ML20125C742

Insp Repts 50-324/92-34 & 50-325/92-34 on 921003-31. Violation Noted.Major Areas Inspected:Maint,Observation, Surveillance Observation,Operational Safety Verification, Licensee self-assessment & Outage Activities

ML20125C742
Person / Time
Site:	Brunswick
Issue date:	11/18/1992
From:	Christensen H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20125C668	List: ML20125C665 ML20125C703 ML20125C742
References
50-324-92-34, 50-325-92-34, NUDOCS 9212140056
Download: ML20125C742 (18)

See also: IR 05000324/1992034

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g UNITED ST ATES

,f g NUCLEAR REGULATORY COMMISslO96

[ 'g' g RErlON11

g, nt 101 M ARIETT A ST RE ET. N W.

o '$ ATL ANTA, GEORGI A 30323

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.....

Report Nos.: 50-325/34 and 50 324/34

Licensee: Carolina Pnwer and Light Company

P, 9. Box 1551

Rtleigh, NC 27602

Docket Nos.: 50 325 and 50-324 ticense Nos.: OPR-71 and DPR-62

Facility Name: Brunswick 1 and 2

Inspection Conducted: October 3 - October 31, 1992'

Lead Inspector: 4 cc3 % 4Senig[r Res' ent inspector

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R. L. Prevatre, ~

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Date Signed

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Other inspectors: D. J. Nelson, Resident Inspector f

P. M. Byron Resident Inspactor

Approved By: k[

H. Chri~ stensen, Chief

D- Il f13 7L

Date Signed

Reactor Projects Section lA

Division of Reactor Projects

SUMMARY

Scope:

This rcutine safety inspection by the resident inspectors invo'Jved the areas of

maintenance observation, surveillance observation., operational safety verification,

licensee self-assessment, outage activities, organizational changes and quality

control inspections.

Results:

In the areas inspected, one violation was identified involving a reactor operator

with an inactive license standing watches (paragraph 4). Additionally, further

examples of Violation 325,324/92-28-02 were identified for failure to maintain g

positive control of visitors (paragraph 4).

Within the area of outage work activities some progress was noted in completing work

requests / job orders (WR/J0s). However, identification of new work negated progress

in backlog reduction of WR/J0s. A reduction in operator work arounds was noted

(paragraph 5).

Units 1 and 2 were in cold shutdown for the entire reporting period. The outage

that started on April 2), 1992, continuad with no announced startup date.

)- 9212140056 921127

PDR ADOCK 05000324

G PDR

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REPORT DETAILS

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1 Persons Contacted

Licensee Employees

K. Ahern, Manager - Operations Unit 2

M. Bradley, Manager - Brunswick Project Assessment

M. Brown, Plant Manager - Unit 2

, *S. Callis, On-Site Licensing Engineer

J. Cowan, Manager - Technical and Regulatory Support

J. Dobbs Assistant to Site Vice President

*S. Floyd, Manager - RegJlator.y Compliance

, *R. Godley, Supervisor - Regulatory Compliance

R. Helme, Manager - Technical Support

J. Holder, Manager - Outage Management & Modifications (0M&M)

• M Jackson, Manager - Maintenance Unit 2

M. Jones, Manager - Training

• P. Leslie, Manager - Security

D. Moore, Manager - Maintenance Unit 1

R. Morgan, Plant Manager - Unit 1

R. Richey, Vice-President - Biunswick Nuclear Project

C. Robertson, Manager - Envirnneental & Radiological Control

• J. Simon, Manager - Operations Unit 1

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• R. Tart, Manager Operations Unit 2

• J, Titrington, Manager - Operations Unit 1

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C. Warriner, Manager - Contract and Administration

E. Willett, Manager - Planning and Scheduling

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Other licensee employees contacted included construction craf tsmen,

engineers, technicians, operators, office personnel and security force

members.

l * Attended the exit interview.

Acronyms and initiailsms used in the report are listed in the last

l paragraph.

2. Maintenance Observation (62703)

The inspectors observed maintenance activities, interviewed personnel

and reviewad records to verify that work was conducted in accordance

with approved precedures, Technical Specificat-ions and applicable

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industry codes and. standards. The inspectors also verified that:

redundant components were operable; administrative controls were

followed; tagouts were adequate; personnel were qualified; correct

replacement parts were used; radiological controls were proper; fire

protection was adequate; quality control hold points were adequate and

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observed; adequate post-maintenance testing was performed; and

independent verification requirements were implemented. The inspectors

. independently verified that selected equipment was properly returned to

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service.

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. Outstanding work requests were reviewed to ensure that the licensee gave

priority to safety related maintenance. The inspectors ,

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observed / reviewed portions of the following maintenance activities:

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WR/JO 92 ABBR 1 thru 8 Bearing replacement and other outage

work activities on DG No. 1

Diesel Generator No. 1

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DG No. 1 inspections and maintenance activities discussed in the

previous report continued. The licensee identified additional problems

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with this DG. The damaged first idler gear and the broken teeth

(Inspection Report 325,324/92-28) were sent to CP&L's Harris

Environmental & Energy (E&E) Center and the consultant for failure

analysis. This analysis has not been completed.

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The four connecting rod bearings adjacent to bearings 6 and 9 were

disa m mbled and inspected. Even though no damage was observed, they

were reassembled with new bearings. Vendor services were obtained to

repair the minor scoring previously identified on the Number 9 bearing

j ourr.al . During the journal repair, the contractor identified that the

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crankshaf t was bowed approximately 0.002 inches.

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As part of the bowed crankshaft investigation, the generator stator

dowel pins were removed. The dowels were found to be slightly bent.

The inspector observed that the stator had shifted outward approximately

1/64 - 1/32 inches. However, it was also found that the stator base

paint was not disturbed, indicating that the stator movement was not

recent. The licensee is still investigating the cause of this movement.

The dowel pins were sent to the Harris E&E Center to determine the force

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required to bend them. This analysis had not been completed at the end

, of the reporting period.

On October 8,1992, cold crankshaft web deflection readings were taken,

lhese readings exceeded the allowable band of .002 inches. After

consultations witn former Nordberg engineers, the licensee decided to

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realign the crankshaft. This was accomplished by adding a 0.020 inch

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shim under the generator pedestal bearing to raise the crankshaft. This

4 returried the deflection readings to within specifications. Reassembly

of the engine was completed on October 13 and break in runs commenced.

The engine was run for 5, 15 and 30 minutes with no load and inspections

were performed after each run. On October 14, the unit was run for one

hour with a 900kw load. Post run inspections found thrust collar

temperatures above normal. Investigation revealed that the thrust

collars had experienced severe thermal stress. Metal displacement was

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i found on the bearing surfaces and radial cracking was identified at

several points on the outer edge of the generator side thrust collar.

The inspector observed that the radial cracking was more significant at '

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the top of the collar. He also noted some pitting of the lower shell of

the No. 9 bearing and that there were slight deposits of aluminu:n

bearing material on the thrust collars. The licensee subsequently found

i brass from the thrust collar embedded in the crankshaft thrust surface.

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On October 16, the licensee removed the oil seal assembly from the

generator end of the engine and found signs of excessive heating on the

upper assembly. The heat stress zone extended from about 280 degrees to

i 100 degrees of the radial area and was approximately 1/2 inch wide on

the inner radius. The inspector noted that the first of four labyrinth

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rings showed signs of heat stress. The housing and first two labyrinth

rings had rolled edges. The crankshaft at a corresponding axial

position was gouged approximately seven to eight inches long,1/2 inch

wide and several mils deep. Because of the above damage, the No. 9

. bearing journal and the No. 8 R and No. 8 L connecting rod bearing

journals were dye-penetrant tested. No damage was found.

l The licensee requested on site assistance from NAK Engineering Company.

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This company is composed of the former chief service engineer and other

former Nordberg engineers. They also held the engine _ design drawings,

The NAK representative has previously assisted the licensee in trouble

. shooting and identifying the causes of previous engine problems.

. The licensee took additional crankshaft measurements on October 17 and

j 18 and concluded that the crankshaft was bowed approximately 0.003

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inches. A marine engineering consultant was contracted to provide a

second opinion and assist in straightening the crankshaft. This

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consultant, after inspecting the crankshaft, determined that it had a

kink instead of a bow. The kink resulted in the No.10 journal being

! offset 4 mils from the No. 9 journal. The marine engineering consultant

believed that the damage was caused by high heat stress which had

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resulted from overheating of the thrust collars. He believed that the

crankshaft could be straightened by using a peening process to relieve

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the induced stresses. He also concluded that the damage in the area of

, the oil seal was caused by the crankshaft jumping. The licensee

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disagreed with his conclusion and believed the damage was caused by 4

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wobbling crankshaft. Neither party has been able to explain the cause

i of the phenomenon which they believed to have caused the damage. Two

representatives from the NRR staff were onsite October 21 and 22, and

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reviewed the problems associated with this engine.

On October 31, the inspector observed the crankshaft peening process. A

hand held pneumatic hammer was used to peen a point predetermined by

rotational clearance measurements on the engine side radius of No. 9

i- journal. The crankshaft straightened approximately .0005 inches. The

l Nos. 6 and 9 journals were then polished by the consultant to remove any

damage that resulted from the previously described failed bearings. A

! second peening operation took place November 2. The licensee then had

difficulty obtaining repetitive measurements while measuring to

determine the amount that the crankshaft had straightened. While

troubleshooting the cause of these inconsistent readings, the licensee

. discovered damage to the flexible drive gear located at the opposite end

(front) of the engine from the generator. The drive gear is attached to

the crankshaft and drives the engine driven lube oil pump. The

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inspector observed that damage occurred on the face of the gear teeth

for approximately 300 degrees The damage was about 1/4 to 3/4 inches

j in length and varied in height on the tooth face. It was noted that as

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the damage approached the root it occurred on both faces and appeared to

have been caused by impact. The licensee observed that approximately

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one-half of the lthe oil pump gear showed signs of thermal stress.

These gears had been previously inspected during the current outage. -It

was therefore apparent that this damage had occurred during the pest .

maintenance runs.

The licensee's diesel consultant, NAK, believed that the gear damage may

have been caused by movement of the diesel ard suggested that the

collision blocks be inspected. Collision blocks are steel blocks

attached to the engine skid by 1-inch steel dowel pins and 3/4-inch

bolts. There are two collision blocks on each side and ends of the

engine. They are used primarily in mobile and marine installations to

restrict engine movement in the event of a vehicle or ship _ collision.

The blocks can be used to determine if there has been any movement of

the engine block relative to the skid. An inspection' revealed that both-

collision blocks at the rear of the engine (generator end) were missing.

The collision blocks were found under the generator mounting . rails.

Investigation revealed that both the dowels and bolts were sheared at

the foundation surface and the bolts were missing. The inspector

observed thht the dowels remaining in the blocks were deformed. The

licensee calculated that the engine had moved approximately 1/4 inch

toward the rear, or generator _end. At the end of this reporting period -

the licensee was attempting to determine the cause(s) of all damage

sustained to DG No. 1. The inspector will follow the licensee's

investigations, inspections and repairs, and rrovide additional

information in the next monthly report.

On October 6, 1992, while observing maintenance on DG No. 1, the

inspector observed that material was improperly stored in an adjacent -

"Q" Temporary Storage Area. The storage area contained material with

unprotected threads and valves which did not have the openings covered

and were not tagged. The inspector -informed maintenance and QC of this

concern. The maintenance foreman stated that the untagged material was

to be scrapped. The scrap material ~ was immediately removed and placed

in a trash container.

Violations and deviations were not identified.

3. Surveillance Observation (61726)

The inspectors observed surveillance testing required by Technical

Specifications. -Through observation, interviews, and records review,

the inspectors verified that: tests conformed to Technical

Specification requirements; administrative controls were followed;

personnel were qualified; instrumentation was calibrated; and data was

accurate and complete.- The inspectors independently verified selected

test results and proper return to _ service of equipment.

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The inspectors-witnessed / reviewed portions of the following test

activities:

! OMST DG-50lR3 54 month inspection on~DG No. 3

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j PT 12.2 B DG No. 2 Monthly t.oad Test

j PT 12.2 0 DG No. 4 Monthly Load Test

' These above tests and inspections were well planned and managed with

j adequate supervisory and technical oversite.-

l Violations and deviations were not identified.

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4. Operational Safety Verification (71707)

The inspectors verified that Unit I and Unit 2 were operated in

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compliance with Technical Specifications and other regulatory

i requirements by direct observations of activities, facility tours,

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C.:;cussions with personnel, reviewing records and independent

l verification of safety _ system status.

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! The inspectors verified that control room manning requirements of 10 CFR

- 50.54 and the Technical Specifications were met.- Control operator,

shift supervisor, clearance, STA, daily and standing instructions and

jumper / bypass logs were reviewed to obtain information concerning

i operating trends and out of service safety systems to ensure that there

. were.no conflicts with Technical Specification Limiting Conditions for

Operations. Direct observations of control room panels, instrumentation

and recorder traces important to safety were conducted to verify

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operability and that operating parameters were within Technical

Specification limits. The inspectors observed shift turnovers to verify

l that system status continuity was maintained. -The inspectors also

verified the status of selected control room annunciators.

The inspectors verified the system alignment and operability of .

! equipment used for the normal and backup means for shutdown cooling on

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each unit. They additionally verified that there was no leakage of

major components; that proper lubrication and cooling water _was

j available; and conditions did not exist- which could prevent. fulfillment

!- of each system's functional- requirements. Instrumentation essential to

system actuation or performance was verified operable by observing on-

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scale indication and proper instrument valve lineup, if accessible.

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The inspectors verified that the licensee's HP policies and procedures-

were followed. This included observation of HP practices _and a review

-of area surveys, radiation work permits, posting and_ instrument

! calibration.

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The inspectors verified by general observations that: the secur_ity

l organization was properly manned and security personnel were capable of

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performing their assigned functions; persons and packages were checked.

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prior to entry into the PA; vehicles were properly authorized, searched

and escorted within the PA; persons within the PA displayed photo

identification badges; personnel in vital areas were authorized;

effective compensatory measures were employed when required; and

security's response to threats or alarms was adequate.

Three occurrences of failure to maintain positive control of visitors

were identified by the licensee during the assessment period. On

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October 2, 1992, an escort attempted to leave the protected area while

his visitor remained in the protected area eating lunch. This is

documented in ACR 92-793. On October 21, an escort was relieved t.t the

i end of his shift, but failed to notify security of the transfer to a new

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escort. This was detected by security when the escort attempted to

leave the protected area without his assigned visitor. This is

documented in ACR 92-847. The next day a security officer observed two

visitors without an escort. It was determined that the escort was in an -

adjacent area and did not have positive control of his visitors. This

is documented in ACR 92-846. These findings indicate that security

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office alertness has increased; however, it appears that other plant

personnel are not adequately trained in escort duties or that additional

. emphasis and oversite by supervisory personnel is necoed. The licensee

received a violation (Inspection Report 325,324/92-28) for failure to

maintain positive control of visitors on September 15, 1992. The

licensee's investigation of that event has not been completed and all

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corrective actions have not been identified. Therefore, the above

deficiencies will be identified as additional examples of Violation

. 325,324/92-28-02. In response to Violation 325,32/,92-28-02, the

licensee agreed to provide any additional correcth e action that is

being taken to address the above events.

The inspectors also observed plant housekeeping controls, verified

i position of certain containment isolation valves, checked clearances and

verified the operability of onsite and offsite emergency power sources.

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In early July 1992, a licensed reactor operator was removed from

licensed duties and placed in a rehabilitation program cfter his

admission of using a controlled substance contrary-to the requirements

, of 10 CFR 26 and subsequent positive testing. The individual completed

a rehabilitation program and his facility unescorted access was restored

on September 8. After a period of observation in unlicensed activities

he was returned to licensed duties on October 3, 1992. He was assigned

and assumed the licensed duties of Reactor Operator, Balance of Plant

(B0P), at approximately 7:00 a.m., on October 3, 1992. At approximately

9:00 a.m., while updating the accumulated watchstanding hours log for

licensed operators, the Operations Shift Supervisor discovered that the

subject operator had not completed the required 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> (five-12 h:.ur

shifts) of watchstanding in the previous quarter (i.e., July, Augusi. and

September). Upon discovery, the Shift Supervisor relieved this

individual of his assigned duties and placed him on watch in a training

status to begin license reactivation.

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10 CFR 55.53.e requires that in order to maintain an active license, the

licensee shall actively perform the function of an operator or senior

operator for a minimum of seven 8-hour or five 12-hour shifts per

calendar quarter. This requirement is implemented ii) the licensing

training instruction, NRC Licensee Operator / Quarterly Reporting

Requirements, TI-208, Volume 1, Rev 6. A review of the licensee's

accumulated watchstanding hour log by the resident inspector showed that

the individual did not stand any licensed watches during the July,

. August and September quarter.

Technical Specification 6.2.2.a and Table 6.2.2.1 list the minuum shift

composition for Unit conditions. The requirements spe.ify that for both

units in Condition 4, a minimum of two Reactor Operators shall be in the

control room. The licensee appears to have met this requirement.

However, the inactive operatnr was the only reactor operator at the

controls for Unit 2. The licensee states that the condition existed for

a very short period. A review of the SCO and C0 logs could neither

substantiate nor disprove that fact. However, the inspector noted that

he entered the control room on October 3 at approximately 9:00 a.m.,

reviewed the operating logs for both units and held a conversation with

the operator concerning his return to duty. At that time he and the

Senior Control Operator were the only licensed reactor operators on

Unit 2 and he was the only individual monitnring the Unit 2 Reactor

Control Board.

On Thursday, October 1, the Unit 2 Manager of Operations informed the

Senior Resident Inspector that the subject operator was being returned

to duty. At the time, he indicated that everything had been checked and

that a letter was being sent to inform the Regional Office that the

individual was being returned to a full duty status. However, a review

after this event reveals that when the individual was returned to an

l active status and reassigned to a shift on September 25, he met the

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requirements of 10 CFR 55.53e since he had stood more than five-12 hour

watches in the preceding quarter of April, May and June 1992. Based on

interviews with affected personnel, it appears that they did not realize

that the quarter would change prior to the individual being returned to

duty and did not perform an actual record review for the second or third

quarter of 1992. The review was accomplished by asking the operator if

he was current in his watch-standing. At the time he was questioned, he

was satisfactory.

The licensea, upon identification of this event, appears to have taken

the correct action of relieving the individual and reassigning his

duties to an active licensed person. The licensee initiated ACR 92-797

to document this event and determine the cause and required corrective

actions. The ACR stated that the immediate corrective action was to

summon a second R0 to the Unit 2 control room to assume the B0? operator

duties and place the above individual in a training status for license

re stora ti'"1. A review of the SCO and C0 logs does not confirm this

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action. Neither log shows that a new reactor operator assumed the watch

I after this event. The log does show that the involved B0P operator

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lined through his duty as B0P operator and changed it to Reactor

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Operator Trainee (ROT) with a date of October 3, 1992. Discussion with

the involved individuals indicated that the Plant Monitor Reactor

Operator was summoned back to the control room to assume the Reactor

, Operator watch. However, this was not documented in either the Reactor

Operator or Senior Reactor Operator log. This weakness and

inconsistency in the amount of information placed in Control Room logs

has been previously identified. Although improvement has been made,

logkeeping is still inconsistent between shifts and generally does not

contain adequate detail to document all significar,t shift occurrences or

allow recreation of events at a later date.

The inspectors became aware of the above event during a routine rev1ew

of ACRs the week of October 19, 1992. Inspection revealed the event and

4 the actions taken to restore the operator to an active status were

incomplete. 10 CFR 55.53(f) states that if the requirements of

10 CFR 55.53(e) are not met, then the licensee operator must complete a

minimum of 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of on-shift functions under the direction of an

operator or senior operator as appropriate and in the position to which

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the individual will be assigned. The 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> must have included a

complete tour of the plant and all required turnover procedures.

The inspectors interviewed the operator involved in the event and

reviewed the reactor operator logs for documentation of the required

training. This review revealed that the operator had used the hours of

watch he stood on October 3 as an unqualified B0P operator as a credit

i toward his required 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> for retraining after disqualification on

October 3.

The inspector then questioned the operator about when he completed the

requirements to return to active status and was told that he had

finished these on October 6. At this time he offered as evidence a

completed Form TI-208-5 used to certify completion of action required to

return to active status. The inspector noted that this form showed 40.5

hours which included the time in question on October 3, 1992. At that

time the inspector requested that security provide a security access

printout for this operator for the period of September 15 to October 27.

A review of this record determined that the operator did not complete a

tour of the plant between his removal from watch on October 3 and his

return to an active status on October 6. The Shift Supervisor signed

him off as completing the tour on October 4, but the inspector

determined that he toured only a few areas of the plant between October

3 and 4.

Questioning of this operator and the Shift Supervisor by Operations

Management revealed that the Shift Supervisor and operator thought that

they could take credit for a period of Auxiliary Operator watches the

individual had stood between October 15 and October 27 as adequate for

the plant tour and that he could take credit for the hours on watch as

an unqualified Reactor Operator on October 3 to meet the requirements.

A further review of the security access logs by the inspector and-

Operations Management determined that the individual had not toured all

plant areas during the Auxiliary Operator watch standing time. It also

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' revealed that the individual had not stood a complete four hour watch

thut he took credit for on October 6. He had credited 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> on

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Octobee 6, but had left the control room and the protected area of the

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' ant prior to completing those 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. In both instances, October 3

u i 00.tober 9, 1992, the operator was returned to an active status

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thout completing the requirements of 10 CFR 55.53. This is a

j ,iolation: Watchstanding With An Inactive License (325,324/92-34-01).

1 The licensee, upon becoming aware of the first event, removed the

! individual from an active licensed status and placed him in a training

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status. After the second event the watchstander was removed from

licensed duties until an investigation could be completed. The

j licensee's corrective actions to_date include: retraining and

recertification of the affected operator, personnel actions for the

Reactor Operator and Shift' Supervisor and improvements in the

! computerized scheduling system _to track watchstanding hours and posting

of all inactive licensed operators in the Shift Supervisor's office.

, This action will be completed by November 24.

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The licensee had prior notification that it might be susceptible to an

event of this nature. In 1989, an event occurred at a nuclear plant:

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where a senior reactor operator with an inactive license assumed the

' watch as operator at the controls. As a result of that event, an

inspection was conducted at Brunswick and other' plants in Region Il to

, determine the administrative controls in place to prevent an occurrence

j of this nature. Inspection Report 325,324/ 89-34_ determined that "no

program or administrative safety net existed to prevent unintentional or

a willful assumption of licensed duties by an unqualified licensed

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operator." That-report also stated the on-shift operations management

had no means in the control room to independently verify that on-watch

personnel are duly licensed. The report noted that no violations had

been identified concerning unqualified personnel performing licensed

duties ~since 1984.

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As a result of the above inspection, the licensee initiated a procedure

change to Licensee Watch Standing Log Operating _ Instruction 01-49,

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Volume VII, Rev. 3, Step 6.2.3, to require that the Day Shift Production

Assistant on the first Saturday of March, June, September and December,

forward a list to the Operations Manager of all personnel whose license

will become inactive at the end of the calendar quarter. This step

i provided approximately one month early notification to-allow remedial

l action before a license became inactive._ This step was deleted when the

above 01-49 procedure was revised on August 1, 1991, to clarify the

I- duties of the production assistant.

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Service Water Pioino

Through wall piping leaks have occurred frequently in the service water

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system. Through wall leaks are significant because, if not corrected,

L they could progress to failures rendering safety systems inoperable. On l

October 19, 1992, a through wall leak occurred in an 18-inch service '

water line running through the Diesel Generator No. 4, four day fuel oil

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tank room. This line is a branch from the Unit 2 Nuclear Service Water

Supply Header and provides the Unit 2 source for cooling all four DGs. -

Diesels No. 3 and No. 4 rely on this source as their primary heat sink

, with the Unit I source as an automatic backup. The opposite

. configuration exists for DGs No. I and No. 2. The one to two gallon per

i minute leak was temporarily repaired. Code repair will be affected '

i before restart. No adverse effects occurred. ,

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The leak occurred in a non-welded, straight run section of the pipe just

downstream from a flanged connection. The carbon steel pipe is cement

! lined. The cement lining is intended to prevent corrosive brackish

water from contacting the carbon steel. This material- combir:atibn was

! prevalent in the service water system a: originally constructed, but

most is being gradually replaced with corrosion resistant copper-nickel

j or stainless steel. The leaking section was replaced in 1985 in

conjunction with changing the upstream piping to co)per-nickel due to

underground leaks. The flanged connection became tie boundary between

, the new copper-nickel and existing carbon steel. This necessitated.

. replacing a short section of carbon steel with new carbon steel to

a accommodate the new flange connection.

Almost all leaks in service water piping occur at weld joints, including

1 some in copper-nickel. Since April 1989, 24 service water. leaks due to

! internal erosion / corrosion have been identified. Only three of these,

( including the one described above, have occurred in non-weld areas; but

i these represent three of the total seven leaks in cement lined carbon

. steel. In all cases, leaks in cement lined carbon steel are the result

of water penetrating the cement lining through cracks or seams. ,

l The remaining cement lined carbon steel pipe in safety significant

l applications is either scheduled to be replaced or visually inspected.

Inspected portions are large diameter pipe sizes that permit entry by

! personnel or remote controlled cameras. No other non-destructive

l- examination methods are routinely included, but in--progress corrosion

i areas are easily identified by the characteristic " rust plume" on the

cement lined internal surface.

No routine internal inspections or non-destructive examinations occur on

i carbon-steel piping that is scheduled for replacement. The current

i schedule, which extends into late 1995, includes all piping downstream

! of the leak described above that supplies the DGs and all Unit 1 DG

supply piping from its branch connection with the Unit.1 nuclear service

j water header. This includes hundreds of feet of-piping and many weld

j -joints. Of the-seven safety significant portions of cement lined carbon

steel pipe that developed leaks, four have occurred in these areas of DG

. service water piping.

i Two of these DG service water leaks occurred at 6 X 8 inch reducers near

L the connections to the DG jacket water coolers. These may be more

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susceptible to erosion / corrosion due to the flow turbulence induced by

I the : mall-to-large diameter change. However, the inspector concludad ,

l that many other susceptible leak locations exist in the DG service water

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supply lines. Most of this piping is too small for internal inspection;

therefore no surveillance is performed to assess the condition of the

piping and hence the failure potential. The majority of this is 6-inch,

non-insulated piping accessible within the DG building and therefore,

could be easily tested by ultrasonic methods.

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The service water system engineers are aware of the vulnerability to

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leaks in these areas and routinely walkdown accessible portions of this

piping specifically to locate leaks. The inspector concluded that while

this is prudent, more evaluation may be warranted in consideration of

the large portion of the system not inspected and the high safety

, significance of Failures in this ara.. URI 92-34-02; Service Water

q

Leaks.

Violations and deviations were not identified.

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5. Outage Work Activities (62703)(37828)

DGB & CB Walls

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Designs are issued on 59 of 61 walls that require repair or

modification. The two remaining designs involve DGB wall modifications

for tornado venting. The repair activities are approximately 75 percent

complete. It is anticipated that the remaining designs will be

completed in early November and work will be completed in December.

Engineering design and design changes have caused the majority of delays

in completing this project.

fWE/SW Booster luni

The 2A and 2C pum) motors have been inspected and refurbished. New pump

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motor baseplates iave been installed. The pumps have been mcdified with

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new pullout pump assemblies and supports have been added to the

discharge piping. Check valve slam tests were performed to verify that

check valve operation will not affect alignment. Extensive vibration

and thermal growth testing / analysis was performed to determine their

effect on alignment. Correct torque values and torquing sequences of

bolts have been determined and incorporated into procedures. The above

activities resulted in reduced vibration levels, lower bearing

temperatures and significant improvements in performance of the pump

motors. Additional work is currently being planned for Unit 1.

Double-D_isc Gate Valy35

Due to concerns noted by the BNP Motor-Operated Valve Task Group in 1988

in19ving the potential for thermal binding and/or bonnet

oveipressurization in certain flex-wedge gate valve applications, the

licensee embarked on a program to replace the valves with a valve type

which would prove to be less susceptible to these phenomena. Plant

modifications were developed to replace 22 flex-wedge gate valves in

both units, 20 of which were in 11RT applications. The applicable plant

systems include HPCI, RCIC, RUCU and Main Steam.

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Over the past several refueling outages,: the valves were replaced with

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Anchor Darling double-disc gate valves. Since the valves have been

installed, the plant has experienced an unusually high LLRT failure rate

of these valves. Eight failures have been identified in this outage.  !

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Several of the failures have ultimately been discovered to be.the result

of poor quality and workmanship during the valve manufacturing ~ process.

ACR 892-782 was generated to investigate the root cause of the failures.

! and to look into commonalities in the failures. The inspector will

! follow licensee activities on this item.-

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1 Reactor Recirculation System Rina Header Supports

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l This work activity is essentially complete except for shielding removal,

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insulation and grating replacement, turnover, and operability testing,

j Maintenance W3/JO Status

!, The current status of the backlog is as follows:

i

Completed Remaining

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Pre 4/21/92 Post 4/21 Since 4/21 In Backlog

. Mnit 1

i Outage 783 -962 858 887

Non-outage 993 3002 2291 1704

hiLZ

. Outage 673 1451 1202 922

Non-Outage 1582- 4319 3772 2129

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l The corrective maintenance backlog was reduced by approximately 200

i items during October. This progress has been very slow. Approxihiately

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5900 corrective maintenance items remained open at the end of October.

The pre-April' 21 backlog has been. reduced from 4465 to 1673 during the

outage. The initia1 ' screening of the overall backlog on a system

! priority basis was essentially-completed for 79 systems as of

i October 27. -Management review of the planned work on items to be

! excepted is still ongoing. Revision 0 of the startup schedule was

! completed, but is under further review and refinement. -The united

l schedule contained several unresolved issues and assumptions that must

be resolved or clarified to improve the schedule accuracy. -The licensee

has committed to providing. a copy of the Integrated Startup Schedule for

! Unit 2 to NRC by November 30, 1992.

!' Structural Steel

l- A summary and status of this item is contained in Inspection Report

325,324/92-27.

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Instrument Racks

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Work on rack replacement on Unit _2 is approx'W.ely 85 percent complete.

Three of three replacement racks are installed. All designs on Unit 2

are completed. This project is behind schedule with an_ anticipated

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completion in late January. Work on Unit 1.is approximately 45 percent

com)lete. The estimated completion date of January may be extended as

wor ( activities and focus are redirected to completing viork and

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restarting Unit 2.

Operator Work-Arounds

Add'd emphasis and focus by the licensee has improved progress on this

item. There were 66 o)en operator work-arounds on Unit 1 and 117 on

. Unit 2 at the end of tie reporting period. The licensee now tracks

these items on a daily basis and provides a report on additions, _

-completions and items not completed on schedule in the daily p.lan of the

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day meeting. Accountability is assigned _for each item. This added

emphasis . appeared to be improving the completion rate of open items in

this area.

Plant Material Condition

Work continues in this area with emphasis in the condenser pits and

intake structure areas. Severely corroded ccmponents are being replaced

and painting / preservation work occurred on the SW/CW intake areas and-

crane, the CB crane, condenser pits, reactor feedpumps, turbine building

" breezeways" and other plant areas. The licensee has developed a plan

and schedule for these activities. A significant amount of work remains

around the SW/CW intake screens.

Turbine 2A low PreswIg Rotor-

The ten year Unit 2 low pressure A turbine ultrasonic inspection

recommended by General Electric was completed. Several indications were

located during the process. Many of the crack indications found in the

1982 inspection have grown in size. Several new crack indications were

discoverad in the dovetails, keyways and hubs.

The recommended fix is to first remove the buckets around the notch on

the fourth stage, turbine end. Depending on the severity of.the cracks

found, options are_ available. One option is to remove the buckets at

the notch and replace the notch buckets with titanium blocks, keyed in

place. Blades. at 180 degrees would be removed. to counterbalance. If 1

the cracks are deep and extensive enough on the wheel, the' buckets or

the entire wheel will be removed and replaced with pressure plate. The-

turbine could then be run, but at reduced efficiency. As the cracks are

being ground out, they will be magnetic particle inspected to check for

crack removal. The keyway cracks will not prevent the unit-from '

starting up but several recommendations _on inspection intervals have

been provided by GE. %s licensee is currently-studying the available l

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options which may include rotor replacement. The inspector will follow .

actions taken on this item.

6. Licensee Celf-Assessment (40500)

l

The inspectors attended selected Plant Nuclear Safety Committee meetings

L conducted during the period. A significant number of ' hose meetings

involved system review of planned and exempted systems ark backlogs.

.

The inspectors verified that the meetings were conducted in accordance

with Technical Specification requirements regarding quorum membership,

.; review process, frequency and personnel qualifications. Meeting minutes

! were reviewed to confirm that decisions and recommendations were

i reflected in the minutes and followup of corrective actions was

1 completed. There were no ca.icerns identified relative to the PNSC

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meetings attended. The ;esolution of safety issues presented during

these meetings was considered to be acceptable,

i In October, the Site Project Assessment Group of NAD loaned the manager

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of the Management Assessment Section to Maintenance for a 90 day period

4 to assist in the training of new maintenance planners and implementation

of maintenance planning upgrades. To supplement.the loss, an engineer

from the corporate assessment section was sent to assume his duties

during this period. On October.23, the inspector was informed by the

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rianager of the Site Project Assessment that he was also -loaning two of

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the three Engineering / Technical Support Assessors to the Site Technical

Support Section to assist the Technical Support Managers from Nuclear

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and BOP areas in managing selected projects. This loan was to be for a

period of three weeks starting on October 26. The reason given for

these reassignments was that the managers of the Technical Support area

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were very involved in the review and prioritization of backlogs and in

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the development of the site restart and three year business plans, and

needed supervisory assistance. When informed of this decision, the

I inspector expressed a concern that this could result in a loss of

j independence from line functions by the assessors. The inspector asked

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what measures had been established to prevent the assessors from later

evaluating activities they were involved in. No measures had been

. established, but after being questioned, the licensee took steps to

address this concern. After lengthy discussions with the licensee, the

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inspector was convinced that these personnel were needed to assist the

i Technical Support and Maintenance areas for a short duration project.

During these conversations the inspector received assurances from the

l Manager of NAD that his organization would not be used in the future as

j a source of personnel for line organizations.

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7. Organizational Changes

On October 6,1992, Mr. J. W. Spencer resigned as Plant General Manager.

_

4 The licensee implemented a unitized organizational structure with Mr. R.

. E. Morgan and Mr. J. M. Brown named as temporary Unit .1 and Unit 2

i

Managers, respectively. Mr. J. G. Titrington and Mr. K. J. Ahern were

named as Manager of Operations and Mr. D. E. Moore and Mr. M. E. Jackson

- were named as Manager of Maintenance for Units 1 and 2, respectively.

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! The E&RC organization will now report to Mr. G. Warriner, Manager - '

! Contract and Ad.Wstration Section. On October 12. Mr. J. P. Cowan was

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named Manager of rechnical and Regulatory Support reporting to Mr, R. B.

Richey, Site Vice President. Mr. -Cowan is on loan from INPO to assist

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in plant recovery operations. Mr. E. E. Willett from the Harris -)lant

was named Manager - Planning and Scheduling, reporting to Mr.- Ric.acy.

l This organization combines OM&M, Planning _and Scheduling, Maintenance

Planning and SWFCG. OM&M will continue to manage outages and implement ,

modifications. The licensee stated that some of the above positions-are

j being filled on a temporary basis and additional changes may occur.

l 8. Quality Control (QC)

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l Quality Control identified numerous welding deficiencies during the -

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outage. These deficiencies included welders working to verbal

i instructions, inadequate welding controls, improper techniques and

i inadequate control of welding rod material. These findings were

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documented in several QC assessment reports and indicated significant

i weaknesses with the site welding program.

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The inspector discussed his concerns in this area with the Corporate

Manager of Quality Control. The QC manager decided to_obtain the

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services of an outside consultant to assess the site welding pr.ogram,

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The assessment identified weaknesses in the areas of welder testing and

i training, procedures and control: of weld rod material. Many of the

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findings were similar to those-previously' identified by QC. The

, assessment concluded that the large number of deficiencies indicated a

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weak welding program. An ACR was written to determine the rov cause

and. corrective actions needed. -The NRC ins)ector noted that this

i assessment focused on the overall program, aut did not contain extsnsive

j field observations.

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j The inspector reviewed the licensee's corrective actions for the

L findings to date. The corrective actions were found to address

[ individual findings, but did not appear to address overall welding

i program weaknesses.

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QC has in the past been successful in effecting corrective actions on

i- individual problems as they are identified; however, it appears that QC

does not have the authority to require progran,matic changes. In

addition, CP&L Quality Verification Procedure,-QVS-202, Support of Self-

i Assessment and Field Surveillance Programs, Revision 0, limits the

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. activities of the QC organization. It-allows QC to stop work on

individual jobs if a hold point exists. The above procedure requires

that QC pass their observations and finding:. to-the line organization

who will take corrective action as they deem _necessary. QC does not

l have an input in determining if corrective action is appropriate cr

adequate to correct the QC 1dentified deficiency. The authority to

assess programs is the responsibility of NAD. KAD has the'expertisc to

assess this area,.but has not performed any assessments of the welding

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program. When questioned on this matter by the NRC inspector, the

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Manager of NAD and the Project Assessment Manager stated-that they did ..

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not look into this item as yet. The inspector will continue to follow

actions teken by the licensee to address the welding program problems.

URI 92-34-03, Welding Program.

9. Exit Interview (30703)

The inspection scope and findings were summarized or, November 6,1992,

with those persons indicated in paragraph 1. The inspectors described

the areas inspected and discussed in detail the inspection findings

listed beiow and in the summary. Dissenting comments were not received

from the licensee. Proprietary information is not contained in this

report.

ILVAlhimjaC OfjLqrJAt_ ion /RefertpstParaarRh

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325,324/92-34-01 Violation - Watchstanding With An

inactive License (paragraph 4).

325,324/92-34-02 URI - Service Water Leaks

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3?5,324/92-34-03 URI - Welding Program

10. Acronyms and initialisms

ACR Adverse Condition Report

BNP Brunswick Nuclear Project

BOP Balance of Plant

BSEP Brunswick Steam Electric Plant

CB Control Building

C0 Control Operator

CP&L Carolina Power & Light Company

DC Diesel Generator

DGb Diesel Generator Building

E&RC Environment'.1 & Radiation Control

GF General Electric

HP Health Physics

HPCI High Pressure Coolant injection

J LLRT Local Leak Rate Test

MOP E tor Operated Potentiometer

MST Maintenance Surveillance Test

NAD Nuclear Assessment Department

NDE Non-Destructive Examination

NRC Nuclear Regulatory Commission

OM&M Outage Management & Modification

PA Protected Area

PNSC Plant Nalear Safety Committee

QC Quality Control

RC Run Control

RCIC Reactor Core Isolatien Cooling

RHR Residual Heat Removal

ROT Reactor Operator Trainee

RWCU Reactor Water Cleanup

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i 500 Senior Control Operator l

SSTR Stop/ start Timing Relay

SW/CW Service Water / Cooling Water

, SWFCG Site Work Force Control Group

( WR/JO Work Request / Job Order ,

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