IR 05000155/1985021
| ML20151U486 | |
| Person / Time | |
|---|---|
| Site: | Big Rock Point File:Consumers Energy icon.png |
| Issue date: | 02/04/1986 |
| From: | Boyd D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20151U468 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-0828, RTR-NUREG-737, RTR-NUREG-828 50-155-85-21, GL-83-28, GL-83-284, GL-85-18, IEB-79-24, NUDOCS 8602110030 | |
| Download: ML20151U486 (21) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-155/85021(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:
November 1, 1985 - January 23, 1986 Inspector:
S. Guthrie
,6h&b D.C.Boyd,JChief 2 - 4^"8 E" Approved By:
Projects Section 20 Date Inspection Summary Inspection on November 1, 1985 - January 23, 1986 (Report No. 50-155/85021(DRP))
Areas Inspected:
Routine, unannounced inspection conducted by the Senior Resident Inspector of Licensee Actions on previous Inspection Findings, Operational Safety, Maintenance Observation, Surveillance Observation, Licensee Event Report Followup, Generic Letters, Licensing Actions, Headquarters Request and Regional Request.
The inspection involved a total of 192 inspector-hours by two NRC inspectors.
Results: Of the ten areas inspected, no violations or deviations were identified.
Significant safety items were identified and are discussed both in section 3 and in the attached cover letter.
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PDR ADOCK O PUR G
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Persons Contacted
- D. &mffman, Plant Superintendent G. Pettijean, Planning and Administrative Services Superintendent
'*G. Withrow, Maintenance. Superintendent
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- R. Alexander,. Technical Engineer R.- Abel, Production and Plant Performance Superintendent
'*L. Monshor,. Quality Assurance Superintendent
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.R. Barnhart, Senior Quality Assurance Administrator P. Donnelly,' Senior Review Supervisor, Nuclear Activities Department-
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W. Blissett, Shift: Supervisor
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D.'Swen,-Senior Engineer-G. Sonnenberg, Shift Supervisor D. Staton, Shift Supervisor
- W. Trubilowicz, Operations Supervisor
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- J. Beer, Chemistry / Health Physics Superintendent-E. Evans Senior Engineer
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R. Brady, Senior. Plant Technical Analyst
.J. Tilton, General Engineer'
-D.-Kelly, Maintenance Supervisor D. Ball,-Maintenance Supervisor W. Blosh, Maintenance Engineer
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M. Acker, Senior Engineer.
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J.'Toskey, General Engineer-J. Kneeland, Reactor Engineer
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L.'Darrah, Shift Supervisor
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J. Horan, Shift Supervisor
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- R. May, Shift Supervisor R.'Scheels, Shift Supervisor p
J. Warner, Property Protection Supervisor L
T. Fisher, Senior Quality Assurance' Administrator S. Bartosik, General Quality Assurance Consultant
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R. Krchmar, General Quality Assurance Analyst
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R. Burdette, Chemistry / Health Physics Supervisor
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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
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(Closed) 155/84002-88, Failure of General Electric Type HFA Relays.
Replacement of' relays and acceptance-testing were. completed during the 1985 refueling outage.
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(0 pen) Unresolved Item 155/85007-02 Licensee's Corrective Action to Reduce Human Error.
This report contains further examples of events which have as a major contributing cause failure of personnel to adhere to procedural requirements.
Inspection Reports 155/85007 and 155/85014 contain several incidents, some of which were the subject of an Enforcement Conference in Region III on December 5.
A summary of that conference is published as an addenaum to Report No. 85014.
On January 21 the inspector reviewed with the Plant Superintendent all-actions and programs implemented by the licensee in response to the problem experienced in 1985.
In summary:
(a)
In retrospect, the licensee has identified through internal critiques that several factors contributed to the difficulties experienced in managing Field Maintenance Service (FMS) personnel during the 1985 refueling outage.
Included are lack of proper planning prior to the outage, lack of a single point contact to oversee the activities of FMS crews, and inadequate attention to detail in the planning stages.
The reorganization of the facility and early retirement of several experienced employees only one month before the outage in a company-wide program to reduce personnel expenditures during a period of financial difficulty had a substantial negative impact on the outage.
(b) The licensee recognizes the need for more detailed planning of work activities during outage periods and intends to begin earlier to ensure a job can be completed before it is commenced.
The licensee intends to create a material services group to handle procurement and inventory control, and to prepare material packages for outage activities.
The intent is to relieve the maintenance supervisor of the burden of material problems and to avoid delays in work activities after tagging and isolation of components.
The licensee intends to create a Planning & Scheduling Section with the outage coordinator and representatives from all departments working under a supervisor to plan all forced or scheduled outages.
The group will generate a shift-by-shift schedule of specific work activities.
The licensee notes this is a major departure from the present system and is expect (d to have significant impact on outage management.
(c) The licensee intends to have a single point contact for FMS crews, a supervisor at a level below the department head level.
(d) The licensee has expanded its training program in local control procedures for component isolation and tagging and now requires completion by all Operations and Maintenance Personnel, Department Heads, and Engineering and Chemistry / Health Physics Supervisors.
Training will be completed during the first quarter of 1986,
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(e) The licensee is initiating several changes in the management of FMS crews.
Indoctrination training for FMS crews on Maintenance Orders (MO)
and local control procedures for tagging will be expanded.
Conducted just prior to the outage and requiring additional training for FMS supervisors.
The training will review specific problems from the 1985 outage.
Crews from'one FMS organization will no longer be supervised by supervisors.from a different FMS crew.
A premaintenance checklist will be provided to FMS workers that will require inspection of the job prior to preparation of the H0.
Following inspection by an FMS Supervisor a tag will be hung on the component so the worker can later correlate the tag with his assigned job.
This new requirement will apply to FMS personnel only and won't be part of the paperwork for site maintenance personnel.
(f) The licensee plans changes in the procedures used to perform valve maintenance.
Preventive maintenance procedures are to be split into a two part procedure, one for inspection and a second to perform work required by the inspection.
Procedures for valve repair which are now generic for all types of valves are to be rewritten to be more specific for each type of valve (i.e., control, motor operated, manual, etc.).
(g) The licensee is pushing for completion of labeling activities in the plant, with all but certain piping in inaccessible areas completed by August 1986.
(h) The licensee made several organizational and administrative changes.
Operating crews were reorganized to take advantage of strengths and to offset weaknesses in individual operators.
The Operations Department has begun conducting a formal shift turnover meeting with all shif t personnel present which is intended to aid in insuring a thorough awareness of existing plant conditions and provide an opportunity to plan and organize the shifts'
activities.
The licensee added a weekly planning meeting for department heads intended to be a comprehensive review of all plant activities.
After three weeks the new format appears to be well received.
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The licensee is reviewing means of encouraging group meetings between first line supervisors and their crews.
(i) The licensee has stated goals and objectives for 1986.
Industrial safety and radiation safety are now related.
Proud of one of the best safety records in the industry, the licensee's intent is to reduce radiation exposure and incidents of contamination by doing jobs correctly on the first attempt.
The added benefit is improved effectiveness in the maintenance and surveillance programs by requiring proper job planning and good performance.
With contamination and radiation levels significantly reduced as a result of recent decontamination work, the licensee intends to expend the manpower to maintain that level of cleanliness, with resultant reduced exposure.
The licensee intends to improve housekeeping, and will soon issue a new administrative procedure that provides more detail on housekeeping expectations and places a greater burden on department heads for enforcement.
The decontamination and housekeeping programs are related but separate.
Personnel safety goals are reemphasized with the recent restructuring of the Plant Safety Committee now chaired by the Plant Superintendent.
One objective is the elimination of old items by requiring resolution within one year.
The licensee is conducting a review of all engineering projects with the aim of prioritization and aggressive pursuit of completion to reduce the total number in progress.
(0 pen) 85007-01, Component identification during the inspection period the licensee made significant progress in identification and labeling of components.
The inspector observed many new tags on valves and instrumentation and stenciled identification on major pumps and tanks.
The licensee stated their intention to continue identification of pumps and tanks and commence markings of pipes for contents and flow direction.
The licensee has not made significant progress in developing an environmentally qualified means of tagging components with a verbal description or other descriptive nomenclature, but stated to the inspector their intention to test laminated labels in various environments throughout the plant. The licensee has voluntarily expanded labeling activities to include asbestos insulation hazards.
During the inspection period the inspector reviewed the licensee's program to sample secondary side water in the emergency condenser.
The condenser was subjected to extensive testing during the 1985 refueling outage after traces of Xenon were detected early in 1985, indicating a primary to secondary leak across the emergency condenser.
The testing failed to identify the leak location, and the reactor was restarted with the suspect tube bundle unisolated.
The licensee
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sampled with 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of startup and through the close of the inspection period continued to perform a weekly analysis with no trace of Xenon.
The licensee is engaged in a study to determine how to monitor very small leakage quantities like those found in 1985 on the emergency condenser.
Presently isolation requirements are based on the fact that releases are not monitored.
With accurate monitoring isolation decisions could be based on releases to the environment.
3.
Operational Safety Verification The inspector observed control room operations, reviewed applicable logs and conducted discussions with control room operators during the inspection period, a.
During the inspection period the inspector observed the activities of contractor personnel working on the refueling deck to remove and prepare for shipment contaminated old channels and other materials stored in the spent fuel pool.
On one occasion the inspector noted that a contractor employee standing in the non-contaminated area of the reactor deck.was wearing a visitor's badge that requires an escort, but that no escort was observed.
The employee identified his escort as another contractor employee who was fully clothed in anti-contamination clothing and full face mask and actively engaged in the work on the contaminated side of the reactor deck. While the employee was within the line of sight of his escort, it was obvious that the escort was not exercising any sort of active control over the employee, and that because of the visual restriction of the face mask and the individual's involvement with his work the escort was not adequately monitoring the location and activities of the employee.
Licensee procedures permit one contractor employee to provide escort for another contractor employee.
The licensee agreed to reemphasize to all persons performing escort duties the significance of their responsibilities.
The contractor employee requiring escort was subsequently badged for unescorted access, b.
During the inspection period the licensee completed construction and testing of the Alternate Shutdown System (ASD).
The inspector observed portions of the operability testing.
During the week of December 9 a team of Region III experts conducted an audit of the licensee's action to satisfy the requirements of 10 CFR 50, Appendix R,.which included walkthrough of operator use of the ASD System.
The audit team's inspection findings are presented in Inspection Report 155/85022(DRS).
c.
During the inspection period the inspector observed several instances of guards posted in response to unusual situations, including ditches adjacent to the security fence, locations near the fence which experienced erosion from storm damage, and the outer equipment lock area while the Alternate Shutdown System (ASD) Cable penetration area was being established as a vital area through a welded enclosure.
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d.
On November 1 the inspector observed fire brigade response to a reported fire in the electrical equipment room.
The brigade response was prompt and efficient, but the fire was actually determined to be steam from the auxiliary boiler adjacent to the electrical equipment room.
e.
On November 1 the inspector observed portions of the plant hydrostatic test prior to startup from the 1985 refueling outage.
The test was conducted in accordance with Surveillance TV10, Hydrostatic Test of. Nuclear Steam Supply System.
f.
On November 6 the reactor was taken critical and 93 jenerator placed on line November 8 after turbine vibrations problems were diagnosed.
On November 14, decantamination personnel working on the reactor deck observed steam issuing from the reactor vessel plug, prompting the licensee to shut the reactor down in search of the leak.
During the shutdown the reactor tripped on a upscale /downscale signal as described elsewhere in this report under Licensee Event Reports.
Prior to the observed plug leakage the reactor vessel head seal leak detection system had indicated failure of the inner seal by detecting pressure between the inner and outer seal rings.
Leakage of the inner ring only following replacement is not uncommon.
Investigation pointed, however, to a leaking flange on the vessel head vent line
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and repairs were performed to that flange.
Hydrostatic testing indicated no leakage and the reactor was taken critical November 18.
During heatup following criticality, the steam leak was again noted, prompting the licensee to shutdown, remove the vessel head, and replace both vessel head seal rings.
Repairs were successful and the unit was returned to service November 23.
g.
On November 25, during power escalation, the inspector observed that control room operators performing control rod manipulations were not making use of laminated cards implemented to help eliminate human error resulting in mispositioned control rods.
Use of the cards, which was committed to by the licensee in their written response to Inspection Report No. 155/85007(DRP), are to be marked using a marking pen to keep track of rod movements.
On November 25 the inspector observed no marks on the cards through card number 63.
Operators' indicated they were unaware the use of the cards was a requirement.
The inspector informed the Plant Superintendent who confirmed that there was a commitment to utilize the cards, and subsequent rod movements were appropriately marked.
During power escalation on recovery from scram on December 8, the inspector again observed that the cards were totally blank, although-rod movement was complete through the positions on card 55.
The operator informed the inspector that he had erased the cards when coming on shift, and had failed to mark the two notches he had driven in.
Operators again indicated they had received no management direction to use,or mark the cards, and that their knowledge of their use had been passed down to them from preceding shifts.
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On December 8 the Operations Supervisor issued a memorandum after recognizing original guidance written in the Daily Orders was apparently inadequate.
The memorandum gave specific instructions to operators for use of the cards during startups and shutdown, and included an explanation of the reason for the new system and the importance of the commitment.
The inspector discussed with the licensee his position that the cards were of no value as a tool if not conscientiously put to use by operators, and that in the implementation of new programs it is essential to convey to operators specific instructions and management's expectations for full compliance and not assume that operators will understand and employ a new program without thorough management in'volvement and direction.
h.
On December 7 the reactor was manually scrammed at the direction of the Shift Supervisor (SS) based on indications of a major steam leak including (1) a fire alarm in the upper control rod drive (CRD) accumulator room, (2) a radio report from~an Auxiliary Operator (AO) of a steam leak observed in the lower CRD accumulator room, and (3) high level alarm in the scram dump tank.
The Reactor Protection System functioned normally and all rods inserted.
The observed steam that indicated a major leak to operators was admitted to a common header that normally drains to the enclosure clean sump when an A0 opened valve VNS-403, Recirculation Pump Drain Header Isolation, to relieve pressure in recirculation pump drain piping upstream to facilitate weld repair of a pinhole leak in the drain piping. Valve VNS-403 was recently installed in the common header downstream of four individual drain line isolation valves off number one recirculation pump to provide for double valve isolation in recirculation pump drains.
Prior to its installation any leakage past any of the individual drain valves would pass directly to the sump, but after installation any leakage served to pressurize the drain header.
The pressurization of the piping resulted in leakage through a small weld defect and it was repairs to that leak that were in progress when the A0 opened VNS-403 to relieve pressure.
The A0's action should have depressurized the header, but instead caused steam flow into the common drain header at a rate sufficient to cause steam to back up into the accumulator rooms and scram dump tank.
Steam flow was the result of recirculation pump drain valve VNS-143 being approximately two to five turns open when normal valve position is fully closed.
The valve had been verified closed during valve line up checks prior to plant start up.
Two possible explanations were put forth by the licensee to explain the mispositioned valve:
(1) Because VHS-143 has the T-handle type of valve operation and relatively tight packing the valve may have been thought to be tightly closed by an operator performing valve lineup checks.
The inspector interviewed several operators and learned that older operators knew that the valve can not be manipulated by hand and a pipe to provide additional leverage is necessary.
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O While older' operators generally stated they would use the pipe to perform a check on VNS-143, newer operators were unaware of that valve characteristic and expected to be able to operate the valve by hand.
(2) On November 1 a packing leak requiring repacking was identified on VNS-143, but because of a communications error the maintenance order (MO) was issued to repack VHS-133, a normally open valve.
No tagging was issued for VNS-133.
Repairmen recognized the error, the MO was changed to repair VNS-143, and the valve was repacked. Although the valve repair procedure requires tagging to repack, none was obtained for VNS-143.
Without tagging there exists no mechanism to ensure the valve is returned to its proper position.
While the licensee's review indicates that the second explanation is the more plausible of the two it is unlikely that the licensee will ever determine which potential explanation actually resulted in the steam leak and subsequent manual scram. While both scenarios point to personnel error the second explanation offers another example of failure of field maintenance service personnel to adhere to component tagging procedures.
During resolution of the incident on December 8 the licensee checked for a similar situation on the Number 2 recirculation pump drain header and determi.ned leakage was present there, also as a result of the newly installed second isolation valve causing pressure to build in the drain header line.
Repairs were completed.
In addition, the licensee checked closed all other affected valves in other systems involved with the facility change used to install VNS-403, except for certain valves related to instrument and control.
Proposed long term corrective actions include:
(1) Development of a program to ensure accurate double verification of valve position for valves operated after the startup check sheet-is complete but prior to actual plant startup.
(2) Revision of generic Maintenance Procedures to specifically address the valves in question.
(3) Evaluate the need for a comprehensive maintenance program for manual valves.
The inspector will track these long term actions under open items (155/85021-01(DRP)).
i.
During the inspection period the inspector reviewed the licensee's activities aimed at reducing instances of personnel contamination.
The increase in contamination and concerns identified by the ALARA coordinator were discussed in section 3.t of Inspection Report 155/85014(DRP).
During the period the i~nspector noted an increased number of contaminations to levels sufficient to require,
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under the licensee's procedures, whole body counting.
Licensee criteria for requiring whole body counting include contamination levels greater than 10,000 DPM above the neck, and greater than 1,000 around the nose, or greater than 500 DPM on swabs used to wipe the nose. Other whole body counts are performed when appropriate even though well below the criteria.
All of the thirteen individuals requiring whole body counting were confirmed to have external contamination as opposed to contamination ingested or inhaled.
In December the licensee used decontamination personnel to extensively clean the sphere.
Efforts were coricentrated on the reactor deck and, control rod drive and recirculating pump rooms.
The reactor deck was decontaminated to less than 10,000 DPM and the clean areas of the sphere were clea,ed to less than 400 DPM.
Some deconning was conducted outside the.phere.
The ALARA coordinator noted that past difficulties in obtaining the necessary personnel to stay ahead of contamination buildup seems to have eased with an increased awareness of the problem.
The licensee has approved funding for a new fuel pool filtration system designed for use within the pool.
The system, which may be operational before the next outage, is expected to replace the present filtration system that uses a flow path including the spent fuel pool, surge tank, filter, heat excha.ger and return to the pool and creates high radiation areas that last year added an estimated total of 15 REM exposure to operations personnel making rounds in the area.
The licensee has established a goal of total personnel exposure for all Big Rock workers below 200 man-REM for 1986, a decline from approximately 300 man-REM for 1985.
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On November 19 the inspector observed preparations for and shipment of a truck load of low level radioactive waste to a burial site.
The inspector verified that procedural requirements were met and that the containers were properly marked, appeared leak tight, and were tightly packed in the truck.
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During the inspection period the licensee determined that Lake Michigan wave action had washed stone into an eighteen inch diameter concrete drain culvert which handles storm drains north of the containment sphere, thereby restricting drainage and causing water to back up in the storm drain when ever cooling water to the Post Incident System Heat Exchanger is placed in operation. Attempts to flush the culvert were unsuccessful.
The drainage system culvert was rerouted to an area where wave acticn and the unusually high
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lake level would not cause blockage and freezing in the culvert.
1.
On January 10 the inspector observed portion of a shipment of tools owned by a contractor performing work at Big Rock.
During'the inspection period the inspector reviewed with the licensee m.
their proposed Reduced Quality Assurance (QA) Involvement Program.
The program is intended to reduce QA review of selected departments
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that have a history of excellent compliance with regulatory, QA, and licensee administrative requirements with the goal of permitting Big Rock QA personnel to become more actively involved with QA problem areas with the program.
The licensee' hopes to establish, by example, standards and goals other departments may pursue.
The licensee has selected the Instrument and Control Department (I&C)
as the only department presently functioning at the expected standard, based on the results of the most recent Systematic Assessment of Licensee Performance (SALP), Institute of Nuclear Power Operations (INPO) evaluations, and licensee QA audits and surveillances.
The last licensee audit resulted in no findings or observations, a positive indicator of quality performance.
The proposed program features controls which include an annual audit, a surveillance six months after audit, and a. spot check program to monitor procedural adequacy.
As proposed the program would essentially eliminate QA review and concurrence in I&C administrative and working level procedure reviews for existing procedures, including changes to those existing procedures.
New procedures would require QA review.
Maintenance order reviews would be curtailed; however, hold and notification points would continue to be controlled by procedure.
The program does not propose reduced involvement for procurement document reviews or receipt inspections.
The inspector expressed his concern to the licensee that the program should be implemented with a change to CPC-2A, the licensee's Quality Assurance Frogram Description, or, as a minimum, concurrence of the Regional Quality Assurance management that a pilot program of this nature could be implemented on an interim basis with appropriate changes to CPC-2A at some specific point in the future.
The inspector noted that there needs to be a clearly defined program that establishes' criteria for diminished QA involvement, specifies minimum QA involvement, and details what aspects of the operation are exempt-from the program.
Since CPC-2A defines licensee commitments and this proposed program departs from those commitments, to implement the program without concurrence would offer the potential for the licensee's QA program to be found in violation of the CPC-2A.
Further, the inspector and Region III management feel strongly that the program should be reviewed by the licensee's Nuclear Safety Board (NSB).
The program was not included in the present quarter's agenda for NSB review.
The inspector will follow the program of the reduced QA involvement
= program under open item (155/85021-02(DRP)).
n.
A review of the licensee's'onsite organizational structure was conducted to determine that personnel qualification levels are in conformance with Technical Specifications, authorities and responsibilities are as delineated in the Technical Specifications and licensee organizational structure changes have been reported to the NRC.
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The review of personnel qualification levels consisted of the.
following positions:
Plant Superintendent, Production and Performance Superintendent, Planning and Administrative Services Superintendent, Engineering and Maintenance Superintendent, Operations Supervisor, Health Physicist and Technical Engineer.
During the review the inspectors noted that the current organization is not reflected in the Technical Specifications.
The licensee has submitted a Technical Specification Change Request dated August 1, 1985 concerning a reorganization of the plant staff below the Plant Superintendent level.
The licensee has indicated the reorganization is to reduce levels of management in certain areas below the Superintendent level, to provide additional analytical staff in the area of plant performance; to consolidate procurement and material services activities; to centralize plant planning activities; and to gain more coordination between maintenance and engineering functions.
This submittal is currently being reviewed by NRR.
The inspectors have noted that the proposed changes have been reviewed against the guidance of ANS1 N18.7-1976/ ANS3.2-Selection and Training of Nuclear Power Plant Personnel and found to be acceptable.
The inspectors have also reviewed the overtime limits addressed in the plant administrative procedures and verified that they were in conformance with Technical Specifications.
Any deviations from_the above overtime guideline limits were reviewed by the Plant Superintendent or his alternate as required by Technical Specifications.
The inspectors have noted that even though these guidelines are required during plant operations the licensee has been complying with these guidelines during the past outage.
o.
The inspectors reviewed the licensee's program for cold weather preparations to ensure the licensee has maintained effective implementation of protective measures for extreme cold weather committed to in response to IE Bulletin 79-24.
The inspectors performed a review and walkdown on systems susceptible to freezing to verify the presence of heat tracing, space heaters, and/or insulation; the proper setting of thermostats and that heat tracing and space heating circuits had been energized.
The inspectors-reviewed systems subject to maintenance and/or modifications during the past year to verify that protective measures had been established.
The inspectors reviewed the licensee's response to IE Bulletin 79-24, frozen lines, dated October 31, 1979 and were satisfied that the licensee is taking adequate protective measures as described in the response.
Review of the licensee's cold weather check-off list indicated that all action has been completed with the exception of installation of air louver covers to be installed by maintenance.
The licensee has
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indicated that the outage priorities have delayed completion of the
' check-off list and that these items are currently scheduled to be performed.
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 and industry codes or standards and in conformance with technical specifications.
During the inspection period the licensee experienced continued difficulty with leakage past the pilot valve assembly on Reactor Depressurization System (RDS) Target Rock depressurization valves.
Erosions of the pilot valve seat is believed to result from minute corrosion particles lodging on the seat during testing.
Once during the past year the licensee has rebuilt top assenblies on all four target rock valves and sent the "C" valve to a testing lab for repair and bench testing outside of the system.
By the end of the inspection period leaking pilot valves had caused the licensee to shut the RDS-101. valves on the "A", "B", and "C" RDS trains.
RDS-101 valves are manual bypass isolation valves which when closed, isolate the piping between the target rock valve and its upstream isolation valve from the reactor pressure it normally sees.
The licensee is evaluating several long term solutions, including major design modifications to the Target Rock Valves and analysis of other methods of protecting against the small break loss of coolant accident.
No violations or deviations were identified in this this area.
5.
Surveillance Observation a.
On December 16 the inspector observed Surveillance T-180-01-D, Leak Test of the containment escape lock.
The test involved pressuriza-tion of the escape lock to 2 psig for six (6) hours and observing any leakage using a calibrated gauge.
The test was conducted according to procedure and with successful results. While observing the test from.the exterior of the containment the inspector reviewed the operating instructions for the lock, which require manipulation of separate levers to mechanically operate the interior and exterior doors.
Those handles were not identified, making it impossible for a person not familiar with the controls to follow the instructions.
When informed of the problem the Operations Supervisor took action to identify the handles, but only after further inquires from the inspector.
During the course of the test, which was' conducted after hours, the inspector observed that the front door to the plant administration building was open and did not require the use of the security computer card reader.
A sign posted at the door states that after 5:30 p.m. the door will be locked witn access only via the card reader.
Responsibility for this door rests with the Shift
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The Operations Supervisor noted the need to be more
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c, b.
January 2 during the performance of weekly surveillance T7-28,
" Diesel' Generator Auto. Start and Run", the Emergency Diesel Generator.
.(EDG) tripped.
Investigation revealed that the EDG fuel pump, which
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fills the EDG day tank from the underground fuel. oil ~ storage tank,
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had failed when a woodruff key. fell from the pump coupling. -The
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. broken coupling led to a trip of the EDG on loss of fuel, and placed-the unit'in a' Limiting Condition for Operations (LCO) under' Technical Specification 11.3.5.3 which permits the EDG to be out of service for
.up to three days before an orderly plant shutdown must be initiated.
Repairs to the pump were completed January. 4.
The licensee indicated that similar failures of the pump coupling that.resulted in EDG
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unavailability have occurred on at least three other occasions and that a modification to the pump coupling was planned for the 1985 outage but not performed.
The licensee elected to perform the
^j modification and on January 9 reentered the LCO for approximate 1y'60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br />.
The EDG successfully completed subsequent attempts to perform
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On January 14 the inspector observed the performance of Surveillance
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huring the performance of Surveillance T7-20, Diesel Fire Pump Start Test, the Diesel Fire Pump.(DFP) failed.to meet acceptance criteria for starting time, a maximum of 20 seconds from first cr nk to full dead head pressure.
Operation personnel informed the inspector that
on previous recent surveillances the DFP'had acted sluggish and had
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exhibited varying engine speed.
Corrective action included cleaning of the injection pump delivery valve and transfer pump discharge side relief valve.
Several post-repair performances of T7-20 showed.
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satisfactory start times.
The licensee is considering changes to the
Preventive Maintenance procedure to increase cleaning activities on
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fuel supply system, and making any applicable changes to the fuel supply system on the Emergency Diesel Generator.
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On January 17 the licensee informed -the inspector that during
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performance of surveillance T180-16, Functional Test of Fire
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Detectors,-three detectors located in the recirculation pump room e
were not.te'sted as required by Technical Specification 4.3.3.8.l.
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The omission was discovered during procedure review at a period-when the plant was at full power and area access was prohibited t-duefto'high radiation levels. The pump room detectors are required oto be tested during each refueling outage, but an inadequate surveillance tracking system allowed startup from the 1985 refueling outage to commence without surveillance performance.
The T180-16 test for other detectors was performed July 3, 1985, prior to the 1985 refueling outage.
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The licensee notified the inspector and Region III and the determination was made that the safety significance of the missed surveillance was minimal and, based on the special safety evaluation performed by the licensee, there was no purpose in forcing the plant into a shutdown to perform the surveillance.
Big Rock Technical Specifications do not stipulate any action in response to a missed surveillance.
The licensee committed to perform the test at the next power reduction that permits access.
The inspector reviewed the licensee's safety evaluation and verified that there was no history of failed detectors in previous surveillances at Big Rock.
The subject detectors had tested successfully during the 1984 refueling outage and the detector circuitry is monitored by a trouble alarm.
The licensee is revising surveillance procedures and tracking systems to prevent recurrence.
The inspector questioned one aspect of the licensee's handling of the missed surveillance.
Based on a negotiated resolution to a similar missed surveillance occurrence at.the licensee's Palisades facility, the licensee believed that by drafting a temporary change to administrative procedures and by performing a safety evaluation and gaining PRC approval, the subject detectors would not have to be declared inoperable.
The inspector advised the licensee that the decision to not require shutdown to perform the surveillance was based on the detentination that continued operation of the plant with the detectors untested posed less of a throat to plant safety and operational stability that'the transients mposed on the reactor by shutting down and restarting.
While the detectors can reasonably be expected to function normally, they remain technically inoperable because the missed surveillance was not performed to demonstrate their operability.
The relief. granted by the Region is limited to this specific incident, and the negotiated resolution from the Palisades issue is not generically applicable to all incidents of missed surveillances..The Technical Specifications and PRC-approved Administrative Procedures are the only applicable regulatory documents available to address the missed surveillance issue.
The licensee is currently addressing the need to address missed surveillances administratively, including such aspects as when a component must be declared inoperable and when do time clocks commence.
6.
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 85007) By letter dated October 24 the licensee submitted LER 85-007, Inadequate Controls as Required by Technical Specifications.
The event occurred September 25 and involves return to service without
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a component leak test to verify operability of the outer (downstream)
containment dirty sump line, CV-4103. When maintenance was performed requiring the replacement of the valve's diaphragm the Shift Supervisor understood from the repairman that diaphragm replacement would not affect valve travel or stem adjustment.
Thus no post maintenance testing was specified. The licensee subsequently determined that the diaphragm was
. threaded onto the. stem, an arrangement likely to affect leak tightness.
Unable to verify the operability of CV-4103 the licensee closed and tagged the inner (upstream) isolation valve on the containment duty sump line CV-4025, thereby establishing containment integrity.
Although shutdown, containment integrity was required during refueling operations.
During the period in which CV-4103 was not declared operable fuel movements within the spent fuel pool were performed in violation of System Operating Procedures requiring containment integrity prior to fuel movement.
During the period that CV-4103 was not operable, CV-4025 was fully operable in the open position, having passed leak tests during the 1984 and 1985 fueling outages.
The licensee's decision to submit the event report was based on the " single failure" concept, noting that had CV-4025 failed while CV-4103 was not operable containment integrity could not be guaranteed.
Valve CV-4103 passed a leak test and was declared fully operable prior to startup from the 1985 refueling outage.
((Closed) LER 85008) By letter dated December 16 the licensee submitted Licensee Event Report (LER)85-008 describing an activation of the Reactor Protection System (RPS) on an upscale /downscale input signal.
Reactor power at the time of the trip was less than.1 percent and a normal reactor shutdown for maintenance was underway.
It is a characteristic of neutron level piroammeters at Big Rock to be highly susceptible to electrical noise at low neutron flux levels, resulting in a history of spurious trip signals from very low power.
The RPS system functioned as expected and the event has no safety implications.
(Closed) LER 85-009, Manual-Reactor Trip.
The circumstances relating to this reactor scram are described in section of this report.
The licensee's post trip review indicated that the Reactor Protection System activated properly and all control rods inserted.
7.
Licensing Activities By letter dated October 29 the staff of NRR issued Amendment No. 80 to the facility's operating license.
The amendment includes Technical Specifications for Containment Pressure and Water Level Monitors.
The two monitors and associated control room indications were required by Section II.F.1. of NUREG-0737, " Clarification of TMI Action Item Plan Requirements", and with this Amendment the licensee's commitment to address those requirements is complete.
By letter dated November 1 the Commission issued Amendment No. 81 to Facility Operating Licensee No. DPR-6.
The amendment required changes to Technical Specifications that revised Maximum Average Planer Linear Heat Generation Rate (MAPLHGR) limits and the Minimum Critical Power Ratio (MCPR) for the reload Il fuel design.
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By letter dated November 1 the staff of NRR granted the licensee's request for relief from certain inservice inspection requirements set forth in 10 CFR 50.55a(G).
Relief was granted for those examinations found to be impractical to perform, which, by granting relief, would not compromise the safety of.the-facility.
The staff required certain substitute examinations where practical, and refused to grant relief in some cases.
By letter dated November-5 the staff of NRR accepted the licensee's Post Trip Review Program and Procedure.
The Post Trip Review is one. area of concern described in Generic Letter 83-28, and that item is now considered.
resolved for Big Rock.
By letter dated November 12 the staff of NRR informed the licensee that the Process Control Program described in the licensee's January 7, 1985,
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submittal is approved on an interim basis for use with Big Rock Point Technical Specification 6.14.
The licensee was advised that future revisions of the program may be necessary to meet'the requirements of 10 CFR 61.
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By letter dated November 15 the staff of NRR informed the licensee that their Equipment Qualification Program complies with the requirements of 10 CRF 50.49 and that the proposed resolution for each of the program's identified deficiencies is accepted.
By letter dated November 19 the licensee was informed by NRR that the requirements of Generic Letter 83-28 related to Post-Maintenance Testing and System Functional Test Description were satisfied by the licensee's program.
By letter dated December 12 the staff of NRR, pursuant to 10 CRF 50.55a (G)(6)(I), granted the licensee relief from inservice testing for valves in the feedwater and Reactor Depressurization System Nitrogen Backup systems.
The decision was based on the conclusion of the staff's Safety Evaluation that the required testing is impractical to perform and that the alternate methods of examination proposed by the licensee are acceptable.
By letter dated January 8 the Commission granted exemption from certain requirements of Appendix J to 10 CRF 50.
The exemption relieves the licensee of the requirement to test reactor containment airlock door seals within three days af ter each opening or every three days during-periods of frequent openings.
Big Rock design requires regular opening of the personnel airlock for containment access necessary for plant operation.
The staff concurred with the licensee's plan to test airlocks every six months and to replace door seals periodically in accordance with manufacturer's recommendations.
This topic is addressed in section 4.20 of NUREG-0828, Systematic Evaluation Program.
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Generic Letters By letter dated November 1 the licensee responded to the requirements-of
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Generic Letter 85-18 to update the-response to Generic Letter 85-04 by providing estimates of licensee needs for operator licensing examinations during fiscal years'1986-1989.
9.
Headquarters Request During the inspection period the_ inspector reviewed licensee corrective-
. actions on twelve items listed in the Integrated Plant Safety. Assessment Report (IPSAR) (NUREG-0828).
The inspector's findings to verify
. completion are as follows:
(a). Sections 4.2.4 and 4.11 of the IPSAR contained a commitment to revise emergency procedures.to prescribe. operator action on flooding of the screen house and-turbine building.
Emergency procedure EMP 3.9 was
' amended in February 1985,-to direct operators to shut _the facility down should the availability of the diesel or electric fire pumps be in jeopardy because of water level in the screenhouse..Unavail-ability of the fire pumps would also prevent their_use as a water source for emergency condenser secondary side makeup.
The procedure requires the operators to summon the local fire department to fill
'the demineralized water tank.
The licensee intends to conduct a-cost / benefit analysis for modification to provide emergency condenser makeup if the screenhouse floods.
(b) Section 4.15 of the'IPSAR required the licensee to come into
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compliance with 10 CRF 50.55a(h) and Regulatory Guide 1.106 by providing assurance that the use of thermal overload protection -
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devices to motors associated with safety related motor operated-valves does not interfere with the performance of the valve's safety function.
The licensee elected to bypass the thermal overloading protection on six valves which must change position in order to perform their safety.-functions.
This modification was completed during the 1984 refueling. outage and documented in'section 8.a of Inspection. Report 155/85005(DRP).
(c) Section 4.16 of the IPSAR records a licensee commitment to modify emergency operating procedures to require a leak test following a confirmed seismic event, and to leave the plant shutdown until
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inoperable leak detection equipment is returned to service.
Emergency procedure EMP 3.7 was revised to include those requirements.
(d) Section 4.19 of the IPSAR contained a recommendation that the licenseeLdemonstrate.the coatings used within containment are qualified for design basis accident conditions and that the coatings would not clog screens.
The question ~of coating acceptability was resolved satisfactorily and documented by letter from NRR to the licensee dated June 13, 1985.
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(e) Section 5.3.5.3 of the IPSAR noted that the licensee proposed to modify control air conditioning to improve operator comfort during summer operations.
The issue has no safety implications.
A modification to provide the cooler with well or service water was completed and used during the summer of 1985.
(f) Section 5.3.9 of the IPSAR addressed modifications to the water purification system that included replacement of corroded components, extensions of the acid line, and installation of the cleanup demineralize pump bypass.
The acid line extension and component replacement were completed and during the 1985 refueling outage the cleanup pump bypass was installed and declared operable.
The project engineer is presently working on an electrical modification to allow the control room operator to isolate the whole system.
(g) Section 5.3.10 of the IPSAR discusses a proposed licensee program to add a second isolation valve to certain reactor coolant system vent and drain valves which previously had only single isolation.
This modification was performed during the 1985 refueling outage and included the addition of valves to steam drum level instrumentation, the cleanup punp discharge strainer drain, and the recirculating pump drains.
(h) Section 5.3.12 of the IPSAR describes a proposed project to improve warehousing facilities to store qualified materials.
A new office facility was erected during the Fall of 1985, and after the offices now occupying the warehouse space are transferred to the new office building the licensee will be able to address the need for ware-housing for qualified replacement parts and materials.
(i) Section 5.2.15 of the IPSAR discusses the licensee's determination that the tube bundle in each of the containment sphere heating and cooling heat exchangers, which constitutes a containment barrier, is beyond repair.
Both tube bundles were replaced with stainless steel bundles in 1983.
(j) Section 5.3.16 of the IPSAR discusses the need to provide ventilation for the C-52 control panel,-located within containment.
Panel C-52 houses power supplies for heating units for constant head level chambers used to indicate reactor vessel water level.
Plant'
operating experience has shown that changes in temperature in the power supplies causes drift in indicated level.
The ventilation project was completed in 1983 with satisfactory results.
(k) Section 5.3.22 of the IPSAR discussed reactor cooling water system relief valves sticking open during pressure transients resulting from pump transfers.
The licersee had prepared for the 1985 refueling outage a modification to install telltale drains to allow identification of the leaking relief but declined to perform the modification, choosing instead to address the broader problem of why the reliefs lift and how to avoid that lifting and subsequent sticking open.
The licensee hopes to take corrective action during the 1986 refueling outage.
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(1) Section 5.3.23 of the IPSAR described a licensee identified need to install an automated isolation valve on the radioactive waste system.
(RSW) backwash that would prevent inadvertent extended flushing of the monitor.
Extended flushing resulted in excessive and unnecessary.
RSW inventories which required costly processing.
The licensee cancelled the facility modification after retraining operators and demonstrating the adequacy of'that training to provide only that quantity of flushing which is actually necessary to clean the monitor.
In summary, all commitments made by the. licensee on IPSAR' items referenced in the TIA have' been completed or cancelled with the exception of the-reactor cooling water relief valve investigation described in item 11 above.
No violations or deviations were identified in this area.
10.
Regional' Request At the request of Region III the inspector reviewed with the licensee clarification provided by NRR on the use of Licensed Reactor Operators (RO) in supervisory positions requiring a Senior Reactor Operator's (SRO)
license.
The review of this issue and the requirements of 10 CFR 50.54 (M)(iliii resulted from a finding that administrative procedures at Millstone Point Station permit the Supervising Control Operator (SCO) to direct the activities of other licensed operators in the absence of the Shift Lupervisor (SS), a situation that is illegal unless the SCO is SR0 licensed.
Contained in 10 CFR 50.54(M)(2)iii is a requirement that for a nuclear power unit in an operational mode other than cold shutdown or refueling, "each licensee shall have a person holding a Senior Operator Licensee for the nuclear power unit in the control room at all times".
Distinction between operator and senior operator is described in 10 CFR 55.4(d), specifying that an operator manipulates a control of a facility while a senior operator directs the licensed activities of licensed operators.
The NRR clarification notes that the control of activities is the responsibility of an SR0 and cannot be delegated to an R0, and concludes that an SCO without an SR0 license directing the
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activities of other licensed RO's is a violation of the SCO's license.
Big Rock Point Administrative Procedures, Volume I, Chapter 4, states that the Shift Supervisor, who is SR0 licensed, "has absolute authority over all control room activities" and that he "shall provide direct command
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oversight of operations, be responsible for the performance of all personnel assigned to his shift who could affect plant safety, and perform management review of ongoing operations in the plant that are important to safety".
Those. cme procedures permit the SS, who is the only SRO licensed individual on shift, to leave the control room /SS office area to "make periodic rounds and inspections of the plant systems and equipment". When the SS is absent for that purpose procedures require that "he will inform Control Operator I (C0-I) to assume command of the control room".
The CO-I is not SR0 licensed.
The administrative control procedures at Big Rock permit situations contrary to the
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The licensee has received an exemption from requirements to have two SR0 licensed operators on shift.
The licensee at the close of the inspection is reviewing potential solutions.
11.
Open Items.
Open items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both.
Open items disclosed during the inspection are discussed in Paragraphs 3.h and 3.m.
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Exit Interview The inspector met with licensee representatives (denoted in Paragraph 1)
throughout the month and at the conclusion of the inspection period and 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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