IR 05000341/1989002

Insp Rept 50-341/89-02 on 890101-0217.Violations Noted.Major Areas Inspected:Action on Previous Insp Findings,Operational Safety,Maint,Surveillance,Followup of Events,Ler Followup & Regional Request

ML20235Z632
Person / Time
Site:	Fermi
Issue date:	03/03/1989
From:	Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20235Z623	List: IR 05000341/1989002 ML20235Z618 ML20235Z629
References
50-341-89-02, 50-341-89-2, NUDOCS 8903160041
Download: ML20235Z632 (20)

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U. S. NUCLEAR REGULATORY COMMISSION l

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REGION III l

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Report No '50-341/89002(DRP)

Docket No. 50-341' Operating License No. NPF-43 Licensee: Detroit Edison Company ,

2000 Second Avenue Detroit, MI 48226 Facility Name: Ferm Inspection At: Fermi Site,. Newport, Michigan Inspection Conducted: January 1, 1989 through February 17, 1989 Inspectors: W. Rogers S. Stasek K. Ridgway M. A. Ring, Chief 7 Approved By:

Reactor Projects Sec ion 3B %' Date'

Inspection Summary Inspection on January 1, 1989 to February 17, 1989 (Report No. 50-341/89002(DRP))

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Areas Inspected: Action on previous inspection findings; operational safety; maintenance; surveillance; followup of events; LER followup; regional request; CAL followup; TI followup and meeting Results: One~ violation was identified (Paragraph 3a). Two unresolved items were identified (Paragraphs 2d and 3c) and three open items were identified (Paragraphs 5, 7a and 7j).

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8903160041 890306 PDR ADOCK 05000341 U

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DETAILS j l

1. Persons Contacted Detroit Edison Company

• R. Bailey, Supervisor, PQA

• C. Cassise, Maintenance

• S. Catola, Vice President, Nuclear Engineering and Services

• G. Cranston, Director, Nuclear Engineering

• L. Goodman, Licensing

• K. Howard, Principle Engineer, Plant Systems

• R. McKeon, Superintendent, Operations

• R. Matthews, Maintenance )

• Orser,.Vice President, Nuclear Operations )

• Riley, Supervisor, Compliance j

• Shafer, General Supervisor, Nuclear Materials

• Stafford, Director, Quality Assurance

• Svetkovich, Assistant to Plant Manager l

• R. Sylvia, Senior Vice President, Nuclear Operations  !

• Trahey, Director, Special Projects  ;

. U.S. Nuclear Regulatory Commission

• Rogers, Senior Resident Inspector

• S. Stasek, Resident Inspector i K. Ridgway, Inspector j

• Denotes those attending the exit meeting on February 17, 1989.

The inspectors also interviewed others of the licensee's staff during this inspectio . Action on Previous Inspection Findings (92701) (Closed) Violation (341/87009-01(DRP)); Failure to make appropriate out-of-specification log entires for equipment.out of service. The inspector verified that memorandum NP-0P-87-0042, dated February 9, 1987, was issued to operating crew personnel. Additionally, the-inspector interviewed numerous Senior Reactor Operator License holders and verified that they understood the appropriate actions to be taken when inservice test pump results come back unacceptable or outside acceptance criteria. Based upon these interviews the inspector considers corrective action adequate. This matter is considered close (Closed) Open Item (341/85042-03(DRP)): Inadequate LER progra ;

The inspector reviewed LERs ' issued in the previous six months to determine whether these LERs were being submitted in a timely l fashion and that the information being provided appeared accurate and correct. LER corrective actions are tracked under the licensee's 2 i

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Deviation Event Report (DER) System to assure completion. At the

.beginning of 1988 the licensee implemented actions associated with 'j the DER program to assure'that a DER is not closed out until all corrective actions are implemented and not just scheduled to be performed. Based upon these actions the inspector considers'this l matter close (Closed) Open Item (341/88003-06(DRP)): Continuous operation of- 3 safety-related room cooler The inspector was provided with i information that qualified the room cooler for continuous operation, as such, this matter is considered close (Closed) Unresolved Item (341/880C3-05(DRP)): Ramifications of steam leak in the Core Spray Division 2 corner room. Located in the Division 2 Core Spray Room is the Reactor Building Condensate Collection Tank. This tank collects the condensate from the reactor building steam heating system. Specifically, there are a number of plenum heating coils and area heating coils that are fed with auxiliary boiler steam. Each heater is equipped with a steam trap that separates the steam from condensat Condensate is then returned to the collector tank. The tank at the time of the original inspection had an overflow line equipped with a loop seal going to a sump and a vent that terminated at the fifth floor of the reactor building inside secondary containment. The reason for the vent was to relieve any air that accumulated in the tank. However, when some of the heating coil steam traps failed, steam was passed into the condensate collection tank. As the pressure in the tank ;

built up, due to the steam, the loop seal associated with the !

overflow line blew out and the steam entered the Division 2 Core Spray pump room. This steam is what the inspector observe In response to this condition the licensee performed a calculation !

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as to the ramifications of this additional steam or heat input into the room in the post LOCA condition. The results revealed that the post LOCA heat load increased by approximately 50% due to the steam v from the condensate tank. Specifically, the LOCA heat load is 366,388 !

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BTU per hou The licensee calculated that the additional steam intrusion heat load was 194,683 BTU per hour. The calculation determined that there is not enough margin to compensate for this additional 194,683 BTU per hour in the design basis condition of 95 degrees fahrenheit for the emergency equipment cooling water (EECW).

However, given the time frames in which the auxiliary boiler stea:n heating system is in service, it is apparent that the temperature of the EECW water would not be 95 degrees. Therefore, an additional

. analysis at 70 degrees fahrenheit for that water determined that there was adequate margin for the room cooler to maintain the temperature below maximum design temperature for the room in a LOCA l- condition.

In the fall of 1988, the licensee modified the condensate storage tank piping configuration by EDP 8383. The reason for the modification was to remove the loop seal, increase the size of the

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vent line and change the exit path for the vent lin The new vent was routed outside of. secondary containment on the south Reactor Building wall to,the environment. Additionally, the licensee indicated that heating steam. traps would be placed in the preventative maintenance program. However, they are classified as.a priority B and, as such, it is' questionable'whether they will ever be accomplishe Therefore, it can'be assumed that steam intrusion to the condensate storage tank will continue and will be vented out the new line to the environmen During the review of this EDP the inspector had a r aber of concerns as to whether this new vent line is accounted for la the secondary containment verification test for integrit The inspector.noted that a design calculation had been performed confirming that secondary containment integrity would remain intact. However, in the inspector's review of the 18 month Secondary Containment ,

Verification Test 24.305.03, the inspector did not note where any t alteration of acceptance criteria had taken this line into accoun The inspector then contacted the engineering group to determine whether the new 4 inch vent line was in fact seismically qualifie The Licensee Engineering Group responded that all auxiliary boiler-lines in the Reactor Building are designed to meet the two over one seismic criteria and would remain intact during a seismic even i The inspector then inquired how maintenance activities on the  !

condensate storage tank would be controlled to assure that if the tank'were drained down or the drain line were to be opened whether secondary containment would remain intact given that no test had been performed to validate the calculation following EDP 8383 implementation. The engineering staff responded that a blind flange configuration had been fabricated on the end of the vent line such that a blind flange could be installed during maintenance activities. The inspector could not ascertain whether any maintenance instructions existed to control installation of this flang As of February 10, 1989, the inspector had requested the licensee provide him with information as to whether:

(1) The seismic qualification of the vent was performed with the blind flange installe (2) Whether any methods exist to assure that the blind flange will be installed when maintenance is done on the auxiliary boiler heating syste (3) Whether the licensee intends to take credit for the analysis l performed under EDP 8383 for maintaining secondary containment integrity.

l (4) If the licensee does take credit for such, whether they will confirm the calculation through test L-_ - - _ - _ _ _

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( This matter is considered unresolved (341/89002-01(DRP)) pending additional revie During the exit meeting the inspector commented on the excessive

, length of, time the licensee took to accomplish the heat load calculation. The inspector identified the steam intrusion condition.

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to the licensee on March 10, 1988 but it was eight months before the calculation was performed on November 3, 198 (0 pen) Open Item (341/87020-01(DRP)): EX0-Sensor Action Pla '

.To resolve reliability concerns reported under a Part 21 report,.

the licensee implemented an action plan to assure operability of the drywell H2/02 sensors in the Post Accident Monitoring System. This plan consisted of:

(1) Performing a function test of the sensors every 31 day (2) Changing out the sensors every six month (3) Reducing sensing line heat trace temperature 20 degrees fahrenheit to reduce loss of electrolytes, which has'been complete (4) Pursuing with the vendor a new membrane made of a different materia The vendor had proposed a modification of the sensor cell that would significantly reduce the loss of electrolyte by plugging vent holes in the sensor. Tests have shown approximately an 80 percent reduction in the loss. The licensee has reviewed and approved the modification and expects the sensors to now have greater'than a four year service life. When scheduling permits, a normal testing and change out schedule will be proposed that will probably increase testing frequency as the sensors approach their end of lif Records show that the monthly test and semiannual change outs have been performed except during reactor shutdown periods when the instruments' operability was not require This item will remain open until a new schedule is approve (Closed) Open Item (341/88021-07(DRP)): Reactor coolant pump GE type AKF field breaker inspection This is a followup on a Regional Request dated September 24, 1987, concerning breaker surveillance recommended by NRC IN 87-12 and GE SIL 44 Procedure NPP 35.301.602, Revision 21, dated January 19, 1989, RC Pump Generator Field Breaker (GE type AKF) General Maintenance, has been developed replacing MI-M037, Revision 2 and the following preventive maintenance events have been established in the Preventive Maintenance Program:

B621 RCP North PM inspection, lubrication and testing, annual B623 RCP South PM inspection, lubrication and testing, annual B312 RCP North PM inspection, rework as required by vendor 3rd fuel

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B310 RCP South PM inspection, rework as required by vendor 3rd fuel The establishment of these PM schedules fulfills the recommendations of NRC IN 87-12 and this item is closed, (Closed) Violation (341/88037-02d(DRP)): failure of OSR0 to document unreviewed safety question reviews. Procedure FIO-FMP-01, Revision 1, Safety Review Group Organization; dated September 7, 1988, now includes the requirement that any OSR0 approval documented in the Committee Meeting Minutes explicitly means that no unreviewed safety questions exist. The inspector also reviewed recent OSR0 Meeting Minutes and found that this statement was also included in the minutes. This violation is close (Closed) Violation (341/88037-02e(DRP)): Failure to have alternate OSR0 member appointments in writing. The OSR0 Chairman issued a memorandum on August 25, 1988' designating the alternate members of OSR0 which was updated on February 2, 1989 to agree with Technical Specification Amendment No. 30. This violation is close (Closed) Open Item (341/88021-06(DRP)): Main Steam Line Radiation l Monitor Surveillance Procedure causes MSIV closure. This item was left open pending completion of improvements to the I&C Technician Training Program. The inspector reviewed new procedures CP-IC-336, I&C Continuing Training, and OE-IC-020-101, Surveillance Prerequisites, and the revised Instrument Repairman Qualification Program Description, QP-IC-720, Revision 4 and determined that the I&C training program improvements had been satisfactorily completed; therefore, this open item is close (Closed) Violation (341/87021-01(DRP)): Minimum Critical Power i

Ratio (MCPR), A) inadequate safety evaluation and failure to request TS/ Licensee Amendment when required, B) failure to perform safety evaluation during a change to facility operation. In their response to this Notice of Violation dated June 13, 1988, the licensee detailed the corrective actions to prevent recurrence as:

(1) An after the fact safety evaluation was performed April 6, 1987, for removing the Moisture Separator Reheater (MSR) from servic (2) On January 27, 1988, a proposed Technical Specification change was submitted to include the effects of MSR outage on the Minimum Critical Power Ratios (MCPR) and include the MSR operability in the Main Steam Bypass System Limiting Condition of Operations. This proposul has not yet been approved by NR (3) Safety evaluations have been performed and approval obtained for reactor operations above 50 and 75 percent reactor power with reduced feedwater temperatures and these results have been included in the March 1988 UFSAR updat _ _ _ _ _ _ _ _ - _

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(4) A new procedure FIO-FMP-01, Safety Review Group Organization, was developed to define the organization and charter of the safety review groups. It specifies that the Onsite Review i Organization is responsible to ensure that preliminary evaluations and if required, 10 CFR 50.59 safety evaluations are complete (5) Procedure FIP-SRI-01, Preliminary Evaluations and 10 CFR 50.59 Safety Evaluations, was developed, superseding two older procedures. This procedure prescribes the method for performing pes and SEs and defines responsibilities and qualifications of personnel handling these evaluation Preparers, reviewers and approvers of pes or SEs are required to have completed prescribed training. Eighty-two employees have completed the short course required for pes and 288 the long course for either pes or SEs. In addition, for SEs of procedures required by Technical Specifications, preparers and reviewers are required to meet the requirements of ANSI N18.1-1971 and be designated by the Plant Manage The inspector reviewed the above corrective actions and found them to be in effect except for the Technical Specification change awaiting NRR revie (Closed) Violation (341/87014-01(DRP)): Failure to assure that safety-related equipment was not placed in proximity to masonry block walls which had not been analyzed under 00-4479. All specific ,

corrective action for this violation had been taken at the time the l inspection report was completed except that administrative controls i did not appear to be in place which would prevent recurrence of this type of violation. In their response to this violation, dated June 18, 1987, the licensee stated that their new reorganization, which had formed the Plant Safety Group which was later designated as the administrator of the Deviation Event Reporting System, had more clearly defined the responsibilities for control of DERs including their disposition P athra similar problems have occurred since the , organization was established; therefore, this violation is csnsidered close . (Closed) Open Item (341/88023-04(DRP)): Generic implication of improper resolution to IE Information Notice 81-16. To ensure that f ailure to properly resolve IEN 81-16 was an isolated case, the licensee conducted a review of 77 procedural commitments which

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were a result of IENs. The 77 were selected at random of a total l

population of 229 and the review was conducted as a Quality

' Surveillance (No. 88-0304) by Quality Engineering. Of the sample selected, one additional commitment was found to have not been properly implemented. This was in response to IEN 84-36 and was to ensure proper staking of a set screw during reassembly of Limitorque Operators. This item was an open issue awaiting

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l implementation (and tracked as such) which had not been completed at the time the Quality Surveillance was conducted in

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l November-December 198 The licensee determined this to be an l acceptable level of performance with no further actions required !

(other than to resolve specific concerns related to those items identified). The inspector agrees with the licensee's determinatio This item is closed, (0 pen) Open Item (341/88023-03(DRP)): Feasibility of installing additional indication for. Reactor Protection System (RPS)

malfunction. A Potential Design Change (PDC 9564) was initiated ;

to address a possible modification of the RPS circuitry to better i monitor system status downstream of the current indication. The PDC received Nuclear Engineering approval on October 6, 1988, and a Design Change Package is to be developed with a preliminary scheduled installation date of the first refueling outag This item will remain open until the modification is completed.- (Closed) Open Item (341/88008-02(DRP)): Lack of establishing shelf life consistenc The inspector reviewed the new shelf life control procedure, FIP-PM2-02, and noted that instructions had been provided to assure consistent shelf life on like components. Also the inspector reviewed documentation supporting walkdowns of the warehouses under the shelf life improvement program to establish shelf life consistenc This matter is considered close No violations or deviations were identified in this are . Operational Safety Verification (71707)  !

l The inspectors observed control room operations, reviewed applicable logs and conducted discussions with control room operators during the period !

from January 1, 1989 through February 17, 1989. The inspectors verified the operability of selected emergency systems, reviewed tagout records !

and verified proper return to service of affected components. Tours of ;

the reactor building and turbine building were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and l excessive vibrations and to verify that maintenance requests had been i initiated for equipment in need of maintenanc l The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the ;

station security pla I The inspectors observed plant housekeeping / cleanliness conditions and l verified implementation of radiation protection controls. During the inspection, the inspectors walked down the accessible portions of the following systems to verify operability by comparing system lineup with plant drawings, as-built configuration or present valve lineup lists; j observing equipment conditions that could degrade performance; and verified that instrumentation was properly valved, functioning, and I calibrate i High Pressure Coolant Injection System Standby Liquid Control System f

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The inspectors also witnessed portions of the radioactive waste system l controls associated with radwaste shipments and barreling.

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These reviews and observations were conducted to verify that facility ,

operations were in conformance with the requirements established under i technical specifications, 10 CFR, and administrative procedure During these reviews the inspectors observed: The improper storage of emergency diesel generator (EDG) parts in a trailer at the north end of the protected area was observed on January 31, 198 The inspector ascertained that the trailer had 1 been used for control of the EDG overhaul activities during the LLRT outag The parts included filters, gaskets, bolts, nuts and relief valve Most of the parts had the approved requisition on stores j and quality control acceptance stickers still attached. The trailer i ~

was a storage facility for the parts but was not controlled as on Procedure FIP-PM 3-01 requires controlled storag Failure i to properly control this area is considered a violation I (341/89002-02(DRP)) of 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures and Drawing The installation of digital fluke meters in control room panels without evaluating the installation under the temporary modification program. One digital fluke meter was installed to provide temporary indication of torus water temperature while the normally installed recorder was being repaired. The fluke meter was mounted in the same place as the recorder which is located in the H11-601' panel .

(Division I emergency core cooling system panel) in the control l room. Two other fluke meters were mounted in the H11-805 panel in i '

the control room to provide cooling tower temperature while the normal indicators were being reoaired. All three of the weters were  !

installed under the work reque n system without evaluation as to whether a safety evaluation was required. This matt,er appears to i

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be a continuation of problems identified under unresolved items 341/88035-01 and 341/88037-0 As such, these deficiencies will '

be evaluated under those unresolved item During a walkdown of the control room on February 3, 1989, the inspector noted that drywell-to-torus differential pressure (dP)

was zer When questioned, the Control Room Nuclear Supervising i Operator (CRNS0) stated that although original plant design required i l

operating with such a dP, operating experience revealed that a dP could not be maintained. Review of system operating procedure l NPP-23.406, " Primary Containment Nitrogen Inerting and Purge System,"

found that a requirement to have a drywell/ torus dP was still include Further, the current operator training material still included a description of operating with a dP. This appears to be indicative of weaknesses within two areas of concern:

(1) previously, engineering had provided an approved modified mode of

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operation ~for the subject system but programs impacted by the change were not changed (i.e., procedural upgrades, training upgrades), and (2) although operators were aware that current operating philosophy was not in conformance with cperating procedures, no actions were I initiated to resolve the discrepanc The following week, during observation of a routine containment venting process, the inspector noted that the drywell was indicating a lower pressure (negative dP) to that of the torus by as much as approximately 4 inches W.C. at times. When the operators were  !

questioned if there were limits to the allowed amount of negative dP encountered during normal operation, they indicated no limits were specifie Engineering was subsequently contacted and responded that the drywell/ torus dP equalization issue had been fully analyzed to meet the assumptions made in the accident analysis as well as containment loading considerations. When asked if the analysis included operation with a negative dP such as during containment ~ venting operations, the response was that that configuration had not been addressed. Pending licensee evaluation of this issue, actions taken to address the two areas of weakness, and completion of inspector review, this is considered an unresolved item (341/89002-03(DRP)).

No other violations or deviations were identified in this are . Monthly Maintenance Observation (62703)

-Station maintenance activities on safety-related systems and components listed below were observed 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 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 implemente Work reqJests Were reviewed to determine the status of outstanding jobs and to assure that priority is assigned to safety-related equipment maintenance which may affect system performanc The following maintenance activities were observed / reviewed:

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A030890103 Preventive Maintenance on 120 VAC Distribution Pane l Q373881113 Preventive Maintenance on South Control Air i Drye )

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Following completion of maintenance on the above equipment, the inspectors  !

verified that the systems had been returned to. service properl No violations or deviations were identified in this are . Monthly Surveillance Observation (61726)

The inspectors observed the following surveillance testing required by Technical Specifications and verified that: testing was performed in accordance with adequate procedures, test instrumentation was calibrated, limiting conditions for operation were met, removal and restoration of the affected components were accomplished, test results conformed with Technical Specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personne .307 Emergency Diesel Generator No. 14 Operability Verification (S0P run).

24.404.04 Standby Gas Treatment System Division II Operability Tes .321.01 Operability of 480V Swing Bus 72CF Automatic Throwover Schem .000.07 Core Performance Parameter Chec On February 2, 1989, while witnessing the performance of the operability surveillance on Emergency Diesel Generator (EDG) No. 14, the inspector noted that the engine had been started locally in accordance with the system operating procedure (50P), but had not been electrically loaded for an extended period of time (approximately 35 minutes). When the inspector questioned the Nuclear Assistant Shift Supervisor (NASS) and the Control Room Nuclear Supervising Operator (CRNS0), neither was aware the EDG had been running under those conditions. It was then determined, when the CRNSO contacted the operator performing the surveillance locally, that a crankcase manometer had " blown out" upon engine start and the operator was awaiting a refill of the manometer by I&C personnel f prior to loading the EDG. The CRNS0 directed that the operator should proceed with the process of loading the EDG and that manometer refill l

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could be done while the machine was loaded. Although this was accomplished, the end result was the EDG was operated in an unloaded

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condition for approximately one hour, and until questioned by the l

inspector, control room personnel were unaware of the operating statu Subsequently, the licensee contacted the vendor concerning running of the diesel generators unloaded. The vendor's recommendation was to run for no more than approximately 10 minutes in an unloaded condition. The basis for this was that unburned fuel oil would tend to collect in the

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engine's exhaust manifold, soak lagging and eventually have the potential to cause a fire in associated areas. The licensee is currently in the process of revising the appropriate operating procedures to include this recommendatio l

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During the time EDG No.14 was completing its surveillance run, control room differential pressure decreased to zero. Under normal conditions a dP of approximately 0.125 inches is maintained by the Control Center Heating Ventilation and Air Conditioning (CCHVAC) System. When the dP was lost, operators determined from obccrvation of control room panel H11-808 instrumentation that certain dampers had repositioned within the CCHVAC system causing the dP loss. However, there was confusion as to what would cause the particular damper realignments observed. The confusion persisted approximately 15-20 minutes until I&C personnel performing surveillance procedure 44.160.02, " Fire Protection Detection Operability and Functional Test," from control room panel H11-816 indicated the damper realignments were a result of their testing activitie Procedure 44.160.02 will undergo a revision to include precautions that control room personnel should be informed prior to performing steps that affect area d The two incidents noted above indicate an apparent weakness in communication between control room operators and personnel performing activities directly affecting the configuration of important plant equipmen This is considered an open item (341/89002-04(DRP)) pending the aforementioned procedural changes and inspector review of operator awareness levels of ongoing plant status change No violations or deviations were identified in this are . Followup of Events (93702)

During the inspection period, several events occurred, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72. The inspectors pursued the events onsite with licensee and/or other NRC official In each case, the inspectors verified that the notification was correct and timely, if appropriate, that the licensee was taking prompt and appropriate actions, that activities were conducted within regulatory requirements and that corrective actions would prevent future recurrence. The specific events are as follows:

January 3, 1989 Main generator hydrogen leak and subsequent reactor shutdow January 4, 1989 Failure of reactor recirculation motor generator set B field breaker to ope January 8, 1989 Loss of normal (lake) water supply to GSW pump hous January 10, 1989 Loss of Offsite Power to Division I with unplanned engineered safety features actuation . _ _

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January 18, 1989 HPCI steam flow isolation instrument found.not in conformance to Technical Specification January 25, 1989 Excessive seal leakage'on east heater feedpump I and. subsequent power reductio January 26, 1989 Trip of south reactor feedpum January 30, 1989 EHC pressure regulator failure February 8, 1989 Loss of pneumatic air seals to the railroad .

car airlock door such that secondary containment could not be maintained in a seismic even February 9,1989 EDG 12 out for maintenance and Division II of CCHVAC out of service requiring plant to commence shutdown. Unusual Event initiated as a resul '

During the inspection period, the resident inspectors also reviewed security-related reportable event No violations or deviations were identified in this are . Licensee Event Report Followup (92700)

Through direct observations, discussions with licensee personnel, and review of records,.the following event reports were reviewed to determine that deportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with technical specification (Closed) LER 85016, Reactor Scram Due to Instrument Valving erro The inspector verified that the licensee has implemented the design change for a more permanent method of supplying a simulated reference leg signal for reactor vessel' level when the reactor vessel head is of Also, the inspector verified that a maintenance instruction has been written to provide specific instruction on placing the system in service and removing it from service. However, the inspector was not able to ascertain how this particular maintenance !

evolution is sequenced beyond scheduling the evolution on the POD in I the overall refueling effort, such as, how is it verified that this action will in fact take place after the reactor vessel head is !

removed. Subsequent discussion with licensee personnel indicated l there was no master document for controlling the overall refueling l action sequences. The failure to have such a document is considered l an open item (341/89002-05(DRP)) for licensee actio l I (Closed) LER 88-026, Excessive Unidentified Reactor Coolant System Leakage Requiring Plant Shutdow (Closed) LER 88-020, Incorrect High Pressure Coolant Injection ,

Surveillance Test Procedure Causes Reactor Scra l 13 l

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• ' (Closed) LER 87-016, Actuation of the Reactor Protection System Due to Transient in Common Reference Le (Closed) LER 87-025, Actuation of the Reactor Protection System Due to a Transient in Common Reference Le Both LERs 87016 and 87025 identify long term corrective action of the installation of needle valves on the common reactor pressure vessel level instrument racks. Installation of these needle valves is a portion of the corrective action associated with violation response 341/86032-02 and, as such, these LERs were closed and the long term corrective action will be tracked under the violatio (Closed) LER 87-017, Reactor Scram Due to South Reactor Feed Pump Turbine Trip Caused by Excessive Vibration, (Closed) LER 87-037, Inadvertent Actuation of Inboard MSIVs due to Procedural Inadequac This LER was reviewed in Inspection Report 341/87036(DRS), a special inspection for this event, in which a violation was identified for an inadequate safety-related procedure (341/87026-01). The licensee modified procedure POM 23.316 and the inspectors verified the adequacy of the chang (Closed) LER 86-005-01, Loss of Power to RPS Bus A Causes ESF Actuations. This power interruption, while in cold shutdown, caused a number of required ESF actuations and isolations and a half scram to occur. All of these occurred as designed. The investigation revealed that the. normal supply, Motor Generator (M-G) Set A, was running properly, but the Electrical Protection Assembly and the Backup Manual Scram Breakers (BUMSB) were trippe No cause for the trips was identifie During the investigation, the Division I BUMSB would not trip on a low voltage condition or when actuated with the Control Room Pushbutton. The failed breaker was replaced with an equivalent breaker as was the only other breaker of this type, the Division II BUMS The Division II BUMSB operated properly but was changed for consistency. The cause of the failure was attributed to a sticky coating on the trip coil plate and armature faces. The inspector reviewed the Engineering Design Packages for the replacement of both BUMSBs and found them to be complete and in accordance with procedures in effect at the tim (Closed) LER 89001, Control Center Heating Ventilation and Air Conditioning Shifted to the Recirculation Mode Potentially Due to a Defective Solenoid Coi (Closed) LER 89002, Failure of Reactor Recirculation System Field Breaker Due to Mechanical Binding. This LER's corrective actions were reviewed and followed up under Confirmatory Action Letter 89-01 and Special Inspection Report 89003. The only outstanding issue from the LER, in terms of corrective actions, is the implementation

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i of on-the-job training to familiarize journeymen electricians with the proper techniques and critical performance elements for performing maintenance on the AKF-2-25 type circuit breaker. This is considered an open item (341/89002-06(DRP)) until complet The licensee has committed to complete this training by July 31, 198 (Closed) LER 89003, Loss of Division I Offsite Power Due to Bushing Failur . (0 pen) LER 89004,liigh Pressure Coolant Injection Inoperable Due to the Isolation Logic Functioning with a Non-Conservative Trip Valu This LER addressed a licensee identified condition that was discovered on January 18, 1989 where a differential flow transmitter setpoint was not in compliance with Technical Specification Specifically, the High Pressure Coolant Injection (HPCI) Division II differential pressure isolation transmitter (E41-N0578) was found to have a incorrectly calculated head correction which resulted in the tran e.itter's effective setpoint being 441.4 inches W.C. which was non-conservatively 31.4 inches above the Technical Specification allowable value (410 inches W.C.). Licensee review determined the condition had existed since E41-N0572 was installed as part of a work request (WR 010B880725) on November 22, 198 The newly installed transmitter was calibrated via procedure 44.020.204, Revision 20 "NSSSS - HPCI Steam Line Flow - Division II Calibration,"

which had been written using a head correction of 83.8 inches from desi;.e : specification 4572. The design specification had previously been found to be in error and actions were initiated to address the required change to procedure 44.020.20 However, the timeliness of the procedural revision is questionable in that 44.020.204 was not scheduled to include this correction until February 1989. This transmitter was one of two that provided for a HPCI Group 6 isolation on differev.ial steam flow conditions. The redundant transmitter was determierd to be within its required setpoint range and, therefore, would have provided the required isolation function. Also, two area temperature monitors were available to provide for a HPCI isolation on a steamline break event. The inspector reviewed associated logic (schematic)

diagrams and agrees with the licensee's determination of isolation availabilit This will be the subject of a Special Inspection l

Report No. (341/89007(DRP)).

The inspector also reviewed one of the licensee's Deviation Event Reports (DER), which had been documented as not reportable. The report was DER 88-911, regarding incorrect mounting clamps installed on the main steam line radiation monitors. The report describes that from original .

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construction until April 23, 1988, the incorrect uninstruct configuration had been installed on the radiation raonitors. The DER had been dispositioned to replace the mounting clamps with the ones utilized in the design calculation for the radiation monitors. In April of 1988 the plant was j in cold shutdown for the LLRT outage and the repair was accomplished before j the plant returned to power. The inspector asked the dispositioning

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engineer why this condition was not reported under 1G CFR 50.73 as an l

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!' u nalyzed condition. The engineer stated that though the installation was not in conformance with the design calculation it would have withstood a seismic evt.1t. The engineer provided documentation to support his ,

L conclusion. At the exit meeting the inspector stated that this type of I

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documentation should have been part of the DER closure packag No violations or deviations were identified in this are , Regional Request (92701) On January 20, 1989, all BWR plant resident inspection offices were requested to alert their licensees of the Pilgrim Plant's problem of undersized service air accumulators and fail open vacuum breaker isolation valves for the torus to reactor building lin When contact was made with cognizant Deco personnel on January 24, 1989, they stated that DECO was already aware of the Pilgrim problems and these were being or had been addressed during their review of NRC Generic Letter 88-14, Instrument Air Supply System Problems Affecting Safety Related Equipment. Later when additional information was requested by the Region, including air supplied door seals, Deco statsd they were also aware of this issue and were reviewing i The noninterruptible air system (NIAS) at Fermi 2, which is intertied with the station air (SA) and interruptible air system (IAS) is a seismic Category 1 system of two independent divisions which supply control air to all safety systems. Each division has a compressor, cooler, dehydrator, air dryer, pre and after filters, ,

and receiver The NIAS compressors do not normally operate but start automatically on low air pressure, containment isolation, or loss of offsite power at which time the NIAS system is automatically isolated from the SA and IA The NIAS compressors and coolers are supplied with RBCCW or EEC NIAS supplies control air to ECC Systems, EECWS, SGTS, RHR, control center air conditioning (including pneumatically operated dampers),

primary containment atmosphere monitor system, SRVs, and MSIV Leakage Control Syste ;

NIAS also supplies air to the two normally closed butterfly isolation valves associated with the two normally closed torus reactcr building vacuum breakers. The isolation valves are opened by a signal when a negative differential pressure exists between the torus and reactor building or upon failure of the NIAS or the emergency power as the isolation valves are self actuating to ope The two normally closed vacuum breakers are also self actuating upon a negative pressure and both are considered to be isolation valve The torus to reactor building vacuum breaker arrangement is not in conformance with 10 CFR 50, Appendix A, Criterion 56, since both the isolation valve and vacuum breakers are outside primary containment and the fail safe opening of the isolation valve on air or power

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failure leaves only one containment isolation barrie This variance is described in the UFSAR. The vacuum breaker isolation valves are included in the Inservice Testing Program, type B and C containment leak testing, monthly operational checks, and weekly position verification As a result of this review no further questions on the vacuum breaker / air supply configuration remain. With regard to the question on the railroad car door air seal this matter will be the subject of special Inspection Report No. 341/89006, The Resident Inspector was requested to followup on a recent event which occurred at Dresden Station for applicability to Fermi On January 10, 1989, two ball check valves in control rod drive hydraulic control unit charging lines at Dresden were discovered to be missing their internal balls. This could have allowed the associated HCU scram accumulators, instead of discharging through the scram inlet valves during a scram as designed, upon a loss of CRD pumps, to discharge through the charging line. The inspector verified that the subject ball check valves (C11-F115) are required, and have been, operability tested at Fermi once per 18 months via a Technical Specifir:ation required surveillance. Procedure 44.010.201,

"CRD Hydraulic Unit Calibration and Functional Test," was reviewed and determined to be satisfactory to detect a problem similar to that found at Dresde I No violations or deviations were identifie . Followup on Confirmatory Action Letter (92703)

(0 pen) CAL-RIII-88-20: This CAL, issued July 15, 1988, dealt with two I events of compression fitting failures in a Reactor Water Cleanup (RWCU)

instrument line in May and July 1988. The CAL documented actions on eight points of which only one remains open, the inspection of fittings on the RWCU system and eight safety-related systems (see Inspection Report No. 341/88026).

The licensee established a schedule for the above inspections and has completed six of nine systems. The inspections have been completed ahead of the scheduled times. The inspections completed have included 104 lines with 1763 fittings. Of these, 802 fittings were found to be acceptable, 741 failed the "go-no go" gap test, 73 contained mixed Parker-Hannifin

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l and Swagelok parts, and 74 failed the minimum ferrule engagement of at least half of the tube All mixed part fittings were corrected to similar parts, preferably Swagelok, and all inspected connections have been tested and left in an acceptable conditio l Inspection and correction work continues on the remaining three systems where an outage is not required. All inspections are expected to be completed prior to the end of the first refueling outag This CAL remains open until the inspections are completed, i

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10. Review of Temporary Instruction TI 2515/99, BWR Power Oscillations )

f l The inspector completed a review during the inspection period of licensee l

actions in response to requirements and recommendations developed for the industry as a result of the March 9,1988 power oscillation event at LaSalle County Station Unit 2. The first part of the review was conducted during an earlier inspection as documented in Inspection Report No. 341/88035. Temporary Instruction (TI) 2515/99, " Inspection of Licensee's Implementation of Requested Actions of NRC Bulletin 88-07 'BWR Power Oscillations,'" provided the guidelines followed throughout the revie Appropriate procedures were previously reviewed, as well as interviews conducted with licensed operators to determine level of knowledge of this event, and associated pertinence to Fermi. During this inspection period, the inspector completed additional interviews of operations personnel including two Reactor Operators, one Nuclear Assistant Shift Supervisor (NASS), one Nuclear Shift Supervisor-(NSS) and two Shift Technical Advisors (STAS) on this subject with all demonstrating an acceptable level of familiarity with the issues. A walkthrough of pertinent procedures was done with the majority of those interviewed with good results. Training records were reviewed and associated lesson plans evaluated for completeness of information provided and timeliness of the training performed in this are All aspects appeared adequat Subsequent to the inspector's earlier review, the licensee identified and revised additional procedures potentially affecting the subject area. The inspector thereafter reviewed the following procedures in addition to those previously, and verified proper incorporation of appropriate requirements / recommendations:

NPP 20.123.01 Loss of Condenser Vacuum NPP 20.131.01 Loss of General Service Water  ;

NPP 20.138.02 Jet Pump Failure ARP 3D102 APRM Upscale ARP 3D103 APRM Downscale i NPP 22.000.03 Power Operation 25 percent to 100 percent j to 25 percen On December 30, 1988, NRC Bulletin 88-07, Supplement 1, " Power Oscillations in Boiling Water Reactors (BWRs)," was issued and required additional action to be taken by BWR licensees. Because of the proactive nature of the licensee's response, including incorporation of earlier recommendations subsequently imposed by the bulletin supplement, no additional corrective actions were required of the licensee beyond those already in place; including addressing all of the GE interim stability recommendations described in the attachment to the bulletin. This TI is close . Meetings On January 6, 1989, the Technical Specification Improvement Program (TSIP) leaders met with the resident inspector to discuss the remaining work items in the TSI The items remaining were:

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(1) Complete the review of the SR0 LC0 packages and identify any open items or Technical Specification change (2) Assure all Technical Specification artic'le package outstanding items are identified on the open items lis (3) Complete the composite open items lis (4) Assure the situational surveillance'and refueling trigger points are satisfactor (5) Obtain Plant Identification System (PIS) numbers for the 89 remaining packages for the surveillance / maintenance cross reference document from engineering. Targeted completion date was March 1, 1989.-

(6) Review the new surveillance tracking program and identify an weaknesses. This would be completed by April 1, 198 (7) ~ Complete the validation of Revision 20 of some 43 and 44 series procedure (8) Establish a mechanism to address the non-mandatory rocedure comments to assure that the comments are considered addressed, On January 6,1989, a conference call was held between NRR, Region III, the licensee and the resident inspector to discuss the emergency core cooling setpoint issue of Violation'88021-02. The major discussion point was a quantification of the reduction in the margin of safety due to instrument inaccuracy. The licensee considered the reduction as minima The call ended with no resolution on the matte . Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations or deviations. Two unresolved items disclosed during the inspection are discussed in Paragraphs 2d and 3 . 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. Three open items disclosed during the inspection are discussed in Paragraphs 5, 7a and 7 . Exit Interview (30703)

The inspectors met with licensee representatives (denoted in Paragraph 1)

on February 17, 1989, and informally throughout the inspection period and summarized the scope and findings of the inspection activities. The i

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inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection. The licensee did not identify any such documents / processes as proprietar The licensee acknowledged the findings of the inspection, i

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