IR 05000341/1986023

Safety Insp Rept 50-341/86-23 on 860630 & 0701.No Violations or Deviations Noted.Major Areas Inspected:Previous Insp Findings in Accordance W/Insp Procedures 30703 & 92701

ML20212A203
Person / Time
Site:	Fermi
Issue date:	07/21/1986
From:	Gautam A, Muffett J, Ulie J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20212A164	List: IR 05000341/1986023 ML20212A159
References
50-341-86-23, NUDOCS 8607280139
Download: ML20212A203 (8)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION III

Report No. 50-341/86023 Docket No. 50-341 License No. NPF-33 Licensee: Detroit Edison Company 2000 Second Avenue Detroit, MI 48224 Facility Name: Enrico Fermi Nuclear Power Plant, Unit 2 Inspection At: Enrico Fermi Nuclear Power Plant, Monroe, MI Inspection Conducted: June 30 and July 1, 1986 Inspectors: A. S. Gautam 7!d !8G Date J. M. Ulie 7[2.l f% '

, Date T i\ E vWU  % y /

Approved By: J. W. Muffett, Chief "I /2.\ /8b Plant Systems Section Dat6

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Inspection Summary Inspection on June 30 and July 1,1986 (Report No. 50-341/86023(DRS))

Areas Inspected: Announced special safety inspection by two regional inspectors of the licensee's actions on previous inspection findings. This inspection was conducted in accordance with Inspection Procedures 30703 and 9270 Results: No violations or deviations were identifie PDR ADOCK 05000341 G PDR

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DETAILS 1. _ersons P Contacted Detroit Edison Company (DECO)

• J. Conen, Licensing Engineer S. Heard, Operations Coordinator

• D. Holland, Nuclear Fire Protection Specialist R. Juhasz, Electrical Preventative Maintenance Engineer

• R. Olson, Systems Engineer

• G. Overbeck, Operations Superintendent U. S. Nuclear Regulatory Commission (NRC)

W. Rogers, Senior Resident Inspector The inspectors also contacted other plant personnel including engineering, maintenance, and operations personne * Denotes those present at the exit meeting conducted on July 1,198 . Licensee Action on Previous Inspection Findings (Closed) Open Item (341/84049-03): The licensee agreed to revise all of the technical specification surveillance procedures incorporating the appropriate reference to NFPA Standards acceptance criteria as applicabl The inspector verified that applicable NFPA Standard (s) had been inccrporated into the reference section of the following technical specification surveillance procedures:

(1) Surveillance Procedure 24.501.01, Revision 9, dated January 7,198 (2) Surveillance Procedure 24.501.02, Revision 10, dated December IF, 198 (3) Surveillance Procedure 24.501.03, Revision 4, dated March 15, 198 (4) Surveillance Procedure 24.501.04, Revision 7, dated December 18, 198 (5) Surveillance Procedure 24.501.05, Revision 5, dated February 21, 198 (6) Surveillance Procedure 24.501.06, Revision 4, dated March 22, 198 (7) Surveillance Procedure 24.501.07, Revision 9, dated November 26, 198 .

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(8) Surveillance Procedure 24.501.08, Revision 7, dated March 3, 198 (9) Surveillance Procedure 24.501.09, Revision 5, dated March 19, 198 (10) Surveillance Procedure 24.501.10, Revision 4, dated February 25, 198 (11) Surveillance Procedure 24.503.02,- Revision 3, dated March 27, 198 (12) Surveillance Procedure 24.504.01, Revision 4, dated March 18, 198 Based on the above review, this iten is considered close b. (Open) Open Item (341/84049-04): By letter dated February 18, 1985, the licensee indicated that by June 30, 1985, a specific walkdown would be conducted to identify any potential deviations from the NFPA codes. The licensee also indicated that any deviations identified would either be corrected or specifically justified to the NRC in writing. This item remains open pending completion of this walkdown and its finding Impell Corporation (Report No. 1020-018-01) performed an NFPA code review and submitted their results to the licensee in a report dated June 14, 1985. This report identified eight deviations from NFPA Codes 12-1977, 12A-1977, 13A-1976, 14-1976, 20-1970, 24-1970, and 518-1977. The inspector confirmed that seven of the eight deviations have been corrected including procedural changes, installation of identification markers, and fire department connection (Automatic Sprinkler / Standpipe Systems) protective caps, and that related signs have been installed. The remaining deviation shows that pressure gauges need to be provided at the top of the standpipe (1) above Hose Station RB-4 on the fifth floor of the Reactor Building, and standpipe (2) above Hose Station RB-1 at the roof of-the Reactor Building. This deviation has been dispositioned by Engineering Design Package (EDP) 3644, but the work has not yet been completed. Consequently, this item will remain open pending the installation of the two gauges discussed abov c. (Closed) Open Item (341/84049-08): Safeteam Concern No. 565-A identified the installation of a defective liquid level gauge on the twelve and one-half ton carbon dioxide supply tank located outside the north wall of the Reactor Building. On June 30, 1986, the licensee's staff provided an internal memo, (Contani to Olson dated February 12, 1985,EF2-104,803) addressing safeteam concerns about a valve on the tank and the isolation valve planned to replace this valve. According to EDP 2359, Revision 0, dated February 28, 1985, the problem valve has been replaced as of August 22, 1985. During this review the NRC inspector verified that a U. L. stamped isolation valve was installed on the lower source line, and has exterior appearance and markings identical to the upper source line isolation valv _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___. . _ _ _ _ _ _ _ _

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. (0 pen) Open Item (341/84049-20): The licensee during a November 2, 1984, meeting with NRR in Bethesda, Maryland, committed to install a fuel warmer on the fuel oil supply filter for the Combustion Turbine Generator (CTG). This CTG provides power to the post fire alternative shutdown system. The purpose of the fuel warmer is to assure that the fuel does not gel during extremely cold weather, causing the CTG to fail to star The licensee in their letter dated October 29, 1985 (VP-85-0202),

committed to install a fuel warmer, the exact configuration of the fuel supply for the CTG starting diesel was not known. Consequently, this configuration has been determined. According to the licensee's letter, the starting diesel and the fuel oil supply components for the CTG's are located in a heated compartment and are not exposed to sub-freezing temperatures. On June 30, 1986, an inspector confirmed that the starting diesel and the fuel oil supply components for the CTG's are located in a heated compartment; however, the heater supplying heat to this compartment is not supervised. A potential exists for a malfunction of this heater thereby allowing the compartment temperature to drop, potentially allowing the fuel oil to gel during extremely cold temperatures. At the exit meeting of July 1,1986, a member of the licensee's staff mentioned that the licensee's engineering group is considering performing calculations to demonstrate that a failure of the heater, over an eight-hour period (since an operations procedure requires surveillance of the compartment), will not allow the temperature to drop to a point where the fuel oil would ge Further, the Licensing Engineer at the exit interview mentioned that upon licensee resolution of this concern, updating of the licensee's October 29, 1985 letter will take place. This item will remain open pending licensee assurance that the fuel oil to the CTG will not ge (Closed) Open Item (341/85025-01): As documented in Inspection Report No. 50-341/84-49, a review of pre-operational test results indicated inconsistent pressures and flows recorded for the ten year old under-ground fire main system hydrostatic test. The licensee acknowledged the inconsistencies in the test and agreed to retest the system at 200 psi By licensee letter dated March 4, 1985, the licensee stated that since installation of the fire protection yard piping about ten years ago, the acceptance criteria for the hydrostatic leak test to be run in May 1985 would be a leakage of 264 gallons over a two-hour period at a system pressure of 200 psi. This acceptance criteria was proposed by the licensee based on guidance in NFPA 24 and the Factory Mutual Handbook, with due consideration for the age of this system. The hydrostatic test was performed en May 31, 1985, with the system pressurized at between 200 to 213 psi for two hour During the test, the system was allowed to stabilize for two hours. The initial leakage was unacceptable. Subsequently, valves within the test boundary were checked for leaks and the packings on three valves were tightened and the cross-tie valve was closed. The leakage measured over the next two hours was 254 gallons. The licensee deemed this leakage satisfactory since it was less than the acceptance criteri _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _

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NRC Supplemental Safety Evaluation Report (SSER) No. 6 indicated that both the acceptance criteria and the measured leakage are acceptabl This satisfies closure of License Condition 2.C(9)(e) with regard to the hydrostatic testing of the fire protection yard pipin Additional concerns were raised by the inspectors indicating that the 200 psig hydrostatic test pressure appeared not to be the proper test pressure. To resolve this concern, the licensee requested an NFPA code interpretation to determine the maximum test pressure for the underground fire main system. On July 1,1986, the licensee provided the response to their request from NFPA. In NFPA's response dated July 17, 1985, the NFPA's Staff Lia1 son's position was that the criteria for existing mains should be determined by the licensee in conjunction with the authority having jurisdiction, taking into account the type of pipe, joints, valves, and the age of the syste Therefore, as determined in SSER No. 6 regarding the hydrostatic test conducted at 200 psig, this additional concern is considered resolve f. (Closed) Open Item (341/85050-01): This item addressed the designation of a backup power supply other than the 120 KV offsite power for fire protection circuits in the event Combustible Turbine Generator No.11 was inoperable for more than 30 day Information is being provided by the licensee to NRR on the electrical characteristics of three operational backup power supplies, including a basis for appropriate changes to the Fermi technical specifications, and applicable action statements. Questions on this issue are being followed up by NRR under TAC No. 6005 g. (Closed) Open Item (341/85050-02): This item addressed NRC concerns on postulated circuit deficiencies in the Division II remote shutdown Panel H21-P101, originally designated to be used for shutdown during a fire. The licensee had committed to have a dedicated 3L panel operational prior to startup, and to disable any functions of Panel H21-P101 that may compromise the dedicated (3L) shutdown syste Remote shutdown Panel H21-P101 provides redundant instrumentation and control for the HPCI syste In order to prevent any postulated failures due to lack of Class IE cable separation in this panel, the licensee determinated Cables 218386-2C and 218387-07C in the relay room, Division II, Cabinet M11-P620, in accordance with EDP-4600 dated January 21, 1986. The inspector reviewed schematic drawings 6I721-2225-2 through 5 and determined that the determination of the above cables prevented initiation of the HPCI from Panel No. H21-P101. The inspector also verified the determination of the above cables in the relay room at Panel M11-P620. Indications for suppression pool water temperature and drywell pressure have not been disabled at Panel H21-P101 as the licensee intends to restore remote HPCI control from this panel (pending corrective action). This panel, however, is no longer used as part of the dedicated (3L) shutdown system and the licensee reported that all appropriate procedures had been revised to exclude the use of this panel as part of the post fire dedicated shutdown syste *

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During the December 2-6, 1985, NRC inspection, (Report No. 50-341/85050), the inspectors reviewed the design of the Fermi 2 post fire dedicated shutdown system, including the instrumentation and control for this system provided on the indepenaent dedicated shutdown (3L) Panel H21-P623. No violations or deviations were identified in the report relative to the design of the new (3L) Panel H21-P623.

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During this review, the inspectors were informed by the licensee that all appropriate testing for this panel had been performed and that it was fully operationa h. (Closed) Open Item (341/85050-03): This item identified an unprotected electrical feed cable, RI0052P, considered part of the dedicated (3L) shutdown system running in the vicinity of other divisional cables. In accordance with Section III.G.2.c of 10 CFR 50, Appendix R, the licensee provided a one hour fire barrier on this cable in Fire Zone 8, together with existing automatic suppression and detection. The inspector reviewed the fire barrier in the field and verified the adequacy of wrapping through quality assui-ance records associated with Work Order No. 98514 . (Closed) Open Item (341/85050-04): This item identified an unprotected 4160V Calvert bus in Fire Zone 2, supplying power to the Standby Feedwater System used in the Appendix R dedicated (3L)

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shutdown syste The licensee initially proposed wrapping all the divisional cables in this zone as the Calvert bus was not easily accessible. Subsequently, in a letter dated January 3, 1986, (VP-85-0221) the licensee chose to meet the provisions of 10 CFR 50, Appendix R, Section III.G.2, for this fire zone by protecting one division of shutdown systems from fire damage. This allowed them not to rely on the Calvert bus during shutdown during a fire in this zon In order to prevent the spread of fire from one division to another, the licensee installed fire stops in horizontal trays that were considered intervening combustibles. The licensee reported that adequate fire stops had been installed to provide a level of fire protection equivalent to the technical requirements of 10 CFR 50, Appendix R, Section II The inspector reviewed Drawing 6E721-2801-15, Revision C, for trays in the cable area at the 603', 6" level of the Auxiliary Buildin Trays 2CO30, 20007 and 2C012 were also examined for wrapping in the field and any conflict with other divisional cables. Adequate separation existed between unwrapped cables together with fire stops, automatic suppression and detection. Wrapping requirements and implementation was verified on QA records associated with the appropriate Work Order No. 64900 J. (Closed) Open Item (341/85050-05): This item addressed deficiencies in the protection of instrumentation cables for reactor pressure and level, torus temperatures and level, and temperature control of the EECW Heat Exchanger inlet valv . .. - _ -

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o Indication functions for the above parameters are independently available in the control room and in the dedicated (3L) shutdown panel. During a postulated fire in Zone 2, the EECW heat exchanger inlet valve may be spuriously closed. To control this the licensee has revised Procedure 20.00018, Revision 1, Section 1.3.1, requiring an operator to manually shut off the air supply to the Division II Heat Exchanger Temperature Control Valve so that the valve fails ope The licensee has also revised Procedure 20.000.18, Revision 1, Section 1.1.3, for a postulated fire in Zones 4 or 6, requiring an operator to monitor the torus level and temperature as well as reactor level and pressure at the dedicated shutdown Panel H21-P623, since control room indications may be affected by the fir The licensee proposed these changes to NRR in their letter, VP-85-0221, dated January 3, 1986, and have used these actions as a basis for determining that protection of these instrumentation cables is not required as provisions of Appendix R,Section III.G.3 are me k. (Closed) Open Item (341/85050-06): The inspectors performed a walkdown of the safe shutdown procedure. As a result, it appeared that due to locations of safe shutdown equipment requiring operator action, time required for those actions to take place, and the complexity of those operator actions at the local panels, the evolutions appear to require three operators: one operator to control reactor vessel pressure and level at the Remote Shutdown Panel and two operators to perform the local operations. The procedure currently requires only two operators, one at the Remote Shutdown Panel and one to perform the local operations. Consequently, the licensee committed to include instructions in the operator's night-order book or the safe shutdown procedure to utilize two operators for the local operation In discussions with the Operations Coordinator, an inspector verified that Standing Order 85-23 dated December 13, 1985, regarding manning of the 3L Safe Shutdown Panel, ensures that the Nuclear Shift Supervisor (NSS) makes three personnel available for Alternative Shutdown operations as soon as the Control Room is no longer capable of controlling the critical plant functions as described in Abnormal Operation Procedure 20.000.1 As an added margin of safety, the licensee has revised Step 1.6.3 of Abnormal Operation Procedure 20.000.18 so as to have all available operation personnel respond to the Safe Shutdown Panel to provide assistance as necessary, 1. (Closed) Open Item (341.85050-07): During the safe shutdown procedure walkdown, the inspectors raised a concern regarding the adequacy of communications between plant personnel (during use of this procedure)

being affected by the distances and time requirements of the evolutions. The inspectors requested an adequate number of portable radios be supplied to assure the completion of the local operation ..

During the plant tour of June 30, 1986, the NRC inspector verified that two portable radios had been provided in the wheeled safe shutdown equipment cart at the Division 1 Shutdown Panel, with provisions for a radio operability test of these two radios. The inspector also learned that these portable radios are in addition to those being normally carried by shift personnel performing safe shutdown activitie Furthermore, according to the Operations Coordinator, Abnormal Operation Procedure 20.000.18 does not require mandatory use of the portable radio . Exit Interview The inspectors met with licensee representatives (denoted in Paragraph 1)

at the conclusion of the inspection on July 1, 1986, and summarized the scope and findings of the inspection. The licensee acknowledged the statements made by the inspectors. The inspectors also discussed the likely informational content of the inspection report with regard to documents reviewed by the inspectors during the inspection. The licensee did not identify any of the documents as proprietary.

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