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Insp Rept 50-155/86-04 on 860124-0408.No Violation or Deviation Noted.Major Areas Inspected:Licensee Actions on Previous Insp Findings,Operational Safety,Maint,Ler Followup & Licensing Actions
	ML20203L263
Person / Time
Site:	Big Rock Point File:Consumers Energy icon.png
Issue date:	04/24/1986
From:	Boyd D; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:	;
Shared Package
ML20203L251	List: ML20203L248; ML20203L263;
References
	50-155-86-04, 50-155-86-4, NUDOCS 8605010198
	Download: ML20203L263 (8)
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U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Report No. 50-155/86004(DRP)

Docket No. 50-155 License No. DPR-6

Licensee: Consumers Power Company

212 West Michigan Avenue

Jackson, MI 49201

Facility Name: Big Rock Point Nuclear Plant

Inspection At: Charlevoix, MI 49720

Inspection Conducted: January 24 through April 8,1986

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Inspector: S. Guthrie

Approved By: D. C. ,

YM

Reactor Projects Section 2D Date

Inspection Summary

Inspection on January 24 through April 8,1986 (Report No. 50-155/86004(DRP))

Areas Inspected: Routine, unannounced inspection conducted by the Senior

Resident Inspector of Licensee Actions on previous Inspection Findings,

Operational Safety, Maintenance, Licansee Event Report followup, and Licensing

Actions.

Results: Of the five areas inspected, no violations or deviations were

identified. No significant safety items were identified. However, the

question of diesel fire pump dependability in light of its age and difficulties

encountered in obtaining parts and experienced repair service is a source of

increasing concern because of that pump's crucial role in providing low

pressure core spray water as well as water for fire protection purposes.

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DETAILS

1. Persons Contacted

D. Hoffman, Plant Superintendent

G. Petitjean, Planning and Administrative Services Superintendent

G. Withrow, Engineering Maintenance Superintendent

R. Alexander, Technical Engineer

R. Abel, Production and Plant Performance Superintendent

L. Monshor, Quality Assurance Superintendent

R. Barnhart, Senior Quality Assurance Consultant

P. Donnelly, Senior Review Supervisor, Nuclear Activities Department

D. Swem, Senior Engineer

G. Sonnenberg, Senior Technical Analyst

D. Staton, Shift Supervisor

W. Trubilowicz, Operations Supervisor

J. Beer, Chemistry / Health Physics Superintendent

E. Evans, Senior Engineer

J. Tilton, General Engineer

D. Kelly, Maintenance Supervisor

D. Ball, Maintenance Supervisor

W. Blosh, Maintenance Engineer

L. Darrah, Shift Supervisor

J. Horan, Shift Supervisor

R. May, Shift Supervisor

R. Scheels, Shift Supervisor

J. Warner, Property Protection Supervisor

T. Fisher, Senior Quality Assurance Consultant

S. Bartosik, General Quality Assurance Consultant

R. Krchmar, General Quality Assurance Analyst

D. Hice, Technical Engineer (Acting)

R. Schrader, Engineering, Maintenance Superintendent (Acting)

The inspector also contacted other licensee personnel in the Operations,

Maintenance, Radiation Protection, and Technical departments.

Denotes those present at exit interview.

2. Licensee Action on Previous Inspection Findings

a. Section 10 of Inspection Report No. 85021 describes the licensee's

administrative procedures permitting the Shift Supervisor (SS), as the

only licensed Senior Reactor Operator (SRO) on shift, to be absent

from the control room and, in his abrence, delegating an operator

holding c Reactor Operator (RO) license to assume command of the

control room. Both of these activities are prohibited by

10 CFR 50.54(m).

The staff of NRR, by letter May 2, 1980, accepted the licensee's

proposal to assign " primary management responsibility" for the plant

to the SS and recognizes that certain emergency situations may

require the SS to leave the control room in the interests of plant

safety. Subsequent to this acceptance by the staff the requirements

of 10 CFR 50.54(m) were imposed by regulation.

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The licensee indicated their intention to submit a change to

technical specifications.

During this review the inspector noted that Administrative Procedures

Volume I, Chapter 4, Section 1.4.a.l.5 states that the SS may leave

the control room during emergency situations other than site or

general emergency "provided the Shift Technical Advisor / Shift Engineer

remains in the control room during his absence." The Shift Technical

Advisor / Shift Engineer positions is no longer staffed at Big Rock as

the licensee fulfills that positions requirements with an On-call

Technical Advisor (OTA). The OTA is required to be onsite during

certain evolutions and within one hour of being summoned by the SS

and thus it is not reasonable to require an OTA, who does not hold

an SRO license, to be present before the SS is allowed to leave the

control room in the interest of plant safety. The licensee agreed

to review the procedural requirement.

b. Section 5.d of Inspection Report No. 85021 described failure of the

diesel fire pump (DFP) to start within the required start time during

performance of weekly Surveillance T7-20, DFP Start Test. Corrective

maintenance efforts were ultimately unsuccessful, and on February 4,

the DFP was declared inoperable based on excessively long start times.

Technical Specification 11.3.1.4. requires both the Electric Fire Pump

and the DFP to be operable at power, and declaring the DFP inoperable

placed the facility in a Limiting Condition for Operation (LCO)

requiring a shutdown to be initiated with 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . At Big Rock the

DFP performs a core spray function as well as providing water for fire

fighting. On February 4 the licensee initiated a change to

Procedure T7-20 to increase the maximum start time from 20.4 seconds

to 45 seconds, citing as engineering justification the Safety

Evaluation performed by NRR supporting the approval of Amendment

No. 44 to the units Operating License. This amendment, dated June 9,

1981, revised reactor operating limits based on a new Loss of Coolant

Accident (LOCA) analysis. Section 2.3 of the Safety Evaluation

concludes that a delay in DFP start time of an additional 25 seconds

(45 seconds total) does not affect the LOCA-based reactor operating

limits. All DFP starts, including those which had exceeded the former

20.4 second limit, were within the revised 45 second limit, thus

relieving the licensee of the requirements of the technical

specification LCO.

On February 4 the inspector reviewed the problen with the licensee

and expressed a concern that the erratic starting behavior of the DFP

and the inability of maintenance personnel and vendors to positively

identify and correct the cause of the poor performance was a problem

that could not be corrected solely by increasing allowable starting

times no matter how valid the engineering justification. The licensee

agreed to operate the DFP continuously from February 4 until entering

an upcoming scheduled outage period where DFP operability was no

longer required by technical specification. The DFP ran continuously

except for daily maintenance trouble shooting sessions until

February 11. During the outage the licensee brought in manufacturer's

representatives to diagnose and correct the problem. Diagnosis and

repairs were hampered by the age of the equipment, prompting the

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licensee to consider the DFP engine for total replacement during the

1986 refueling outage. Unavailability of parts and a shortage of

maintenance personnel experienced with the outdated engine make future

repairs questionable. Electrical components cleaning, fuel line leak

tightness verification, and valve adjustments produced satisfactory

start time performance and a pump output capacity test was

satisfactorily performed February 15. Following the DFP's return to

operability the licensee conducted daily performances of T7-20, n '.h

maintenance personnel present, from February 17 to March 3. All tests

had start times of less than 7 seconds, a figure consistent with the

pump's long term surveillance history.

The inspector will monitor the licensee's activities related to DFP

engine replacement.

3. Operational Safety Verification

The inspector observed control room operations, reviewed applicable logs

and conducted discussions with control room operators during the inspection

period. The inspector verified the operability of selected emergency

systems, reviewed tagout records and verified proper return to service of

affected components. Tours of the containment sphere and turbine building

were conducted to observe plant equipment conditions, including potential

fire hazards, fluid leaks, and excessive vibrations and to verify that

maintenance requests had been initiated for equipment in need of main-

tenance. The inspector, by observation and direct interview, verified that

the physical security plan was being implemented in accordance with the

station security plan.

The inspector observed plant housekeeping / cleanliness conditions and

verified implementation of radiation protection controls. During the

inspection period, the inspector walked down the accessible portions of

the Liquid Poison, Emergency Condenser, Reactor Depressurization System

(RDS), Post Incident, Core Spray and Containment Spray systems to verify

operability.

a. Throughout the report period the licensee experienced problems with

high turbine gland seal steam pressure. Turbine gland seal steam

normally runs about 2 psig but increased for reasons that remain

unclear to about 8 psig, a pressure at which gland seal steam escapes

from the turbine shaft gland and condenses to become mixed with

lubricating oil at the turbine shaft bearing. Presently the quantity

of water becoming mixed with oil is minimal and easily removed by a

centrifugal purifier and by evaporation from the warm oil. Pending

determination of corrective action by turbine specialists, operators

are reducing load in one mwe increments to keep seal steam pressure

under 8 psig. Power has been reduced from 70 mwe to 66 mwe for this

purpose.

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b. On February 10 at 10:00 p.m. the licensee attempted to perform

Quarterly Surveillance T90-07, RDS Isolation Valve Test. To perform

the test, RDS-101 valves (bypass manual isolation) must be open and

the piping between the upstream isolation valve and the depressuri-

zation valve pressurized. Erosion of the pilot valve assembly on

SV-4985 (B train depressurization valve) caused lifting of that valve

and the test was terminated. RDS valves 101 B and C were reclosed.

The licensee, in anticipation of this situation preventing performance

of the required surveillance, had scheduled an outage period to

perform RDS valve maintenance.

The following morning of February 11 the licensee performed primary

plant leak rate calculations and determined total unidentified leak

rate to be 1.126 gpm. Technical Specification 4.1.2.(c) requires

the plant be placed in hot shutdown condition within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Big

Rock Emergency Procedures require that declaration of an Unusual Event

be made when plant shutdown is required by a technical specification

LCO. All Unusual Event notifications were completed, and the reactor

was shutdown within the required period. Leak rate calculations

performed after shutdown indicated total unidentified leakage of

0.349 gpm. The licensee suspects leakage through the RDS valves

which were manipulated during the surveillance attempt.

During the outage the licensee replaced depressurization valve top

assemblies on SV-4985, SV-4986, and SV-4987. Valve RDS 101 B was

also replaced.

The reactor was returned to service February 16. Unidentified leakage

following startup was 0.192 gpm.

c. On March 7 the inspector discussed with the licensee an event at the

Lacrosse facility in which heat generated in a silver zeolite sampling

cartridge in use at the offgas sample line caused hydrogen ignition

in the sample line and offgas system piping. The licensee had

discussed the incident with the Lacrosse licensee and evaluated the

use of silver zeolite cartridges at this facility. Currently the

silver zeolite cartridges are used for emergency general sampling for

all areas but are capable of sampling at the offgas sample point. The

licensee had already determined the need for a warning sign at the

offgas sample point.

d. On March 23 the unit experienced an increase of offgas flow of

6-8.5 CFM with no significant changes in any other plant parameter.

Investigation revealed a hole in a 10 inch steam line piping elbow

downstream of bypass valve CV4014. This was apparently caused by

erosion from steam impinging on the elbow's interior surface from a

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warming line. The line is normally under vacuum from the main

condenser but the size of the hole when first discovered was small

enough to be within the capacity of the air ejectors to maintain

vacuum.

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During the period of increased offgas flow the licensee observed a

slight increase in radionuclide activity exhausting to atmosphere as

short lived nuclides were rushed through the offgas system's hold up

volume. This hold up volume, given normal offgas flow rates, provides

sufficient time for short lived radionuclides to decay within the

volume, thus reducing the total activity discharged to the atmosphere

via the stack. Xenon 138, a short lived nuclide monitored by the

licensee, increased from a typical valve of 400 uci/sec to around

800 uci/sec. Licensee monitoring of Xenon 133, a long lived nuclide

which does not linger in the hold up volume long enough to decay,

significantly showed no change. Discharges are limited by 10 CFR 50,

Appendix 1.

On March 24 a temporary patch was affixed to the elbow's exterior.

Following fabrication, on March 31, a patch was welded to the elbow.

During the installation process, declining condenser vacuum required

operator action to increase air ejector flow to prevent a reactor

scram from low vacuum (22 in. hg). Permanent elbow replacement is

planned for the 1986 refueling outage.

e. On March 26 the inspector observed portions of hands-on fire training

conducted at the site.

No violations or deviations were identified in this area.

4. Monthly Maintenance Observation

Station maintenance activities of safety-related systems and components

listed below were observed / reviewed to ascertain that they were conducted

in accordance with approved procedures, regulatory guides, industry codes

or standards, and in conformance with technical specifications.

The following items were considered during this review: the limiting

conditions for operation were met while components or systems were removed

from service; approvals were obtained prior to initiating the work;

activities were accomplished using approved procedures and were inspected

as applicable; functional testing and/or calibrations were performed prior

to returning components or systems to service; quality control records were

maintained; activities were accomplished by qualified personnel; parts and

materials used were properly certified; radiological controls were

implemented; and fire prevention controls were implemented.

Wor k requests were reviewed to determine status of outstanding jobs and

to assure that priority is assigned to safety related equipment maintenance

which may affect system performance.

a. On March 24 the licensee entered a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months LC0 for replacement of

Solenoid Valve SV-9153 on Control Valve CV-4094, Exhaust Ventilation

Downstream Isolation Valve. Solenoid Replacement was completed within

seven hours.

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b. On April 1, during the performance of T7-20, DFP Start Test, the

operator observed dripping leakage of fuel oil from a fuel oil filter

on the engine. Vibration of the filter during operation brought it

in contact with its support bracket, eventually wearing through the

filter housing. Filter replacement and bracket modification required

entry into a LCO as required by Technical Specification 11.3.1.4.

Repairs were completed with the 24 LCO requirements.

c. During the inspection period the licensee received notification from

the Consolidated Pipe and Valve Supply Company that officials of the

Golden Gate Forged Flange Company, a supplier of forged flanges sold

to the licensee by Consolidated Pipe, had been charged in Federal

Court with criminal false statements related to falsified test

certifications. The licensee promptly researched all purchase orders

from the vendor and all records of transfer of materials from the

terminated Midland Plant and informed the inspector that none of the

suspect forged flanges were installed or are in storage at Big Rock.

No violations or deviations were identified in this area.

5. Licensee Event Reports Followup

Through direct observations, discussions with licensee personnel, and

review of records, the following event reports were reviewed to determine

that reportability requirements were fulfilled, immediate corrective action

was accomplished, and corrective action to prevent recurrence had been

accomplished in accordance with technical specifications.

(Closed) LER 86001 and 86001, Revision 1, Failure to Perform Required

Surveillance Test. This LER describes the licensee's failure to test fire

detection instruments located in the recirculation pump room during the

1985 refueling outage, as required by Technical Specification 4.3.3.8.1.

The omission was attributed to procedural inadequacy which called for

testing of several detectors with different surveillance frequencies under

a single procedure, thus creating the potential for the oversight. The

omission was discovered on January 17, 1986 and the test was performed on

February 15, 1986 during the next period permitting recirculation pump room

entry.

The LER was revised by the licensee after determining that wording in the

original submittal gave the incorrect impression that the Senior Resident

Inspector had granted permission to continue plant operations in violation

of a LCO. In fact, Big Rock technical specifications do not include an

action statement requiring plant shutdown to perform the required

surveillance. When informed of the situation the inspector concurred with

the licensee's decision not to voluntarily shutdown the plant to perform

the fire detector surveillance. The inspector based his position on the

detectors successful surveillance history and the recognition that the

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threat to plant safety and operational stability resulting from plant

shutdown and restart exceeded the threat to operational safety posed by

three untested fire detectors.

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The missed surveillance was discussed in Section 5.e of Inspection Report

No. 85021.

(Closed) LER 86002, Exceeding Technical Specifications Unidentified Leak

Rate Limit. This LER discusses the licensee's action to take the unit from

90% power to cold shutdown as required by Technical Specification 4.1.2.C.

This action was in response to an unidentified leak rate in excess of

1.0 gpm observed during performance of surveillance testing on RDS Valves

on February 11. The event is described in detail in Section 3.b of this

report.

6. Licensing Activities

By letter dated March 10 the commission issued Amendment No. 83 to Facility

Operating License No. DRP-6 for Big Rock Point. The amendment changes

technical specifications to reflect a plant staff reorganization implemented

in 1985.

By letter dated March 20, 1986, the Commission issued an exemption from the

requirements of 10 CFR 50.62(c)(5) to install an automatic recirculating

pump trip to trip the reactor under conditions indicative of an Anticipated

Transient Without Scram (ATWS) event. The letter references several

engineering evaluations and concludes that the existing installed oversized

safety valve capacity at Big Rock is sufficient to limit primary coolant

system pressure rise within acceptable limits without an automatic pump

trip.

7. Exit Interview

The inspector met with licensee representatives (denoted in Section 1)

throughout the month and at the conclusion of the inspection period

summarized the scope and findings of the inspection activities. The

licensee acknowledged these findings. The inspector also discussed the

likely informational content of the inspection report with regard to

documents or processes reviewed by the inspector during the inspection.

The licensee did not identify any such documents or processes as

proprietary.

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ML20203L263

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