IR 05000155/1985007
| ML20128A149 | |
| Person / Time | |
|---|---|
| Site: | Big Rock Point File:Consumers Energy icon.png |
| Issue date: | 06/27/1985 |
| From: | Boyd D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20128A146 | List: |
| References | |
| 50-155-85-07, 50-155-85-7, NUDOCS 8507020576 | |
| Download: ML20128A149 (11) | |
Text
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
k
.
}
U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-155/85007(DRP)
Docket No. 50-155 License No. DPR-6 Licensee: -Consuners Power Company 212 West Michigan Avenue Jackson, MI 49201 Facility Name: Big Rock Point Nuclear Plant
' '
Inspection At: Chcrlevoix, MI 49720 Inspection Conducted: April 30, 1985 - June 10, 1985
.
.
Inspector: S. Guthrie Y '</ 6-2'7-85 Approved By: D. C. Boyd, Chief Projects Section 2D Date
!
1r.spection Sumary inspection on April 30, 1985 - June 10, 1985 (Report No. 50-155/85007(DRP))
Treas Inspected: Routine, unannounced inspecticn conducted by the Senior Resident Inspector of licensee actions on Previous Inspection Findings, Operational Safety Verification, Monthly Maintenance Observation, Reactor Trips, Licensing Activities, and Followup On Regional Requests. The inspection involved a total of 112 inspector-hours by one NRC inspecto Results: Of the six areas inspected, no violations or deviations were ( identified. Herever, several areas of safety concern were discussed with plant management ir.cluding: the increasing evidence of personnnel error (paragraphs 3.f and 3.g); and the general lack of identification of piping and components
'
throughout the facility (paragraph 3.j).
,
!
,
0507020576 850628 .
. PDR ADOCK 05000155 l G PDR i
_ _ _ _ _ _ - _ _ _ _ _ - _ - _ - _ _ _ _ _ _ _ _ _ - _ - _ -
.
.
DETAILS Persons Contacted
- D. Hoffman, Plant Superintendent G. Pettijean, Technical Superintendent G. Withrow, Maintenance Superintendent
- R. Alexander, Technical Engineer
- A. Sevener, Operations Superintendent R. Abel, Operations and Maintenance Superintendent )
- L. Monshor, Quality Assurance Superintendent 1 R. Barnhart, Senior Quality Assurance Administrator !
J. Lovell, Quality Control Supervisor E. McNamara, Shift Supervisor W. Blissett, Shift Supervisor D. Swem, General Engineer G. Sonnenberg, Shift Supervisor D. Staton, Shift Supervisor
- D. Wilks, Maintenance Supervisor The inspector also contacted other licensee personnel in the Operations, Maintenance, Radiation Protection and Technical Department * Denotes those present at exit intervie . Licensee Action on Previous Inspection Findings (Closed) Violation Severity Level 4 (155/83004-03). Failure to establish controls in the area of material contro In response to this violation the licensee committed to review Volume 13 " Material Control" of the Big Rock Point Manual and to revise the scope of the Quality Assurance Department Procedure. The inspector verified that section 5.2.2 of Procedure 13.3 of Volume 13 was revised to address: (1) the need to protect sensitive internals, threads, and weld end preparations; (2)
prohibition of storage of food or drink in the Q-stockroom or warehouse; (3) availability of items for storage and handling while minimizing risk of damage. The inspector also verified that the Nuclear Quality Assurance Department Procedure (No. X-4) was revised in section 5.3.1 to state that storage area inspections or surveillances would be performed in accordance with locally developed checklists which identify the items / areas to be inspected, characteristics and conditions of items to be verified, and to specify acceptance criteri (Closed) Open Item 155/78009-02, Nuclear Mutual Limited Fire Inspection of October 23, 1978. This item has been open since 1978 and is being closed because it now is moot. Fire protection provisions now are required by 10 CFR 50.48 and Appendix R to 10 CFR 50 which were published in 198 L
._ ___ _ ___________ ________ -
.
(Closed) Open Item (155/840xx-03); Part 21 Peport from GE on Use of Locktite-242; This was the subject of open item 155/84-07-04 which was closed in Inspection Report 155/8401 . 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 eouipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations I and to verify that maintenance requests had been initiated for equipment in need of naintenance. The inspector by observation and direct interview verified that the physical security plan was being implemented in accord-ance with the station security pla 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, Peactor Depressurization Post Incident, Core Spray and Containment Spray systems to verify operability.
1 On May 23 the inspector discussed with the licensee two observed instances of licensee personnel exiting a controlled area without using a monitoring device to check for contamination. The licensee agreed on the need to reinforce among its workers the importance of personnel monitoring to reduce the spread of contaminatio On April 30 the inspector observed the arrival on site of new fuel for Cycle 21. The inspector's observations included security precautions, verification of shipping container integrity, proper t container handling, appropriate coverage by radiation protection
! technicians, Quality Control inspectors, and a vendor representative, and careful handling of fuel assemblies during inspection and storage. The entire evolution was conducted according to approved procedures, On May 1 an inspection by the Shift Supervisor identified leakage of the No. 1 Reactor Recirculation Pump Seal. The pump was idled and isolated and the reactor operated on single loop recirculation until a replacement seal was overhauled. The unit was shut down on May 15 for seal replacement. On May 1, during the recirculation purp isolation, the pump suction valve, N003A, failed to close on signa The valve was closed by hand. Repairs were completed to contacts in the valve motor circuitry and N003A was test operated and declared operable prior to entering the outage period May 1 On May 25 the licensee observed a steadily increasing level of airborne contanination in the containment sphere and received an alarm indicating a steam leak in the containment pipeway. A leak
be -
.
.
rate calculation indicated an unidentified leak rate of 0.942 gallons / minute. The licensee began reducing power and conducted inspections that identified blown packing in motor operated valve IA-60B, Controlled Seal Leakage to 3/4" Heat Exchanger for Reactor Recirculation Pump No. 2. The reactor was shut down and attempts were made to backseat the valve to reduce packing leakage without success. The recirculation pump was isolated, IA-60B repacked, and the reactor returned to service on May 26. System inspections conducted as part of the startup procedure revealed continued leakage of IA-60B packing. Attempts to adjust the newly installed packing resulted in the breakage of a packing gland bolt. The unit was shutdown and repairs to IA-60B completed. The reactor returned to service at 12:31 a.m., May 2 e. On May 31 the licensee's Corrective Action Review Board concluded that because pipe hanger SH-102 supporting Reactor Depressurization System (RDS) piping inside the stean drum enclosure had been found to be detensioned the RDS system must be declared inoperable based upon RDS piping being outside design analysis. The hanger normally has a constant pretension of approximately 2200 pounds but during a recent outage was observed to be totally detensioned. The licensee reported that approximately 6 years ago the hanger was pulled from the wall during a hydrostatic test of the steam drum. For subsequent hydrostatic tests the licensee determined that the hanger should be detensioned and uncoupled from its mount. At some undetermined point the hanger was uncoupled and not retensioned until ater the discovery on May 25, 1985. Big Rock Point technical specifications do not address hanger requirements. However, the licensee conservatively declared the RDS system inoperable and a reactor shutdown was commenced. When reactor power was reduced to a level that permitted personnel entry into the steam drum enclosure, approximately 16 MWE, the hanger was tensioned to a predetermined setting for plant tenperatures and the shutdown was terninated before the unit was completely shut down. The tensioning activity took less than ten minutes, and the reactor was returned to full power operatio The Big Rock Point Manual, Volume 9A, Site Emergency Implementing Procedures, requires that whenever failure to meet a Limiting Condition of Operation results in a mandatory reactor shutdown a declaration of an unusual event must be made. Big Rock Manual Volume 1, Table 1.15-6, one hour reporting requirements, specifies that the declaration of any emergency class in the Site Emeraency Plan is reportable within one hour under 10 CFR 50.72 (a)(i}. The licensee notified NRC Headquarters via telephone of the unit shutdown but made no mention of the Unusual Event declaration. NRC Headquarters was unaware of the Unusual Event status until the plant phoned to cancel that status. A review by the licensee pointed out some confusion among personnel about the various reporting requirements, the several governmental organizations that are on the notification list, and the time limits for notification. The licensee is preparing a memorandum to Shift Supervisors offering guidance and clarification of this error, and is also investigating the possibility of reducing the number of required phone call .
.
The inspector reviewed the occurrence and concurred with the licensee's evaluation that the failure to notify NRC of an Unusual Event status was due to human oversight possibly influenced by cunbersome reporting requirements and not attributable to any procedural deficiency. The inspector expressed a general concern that the complexity of the Shift Supervisor's role in determining Site Emergency Plan classifications, identifying all the procedural and regulatory reporting requirements, and actually making the telephone notifications could distract the Shift Supervisor from the more important role of directing plant operations to place the reactor in a safe condition, mitigate the effects of an accident, and prevent the uncontrolled release of radioactivit The inspector noted that, in his view. .he licensee was not obligated by the requirements of the Technical Saccifications or 10 CFR to imediately shut down the reactor and (fect repairs on hanger SH-102. The inspector noted the conservative approach taken by the licensee in identification and resolution of the problem. The licensee informed the inspector that they have conducted a study to determine the effects on RDS piping of having the hanger detensioned for as much as six years. The evaluation determined that the piping was not subjected to stresses greater than those experienced during hydrostatic testing which involved unpinning of the hanger as described above. The licensee stated their intentions to replace the hanger with a type that would eliminate the need for the unpinning activit f. On May 27 the licensee determined that two control rods, B3 and E4, had been withdrawn out of sequence during a startup following repairs to M0-IA-608. The rods should have been pulled to position 02 and were instead pulled to position 04. A review by the Reactor Engineer determined that no reactor thermal limits had been exceeded. The reactor was near the end of cycle for the present fuel load, and the rod notches involved were are of low reactivity worth. The error is of minimal safety significance. The licensee determined the cause of the incident to be inattentiveness on the part of the operator. The licensee reviewed the occurrence with the operator involved. The inspector determined that this rod withdrawal out of sequence event is not related to an earlier incident of the same type documented in section 3.d of Report No. 85002 in which operators used the incorrect withdrawal sequence when more than one was available. This incorrect rod withdrawal sequence normally would be considered a level IV violation but because it was discovered and corrected by the licensee, and meets all of the criteria of the Enforcement Policy for self identification (10 CFR 2, Appendix C, Part V.A) no notice of violation will be issue g. On May 16 Maintenance Department personnel discovered incorrect tagging on valves isolated for the recirculation pump repairs. The recirculation pump discharge hypass valve, P0-N002A, was to be tagged closed. The valve had been closed, but M0-IA-60A, Controlled Seal leakage isolation to the 3/4" heat exchanger for No. I recirculation pump seal cooling, was closed and tagged in error. The licensee
_
.
.
informed the inspector that the valves are not similar in size or appearance, and that the incorrect tagging was attributable to human error. The licensee stated that no second check had been performed to verify correct placement of the tags because of the high radiation dose rates in the area. The licensee is reviewing photographs of the recirc pump room to use as an aid to operators for minimization of stay time and correct component identification. The Operations Superintendent issued a memorandum to operators noting operational incidents involving human erro h. On May 16 the licensee informed the inspector of an error in identification of pipe located in the turbine building that resulted in a section of turbine oil vapor extractor atmospheric vent piping being cut and relocated. The line had been incorrectly identified to the contractor as a turbine building roof drain by the licensee. The contractor, who was performing the work at the verbal request of the licensee's Project Engineer, had no responsibility for misidentifi-cation of the line. The safety significance of the incident is minimal; however, the inspector related his concern to the licensee that the failure of the Project Engineer to prepare and process for approval the work authorizations required for work performed by contractors implies an administrative problem with the potential for creating other incidents of greater severity. This is the second instance in six months where licensee personnel have acted to circumvent procedural requirements, the first being an attempt to bypass a quality control holdpoint as documented in section 3.e of Report No. 8401 Further, it is the fourth example in this inspection period of a deficiency in the operation of the facility attributable to human error (others are discussed in sections 3.e.,
3.f., and 3.g.). All four of these examples could have been viola-tions except that they were discovered by the licensee and otherwise net the criteria of the Enforcement Policy (10 CFR 2, Appendix C, PartV.A.). Therefore, no notices of violation were issue However, the entire issue of human errors will be carried as an unresolved item pending completion of corrective action (155/85007-02)
1. During this and previous inspection periods the inspector observed the effect of the licensee's corporate reorganization on the site Quality Assurance (0A) group. Following the termination of the Midland facility the licensee, in November,1984, reorganized and assigned many of the functions previously performed by General Office (GO) groups to the licensee's two operating nuclear plants. Big Rock site OA became responsible for the site Inservice Inspection Program, nuclear fuels procurement, the reactor physics package for each fuel cycle, and reviews of work performed by engineering at G0 in support of activities at Big Roc In addition, site QA took over the Appendix R Pemote Shutdown project and the Environmental Quali-fication of Electrical Equipment (EEQ). Both projects should be completed in 1985. The inspector related his concern in Report N /85-02(DRP) that these reassigned duties, when added to the full work load of audits and surveillances already scheduled for
L_
.
.
1985, would appear to be beyond the capacity of the site QA group without a corresponding increase in manpower. The Quality Assurance Program Description, CPC-2A, section 1.7.5, gives the Nuclear Assurance Department Executive Director responsibility for "estab-lishing staffing levels based on workload analysis and experience of manpower versus task history". Aside from discussions during a November 1984 staff meeting no fornal, documented task or workload analyses were performed prior to transfer of QA functions to Big Rock site QA. The Quality Control (QC) function of the QA organization is not affecte On May 17 the inspector met with licensee management to express his concern. The licensee agreed only to continue to monitor the situation, and declined to commit to additional qualified personnel at Big Rock or to reassignment of any newly transferred program The licensee claimed to have adequate numbers of QA auditors available at the Palisades facility and to have contractor personnel available. The licensee acknowledged that the site QA Superintendent had reported concerns similar to the inspector's in each of his last three monthly reports, but differed with the inspector's stated concern that the matter warranted urgent attention by managemen The site QA Superintendent has been actively attempting to transfer the fuel procurement program to another grou The inspector's review indicated that as of May 1 the number of audits completed in 1985 is comparable to the number completed for the same period in 1984 All audits on the original schedule for 1985 have been completed. The Big Rock OA group has withdrawn its obligation to support three audits at the Palisades plant in the fall of 1985, and has transferred an estimated twenty percent of its surveillances to the site QC group. (An audit differs from a surveillance by its greater depth of review.) Through discussions with QA personnel the inspector concluded that the reduced time available to devote to surveillance has resulted in reviews that are less comprehensive. Further, the QA personnel expressed their concern that they no longer have the time available to spend in the plant using their judgment and intuition to identify and to address areas of concer During the May 17 meeting with licensee management the licensee expressed an identified goal of reducing the site QA involvement with the review process for procedures and engineering documents generated at Big Rock, citing the heavy time investment in reviews that in some instances expand into major rewrites. The licensee noted the need for increased awareness of procedural and code requirements among the engineers preparing documents for 0A review. The inspector indicated his concern that while improvement in the quality of document preparation by site engineers is a valid management objective for better utilization of OA inspectors, it is not a potential solution to the basic concern that the 0A departnent work load is too heav The depth of the QA reviews now required points out the need for heavy continued 0A involvement until after the site engineering group has improved the quality of document preparatio L
.
.
j. On May 21 the inspector participated as an observer in the annual emergency exercise conducted by the licensee which was evaluated by the Federal Emergency Management Agency (FEMA) and Region III emergency preparedness specialists. The inspector's conments were incorporated into Inspection Report 50-155/85004 (DRSS). The inspector participated in the public meetings with local official k. Of the four examples of human error noted in section 3.h. above, two were related. The first involved incorrect tagging on valves in the recirculation pump room and the second involved cutting and relocation of a piece of oil vapor extractor line nistaken for a roof drain. Both occurrences are described earlier in this repor The inspector registered his concern with the licensee that one factor tending to increase the likelihood that this type of error will continue to occur at this facility is the inadequacy of component and piping identification throughout all areas of the plant except the control room. Most valves are identified with a brass tag approximately 1.25 inches in diameter using stamped numbers and letters approximately 3/8" high. Descriptive nomenclature is not provided. Most pumps, tanks, equipment, piping, indicators, and parameter sensing and transmitting components are not identifie Specific components have been marked by numbers, symbols, or notes handwritten in pencil or marker pen on the component or on an adjacent wal Piping is not marked for fluid being contained or direction of flow. Electrical switching equipment is generally better labeled than mechanical component During tours and interviews with plant personnel over a period of several nonths the inspector concluded that there are many unnarked components in all areas of the plant which operators and technicians are not able to identify, and that for some components marked with brass tags the personnel were not able to describe the component's function. The inspector questioned how an operator's inability to identify an unnarked component would affect that person's abililty to respond to emergency situations, and stated that confusion about component identification during maintenance activities or normal operational evolutions could endanger personnel and adversely impact on plant safet Knowledge of component identification and function among operators nay be of increased concern as older, more experi-enced operators are being replaced by persons with less Big Rock experienc The licensee is currently involved in a control room design review study which addresses the human factors aspects of labeling, prinarily in the control room. The Operations Department has a program to mark components identified to them as needing labeling, but this informal program is not being actively implemented and has no stated goals or tine schedules. The inspector requested that the licensee drvelop and aggressively implement a fomal program to label all components in the plant with numerical and/or descriptive identification and to mark all pipes for contents contained and direction of flow. The labeling program requested would be at least as comprehensive as that conducted at the Palisades facility during
i
.
.
the period 1979-1981. The licensee made no committment other than to study the matter. Licensee actions will be tracked under open item (155/85007-01).
No violations or deviations were identified in this are . Monthly Maintenance Observation Station maintenance activities of safety related systems and components listed belcu 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 specification The following items were considered during this review: the limiting conditions for operation were met while components or systens 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 implemente Work 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, On May 22 the inspector observed portions of maintenance performed to repack No. 1 Reactor Feed Pump (RFP). On May 27 reactor power was reduced to approximately 45 MWE to repack No. 1 RFP. The repairs were completed and the unit returned to full power operatio On May 22, operators observed a flange leak on No. 2 RFP. The leak disappeared, but following the plant evolutions of May 25 - 27, the flange leak was again observed. At the close of the inspection period the flange was leaking at a low rate while the licensee evaluated corrective actio Between May 1 and May 15 the inspector observed portions of the rebuilding of the replacement seal for No. 1 Recirculation Pum The rebuild and subsequent testing was conducted according to a procedure developed specifically for the evolution using off site assistance. The licensee involved the vendor and utilized the services of two consultants to provide supervisory guidance, thus conserving allowable exposures for plant workers in anticipation of the upcoming refueling outag The inspector reviewed the machinery histories, maintenance orders, procedure MGP-15, Valve Preventive Maintenance, and Periodic Activity Control Sheets (PACS) for IA60A and IA608. Valve IA60B experienced a packing leak in February,1984, that necessitated a forced shutdow The valve had received a packing adjustment in 1979, but histories dating to 1977 showed no other packing activity. Valve IA60B showed a similar record of preventive maintenance (PM) activity, with adjust-
L ._ _ _ _ _ _ _ _ - -
.
.
ments in 1979, 1981, 1983, and 1984 The inspector expressed his conclusion to the licensee that the forced shutdown of May 25 caused by IA60B packing failure could have been avoided had the PM progran been structured to perform pH work on components before they display warning signs of impending failure. In the case of IA60B, the failure of IA60A, a valve with an operational and maintenance history nearly identical to that of IA608, could have signaled the need to repack IA60 No violations or deviations were identified in this are . Reactor Trips On May 25, with the reactor shutdown and all control rods inserted, the Reactor Protection System (RPS) generated a trip signal on upscale /
downscale differences in picoammeter readings. Channel one was out of service for maintenance with one upscale trip signal inserted when a spurious downscale signal was inserted from channel three. Spurious signals while shutdown are a known operating characteristic of the picoammeters and result from the instrument's high sensitivity to electrical noise. There was no safety hazard presented by the even The licensee stated their intention to seek exenption from the reporting requirements of 10 CFR 72 for this type of RPS system actuatio No violations or deviations were identified in this are . Licensing Activities The inspector provided input to the Office of Nulcear Reactor Regulation (NRR) staff review of the licensee's application for relief from testing of certain valves in the feedwater system as required by Technical Specification, Section 9, Inservice Inspection and Testin The inspector provided input to the NRR staff review of the licensee's January 30, 1985, application to change Technical Specification, Section 6, Organizatio At the request of NRR the inspector provided input to the NRR staff review of the licensee's application to change Technical Specifications to include a definition of operability and associated Limiting Conditions of Operation (LC0). The topic is addressed in section 5.3.24 and Table of the Integrated Plant Safety Assessment (IPSAR), NUREG-0828. The inspector continued to point out the need to define the term " hot shutdown" specified in Technical Specifications Section 3.1.5.A, Reactor Depressurization System (RDS) Operability and used in several operating procedures, but not now define . Followup on Regional Requests During the inspection period the inspector reviewed the licensee's handling of IE Information Notices (IN). The licensee has single point accountability for action on all IN's received, and each IN receives,
-
. . . . _ ._ _
.. . - _ ____ ._ ___
!
.
.
.
l as a minimum, review by the Technical Engineer and the Plant Review
- Committee (PRC). The inspector regards licensee action on IN's as
) appropriat i
' Open Items Open items are matters which have been discussed with the licensee, which i will be reviewed further by the inspector, and which involve some action l on the part of the NRC or licensee or both. Open itens disclosed during the inspection are discussed in Paragraph l Unresolved items Unresolved items are matters about which more information is required in !
order to ascertain whether they are acceptable items, violations, or deviations. Unresolved items disclosed during the inspection are dis- ,
cussed in Paragraph '
,
,
( 10. Exit Interview (
i The inspector met with licensee representatives (denoted in Paragraph 1) .
J throughout the month and at the conclusion of the inspection period and I sumnarized the scope and findings of the inspection activities. The j 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 j proprieta r ;
!
,
<
f'
I l
l
-
)
l
!
i.
!
i'
_ - _ _ - _ _ - _ _ _ _ - _ _ _ _ _ -. _ _ _ - . _ _ _ _ _ _ _ _ _ _ ____
i