IR 05000341/1986032

Insp Rept 50-341/86-32 on 860930-861110.Violation Noted: Inability of Corrective Actions to Preclude Addl Reactor Scram/Esf Actuations.One Unresolved & One Open Item Identified

ML20214V872
Person / Time
Site:	Fermi
Issue date:	12/02/1986
From:	Wright G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20214V842	List: IR 05000341/1986032 ML20214V840 ML20214V856
References
RTR-NUREG-0737, RTR-NUREG-737, TASK-2.B.1, TASK-2.D.3, TASK-2.E.4.1, TASK-2.F.1, TASK-TM 50-341-86-32, NUDOCS 8612090884
Download: ML20214V872 (32)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION III

Report No. 50-341/86032(DRP)

Docket No. 50-341 Operating License No. NPF-43 Licensee: Detroit Edison Company 2000 Second Avenue Detroit, MI 48226 Facility Name: Fermi 2 Inspection At: Fermi Site, Newport, MI Inspection Conducted: September 30 through November 10, 1986 Inspectors: W. G. Rogers M. E. Parker J. M. Jacobson J. S. Mueller f Approved By: . i / M f d h [o Reactor Projects Section 2C Date '

Inspection Summary Inspection on Se)tember 30 through November 10, 1986 (Report No.50-341/86032( MP))

Areas Inspected: Routine, unannounced inspection by resident inspectors of inspector identified itms; operational safety; maintenance;. surveillance; LER followup; report review; followup of events; management meetings; plant trip; startup test witnessing and observation; design, design change, and modification; TMI action items; and re-evaluation of cracks - Fermi Results: One violation was identified (Paragraph 8.a. inability of corrective actions to preclude additional reactor SCRAM /ESF actuations). One unresolved item was identified (Paragraph 2.b) and one open item was identified (Paragraph 8.b).

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DETAILS Persons Contacted Detroit Edison Company

• F. Agosti, Manager, Nuclear Operations

• L. Bregni, Compliance Engineer

• L. Collins, Systems Engineering, Nuclear Engineering J. Conen, Licensing Engineer J. DuBay, Superintendent Services R. Eberhardt, Rad-Chem Engineer J. Leman. Superintendent, Maintenance and Modification

• R. Lenart, Plant Manager, Nuclear Production L. Lessor, Consultant to the Plant Manager, Nuclear Production R. May, Management Engineer W. Miller, Supervisor, Operational Assurance S. Noetzel, General Director, Nuclear Engineering T. O'Keefe, Technical Engineer

• G. Ohlemacher, Assistant Maintenance Engineer G. Overbeck, Superintendent, Operations J. Plona, Assistant Operations Engineer

• E. Preston, Operations Engineer W. Ripley, Startup Director L. Simpkins, Director Nuclear Engineering

• F. Sondgeroth, Engineer - Licensing

• B. R. Sylvia, Group Vice President, Nuclear Operations

• W. Tucker, Superintendent Operations

• G. Trahey, Director, Quality Assurance

• R. Wooley, Acting Supervisor, Licensing i- U.S. Nuclear Regulatory Consnission

• M. Farber, Reactor Inspector

• J. Mueller, Engineering Co-Op

• M. Parker, Resident Inspector W. Rogers, Senior Resident Inspector *

• L. Whitney, Reactor Inspector

• Denotes those who attended the exit meeting.

i The inspectors also interviewed others of the licensee's staff during

. this inspection.

t Followup on Inspector Identified Items (92701)

' (0 pen) Open Item (341/85045-01(DRS)): Service Life of Main Steam Bypass Line. On September 24, 1986, the metallurgical inspector from the Division of Reactor Safety, Region III Office, visited the Fermi 2 site to review preliminary operating data and service life analysis of the main steam bypass lin . . . - . .

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Preliminary operating data shows that the threshold stress intensity calculated by Hopper and Associates (Report No. HA-5-86-494) of psi inch is exceeded at a bypass valve opening of approximately 35%

to 45%. The operating data for pipe wall strain was forwarded to Hopper & Associates and Stone & Webster for re-evaluation of the bypass line service life projection The Hopper report (No. HA-10/86-532) prediction of service life is based on a detailed fracture mechanics analysis assuming the maximum permissible weld flaw per code is located at the point of highest stress. A statistical analysis of the operating strain data was used ,

to predict crack initiation and propagation to failure. The report '

concluded that for bypass valve openings of 30% to 40%, the predicted cumulative service life was approximately 130 day The Stone & Webster report (No. NE-SW-86-0018) prediction of service life utilizes the microscopic fatigue theory methodology. The computer model assumes a moment stress based on a theoretical forcing function and a hoop stress resulting from flexural vibration. The resulting alternating stress was compared with the ANSI /ASME fatigue life curve to determine the service life prediction. The report concluded that at the critical bypass valve opening of 35% to 45%,

the predicted cumulative service life ranges from 13 to 26 day Both reports agreed on the general location of highest stress and the critical valve operating range of 30% to 45%. The piping system location of most interest is between the first two elbows downstream of the west bypass valv In an effort to validate or invalidate the basis of the Stone &

Webster analysis, the licensee will install strain gauges on the first elbow downstream of the west bypass valve. Thus, the actual alternating stress contribution from bending can be used for the evaluation as opposed to the theoretical valve. During the operation of the bypass system a cumulative running time of the valves in the 30% to 45% range will be kep This item will remain open pending NRC review of additional operating data and any revised service life prediction b. (Closed) Open Item (341/86026-09(DRP)): Calibration of safety related temperature sensing devices. The inspector pursued the methodology utilized by the licensee to meet definition 1.4 of Technical Specifications for channel calibratio Following a conference call with the site inspectors, NRC Region III management and licensee management, the licensee documented the ways in which temperature sensors are calibrated in letter GP-86-0003 dated October 2, 198 In the letter three methods were identified to calibrate temperature sensors. These methods were:

Comparison checks of redundant sensors Operator qualitative assessment Pre and post connection comparisons

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Whether.these methods'are in compliance with the. definition of channel calibration has been escalated to an unresolved item (341/86032-01(DRP)). Therefore, open item 341/86026-09 has been superseded. The matter has been submitted to NRC Region III for resolutio : Operational Safety Verification (71707)

The inspectors observed control room operations,' reviewed applicable logs and conducted discussions with control room operators during the period from September 30, 1986 to November.10, 1986. 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 excessive vibrations and to verify that maintenance requests had been-initiated for equipment in need of maintenanc The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the '

station security pla The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls. During the-inspection, the inspectors walked down the accessible portions of the Thermal Hydrogen Recombiner and Core Spray systems to verify operability by comparing system lineup with~ plant drawings, as-built configuration or present valve lineup lists; observing equipment conditions that.could degrade performance; and verified that instrumentation was properly valved, functioning, and calibrate :

The inspectors also witnessed portions of the radioactive waste system controls associated with radwaste shipments and barrelin These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under technical specifications, 10 CFR, and administrative procedure [

During this inspection period the inspector observed numerous pieces of equipment out of service as indicated by a high number of control room indication system (CRIS) dots. The situation was brought to the attention of licensee management. Management took timely and comprehensive action to repair / troubleshoot the out of service equipment. As such the CRIS dots are being reduced. Additionally, management is applying resources to continue CRIS dot reductio No violations or deviations were identified in this are " Monthly Maintenance Observation (62703)

i I Station maintenance activities of safety-related systems and components j listed below were ebserved to ascertain that they were conducted in

accordance with approved procedures, regulatory guides and industry

[ codes or standards and in conformance with technical specifications.

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y The following items were considered during this review: the liniting'

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 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 performanc The following maintenance activities were observed: -

Balancing of electrical loads on MPU- B21-F028B Main Steam Isolation Valve (MSIV) Limit Switch Repai '

Following completion of maintenance on the MPU-3 and MSIV limit switch, the inspectors verified that these systems had been returned to service properl No violations or deviations were identified in this are . Monthly Surveillance Observation (61726)

The inspectors observed 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 The inspectors witnessed the following test activities:

l 24.608 Rod Worth Minimizer Functional Test 24.609 Rod Sequence Control System Functional Test l 44.010.126 RPS-APRM C Channel Functional Test No violations or deviations were identified in this area.

l 6. Licensee Event Reports Followup (92700)

i Through direct observations, discussions with licensee personnel, and l review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, immediate corrective

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action was accomplished, and corrective action to prevent recurrence had l been accomplished in accordance with technical specification s l 5

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(Closed) LER 85042 --Division II Emergency Equipment Cooling Water

Automatic Initiation.

b5 (Closed) LER 85048 - Division I Emergency Equipment Cooling Water

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During the review of.LERs 85042 and 85048, the inspector.noted that the root cause was identified as unknown. However, LER 86006, which was ,

closed out in Inspection Report No. 50-341/86019, subseq:tcatly identified c T, the root cause to be a malfunctioning sticky reset switch at the F emergency diesel generator digital load sequencer. As such, the

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correstive action taken to preclude a recurrence in LER 86006 satisfies

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. LERs 85042.and85048. The inspectors have requested the licensee t ensure: adequate documentation exists for these LERs and associated y ~

Deviation' Event Reports (DERs) to support.the root cause as during the

, Ereview the insp'ector was unable to reach the same conclusion without iM - requesting additional documentatio No violations or deviations were identified in this area.

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$. Report Review (90713)

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During the inspection period, the inspector reviewed the licensee's Monthly'pperating Report for September 1986. The inspector confirmed

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,- Specification No. 6.6.A.3 and Regulatory Guide 1.16.

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'No violations or deviations were identified in this area.

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4 8i Followup of Events (93702)

luring thc' inspection period, the licensee experienced several events,

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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 officials. In each case, the inspectors verified that

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the notification was correct and timely, if appropriate, that the

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licensee was taHng prompt and appropriate actions, that activities

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wers conducted within regulatory requirements and that corrective

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'b- October 5, 1986 - Manual reactor SCRAM due to high condenser temperature caused by loss of condenser vacuum.

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Octoberi5, 1986 - Emergency Core Cooling System, Reactor Protection

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System, and Engineered Safety Feature actuations

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s resulting from I&C activities. (See Section a of

, this paragraph for further followup on this event)

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. October 6, 1986 - Reactor SCRAM on low water level resulting from an

! I&E technician causing a spurious low water level

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signa (See Section a of this paragraph for further w l'followuponthisevent)

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o October 7, 1986 - Reactor Water Cleanup System isolation causing

- outboard isolation valve to close on a false differential temperature while obtainins routine

'eading r October 9. 1986 - Engineered Safety Features actuation due to loss of BOP 120 VAC instrument power suppl (See Section b

' of this paragraph for further followup on this event)

October 10, 1986 - EngineeredSafetyFeaturedactuationcausedbyI&C technician shortingithe fuel pool ventilation radiation monito ,.,

October 18, 1986 - Reactor SCRAM on low water level due to failure of the reactor pressure regulato Following the manual reactor SCRAM on October 5. 1986, the licensee recognized that the plant response to the manual SCRAM tripped two of the four reactor water level reactor protection system channel The licensee assumed that only two channels tripped due to the instrument tolerances associated with the reactor water level sensing system. To verify this assumption the licensee started calibration checks of the reactor water level sensing system to determine the actual setpoints at which each channel trips. On October 5, 1986, I&C technicians started the calibration check of transmitter No. B21-N080C which provides a reactor low water level SCRAM signal to Division 1 of the reactor protection system utilizing surveillance Procedure No. 44.010.19. The calibration

- rig was not connected to the transmitter to maintain double isolation between the test rig and the reference leg as shown in the procedure and the reference leg isolation valve,.the only isolation between the reference leg and the test rig, was not fully closed as required in the procedure. When the test rig was connected to the transmitter a very short duration. pressure-perturbation of the reference leg ensued which was sensed by the affected transmitters as a low reactor water level. Perturbation ,

of the reference leg at this facility also affects numerous other level transmitters associated with the ECCS/ESF actuation system since a common reference leg is uu d. Therefore, a great deal of the ESF/ECCS equipment actuated on - he sensed low reactor leve Equipment actuated included M. c p* ssure core injection, reactor '

core isolation cooling, als i w g . y diesel generators, Division II of standby gas treatment system, Division I of core spray and-the reactor SCRAM solenoid valves. Approximately 80 seconds later #

a much larger and longer perturbation of the reference leg occurred

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when the test rig began pressurizing the transmitter. This perttrbation caused the additional actuation of the low pressure

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core injection system and Division II of the core spray system.

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Operators examined true level indication-and determined that the reactor vessel level was normal. The ECCS/ESF equipment was

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subsequently secured and reset. Following discussions between the operations and I&C personnel it was concluded that the reference

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leg isolation valve on transmitter No. B21-N080C was potentially leaking. The drain valve for the reference leg side of B21-N080C was left open to observe for leakage. No leakage was noted and the valve was closed. On October 6, 1986, another calibration check of transmitter No. B21-N080C was attempted. Upon completing the calibration check and valving the transmitter back in service another perturbation of the reference leg occurred. The cause of I the perturbation was from an air bubble trapped between the drain i valve and the reference leg isolation valve passing through the l reference leg when the reference leg isolation valve was opene This pressure perturbation was not as severe as the ones of the day before and only causcd a reactor SCRAM signa Subsequent discussion with the licensee revealed that the turnover regarding the status of transmitter No. B21-N080C had not been adequate to alert personnel that the reference leg drain line needed to be filled prior to the transmitter's return to servic On April 8, May 1, May 6, and September 28, 1985, similar occurrences of incorrect valving techniques by I&C technicians happened causing a reactor SCRAM (see LERs 85005,85014,85015,85067). The licensee's response to these occurrences was to revise the l

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procedures to enhance operator proficiency in valving equipment in and out-of-service, provide a mockup to valve equipment in and out of service for I&C personnel to train upon, and train the I&C personnel on the new procedures and mockup. These corrective actions were provided in the applicable conditions adverse to quality reports and the applicable LERs. All of these corrective actions had taken plac The inability of the aforementioned corrective actions to preclude additional reactor SCRAMS /ESF actuations through similar occurrences is considered a violation of 10 CFR 50 Appendix B Criterion XVI, Corrective Action (341/86032-02(DRP)).

The licensee has established the following corrective actions to the violation:

Specific valving instruction for individual instruments shall be incorporated into the appropriate surveillance procedur A human factors study is underway on the specific instrument rack, P005 and its companion racks P004, P009, P010. The study will be completed by November 30, 198 Formal qualification and requalification shall be done on the reactor valve instrument rack mockup by December 30, 198 A letter describing the different valve / tubing configurations associated with the reactor level / pressure transmitters shall be issued to all I&C technician Informal discussions shall be held with all I&C technicians on the situatio _ _ _ _ _ _ _ _ _ _ _ _

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Considering the licensee's corrective actions, no further written response need be provided regarding this violation. Finally, when all reactor level sensing channels were calibration checked, the licensee's assumption on why only two channels tripped was validate b. The Fermi 2 facility utilizes 3 methods to energize 120 VAC load These methods are the reactor protection power supply system, uninterruptible power system, and the modular power unit (MPU)

system. The third method is comprised of six MPUs. The six MPUs are classified safety-related for MPU-1 and MPU-2 and balance of plant for MPU-3 through MPU- At 0941 on October 9, 1986, MVP-3 automatically transferred to its alternate power supply due to low voltage on the normal power supply during excitation of the turbine generator at 10.8% reactor powe Prior to the transfer, operators had noted voltage fluctuations on MPU-3. Due to the break before make power supply transfer feature, numerous equipment and indication abnormalities were observed during the transfer. The major items were:

Scoop tube lockout of reactor recirculation pump *

A significant number of process and area radiation monitors were alarmin *

Turbine tri Partial loss of instrument ai Automatic start of diesel and electric fire pump Loss of control of the feedwater startup valv Standby Gas Treatment automatic start and CCHVAC switched to the recirculation mode due to the radiation monitor problem With the loss of control of the startup feedwater valve, the operators placed the standby feedwater system in service and controlled reactor pressure vessel level with only minor changes in level and no perturbations in pressure. Therefore, the MPU transfer had minimal affects on major plant parameters due to operator action and the initial power leve The inspector reviewed the procedure guidance available to the operator to cope with the situation and found the procedures weak on what is fed from MPU-3, operator response to the situation and equipment actuated by the transfer. Additionally, the inspector reviewed the abnormal procedure for total loss of MPUs and noted it to be weak.

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On October 15, 1986, the inspection personnel and utility personnel met to discuss the MPU-3 transfer and potential corrective action . - . -

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Based on the licensee's investigation, the component failure which caused MPU-3 to transfer to the alternate power supply was a feeder fuse to the No. 2 distribution panel. The control power for generator excitation is from MPU-3 distribution panel No. 2. When the control power for the exciter was energized, 47 amps of current was drawn. The installed fuse was rated at 40 amps and subsequently blew causing a transfer to the alternate power supply. The root cause of the component failure was an improper assumption in the design calculations for the MPU voltage regulator efficiency. The voltage regulator was a "solatron" transformer which uses a capacitor in its design to maintain a constant voltage. However, while constant voltage is maintained with this type of transformer, the phase angle changes with an increase in inductive loading, such as exciting the generator, resulting in a significant increase in current to compensate for the phase angle chang On October 31, 1986, the licensee briefed the inspectors on corrective actions to MPU-3. The completed corrective actions were:

Originally a transfer of 10 amps load from the failed feeder fuse circuit, and finally a transfer of 34 amps load to a temporary fee Increasing the feeder fuse size from 40 to 45 amps, coupled with a 34 amp load reduction, will allow for an increasing inductive load such as generator excitatio Constant monitoring of the current and voltage on MPU-3 until assurance is gained that the circuitry is performing as expecte Calculations of other MPUs reviewed and loads preliminarily determined to be less than the maximum permissible limi Where other "solatron" transformers were utilized, the electrical load situation was analyzed with no hardware changes require Transfer the sequence of events recorder to a balance of plant batter Transfer of the offgas AC equipment to another distribution pane Planned corrective actions include:

Development of load lists and failure modes for equipment powered by MPU- Completion of calculation revisions utilizing the appropriate voltage regulator efficienc Evaluate potential impact of MPU-3 transients on plant operation to determine long-term load shifts on MPO- . -

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Determine whether load lists / failure modes should be developed for the entire plan The inspector shall follow the licensee's initiatives to reduce the impact of electrical power source failures on the facility and enhance the operator response to such failures as an open item (341/86032-03(DRP)). The resident inspectors also followed up on several security events during this inspection perio . Management Meetings On October 7, 1986, at the Nuclear Operations Center, a management meeting with the public invited was held between the licensee and NRC Region III. The purpose of the meeting was for the licensee to update the NRC on the progress of licensee improvement program The personnel who participated in the meeting are identified in Paragraph The meeting began with opening remarks from Mr. Greenman. Mr. Sylvia then presented a chronology of events from the issuance of the 50.54(f) letter. Mr. Agosti presented details of the Nuclear Operations Improvement Program, Reactor Operations Improvement Plan goal indicators and Power Ascension Program. Mr. Sylvia summarized for the licensee followed by Mr. Greenman summarizing for the NRC. Questions from the public were then take On October 8, 1986, NRC Region III Regional Administrator, Mr. James Keppler toured the facility and met with utility personne The tour was in the morning and consisted of the control room and portions of the reactor building and turbine building. Following the tour, the regional administrator met with the licensee and discussed the licensee's violation response to Inspection Report No. 50-341/85040, On October 28, 1986, NRC Commissioner James Asselstine toured the facility and met with utility personnel. During the morning the

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Commissioner toured the control room, turbine building, reactor building, and radwaste control room. During the afternoon the Commissioner met with senior licensee management. Areas of discussion were the status of the licensee's improvement programs, assessment of the licensee organizational and personnel changes,

maintenance initiatives, and the Commissioner's impressions of the tour.

10. Plant Trips (93702)

Following the plant trips on October 5 and October 18, 1986, the inspectors ascertained the status of the reactor and safety systems by observation of control room indicators and discussions with licensee personnel concerning plant parameters, emergency system status and reactor coolant chemistry. The inspectors verified the establishment of proper communications and reviewed the corrective actions taken by the licensee.

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All systems responded as expected, and the plant was returned to operation on October 7 and October 19, 1986, respectivel No violations or deviations were identifie . Startup Test Witnessing and Observation (72302)

The inspectors reviewed portions of startup test procedures, reviewed procedure results completed to date, toured the areas containing system equipment, interviewed personnel, and observed test activities of those startup tests identified belo During this review, the inspectors noted that the latest revision of the test procedure was available and in use by crew members, the minimum crew requirements were met, the test prerequisites were met, appropriate plant systems were in service, the special test equipment required by the procedure was calibrated and in service, the test was performed as required by approved procedures, temporary modifications such as jumpers were installed and tracked per established administrative controls, and test results for the tests observed by the inspectors indicated that acceptance criteria were me Shutdown from Outside the Control Room The inspectors observed the performance of STUT.01A.028 Revision 7,

" Shutdown From Outside Control Room - Hot Shutdown Demonstration."

On October 23, 1986, the licensee commenced demonstration of a shutdown of the reactor from outside the control room. The reactor was operating at 18% power with the turbine on line prior to the shutdown. The licensee was able to demonstrate operability of equipment on the remote shutdown panel located in the Division I switchgear roo Equipment located on the panel is RCIC, RHR, and two SRVs. Suppression pool cooling was placed in service and both SRVs were actuated. RCIC was initiated to demonstrate operability but was not needed to control level due to the lack of decay heat and was, therefore, secured within a few minutes. Control of the plant was returned to the control room approximately 45 minutes after initiation of the shutdown. The reactor was then taken to cold shutdown for a short outag During performance of the test the operators experienced difficulty with transferring Division II A.C. power to the shutdown panel due to sticking key / locks. The inspectors have since followed up and verified that this has been resolved by replacement of core loc The inspectors noted during the performance of the test that due to the lack of isolation decayheat valves and the immediate closure of the main steam (MSIVs), the licensee was unable to demonstrate control of reactor vessel level using RCIC as the level was stabilized immediately after securing the MSIVs and tripping feed pumps. In fact the operators knew in advance of the test that it would be necessary

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to secure the reactor feed pumps, heater feed pumps and to throttle the CRD flow to minimum in order to maintain reactor vessel level low enough to perform RCIC testing without tripping the RCIC turbine on high level. Of concern to the inspector is whether the intent of the test is to control reactor vessel level using the RCIC system or to demonstrate operability of RCIC at the shutdown panel. The inspectors have discussed this concern with NRR and Regional Management and have come to the conclusion that it was not incumbent upon the licensee to demonstrate control of RV level throttling flow with the RCIC control valv Reactor Core Isolation Cooling (RCIC) 150 PSIG Injection Into the Reactor Vesse The inspectors observed the performance of STUT.HUD.014, Revision 4,

"RCIC System - 150 PSIG Vessel Injection."

This test was performed to verify proper operation of RCIC system while the reactor is operating at 150 psig. This test consisted of both a manual and automatic initiation and injection of water into the reactor vessel. The RCIC system was lined up from the condensate storage tank to the reactor vesse The inspectors noted that in both tests startup test personnel presented very informative pretest briefings to all personnel involved with the tests. To ensure all areas of concern had been addressed, the licensee performed a dry run of the shutdown from outside the control room and assigned a dedicated shift to perform the shutdown while the assigned shift observed normal control room activities. Both tests were considered to be well planned and good coordination was observed between startup test personnel and operations shift.

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No violations or deviations were identified in this area.

l 13. Design,DesignChanges,andModifications(37700)

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The inspectors reviewed a design change and modification that was

! determined by the licensee to not require approval by the NRC to verify that it was in conformance with regulatory requirements. The following items were considered during the review: the change had been reviewed and approved in accordance with 10 CFR 50.59 and was technically adequate; it was reviewed and approved in accordance with technical specifications and established QA/QC controls; it was controlled by established procedures; activities were conducted in accordance with appropriate specifications, drawings, and other requirements; testing of the modification was conducted in accordance with technically adequate and approved procedures; and appropriate controls were implemented during installation of the modificatio The following design change and modification was reviewed:

Substitution of a Non-ASME Stem in Valve No. E1150-F060B, LPCI Loop B Injection Line Manual Isolation Valv . - _ _ _ _ - _ _ _ _ _ _ _

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During a closecut review of work performed on E1150-F608, the licensee-discovered that the stem installed on F60B valve was commercial quality material. This stem is a pressure retaining component and it, therefore, required ASME Class 1 certification. The inspector has reviewed the i licensee's Temporary Modification Request, Deviation / Event Report, Safety Evaluations, and procurement documents concerning use of the valve ste The licensee originally tried reconciliation of the parts used to owners design requirements but was unsuccessful as the stem failed the Charpy V-Notch test performed in accordance with ASME code requirements. The licensee subsequently performed a 10 CFR 50.59, Safety Evaluation Review to justify use of the non-ASME stem until replacement during the first refueling outag This valve is located inside the primary containment and provides isolation of the Division II RHR injection line from the reactor recirculation syste The valve itself is normally open and non-isolable from the reactor vesse The valve is a 24-inch manually operated gate valve used for maintenance purposes only. It is not used nor is it accessible during normal power operatio In the Safety Evaluation the licensee has concluded that use of the

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valve stem until the first refueling outage is acceptable, and this is substantiated by the valve vendor, Powell Valves, who came to the same conclusion. In addition, Powell Valves has applied additional constraints:

(1) the valve will not be operated or otherwise impact loaded, and (2) the stem temperature will remain above 40'F. This has been determined acceptable as the valve is normally locked in the fully open position and back seated. The valve is located inside the drywell which is above 40 F and is not accessible during operation. There are no requirements to operate the valve during operation, and there are no impact or shock loadings on the valve stem when the valve is in the full open positio The stem does not have a pressure component acting on it that could lead to early stem failure. The licensee has come to the conclusion that there is, therefore, no challenge to stem integrity during operation and probability of a stem failure remains unchanged during plant operatio The evaluation has also determined that failure of the valve stem is enveloped by the present accident analysis as described in the FSA No violations or deviations were identified in this are . TMI Action Items (25401B)

This section summarized the inspectors' field verification of compliance with certain TMI Action Item Requirements in accordance with Temporary Instruction (TI) 2514/01, Revision 2, and NUREG-0737, " Clarification of TMI Action Plan Requirements." Refer to NUREG-0798, " Safety Evaluation Report," for further information on these action item (Closed) TMI Action Item II.B.1. TMI Action Item II.B.1 required installation of reactor coolant system and reactor vessel head high-point venting which is operable from the control room. Also, procedures for operator use of the vents including the information

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available to the operator for initiating or terminating vent usage were to be submitte A normally closed head vent line provides for low-pressure operation when the steam lines or relief valves are not available for ventin Other vent paths such as reactor core isolation cooling (RCIC), high pressure core injection (HPCI), safety / relief valves (SRV), and residual heat removal (RHR) heat exchanger vents provide additional seismically and Class 1E qualified venting capability. Emergency procedures used to assure core cooling under accident conditions with the RCIC or HPCI systems would result in venting of the reactor coolant system; therefore, no specific procedures for venting using these systems were provide The NRC Office of Nuclear Reactor Regulation (NRR) has concluded that this design met the vent requirements of this action ite The inspector has reviewed licensee's system drawings, procedures, and control room instrumentation and confirmed proper implementation of the NRR-approved design. This item is considered close b. (Closed) TMI Action Item II.D.3. TMI Action Item II.D.3 required power-operated reactor coolant system relief and safety valves be provided a positive position indication in the control room derived from a reliable valve position detection device or a reliable indication of flow in the discharge pip Fermi 2 has a valve position indication system that uses one pressure switch on each of the fifteen safety and relief valves. The in-containment, tail pipe-mounted, pressure switch system provides positive indication of the valve position by pressure switch control of backlighted valve push buttons. A visual annunciator is provided in the control room to notify the operator when any of the safety /

relief valves are not fully cle;ed. Should a failure of the primary pressure switch system occur, a backup method of valve position indication is provided by temperature elements mounted in the existing tailpipe which detect the elevated temperature associated with an open valv The NRC Office of Nuclear Reactor Regulation (NRR) has reviewed this design and concluded that it satisfied the requirements of this action item. The inspectors observed safety / relief valve operability testing during the inspection period detailed in Inspection Report No. 50-341/86026 and identified no concerns. This item is considered closed, c. (Closed) TMI Action Item II.E. TMI Action Item II.E.4.1 required redundant dedicated containment penetrations designed to meet requirements of General Design Criteria (GDC) 54 and 56 of Appendix A to 10 CFR 50 and sized to satisfy the flow requirements of the syste It also required procedures for the use of the combustible gas control system (CGCS) following an accident resulting in a degraded core and release of radioactivity to the containment be reviewed and, if necessary, revise __ _ - - _ - - - - - - - J

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available to the operator for initiating or terminating vent usage ,

were to be submitte '

A normally closed head vent line provides :for low-pressure operation

when the steam lines or relief valves are not available for ventin Other vent paths such as reactor core isolation cooling (RCIC), high pressure core injection (HPCI), safety / relief valves (SRV). and residual-heat removal-(RHR) heat exchanger vents provide additional seismically and Class IE qualified venting. capabilit Emergency

. procedures used to assure core cooling under accident conditions t

with the RCIC or HPCI systems would result in venting of the reactor coolant system; therefore, no specific procedures for venting using these systems were provide The NRC Office of Nuclear Reactor Regulation'(NRR) has concluded that this design met the vent requirements of this action item.

L The inspector has reviewed licensee's system drawings, procedures,

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and control room instrumentation and confirmed proper implementation of the NRR-approved design. This item is considered closed.

i (Closed) TMI Action Item II.D.3. TMI Action Item II.D.3 required power-operated reactor coolant system relief and safety valves be

provided a positive position indication in the control room derived from a reliable valve position detection device or a reliable j indication of flow in the discharge pipe.

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Fermi 2 has a valve position indication system that uses one pressure switch on each of the fifteen safety and relief valves. The

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in-containment, tail pipe-mounted, pressure switch system provides positive indication of the valve position by pressure switch control

of backlighted valve push buttons. A visual annunciator is provided in the control room to notify the operator when any of the safety /

relief valves are not fully closed. Should a failure of the primary pressure switch system occur, a backup method of valve position indication is provided by temperature elements mounted in the existing tailpipe which detect the elevated temperature associated

. with an open valv ,

The NRC Office of Nuclear Reactor Regulation (NRR) has reviewed this i design and concluded that it satisfied the requirements of this action item. The inspectors observed safety / relief valve operability testing during the inspection period detailed in Inspection Report j No. 50-341/86026 and' identified no concerns. This item is considered j closed.

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c. (Closed)TMIActionItemII.E.4.1. TMI Action Item II.E.4.1 required

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redundant dedicated containment penetrations designed to meet requirements of General Design Criteria (GDC) 54 and 56 of Appendix A to 10 CFR'50 and sized to satisfy the flow requirements of the syst:m.

, It also required procedures for the use of the combustible gas control

! system (CGCS) following an accident resulting in a degraded core and'

{ release of radioactivity to the containment be reviewed and, if j necessary, revised.

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Redundant external recombiners which meet the single-failure requirements of GDC 54 and 56 are in place. Final Safety Analysis Report (FSAR) Section H.II.E.4.1.3 and Safety Evaluation Report (SER)

Section II.E.4.1 inaccurately state that the CGCS system is operated from the control room; the system is placed in the ready mode from the control room, however, the system is actually operated from the relay room. The inspector has requested the licensee to clarify this in the FSAR. In any case, no access is required to the skid for normal recombiner operatio The NRC Office of Nuclear Reactor Regulation (NRR) has confirmed

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that this design satisfied the requirements of this action ite The inspector walked down the CGCS and confirmed the existence of

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dedicated system penetrations which meet the GDC requirement The inspector also reviewed the operating procedures for the CGCS and raised no concerns regarding their adequacy. This item is considered closed, (Closed) TMI Action Item II.F.1.2.D. TMI Action Item II.F.1. required a continuous containment pressure indication in the control room with measurement capability to indicate three times the design a

pressure of the containment for concrete, four times the design pressure for steel, and -5 psig for all containment The drywell pressure monitoring system measures pressure in the narrow range from -5 to +5 psig and in the wide range from 0 to 250 psig. These measurements are made by two independent instruments and are each recorded on a multi-channel recorder.

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The design, accuracy, and response time of the containment pressure monitoring system have been reviewed by the NRC Office of Nuclear Reactor Regulation (NRR) and found to meet the requirements of this action item. The inspectors have confirmed its installation and verified operability of this system by direct observation after review of drawings and procedures. This item is considered close (Closed) TMI Action Item II.F.1.2.E. TMI Action Item II.F.1. required a wide range instrument in the control room for continuous indication of containment water level covering the range from the bottom to five feet above the normal water level of the suppression poo The suppression pool water level monitoring system continuously monitors and records on a chart recorder in the control room the

. water level in the pressure suppression chamber. Its range is from 56 inches above normal water level to 144 inches below norma This span indicates water level from the vacuum breaker elevation to a level below the suction inlets of the ECCS pumps. The estimated system accuracy is better than the required 8.8 inche The NRC Office of Nuclear Reactor Regulation (NRR) has determined that this design satisfied the requirements of this action ite The inspectors have confirmed by direct observation that the design has been accurately installed. This item is considered close . . _ ,_ _ _ _ . . _ _ _ ~ . _ _ . _ _ _ _ _ . _ . _ _ _ _. . _ _ _ . _ . _ _ _

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. . (Closed) TMI Action Item II.F.1.'2.F. TMI Action Item II.F.1. required a continuous indication of hydrogen concentration in the containment atmosphere be provided in the control room over the range of 0% to 10% under both positive and negative ambient pressur The hydrogen / oxygen monitoring system consists of redundant high-speed sample loops with controls for sampling from six zones inside conta:nment. Hydrogen concentration indication in the control room has a range of 0% - 30% gas concentration by volume. Abnormal conditions are alarmed in the control room. The manufacturer has qualified the system to operate in the post-LOCA environment. The instrument indicates within 2% of full scale accuracy for pressures from -2 psig to +56 psi The NRC Office of Nuclear Reactor Regulation (NRR) has reviewed the design of this system and determined that it complied with the requirements of this action item. The inspectors have reviewed the licensee's description and drawings of the system and have observed the relevant instrumentetion in the control room. No concerns have been identified. This item is considered close No violations or deviations were identified in this are . Re-evaluation of Cracks in Fermi 2 In response to a concern brought to the attention of the NRC regarding cracks in the base mat slab of the Reactor Building at Fermi 2, the licensee, and the architect / engineer reexamined the crack issue to assure that the concrete met its design intent. The licensee's review reconfirmed previous determinations that the base mat concrete meets the design criteria, including all pertinent seismic requirement The NRC monitored this reevaluation by the licensee and, in addition, contracted with a concrete expert to independently review this concer The consultant's review concluded that the base mat will carry the static and seismic loads, infiltration of ground water is very small and easily manageable, corrosion of reinforcing steel is essentially impossible and exfiltration of water to the ground is impossible either in a pipe-break accident or a flood. A copy of the consultant's letter providing preliminary documentation of his efforts and results was forwarded to the individual who expressed the concern on September 19, 1986. A copy of the consultant's final report dated October 28, 1986, was forwarded to Region III and is attached to this inspection repor Based on previous inspection findings, on the licensee's reevaluation, and the NRC consultant's findings, the NRC has concluded that the cracks in the Fermi Unit 2 base mat do not impair the base mat from carrying the design static and seismic loads. Further, it has been determined that an earthquake similar to that of the Perry earthquake is well within the design considerations for a Fermi site-specific earthquak . _ . _ _ _ ____

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15. Unresolved Items

' Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations or deviations. An unresolved item disclosed during the inspection is discussed in Paragraph . 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. An open item disclosed during the inspection is discussed in Paragraph . Exit Interview (30703)

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

on November 4,1986, and informally throughout the inspection period and summarized the scope and findings of the inspection activities. The 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 proprietary. The licensee acknowledged the findings of the inspectio .. - . . - - - . - - .. . . - . . . - - - - - . . .

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EVALUATION OF CRACKS IN THE FOUNDATION BASE NAT AT THE FERMI 2 NUCLEAR POWER FLANI

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Robert E. Philleo Consulting Engineer

i The base mat for the Fermi 2 plant was placed during June and July of 1971. Beginning in April 1972 and continuing for several years, a series t

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of random cracks were noted on the top surface of the mat. They were the subject of extensive investigation and repair. It was concluded that the cracks did not present safety or operational hazards. Subsequent to the design and construction of the base mat a change in Nuclear Regulatory l

Commission seismic criteria for the geographic area in which the plant is

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located resulted in a situation in which the design of any new structures at the Fermi site would be required to consider a more severe site-specific earthquake than was considered in the original Fermi 2 design. The

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i safety issue was reopened in correspondence between a private citizen

and the Nuclear Regulatory Coassission during the sunser of 1986. I -

i was requested by the Nuclear Regulatory Commission to review the history of the base mat and to evaluate its safety. I was requested to include in the evaluation the ability of the mat to withstand both the new site-specific earthquake and the Perry earthquake, an actual earthquake which occurred in northeastern Ohio in January 198 SCOPE OF INVESTIGATION l

I spent the periods September 3-5 and September 9-12 at the sit On September 3 I met with representatives of Detroit Edison, Sargent and l l

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Lundy, Hopper and Associates, Nuclear Regulatory Commission Resident '

i Inspector's office, and the Nuclear Regulatory Commission Region III headquarters. Attendees at.the meeting are listed in Appendix A. At that meeting Detroit Ed2. son briefed me on the history of the base mat.

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I They provided me with a chronology of events (Appendix B) and a list of pertinent documents (Appendix C). During my investigation I requested l

! l and received other docunents which were necessary for a complete understanding of the behavior and analysis of the mat. These documents l

! are listed in Appendix 1). I examined construction photographs and ground ,

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' water levels in order to estimate the loads on the mat at relevant time l

' I reviewed pertinent design calculations and checked many in detai During this check I had several telephone conversations with l representatives of Sargent and Lundy, the designer of record for the l plant, in order to clarify my understanding of certain parts of the calculations. On September 4 and 10 I inspected the mat itself. I j

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l examined all the cracks, compared their location with those shown in the 1 l

record, noted the presence or absence of seepage, and checked the edges of each crack with a st.raightedge to determine if there had been any

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j relative displacement of the concrete on either side of the crack. On l

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FINDINGS i 1. The cracks are accurately described in the recor . There are seven cracks in the mat seeping some water, but there is no measurable flo . The top mat surface is generally dry with some water present from leaking mechanical systems and wall cracks which have not been repaire . Where it was possible to check displacement with a straightedge, none existed. In some cases material used to repair the crack produced a mound over the crack so that the straightedge could not be placed on both sides of the crack simultaneousl . The original crack widths in 1972 were reported to be of the order of 0.03 inches. Cracks now visible are either sealed or very fin . At the time of the first report of cracks (April 1972) about one-third of the total structural dead weight of the reactor building was being supported by the base ma . A report of groundwater levels immediately adjacent to the reactor building could not be located, but available information from other sounding wells on the site is not inconsistent with the information, contained in a letter dated June 12, 1972, from W. H. Jens of Detroit Edison to Boyce Grier of the Atomic Energy Commission, that at the time cracking was first observed there was a head of fifteen feet on the base ma . The mat was reanalyzed under the assumption that cracks go entirely through the mat, that they may occur at any location, and that shear is transmitted only by the shear-friction phenomenon allowed for in

" Building Code Requirements for Reinforced Concrete (ACI 318-83)" of the American Concrete Institute. The loading included the revised site-specific earthquake. The mat proved to be saf . None of the cracks are in the critical shear or flexure zone . No detailed analysis of the Perry earthquake has been made, but a comparison of the response spectra indicates that for the frequencies of interest, the displacements, velocities, and accelerations of the Perry earthquake are between 0.3 and 0.6 of those for the Fermi site-specific earthquak . All of the concrete in the base mat is somewhat stronger than require . The reactor building is floodproofed to a level more than one foot above the water level predicted by the maximum metereological even , - _-_-_-________- -

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13. The most severe pipe-break accident postulated in the Final Safety Analysis Report would flood the torus room to a depth of 8.6 fee IMPLICATIONS OF FINDINGS In order to evaluate the significance of the cracks, the following questions must be answered:

1. Do the cracks impair the structural performance of the base mats a. under static loads?

b. under the original design seismic loads?

c. under the subsequently revised seismic loads?

d. under the Perry earthquake?

2. Does infiltration of ground water:

a. pose safety or operational problems?

b. permit corrosion of the reinforcing steel?

3. Is exfiltration of contaminated water from the plant into the ground water possible?

It is evident that the cracks were not caused by structural load The static loads for which the mat is designed include the dead weight of the mat, the uplif t force cf the ground water (which is four times as great as the dead weiSh t), and the wei6ht of the walls and components of the reactor building. The mat was placed during June and July 197 Reference to the cracks first appeared in the record on April 12, 197 At that time only about one-third of either the uplift load or the building load had been applied to the structure. The cracks had to b1 the result of restrained volume changes in the concret Cracks in reinforced concrete may occur in compression zones, tension zones, or zones of high shear stress. Cracks in compression zones are of no concern because they'close under load. Concrete must crack in tensile zones in order for the steel to achieve any significant portion of its tensile strength. Normally the cracks form as a result of load and are numerous and very narrow. But if pre-existing cracks exist, they serve the same purpose. Thus, pre-existing cracks in the tensile zone do not hinder the functioning of reinforced concrete. Their width may raise a question about steel corrosion. Cracks in zones of high shear stress are a potential source of concern. If such cracks, or the reinforcing steel passin6 through them, are unable to transmit the shear stress, there will be a relative displacement of the concrete on the two aides of the crack. The fact that no displacement could be detected indicates there are no incipient shear failures in the ma Thus, without making any calculations, it may be determined that the base ,

mat is adequate for carrying its design static load I Calculations support the visual observations. Since the cracks are random and unrelated to critical stress locations, it would be a-3-

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coincidence if any occurred in critical flexure or shear zone Identification of the critical stress zones by calculations demonstrates that none did. Calculations are the only feasible means for evaluating seismic response. A finite element analysis has demonstrated that the mat will successfully withstand both the original design earthquake and the subsequently developed site-specific earthquake under the assumption that the cracks extend completely through the mat, that they may occur anywhere on the mat, and that there is no shear transfer other than by the shear-friction phenomenon. No actual analysis was made in which the Perry earthquake was applied to the Feral structure. but since the loading produced by the Perry earthquake is much less than that produced by the Fermi site-specific earthquake, there is no doubt that the structure could withstand the Perry earthquak The 0.03-inch crack width noted in 1972 is twice the width recommended for corrosion control in " Building Code Requirements for Reinforced Concrete (ACI 318-83)" of the American Concrete Institut The cracks were grouted in 1972 with a cement-fly ash grout. The cracks which have been detected more recently are too narrow to be successfully treated with cement grout. They have been sealed with epoxy resi There were 46 such cracks sealed in 1984 and 1985. The operation has been almost completely successful as affirmed by the generally dry condition of the top of the mat and the fact that only seven cracks are seeping some water. The extremely small flow is well within the capability of the project water-handling facilitie There is virtually no potential for steel corrosion. The widths of the cracks in the repaired condition are well below American Concrete Institute recommendations. And since the cracks are either sealed or filled with water, there is no opportunity for oxygen to reach the stee Without oxygen there can be no corrosio Exfiltration of water from the reactor building into the ground could occur only if a tremendous quantity of water poured into the buildin Since the base mat is 35 feet below the water table, over 35 feet of water would have to accumulat But the most severe pipe-break accident puts only 8.6 feet of water in the torus room. The reactor l

would achieve a state of cold shutdown before the maximum water height is reached. The reactor building is flood-proofed to a level more than a foot l

l above the highest possible flood level, and all doors and penetrations below that level are of wctertight design. In the unlikely event that a door were left open during a flood, water could enter the reactor building, but it could not rise above the level of the outside wate In order to evaluate the safety of the structure it is not necessary l

to pinpoint the exact cause of the cracks. However, it is almost

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certainly the result of thermal cracking associated with the high temperature rise of the very strong concrete. The concrete is much stronger than it needs to be. Although the use of fly ash reduces the rate of strength gain somewhat, almost all the concrete reached its required 28-day strength in less than seven days, and the one 90-day test that was made resulted in a strength over twice that required. While a maximum j temperature limit was imposed which required the use of ice, there was I probably a temperature rise in this massivs structure of over 100 F. In-4-

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cooling 100 degrees to sabient temperature, concrete must inevitably crack. In carrying out such placements, cracking can be minimized by following the advice in " Effects of Restraint, Volume Change, and Reinforcement on Cracking in Massive Concrete (ACI 207.2R)" of the American Concrete Institute. The search for an improved concrete, suggested in earlier correspondence when the cracking had first been discovered, has not materialized because Detroit Edison has not undertaken any nuclear reactor construction since Fermi CONCLUSIONS 1. The base sat will safely carry the design static and seismic loads, including those resulting from the revised site-specific earthquake and the Perry earthquak . Infiltration of ground water is very small and easily manageabl . Corrosion of steel is essentially impossibl . Exfiltration of water to the ground is impossible either in a pipe-break accident or a floo *

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. LIST OF APPENDICES APPENDIX As List of Attendees at Meeting on September 3, 1986 APPENDIX 3: Reactor Building Foundation Slab Chronology of Events APPENDIX C: Reactor Building Base Slab Document Package

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APPENDIX Dr Additional Documents Requested APPENDIX E List of Attendees at Meeting on September 12, 1986 l

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AFFENDIX A List of Attendees at Meeting on September 3, 1986 Robert A. Bryer Systems Engineer, Detroit Edison Domingo J.Carreira Sargent and Lundy Duane Danielson Nuclear Regulatory Commission, Region III David M. Hopper Hopper and Associates Sylvester H. Noetzel General Director, Nuclear Engineering, Detroit Edison Robert E. Philleo Consulting Engineer Walter Rogers Nuclear Regulatory Conunission, Resident Inspector Frank Sondgeroth Licensing Engineer, Detroit Edison David Spiers General Supervisor, Project and Plant Engineering, Detroit Edison Richard A. Witt Sargent and Lundy

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Reactor Building Foundation Slab Chronology of Events June & July 1971 construct nesctor Building base slab April 12, 1972 Cracks discovered in R.B. base slab. Ralph Parsons incident report written. WIPQC #175 April 14, 1972 ABC Region III notified of cracks. EF2-9459 May 1, 1972 Sargent & Lundy subsits a report on the R.B. base slab cracks and proposed repair. SLS 373 May 12, 1972 latter EF2-9933 sent to AEC describing R.B. base slab cracks and Edison's proposed repai June 2, 1972 latter EF2-10,216 to AEC stating the results of sdison's investigation of the R.B. base slab crack July 14,1972 sargent & Lundy completes analysis of R.B. bas,e

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slab assuming that cracks extend through the full thickness of slab. S&L concludes that the structural integrity of the slab is not impaire SLS-408 July 26, 1972 AEC letter to W. J. McCarthy reports on AEC inspection of construction activitie ,

September 25, 1972 R. M. Parsons completes an independent review of the R.B. base slab. Conclude that the structural integrity of the base slab is not compromised by the cracks. (R. M. Parsons letter to C. A. Kus -

Sept. 25, 1972)

September thru l

govember 1973 menctor Building base slab cracks repaired by

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injection grouting by Ime Tursillo Co.

1 May 12, 1974 Effectiveness of base slab grouting tested by

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hydrostatic test to elevation 567'-0".

November 8, 1974 Technical report EF2-29,332 submitted to unc via l

letter EF2-29537 to close 50 55(e)(3) ites.

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July 27, 1979 unc Inspection Report 50-341/79-04 reports on NRC

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investigation of oracks in Reactor Building base slab. Report confirms that crack repair program uns complete and not items of monoonformance were noted. (Pages 27 and 28 of report).

March 31, 1982 NRC inspector testifies before Atomic Safety and i

Licensing Board that Edison adequately addressed

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and resolved the concrete cracking in the Reactor Building base slab. (Page 28 of report)

March 10, 1982 thru December 1982 A survey of the R.B. base slab conducted to determine the number of unter infiltration point ' October 29, 1982 Atomic safety and Licensing Board administrative f judges ruled on intervener contention of inadequate construction. Judges ruled that R.B. base slab cracks were satisfactorily repaired and the cracks i are not flaws in constructio December 1982

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thru March 1983 Six cracks in R.B. base slab repaired by injection

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grouting performed by Structural Bonding Company.

I July 1984 thru

! October 1984 survey of R.B. base slab oonducted. Additional

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unter inflitration points identifie .

November 1984 thru April 1985 gDP-1824 prepared to seal cracks using injection i grouting. Grouting performed by Structural Bonding Compan ;

I October 25, 1985 survey of R.B. basement revealed one wall crack and l'

one damp floor spot. IE-PJ-85-0124 June 12, 1986 Beactor Building base slab examined for evidence of i

ground unter infiltration. There were no unter spots detected on the base sla July 23, 1986 Letter from Mary Sinclair to Mr. J. seppler NRC Region III expressing concern of the R.B. base slab crack e l

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July 30, 1986 Letter from ter. J. geppler Enc assion III to tenry Sinclair committing the Enc and the Fermi 2 4 architect engineer to reezamine the R.B. base slab eracking issu August 20, 1986 Telephone call from Edison (A. Alohalabi) to Sargent & Lundy (M. Tatosian) initiating a re-evaluation of the Reactor Building base slab for orsoked condition.

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August 21, 1986 Letter IIA-8/86-521 from Bopper Associates attesting to the ability of the Fermi 2 base slab to withstand the January 31, 1986 Chio earthquake.

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August 28, 1986 gdison submitted written scope document to have Sergent & Lundy re-analyse the base sla August 28, 1986 Letter HA-8/86-522 commenting on the affect of

! moisture on the base slab re-enforcing stee August 29, 1986 Sargent & Lundy letter SLS-gF-322 reporting that the re-evaluation confirms the structural integrity

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of the base sla ,

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Written by

R. A. Bryer Systems Engineer RAB/sv

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cc: A. M. A1chalabi S. H. Noetzel R. Y. Buck L. g. Schuerman

i J. R. Green L. J. Simpkin

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• • APPMDIX C Reactor Building Base Slab Document Package 4/21/72 Incident report IMPQC 175 F2-9459 4/14/72 Memo from A. Alexiou to W. Jens SLS 373 5/1/72 Sargent & Lundy htter to Edison . SLS 376 5/9/72 Sergent & Lundy letter to Edison F2-9933 5/12/72 Edison htter to AEC F2-10216 6/2/72 Edison letter to AE 7 6/28/72 AEC htter to Edison SLS 408 7/14/72 Sargent & Lundy letter to Edison 9. 7/26/72 AEC htter to Edison 10. 9/25/72 R. M. Parsons letter to Edison Lee Turzillo grouting procedure 11. 10/22/73 12. EF2-29537 11/8/74 Edison letter to AE 7/21,79 NRC Inspection Report 50-34/79-04

14. 6/7/79 NRC letter to Edison

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15. 3/31/82 ASLB Questions & Answers ASLB notes pages 20, 21, & 22 16. 1W29/82

! 17 F2-100522 1/16/84 Edison memo from R. Buck to L.

4 Schuerson

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18. E2-104431 1/17/85 Edison memo from R. Buck to Noetzel l

19. E 85-366 7/18/85 Edison meno from R. Buck to A1chalabi 20. NE-PJ-85-0124 10/25/85 Edison memo from A. Colantea to Spiers-11-

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. s 21. 1/12/86 Edison meno from R. Buck to A1chalabi 22. 7/23/86 Mary Sinclair htter to NRC 7/30/86 NRC htter to Mrs. Mary Sinclair

24. HA-8/ E 521 8/21/86 Hopper Associates htter to Edison 8/28/86 Edison htter and scope document to 25. NE-NS-86-02T1 Sargent & Lundy 26. HA-8/8 M 22 8/28/86 Hopper Associates htter to Edison 27. SLS-EF 322 8/29/86 Sament & Lundy letter to Edison 28. FSAR Section 2.5.4.1 Base slab constniction 29. Design drawings 6C721-2309 thru 2316 30. EP 1824 1-I-12-

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APPENDIX D ADDITIONAL DOCUMENTS REQUESTED 1. Final Safety Analysis Report 2. Project photographs for period June 1971 to April 1972 3. Sargent and Lundy Calculations SF-0003, pp lb, 3a, 18, 20, 26-61 4. Concrete Inspection Reports for June 14, July 9, July 15, and July 26, 1971 5, Well-Logging Reports, February 15, 1971 to March 5, 1973-13-

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AFFENDIX E List of Attendees at Meeting on September 12, 1986 .

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Abdul Alchalab Supervisor, Mechanical / Civil, Detroit Edison

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Robert A. Bryer Systems Engineer, Detroit Edison >

Ron Buck Engineer, Detroit Edison Donald Ferenoz Group Leader, QA, Detroit Edison ,

Sylvestor H. Noetzel General Director, Nuclear Engineering, Detroit Edison Robert E. Philleo Consulting Engineer Walter Rogers Nuclear Regulatory Commission, Resident 1 Inspector Frank Sondgeroth Licensing Engineer, Detroit Edison

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