed) Loss of Decay Heat Removal: The

inspectors conducted an inspection of licensee actions in response to'NRC

Generic Letter. 88-17..which dealt with loss of decay; heat removal during

nonpower operation. The inspection followed the guidance given' in

Temporary Instruction 2515/101 to the NRC Inspection Manual,4 titled " Loss

.of Decay Heat Removal (Generic Letter No. 88-17).10 CFR 50.54 (f)." The'

scope of the inspection was limited to licensee expeditious?

' '

actions, as,

defined its GL 88-17.

. The:11censee's response to the en iitious actions identified in Generic

Letter 88-17 was submitted in a January 16, 1989, letter. The inspectors

reviewed the response and verified implementation of. selected features

through review of plant procedures, discussions with ' operations,

licensing, and training personnel, and plant observations. In accordance

with.T1 2515/101, the inspection was performed prior to NRR! evaluation of

. the licensee's response given that the plant was in an outage that

involved a reduced inventory condition. The plant's initial entry into a

reduced inventory condition, subsequent to the issuance of TI 2515/101,

was on April 18, 1989, to allow draining of steam generator tubes and

~ installation of blank flanges on reactor coolant pump seal leakoff lines.

The inspectors reviewed training lesson plan 03-I-16-LP which covered, in

part, a discussion of GL 88-17 and licensee response actions. This

training was given to operators prior to the 1989 Refueling Outage.

Discussion with training personnel and review of detailed notes used by

the lecturer verified that the training included a discussion of the

April 1987 Diablo Canyon event and review of planned hardware,

procedural, and administrative changes implemented in response to the

concerns outlined in GL 88-17. In addition, Operation's Department

- supervisory and engineering personnel conducted pre-evolution briefings

for reduced RCS inventory operations with each shift crew prior to the

plant being p1rsed in a reduced inventory condition.

i

Overall. control . for plant operations in a reduced inventory condition was

effected by the issuance of General Operating Instruction GOI-12,

. Revision 0, titled " Plant Operation, Reactor Coolant System Reduced

Inventory and Recovery from Refueling." This procedure also provided

transition to other, more specific, procedures such as Administrative

Order A0-3-11, Revision 23, titled " Containment Access, Integrity,

Evacuation, and Inspections" which required the completion of closed

containment restoration plans for any open containment penetrations

,

.during reduced inventory conditions. The inspectors verified that

additional procedures provided for the assurance of two available means

'

of adding inventory to the reactor coolant system in the event of failure

of both residual heat removal pumps, and provided controls for hot leg

flow paths. GOI-12 included general guidance on the avoidance of

operations that would lead to reactor coolant system perturbations. In

addition, during the entry into reduced inventory conditions on April 18,

the Operations Department provided for 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> shift coverage by

engineers' knowledgeable with GL-88-17 concerns to assist the operation

shift supervisor in the review of activities which may perturb the

reactor coolant system or connected systems during reduced inventory

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e 'conditioris. Atthe' time!o[ inspection,thelicenseewasconsidering }{

additional or different controls to avoid reactor coolant system 1

l perturbations. 1

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? Licensee procedures'provided for the' monitoring of core exit temperatures

with two core exit thermocouple ~whenever the' reactor vessel head was ,

installed. .In addition Residual Heat Removal System performance was to-

'

be' monitor'ed by control room operators for system parameters such as pump

flow, amperage, discharge pressure, suction pressure, and inlet / outlet

' temperature < i ndications.

The licensee' reactor coolant system level indication system consisted of ~

'two. standpipes connected'to the "B" and "C" loop crossover legs of.the

,_ . reactor. coolant system. One standpipe, joined piping. associated with'

reactor coolant system flow transmitter FT-425 on the "B" loop;Lthe other

'

standpipe.' joined piping associated with FT-435 on the "C" loop. The

"" ,

standpipes were vented through permanently installed tubing to the top of

.the pressurizer shed. The standpipe associated with the "C" loop was

vented through. tubing which joined the spray line which enters the

pressurizer steam space. 'The vent path then used piping which leads to

'the pressurizer. power. operated relief valves, through manual valve 8094,

and.then through an open flange to the pressurizer shed air space. The

. standpipe associated with the "B" loop was vented through tubing which

connected.to piping upstream of manual valve 8094. The vent path was

then through the above mentioned open flange to the pressurizer shed air

space. Almough the. vent paths shared some common piping, the inspectors

considerea .at the two level indications were not inconsistent with the

guidance of GL 88-17 for independent level instrumentation. In addition,

the inspectors noted that the licensee provided an additional vent path,

.as allowed by thei.r procedures, by opening the pressurizer power operated

. relief valves,. draining.the pressurizer relief tank below the water

spargers, and replacing one of the pressurizer relief tank rupture discs

.. .with a screen.

Prior to the plant entering reduced inventory conditions, .the inspectors.

performed'a walkdown of the accessible portions of the level indication

system'outside high radiation areas. . The.' licensee had completed

modifications to the camera system which provided visual level indication

l' to the control room.' The modifications allowed in part control room

operators to. remotely tilt, pan, and focus the camera and allowed the

camera to be moved vertically over a 20' foot range locally te reduce

= optical parallax. In the walkdown, the inspectors identified that tubing

on the vent path.for the "B" loop standpipe was disconnected at a

swagelock fitting located in the pressurizer shed air space upstream of

l- the poin't at which the tubing joined the piping associated with manual

valve.8094. LThe tubing was:thus adequately vented in the as-found

'

,

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condition but'in'a different manner'than indicated by plant procedures.

, ;The plant was not in a reduced inventory condition. In response, the

L ' licensee initiated an; internal event report, completed level standpipe

walkdowns and no other discrepancies were identified, and connected the

l

--fitting prior to placing the plant in'a reduced inventory condition on

-April 18b l989. A critique led by plant management identified several

potential:causes for the disconnected fitting, and included a corrective

action to' require a walkdown of the system prior to use. Prior to the

,

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f; event, auxiliary operators had conducted limited shiftly inspections.of

L . the standpipes primarily for system leaks and discrepancies at steel to

gl. ass joints and glass to glass joints in the standpipes.

! In the review of licensee actions and in discussions with licensee

personnel, the inspectors understood that implemented actions differed

from those outlined in tne January 16, 1989, submittal in the following

respects. First, the licensee has not revised all plant procedures to

ensure that all operations.that may lead to perturbations of the reactor

coolant system were prohibited. This was changed to a longer term action

for consideration and compensated for by actions such as assigning 24

hour engineering coverage to support-the shift supervisor as described

above. Second, a single procedure incorporating all applicable

instructions.for draining the reactor coolant system and responding to a

loss decay heat removal was not prepared. The licensee had developed

G01-12 with the purpose of providing more definitive control over

operations during reduced inventory conditions and providing direction to

, operators for transitioning to other procedures. At the time of

inspection the licensee planned to submit a supplement to'their previous

response which would discuss these changes and discuss other additional

clarifications.

4

- No violations or deviations were identified.

,

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. 9. Unresolved Item .

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An unresolved' item is a matter about which more information isl required

r. to ascertain whether it is an acceptable item, a4 deviation,'or:a

^

1/ violation. An unresolved item is discussed in paragraph 51, >

10. Exit Interview (30703)

The inspectors met with the plant management as denoted in paragraph 1 on

May 19, 1989, and with licensee management throughout the. _ ,

inspection period. The inspectors also met with plant management on

April 14, 1989. In these meetings the inspectors summarized the scope

and findings of the inspection activities.

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