View source for NRC-94-0075, Responds to CAL on 931225 Turbine Event.Results of Investigation Into Cause of Event & Action Being Taken to Restore Turbine to Serviceable Condition Encl

{{Adams
| number = ML20072P055
| issue date = 08/24/1994
| title = Responds to CAL on 931225 Turbine Event.Results of Investigation Into Cause of Event & Action Being Taken to Restore Turbine to Serviceable Condition Encl
| author name = Gipson D
| author affiliation = DETROIT EDISON CO.
| addressee name = 
| addressee affiliation = NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
| docket = 05000341
| license number = 
| contact person = 
| case reference number = CON-NRC-94-0075, CON-NRC-94-75
| document report number = CAL, NUDOCS 9409070080
| document type = CORRESPONDENCE-LETTERS, INCOMING CORRESPONDENCE
| page count = 37
}}

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      '         Do'uglas R Gipson su r V4 Her&nt                                                                        .
dC *O? )( & I [f '?) O Detroit
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August 24, 1994 NRC-94-0075 U. S. Nuclear Regulatory Commission Attn:        Document Control Desk Washington, D. C.              20555

==References:==
: 1) Fermi 2 NRC Docket No. 50-341 NRC License No. NPF-43
: 2) NRC Letter, Martin to Gipson, dated December 28, 1993
: 3) LER 93-014-01, NRC-94-0025, dated April 25, 1994
: 4) NRC Inspection Report 50-341/94007, dated June 15, 1994
: 5) LER 93-015-01, NRC-94-0026, dated April 21, 1994

==Subject:==
Response to Confirmatory Action Letter on December 25, 1993 Turbine Event On December 25, 1993 a turbine-generator failure occurred at Fermi 2.
On December 28, 1993, the NRC Regional Administrator sent Detroit Edison a Confirmatory Action Letter (CAL) documenting the NRC's understanding of the actions Detroit Edison was planning to perform (Reference 2). This letter constitutes the response to the CAL.
This response addresses the results of the internal investigation into the cause of the turbine failure, the actions being taken to restore the turbine to a serviceable condition, and the evaluation of the effects of the abnormal water chemistry experienced in the reactor on the fuel and reactor internals.
There were 6 actions listed in the Confirmatory Action Letter.
Reference 4 closed out Items 3, 4, 5, and 6. Additionally, the NRC has reviewed the B loop recirculation pump discharge valve failure and discussed in Reference 4 that the failure analysis was considered acceptable and proposed corrective actions were appropriate.
The majority of evaluations and resulting actions are complete, a few activities are still in progress. The following commitments are being made in this letter:                                                 g 9409070080 940824                              /#          N          Dg/[/I gDR   ADDCK 0500            41 g fp                   /
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      . USMRC                                                                      l August 24, 1994                                                           l l
NRC-94-0075 Page 2 l
o     Inspection plans are being developed to monitor for any possible long-term effects of the chemistry transient on the reactor vessel internals, o     The low pressure steam path is scheduled to be replaced in the      l next refueling outage (RF05).                                       ]
o     The following modifications will be implemented during the current outage (RF04) to increase moisture removal capability:
                  -    Modify low pressure turbine cylinders before stage 7 and before stage 8 drain holes.
                  -    Modify extraction steam line to Feedwater Heaters 1 and 2 low point drains.
o     Moisture carry over/ moisture removal testing will be performed following R5'04    Results will be reviewed and corrective actions deemed appropriate will be implemented during RF05 o     Extraction / Heater Drain Systems will be reviewed for conformance with ANSI /ASME Standard TDP-2-1985 and any appropriate changes will be implemented prior to restart from RF05 o     The low pressure turbines have been or will be overspeed tested to 1207,.                                                          ,
o     Trim balancing of all low pressure turbines has been or will be performed with 7th and 8th stage blades removed.
o     The following activities will be addressed in a supplementary response prior to plant startup:
                  -    Results of straightening and balancing of low pressure turbine rotors, discussion of plans to monitor turbine vibration during startup and actions planned if excessive vibration is experienced.
                  -    Results of turbine missile analysis and safety evaluation review.
                   -   Results from crud scrapings and destructive tests on the fuel bundle parts.
Enclosure 1 to this letter addresses the turbine-generator failure and Enclosure 2 discusses the evaluation of the abnormal chemistry effects on the fuel and reactor internals.      Detroit Edison believes that operation of Fermi 2 as planned will be a safe and acceptable activity based on the evaluation results.

  ~
      ,     USNRC August 24, 1994 NRC-94-0075 Page 3 If there are any questions on the information provided in this letter, please contact Lynne S. Goodman, Director, Nuclear Licensing at (313) 586-4097     She will answer any questions, make information available to NRC technical reviewers and inspectors, or arrange a meeting.
Sincerely, 4
cc:   T. G. Colburn H. P. Phillips K. R. Riemer NRC Regional Administrator L
4 f

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* O ENCLOSURE 1 RESULTS OF THE INVESTIGATION INTO THE CAUSE OF THE 12/25/93 TURBINE-GENERATOR FAILURE AT FERMI 2 AND ACTIONS BEING TAKEN TO RESTORE THE TURBINE TO A SERVICEABLE CONDITION i
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             ', Enclosure 1 to NRC-94-0075 Page 1 i
I.      INTRODUCTION On December 25, 1993 Fermi 2 was operating at 93% of licensed reactor power generating 1107 Mwe net. Operators reported that the plant was operating normally and that no abnormal                           ,
indications were present. At 1315 hours, without warning, the Main Turbine Generator (MTG) tripped and the reactor scrammed.                   !
A turbine blade penetrated the Low Pressure Turbine No. 3 (LP-3)
Exhaust Hood. Severe vibration caused considerable damage to the MTG including destruction of the exciter and damage to the General Service Water and Turbine Building Closed Cooling Water supply piping. Hydrogen, seal oil, and lubricating oil were                     ,
released and ignited. The resultant hydrogen and oil fires                      ;
triggered deluge and sprinkler systems. The oil and water mixture ultimately flooded the Turbine and Radwaste Building                     I Basements.
l II.      ANALYSIS A. INTRODUCTION Shortly after the event, site management placed the Turbine Building under quarantine to assure personnel safety and ensure that no evidence related to root cause was lost. A Turbine Generator Assessment Team was formed and developed an Action Plan that contained procedures for the identification, documentation and preservation of evidence. After initial review by turbine and generator equipment experts and a metallurgist, evidence judged to be related to root cause was uniquely identified and placed in controlled storage. A Detroit Edison Root Cause Analysis Team (RCA) was then formed to determine the root cause(s) of the event. The original equipment manufacturer (OEM) of the MTG, GEC ALSTHOM, cooperated and also conducted an independent root cause. analysis. Failure Prevention International (FPI) was also contracted to perform a
                        -third party independent root cause analysis.
The three teams independently evaluated all reasonable potential causes of the event, systematically eliminating those which did not contribute to the root cause. The analysis method ensured that all of the approximately 1600 identified potential causes-
                        -were addressed. From these potential'causes, each independent team developed a list of probable causes. As is frequently the case with such events, thcre was a lack of totally conclusive evidence and it has not been possible to establish a single root cause with 100% certainty. In recognition of this, the most probable root causes have been identified and corrective actions were identified to bound the three causes. (Corrective actions are described in Section IV.A " CORRECTIVE ACTIONS"). The corrective actions are designed to prevent recurrence of the event.                                                                          <

       -.                                    --      _.    - - .                        _ _ _ . ~. _.
4 Enc'losure 1 to NRC-94-0075 Page 2 B. FAILURE MECHANISM The following failure mechanism conclusions were reached by all three RCA Teams.
The event initiated with the failure of Blade No. 9 of the front flow (governor end), 8th stage of LP 3 Metallurgical analysis revealed that this blade failed due to the mechanism of high cycle fatigue. The fatigue crack initiated about 1-1/4 in, above the blade platform on the pressure (concave) side near the trailing edge. The crack propagated to a critical size and the blade failed due to overload. The separated blade section impacted trailing Blade No. 8 and caused it to fail due to tensile overload. Trailing Blader Nos. 7, 6, and 5 then failed               :
in succession also due to tensile overload. The unbalanced condition associated with the sudden mass loss resulted in severe shaft vibration. This severe vibration actuated the turbine mechanical over-speed trip, tripping the MTG and causing a reactor scram. The MTG did not overspeed.
Crack indications were discovered in 7th Stage blade roots and discs during post event examination. These indications have been determined to have existed prior to the event and were not              ,
a cause of the event. (For additional information see Section                ,
IV.B.3 " Repairs".)
C. ROOT CAUSE ANALYSIS This section will address the probable root causes identified by the three Teams. Please note the following three key points:                 ,
o      -There was agreement on probable causes among the Teams, but there were differing opinions regarding the relative importance and interpretation of evidence and analytical             ,
results.
o       In most cases the individual probable root cause                     !
conclusions of the Teams are a combination of more than one probable cause.
o       Based on the review of the' conclusions of the Teams, Detroit Edison has concluded that the first three defined probable root causes discussed below, Steam Path Water, Physical Characteristics of Blade No. 9 and Torsional Resonance, are the most probable causes of the Blade No. 9 failure.
The following is a description of the probable causes and contributing factors identified by the three RCA Teams.

       . ', Enclosure 1 to NRC-94-0075 Page 3
: 1. STEAM PATH WATER:
This probable root cause has two categories: Accumulation of Steam Path Water and Water Induction. These causes are described and discussed individually below:
Accumulation of Steam Path Water - As steam passes through the turbine some condenses as free water. The water forms droplets which impact the rotating and stationary blades,            ;
and accumulates and is shed from a blade's trailing edge as larger droplets. The water is also slung radially outward due to centrifugal force, accumulating as an annular ring            ,
at the outlet side of the diaphragms. Moisture is removed            l between stages and piped to feedwater heaters with extraction steam or directed to the condenser directly from the turbine internals. Inadequate interstage water removal can lead to increased steam path uater.
A postulated mechanism involving excess steam path water to explain the observed turbine blade failure involves a "proud" blade, i.e., one that projects radially or axially to a greater extent than the majority of blades. Because of variability in manufacturing and installation, a blade            !
may become proud, to some extent, and therefore, subject to          I greater loading than the others. As the "proud" blade moves through the water it may twist due to resisting force. At some threshold, the blade could become overloaded resulting in permanent deformation or excited at a resonant frequency. A cyclic load could result in stresses exceeding the fatigue strength of the "proud" blade.
Water Induction - Normal moisture levels in the machine are not a source of abnormal excitation loading. They do not generally present a serious problem and there is no practical limit to the quantity of entrained water.
However, the situation is quite different if slugs of water are present. These may be due to reversal or blockage of flow in extraction / drain lines causing an interruption in the normal water extraction process, or as a result of steam flashing in the extraction / drain lines or heaters and forcing water back into the turbine.
Slugs of water have been known to be capable of deforming blades foils. The water mass will break up immediately on the first impact and the effects will be restricted to only one or two blades. Observations of damage on turbines which are known to have experienced water problems confirm that often only a small number of blades can be affected.
Results of inspections of turbine and extraction steam system, analyses of postulated events and review of historical operating data have not substantiated nor eliminated steam path water as the cause of the event.

Enclosure 1 to NRC-94-0075 Page 4
: 2. PHYSICAL CHARACTERISTICS OF BLADE NO. 9:
Detailed inspection and metallurgical examinations of Blade No. 9 revealed two characteristics which could make it vulnerable to fatigue failure due to steady state and cyclic service loads:     1) the trailing edge of the foil section at the point of the fracture was found to be approximately 40% thinner than blades which had not failed;             '
and 2) a residual tool mark was found on Blade No. 9 at the point of initiation of the fatigue crack. Both characteristics are considered undesirable from the standpoint of effects on blade fatigue life. These characteristics are not typical or associated with operationally-caused wear.                                              ,
If 8th stage blade fatigue life was a generic problem, other blades with some evidence of fatigue cracking would be expected. Visual and non-destructive examination of 8th stage blades removed from the LP rotors revealed no evidence of such cracking. The trailing edges of all 8th stage blades on the LP rotors were measured.       Blade No. 9 exhibited the thinnest trailing edge. This observation was statistically significant in that its measurement was more than three standard deviations from the mean of the total population. Thus, the vulnerability to fatigue failure was not concluded to be a generic problem, rather it is believed to be limited to Blade No. 9 due to its physical characteristics.
Stages 1 through 6 blades are less susceptible to this type of failure for the following reasons:
: 1)   They are subjected to lower service stresses.
: 2)    They are shorter, have continuous interconnected shrouds and are more rigid.
: 3)    Their resonant frequencies are significantly higher                j and therefore are less susceptible to excitation by potentially damaging vibration modes.
Based on the above considerations, the unique physical characteristics of Blade No. 9 were considered to be a significant contributor to its failure.
3     MTG ROTOR SYSTEM TORSIONAL RESONANCE:
Negative sequence current can have an adverse effect on turbine generators if the complete rotor assembly is torsionally resonant at 120 Hertz. The negative sequence current imposes an alternating torque on the generator rotor and turbine rotors, causing the rotors to alternately twist in addition to their normal rotation. Because of the large size and complex shape of the complete Turbine

Enclosure 1 to NRC-94-0075 Page 5 Generator rotor assembly, it has many frequencies at which it is likely to twist, called tv.sional resonant frequencies. If the turbine generator rotors are torsionally resonant at 120 Hertz, the combination of torque due to negative sequence current and resonance can lead to high stress in turbine blades. Based on the configuration of the LP rotors, the 7th and 8th Stage blades are the most susceptible to torsional resonance.
There are several sources of negative sequence current but the most common are load distribution and system transients. There is always some phase unbalance in the system, therefore, there is always some source for the torsional excitation frequency of two times line frequency.
The negative sequence current is not automatically recorded. This is consistent with industry practice since this is a relatively new phenomenon being addressed by the utilities.
At the time of the design of the Fermi 2 Turbine Generator (circa 1970) torsional vibration was considered only for rotors and couplings.      Blades and discs were not addressed. This was accepted design practice at the time.
More recent analyses have utilized advanced modeling capabilities that take into account the flexibilities and interactions of rotors, shafts, discs and blades.
GEC ALSTHOM was requested by Detroit Edison in March 1993, to evaluate torsional reponse as a result of an industry notification on this subject. GEC ALSTHOM concluded, based on tests of LP rotors of the type supplied to Fermi 2 conducted in their overspeed facilities, that " torsional response of the Enrico Fermi turbine generator is quite satisfactory and that negative sequence torque excitation will not cause any problems".
A more detailed, machine specific, turbine generator system analysis for torsional resonance of the Fermi 2 system was completed by GEC ALSTHOM in May 1994. They concluded that torsional resonance was not a factor in the failure of Blade No. 9. However, an independent third party review of GEC ALSTHOM analyses did not completely support GEC ALSTHOM conclusions and the third party recommended testing. Since the Fermi 2 MTG is being reassembled in a different configuration than existed at the time of the event, verification testing is not possible.      Therefore, it is not possible to prove or disprove that torsional resonance was the root cause of the event.
GEC ALSTHOM has completed a torsional resonance stress analysis of the turbine generator system configuration (with LP Stage 7 and 8 rotating and stationary blades removed, with pressure plates installed in place of 7th and

Enc'losure 1 to NRC-94-0075 Page 6 8th Stage stationary blades, and with a static exciter) which will exist in the startup from RF-04. The analysis includes a conservative calculation of rotor stresses by considering excitation of a torsional resonance. The additional dynamic stresses are negligible and the analysis concludes that torsional vibration of the turbine generator rotor system (post RF-04) is not a concern. Independent review of this analysis technique is planned.
: 4. LACING RODS:
The 8th stage blades (and only the 8th stage blades) are linked by lacing rods with one rod between each blade. The loss of two rods would allow a blade to become free-standing and possibly more susceptible to excitation.
The loss of the lacing rods had been discounted as there was no supporting evidence from the rotor vibration records to indicate a balance change of sufficient magnitude.
However, it was postulated that a mechanism for losing the lacing rod connections could involve a single blade twisting so that the ends of two adjacent rods (connected to the same blade) come free while other ends remain in place in their blades. In this cenfiguration, a single blade will become free-standing. The freed rods would then bend outward under the influence of centrifugal force and remain hooked in their blades with no change in rotor balance. The additional mass close to the tip of the free-standing blade would cause a further small frequency change. In this condition excitation of the free standing blade r<.uld occur. Physical evidence was destroyed as a result of the failure which prevents determining conclusively, the contribution of the lacing rods to the failure of Blade No. 9
: 5. BWR ENVIRONMENT DESIGN:
Higher levels of oxygen generally present in BWR steam can have a negative effect on material fatigue strength. The reason this was identified as a contributing factor is based on the different failure history at Fermi 2 (BWR) compared to sister MTGs at PWRs and the lack of evidence suggesting that a BWR operating environment was adequately considered:in the Fermi 2 blading design. Consequently, it has been concluded that the higher oxygen levels in BWR generated steam could be a contributor to the failure of Blade No. 9, and that this factor may not have been considered in the original blade design.

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Enc ~1osure-1 to NRC-94-0075 Page 7
: 6. STEAM / WATER CHEMISTRY:
The higher oxygen levels present in BWR steam has some impact on the fatigue strength of the blading material.
Under normal circumstances it would be expected that there would be sufficient margins in the design to accommodate the higher effects.of this oxygen concentration. However, the history of fatigue cracking in blading and discs of.
other stages (5th and 7th) suggests that the Steam / Water Chemistry could have contributed to the failure of Blade-No. 9 The latter two items, BWR Environment Design and Steam / Water Chemistry, are not an operational concern for at least one more operating cycle. The contribution of          ,
steam path chemistry is primarily associated with the effects of ionic species such as oxygen, sulfates, chlorides, etc. on fatigue strength. This factor is of lesser concern on blades and discs with significantly lower service stresses than the higher loaded 7th and 8th stages of the LP Turbines.
7    LOW CONDENSER BACKPRESSURE:                                     ,
i The day of the event condenser backpressure was among the lowest points in Fermi II operating history. Since this condition increases loading most significantly on the turbine last stage blade rows it could have been a contributor to the failure of Blade No. 9 Detroit Edison does not believe that this factor had much, if any, effect on the Blade No. 9 failure. Nonetheless, elimination of the 8th Stage Blades for the next operating cycle removes the blading most load sensitive to low condenser backpressure.
III. TURBINE BLADE MODIFICATION AND PRESSURE PLATE INSTALLATION A. SAFETY Detroit Edison has evaluated all viable options for safe and reliable operation of Fermi 2 MTG for Cycle 5.
Operation with the 7th and 8th stage stationary blades (diaphrages) and rotating blades (airfoils) on both ends of    ;
each of the three LP Turbines removed is the preferred option. Pressure plates will be installed in place of the      ,
stationary diaphragms (and thus, will not rotate) to replicate the pressure drop of the removed blading in all three LP Turbines. Blade stubs (root protectors), which        .
will remain fastened in their' normal manner, will protect the root sections of the 7th and 8th stage disks. This option provides the highest benefit with the lowest risk        l until a new replacement steam path can be installed during

Enclosure 1 to NRC-94-0075 Page 8 the next refueling outage which is currently scheduled for the first half of 1996. Operation with pressure plates installed as described above is a proven technology which   ;
significantly reduces the risk of recurrence of a MTG failure.
Please note that a safety evaluation on the pressure plates and turbine missile analysis is still under review.
B. DESIGN AND VERIFICATION The design purpose of a pressure plate is to create the pressure drop of the removed stages of blades and diaphragms to avoid overloading other stages, particularly the immediately upstream stage. Detroit Edison has conducted a comprehensive review and verification process, as outlined below, to insure that operation with the GEC ALSTHOM designed pressure plates will not pose adverse operational effects.
: 1. Westinghouse performed a detailed review of the GEC ALSTHOM proposed pressure plate design using their own' design methodology and verification process. This review focused on the capability of the pressure plate design to duplicate the turbine thermodynamic conditions and structural adequacy of the pressure plate. They have concluded that the GEC ALSTHOM design is adequate and, indeed,             q conservative.
: 2. Westinghouse pressure plate design and operating experience with pressure plates were reviewed by site personnel and found to be applicable to the GEC ALSTHOM design.
3    Technical and Engineering Services (Detroit Edison) provided a detailed review of the prior operational experience with pressure plates designed by GEC ALSTHOM at Fermi 2. No adverse operational or vibration effects were identified.
: 4. MPR Associates performed a survey of domestic Westinghouse and GE turbines that have operated with pressure plates      l installed. This survey specifically requested operational  -l limitations and adverse operational effects experienced.
The period covered begins in 1970, with more than twelve nuclear plants identified. Experience supports the installation of pressure plates at Fermi, with plants identified that also installed pressure plates in the last l
two stages of the LP turbine (s).
5     Failure Prevention International (FPI) performed:
: a. an independent study utilizing their own experience,

Enclosure 1 to NRC-94-0075 Page 9
: b. a review of the GEC ALSTHOM and Westinghouse identified relevant experience summaries,
: c. a review of the Westinghouse conclusions of the GEC ALSTHOM design review, and                               1
: d. a review of the MPR industry experience survey.
FPI concluded that their experience, the experience of the GEC ALSTHOM design review by Westinghouse, and the identified operational experience supports the prudency and viability of installing pressure plates.
: 6. A Safety Evaluation for the pressure plates is under review in accordance with 10 CFR 50.59 and site procedures.
IV. ACTIONS TAKEN/ INITIATED FOR RELIABLE OPERATION A. CORRECTIVE ACTIONS:
The RCA Teams Nere aware of the decision to operate in Fuel Cycle No. 5 with low pressure turbine 7th and 8th stage blades and diaphragms removed, and pressure plates installed. The teams were also aware of the decision to replace the low pressure steam path in RF-05. The following corrective actions address the probable root cause corrective actions identified by the RCA Teams and were made in light of these decisions:            ;
: 1. In order to increase moisture removal and reliability from the turbine the following modifications will be implemented during RF-04:
1
: a. Modify LPs cylinder before Stage 7 and before Stage 8   l drain holes.
: b. Modify extraction steam line to Feedwater Heaters 1 and 2 low point drains.
: 2. Perform moisture carry over/ moisture removal testing following RF-04. Review results and implement corrective actions deemed appropriate during RF-05 3     Perform moistura carryover / moisture removal testing to evaluate effects of any corrective actions implemented following RF-05
: 4. Review Extraction / Heater Drain Systems for conformance with ANSI /ASME Standard TDP-2-1985 " Recommended Practices for Prevention of Water Damage to Steam Turbines Used for Electric Power Generation", and implement appropriate changes prior to restart from RF-05.

Enclosure 1 to NRC-94-0075 Page 10
: 5. Confirm that the replacement low pressure steam path has features for adequate water removal as part of the design
'                                  review, prior to RF-05
: 6. Ensure by evaluation or testing that replacement steam path component designs bound anticipated service loads and operating conditions including excitation of torsional resonance. Please note that the RCA Team recommendations related to torsional resonance analyses and testing on the                           ,
existing machine have been dispositioned'through analyses                            l as specified in Section II.C.3 "MTG ROTOR SYSTEM TORSIONAL                           f RESONANCE".
7    Ensure that the BWR steam path environment is considered in the design of replacement components.                                               ;
: 8. Ensure that replacement steam path components are manufactured and installed to design specifications.                                i l
B. CURRENT STATUS OF MTG
: 1. Non-Destructive Examination (NDE)
Because of the damage caused by the December 25, 1993 event                          ;
Detroit Edison performed the following extensive NDE.                                j
: a. Magnetic Particle Test / Examination (MT): Prior to                            l shipping the LP Turbines to Charlotte, MTs were performed on all exposed surfaces of all LP Turbines.                          i MT was also performed on the exposed surfaces of the High Pressure turbine.
: b. Ultrasonic Testing (UT): All three LP Turbines were shipped to the Westinghouse Co. Repair Facility in Charlotte, North Carolina. GEC ALSTHOM                                        ,
representatives performed UT analysis on all LP Turbine's 4, 5, and 6 stage blade roots and disc heads.    (Based; on visual and magnetic particle testing / examination, UT analysis of Stage 1, 2, and 3 blade roots is not warranted). Westinghouse personnel performed the UT on all disc bores and dowel holes on                         3 all three turbines.
The HP Turbine had its rotor bore UT'd at Fermi.
: 2. Dynamic Tests:
LP Turbine overspeed testing up to approximately 120%                              !
was/will be performed with blades installed on all discs in order to produce the maximum stress (at this overspeed condition) on retating components.      This test provides assurance of rotating component integrity by confirming                              l

Enclosure 1 to NRC-94-0075                                                                  l Page 11 I
that the rotors' discs and blades will not shift and/or          l come loose at the normal operating speed (100%) or at the turbine overspeed (110%) trip test speed. Additionally, the increased centrifugal force imposed by the overspeed        ,
condition assists in reducing the rotor's bow by relieving any uneven " hold" that a disc may have on a rotor shaft.
Trim balancing of all LP Turbines has been or will be           ,
performed with the 7th and 8th Stage blades removed at the normal operating speed, 1800 RPM (1005), and 10%
overspeed. Trim balancing will also be used to confirm          ;
expectations that the change in critical speeds is small.        l J
The generator rotor was sent to Siemens Co. repair facility     i for high speed balancing in addition to other corrective        j maintenance. Maintenance was completed and the generator rotor returned to Fermi.                                        ,
3    REPAIRS
: a. LP Rotor Bows - LPs rotors were/will be overspeed tested to reduce the bows in their rotors as described above. LP-3 had to have three discs on its front end heated to relieve uneven stresses between the rotor and these discs prior to overspeed testing. (Heating the discs relieves their uneven hold on the rotor which resulted from the event and subsequent abnormal shutdown. )
The as left bows on the LPs rotors are acceptable because the bows have been or will be proven to be stable based on overspeed tests. These overspeed tests increased or will increase the centrifugal          i forces on rotating components at least 40% above normal operating conditions prior to removal of the 7th and 8th Stage Blades. (As stated previously, the removal of these blades significantly reduces the stress levels on their associated discs during normal operation.) Additionally, the effects of the bow will be or have been balanced out to acceptable levels for -
operation. LP 1 and 2 have had their final tria           ,
balancing performed at Charlotte. The rotors' bows are approximately 11 mils. and after balancing the        :
vibration is less than 2.0 mils, at 1800 RPM for each rotor.
: b. Root Protectors - Seventh and 8th Stage airfoil blade roots were or will be installed to protect the discs.
These root protectors will be fastened to the disc in their normal manner as if the-full blade was attached.
The as left root protectors are acceptable because they will be attached to the discs in the normal I

Enc ^losure 1 to NRC-94-0075 Page 12 i
I manner even though the operational stresses on them      ;
are significantly less.                                  I
: c. Discs - Indications were identified by NDE on all three LP 7th Stage disc steeples (disc heads) and also on the 5th Stage of LP 3 (rear flow only) disc heads.
The 7th Stage indications which were judged to.be significant were blended out (ground out). The remaining indications on Stage 7 disc heads were judged to be insignificant, by both Westinghouse and GEC ALSTHOM representatives. The Stage 5 disc head indications have been examined by Westinghouse and GEC ALSTHOM. GEC ALSTHOM's recommendation to blend out the indications has been completed.
Indications have been identified on LP 3 disc's steam balance holes (rear flow only). These indications have been inspected by Westinghouse and GEC ALSTHOM.
Remedial actions per GEC ALSTHOM have been completed.
The as left discs are acceptable because significant indications have been blended out. With respect to the 7th and 8th Stage discs the stress levels have been reduced by removing the airfoil section of the blade. The LP turbines have or will be overspeed tested to 120%. The centrifugal forces induced during these runs on Stages 1 through 6 discs are at least 40% greater than those expected during the normal operation of the rotors and significantly greater than this for the 7th and 8th stage discs.
: d. Generator / Exciter - The generator has been cleaned and reinsulated. The exciter is being replaced because of excessive mechanical damage.
C. SYSTEMS EVALUATION System Walkdown Teams were established to identify the corrective and preventive maintenance needed to return Turbine Building Systems to service in a reliable condition. Members of the Teams consisted of multi-discipline engineers from Technical and Plant           l Engineering Departments. The multi-discipline review          l approach was used to more accurately assess and identify physical damage to the major systems in the Turbine           ,
Building. Systems which received the highest priority and     i thus, were walked down first are Turbine Building Closed Cooling Water, Station Air, Condensate Storage & Transfer, Standby Feedwater and Off-Cas Systems. Mechanical, Electrical and Instrumentation & Control Checklists and guideline instructions were developed and implemented to assure thoroughness of each system walkdown.

l
      . Enc'losure'1 to                                                                                 l NRC-94-0075 Page 13 CONCLUSIONS - Each system that was walked down had a report written which describes the equipment inspected, the results of the inspection and corrective actions initiated. Corrective actions are being evaluated and                               i implemented as required per the normal plant work control process.
I D. STRUCTURAL EVALUATION As a result of the MTG failure and resulting events, the need to inspect and evaluate plant structures, supports and components for damage was required. Additionally,                                 .
actuation of the Seismic Monitor and resulting conclusions                          l needed to be evaluated.                                                            ,
A Structural Walkdown Team was formed. The walkdown team consisted of qualified Structural and Civil Engineers, in the Mechanical / Civil Group of Plant Engineering, with an average of fifteen years of nuclear power plant                                   ;
experience. During walkdown preparation, the turbine                              L accident and the resulting events were studied to determine the most critical items to inspect.
In order to evaluate the damage and determine the type of repair needed in the Turbine Building, structural design documents, drawings and design calculations were reviewed.
The Turbine Building structural elements were visually inspected for signs of damage or displacement. The elements examined included concrete slabs, walls, beams, columns, concrete. foundations / pedestals, masonry walls, structural steel beams, columns, bracing and stair stringers, doors and frames, penetrations, anchor bolts, and isolation joints.
Structural walkdown teams interacted with the System Walkdown teams by exchanging information and findings concerning system supports and foundation damage. In addition, specific Safety Engineering personnel supported the walkdown efforts by notifying Structural team members of their findings and requesting evaluations.
The excitation of the seismic monitors was of a shock incident, not a tectonic earthquake. A shock impulse                              ;
imparts low energy into a structure and does not result in_
significant structural stresses. The structural integrity of the Reactor / Auxiliary Building and the equipment therein was not compromised. Nonetheless, walkdowns of the Reactor Pedestal, Drywell Concrete Floor Slab and adjacent areas to                       ;
the Turbine Building were performed with no damage                                ;
identified.
CONCLUSIONS - The structural integrity of the Turbine Pedestal, Turbine Building Structure, Reactor / Auxiliary Building and Radwaste Building were not compromised as a

Enclosure 1 to NRC-94-0075 Page 14 result of the turbine event. Observed indications tended to be superficial and cosmetic in nature and will be repaired or have been accepted as-is based on a case by case evaluation. Local structural damage was identified on MTG bearing beam stiffener members. Actions to correct this problem are in progress. The LP 3 lower section and main condenser under LP 3 had sustained damage due to direct turbine missile hits. The corrective action to repair these locations is in progress. The overall structural integrity of the damaged components was not compromised.
E. STARTUP TESTING Enhanced start-up testing will occur to monitor the MTG and pressure plate performance. (Please note that these tests are in addition to the planned completion of the power uprate integrated system tests.) Key system parameters will be monitored and compared to historical values and expected values based on the revised heat balance. The results af these comparisons will be evaluated to assure that the MTG and pressure plates are operating as expected and to determine if imposition of any operating limitations is appropriate / required.
V. CONCLUSION While the specific root cause has not been determined with 100%
certainty, the most likely root causes have been identified and bounded by the specified corrective actions. The processes used to repair and modify the MTG incorporated not only the OEM input but also input from one of the industry's most experienced manufacturers. Independent and third party review also occurred in the pressure plate design. The effects of the event have been identified by extensive testing and/or visual inspection, and corrective actions have been completed or actions have been initiated for their correction. The post repair testing at Charlotte of the three LP Turbine rotors was or will be performed at much higher stress levels than those expected during the remaining operational cycle of these turbines.
i i
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8 1
ENCLOSURE 2 EVALUATION OF THE EFFECTS OF THE ABNORMAL WATER CHEMISTRY FROM THE 12/25/93 EVENT AT FERMI 2 ON THE FUEL AND REACTOR INTERNALS

Enclosure 2 to NRC-94-0075 Page1 Introduction On December 25,1993 a reactor scram occurred initiated by the loss of turbine blades from the # 3 low pressure turbine. One blade punctured the hood, with the remaining blades thrown downward, severing many condenser tubes.
Excess water from the condenser was routed to the condensate storage tank (CST),
significantly degrading the quality of water in the tank. The Reactor Core Isolation Cooling system (RCIC) was placed into service at 1315 EST approximately 15 minutes following the scram. The RCIC was aligned with suction from the CST. Shortly thereafter the standby feedwater pumps were also placed into sersice with suction from the CST.
The Condensate Filter Demineralizer System was shut down at 1611 EST and the circulation water was isolated from the main condenser at 1626 EST. By 1810 EST the first chemistry analysis of the reactor water showed a reactor water conductivity of 61.4 uS/cm at a pil of 9.8. High chlorides and sulfates were also reported (4-5 parts per million ).
Vessel cool down commenced approximately one hour after the scram. A temperature of 350 degree F. was reached at 2100 EST. The Residual Heat Removal System (RHR) was placed into service at 2010 EST on 26 December. The reactor temperature decreased reaching 150 degrees F. at 0100 EST 27 December.
The reactor water peaked at 182 uS/cm at a pH of 10.6. The principle ions contributing to the conductivity were chloride (11-12 ppm), sulfate (10-11 ppm), and nitrate (1.2-1.4 ppm). Subsequent analysis of calcium (8 ppm) and sodium (5-6 ppm) were reported.
A.       Fuel Inspections Four fuel bundles were inspected and three crud scraped to detennine if there was any effect on the fuel or related components attributed to the chemical transient. The scope of the inspection included:
          . visual examination and oxide thickness measurement of selected rods.
          . retrieval of bundle parts for destructive examination at the GE hot cell to evaluate Inter granular Stress Corrosion Cracking (.IGSCC) on susceptible components. These components included nuts, locktab washers, and 2 selected expansion springs from each bundle as well as I channel fastener.
I

Enclosure 2 to NRC-94-0075 Page 2 l
       . Non-destructive examination (NDE) inspection of the two failed fuel rods (not             j associated with the chemical transient)                                                   l The following bundles were inspected to assess the effect of the chemical transient:         )
l LJK962(GE6)           Located in the fuel pool and used to benchmark the other bundles       l that experienced the transient. This is a thrice burned cycle 3 failed l bundle. This bundle did not experience the chemical transient.         l LYS488(GE8B)          Thrice burned, cycle 4 failed fuel bundle                              !
LYX594(GE98)          Twice burned, high exposure. The channel fastener from this bundle     l was sent for hot cell examination                                      j YJ2809(gel 1)         Once burned, high anticipated cycle 5 exposure Crud scrapings were taken from the following bundles:
LJK961(GE6)           This bundle was located in the fuel pool and did not experience the chemical transient, symmetrical to LJK962(GE6)
LYS486(GE8B)          Symmetrical to LYS488(GE8B)                                            !
YJ2809(gel 1)         This bundle was both inspected and crud scrapped.
The location of the fuel bundles relative to the core can be found in figure 1.
The results of the inspection are as follows:
                                                                                                    )
       . Rod oxide measurements indicated nominal corrosion levels. Some of the rods found in bundle LJK962 exhibited a visual standard 3 (most exhibited visual standard 2) and oxide thickness ranging from 1.0 to 2.5 mils. This is not unexpected for a high exposure bundle and no conosion resistant heat treatment. The rods examined on the remaining bundles were also mostly visual standard 2, but some exhibited visual standard I which indicated virtually no corrosion. These rods had an oxide thickness      i ranging from approximately 0 to !.0 mil.
1
       . The results from the crud scrapings and destructive tests on the bundle parts is scheduled to be received by the end of August.                                            ;
       . Visual examination of the various fuel components found the surface conditions to be indicative of exposure to a BWR environment There was no evidence of surface              I degradation in forms of stress corrosion cracking or micro biologically induced corrosion.

Enclosure 2 to NRC-94-0075 Page 3 B.      Control Rod Drives Six control rod drives (CRD) were inspected during the rebuild activities. The results of the inspections are as follows:
      . The CRD scram function would not be adversely affected by the observed corrosion condition. However continued corrosion may result in excessive seal degradation and lead to early CRD refurbishment.
      . Corrosion deposits were found on the CRD components, especially on the index tube and piston surfaces. The deposits suggest that the index tube and piston tube corrosion were promoted by the circulating water transient. In comparison to CRD's of similar service life the corrosion appears to be worse than average.
      . The general corrosion on the index and piston tubes is moderately severe. Stress corrosion cracking is not expected to initiate from these sites.
Based on the inspection it was concluded (GE-NE Cl100297-01, Rev.1) that no ft rther refurbishment was necessary during RF-04 provided the CRD's were exercised daily when conditions permitted.
C.      Local Power Rance Monitors (LPRMs)
Fenni 2 has 29 LPRMs with NA200 detectors and 14 LPRMs with NA300 detectors.
Following the transient one NA200 detector string failed (48-498) at 33.75 hours after the scram. Approximately eleven weeks later the second NA200 string (40-25C) failed.
Since the possibility oflater failures could not be excluded, the remaining NA200 detectors were replaced.
D.      Reactor Internal Inspections Table 1 Lists the Class I reactor pressure vessel (RPV)/ RPV nozzle welds and Class 1 and 2 pipe welds and components examined during the RF-04. Table 2 lists the examinations conducted during In Vessel Visual Inspections (IVVI). Both ASME inspections and all augmented inspections are listed .
l

I Enclosure 2 to NRC'-94-0075 Page 4 l
INSPECTION OBJECTIVES:
The objectives of the remote underwater in Vessel Visual Inspections (IVVI) perfonned       l during RF-04 consisted of three primary categories. First was to assure the continued integrity and operational readiness of the RPV Internals. Second was to verify that the 2
RPV Chemistry Transient, associated with the Turbine / Generator event of 12/25/93, had no near tenu detrimental effects on the RPV Internals. The third and final objective, was to assure that those RPV Internals which have experienced cracking in BWR reactors were included in the Fermi 2 IVVI and received special attention.
The visual inspections perfonned utilized a high resolution color camera system equipped    ,
with twin lights capable ofintensity adjustment. The camera system had a 10X magnification. The camera system's resolution and sensitivity for inspections was verified using a 1 mil wire on the inspection surface for each distance of examination.
For example, those examinations perfonned at a distance of 3" had a system verification perfonned with a 1 mil wire on the surface with the camera at an inspection distance of 3" Those examinations perfonned at a distance of 12" had a camera system verification perfonned at 12" In addition all accessible Core Shroud circumferential weld surfaces and certain other key areas were hydrolyzed to clean the surface prior to conduct of inspections thus yielding the best possible visual inspection results.
INSPECTION RESULTS:
CORE SIIROUD INSIDE SURI' ACE                                                                4 l
The inside surface of tne Core Shroud has been inspected to the maximum extent possible on the H-2 through H-4 welds. No indications were found on the H-3 and H-4 welds on the inside surface of the shroud. Two small indications < l-inch long were found at the      i 125 degree azimuth just above the H2 weld but not in the H2 weld. These indications are generally in a vertical direction, jagged in nature and tight with no visible separation. l These indications appear to be different from indications found at other BWR's and most probably arc a result of cold working during the fabrication process. These indications were evaluated against established flaw screening criteria and have no significant effect on the stnictural integrity of the shroud.
CORE SilROUD OUTSIDE SURFACE The circumferential welds on the outside surface of the Core Shroud have been visually inspected to the extent possible from the H1 weld through the H7 weld with no

Enclosure 2 to NRC'-94-0075 Page 5 indications being found. The H-8 and H-9 shroud support welds were also looked at but from a distance and at an angle. No indications were found.
SIIROUD IIEAD BOLTS All Shroud Head Bolts were examined using approved Ultrasonic Testing procedures with crack like indications being found in 16 of the 43 bolts. The crack location was identical to those found at other BWRs (i.e., at the collar crevice). The 16 cracked bolts were replaced with those of a new and more IGSCC crack resistant design. A 17th bolt was replaced for reasons other than crack indications. The remaining old design bolts which had no indications were reviewed and found to be acceptable for the next operating cycle. These bolts were reinstalled returning the configuration to the original design of 48 bolts. A design review was performed in part to detennine the structural significance    i of operating with indications in 16 shroud head bolts. This review determined that only 20 bolts are required to fulfill design requirements.
STEAM DRYER Tic Rod Nut / Washer Tack Welds - During manufacture, the individual vanes are assembled by alternately sliding a vane then four cylindrical spacers over four 3/8 inch diameter tie rods, two at the top and two at the bottom. When the correct number of         ,
vanes are assembled on the tie rods,3/8 inch thick dryer unit end plates are secured to the tie rods with an eccentric washer and nut on both ends of each rod. These washers and nuts are then tack welded or plug welded to keep them in place. Many of the 48 tie rod end washers / nuts protrude above the unit end plate surface. Fifteen of these protniding tie rods have cracked tack welds, however all but 4 of these have at least 2 intact tack welds at each location. The remaining 4 tie rod nut / washers that contain failed tack welds have at least one good tack weld remaining Similiar cracking has occurred at other RWR"s. The failed welds do not represent a structural or ftmetional concern. The only potential concern is for loose pieces. However, the tie rod nut is tack welded to the tie rod and these tack welds are intact. Therefore, this is not considered a problem. Since much of the stress is relieved when one of the tack welds crack, the potential for cracking the remaining weld (s) dissipates. There is little or no concern that these four nuts will back out during the next cycle with the remaining sound weld. Repairs made during RF-03 on the hood to end panel welds were re-inspected and found to be in good condition.
STEAM DRYER St'PPORT RING Two indications were identified on the steam dryer support ring this outage, one indication was approximately 1/2" in length on the vertical face of the ring, the other

Enclosure 2 to NRC-94-0075 Page 6 indication was 4" - 6" in length on the horizontal face of the support ring. Based on experience with support ring cracking on similar dryers, these indications were caused by IGSCC. The primary source of stress is residual fabrication stress. Based on experience from similar dryers of the same design with more severe cracking, this crack does not present a concern for the structural adequacy of the support ring.
CORROSION DEPOSITS / BIOLOGICAL GROWTil DEPOSITS Unusual surface conditions were identified during IVVI inspections on the unciad feed water nozzles and also on the RPV cladding near the steam line nozzles 3600 around the vessel. As a result, a sampling dive into the RPV was planned. On June 29,1994, a diver successfully completed the necessary corrosion product sampling, visual inspections, and exploratory inspections in the Reactor Vessel. Corrosion deposits / samples were removed from both the "C" feed water nozzle unclad area (1500) and the cladding at approximately the same azimuth. Based on the preliminary results of the sampling, there is no evidence of micro biologically induced corrosion (MIC) in the vessel although the samples did test positive for the presence of bacteria.
During the dive the diver found that on the feed water nozzles the corrosion deposits were very loose and were scraped off easily. There was no base metal attack on the unciad surfaces. The IVVI contractor perfonned hydrolyzing on a sample location in the feed water nozzle area and this removed the corrosion deposits.
The corrosion deposits on the vessel cladding (3600 ) were found to be more tightly adhered than the deposits on the feed water nozzles. However, the vessel cladding corrosion deposits has been looked at and it has been confinned that there has been no base metal attack. All evidence of selected deposits were successfully removed with the application oflight buffing using a 3M/Scotchbrite wheel on a small grinder. No pits or degradation of the cladding was identified. Both the feed water nozzles and the vessel cladding corrosion were hydrolyzed to remove the deposits.
The hydrolyzing was completely effective in cleaning the feed water nozzles and approximately 75 percent effective in removing the deposits on the vessel cladding. The cleaning was done as a precaution and no further action is recommended by Detroit Edison or General Electric during this outage.
STANDARD RPV IVVI INSPECTIONS i
Nonnally scheduled inspections were also conducted on the following RPV internal components. Inspections on selected components listed below were perfonned per the augmented requirements of GE SIL's, RICSIL's, NUREG's and I.E. Bulletins. No

1
* 1 Enclosure 2 to                                                                             ;
NRC-94-0075 Page 7 evidence or signs of degradation or indications were identified on any of these components.
        - Steam Dryer Support Lugs Steam Dryer Drain Channel welds Shroud IIead/ Separator Stand Pipes / Ties Feed water Nozzles /Spargers/ Brackets (6)
Core Spray Nozzles /Spargers/ Internal Piping Top Guide Hold Downs, . Beam Alignment Surveillance Specimen Holder and Brackets (1)
Incore Dry Tubes (12)
Control Rod Blades (2 of original 20)
        - Jet Pump Assemblies (20) including beams, inlet mixer, riser ann braces, restrainer brackets and instrumentation lines Shroud Support Ring (s) Gussets Summary An irradiated fuel and vessel inspection was conducted to assess the impact of the Dec.
25 chemistry transient on the fuel and associated components. Visual and eddy current examination of the fuel components found the materials to have the surface conditions characteristic of exposure to a BWR environment. All Class 1, Class 2 and RPV nozzle and dissimilar metal weld non destructive examinations revealed no indications of degradation. Visual examinations of the jet pumps, steam separator, feedwater spargers, core spray spargers and internal piping, top guide, and selected integral attachments revealed no indications of degradation. Indications were found in the shroud above the     !
H2 weld, shroud head bolts, steam dryer and dryer support ring. The degraded shroud        ;
head bolts were replaced. The indications were evaluated and are not considered a          i concern for the fifth operating cycle. Inspection plans are being developed to monitor for :
any possible long term effects.
Six control rod drive mechanisms (CRD) were examined. All six CRD's exhibited moderately severe corrosion on the nitrided index and piston tubes. In general, other      l nitrided parts (guide cap, collet assembly) accessible for visual inspection displayed     !
relatively minor evidence of pitting corrosion or deposits. The observed corrosion         l condition would not adversely affect the scram function per an evaluation by General       I Electric Co.                                                                               l Two Local Power Range Monitors (LPRM's) failed following the event. The failures           l occurred in the old NA 200 design detectors. To preclude failures of the further 1
l
                        ,_                                                                     l

4
      -                                                                                                 i
    ~
Enclosure 2 to NRC-94-0075 Page 8 detectors, all NA 200 detectors were replaced with the newer NA 300 model, which does not have a crevice in the relatively thin detector wall.
As a precaution Detroit Edison replaced thejet pump hold down bearns. This was done as a conservative measure based on recent industry experience with beam cracking and possible deleterious effects from the cinemistry transient.
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4 Enclosure 2 to NT C-94-0075 Page 10                                                                                                                                                                               ,
TABLE NO.1 RF-04 SECTION XI SCIIEDULED EXAMINATIONS AND ADDITIONAL AUGMENTED EXAMINATIONS (EXCLUDING IVVI)
CLASS 1 - PIPING WELDS EXAMINED:
Description                  QUANTITY              NDE                           ASME                    AUGMENTED                         AUGMENTED EXAMINED       METIIOD                       SECTION XI                              EXAM                               REASON Piping Welds r
B21-Main Steam                 (6)        MT/UT                              YES                              NO                                                                 j B31-Recirculation        (11 Total)        Pr/UT                                                                                                                                 !
(5)                                           YES                              YES            GL 88-01 Category B,                                7 (1)                                           YES                              NO             NUREG 0313, Rev 2 (5)                                           NO                               YES            GL 88-01 Category B, NUREG 0313, Rev 2 El1-RHR(residual heat          (4)     MT/PT/UT                              YES                              NO l          removal)
E21-CS(core spray)             (1)         Pr/UT                             YES                              NO E41-1IPCI(high pressure        (1)        MT/UT                              YES                              No coolant injection)
G33-RWCU(reactor          (5 Total)        PT/UT water cleanup)                 (4)                                           YES                              NO (1)                                           NO                               YES            GL 88-01 Category B,                                ,
NUREG 0313 Rev 2 N21-FW(feed water)             (6)     PT/MT/UT                              YES                              NO Piping Lugs B21-Main Steam                  (4)              MT                           YES                              NO El1-RIIR                        (6)              PT                           YES                              NO E21-CS                          (8)              MT                           YES                              NO N21-FW                          (4)              PT                           YES                              NO
  ~
C11-CRD                             (2)              PT                           YES                              NO
                                ,.     , , ,   -.  . , , ,      . , , . .  .,-e  ,, ,.      u -.,y.. . -. . ,y  . . , ,      -.,.,_%.., .-_a     .____,,,....m    _ _ - - , , . . _ . . _ ,

Enclosure 2 to NRC-94-0075 Page11 TABLE NO.1 RF-04 SECTION XI SCIIEDULED EXAMINATIONS AND ADDITIONAL AUGMENTED EXAMINATIONS (EXCLUDING IVVI)
CI ASS 2 - PIPING WEI DS EXAMINED:
Description                      QUANTITY              NDE                        ASME           AUGMENTED          AUGMENTED EXAMINED           METIIOD                     SECTION XI          EXAM               REASON Pipe Lugs EIl-R1IR                      (26)              MT/PT                        YES                NO                 N/A E21-CS                         (2)                MT                         YES               NO                  N/A Pipe Welds C41-SLC(standby liquid         (2)                 PT                        YES               NO                  N/A control)
El1-RHR                       (11)             MT/LT"                        YES               NO                  N/A E21-CS                         (2)                MT                         YES               NO                  N/A E41-IIPCI                      (5)           MT/PT/UT"                       YES               NO                  N/A N30-MS(mam steam)              (2)             Aff/UT"                       YES               NO                  N/A T48-CGC{'ombustible            (2)                MT                         YES               NO                  N/A gas control)
G41-FPCCU(fuel pool            (1)                MT                         YES               NO                  N/A coolmg and cleanup)
NON-CLASS - PIPING WELDS EXAMINED:
Description                      QUANTITY              NDE                        ASME           AUGMENTED          AUGMENTED EXAMINED            METIIOD                    SECTION XI           EXAM              REASON Pipe Welds Condensate             (4)                        ITT                        NO                YES   GL 88-01 Category D, NUREG 0313, Rev 2 NOTE: " MT and UT required on circumferential butt welds > 1/2" wall thickness.
o

Enclosure 2 to NRC-94-0075 Page 12 TABLE NO. 2 IN VESSEL VISUAL EXAMINATIONS RF-04 SECTION XI SCllEDULED EXAMINATIONS AND ADDITIONAL AUGMENTED EXAMINATIONS VT VISUAL EXAMINATIONS (VT-3 EXCEPT AS NOTED:
                                                   %              ASME                   AUGMENTED          AUGMENTED Descrintion                    COVERAGE          SECTION XI                   EXAM                REASON Steam Dryer Assembly Steam dryer support lugs         100 %            YES                       YES    GE Report Reconunendation and brackets Steam dryer welds -              100 %            YES                       YES including repair welds Drain Channel seam               100 %            YES                       YES                 SIL 474 welds Shroud IIcad/ Separator Stand pipes (welds as            ~30%             YES                       NO accessible)
Shroud llend Bolts                  100 %           YES/VT                   YES/UT   LTF exammation per SIL 433, Supplement 1 9
y     ,-~r.  .    -     -.-m,  ,--, -o  ,,-e...       ,e  ,,        ,   . - -

Enclosure 2 to NRC-94-0075 Page 13 TABLE NO. 2 (CONTINUED)
IN VESSEL VISUAL EXA311 NATIONS                                                 r RF-04 SECTION XI SCIIEDULED EXA311 NATIONS AND
!                                                                         ADDITIONAL AUGMENTED EXA311 NATIONS VT VISliAI, EXAMIN ATIONS (VT-3) EXCEPT AS NOTED:
                                                          %                ASME                                        AUGMENTED              AUGMENTED l
Description                             EXAMINED            SECTION XI                                            EXAM                 REASON i
Shroud (VT-1)-enhanced technique Outside Surface 3600 around iI-l            100 %           YES/ PARTIAL                                    YES/ FULL VT     SIL 572. Rev 1 through 11-7            (ofaccessible                                                (of accessible areas)   RICSIL 054, Rev 1     [
circumferertial welds       areas)                                                                           RICSIL 068,           t
,                           to maximum extent                                                                                            IE Notice 93-079 possible
                       . Shroud support welds           100 %           YES/ PARTIAL -                                  YES/ FULL VT                           i (VT-3)           (accessible areas)                                            (of accessible areas)_
inside Surface 360 around P -              100 %           YES/ PARTIAL                                    YES/ FULL VT     SIL 572, Rev 1 through 11-4                                                                         (of accessible areas)   RICSIL 054, Rev 1 circumferential welds                                                                                        RICSIL 068,            j to maximum extent                                                                                            IE Notice 93-079       ,
possible Feedwster Nozzles (6)-
              ~ Unclad Nozzle Bore Area                 100 %               YES                                                YES       NUREG 0619 Spargers (6) -                100 %               YES                                                YES
* Sparger Hrackets (6)          100 %               YES                                                NO s
  -    , - , . . - , ,                , ,.     -     -               -            ~....             , . - - . . - - . . . . -          ,         ,         ,,.

Enclosure 2 to NRC-94-0075 Page 14 TABLE NO. 2 (CONTINUED)
IN VESSEL VISUAL EXAMINATIONS RF-84 SECTION XI SCIIEDULED EXAMINATIONS AND ADDITIONAL AUG3IENTED EXA311 NATIONS VT VISif AI, EXA%IINATIONS (VT-3) EXCEPT AS NOTED:
                                                         %                       ASS 1E Description                                                                            AUG3fENTED         AUG31ENTED COVERAGE                     SECTION XI                 EXA51               REASON Core Spray Nonles (2)
Spargers (accessible areas)        ~100%                       YES                       YES     SIL 289, Supplement i Core spray internal piping        ~100"a                                                         IE Bulletm 80-13 YES                      YES (accessible areas)                                                                               SIL 289, Suppicment 1 IE Bulletm 80-13 Pipmg brackets (accessibic        -lW%
i                                                                                 YES                       NO areas)
Top Guide (6 locations)
Itold douns                       100 %                      YES                       NO (top surfaces ontv)
Beam Alignment                    ~3%                        YES                       NO Beam cracking                     ~3%                        YES                       YES     SIL 554 RICSIL 059 m
I

Enclosure 2 to NRC-94-0075 Page 15 TABLE NO. 2 (CONTINUED)
IN VESSEL VISUAL EXA311 NATIONS RF-04 SECTION XI SCilEDULED EXA311 NATIONS AND ADDITIONAL AUGMENTED EXAMINATIONS VT VISUAL EXAMINATIONS (VT-3) EXCEPT AS NOTED:
l                                              %         ASME                           AUGNENTED                AUGMENTED Description                         COVERAGE    SECTION XI                                EXAM                REASON Jet Pumps Jet Ptunp Assemblies (20)       100 %    YES(partial)                               YES    SIL 465, Supplement 1 Instrumentation lines and       100 %    YES(partial)                               YES    SIL 420                                                                                               ,
brackets (as accessible)
Jet pump riser arms (20)        100 %    YES(partial)                               YES    SIL 551 (VT-1)
Jet pump restrainer screws      100 %    YES(partial)                               YES    SIL 574 (20)
Jet Pump IIold Down Beams Perfonn UT and ET             100 %       NO                               YES (100%)    SIL 330, Supplements 1 and 2 leddy current testing)                                                                   RICSIL 065 baseline inspection in                                                                   IE Bulletin 80-09 warehouse.
Perfonn UT and visual         100 %   YES/ VISUAL                           YES UT/Vf    SIL 330, Supplements I and 2 preservice mspection                                                            (100%)   RICSIL 065 following installation                                                                   IE Bulletin 80-09 O
6
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Enclosure 2 to NRC-94-0075                                                                                                                                                                                             .;
Page 16 TABLE NO. 2 (CONTINUED)
IN VESSEL VISUAL EXAMINATIONS RF-04 SECTION XI SCIIEDULED EXAMINATIONS AND ADDITIONAL AIIGMENTED EXAMINATIONS VT VISITAI, EXA%11 NATIONS (VT-3) EXCEPT AS NOTED:
                                                                                               %          ASSIE                     AUG31ENTED             AUGMENTED Description                                                        COVERAGE     SECTION XI                     EXA31                 REASON Surs eillance Specimen 1Iolders Specimen bracLets (1)                                            100*i,          YES                        NO Incore Dry Tubes (4SR31/81R31)
(source range monitor / intermediate range monitor)
Examine upper 18-24                                            100 %           NO                         YES      SIL 409 inches                                                                                                             Inspection recommended in GE Report.
I RPV Bottom llead Inspect RPV bottom head                                        ~10%            NO                         YES      Inspection recommended in GE at 2 locations                                                                                                     Report Control Rod BladenCRB)
Inspect 2 of 20 original                                        10 %           NO                         YES      Inspection recommended in GE CRIfs per GE Report.                                                                                               Report RPV Cladding Perform visual inspection                                       2%             YES                        YES      Sampling dive per GE of RPV cladding and                                                                                                reconunendations including visual l                          , feedwater nozzle                                                                                                    inspxtion.
I                             corrosion deposits.
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